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 2001 through 2003, and provides information about the
capital resources, liquidity and financial performance of Sempra Energy
and its subsidiaries (collectively referred to as "the company"). This
section also focuses on the major factors expected to influence future
operating results and discusses investment and financing activities and
plans. It should be read in conjunction with the Consolidated Financial
Statements included in this Financial Report.
2
OVERVIEW
Sempra Energy
Sempra Energy is a Fortune 500 energy services holding company. Its
business units provide a wide spectrum of value-added electric and
natural gas products and services to a diverse range of customers.
Operations are divided between delivery services, which are comprised of
the California utility subsidiaries, Sempra Energy Global Enterprises
(Global) and Sempra Energy Financial as described below.
----------------------------
| |
| Sempra Energy |
| |
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|
----------------------------------------------
| | |
- ------------------------- ---------------------- -----------------
| | | | | |
| California Utilities | | Sempra Energy | | Sempra Energy |
| | | Global Enterprises | | Financial |
- ------------------------- | | | |
| ---------------------- -----------------
| ------------------- |
|--| | | --------------------
| | Southern | |-- | |
| | California | | | Sempra Energy |
| | Gas | | | Trading |
| | | | | |
| ------------------- | --------------------
| | --------------------
| -------------------- |---| |
|--| | | | Sempra Energy |
| San Diego Gas | | | Resources |
| & Electric | | | |
| | | --------------------
-------------------- | --------------------
|---| |
| | Sempra Energy |
| | LNG |
| | |
| --------------------
| --------------------
|---| |
| | Sempra Energy |
| | International |
| | |
| --------------------
|
| --------------------
|---| |
| Sempra Energy |
| Solutions |
| |
--------------------
3
Summary descriptions of the operating business units are provided below
and further detail is provided throughout this section of the Financial
Report.
The major events during 2003 affecting the results for the year and
future years include the following:
- -- Favorable resolution of significant income-tax issues which
increased 2003 earnings by $118 million;
- -- Favorable decisions, subject to appeal, upholding Sempra Energy
Resources' (SER) contract with the California Department of Water
Resources (DWR);
- -- California Public Utilities Commission (CPUC) settlement subject
to appeal, relating to SDG&E's intermediate-term power-purchase
contracts and recognition of the related $65 million after-tax
gain;
- -- Rate-setting process for 2004 and future years nearing resolution
for SoCalGas and SDG&E;
- -- Completion of construction for generating plants by the company's
generation subsidiary;
- -- Entry into the liquefied natural gas (LNG) business in Baja
California, Mexico and in Louisiana;
- -- The end of incentive-pricing ratemaking for the San Onofre Nuclear
Generation Station (SONGS), 20% owned by SDG&E;
- -- Continuing preliminary proceedings related to a claim by the
company's international business unit for compensation from the
Argentine government for changes in natural gas tariffs;
- -- Continuing legal proceedings concerning anti-trust claims made
against the company, San Diego Gas & Electric Company (SDG&E) and
Southern California Gas Company (SoCalGas);
- -- Write down of the carrying values of Frontier Energy and Atlantic
Electric & Gas Limited (AEG); and
- -- Application of a new accounting principle, requiring consolidation
of two affiliates.
The California Utilities
As of December 31, 2003, SoCalGas and SDG&E (the California Utilities)
served over 22 million consumers. Natural gas service was provided
throughout Southern California and portions of central California
through over 6.2 million meters. Electric service was provided
throughout San Diego County and portions of Orange County, both in
Southern California, through 1.3 million meters.
4
Sempra Energy Global Enterprises (Global)
Global is a holding company for most of the subsidiaries of Sempra
Energy that are not subject to California utility regulation.
Global's principal subsidiaries provide the following energy-related
products and services:
- -- Sempra Energy Trading (SET) is a wholesale trader of physical and
financial energy products, including natural gas, power, crude oil
and other commodities, and a trader and wholesaler of metals,
serving a broad range of customers;
- -- SER acquires, develops and operates power plants for the
competitive market;
- -- Sempra Energy LNG Corp. (SELNG) is developing regasification
terminals for LNG;
- -- Sempra Energy International (SEI) engages in energy-infrastructure
projects outside the United States and, as of December 31, 2003,
had interests in companies that provide natural gas or electricity
services to over 2.8 million customers in Argentina, Chile, Mexico
and Peru and in two small natural gas distribution utilities in
the eastern United States; and
- -- Sempra Energy Solutions (SES) provides energy-related products and
services on a retail basis, including commodity sales to
electricity and natural gas consumers and energy efficiency
engineering services.
Sempra Energy Financial (SEF)
In order to reduce Sempra Energy's income taxes, SEF invests in limited
partnerships which own 1,300 affordable-housing properties throughout
the United States and holds an interest in a limited partnership that
produces synthetic fuel from coal.
RESULTS OF OPERATIONS
Overall Operations
Net income was $649 million in 2003, a 9.8% increase over 2002, and
earnings per diluted share was $3.03, an increase of 5.6%. The
percentage increase in earnings per diluted share was less than the
percentage increase in earnings due to the issuance of shares needed to
finance the company's expanded Global business.
5
The following chart shows net income and diluted earnings per share for
each of the five years following the formation of the company in 1998.
(Dollars in millions, except per share amounts)
- -------------------------------------------------------------
Net Income Earnings Per Share
------------- --------------------
2003 $ 649 $ 3.03
2002 $ 591 $ 2.87
2001 $ 518 $ 2.52
2000 $ 429 $ 2.06
1999 $ 394 $ 1.66
- -------------------------------------------------------------
Although operating income was less in 2003 than in 2002, there were many
unusual items that affect this comparison. The following table
summarizes the major factors affecting the comparison of net income and
operating income for 2002 and 2003.
Net Operating
(Dollars in millions) Income Income
- -----------------------------------------------------------------------
2002 $ 591 $ 987
Extraordinary item in 2002 (16) --
Merger savings in 2002 (25) (42)
Income-tax settlements in 2002 (25) --
California energy crisis litigation costs
in 2002 13 23
------- -------
538 968
Income-tax settlements in 2003 118 --
SDG&E power contract settlement in 2003 65 116
Impairment of Frontier Energy assets in 2003 (47) (77)
Impairment of AEG assets in 2003 (21) (24)
California energy crisis litigation costs and
SoCalGas sublease loss in 2003 (49) (85)
SoCalGas' natural gas procurement awards in
2003 29 49
Changes in accounting principles in 2003:
Repeal of EITF 98-10 (29) --
Adoption of FIN 46 (17) --
2003 impact of the repeal of EITF 98-10 9 15
Operations (2003 compared to 2002) 53 (23)
------- -------
2003 $ 649 $ 939
------- -------
- -----------------------------------------------------------------------
California Utility Operations
To understand the operations and financial results of the California
Utilities, it is important to understand the ratemaking procedures to
which they are subject.
The California Utilities are subject to various regulatory bodies and
rules at the national, state and local levels. The primary California
6
body is the CPUC which regulates utility rates and operations. The
primary national bodies are the Federal Energy Regulatory Commission
(FERC) and the Nuclear Regulatory Commission (NRC). The FERC regulates
interstate transportation of natural gas and electricity and various
related matters. The NRC regulates nuclear generating plants. Local
regulators and municipalities govern the placement of utility assets,
including natural gas pipelines and electric lines. Other business units
are also subject to regulation including, as the case may be, the FERC,
various state commissions, local bodies, and various similar bodies in
countries other than the United States.
California's electric utility industry was significantly affected by
California's restructuring of the industry during 2000-2001. Beginning
in mid-2000 and continuing into 2001, supply/demand imbalances and a
number of other factors resulted in abnormally high electric commodity
costs, leading to several legislative and regulatory responses,
including a ceiling imposed on the cost of the electric commodity that
SDG&E could pass on to its small-usage customers. To obtain adequate
supplies of electricity, beginning in February 2001 and continuing
through December 31, 2002, the DWR began purchasing power to fulfill the
full net short position of the investor-owned utilities (IOUs),
consisting of all electricity requirements of the IOUs' customers other
than that provided by their existing generating facilities or their
previously existing purchased-power contracts.
Beginning on January 1, 2003, SDG&E and the other IOUs resumed their
electric commodity procurement function. In addition, the CPUC
established the allocation of the power purchased by the DWR under long-
term contracts for the IOUs' customers and the related cost
responsibility among the IOUs for that power. This is discussed further
in Note 13 of the notes to Consolidated Financial Statements.
The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore customers.
Restructuring is again being considered, as discussed in Note 14 of the
notes to Consolidated Financial Statements.
See additional discussion of these matters under "Factors Influencing
Future Performance" and in Notes 13 and 14 of the notes to Consolidated
Financial Statements.
Natural Gas Revenue and Cost of Natural Gas. Natural gas revenues
increased to $4.0 billion in 2003 from $3.3 billion in 2002, and the
cost of natural gas increased to $2.1 billion in 2003 from $1.4 billion
in 2002. Additionally, natural gas revenues increased to $1.0 billion
for the three months ended December 31, 2003 from $971 million for the
same period in 2002, and the corresponding cost of natural gas increased
to $542 million in 2003 from $436 million in 2002. These changes were
primarily attributable to natural gas price increases. For the year,
this was partially offset by reduced volumes. Revenues also increased
due to approved performance awards recognized during 2003. See
discussion of performance awards in Note 14 of the notes to Consolidated
Financial Statements.
Under the current regulatory framework, the cost of natural gas
purchased for customers and the variations in that cost are passed
through to the customers on a substantially concurrent basis. However,
SoCalGas' Gas Cost Incentive Mechanism (GCIM) allows SoCalGas to share
7
in the savings or costs from buying natural gas for customers below or
above monthly benchmarks. 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 between customers and
shareholders. In addition, SDG&E's natural gas procurement Performance-
Based Regulation (PBR) mechanism provides an incentive mechanism by
measuring SDG&E's procurement of natural gas against a benchmark price
comprised of monthly natural gas indices, resulting in shareholder
rewards for costs achieved below the benchmark and shareholder penalties
when costs exceed the benchmark. See further discussion in Notes 1 and
14 of the notes to Consolidated Financial Statements.
Natural gas revenues decreased to $3.3 billion in 2002 from $4.4 billion
in 2001, and the cost of natural gas distributed decreased to $1.4
billion in 2002 from $2.5 billion in 2001. The decrease in natural gas
revenues was primarily due to lower natural gas prices and decreased
transportation charges related to electric generation plants and the
North Baja pipeline's beginning of service in September 2002 (see Note
15 of the notes to Consolidated Financial Statements). The decrease in
the cost of natural gas was primarily due to lower average natural gas
commodity prices. For the fourth quarter, natural gas revenues increased
to $971 million in 2002 from $773 million in 2001, and the cost of
natural gas distributed increased to $436 million in 2002 from $319
million in 2001 due primarily to increased natural gas prices.
Electric Revenue and Cost of Electric Fuel and Purchased Power.
Electric revenues increased to $1.8 billion in 2003 from $1.3 billion in
2002, and the cost of electric fuel and purchased power increased to
$0.5 billion in 2003 from $0.3 billion in 2002. Additionally, for the
fourth quarter electric revenues increased to $419 million in 2003 from
$320 million in 2002, and the cost of electric fuel and purchased power
increased to $113 million in 2003 from $76 million in 2002. These
changes were attributable to several factors, including the effect of
the DWR's purchasing the net short position of SDG&E during 2002, higher
electric commodity costs and volumes in 2003, and the increase in
authorized 2003 distribution revenue. In addition, the increase in
revenue was due to the recognition of $116 million related to the
approved settlement of intermediate-term purchase power contracts and
higher PBR awards during the third quarter or 2003.
Electric revenues decreased to $1.3 billion in 2002 from $1.7 billion in
2001, and the cost of electric fuel and purchased power decreased to
$0.3 billion in 2002 from $0.8 billion in 2001. These decreases were
primarily due to the DWR's purchasing SDG&E's net short position for a
full year in 2002 and the effect of lower electric commodity costs and
decreased off-system sales. For the fourth quarter, electric revenues
increased to $320 million in 2002 from $284 million in 2001, and the
cost of electric fuel and purchased power decreased to $76 million in
2002 from $87 million in 2001. The increase in electric revenues was due
primarily to higher electric distribution and transmission revenue as
well as additional revenues from the Incremental Cost Incentive Pricing
(ICIP) mechanism, while the decrease in cost of electric fuel and
purchased power was due primarily to a decrease in average electric
commodity costs. Refer to Note 13 of the notes to Consolidated Financial
Statements for further discussion of ICIP and SONGS.
8
The tables below summarize the California Utilities' natural gas and
electric volumes and revenues by customer class for the years ended
December 31, 2003, 2002 and 2001.
<table>
NATURAL GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
<caption>
Natural Gas Sales Transportation & Exchange Total
- ---------------------------------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
- ---------------------------------------------------------------------------------------------
<s> <c> <c> <c> <c> <c> <c>
2003:
Residential 273 $ 2,479 2 $ 7 275 $ 2,486
Commercial and industrial 121 863 277 189 398 1,052
Electric generation plants -- 3 241 79 241 82
Wholesale -- -- 20 4 20 4
---------------------------------------------------------------
394 $ 3,345 540 $ 279 934 3,624
Balancing accounts and other 386
--------
Total $ 4,010
- ---------------------------------------------------------------------------------------------
2002:
Residential 289 $ 2,089 2 $ 8 291 $ 2,097
Commercial and industrial 117 635 294 183 411 818
Electric generation plants -- -- 264 43 264 43
Wholesale -- -- 16 12 16 12
---------------------------------------------------------------
406 $ 2,724 576 $ 246 982 2,970
Balancing accounts and other 293
--------
Total $ 3,263
- ---------------------------------------------------------------------------------------------
2001:
Residential 297 $ 2,797 2 $ 6 299 $ 2,803
Commercial and industrial 113 903 262 174 375 1,077
Electric generation plants -- -- 417 104 417 104
Wholesale -- -- 40 10 40 10
---------------------------------------------------------------
410 $ 3,700 721 $ 294 1,131 3,994
Balancing accounts and other 377
--------
Total $ 4,371
- ---------------------------------------------------------------------------------------------
ELECTRIC TRANSMISSION AND DISTRIBUTION
(Dollars in millions, volumes in million kilowatt hours)
2003 2002 2001
------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
------------------------------------------------------------------
Residential 6,702 $ 731 6,266 $ 649 6,011 $ 775
Commercial 6,263 674 6,053 633 6,107 753
Industrial 1,976 161 1,883 160 2,792 325
Direct access 3,322 87 3,448 117 2,464 84
Street and highway lighting 91 11 88 9 89 10
Off-system sales 8 - 5 - 413 88
------------------------------------------------------------------
18,362 1,664 17,743 1,568 17,876 2,035
Balancing and other 123 (286) (359)
------------------------------------------------------------------
Total $ 1,787 $ 1,282 $ 1,676
------------------------------------------------------------------
</table>
9
As explained in Note 13 of the notes to Consolidated Financial
Statements, commodity-related revenues from the DWR's purchasing of
SDG&E's net short position or from the DWR's allocated contracts are not
included in revenue. However, the associated volumes and distribution
revenue are included herein.
Other Operating Revenues and Cost of Sales. These tables provide a
breakdown of other operating revenues and cost of sales by business
unit.
- ----------------------------------------------------------------------
(Dollars in millions) 2003 2002 2001
- ----------------------------------------------------------------------
OPERATING REVENUES
Sempra Energy Trading $ 1,144 $ 821 $ 1,047
Sempra Energy Resources 671 349 178
Sempra Energy International 208 176 289
Sempra Energy Solutions 175 177 180
-------- -------- --------
Total Global Enterprises 2,198 1,523 1,694
Parent and Other* (108) (20) (11)
-------- -------- --------
Total $ 2,090 $ 1,503 $ 1,683
======== ======== ========
COST OF SALES
Sempra Energy Trading $ 542 $ 293 $ 320
Sempra Energy Resources 433 218 185
Sempra Energy International 166 148 257
Sempra Energy Solutions 65 56 92
-------- -------- --------
Total Global Enterprises 1,206 715 854
Parent and Other* (2) (6) 19
-------- -------- --------
Total $ 1,204 $ 709 $ 873
======== ======== ========
*Includes certain intercompany eliminations recorded in consolidation.
- ----------------------------------------------------------------------
For the fourth quarters of 2003 and 2002, revenues increased to $598
million from $409 million in 2002 and costs increased to $318 million
from $206 million. These increases and the annual increases shown above
were primarily due to higher revenues at SET as the result of increased
volumes and volatility in the energy commodity markets, as well as
increased revenues from SER's resumption of contract sales of
electricity to the DWR in April 2002 and sales by its Twin Oaks power
plant purchased in the fourth quarter of 2002.
The decreases in revenues and costs in 2002 from 2001 were primarily due
to reduced SEI revenues as a result of decreased natural gas prices at
its Mexican subsidiaries and lower activity at SET as a result of
decreased volatility in energy commodity markets and lower energy
commodity prices, partially offset by increased activity from
acquisitions made during 2002. These decreases were partially offset by
the increase in SER's sales to the DWR that commenced in June 2001
through September 2001 at below cost, and resumed in April 2002 at
favorable contract rates under its long-term contract.
10
For the fourth quarters of 2002 and 2001, revenues increased to $409
million from $242 million in 2001 and costs increased to $206 million
from $174 million. The increases were primarily due to increased
activity at SET as a result of higher volatility in energy commodity
markets as well as increased SER sales.
Other Operating Expenses. This table provides a breakdown of operating
expenses by business unit.
- ------------------------------------------------------------------
(Dollars in millions) 2003 2002 2001
- ------------------------------------------------------------------
OPERATING EXPENSES
California Utilities:
Southern California Gas Company $ 954 $ 872 $ 792
San Diego Gas & Electric 637 560 491
-------- -------- --------
Total Utilities 1,591 1,432 1,283
Sempra Energy Trading 374 304 370
Sempra Energy Resources 93 44 21
Sempra Energy International 120 49 70
Sempra Energy Solutions 71 66 68
-------- -------- --------
Total Global Enterprises 658 463 529
Parent and Other* 38 6 (52)
-------- -------- --------
Total $ 2,287 $ 1,901 $ 1,760
======== ======== ========
* Includes certain intercompany eliminations recorded in consolidation.
- -----------------------------------------------------------------------
The increase at the California Utilities in 2003 from 2002 was primarily
the result of a $75 million before-tax charge for litigation and for
losses associated with a sublease of portions of the SoCalGas
headquarters building, and increased labor and employee benefit costs.
The non-recurring sublease losses pertain to pre-2003 transactions, but
are charged against current operations because they are not material to
annual financial statements. A smaller portion of the increase was due
to the California fires, which primarily affected SDG&E and which are
discussed in Note 14 of the notes to Consolidated Financial Statements.
The fire costs are expected to be recovered in rates. General operating
costs increased at SET due to the increased activity and a full year's
activities for the businesses acquired in 2002, at SER due to the new
power plants and at SEI due to the $77 million before-tax write-down of
the carrying value of the assets of Frontier Energy, as described in
Note 1 of the notes to Consolidated Financial Statements. In addition,
operating costs increased due to a $24 million before-tax write-down of
the carrying value of the assets of AEG and due to higher antitrust
litigation costs at the Global companies. During 2002 the California
Utilities recorded $23 million in litigation costs related to the
California energy crisis.
11
For the 2003 and 2002 fourth quarters, other operating expenses
increased to $656 million in 2003 ($474 million from the California
Utilities) from $587 million in 2002 ($457 from the California
Utilities). The increase was mainly due to increased operating costs at
SDG&E, SET and SER as discussed above.
For the 2002 and 2001 fourth quarters, other operating expenses
increased to $587 million from $394 million in 2001. This increase and
the annual increase shown above was due primarily to increased operating
costs at the California Utilities resulting largely from higher labor
and employee benefits costs, litigation costs related to the California
energy crisis, costs associated with SDG&E's nuclear generating
facilities and balancing account costs at SoCalGas.
Other Income. Other income, primarily equity earnings from
unconsolidated subsidiaries and interest on regulatory balancing
accounts, was $26 million, $15 million and $3 million in 2003, 2002 and
2001, respectively. The increase in 2003 was due to increased equity
earnings at SEI and other subsidiaries, and reduced balancing account
interest expense, partially offset by lower operating results at SER's
joint ventures resulting from business interruption insurance proceeds
received in 2002 related to an outage at the El Dorado plant during
2001.
The increase in 2002 was primarily due to increased sales at the El
Dorado power plant and the business interruption insurance proceeds,
offset partially by lower 2002 equity earnings from international
investments and the $19 million gain from SDG&E's sale of its property
in Blythe, California in 2001.
Other income for the fourth quarter was a net loss of $12 million for
2003 compared to income of $9 million for 2002 and a loss of $12 million
for 2001. The decrease in 2003 was due to decreased equity earnings from
SEI as well as lower operating results at SER's joint ventures. The
increase in 2002 was due primarily to lower net regulatory interest
expense.
Interest Income. Interest income was $104 million, $42 million and $83
million in 2003, 2002 and 2001, respectively. $59 million of the
increase in 2003 was due to the favorable resolution of income-tax
issues with the Internal Revenue Service (IRS) in 2003. The decrease in
2002 compared to 2001 was due primarily to lower interest income on
short-term investments.
Interest Expense. Interest expense was $308 million, $294 million and
$323 million in 2003, 2002 and 2001, respectively. The increase in 2003
was due to the issuance of $1 billion of long-term notes in April 2002
and early 2003, and the reclassification of preferred dividends on
mandatorily redeemable trust preferred securities and preferred stock of
subsidiaries to interest expense as a result of the adoption of
Statement of Financial Accounting Standards (SFAS) 150, "Accounting for
Certain Financial Instruments with Characteristics of Liabilities and
Equity," on July 1, 2003 (see Note 1 of the notes to Consolidated
Financial Statements). These increases were offset partially by the
paydown of commercial paper and debt maturities at the California
Utilities.
12
The decrease in 2002 was primarily due to an increase in capitalized
interest related to construction projects, lower interest rates and the
favorable effects of interest rate swaps. Interest rates on certain of
the company's debt can vary with credit ratings, as described in Notes 4
and 5 of the notes to Consolidated Financial Statements.
Interest expense for the fourth quarter was $85 million, $74 million and
$63 million in 2003, 2002 and 2001, respectively. The increase in 2003
was due to the issuance of the $400 million of long-term notes, offset
partially by the paydown of commercial paper and debt maturities at the
California Utilities. The increase in 2002 was attributable to the
issuance of $600 million of equity units by the company and $250 million
of first mortgage bonds issued by SoCalGas, partially offset by debt
maturities at the California Utilities.
Income Taxes. Income tax expense was $47 million, $146 million and $213
million in 2003, 2002 and 2001, respectively. The effective income tax
rates were 6.3 percent, 20.2 percent and 29.1 percent, respectively. The
changes in 2003 compared to 2002 were primarily due to the favorable
resolution of income-tax issues in the fourth quarter of 2003 (which
reduced income tax expense by $83 million) and a $39 million increase in
income tax credits from synthetic fuel investments in 2003 (see
discussion of Section 29 credits in Note 7), offset partially by a $25
million favorable resolution of income-tax issues at SDG&E in the second
quarter of 2002. Income before taxes in 2003 included $59 million in
interest income arising from the income tax settlement, resulting in an
offsetting $24 million income tax expense. The decreases in income tax
expense and in the effective income tax rates for 2002 compared to 2001
were primarily due to the favorable resolution of income-tax issues at
SDG&E and increased income tax credits from synthetic fuel investments
in 2002.
Income tax expense (benefit) for the fourth quarter was ($62) million in
2003 compared to $3 million in 2002, and ($40) million in 2001. The
corresponding effective income tax (benefit) rates were (32.8) percent,
2.2 percent and (59.7) percent. The change in the 2003 quarter was due
primarily to the resolution of the income-tax issues discussed above.
The change in 2002 was due primarily to increased income before taxes,
as well as the resolution in 2001 of prior-year tax issues. The low
effective income tax rate in the 2002 quarter was primarily due to
increased income tax credits from affordable-housing and synthetic fuel
investments. These investments are discussed in Note 3 of the notes to
Consolidated Financial Statements.
In connection with its affordable-housing investments, the company has
unused tax credits dating back to 1999, which the company fully expects
to utilize before their various expiration dates of 2019 to 2022. At
December 31, 2003, the amount of these unused tax credits was $192
million. In addition, the company has $74 million of alternative minimum
tax credits with no expiration date.
Net Income. Changes in net income between 2002 and 2003 are summarized
in the table shown previously under "Overall Operations."
Excluding the effects of the $16 million extraordinary item in 2002 (see
Note 1 of the notes to Consolidated Financial Statements), the increase
in net income in 2002 compared to 2001 was primarily due to improved
results at SER, lower interest expense, the 2001 after-tax charge of $25
13
million for the surrender of SEI's Nova Scotia natural gas distribution
franchise and the effects of the income tax matters referred to above.
These factors were partially offset by lower income in 2002 from SET and
the $20 million after-tax gain on the sale of Energy America in 2001.
Net income for the fourth quarter of 2003 was $234 million, or $1.03 per
diluted share of common stock in 2003, compared with $148 million, or
$0.72 per diluted share of common stock in 2002, and $107 million, or
$0.52 per diluted share of common stock in 2001. Net income for the
fourth quarter of 2003 includes a $17 million charge for the cumulative
effect of the change in accounting principle ($0.07 per diluted share of
common stock). Net income for the fourth quarter of 2002 includes a $14
million extraordinary gain related to SET's acquisitions ($0.07 per
diluted share of common stock). Excluding the cumulative effect of the
accounting change and the extraordinary item, the increase in quarterly
earnings in 2003 compared to 2002 was mainly due to the favorable
resolution of income tax issues at the California Utilities in 2003. The
increase in 2002 compared to 2001 was primarily attributable to
increased earnings at SET (from increased volatility in the energy
markets and the contribution from the metals business) and increased
earnings at SER from the DWR contract, offset partially by decreased
profitability from SEI's Argentine investments.
Book value per share was $17.17, $13.79 and $13.16, at December 31,
2003, 2002 and 2001, respectively. The increases in 2003 and 2002 were
primarily the result of comprehensive income exceeding the dividends
and, in 2003, the sale of additional shares of common stock for a per-
share price in excess of its book value.
14
Net Income by Business Unit
Years ended December 31,
- -----------------------------------------------------------------------
(Dollars in millions) 2003 2002 2001
- -----------------------------------------------------------------------
California Utilities
Southern California Gas Company $ 209 $ 212 $ 207
San Diego Gas & Electric 334 203 177
------ ------ ------
Total Utilities 543 415 384
Global Enterprises
Sempra Energy Trading 98 126 196
Sempra Energy Resources 94 60 (27)
Sempra Energy International 1 26 25
Sempra Energy Solutions 16 21 1
------ ------ ------
Total Global Enterprises 209 233 195
Sempra Energy Financial 41 36 28
Parent and Other* (144) (93) (89)
------ ------ ------
Consolidated $ 649 $ 591 $ 518
====== ====== ======
* Includes after-tax interest expense of $100 million, $70 million and
$80 million in 2003, 2002 and 2001, respectively, and intercompany
eliminations recorded in consolidation.
- -----------------------------------------------------------------------
Southern California Gas Company
SoCalGas recorded net income of $209 million and $212 million in 2003
and 2002, respectively, and net income of $61 million and $45 million
for the three-month periods ended December 31, 2003 and 2002,
respectively. During 2003, net income was affected by the resolution of
income-tax issues in the fourth quarter and the $29 million after-tax
GCIM awards in the third quarter (see Note 14 of the notes to
Consolidated Financial Statements for a discussion of GCIM awards),
offset by a $32 million after-tax charge for litigation and for losses
associated with a long-term sublease of portions of its headquarters
building, and the end of sharing of merger savings (which positively
impacted earnings by $17 million for the year ended December 31, 2002).
The change for the quarter was due primarily to the resolution of the
income-tax issues, offset partially by the end of sharing of merger
savings (which positively impacted earnings by $4 million for the fourth
quarter of 2002).
Net income for SoCalGas increased to $212 million in 2002 compared to
$207 million in 2001 primarily due to decreased interest expense in
2002, offset partially by higher depreciation expense and the 2000 GCIM
award recorded in 2001. Net income for the fourth quarter of 2002
decreased compared to the fourth quarter of 2001 due mainly to increased
operating costs, partially offset by lower interest expense in 2002.
15
San Diego Gas & Electric
SDG&E recorded net income of $334 million and $203 million in 2003 and
2002, respectively, and net income of $128 million and $53 million for
the fourth quarters of 2003 and 2002, respectively. The increase for the
year was primarily due to the favorable resolution of income tax issues
in the fourth quarter of 2003, which positively affected earnings by $79
million, income of $65 million after-tax related to the approved
settlement of certain purchase power contracts (see Note 13 of the notes
to Consolidated Financial Statements), higher earnings from PBR awards,
and higher electric transmission and distribution revenue. These factors
were partially offset by higher operating expenses, including litigation
charges in the third quarter of 2003, the end of sharing of the merger
savings (which positively impacted earnings by $8 million in 2002) and
the $25 million favorable resolution of prior years' income-tax issues
recorded in the second quarter of 2002. The change for the quarter was
due to the resolution of the income tax issues and higher electric
transmission and distribution revenue, offset partially by the end of
sharing of the merger savings (which positively impacted earnings by $2
million for the 2002 quarter).
Net income increased to $203 million in 2002 from $177 million in 2001.
The increase was primarily due to the $25 million after-tax benefit
noted above and lower interest expense in 2002, partially offset by
lower interest income in 2002 and the 2001 gain on the sale of SDG&E's
Blythe property. Net income increased to $53 million for the fourth
quarter of 2002, compared to $45 million for the corresponding period in
2001, primarily due to higher natural gas income, an increase in
electric transmission and distribution revenues, and income tax
adjustments in 2002, partially offset by the 2001 Blythe gain.
Sempra Energy Trading
SET recorded net income of $98 million in 2003 compared to $126 million
and $196 million in 2002 and 2001, respectively. For the fourth quarter,
SET recorded net income of $59 million in 2003 compared to $53 million
and $10 million in 2002 and 2001, respectively. For purposes of
comparison with the corresponding periods, net income for 2003 and 2002
would have been $117 million and $110 million if not for the repeal of
Emerging Issues Task Force (EITF) 98-10 in 2003 and the extraordinary
gain recognized in 2002, both discussed in Note 1 of the notes to
Consolidated Financial Statements. The repeal of EITF 98-10 adversely
impacted SET's results by a cumulative effect adjustment of $28 million
and positively impacted earnings by $9 million related to operations in
2003, including a $12 million positive adjustment for the three months
ended December 31, 2003.
The decrease in net income in 2002 compared to 2001 was primarily due to
greater revenues in 2001 resulting from higher volatility in energy
commodity markets during the first half of 2001, partially offset by the
extraordinary gain of $16 million, earnings from new acquisitions and
increased synthetic fuel credits in 2002.
SET's net income included the impact of its synthetic fuel credits of
$73 million, $39 million and $28 million in 2003, 2002 and 2001,
respectively (see Note 7 of the notes to Consolidated Financial
Statements), which contributed $23 million, $11 million and $5 million
to earnings in 2003, 2002 and 2001, respectively.
16
A summary of SET's net unrealized revenues for trading activities
follows:
- -----------------------------------------------------------------
Years ended December 31,
(Dollars in millions) 2003 2002
- -----------------------------------------------------------------
Balance at beginning of period $ 180 $ 405
Cumulative effect adjustment (48) --
Additions 755 442
Realized (618) (667)
------------------------------------
Balance at end of year $ 269 $ 180
====================================
- -----------------------------------------------------------------
The estimated fair values for SET's net unrealized trading assets as of
December 31, 2003, and the periods during which unrealized revenues are
expected to be realized, are (dollars in millions):
<table>
<caption>
Fair Market
Value at
December 31, /--Scheduled Maturity (in months)--/
Source of fair value 2003 0-12 13-24 25-36 >36
- -------------------------------------------------------------------------
<s> <c> <c> <c> <c> <c>
Prices actively quoted $ 163 $ 84 $ 68 $(14) $ 25
Prices provided by other
external sources (4) (6) (2) -- 4
Prices based on models
and other valuation
methods 22 5 2 -- 15
------------------------------------------------
Over-the-counter (OTC)
revenue (1) 181 83 68 (14) 44
Exchange contracts (2) 88 19 57 8 4
------------------------------------------------
Total $ 269 $ 102 $ 125 $ (6) $ 48
================================================
(1) The present value of net unrealized revenues to be received from
outstanding OTC contracts.
(2) Cash received associated with open Exchange contracts.
- -------------------------------------------------------------------------
</table>
Sempra Energy Resources
SER recorded net income of $94 million in 2003 and $60 million in 2002,
compared to a net loss of $27 million in 2001. Net income for 2003
includes the cumulative effect of the change in accounting principle,
which positively impacted SER's earnings by $9 million. See further
discussion of this in Note 1 of the notes to Consolidated Financial
Statements. Excluding this impact, the change in 2003 was primarily due
to increased volumes under SER's contract with the DWR, offset by
increased interest expense and start-up expenses related to SER's new
power plants. The increase in earnings for 2002 was primarily due to
SER's sales to the DWR that resumed in April 2002 at contract rates
17
under its long-term contract, compared to 2001 sales which were at less
than cost, and the recovery in 2002 of business interruption insurance
related to an outage at the El Dorado plant in 2001. Losses in 2001
arose from development costs of new generation projects and from selling
power to the DWR at below cost.
Sempra Energy International
Net income for SEI was $1 million, $26 million and $25 million for 2003,
2002 and 2001, respectively. The change in 2003 was primarily due to the
$50 million after-tax impairment of the carrying value of long-lived
assets at Frontier Energy (one of SEI's small U.S. utilities), partially
offset by increased equity earnings from its South American joint
ventures and a full year of earnings from the Gasaducto Bajanorte
pipeline in Mexico, which began operations in September 2002. The
increase for 2002 was primarily due to the after-tax charge of $25
million in 2001 following the surrender of the natural gas distribution
franchise in Nova Scotia, partially offset by reduced profitability from
SEI's Argentine subsidiaries in 2002. A discussion of the Argentine
economic issue is included in Notes 1 and 3 of the notes to Consolidated
Financial Statements.
Sempra Energy Solutions
SES recorded net income of $16 million in 2003, $21 million in 2002 and
$1 million in 2001. The change in 2003 was primarily due to reduced
profits from retail commodity sales, caused by higher wholesale energy
prices' making it more difficult for non-utility energy suppliers to
offer prices significantly below utility energy prices. The increase in
net income from 2001 to 2002 was primarily due to increased commodity
sales. In delivering electric and natural gas supplies to its commercial
and industrial customers, SES hedges its price exposure through the use
of exchange-traded and over-the-counter financial instruments. A summary
of SES' net unrealized revenues from trading activities follows:
- --------------------------------------------------------------------
Years ended December 31,
(Dollars in millions) 2003 2002
- -----------------------------------------------------------------
Balance at beginning of period $ 90 $ 55
Cumulative effect adjustment (2) --
Additions 75 90
Realized (85) (55)
----------------------------------
Balance at end of year $ 78 $ 90
==================================
- --------------------------------------------------------------------
18
The estimated fair values for SES' net unrealized trading assets as of
December 31, 2003, and the periods during which unrealized revenues are
expected to be realized, are (dollars in millions):
<table>
<caption>
Fair Market
Value at
December 31, /--Scheduled Maturity (in months)--/
Source of fair value 2003 0-12 13-24 25-36 >36
- -------------------------------------------------------------------------
<s> <c> <c> <c> <c> <c>
Exchange contracts $ 1 $ 1 $ -- $ -- $ --
Prices actively quoted 77 44 18 10 5
------------------------------------------------
Total $ 78 $ 45 $ 18 $ 10 $ 5
================================================
- ------------------------------------------------------------------
</table>
Sempra Energy Financial
SEF recorded net income of $41 million in 2003, $36 million in 2002 and
$28 million in 2001. The increase in 2003 was due to lower amortization
expense, partially offset by increased equity losses from certain
investments. The increase in 2002 was due to higher synthetic fuel
(Section 29) income tax credits compared to 2001.
See discussion of Section 29 income tax credits in Note 7 of the notes
to Consolidated Financial Statements. Whether SEF will invest in
additional affordable-housing properties will depend on Sempra Energy's
income tax position.
Parent and Other
Net losses for Parent and Other were $144 million, $93 million and $89
million in 2003, 2002 and 2001, respectively. The increase in 2003 was
due to the $26 million negative after-tax impact of the cumulative
effect of a change in accounting principle, the $21 million after-tax
write down of the carrying value of the assets of AEG and higher
interest expense as a result of the issuance of $1 billion of long-term
notes in late 2002 and early 2003. The adoption of Financial Accounting
Standards Board (FASB) Interpretation No. (FIN) 46, "Consolidation of
Variable Interest Entities" and the resulting consolidation of AEG is
discussed in Note 1 of the notes to Consolidated Financial Statements.
CAPITAL RESOURCES AND LIQUIDITY
The company's California Utility operations are the major source of
liquidity. Funding of other business units' capital expenditures is
significantly dependent on the California Utilities paying sufficient
dividends to Sempra Energy and on liquidity requirements at SET, which
fluctuate significantly.
At December 31, 2003, the company had $432 million in cash and $2.1
billion in available unused, committed lines of credit.
Management believes these amounts and cash flows from operations and new
security issuances will be adequate to finance capital expenditure
19
requirements (see Future Construction Expenditures and Investments for
forecasted capital expenditures for the next five years), shareholder
dividends, any new business acquisitions or start-ups, and other
commitments. If cash flows from operations were to be significantly
reduced or the company were to be unable to issue new securities under
acceptable terms, neither of which is considered likely, the company
would be required to reduce non-utility capital expenditures and
investments in new businesses. Management continues to regularly monitor
the company's ability to finance the needs of its operating, financing
and investing activities in a manner consistent with its intention to
maintain strong, investment-quality credit ratings.
At the California Utilities, cash flows from operations and from new and
refunding debt issuances are expected to continue to be adequate to meet
utility capital expenditure requirements and provide dividends to Sempra
Energy. However, if SDG&E receives CPUC approval of its plans to
purchase from SER a 550-megawatt (MW) generating facility to be
constructed in Escondido, California, the level of SDG&E's dividends to
Sempra Energy is expected to be significantly lower during the
construction of the facility to enable SDG&E to increase its equity in
preparation for the purchase of the completed facility. See Note 15 of
the notes to Consolidated Financial Statements for additional discussion
on the planned Palomar plant.
SET provides or requires cash as the level of its net trading assets
fluctuates with prices, volumes, margin requirements (which are
substantially affected by credit ratings and commodity price
fluctuations) and the length of its various trading positions. Its
status as a source or use of cash also varies with its level of
borrowing from its own sources. SET's intercompany borrowings were
$359 million at December 31, 2003, down from $418 million at December
31, 2002. SET's external debt was $115 million at December 31, 2002.
There was no external debt outstanding at December 31, 2003. Company
management continuously monitors the level of SET's cash requirements in
light of the company's overall liquidity. Such monitoring includes the
procedures discussed in "Market Risk."
SELNG will require funding for its planned development of LNG receiving
facilities. While funding from the company is expected to be adequate
for these requirements, the company may decide to use project financing
if that is believed to be advantageous.
SER's projects are expected to be financed through a combination of
project financing, SER's borrowings and funds from the company.
SEI is expected to require funding from the company and/or external
sources to continue the expansion of its existing natural gas
distribution operations in Mexico and its planned development of
pipelines to serve LNG facilities expected to be developed in Baja
California, Mexico and Hackberry, Louisiana.
In the longer term, SEF is expected to again be a net provider of cash
through reductions of consolidated income tax payments resulting from
its investments in affordable housing and synthetic fuel. However, that
was not true in 2003 and will not be true in the near term, while the
company is in an alternative minimum tax position.
20
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by operating activities totaled $1.1 billion, $1.4
billion and $0.7 billion for 2003, 2002 and 2001, respectively.
The decrease in cash flows from operations in 2003 compared to 2002 was
primarily attributable to a decrease in overcollected regulatory
balancing accounts at the California Utilities, partially offset by
higher accounts payable in 2003 primarily due to timing.
The increase in cash flows from operations in 2002 compared to 2001 was
attributable to SDG&E's collection of balancing accounts (see Note 1 of
the notes to Consolidated Financial Statements) and the change to a net
income tax liability position at December 31, 2002 compared to a net
income tax asset position at the end of 2001. In addition, cash flows
from operations increased due to less growth in net trading assets and
the payment of higher trade payables in 2001. These increases were
partially offset by a decrease in deferred income taxes and investment
tax credits and higher accounts receivable in 2002 resulting from an
increase in SoCalGas' natural gas commodity costs for the fourth quarter
of 2002 compared to the corresponding period in the prior year.
During 2003, the company made pension plan contributions of $27 million
for the 2003 plan year. Contributions of $3 million were made in each of
2002 and 2001.
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash used in investing activities totaled $1.3 billion, $1.7 billion
and $1.0 billion for 2003, 2002 and 2001, respectively.
The decrease in cash used in investing activities in 2003 compared to
2002 was primarily due to lower capital expenditures for the
Termoelectrica de Mexicali (TDM) power plant and lower investments in
U.S. Treasury obligations made in connection with the Mesquite synthetic
lease, higher distributions from investments in South America, and SET's
higher acquisition activities in 2002.
The increase in cash used in investing activities in 2002 compared to
2001 was primarily due to increased capital expenditures, primarily at
SER and the California Utilities, and SET's acquisition activities.
Expenditures for property, plant and equipment, and for those
investments that effectively constitute similar expenditures, are
presented in the following table.
(in millions)
--------------------------------
2003 $1,228
2002 $1,524
2001 $1,179
2000 $ 963
1999 $ 705
--------------------------------
The 2002 amount is larger than the other years due to the construction
of the SER power plants.
21
Capital Expenditures for Property, Plant and Equipment
Capital expenditures were $1.0 billion in 2003 compared with $1.2
billion in 2002 and $1.1 billion in 2001. The decrease in 2003 from
2002 was due primarily to lower capital expenditures for the TDM power
plant.
The California Utilities
Capital expenditures for property, plant, and equipment by the
California Utilities were $762 million in 2003 compared to $731 million
in 2002 and $601 million in 2001. The increase in 2003 was primarily
due to $40 million of capital costs associated with the Southern
California wildfires in October 2003. The increase in 2002 was due to
additions to SDG&E's natural gas and electric distribution systems,
improvements to SoCalGas' distribution system, and expansion of pipeline
capacity to meet increased demand by electric generators and by
commercial and industrial customers.
Sempra Energy Resources
SER acquires, develops and operates power plants throughout the U.S. and
Mexico. The following table lists the MW capacity of each power plant
currently in operation. All of the plants are natural gas-fired
combined-cycle facilities, except for Twin Oaks Power, which is coal-
fired.
Generating
Power Plant Capacity Location
- --------------------- ----------- -----------------------
Mesquite Power 1,250 Arlington, AZ
Termoelectrica De Mexicali 600 Mexicali, Mexico
Twin Oaks Power 305 Bremond, TX
Elk Hills Power (50% owned) 275* Bakersfield, CA
El Dorado (50% owned) 240* Boulder City, NV
-----
Total MW in operation 2,670
=====
* SER's share
Other potential plants, including the Palomar plant, which is discussed
above and in Note 15 of the notes to Consolidated Financial Statements,
are in various stages of consideration, permitting or site-acquisition.
Others have completed these stages but construction is awaiting market
changes that will permit advance signing of long-term contracts at
adequate margins.
In 2003, TDM commenced operations of its 600-MW, $350 million power
plant near Mexicali, Baja California, Mexico. SER invested $34 million
and $158 million in TDM in 2003 and 2002, respectively.
Operations also commenced in 2003 for the wholly owned 1,250-MW Mesquite
Power plant, located near Phoenix, Arizona. Prior to 2004, this project
was financed through a synthetic lease agreement. See further discussion
of the consolidation of Mesquite Trust, the owner of Mesquite Power, in
Note 1 of the notes to Consolidated Financial Statements. In January
2004, the company terminated the lease and purchased the assets of
Mesquite Trust for $631 million.
22
Also in 2003, SER made turbine payments of $69 million for power plants
under development.
In October 2002, SER purchased the 305-MW, coal-fired Twin Oaks power
plant for $120 million.
See Note 2 of the notes to Consolidated Financial Statements for
additional discussion on SER's recent power plant investments and
acquisitions.
Sempra Energy LNG
In April 2003, SELNG completed its previously announced acquisition of
the proposed Cameron LNG project from a subsidiary of Dynegy, Inc.
In December 2003, SELNG and Shell International Gas Limited announced
plans to form a 50/50 joint venture to build, own and operate Energia
Costa Azul, an LNG receiving terminal in Baja California. In December
2003, SELNG signed a Heads of Agreement (HOA) for the supply of 500
million cubic feet of gas a day from Indonesia's Tangguh LNG
liquefaction facility to Energia Costa Azul. The non-binding HOA is
expected to be the precursor to a full 20-year purchase/supply
agreement. In 2003, SELNG invested $42 million in Cameron LNG and $10
million in Energia Costa Azul. See Note 2 of the notes to Consolidated
Financial Statements for additional discussion on the LNG projects.
Sempra Energy International
In 2002, SEI completed construction of the 140-mile Gasoducto Bajanorte
Pipeline that connects the Rosarito Pipeline south of Tijuana, Mexico
with a pipeline built by PG&E Corporation that connects to Arizona. SEI
invested $17 million, $37 million and $74 million in the pipeline in
2003, 2002 and 2001, respectively, for a total through December 31, 2003
of $128 million.
Three of SEI's Mexican subsidiaries build and operate natural gas
distribution systems in Mexicali, Chihuahua and the La Laguna-Durango
zone in north-central Mexico. On February 7, 2003, SEI purchased the
remaining minority interests in all of its Mexican subsidiaries. As a
result, as of December 31, 2003, SEI owns 100 percent of all its Mexican
subsidiaries. Through December 31, 2003, the distribution companies have
made capital expenditures aggregating $127 million. Total capital
expenditures for these subsidiaries were $15 million in both 2003 and
2002, and $19 million in 2001.
Sempra Energy Trading
In 2003, SET spent $27 million for the development of Bluewater Gas
Storage, LLC. See Note 2 of the notes to Consolidated Financial
Statements for further discussion.
Investments
Investments and acquisition costs were $202 million, $429 million and
$111 million for 2003, 2002 and 2001, respectively. The decrease from
2003 to 2002 was due to lower investments in U.S. Treasury obligations
made in connection with the Mesquite synthetic lease in 2003 and SET's
higher acquisition activities in 2002. The increase in 2002 was due to
23
the increase in requirements for the synthetic lease financing for the
construction of the Mesquite Power plant and SET's acquisition of new
businesses. For a discussion of the synthetic lease, see Note 2 of the
notes to Consolidated Financial Statements.
Sempra Energy Trading
During 2002, SET completed acquisitions that added base metals trading
and warehousing to its trading business. The purchase price of the 2002
acquisitions totaled $119 million, net of cash acquired. For additional
discussion related to the SET acquisitions, see Note 2 of the notes to
Consolidated Financial Statements.
Sempra Energy Resources
In July 2003, the 550-MW Elk Hills power plant near Bakersfield,
California began commercial operations. Elk Hills, an unconsolidated
subsidiary, is jointly owned with Occidental Energy Ventures Corporation
(Occidental) and supplies electricity to California. During 2003, 2002
and 2001, SER invested $47 million, $39 million and $91 million,
respectively. Information concerning litigation with Occidental is
provided in Note 15 of the notes to Consolidated Financial Statements.
Other
See further discussion of investing activities, including the $197
million foreign currency exchange adjustment relating to Argentina, in
Notes 2 and 3 of the notes to Consolidated Financial Statements.
Future Construction Expenditures and Investments
The company expects to make capital expenditures of $1.1 billion in
2004. Significant capital expenditures are expected to include $750
million for California utility plant improvements and $170 million for
the development of the two LNG regasification terminals. These
expenditures are expected to be financed by cash flows from operations
and security issuances.
Over the next five years, the company expects to make capital
expenditures of $4.4 billion at the California Utilities and has
identified $2.1 billion of capital expenditures at the other
subsidiaries, including the development of the LNG facilities and
construction of power plants by SER. Both amounts include the Palomar
plant (see Note 15 of the notes to Consolidated Financial Statements for
further discussion) which would be constructed by SER and then purchased
by SDG&E.
Construction, investment and financing programs are periodically
reviewed and revised by the company in response to changes in economic
conditions, competition, customer growth, inflation, customer rates, the
cost of capital, and environmental and regulatory requirements. In
addition, the excess of existing power plants and other energy-related
facilities compared to market demand in certain regions of the country
and/or the plants that are owned by companies in financial distress may
provide the company with opportunities to acquire existing power plants
instead of or in addition to new construction.
24
The company's level of construction expenditures and investments in the
next few years may vary substantially, and will depend on the
availability of financing and business opportunities providing desirable
rates of return. The company intends to finance its capital expenditures
in a manner that will maintain its strong investment-grade ratings and
capital structure.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash provided by financing activities totaled $109 million, $138
million and $275 million for 2003, 2002 and 2001, respectively.
The cash provided by financing activities decreased in 2003 due to
reduced long-term borrowings and higher repayments on long-term debt and
short-term borrowings, partially offset by an increase in stock
issuances.
Cash flows from financing activities decreased in 2002 from 2001 due
primarily to the higher temporary drawdowns of lines of credit in 2001,
partially offset by increased debt issuances in 2002.
Long-Term and Short-Term Debt
In 2003, the company issued $900 million in long-term debt, consisting
of $400 million of senior unsecured notes and $500 million of first
mortgage bonds issued by SoCalGas.
Repayments on long-term debt in 2003 included $100 million of the
borrowings under a line of credit and $66 million of rate-reduction
bonds. In 2003, SEF repaid $36 million of debt incurred to acquire
limited partnership interests. Repayments also included $325 million of
SoCalGas' first mortgage bonds. In addition, $70 million of SoCalGas'
$75 million medium-term notes were put back to the company. The
remaining $5 million matures in 2028.
In January 2004, SoCalGas optionally redeemed its $175 million 6.875%
first mortgage bonds. Also in January 2004, SER purchased the assets of
Mesquite Trust, thereby extinguishing $630 million of debt outstanding.
The net short-term debt reduction of $518 million in 2003 primarily
consisted of the paydown of commercial paper.
In 2002, the company issued $1.2 billion in long-term debt, including
$600 million of equity units at Sempra Energy and $250 million of 4.80%
first mortgage bonds at SoCalGas. Each equity unit consists of $25
principal amount of the company's 5.60% senior notes due May 17, 2007
and a contract to purchase for $25 on May 17, 2005, between .8190 and
..9992 of a share of the company's common stock, with the precise number
within that range to be determined by the then-prevailing market price.
In addition, SER drew down $300 million against a line of credit to
finance construction projects and acquisitions.
Repayments on long-term debt in 2002 of $479 million included $200
million borrowed under a line of credit, $138 million of first mortgage
bonds and $66 million of rate-reduction bonds.
The net short-term debt reduction of $307 million in 2002 primarily
consisted of the paydown of commercial paper.
25
Repayments on long-term debt in 2001 included $150 million of first
mortgage bonds, $66 million of rate-reduction bonds and $120 million of
unsecured debt.
The net short-term debt increase of $310 million in 2001 primarily
represented borrowings through Global. Funds were used to finance
construction costs of various power plant and pipeline projects in
California, Arizona and Mexico.
In August 2003 Global replaced a $950 million revolving line of credit
with two syndicated revolving credit agreements, permitting aggregate
revolving credit borrowings of $1 billion. Global had no commercial
paper outstanding at December 31, 2003 and $422 million of commercial
paper, guaranteed by Sempra Energy, outstanding at December 31, 2002.
See Notes 1, 4 and 5 of the notes to Consolidated Financial Statements
for further discussion of debt activity and lines of credit.
Capital Stock Transactions
On October 14, 2003, the company completed a common stock offering of
16.5 million shares priced at $28 per common share, resulting in net
proceeds of $448 million. The proceeds were used primarily to pay off
short-term debt.
In April and May of 2002, the company publicly offered and sold $600
million of "Equity Units," as discussed above.
Dividends
Dividends paid on common stock amounted to $207 million in 2003, $205
million in 2002 and $203 million in 2001.
The payment of future dividends and the amount thereof are within the
discretion of the company's board of directors. The CPUC's regulation of
the California Utilities' capital structure limits the amounts that are
available for loans and dividends to the company from the California
Utilities. At December 31, 2003, SDG&E and SoCalGas could have provided
a total (combined loans and dividends) of $290 million and $175 million,
respectively, to Sempra Energy. At December 31, 2003, SDG&E and SoCalGas
had actual loans, net of payables, to Sempra Energy of $75 million and
$21 million, respectively.
Capitalization
Total capitalization, including the current portion of long-term debt
and excluding the rate-reduction bonds (which are non-recourse to the
company) at December 31, 2003 was $9.1 billion. The debt-to-
capitalization ratio was 55 percent at December 31, 2003. Significant
changes in capitalization during 2003 included the October 2003 common
stock offering, long-term borrowings and repayments, income and
dividends.
26
Commitments
The following is a summary of the company's principal contractual
commitments at December 31, 2003. Trading liabilities are not included
herein as such derivative transactions are primarily hedged against
trading assets. In addition, liabilities reflecting fixed-price
contracts and other derivatives are excluded as they are primarily
offset against regulatory assets at the California Utilities. Additional
information concerning commitments is provided above and in Notes 4, 5,
11 and 15 of the notes to Consolidated Financial Statements.
<table>
<caption>
By Period
- -----------------------------------------------------------------------------------
2005 2007
(Dollars in millions) and and
Description 2004 2006 2008 Thereafter Total
- -----------------------------------------------------------------------------------
<s> <c> <c> <c> <c> <c>
Short-term debt $ 28 $ -- $ -- $ -- $ 28
Long-term debt 1,433 499 690 2,652 5,274
Due to unconsolidated affiliates -- -- 62 300 362
Preferred stock of subsidiaries
subject to mandatory
redemption 1 3 20 -- 24
Operating leases 97 162 145 213 617
Purchased-power contracts 214 457 458 2,235 3,364
Natural gas contracts 988 358 46 207 1,599
Construction commitments 19 16 14 48 97
Twin Oaks coal supply 29 54 50 322 455
SONGS decommissioning 20 22 9 265 316
Asset retirement obligations 4 8 2 7 21
Environmental commitments 23 38 -- -- 61
Other -- -- 20 55 75
---------------------------------------------------
Totals $ 2,856 $ 1,617 $ 1,516 $ 6,304 $12,293
===================================================
</table>
27
Credit Ratings
Several credit ratings of the company and its subsidiaries declined in
2003, but remain investment grade. As of January 31, 2004, credit
ratings for Sempra Energy and its primary subsidiaries were as follows:
S&P* Moody's** Fitch
- ----------------------------------------------------------------
SEMPRA ENERGY
Unsecured debt BBB+ Baa1 A
Trust preferred securities BBB- Baa2 A-
------------------------------------
SDG&E
Secured debt A+ A1 AA
Unsecured debt A- A2 AA-
Preferred stock BBB+ Baa1 A+
Commercial paper A-1 P-1 F1+
------------------------------------
SOCALGAS
Secured debt A+ A1 AA
Unsecured debt A- A2 AA-
Preferred stock BBB+ Baa1 A+
Commercial paper A-1 P-1 F1+
------------------------------------
PACIFIC ENTERPRISES
Preferred stock BBB+ - A
------------------------------------
GLOBAL
Unsecured debt guaranteed
by Sempra Energy - Baa1 -
Commercial paper guaranteed
by Sempra Energy A-2 P-2 F1
-----------------------------
* Standard & Poor's
** Moody's Investor Services, Inc.
As of January 31, 2004, the company has a stable outlook rating from all
three credit rating agencies.
FACTORS INFLUENCING FUTURE PERFORMANCE
The California Utilities provide a generally stable base of earnings for
the company. Earnings growth and variability results primarily from
activities at SET, SER, SELNG and SEI. Developments and pending matters
concerning the factors influencing future performance are summarized
below. Notes 13, 14 and 15 of the notes to Consolidated Financial
Statements describe events in the deregulation of California's electric
and natural gas industries and various FERC, SET and income tax issues.
California Utilities
Electric Industry Restructuring and Electric Rates
Subsequent to the electric capacity shortages of 2000-2001, SDG&E's
service territory had and continues to have an adequate supply of
electricity. However, various projections of electricity demand in
SDG&E's service territory indicate that, without additional electrical
generation and transmission and reductions in electrical usage,
beginning in 2005, electricity demand could begin to outstrip available
resources. SDG&E has issued a request for proposals (RFP) to meet the
electric capacity shortfall, estimated at 69 MW in 2005 and increasing
annually by approximately 100 MW, and has filed a proposed plan at the
CPUC for meeting these capacity requirements. See Note 13 of the notes
to Consolidated Financial Statements for additional information
regarding the RFP results.
28
Through December 31, 2003, the operating and capital costs of SONGS
Units 2 and 3 were recovered through the ICIP mechanism which allowed
SDG&E to receive 4.4 cents per kilowatt-hour for SONGS generation. Any
differences between these costs and the incentive price affected net
income. For the year ended December 31, 2003, ICIP contributed $53
million to SDG&E's net income. Beginning in 2004 the CPUC has provided
for traditional rate-making treatment, under which the SONGS ratebase
would start over at January 1, 2004, essentially eliminating earnings
from SONGS except from future increases in ratebase.
See additional discussion of this and related topics, including the
CPUC's adjustment to its plan for deregulation of electricity, in Note
13 of the notes to Consolidated Financial Statements.
Natural Gas Restructuring and Rates
In December 2001 the CPUC issued a decision related to natural gas
industry restructuring; however, implementation has been delayed. A CPUC
decision could be issued in the first quarter of 2004. With the
California Utilities' natural gas supply contracts nearing expiration,
the company believes that regulation needs to consider sufficiently the
adequacy and diversity of supplies to California, transportation
infrastructure and cost recovery thereof, hedging opportunities to
reduce cost volatility, and programs to encourage and reward
conservation. Additional information on natural gas industry
restructuring is provided in Note 14 of the notes to Consolidated
Financial Statements.
CPUC Investigation of Compliance with Affiliate Rules
On February 27, 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to ensure that they have
complied with statutes and CPUC decisions in the management, oversight
and operations of their companies. In September 2003, the CPUC suspended
the procedural schedule until it completes an independent audit to
evaluate energy-related holding company systems and affiliate activities
undertaken by Sempra Energy within the service territories of SDG&E and
SoCalGas. The audit will cover years 1997 through 2003, is expected to
commence in March 2004 and should be completed by the end of 2004. In
accordance with existing CPUC requirements, the California Utilities'
transactions with other Sempra Energy affiliates have been audited by an
independent auditing firm each year, with results reported to the CPUC,
and there have been no material adverse findings in those audits.
Additional information on the CPUC's investigation is provided in Note
14 of the notes to Consolidated Financial Statements.
Cost of Service Filing
The California Utilities have filed cost of service applications with
the CPUC, seeking rate increases designed to reflect forecasts of 2004
capital and operating costs. The California Utilities are requesting
revenue increases of $121 million. On December 19, 2003, settlements
were filed with the CPUC for SoCalGas and for SDG&E that, if approved,
would resolve most of the cost of service issues. A CPUC decision is
likely in the second quarter of 2004. The California Utilities have also
filed for continuation through 2004 of existing PBR mechanisms for
service quality and safety that would otherwise expire at the end of
29
2003. In January 2004, the CPUC issued a decision that extended 2003
service and safety targets through 2004, but deferred action on applying
any rewards or penalties for performance relative to these targets to a
decision to be issued later in 2004 in a second phase of these
applications. This is discussed in Note 14 of the notes to Consolidated
Financial Statements.
Sempra Energy Global Enterprises
Electric-Generation Assets
As discussed in "Cash Flows From Investing Activities," the company has
been involved in the development of several electric-generation projects
that will significantly impact the company's future performance. SER has
2,670 MW (its share) of new generation in operation, including the 550-
megawatt Elk Hills power project, the 1,250-megawatt Mesquite Power
plant, the 600-megawatt TDM power plant, the 305-megawatt Twin Oaks
power plant and the 480-megawatt El Dorado Energy. Except for Elk Hills,
the plants' electricity is available for markets in California, Arizona,
Texas and Mexico and may be used to supply power to California under
SER's agreement with the DWR.
Investments
As discussed in "Cash Flows From Investing Activities" above, the
company's investments will significantly impact the company's future
performance. During 2002, SET completed acquisitions that added base
metals trading and warehousing to its trading business. These
acquisitions included Sempra Metals Limited and Henry Bath & Son
Limited. In addition, SET acquired assets of Sempra Metals &
Concentrates Corp. and the U.S. warehousing business of Henry Bath,
Inc., and SER acquired the Twin Oaks Power plant.
SELNG is in the process of developing Energia Costa Azul, an LNG
receiving terminal in Baja California, Mexico, and the Cameron LNG
receiving terminal in Hackberry, Louisiana. This is discussed in Note 2
of the notes to Consolidated Financial Statements. The viability and
future profitability of this business unit is dependent upon numerous
factors, including the relative prices of natural gas in North America
and from LNG suppliers located elsewhere, negotiating sale and supply
contracts at adequate margins, and completing cost-effective
construction of the required facilities.
The Argentine economic decline and government responses (including
Argentina's unilateral, retroactive abrogation of utility agreements
early in 2002) are continuing to adversely affect the company's
investment in two Argentine utilities. In September 2002, SEI initiated
proceedings under the 1994 Bilateral Investment Treaty between the
United States and Argentina for recovery of the diminution of the value
of its Argentine investments resulting from governmental actions. SEI
has made a request for arbitration to the International Center for
Settlement of Investment Disputes. Additional information regarding this
proceeding and related insurance is provided in Note 3 of the notes to
Consolidated Financial Statements.
30
MARKET RISK
Market risk is the risk of erosion of the company's cash flows, net
income, asset values and equity due to adverse changes in prices for
various commodities, and in interest and foreign-currency rates.
The company has adopted corporate-wide policies governing its market
risk management and trading activities. Assisted by the company's Energy
Risk Management Group (ERMG), the company's Energy Risk Management
Oversight Committee (ERMOC), consisting of senior officers, oversees
company-wide energy risk management activities and monitors the results
of trading activities to ensure compliance with the company's stated
energy risk management and trading policies. Utility management receives
daily information on positions and the ERMG receives information
detailing positions creating market and credit risk from all company
affiliates (on a delayed basis as to the California Utilities). The ERMG
independently measures and reports the market and credit risk associated
with these positions. In addition, all affiliates have groups that
monitor 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 interval. The company has adopted the variance/covariance
methodology in its calculation of VaR, and uses both the 95-percent and
99-percent confidence intervals. VaR is calculated independently by the
ERMG for all company affiliates. Historical volatilities and
correlations between instruments and positions are used in the
calculation.
Following is a summary of SET's trading VaR profile (using a one-day
holding period) in millions of dollars:
95% 99%
- ------------------------------------------------------
December 31, 2003 $ 2.6 $ 3.7
2003 average $ 6.5 $ 9.2
December 31, 2002 $ 4.6 $ 6.5
2002 average $ 6.2 $ 8.7
- ------------------------------------------------------
The California Utilities use energy and gas derivatives to manage
natural gas and energy price risk associated with servicing their load
requirements. The use of derivative financial instruments by the
California Utilities is subject to certain limitations imposed by
company policy and regulatory requirements.
See the revenue recognition discussion in Notes 1 and 10 and the
additional market risk information regarding derivative instruments in
Note 10 of the notes to Consolidated Financial Statements.
The following discussion of the company's primary market risk exposures
as of December 31, 2003 includes a discussion of how these exposures are
managed.
31
Commodity Price Risk
Market risk related to physical commodities is created by volatility in
the prices and basis of certain commodities. The company's market risk
is impacted by changes in volatility and liquidity in the markets in
which these commodities or related financial instruments are traded. The
company's various affiliates are exposed, in varying degrees, to price
risk primarily in the petroleum, metals, natural gas 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 its worldwide
trading activities in natural gas, electricity, petroleum products,
metals and other commodities. As a result, SET is exposed to price
volatility in the related domestic and international 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.
Sempra Energy Solutions
SES derives a substantial portion of its revenue from delivering
electric and natural gas supplies to its commercial and industrial
customers. As a result, SES is exposed to price volatility in the
related domestic markets. Its contracts are written in a manner intended
to preserve margin and carry minimal market risk. Exchange-traded and
over-the-counter instruments are used to hedge contracts. The
derivatives and financial instruments used to hedge the transactions
include swaps, forwards, futures, options or combinations thereof.
California Utilities
With respect to the California Utilities, market risk exposure is
limited due to CPUC authorized rate recovery of commodity purchase,
sale, intrastate transportation and storage activity. However, the
California Utilities may, at times, be exposed to market risk as a
result of SDG&E's natural gas PBR and electric procurement activities or
SoCalGas' GCIM, which are discussed in Notes 13 and 14 of the notes to
Consolidated Financial Statements. They manage their risk within the
parameters of the company's market risk management and trading
framework. As of December 31, 2003, the total VaR of the California
Utilities' natural gas and electric positions was not material. In
addition, if commodity prices rose too rapidly, it is likely that
volumes would decline. This would increase the per-unit fixed costs,
which could lead to further volume declines, leading to increased per-
unit fixed costs and so forth.
Interest Rate Risk
The company is exposed to fluctuations in interest rates primarily as a
result of its long-term debt. The company historically has funded
utility operations through long-term debt issues with fixed interest
rates and these interest rates are recovered in utility rates. As a
32
result, some recent debt offerings 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, 2003, the California Utilities had $1.8 billion of
fixed-rate debt and $0.3 billion of variable-rate debt. Interest on
fixed-rate utility debt is fully recovered in rates on a historical cost
basis and interest on variable-rate debt is provided for in rates on a
forecasted basis. At December 31, 2003, utility fixed-rate debt had a
one-year VaR of $280 million and utility variable-rate debt had a one-
year VaR of $11 million. Non-utility debt (fixed-rate and variable-rate)
subject to VaR modeling totaled $2.6 billion at December 31, 2003, with
a one-year VaR of $176 million.
At December 31, 2003, the notional amount of interest-rate swap
transactions totaled $650 million. See Note 5 of the notes to
Consolidated Financial Statements for further information regarding
interest rate swap transactions.
In addition the company is ultimately subject to the effect of interest-
rate fluctuation on the assets of its pension plan and other
postretirement plans.
Credit Risk
Credit risk is the risk of loss that would be incurred as a result of
nonperformance by counterparties of their contractual obligations. As
with market risk, the company has adopted corporate-wide policies
governing the management of credit risk. Credit risk management is
performed by the ERMG and the California Utility's credit department and
overseen by the ERMOC. Using rigorous models, the groups continuously
calculate current and potential credit risk to counterparties to monitor
actual balances in comparison to approved limits. The company avoids
concentration of counterparties whenever possible and management
believes its credit policies with regard to counterparties significantly
reduce overall credit risk. These policies include an evaluation of
prospective counterparties' financial condition (including credit
ratings), collateral requirements under certain circumstances, the use
of standardized agreements that allow for the netting of positive and
negative exposures associated with a single counterparty and other
security such as lock-box liens and downgrade triggers. At December 31,
2003, SET had 17 customers that owed $20 million to $100 million each.
The majority of these accounts related to amounts invoiced for delivered
physical energy commodities and were settled within 30 days. The company
believes that adequate reserves have been provided for counterparty
nonperformance.
As described in Note 15 of the notes to Consolidated Financial
Statements, SER has a contract with the DWR to supply up to 1,900 MW of
power to the state over 10 years, beginning in 2001. This contract
results in a significant potential nonperformance exposure with a single
counterparty; however, this risk has been addressed and mitigated by the
terms of the contract.
The company monitors credit risk through a credit approval process and
the assignment and monitoring of credit limits. These credit limits are
33
established based on risk and return considerations under terms
customarily available in the industry.
The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall cost
of borrowing. The company would be exposed to interest-rate fluctuations
on the underlying debt should counterparties to the agreement not
perform. See "Interest Rate Risk" for additional information regarding
the company's use of interest-rate swap agreements.
Foreign Currency Rate Risk
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. As a result of the
devaluation of the Argentine peso that began at the end of 2001, SEI has
reduced the carrying value of its investment downward by a cumulative
total of $197 million as of December 31, 2003. These non-cash
adjustments continue to occur based on fluctuations in the Argentine
peso and have not affected net income, but have affected other
comprehensive income (loss) and accumulated other comprehensive income
(loss). See further discussion in Note 3 of the notes to Consolidated
Financial Statements.
In appropriate instances, the company may attempt to limit its exposure
to changing foreign exchange rates through both operational and
financial market actions. Financial actions may include entering into
forward, option and swap contracts to hedge existing exposures, firm
commitments and anticipated transactions. As of December 31, 2003, the
company had no significant arrangements of this type.
CRITICAL ACCOUNTING POLICIES AND KEY NON-CASH PERFORMANCE INDICATORS
Certain accounting policies are viewed by management as critical because
their application is the most relevant, judgmental and/or material to
the company's financial position and results of operations, and/or
because they require the use of material judgments and estimates.
The company's most significant accounting policies are described in Note
1 of the notes to Consolidated Financial Statements. The most critical
policies, all of which are mandatory under generally accepted accounting
principles and the regulations of the Securities and Exchange
Commission, are the following:
SFAS 5 "Accounting for Contingencies," establishes the amounts and
timing of when the company provides for contingent losses.
Details of the company's issues in this area are discussed in Note
15 of the notes to Consolidated Financial Statements.
SFAS 71 "Accounting for the Effects of Certain Types of
Regulation," has a significant effect on the way the California
Utilities record assets and liabilities, and the related revenues
and expenses, that would not be recorded absent the principles
contained in SFAS 71.
SFAS 109 "Accounting for Income Taxes," governs the way the
company provide for income taxes. Details of the company's issues
34
in this area are discussed in Note 7 of the notes to Consolidated
Financial Statements.
SFAS 123 "Accounting for Stock-Based Compensation" and SFAS 148
"Accounting for Stock-Based Compensation - Transition and
Disclosure," give companies the choice of recognizing a cost at
the time of issuance of stock options or merely disclosing what
that cost would have been and not recognizing it in its financial
statements. The company, like most U.S. companies, has elected the
disclosure option for all options that are so eligible. The effect
of this is discussed in Note 1 of the notes to Consolidated
Financial Statements.
SFAS 133 "Accounting for Derivative Instruments and Hedging
Activities," SFAS 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities" and SFAS 149
"Amendment of Statement 133 on Derivative Instruments and Hedging
Activities," have a significant effect on the balance sheets of
SET, SES and the California Utilities but have no significant
effect on the California Utilities' income statements because of
the principles contained in SFAS 71. The effect on SET's income
statement is discussed in Note 10 of the notes to Consolidated
Financial Statements.
EITF 02-3 "Issues Involved in Accounting for Derivative Contracts
held for Trading Purposes and Contracts Involved in Energy Trading
and Risk Management Activities," has a significant effect on the
financial statements of SET and SES, both of which had been
recording transactions in accordance with EITF Issue 98-10, which
was eliminated by EITF Issue 02-3. However, most of the trading
assets and liabilities of SET and SES will now be covered by SFAS
133, SFAS 138 and SFAS 149, which have a similar effect.
SFAS 52 "Foreign Currency Translation" is critical to the
company's international operations and its application is
materially affected by the company's treatment of certain loans to
the Argentine affiliates as equity (based on expectations that
repayment will not occur in the near future).
FIN 46, "Consolidation of Variable Interest Entities an
interpretation of ARB No. 51," is critical to the company's
consolidation of variable interest entities (VIEs) in its
financial statements. FIN 46 requires the company to consolidate
VIEs for which it is the primary beneficiary, as defined, and
deconsolidate any previously consolidated affiliates that do not
meet the consolidation criteria of FIN 46. Sempra Energy has
identified two VIEs for which FIN 46 deems it to be the primary
beneficiary. One of the VIEs is the owner of the Mesquite Power
plant. The other VIE relates to an investment in an unconsolidated
subsidiary, AEG. Sempra Energy consolidated these entities in its
financial statements at December 31, 2003. In accordance with FIN
46, the company deconsolidated a wholly owned subsidiary trust
from its financial statements at December 31, 2003. See further
discussion in Note 1 of the notes to Consolidated Financial
Statements.
35
In connection with the application of these and other accounting
policies, the company makes estimates and judgments about various
matters. The most significant of these involve:
The calculation of fair or realizable values (including
the likelihood of fully realizing the value of the
investments in Argentina under the Bilateral Investment
Treaty and the realizable value of Frontier Energy and
AEG, all of which are discussed in Note 1 of the notes to
Consolidated Financial Statements).
The collectibility of receivables, regulatory assets,
deferred tax assets and other assets.
The costs to be incurred in fulfilling certain contracts
that have been marked to market.
The various assumptions used in actuarial calculations for
pension and other postretirement benefit plans.
The likelihood of recovery of various deferred tax assets.
The probable costs to be incurred in the resolution of
litigation.
Differences between estimates and actual amounts have had
significant impacts in the past and are likely to do so in the
future.
As discussed elsewhere herein, the company uses exchange quotations or
other third-party pricing to estimate fair values whenever possible.
When no such data is available, it uses internally developed models and
other techniques. The assumed collectibility of receivables considers
the aging of the receivables, the creditworthiness of customers and the
enforceability of contracts, where applicable. The assumed
collectibility of regulatory assets considers legal and regulatory
decisions involving the specific items or similar items. The assumed
collectibility of other assets considers the nature of the item, the
enforceability of contracts where applicable, the creditworthiness of
the other parties and other factors. Costs to fulfill contracts that are
carried at fair value are based on prior experience. Actuarial
assumptions are based on the advice of the company's independent
actuaries. The likelihood of deferred tax recovery is based on analyses
of the deferred tax assets and the company's expectation of future
financial and/or taxable income, based on its strategic planning.
Choices among alternative accounting policies that are material to the
company's financial statements and information concerning significant
estimates have been discussed with the audit committee of the board of
directors.
Key non-cash performance indicators for the company's subsidiaries
include numbers of customers, and quantities of natural gas and
electricity sold for the California Utilities, and plant availability
factors at SER's generating plants. SET does not use non-cash
performance factors. Its key indicators are profit margins by product
line and by geographic area. The California Utilities' information is
provided in "Introduction" and "Results of Operations." For competitive
36
reasons, SER does not disclose its plant availability factors, but
considers them to be very good, except for the second unit at Mesquite,
which just began generation in December 2003. The following tables
provide the SET information.
Trading Margin Years ended December 31,
(Dollars in millions) 2003 2002
- --------------------------------------------------------------
Geographical:
North America $ 366 $ 311
Europe/Asia 172 165
--------------------------
Total $ 538 $ 476
--------------------------
Product Line:
Gas $ 141 $ 173
Power 69 89
Oil - Crude and Products 128 74
Metals 96 78
Other 104 62
--------------------------
Total $ 538 $ 476
- --------------------------------------------------------------
Other than its two small natural gas utilities in the eastern United
States, SEI's only consolidated operations are in Mexico. The three
local natural gas distribution utilities have increased their customer
count to almost 100,000 and their sales volume to almost 50 million
cubic feet per day in 2003. The two pipelines had sales volumes of
almost 450 million cubic feet per day in 2003.
NEW ACCOUNTING STANDARDS
Relevant pronouncements that have recently become effective and have had
a significant effect on the company are SFAS 143, 144, 148, 149 and 150,
FIN 45 and 46, and EITF 02-3. They are described in Note 1 of the notes
to Consolidated Financial Statements. Pronouncements that could have a
material effect on the company are described below.
EITF Issue 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities": In accordance with the EITF's
rescission of Issue 98-10, the company no longer recognizes energy-
related contracts under mark-to-market accounting unless the contracts
meet the requirements stated under SFAS 133, "Accounting for Derivative
Instruments and Hedging Activities," and its successors, which is the
case for a substantial majority of the company's contracts. Upon
adoption of this consensus on January 1, 2003, the company recorded the
initial effect of rescinding Issue 98-10 as a cumulative effect of a
change in accounting principle, which reduced after-tax earnings by $29
million. This is further described in Note 1 of the notes to
Consolidated Financial Statements.
SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143,
requires entities to record the fair value of liabilities for legal
obligations related to asset retirements in the period in which they are
incurred. It also requires most energy utilities, including the
California Utilities, to reclassify amounts recovered in rates for
37
future removal costs not covered by a legal obligation from accumulated
depreciation to a regulatory liability.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities under SFAS 133.
Under SFAS 149 natural gas forward contracts that are subject to
unplanned netting (see Note 1 of the notes to Consolidated Financial
Statements) do not qualify for the normal purchases and normal sales
exception. The company has determined that all natural gas contracts are
subject to unplanned netting and as such, these contracts will be marked
to market. In addition, effective January 1, 2004, power contracts that
are subject to unplanned netting and that do not meet the normal
purchases and normal sales exception under SFAS 149 will be further
marked to market. Implementation of SFAS 149 on July 1, 2003 did not
have a material impact on reported net income.
FIN 46, "Consolidation of Variable Interest Entities an interpretation
of ARB No. 51": In January 2003, the FASB issued FIN 46 to strengthen
existing accounting guidance that addresses when a company should
consolidate a VIE in its financial statements.
Sempra Energy has identified two VIEs for which it is the primary
beneficiary. One of the VIEs (the Mesquite Trust) is the owner of the
Mesquite Power plant for which the company has a synthetic lease
agreement as described in Note 2. The other VIE relates to the
investment in AEG. Sempra Energy consolidated these entities in its
financial statements at December 31, 2003.
In accordance with FIN 46, the company has deconsolidated a wholly owned
subsidiary trust from its financial statements at December 31, 2003. See
further discussion regarding FIN 46 in Note 1 of the notes to
Consolidated Financial Statements.
38
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report contains statements that are not historical fact and
constitute forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. The words "estimates,"
"believes," "expects," "anticipates," "plans," "intends," "may,"
"could," "would" and "should" or similar expressions, or discussions of
strategy or of plans are intended to identify forward-looking
statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions. Future
results may differ materially from those expressed in these forward-
looking statements.
Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions and developments; actions by the California Public
Utilities Commission, the California Legislature, the California
Department of Water Resources, environmental and other regulatory bodies
in countries other than the United States, and the Federal Energy
Regulatory Commission; capital market conditions, inflation rates,
interest rates and exchange rates; energy and trading markets, including
the timing and extent of changes in commodity prices; weather conditions
and conservation efforts; war and terrorist attacks; business,
regulatory and legal decisions; the status of deregulation of retail
natural gas and electricity delivery; the timing and success of business
development efforts; and other uncertainties, all of which are difficult
to predict and many of which are beyond the control of the company.
Readers are cautioned not to rely unduly on any forward-looking
statements and are urged to review and consider carefully the risks,
uncertainties and other factors which affect the company's business
described in this report and other reports filed by the company from
time to time with the Securities and Exchange Commission.
39
FIVE YEAR SUMMARY
<table>
<caption>
At December 31 or for the years ended December 31
(Dollars in millions except per share amounts)
2003 2002 2001 2000 1999
-------------------------------------------------------------------------------
<s> <c> <c> <c> <c> <c>
OPERATING REVENUES
California utilities:
Gas $ 4,010 $ 3,263 $ 4,371 $ 3,305 $ 2,911
Electric 1,787 1,282 1,676 2,184 1,818
Other 2,090 1,503 1,683 1,271 631
-----------------------------------------------
Total $ 7,887 $ 6,048 $ 7,730 $ 6,760 $ 5,360
-----------------------------------------------
Operating income $ 939 $ 987 $ 997 $ 884 $ 763
Net income $ 649 $ 591 $ 518 $ 429 $ 394
Net income per common share:
Basic $ 3.07 $ 2.88 $ 2.54 $ 2.06 $ 1.66
Diluted $ 3.03 $ 2.87 $ 2.52 $ 2.06 $ 1.66
Dividends declared per common
share $ 1.00 $ 1.00 $ 1.00 $ 1.00 $ 1.56
Return on common equity 19.3% 21.4% 19.5% 15.7% 13.4%
Effective income tax rate 6.3% 20.2% 29.1% 38.6% 31.2%
Price range of common shares $ 30.90- $ 26.25- $ 28.61- $ 24.88- $ 26.00-
22.25 15.50 17.31 16.19 17.13
AT DECEMBER 31
Current assets $ 7,886 $ 7,010 $ 4,790 $ 6,525 $ 3,090
Total assets $22,009 $20,242 $17,746 $17,850 $13,312
Current liabilities $ 8,348 $ 7,247 $ 5,472 $ 7,490 $ 3,236
Long-term debt (excludes
current portion) $ 3,841 $ 4,083 $ 3,436 $ 3,268 $ 2,902
Shareholders' equity $ 3,890 $ 2,825 $ 2,692 $ 2,494 $ 2,986
Common shares outstanding
(in millions) 226.6 204.9 204.5 201.9 237.4
Book value per common share $ 17.17 $ 13.79 $ 13.16 $ 12.35 $ 12.58
-------------------------------------------------------------------------------
</table>
40
Statement of Management's Responsibility for the 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 Financial 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 audit committee of 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 compliance with the system of internal control
through its own review and an internal auditing program, which
independently assesses the effectiveness of the internal controls. The
company's independent auditors also consider certain elements of
internal controls in order to determine their audit procedures for the
purpose of expressing an opinion on the company's financial statements.
Management considers the recommendations of the internal auditors and
independent auditors concerning the company's system of internal
controls and takes appropriate actions. Management believes that the
company's system of internal control is adequate to provide reasonable
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
high 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, comprised 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 the independent auditors, and recommends to the board of
directors any appropriate response to those discussions. The audit
committee appoints 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 Senior Vice President and
Chief Financial Officer Controller
41
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, 2003 and
2002, 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, 2003. 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, 2003 and 2002, and the results of their
operations and their cash flows for each of the three years in the
period ended December 31, 2003, in conformity with accounting principles
generally accepted in the United States of America.
As described in Note 1 to the financial statements, the Company adopted
Statement of Financial Accounting Standards No. 143, Accounting for
Asset Retirement Obligations, effective January 1, 2003, and Financial
Accounting Standards Board Interpretation No. 46, Consolidation of
Variable Interest Entities an interpretation of ARB No. 51, effective
December 31, 2003.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 23, 2004
42
<table>
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED INCOME
(Dollars in millions, except per share amounts)
<caption>
Years ended December 31,
2003 2002 2001
------- ------- -------
<s> <c> <c> <c>
OPERATING REVENUES
California utilities:
Natural gas $ 4,010 $ 3,263 $ 4,371
Electric 1,787 1,282 1,676
Other 2,090 1,503 1,683
------- ------- -------
Total 7,887 6,048 7,730
------- ------- -------
OPERATING EXPENSES
California utilities:
Cost of natural gas 2,071 1,381 2,549
Cost of electric fuel and purchased power 541 297 782
Other cost of sales 1,204 709 873
Other operating expenses 2,287 1,901 1,760
Depreciation and amortization 615 596 579
Franchise fees and other taxes 230 177 190
------- ------- -------
Total 6,948 5,061 6,733
------- ------- -------
Operating income 939 987 997
Other income - net 26 15 3
Interest income 104 42 83
Interest expense (308) (294) (323)
Preferred dividends of subsidiaries (10) (11) (11)
Trust preferred distributions by subsidiary (9) (18) (18)
------- ------- -------
Income before income taxes 742 721 731
Income tax expense 47 146 213
------- ------- -------
Income before extraordinary item and cumulative effect of
changes in accounting principles 695 575 518
Extraordinary item, net of tax (Note 1) -- 16 --
------- ------- -------
Income before cumulative effect of changes in accounting principles 695 591 518
Cumulative effect of changes in accounting
principles, net of tax (Note 1) (46) -- --
------- ------- -------
Net income $ 649 $ 591 $ 518
======= ======= =======
Weighted-average number of shares outstanding (thousands):
Basic 211,740 205,003 203,593
------- ------- -------
Diluted 214,482 206,062 205,338
------- ------- -------
Income before extraordinary item and cumulative effect of
changes in accounting principles per share of common stock
Basic $ 3.29 $ 2.80 $ 2.54
------- ------- -------
Diluted $ 3.24 $ 2.79 $ 2.52
------- ------- -------
Income before cumulative effect of changes in accounting
principles per share of common stock
Basic $ 3.29 $ 2.88 $ 2.54
------- ------- -------
Diluted $ 3.24 $ 2.87 $ 2.52
------- ------- -------
Net income per share of common stock
Basic $ 3.07 $ 2.88 $ 2.54
------- ------- -------
Diluted $ 3.03 $ 2.87 $ 2.52
------- ------- -------
Common dividends declared per share $ 1.00 $ 1.00 $ 1.00
======= ======= =======
See notes to Consolidated Financial Statements.
</table>
43
<table>
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
<caption>
December 31,
-------------------------
2003 2002
---------- ----------
<s> <c> <c>
ASSETS
Current assets:
Cash and cash equivalents $ 432 $ 455
Short-term investments 363 --
Accounts receivable - trade 1,012 754
Accounts and notes receivable - other 127 132
Interest receivable 62 3
Due from unconsolidated affiliates -- 80
Income taxes receivable 20 --
Deferred income taxes -- 20
Trading assets 5,250 5,064
Regulatory assets arising from fixed-price
contracts and other derivatives 144 151
Other regulatory assets 89 75
Inventories 147 134
Other 240 142
------- -------
Total current assets 7,886 7,010
------- -------
Investments and other assets:
Due from unconsolidated affiliates 55 57
Regulatory assets arising from fixed-price
contracts and other derivatives 650 812
Other regulatory assets 554 532
Nuclear decommissioning trusts 570 494
Investments 1,114 1,313
Fixed-price contracts and other derivatives -- 42
Sundry 706 664
------- -------
Total investments and other assets 3,649 3,914
------- -------
Property, plant and equipment:
Property, plant and equipment 15,317 13,816
Less accumulated depreciation and amortization (4,843) (4,498)
------- -------
Total property, plant and equipment - net 10,474 9,318
------- -------
Total assets $22,009 $20,242
======= =======
See notes to Consolidated Financial Statements.
</table>
44
<table>
SEMPRA ENERGY
CONSOLIDATED BALANCE SHEETS
(Dollars in millions)
<caption>
December 31,
-------------------------
2003 2002
---------- ----------
<s> <c> <c>
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Short-term debt $ 28 $ 570
Accounts payable - trade 815 694
Accounts payable - other 64 50
Income taxes payable -- 22
Deferred income taxes 123 --
Trading liabilities 4,457 4,094
Dividends and interest payable 136 133
Regulatory balancing accounts - net 424 578
Fixed-price contracts and other derivatives 148 153
Current portion of long-term debt 1,433 281
Other 720 672
------- -------
Total current liabilities 8,348 7,247
------- -------
Long-term debt 3,841 4,083
------- -------
Deferred credits and other liabilities:
Due to unconsolidated affiliates 362 162
Customer advances for construction 89 91
Postretirement benefits other than pensions 131 136
Deferred income taxes 634 800
Deferred investment tax credits 84 90
Regulatory liabilities arising from cost
of removal obligations 2,238 2,486
Regulatory liabilities arising from asset
retirement obligations 281 --
Other regulatory liabilities 108 121
Fixed-price contracts and other derivatives 680 813
Asset retirement obligations 313 --
Deferred credits and other 831 984
------- -------
Total deferred credits and other liabilities 5,751 5,683
------- -------
Preferred stock of subsidiaries 179 204
------- -------
Mandatorily redeemable trust preferred securities -- 200
------- -------
Commitments and contingent liabilities (Note 15)
SHAREHOLDERS' EQUITY
Preferred stock (50 million shares authorized,
none issued) -- --
Common stock (750 million shares authorized;
227 million and 205 million shares outstanding at
December 31, 2003 and December 31, 2002, respectively) 2,028 1,436
Retained earnings 2,298 1,861
Deferred compensation relating to ESOP (35) (33)
Accumulated other comprehensive income (loss) (401) (439)
------- -------
Total shareholders' equity 3,890 2,825
------- -------
Total liabilities and shareholders' equity $22,009 $20,242
======= =======
See notes to Consolidated Financial Statements.
</table>
45
<table>
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Dollars in millions)
<caption>
Years ended December 31,
2003 2002 2001
------- ------- -------
<s> <c> <c> <c>
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 649 $ 591 $ 518
Adjustments to reconcile net income
to net cash provided by operating activities:
Extraordinary item, net of tax -- (16) --
Cumulative effect of changes in accounting
principles 46 -- --
Depreciation and amortization 615 596 579
Foreign currency loss (gain) 8 (63) --
Deferred income taxes and investment
tax credits (73) (92) 106
Non-cash rate reduction bond expense 68 82 66
Equity in (income) losses of unconsolidated
affiliates (8) 55 (12)
Impairment losses 101 -- --
Loss (gain) on sale and disposition of assets 8 14 (14)
Other - net 2 (5) --
Net changes in other working capital components (224) 151 (203)
Customer refunds paid -- -- (127)
Changes in other assets (66) 87 (280)
Changes in other liabilities (5) 40 99
------- ------- -------
Net cash provided by operating activities 1,121 1,440 732
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Expenditures for property, plant and equipment (1,049) (1,214) (1,068)
Investments and acquisitions of subsidiaries,
net of cash acquired (202) (429) (111)
Dividends received from unconsolidated affiliates 72 11 80
Net proceeds from sale of assets 29 -- 128
Loans to unconsolidated affiliates (99) (82) (57)
Other - net (4) (14) (11)
------- ------- -------
Net cash used in investing activities (1,253) (1,728) (1,039)
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Common dividends paid (207) (205) (203)
Issuances of common stock 549 13 41
Repurchases of common stock (6) (16) (1)
Issuances of long-term debt 900 1,150 675
Payments on long-term debt (601) (479) (681)
Loan from unconsolidated affiliate -- -- 160
Increase (decrease) in short-term debt - net (518) (307) 310
Other - net (8) (18) (26)
------- ------- -------
Net cash provided by financing activities 109 138 275
------- ------- -------
Decrease in cash and cash equivalents (23) (150) (32)
Cash and cash equivalents, January 1 455 605 637
------- ------- -------
Cash and cash equivalents, December 31 $ 432 $ 455 $ 605
======= ======= =======
46
Years ended December 31,
2003 2002 2001
------- ------- -------
CHANGES IN OTHER WORKING CAPITAL COMPONENTS
(Excluding cash and cash equivalents, and debt due
within one year)
Accounts and notes receivable $ (231) $ (121) $ 353
Net trading assets 81 66 (362)
Income taxes - net 6 86 (121)
Inventories (13) (11) 33
Regulatory balancing accounts (156) 170 88
Regulatory assets and liabilities (30) 1 39
Other current assets (8) 51 33
Accounts payable 98 (103) (302)
Other current liabilities 29 12 36
------- ------- -------
Net changes in other working
capital components $ (224) $ 151 $ (203)
======= ======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 296 $ 279 $ 302
======= ======= =======
Income tax payments, net of refunds $ 118 $ 140 $ 138
======= ======= =======
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING AND
FINANCING ACTIVITIES
Acquisition of subsidiaries:
Assets acquired $ -- $ 1,134 $ --
Cash paid, net of cash acquired -- (119) --
------- ------- -------
Liabilities assumed $ -- $ 1,015 $ --
======= ======= =======
Consolidation of variable interest
entities:
Assets recorded $ 820 $ -- $ --
Liabilities recorded (881) -- --
------- ------- -------
Total $ (61) $ -- $ --
======= ======= =======
See notes to Consolidated Financial Statements.
</table>
47
<table>
SEMPRA ENERGY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
Years ended December 31, 2003, 2002 and 2001
(Dollars in millions)
<caption>
Deferred Accumulated
Compensation Other Total
Comprehensive Common Retained Relating Comprehensive Shareholders'
Income Stock Earnings to ESOP Income (Loss) Equity
- ----------------------------------------------------------------------------------------------
<s> <c> <c> <c> <c> <c> <c>
Balance at December 31, 2000 $1,420 $1,162 $ (39) $ (49) $2,494
Net income $518 518 518
Comprehensive income adjustments:
Foreign currency translation
losses (Note 1) (186) (186) (186)
Pension (7) (7) (7)
-----
Comprehensive income $325
=====
Common stock dividends declared (205) (205)
Quasi-reorganization
adjustment (Note 1) 35 35
Sale of common stock 41 41
Repurchase of common stock (1) (1)
Common stock released from ESOP 3 3
-------------------------------------------------------
Balance at December 31, 2001 1,495 1,475 (36) (242) 2,692
Net income $591 591 591
Comprehensive income adjustments:
Foreign currency translation
losses (Note 1) (162) (162) (162)
Pension (35) (35) (35)
-----
Comprehensive income $394
=====
Common stock dividends declared (205) (205)
Issuance of equity units (Note 5) (61) (61)
Sale of common stock 18 18
Repurchase of common stock (16) (16)
Common stock released from ESOP 3 3
-------------------------------------------------------
Balance at December 31, 2002 1,436 1,861 (33) (439) 2,825
Net income $649 649 649
Comprehensive income adjustments:
Foreign currency translation
gains (Note 1) 57 57 57
Pension (16) (16) (16)
SFAS 133 (3) (3) (3)
-----
Comprehensive income $687
=====
Common stock dividends declared (212) (212)
Equity units adjustment 6 6
Quasi-reorganization
adjustment (Note 1) 19 19
Sale of common stock 566 566
Repurchase of common stock (6) (6)
Common stock released from ESOP 7 (2) 5
-------------------------------------------------------
Balance at December 31, 2003 $2,028 $2,298 $ (35) $ (401) $3,890
- ----------------------------------------------------------------------------------------------
See notes to Consolidated Financial Statements.
</table>
48
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The Consolidated Financial Statements include the accounts of Sempra
Energy (the company) and all majority-owned subsidiaries. Investments in
affiliated companies over which Sempra Energy has the ability to
exercise significant influence, but not control, are accounted for using
the equity method. All material intercompany accounts and transactions
have been eliminated.
Quasi-Reorganization
In 1993, Pacific Enterprises (PE) divested substantially all of its non-
utility business and effected a quasi-reorganization for financial
reporting purposes as of December 31, 1992. Certain of the liabilities
established in connection with the quasi-reorganization, including
various income-tax issues, were favorably resolved, resulting in
restoring $35 million and $19 million to shareholders' equity in 2001
and 2003, respectively. These restorations did not affect the
calculation of net income or comprehensive income. The remaining
liabilities will be resolved in future years and management believes the
provisions established for these matters are adequate.
Use of Estimates in the Preparation of the Financial Statements
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of revenues and expenses
during the reporting period, and the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities at
the date of the financial statements. Actual amounts can differ
significantly from those estimates.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the
current year's presentation.
Regulatory Matters
Effects of Regulation
The accounting policies of the company's principal utility subsidiaries,
San Diego Gas & Electric (SDG&E) and Southern California Gas Company
(SoCalGas) (collectively, the California Utilities), 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).
The California Utilities prepare their financial statements in
accordance with the provisions of Statement of Financial Accounting
Standards (SFAS) 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
49
recover that asset from customers. Regulatory liabilities represent
reductions in future rates for amounts due to customers. To the extent
that recovery is 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 144, "Accounting for
the Impairment or Disposal of Long-Lived Assets" requires that a loss
must be recognized whenever a regulator excludes all or part of utility
plant or regulatory assets from ratebase. Information concerning
regulatory assets and liabilities is described in "Revenues,"
"Regulatory Balancing Accounts," and "Regulatory Assets and
Liabilities."
Regulatory Balancing Accounts
The amounts included in regulatory balancing accounts at December 31,
2003, represent net payables (payables net of receivables) of $86
million and $338 million for SoCalGas and SDG&E, respectively. The
corresponding amounts at December 31, 2002 were net payables of $184
million and $394 million. The payables normally are returned by reducing
future rates.
Balancing accounts provide a mechanism for charging utility customers
the amount actually incurred for certain costs, primarily commodity
costs. However, fluctuations in most operating and maintenance costs
affect earnings. In addition, fluctuations in consumption levels affect
earnings at SDG&E. The CPUC approved 100 percent balancing account
treatment for variances between forecast and actual for SoCalGas'
noncore revenues and throughput, eliminating the impact on earnings from
any throughput and revenue variances from adopted forecast levels.
Additional information on regulatory matters is included in Notes 13 and
14.
50
Regulatory Assets and Liabilities
In accordance with the accounting principles of SFAS 71, the company
records regulatory assets and regulatory liabilities as discussed above.
Regulatory assets (liabilities) as of December 31 relate to the
following matters:
(Dollars in millions) 2003 2002
- -----------------------------------------------------------------------
SDG&E
- ------
Fixed-price contracts and other derivatives $ 560 $ 636
Recapture of temporary rate reduction* 259 326
Deferred taxes recoverable in rates 273 190
Unamortized loss on retirement of debt - net 44 49
Employee benefit costs 35 35
Cost of removal obligations** (846) (1,162)
Asset retirement obligations** (303) --
Other 24 7
-------- --------
Total 46 81
-------- --------
SoCalGas
- ---------
Fixed-price contracts and other derivatives 233 325
Environmental remediation 44 43
Unamortized loss on retirement of debt - net 45 38
Cost of removal obligation** (1,392) (1,324)
Deferred taxes refundable in rates (192) (164)
Employee benefit costs (77) (142)
Other 8 8
-------- --------
Total (1,331) (1,216)
PE - Employee benefit costs 72 80
-------- --------
Total PE consolidated (1,259) (1,136)
-------- --------
Total $(1,213) $(1,055)
======== ========
- -----------------------------------------------------------------------
* In connection with electric industry restructuring, which is described
in Note 13, SDG&E temporarily reduced rates to its small-usage
customers. That reduction is being recovered in rates through 2007.
** See discussion of SFAS 143 in "New Accounting Standards."
51
Net regulatory liabilities are recorded on the Consolidated Balance
Sheets at December 31 as follows:
(Dollars in millions) 2003 2002
- ---------------------------------------------------------------------
Current regulatory assets $ 233 $ 226
Noncurrent regulatory assets 1,204 1,344
Current regulatory liabilities* (23) (18)
Noncurrent regulatory liabilities (2,627) (2,607)
-------- --------
Total $(1,213) $(1,055)
======== ========
- ---------------------------------------------------------------------
* Amount is included in Other Current Liabilities.
All of the assets either earn a return, generally at short-term rates,
or the cash has not yet been expended and the assets are offset by
liabilities that do not incur a carrying cost.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with maturities of three
months or less at the date of purchase.
Collection Allowances
The allowance for doubtful accounts was $19 million, $12 million and $22
million at December 31, 2003, 2002 and 2001, respectively. The company
recorded a provision for doubtful accounts of $5 million, $13 million
and $21 million in 2003, 2002 and 2001, respectively.
The allowance for realization of trading assets was $67 million, $86
million and $23 million, at December 31, 2003, 2002 and 2001,
respectively. The company recorded a provision (reduction thereof) for
trading assets of ($4) million, $20 million and $15 million in 2003,
2002 and 2001, respectively.
Trading Instruments
Trading assets and trading liabilities include option premiums paid and
received; unrealized gains and losses from exchange-traded futures and
options, over-the-counter (OTC) swaps, forwards, physical commodities
and options; and base metals. Trading instruments are recorded by Sempra
Energy Trading (SET) and Sempra Energy Solutions (SES) on a trade-date
basis and the majority of such derivative instruments are adjusted daily
to current market value. Unrealized gains and losses on OTC transactions
reflect amounts which would be received from or paid to a third party
upon net 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 an enforceable netting arrangement.
Additionally, as a result of SET's acquisitions in 2002, the company
acquired $0.8 billion of base metals inventory. As of December 31, 2003
and 2002, trading assets included commodity inventory of $1.4 billion
and $2.0 billion, respectively.
In October 2002, the Emerging Issues Task Force (EITF) rescinded fair
value accounting for recording energy-trading activities and required
52
contracts subsequently entered into to be accounted for at historical
cost or the lower of cost or market, unless the contracts meet the
requirements for fair value accounting under SFAS 133 and 149 (see below
in "New Accounting Standards"). Energy transportation and storage
contracts are recorded at cost. Energy commodity inventory is being
recorded at the lower of cost or market. The company's base metals and
concentrates inventory continue to be recorded at fair value in
accordance with Accounting Research Bulletin (ARB) No. 43 "Restatement
and Revision of Accounting Research Bulletins." See further discussion
of EITF Issue 02-3 below in "New Accounting Standards."
Futures and exchange-traded option transactions are recorded as
contractual commitments on a trade-date basis and carried at current
market value based on current closing exchange quotations. Derivative
commodity swaps and forward transactions are accounted for as
contractual commitments on a trade-date basis and carried at fair value
derived from current 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. For long-dated forward transactions,
current market values are derived using internally developed valuation
methodologies based on available market information. When there is an
absence of observable market data at inception, the value of the
transaction is its cost. 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 significantly from realized
values. Changes in market values are reflected in net income. Although
trading instruments may have scheduled maturities in excess of one year,
the actual settlement of these transactions can occur sooner, resulting
in the current classification of trading assets and liabilities on the
Consolidated Balance Sheets. "New Accounting Standards" below provides a
discussion of the rescission of EITF 98-10.
Inventories
At December 31, 2003, inventory shown on the Consolidated Balance
Sheets, which does not include amounts included in trading assets,
included natural gas of $89 million and materials and supplies of $58
million. The corresponding balances at December 31, 2002 were $77
million and $57 million, respectively. Natural gas at the California
Utilities ($84 million and $74 million at December 31, 2003 and 2002,
respectively) is valued by the last-in first-out (LIFO) method. When the
California Utilities' inventory is consumed, differences between the
LIFO valuation and replacement cost are reflected in customer rates.
Materials and supplies at the California Utilities are generally valued
at the lower of average cost or market.
Property, Plant and Equipment
Property, plant and equipment primarily represents the buildings,
equipment and other facilities used by the California Utilities to
provide natural gas and electric utility services, and the newly
constructed power plants at Sempra Energy Resources (SER).
The cost of plant includes labor, materials, contract services and
related items. In addition, the cost of utility plant includes an
53
allowance for funds used during construction (AFUDC). The cost of non-
utility plant includes capitalized interest. The cost of most retired
depreciable utility plant minus salvage value is charged to accumulated
depreciation.
Property, plant and equipment balances by major functional categories
are as follows:
Property, Plant Depreciation rates
and Equipment at for years ended
December 31 December 31
- ----------------------------------------------------------------------
(Dollars in billions) 2003 2002 2003 2002 2001
- ----------------------------------------------------------------------
California Utilities:
Natural gas operations $ 8.0 $ 7.7 4.28% 4.25% 4.25%
Electric distribution 3.2 3.0 4.70% 4.66% 4.67%
Electric transmission 0.9 0.9 3.09% 3.17% 3.19%
Other electric 0.7 0.6 9.53% 9.37% 8.46%
----------------
Total 12.8 12.2
Other operations 2.5 1.6 various various various
----------------
Total $ 15.3 $ 13.8
----------------
- ----------------------------------------------------------------------
Accumulated depreciation and decommissioning of natural gas and electric
utility plant in service were $3.1 billion and $1.4 billion,
respectively, at December 31, 2003, and were $2.9 billion and $1.3
billion, respectively, at December 31, 2002. See discussion of SFAS 143
under "New Accounting Standards." Depreciation expense is based on the
straight-line method over the useful lives of the assets or a shorter
period prescribed by the CPUC. See Note 13 for discussion of the sale of
generation facilities and industry restructuring. Maintenance costs are
expensed as incurred.
AFUDC, which represents the cost of funds used to finance the
construction of utility plant, is added to the cost of utility plant.
AFUDC also increases income, partly as an offset to interest charges and
partly as a component of Other Income - Net, in the Statements of
Consolidated Income, although it is not a current source of cash. AFUDC
amounted to $29 million, $34 million and $17 million for 2003, 2002 and
2001, respectively. Total capitalized carrying costs, including AFUDC
and the impact of SER's construction projects, were $55 million, $63
million and $28 million for 2003, 2002 and 2001, respectively.
Long-Lived Assets
The company periodically evaluates whether events or circumstances have
occurred that may affect the recoverability or the estimated useful
lives of long-lived assets. Impairment occurs when the estimated future
undiscounted cash flows are less than the carrying amount of the assets.
If that comparison indicates that the assets' carrying value may be
permanently impaired, the potential impairment is measured based on the
difference between the carrying amount and the fair value of the assets
based on quoted market prices or, if market prices are not available, on
54
the estimated discounted cash flows. This calculation is performed at
the lowest level for which separately identifiable cash flows exist. See
further discussion of SFAS 144 in "New Accounting Standards." During the
third and fourth quarters of 2003, the company recorded impairment
charges of $77 million and $24 million to write down the carrying value
of the assets of Frontier Energy and Atlantic Electric & Gas Limited
(AEG), respectively. This is discussed further in "New Accounting
Standards" below.
Nuclear Decommissioning Liability
At December 31, 2002, in accordance with SFAS 71, SDG&E had recorded a
$355 million regulatory liability representing SDG&E's share of the
estimated future decommissioning costs of the San Onofre Nuclear
Generating Station (SONGS). In addition, Deferred Credits and Other
Liabilities included $139 million of accrued decommissioning costs
associated with SONGS. As of December 31, 2003, as the result of
implementing SFAS 143, "Accounting for Asset Retirement Obligations,"
SDG&E had asset retirement obligations and related regulatory
liabilities of $316 million and $303 million, respectively. Additional
information on SONGS decommissioning costs is included below in "New
Accounting Standards."
Legal Fees
Legal fees that are associated with a past event and not expected to be
recovered in the future are accrued when it is probable that they will
be incurred.
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
foreign-currency translation adjustments, minimum pension liability
adjustments, and certain hedging activities. The components of other
comprehensive income are shown in the Statements of Consolidated Changes
in Shareholders' Equity.
55
Stock-Based Compensation
The company has stock-based employee compensation plans, which are
described in Note 9. The company accounts for these plans under the
recognition and measurement principles of Accounting Principles Board
(APB) Opinion 25, "Accounting for Stock Issued to Employees," and
related Interpretations. For certain grants, no stock-based employee
compensation cost is reflected in net income, since the options granted
under those plans had an exercise price equal to the market value of the
underlying common stock on the date of grant. See "New Accounting
Standards" below for further discussion. The following table provides
the pro forma effects of recognizing compensation expense in accordance
with SFAS 123, "Accounting for Stock-Based Compensation":
<table>
<caption>
Years ended December 31,
-----------------------------------------
2003 2002 2001
-----------------------------------------
<s> <c> <c> <c>
Net income as reported $ 649 $ 591 $ 518
Stock-based employee compensation
expense included in the computation
of net income, net of tax 13 3 7
Total stock-based employee compensation
under fair value method for all awards,
net of tax (20) (11) (8)
----------------------------------------
Pro forma net income $ 642 $ 583 $ 517
========================================
Earnings per share:
Basic--as reported $ 3.07 $ 2.88 $ 2.54
========================================
Basic--pro forma $ 3.03 $ 2.84 $ 2.54
========================================
Diluted--as reported $ 3.03 $ 2.87 $ 2.52
========================================
Diluted--pro forma $ 2.99 $ 2.83 $ 2.52
========================================
</table>
Revenues
Revenues of the California Utilities are primarily derived from
deliveries of electricity and natural gas to customers and changes in
related regulatory balancing accounts. Revenues from electricity and
natural gas sales and services are generally recorded under the accrual
method and recognized upon delivery. The portion of SDG&E's electric
commodity that was procured for its customers by the California
Department of Water Resources (DWR) and delivered by SDG&E is not
included in SDG&E's revenues or costs. For 2001, California Power
Exchange (PX) and Independent System Operator (ISO) power revenues have
been netted against purchased-power expense to avoid double-counting of
power sold into and then repurchased from the PX/ISO. During 2003, costs
associated with long-term contracts allocated to SDG&E from the DWR were
also not included in the Statements of Consolidated Income, since the
56
DWR retains legal and financial responsibility for these contracts.
Refer to Note 13 for a discussion of the electric industry
restructuring. Natural gas storage contract revenues are accrued on a
monthly basis and reflect reservation, storage and injection charges in
accordance with negotiated agreements, which have terms of up to three
years. Operating revenue includes amounts for services rendered but
unbilled (approximately one-half month's deliveries) at the end of each
year.
Through 2003, operating costs of SONGS Units 2 and 3, including nuclear
fuel and related financing costs, and incremental capital expenditures
were recovered through the Incremental Cost Incentive Pricing (ICIP)
mechanism which allowed SDG&E to receive 4.4 cents per kilowatt-hour for
SONGS generation. Any differences between these costs and the incentive
price affected net income. For the year ended December 31, 2003, ICIP
contributed $53 million to SDG&E's net income. Beginning in 2004 the
CPUC has provided for traditional rate-making treatment, under which the
SONGS ratebase would start over at January 1, 2004, essentially
eliminating earnings from SONGS except from future increases in
ratebase.
Additional information concerning utility revenue recognition is
discussed above under "Regulatory Matters."
SET generates a substantial portion of its revenues from market making
and trading activities, as a principal, in natural gas, electricity,
petroleum, metals and other commodities, for which it quotes bid and ask
prices to end users and other market makers. Principal transaction
revenues are recognized on a trade-date basis, and include realized
gains and losses, and the net change in the fair value of unrealized
gains and losses. SET also earns trading profits as a dealer by
structuring and executing transactions. SET utilizes derivative
instruments to reduce its exposure to unfavorable changes in market
prices, which are subject to significant and volatile fluctuations.
These instruments include futures, forwards, swaps and options. Options,
which are either exchange-traded or directly negotiated between
counterparties, provide the holder with the right to buy from or sell to
the other party an agreed amount of a commodity at a specified price
within a specified period or at a specified time.
As a writer of options, SET generally receives an option premium and
then manages the risk of an unfavorable change in the value of the
underlying commodity by entering into related transactions or by other
means. Forward and future transactions are contracts for delivery of
commodities in which the counterparty agrees to make or take delivery at
a specified price. Commodity swap transactions may involve the exchange
of fixed and floating payment obligations without the exchange of the
underlying commodity. SET's financial instruments represent contracts
with counterparties whereby payments are linked to or derived from
market indices or on terms predetermined by the contract.
Non-derivative contracts are being carried at cost and accounted for on
an accrual basis. Hence, the related profit or loss will be recognized
as the contract is performed. Derivative instruments are discussed
further in Note 10.
57
Revenues of SES are generated from commodity sales and energy-related
products and services to commercial, industrial, government and
institutional markets. Energy supply revenues from natural gas and
electricity commodity sales are recognized on a current fair value basis
and include realized gains and losses and the net change in unrealized
gains and losses measured at fair value. Revenues on construction
projects are recognized during the construction period using the
percentage-of-completion method, and revenues from other operating and
maintenance service contracts are recorded under the accrual method and
recognized as service is rendered.
SET and SES record revenues from trading activities on a net basis in
accordance with EITF 02-3. See further discussion of this matter and the
rescission of EITF 98-10 under "New Accounting Standards."
Revenues of SER are derived primarily from the sale of electric energy
to governmental and wholesale power marketing entities, which are
recognized in accordance with provisions of EITF 91-6, "Revenue
Recognition of Long-term Power Supply Contracts," and EITF 96-17,
"Revenue Recognition Under Long-term Power Sales Contacts that Contain
Both Fixed and Variable Terms." During 2003 and 2002, electric energy
sales to the DWR accounted for a significant portion of total SER
revenues.
The consolidated foreign subsidiaries of Sempra Energy International
(SEI), all of which operate in Mexico, recognize revenue similarly to
the California Utilities, except that SFAS 71 is not applicable due to
the different regulatory environment.
Extraordinary Gain
During 2002, SET acquired two businesses for amounts less than the fair
values of the business' net assets. In accordance with SFAS 141,
"Business Combinations," those differences were recorded as
extraordinary income. The $16 million of extraordinary income was
recorded in the second quarter ($2 million) and in the fourth quarter
($14 million).
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 do not enter into the
calculation of net income or retained earnings, but are reflected in
comprehensive income and accumulated other comprehensive income, a
component of shareholders' equity, as described below. Foreign currency
transaction gains and losses are included in consolidated net income. To
reflect the fluctuation in the Argentine peso, the functional currency
of the company's Argentine operations, SEI adjusted its investment in
its two Argentine natural gas utility holding companies upward by $26
million and downward by $102 million in 2003 and 2002, respectively.
These non-cash adjustments did not affect net income, but did increase
or reduce comprehensive income and accumulated other comprehensive
income (loss). Smaller adjustments have been made to operations in other
countries. Additional information concerning these investments is
described in Note 3.
58
Transactions with Affiliates
Loans to Unconsolidated Affiliates
In December 2001, SEI issued two U.S. dollar denominated loans totaling
$35 million and $22 million to its affiliates Camuzzi Gas Pampeana S. A.
and Camuzzi Gas del Sur S. A., respectively. These loans have variable
interest rates (8.168% at December 31, 2003) and are due on March 13,
2004. The total balance outstanding under the notes was $55 million and
$56 million at December 31, 2003 and 2002, respectively. At December 31,
2003, this amount is included in non-current assets, under the caption
Due from Unconsolidated Affiliates because they will be refinanced on
longer terms.
Additionally, at December 31, 2002, SET had $79 million due from AEG and
the company had $1 million due from other affiliates. At December 31,
2002, the outstanding loans are included in current assets under the
caption Due from Unconsolidated Affiliates. In addition, SET had $44
million of trading assets due from AEG at December 31, 2002. At December
31, 2003, as a result of the adoption of FASB Interpretation No. (FIN)
46, AEG was consolidated. See "New Accounting Standards" below for a
discussion of FIN 46.
Loans from Unconsolidated Affiliates
At both December 31, 2003 and 2002, SEI had long-term notes payable to
affiliates which include $60 million at 6.47% due April 1, 2008 and $100
million at 6.62% due April 1, 2011. The loans are due to Chilquinta
Energia Finance, LLC and are secured by SEI's investments in Chilquinta
Energia S.A. and Luz del Sur S.A.A. (Luz del Sur) (See Note 3).
The company also reclassified $200 million of mandatorily redeemable
trust preferred securities to Due to Unconsolidated Affiliates as a
result of the adoption of FIN 46 effective December 31, 2003. In
addition, dividend payments required on these instruments, previously
recorded to Preferred Dividends of Subsidiaries and Trust Preferred
Distributions, were recorded to Interest Expense for the last six months
of 2003 on the company's Statements of Consolidated Income, in
accordance with SFAS 150. See discussion of SFAS 150 in "New Accounting
Standards" below.
Revenues and Expenses with Unconsolidated Affiliates
During 2003 and 2002 SER recorded $61 million and $39 million,
respectively, in sales to El Dorado, an unconsolidated affiliate, and
recorded $69 million and $49 million, respectively, of purchases for
those same years.
New Accounting Standards
SFAS 132 (revised 2003), "Employers Disclosures about Pensions and Other
Postretirement Benefits": This statement revised employers' disclosures
about pension plans and other postretirement benefit plans. It requires
disclosures beyond those in the original SFAS 132 about the assets,
obligations, cash flows and net periodic benefit cost of defined benefit
pension plans and other defined postretirement plans. It does not change
59
the measurement or recognition of those plans. This statement is
effective for financial statements with fiscal years ending after
December 15, 2003.
SFAS 142, "Goodwill and Other Intangible Assets": In July 2001, the FASB
issued SFAS 142, which provides guidance on how to account for goodwill
and other intangible assets after an acquisition is complete. SFAS 142
calls for amortization of goodwill to cease and requires goodwill and
certain other intangibles to be tested for impairment at least annually.
Amortization of goodwill, including the company's share of amounts
recorded by unconsolidated subsidiaries, was $24 million in 2001. In
accordance with the transitional guidance of SFAS 142, recorded goodwill
attributable to the company was tested for impairment in 2002 by
comparing the fair value to its carrying value, using a discounted cash
flow methodology. As a result, during the first quarter of 2002, SEI
recorded a pre-tax charge of $6 million related to the impairment of
goodwill associated with its two domestic subsidiaries. Impairment
losses are reflected in Other Operating Expenses in the Statements of
Consolidated Income.
If goodwill amortization had not been recorded in 2001, reported net
income for 2001 would have increased by $15 million to $533 million.
Basic and diluted earnings per share would have increased by $0.07 to
$2.61 and $2.59 respectively.
During 2002, SET completed several acquisitions as further discussed in
Note 2. As a result of SET's acquisition of the metals warehousing
business, the company recorded $21 million of goodwill on the
Consolidated Balance Sheets. In addition, a $16 million after-tax
extraordinary gain reflecting negative goodwill was recorded in 2002 for
the purchase of the base metals and concentrates businesses.
During the first quarter of 2003 SEI purchased the remaining minority
interests in its Mexican subsidiaries, which resulted in the recording
of an addition to goodwill of $6 million and to an intangible asset of
$4 million.
The changes in the carrying amount of goodwill (included in Noncurrent
Sundry Assets on the Consolidated Balance Sheets) for the years ended
December 31, 2003 and 2002 are as follows:
(Dollars in millions) SET Other Total
- ----------------------------------------------------------------------
Balance as of January 1, 2002 $ 120 $ 52 $ 172
Goodwill acquired during the year 21 -- 21
Impairment losses -- (6) (6)
Other -- (5) (5)
---------------------------
Balance as of December 31, 2002 141 41 182
Goodwill acquired during the year -- 6 6
---------------------------
Balance as of December 31, 2003 $ 141 $ 47 $ 188
---------------------------
SET is the only reportable segment that has goodwill. In addition, the
unamortized goodwill related to unconsolidated subsidiaries (included in
Investments on the Consolidated Balance Sheets), primarily those located
60
in South America, was $299 million and $294 million at December 31, 2003
and 2002, respectively, before foreign currency translation adjustments.
Including foreign currency translation adjustments, these amounts were
$232 million and $219 million, respectively. Unamortized other
intangible assets were not material at December 31, 2003 and 2002.
SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143,
issued in July 2001, addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived assets
and the associated asset retirement costs. It applies to legal
obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development and/or normal
operation of long-lived assets, such as nuclear plants. It requires
entities to record the fair value of a liability for an asset retirement
obligation in the period in which it is incurred. When the liability is
initially recorded, the entity increases the carrying amount of the
related long-lived asset by the present value of the future retirement
cost. Over time, the liability is accreted to its full value and paid,
and the capitalized cost is depreciated over the useful life of the
related asset.
The adoption of SFAS 143 on January 1, 2003 resulted in the recording of
an addition to utility plant of $71 million, representing the company's
share of SONGS estimated future decommissioning costs (as discounted to
the present value at the dates the units began operation), and
accumulated depreciation of $41 million related to the increase to
utility plant, for a net increase of $30 million. In addition, the
company recorded a corresponding retirement obligation liability of $309
million (which includes accretion of that discounted value to December
31, 2002) and a regulatory liability of $215 million to reflect that
SDG&E has collected the funds from its customers more quickly than SFAS
143 would accrete the retirement liability and depreciate the asset.
These liabilities, less the $494 million recorded as accumulated
depreciation prior to January 1, 2003 (which represents amounts
collected for future decommissioning costs), comprise the offsetting $30
million. See further discussion of SONGS' decommissioning and the
related nuclear decommissioning trusts in Note 6.
On January 1, 2003, the company recorded additional asset retirement
obligations of $20 million associated with the future retirement of a
former power plant and three storage facilities.
In accordance with SFAS 143, Sempra Energy identified several other
assets for which retirement obligations exist, but whose lives are
indeterminate. A liability for these asset retirement obligations will
be recorded if and when a life is determinable.
61
The change in the asset retirement obligations for the year ended
December 31, 2003 is as follows (dollars in millions):
Balance as of January 1, 2003 $ --
Adoption of SFAS 143 329
Accretion expense 22
Payments (14)
------
Balance as of December 31, 2003 $ 337*
======
* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.
Had SFAS 143 been in effect on January 1, 2002, the asset retirement
obligation liability would have been $363 million as of that date.
Except for the items noted above, the company has determined that there
is no other material retirement obligation associated with tangible
long-lived assets.
Implementation of SFAS 143 has had no effect on results of operations
and is not expected to have a significant effect in the future.
In accordance with CPUC regulations, the California Utilities collect
estimated removal costs in rates through depreciation. SFAS 143 also
requires the company to reclassify estimated removal costs, which have
historically been recorded in accumulated depreciation, to a regulatory
liability. At December 31, 2003, these costs were $1.4 billion and $846
million for SoCalGas and SDG&E, respectively. At December 31, 2002, the
corresponding amounts were $1.3 billion and $1.2 billion for SoCalGas
and SDG&E, respectively. The decrease in the SDG&E amount during 2003
is due to SFAS 143 requiring further reclassification of those costs
related to a legal obligation (primarily SONGS costs) to Asset
Retirement Obligations.
SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets":
In August 2001, the FASB issued SFAS 144, which replaces SFAS 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of." It applies to all long-lived assets. Among
other things SFAS 144 requires that those long-lived assets classified
as held for sale be measured at the lower of carrying amount (cost less
accumulated depreciation) or fair value less cost to sell.
During the third and fourth quarters of 2003, the company recorded
impairment charges of $77 million and $24 million to write down the
carrying value of the assets of Frontier Energy and AEG, respectively.
The Frontier Energy impairment resulted from reductions in actual and
anticipated sales of natural gas by the utility. The AEG impairment was
due to less than anticipated customer growth. These charges are included
in Other Operating Expenses in the Statements of Consolidated Income. In
applying the provisions of SFAS 144, management determined the fair
value of such assets based on its estimates of discounted future cash
flows.
SFAS 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure": In December 2002, the FASB issued SFAS 148, an amendment to
SFAS 123, "Accounting for Stock-Based Compensation," which gives
62
companies electing to expense employee stock options three methods to do
so. In addition, the statement amends the disclosure requirements to
require more prominent disclosure about the method of accounting for
stock-based employee compensation and the effect of the method used on
reported results in both annual and interim financial statements.
The company has elected to continue using the intrinsic value method of
accounting for stock-based compensation. Therefore, SFAS 148 will not
have any effect on the company's financial statements. See Note 9 for
additional information regarding stock-based compensation.
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": Effective July 1, 2003, SFAS 149 amended and
clarified accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities under SFAS 133. Under SFAS 149 natural gas forward contracts
that are subject to unplanned netting generally do not qualify for the
normal purchases and normal sales exception. ("Unplanned netting" refers
to situations whereby contracts are settled by paying or receiving money
for the difference between the contract price and the market price at
the date on which physical delivery would have occurred.) In addition,
effective January 1, 2004, power contracts that are subject to unplanned
netting and that do not meet the normal purchases and normal sales
exception under SFAS 149 will continue to be marked to market.
Implementation of SFAS 149 did not have a material impact on reported
net income.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity": This statement establishes
standards for how an issuer classifies and measures certain financial
instruments with characteristics of both liabilities and equity. SFAS
150 requires that certain mandatorily redeemable financial instruments
previously classified in the mezzanine section of the balance sheet be
reclassified as liabilities. The company adopted SFAS 150 beginning July
1, 2003 by reclassifying $200 million of mandatorily redeemable trust
preferred securities to Deferred Credits and Other Liabilities and $24
million of mandatorily redeemable preferred stock of subsidiaries to
Deferred Credits and Other Liabilities and to Other Current Liabilities
on the Consolidated Balance Sheets. In addition, dividend payments
required on these instruments, previously recorded to Preferred
Dividends of Subsidiaries and Trust Preferred Distributions, were
recorded to Interest Expense on the company's Statements of Consolidated
Income. For the year ended December 31, 2003, the related amount
recorded as interest expense for the last six months totaled $9 million.
On December 31, 2003, the $200 million of mandatorily redeemable trust
preferred securities were reclassified to Due to Unconsolidated
Affiliates due to the adoption of FIN 46 as discussed below.
EITF 98-10, "Accounting for Contracts Involved in Energy Trading and
Risk Management Activities": In accordance with the EITF's rescission of
Issue 98-10 by the release of Issue 02-3, the company no longer
recognizes energy-related contracts under mark-to-market accounting
unless the contracts meet the requirements stated under SFAS 133 and
SFAS 149, which is the case for a substantial majority of the company's
contracts. On January 1, 2003, the company recorded the initial effect
of Issue 98-10's rescission as a cumulative effect of a change in
accounting principle, which reduced after-tax earnings by $29 million.
63
On a net basis, $9 million of the $29 million was realized during the
year ended December 31, 2003. Neither the cumulative nor the ongoing
effect impacts the company's cash flow or liquidity.
EITF 02-3, "Issues Involved in Accounting for Derivative Contracts Held
for Trading Purposes and Contracts Involved in Energy Trading and Risk
Management Activities": In June 2002, a consensus was reached in EITF
02-3, which codifies and reconciles existing guidance on the recognition
and reporting of gains and losses on energy trading contracts, and
addresses other aspects of the accounting for contracts involved in
energy trading and risk management activities. Among other things, the
consensus requires that mark-to-market gains and losses on energy
trading contracts should be shown on a net basis in the income
statement, effective for financial statements issued for periods ending
after July 15, 2002. Adoption of EITF 02-3 in 2002 required that SES
change its method of recording trading activities from gross to net,
which had no impact on previously recorded gross margin, net income or
cash provided by operating activities. SET was already recording
revenues from trading activities on a net basis and required no change.
For 2001, recording revenues for all trading activities on a net basis
decreased previously reported revenues by $348 million to $7.7 billion.
There was no impact on reported revenues for the years ending December
31, 2003 and 2002 as trading activities were already reported on a net
basis.
EITF 03-11, "Reporting Realized Gains and Losses on Derivative
Instruments that are Subject to FASB Statement No. 133, Accounting for
Derivative Instruments and Hedging Activities and Not 'Held for Trading
Purposes' as Defined in EITF Issue No. 02-3, Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities":
During 2003, the EITF reached a consensus that determining whether
realized gains and losses on physically settled derivative contracts not
held for trading purposes should be reported in the income statement on
a gross or net basis is a matter of judgment that depends on the
relevant facts and circumstances. Adoption of EITF 03-11 in 2003 did not
have a significant impact to the company's financial statements and the
company does not expect a significant impact in the future.
FIN 45, "Guarantor's Accounting and Disclosure Requirements for
Guarantees": In November 2002, the FASB issued FIN 45, which elaborates
on the disclosures to be made in interim and annual financial statements
of a guarantor about its obligations under certain guarantees that it
has issued. It also clarifies that a guarantor is required to recognize,
at the inception of a guarantee, a liability for the fair value of the
obligation undertaken in issuing a guarantee. As of December 31, 2003,
substantially all of the company's guarantees were intercompany, whereby
the parent issues the guarantees on behalf of its consolidated
subsidiaries. The only significant guarantees for which disclosure is
required are that of the synthetic lease for the Mesquite Power plant,
the mandatorily redeemable trust preferred securities and $25 million
related to debt issued by Chilquinta Energia Finance, LLC, an
unconsolidated affiliate. The synthetic lease for the Mesquite Power
plant and the mandatorily redeemable trust preferred securities were
also affected by FIN 46, as described below.
64
FIN 46, "Consolidation of Variable Interest Entities an interpretation
of ARB No. 51": FIN 46 requires the primary beneficiary of a variable
interest entity's activities to consolidate the entity. During December
2003, the FASB issued FIN 46 revised (FIN 46R) to defer the
implementation date for pre-existing variable interest entities (VIEs)
that are special purpose entities (SPEs) until the end of the first
interim or annual period ending after December 15, 2003. For VIEs that
are not SPEs, companies must apply FIN 46R no later than the end of the
first reporting period ending after March 15, 2004.
Sempra Energy has identified two VIEs for which it is the primary
beneficiary. One of the VIEs (Mesquite Trust), which is an SPE, is the
owner of the Mesquite Power plant for which the company had a synthetic
lease agreement, as described in Notes 2 and 5. The Mesquite Power plant
is a 1,250-megawatt (MW) project that provides electricity to wholesale
energy markets in the Southwest. Construction began in September 2001
and the first phase of commercial operations (50 percent of the plant's
total capacity) began in June 2003. The second phase of commercial
operations (the remaining 50 percent) began in December 2003.
Accordingly, as the FASB's deliberations during the deferral period did
not result in the exclusion of Mesquite Trust from FIN 46's definitions,
Sempra Energy consolidated this entity in its financial statements at
December 31, 2003. The company bought out the lease in January 2004. At
December 31, 2003, the total assets and total liabilities of Mesquite
Trust were $643 million and $630 million, respectively. The company also
recorded an after-tax credit for the cumulative effect from the change
in accounting principle of $9 million.
The other variable interest entity is AEG, which markets power and
natural gas commodities to commercial and residential customers in the
United Kingdom. Sempra Energy consolidated AEG in its financial
statements at December 31, 2003. Consolidation of AEG required Sempra
Energy to record 100 percent of AEG's December 31, 2003 balance sheet,
whereas it previously recorded only its share of AEG's net operating
results. As of December 31, 2003 total assets and total liabilities of
this unconsolidated subsidiary were $180 million and $251 million,
respectively. Due to AEG's consolidation, the company recorded an after-
tax charge for the cumulative effect of the change in accounting
principle of $26 million.
In accordance with FIN 46R, the company deconsolidated a wholly owned
subsidiary trust from its financial statements at December 31, 2003. The
trust has no assets except for its corresponding receivable from the
company. Due to the deconsolidation of this entity, Sempra Energy has
reclassified $200 million of mandatorily redeemable trust preferred
securities to Due to Unconsolidated Affiliates on its Consolidated
Balance Sheets.
FASB Staff Position (FSP) 106-1, "Accounting and Disclosure Requirements
Related to the Medicare Prescription Drug, Improvement and Modernization
Act of 2003": Issued January 12, 2004, FSP 106-1 permits a sponsor of a
postretirement health care plan that provides a prescription drug
benefit to make a one-time election to defer accounting for the effects
of the Medicare Prescription Drug, Improvement and Modernization Act of
2003 (the Act). The company has elected to defer the effects of the Act
as provided by FSP 106-1. Any measure of the accumulated postretirement
benefit obligation or net periodic postretirement benefit cost in the
65
financial statements or the accompanying notes do not reflect the impact
of the Act on the plans. At this time, specific authoritative guidance
on the accounting for the federal subsidy provided by the Act is pending
and that guidance could require the company to change previously
reported information.
Other Accounting Standards: During 2003 and 2002 the FASB and the EITF
issued several statements that are not applicable to the company but
could be in the future. In April 2002, the FASB issued SFAS 145, which
rescinds SFAS 4, "Reporting Gains and Losses from Extinguishment of
Debt," and SFAS 64, "Extinguishments of Debt Made to Satisfy Sinking-
Fund Requirements." In June 2002, the FASB issued SFAS 146, "Accounting
for Costs Associated with Exit or Disposal Activities." SFAS 146
supersedes previous accounting guidance, principally EITF 94-3,
"Liability Recognition for Certain Employee Termination Benefits and
Other Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)."
NOTE 2. RECENT ACQUISITIONS AND INVESTMENTS
Sempra Energy Trading
In 2003, SET spent $27 million related to the development of Bluewater
Gas Storage, LLC, a natural gas storage facility in Michigan. SET owns
the rights to develop the facility and to utilize its capacity to store
natural gas for customers who buy, sell or transport natural gas in
Michigan. The facility is expected to commence operations in 2004.
During 2002, SET completed $119 million of acquisitions that added base
metals trading and warehousing to its trading business. On February 4,
2002, SET completed the acquisition of London-based Sempra Metals
Limited, a leading metals trader on the London Metals Exchange, for $65
million, net of cash acquired. In April 2002 SET completed the
acquisition of the assets of New York-based Sempra Metals & Concentrates
Corp., a leading global trader of copper, lead and zinc concentrates,
for $24 million. Also in April 2002, SET completed the acquisition of
Henry Bath & Sons Limited, which provides warehousing services for non-
ferrous metals in Europe and Asia, and the assets of the U.S.
warehousing business of Henry Bath, Inc., for a total of $30 million,
net of cash acquired.
As discussed in Note 1, the company recognized an extraordinary after-
tax gain of $16 million for negative goodwill for the acquisitions of
the base metals and concentrates businesses. Additional information on
the extraordinary gain is provided in Note 1. In addition, goodwill of
$21 million related to the acquisition of the metals warehousing
business was recorded on the Consolidated Balance Sheets and is expected
to be fully deductible for tax purposes.
66
Sempra Energy Resources
In October 2002 SER purchased a 305-MW, coal-fired power plant (renamed
Twin Oaks Power) for $120 million. SER sells substantially all of the
output of the plant under a five-year contract expiring on October 1,
2007. In connection with the acquisition, SER also assumed a contract
that includes annual commitments to purchase coal for the plant until an
aggregate minimum volume has been achieved or through 2025.
Termoelectrica De Mexicali (TDM), a 600-MW power plant near Mexicali,
Baja California, Mexico, commenced operations in July 2003. In May 2003,
a federal judge issued an order finding that the U.S. Department of
Energy's (DOE) abbreviated assessment of two Mexicali power plants,
including SER's TDM plant, failed to evaluate the plants' environmental
impact adequately and called into question the U.S. permits they
received to build their cross-border transmission lines. On July 8,
2003, the judge ordered the DOE to conduct additional environmental
studies, but denied the plaintiffs' request for an injunction blocking
operation of the transmission lines, thus allowing the continued
operation of the TDM plant. The DOE has until May 15, 2004, to
demonstrate why the court should not set aside the permits. Through
December 31, 2003, TDM has made capital expenditures of $342 million.
The 1,250-MW Mesquite Power plant, located near Phoenix, Arizona, cost
$686 million and provides electricity to wholesale energy markets in the
Southwest. The first phase of commercial operations (50 percent of the
plant's total capacity) began in June 2003. The second phase of
commercial operations (the remaining 50 percent) began in December 2003.
As of December 31, 2003, this project was owned by the Mesquite Trust
and financed through a synthetic lease agreement. Through December 31,
2003, SER had borrowed $630 million under this facility. All amounts
above $280 million required collateralization through purchases of U.S.
Treasury obligations. The collateralized U.S. Treasury obligation
amounted to $363 million at December 31, 2003. This is included in
Short-Term Investments on the Consolidated Balance Sheets. As a result
of implementing FIN 46, Sempra Energy consolidated the Mesquite Trust,
which had total assets and total liabilities of $643 million and $630
million, respectively, at December 31, 2003. See further discussion
under "New Accounting Standards" in Note 1. On January 21, 2004, SER
elected to purchase all of the power plant assets of Mesquite Trust for
$631 million. The purchase required cash of $268 million and the
liquidation of the $363 million in treasury securities held by the
Mesquite Trust as collateral.
Sempra Energy LNG Corp.
In April 2003, Sempra Energy LNG Corp. (SELNG) completed its acquisition
of the proposed Cameron liquefied natural gas (LNG) project in
Hackberry, Louisiana from a subsidiary of Dynegy, Inc. SELNG has paid
Dynegy $36 million for the acquisition, which includes rights to the
location, licensing and FERC approval of the project, which is still in
the permitting stage. Additional payments are contingent on meeting
certain benchmarks and milestones and the performance of the project. As
of December 31, 2003, the company had accrued $30 million as an estimate
of the contingent payment. The total cost of the project is expected to
be $700 million. The terminal will be capable of supplying 1.5 billion
cubic feet (bcf) of natural gas per day. Construction is expected to
67
begin in 2004 and commercial operations could begin in 2007. FERC
approved the construction and operation of the project in September
2003.
In December 2003, SELNG and Shell International Gas Limited (Shell)
announced plans to form a 50/50 joint venture to build, own and operate
Energia Costa Azul, a LNG receiving terminal in Baja California on the
west coast of Mexico, approximately 50 miles south of San Diego. The
proposed joint venture will combine the two separate Baja California LNG
receiving terminals proposed by Shell and SELNG into a single project.
It is expected that construction will begin in 2004 with terminal
operations commencing in 2007. The cost of the project is estimated to
be $600 million. The terminal will be capable of supplying 1 billion
cubic feet (bcf) of natural gas per day, half of which will be used to
meet the growing energy demands in western Mexico. The proposed joint
venture contemplates that SELNG and Shell would share the investment
costs of the terminal equally and each would take 50 percent of the
capacity of the terminal. Any surplus natural gas from the facility will
be used to provide new natural gas supplies for the southwestern United
States.
Also in December 2003, SELNG, British Petroleum and BPMiGas signed a
non-binding Heads of Agreement (HOA) for the supply of 500 million cubic
feet of gas a day from Indonesia's Tangguh LNG liquefaction facility to
Energia Costa Azul. The non-binding HOA is expected to be the precursor
to a full 20-year purchase/supply agreement.
Also in connection with this project, Mexico's national environmental
agency issued an environmental permit in April 2003. Three other
significant permits, an operating permit from Mexico's energy regulatory
commission, a local land-use permit from the City of Ensenada and a
coastal zone use permit, were granted in 2003. The permit to construct
marine facilities is pending and expected to be received in the near
future. In November 2003, a Mexican tribunal issued the equivalent of a
preliminary injunction against a Mexican environmental agency's adoption
of the environmental impact authorization covering the project. The
injunction temporarily suspends the permit until the matter can proceed
to a hearing on the merits of the authorization. Sempra Energy believes
the suspension of these permits will be temporary and will not delay the
2007 commercial start date of the terminal.
Sempra Energy International
SEI's Mexican subsidiaries build and operate natural gas distribution
systems in Mexicali, Chihuahua and the La Laguna-Durango zone in north-
central Mexico. On February 7, 2003, SEI purchased the remaining
minority interests in its Mexican subsidiaries.
NOTE 3. INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES
Investments are accounted for under the equity method when the company
has an ownership interest of twenty to fifty percent. In these cases the
company's pro rata shares of the subsidiaries' net assets are included
in Investments on the Consolidated Balance Sheets, and are adjusted for
the company's share of each investee's earnings or losses, dividends and
foreign currency translation effects. Earnings are recorded as equity
earnings in Other Income - Net on the Statements of Consolidated Income.
68
The company accounts for certain investments in housing partnerships
made before May 19, 1995 under the cost method, whereby they are
amortized over ten years based on the expected residual value. The
company has no unconsolidated subsidiaries where its ability to
influence or control an investee differs from its ownership percentage.
The company's long-term investments are summarized as follows:
December 31,
(Dollars in millions) 2003 2002
- -----------------------------------------------------------------------
Equity method investments:
Chilquinta Energia $ 337 $ 387
Luz del Sur 177 117
Sodigas Pampeana and Sodigas Sur 66 17
Elk Hills power project 218 172
El Dorado Energy 68 73
Sempra Energy Financial housing partnerships 175 206
Sempra Energy Financial synthetic fuel partnerships 14 8
------- -------
Total 1,055 980
------- -------
Cost method investments:
Sempra Energy Financial housing partnerships 47 57
Other 12 3
------- -------
Total 59 60
------- -------
Investments in unconsolidated subsidiaries 1,114 1,040
------- -------
Other:
Mesquite power plant project
Collateralized U.S. Treasury obligations* -- 228
Reimbursable project costs -- 45
------- -------
Total -- 273
------- -------
Total long-term investments $ 1,114 $ 1,313
- -----------------------------------------------------------------------
* The balance of $363 million at December 31, 2003 was reclassified to
Short-Term Investments.
For equity method investments, costs in excess of equity in net assets
were $232 million and $219 million at December 31, 2003 and 2002,
respectively. Through December 31, 2001, the excess of the investment
over the related equity in net assets had been amortized over various
periods, primarily forty years (see Note 1). In accordance with SFAS
142, amortization ceased in 2002. Costs in excess of the underlying
equity in net assets will continue to be reviewed for impairment in
accordance with APB Opinion 18, "The Equity Method of Accounting for
Investments in Common Equity." See additional discussion of SFAS 142 in
"New Accounting Standards" in Note 1. Descriptive information concerning
each of these subsidiaries follows.
69
Sempra Energy International
SEI and PSEG Global (PSEG), an unaffiliated company, each own a 50-
percent interest in Chilquinta Energia S.A., a Chilean electric utility,
and 44 percent interests in Luz del Sur S.A.A. (Luz del Sur), a Peruvian
electric utility.
SEI also owns 43 percent of two Argentine natural gas utility holding
companies, Sodigas Pampeana S.A. and Sodigas Sur S.A. As a result of the
devaluation of the Argentine peso at the end of 2001 and subsequent
declines in the value of the peso, SEI had reduced the carrying value of
its investment downward by a cumulative total of $197 million as of
December 31, 2003. These non-cash adjustments continue to occur based on
fluctuations in the Argentine peso. They do not affect net income, but
increase or decrease other comprehensive income (loss) and accumulated
other comprehensive income (loss).
The related Argentine economic decline and government responses
(including Argentina's unilateral, retroactive abrogation of utility
agreements early in 2002) continue to adversely affect the operations of
these Argentine utilities. In 2002, SEI initiated arbitration
proceedings under the 1994 Bilateral Investment Treaty between the
United States and Argentina for recovery of the diminution of the value
of its investments that has resulted from Argentine governmental
actions. In 2003, SEI filed its legal brief with the International
Center for Settlement of Investment Disputes, outlining its claims for
$258 million. The company has also presented additional information that
may provide a basis for a larger award. A decision is expected in early
2005. Sempra Energy also has a $48.5 million political-risk insurance
policy under which it filed a claim to recover a portion of the
investments' diminution in value.
Sempra Energy Resources
The 550-MW Elk Hills Power (Elk Hills) project, which is located near
Bakersfield, California, began commercial operations in July 2003. Elk
Hills is 50 percent owned by SER in a joint venture with Occidental
Energy Ventures Corporation.
The 480-MW El Dorado power plant, located near Las Vegas, Nevada, began
commercial operations in May 2000. The El Dorado Energy project is 50
percent owned by SER in a joint venture partnership with Reliant Energy
Power Generation.
At December 31, 2003, the investments in U.S. Treasury obligations
related to the Mesquite project was reclassified to short-term
investments as the result of the company buying out the lease in January
2004. See discussion in Note 1.
Sempra Energy Financial (SEF)
SEF invests as a limited partner in affordable-housing properties. SEF's
portfolio includes 1,300 properties throughout the United States that
are expected to provide income tax benefits (primarily from income tax
credits) over 10-year periods. SEF also has an investment in a limited
partnership which produces synthetic fuel from coal. Whether SEF will
70
invest in additional properties will depend on Sempra Energy's income
tax position. See additional discussion of income tax issues in Note 7.
NOTE 4. SHORT-TERM BORROWINGS
At December 31, 2003, the company had available $2.1 billion in unused,
committed lines of credit to provide liquidity and support commercial
paper.
Committed Lines of Credit
Sempra Energy Global Enterprises (Global) has two syndicated revolving
credit agreements, each permitting revolving credit borrowings of $500
million. One is a 364-day credit agreement that may be converted into a
one-year term loan upon the August 2004 expiration of the revolving
credit period. The other is a three-year agreement permitting revolving
credit borrowings until the expiration of the agreement in August 2006.
Borrowings under the agreements are guaranteed by Sempra Energy and bear
interest at rates varying with market rates and Sempra Energy's credit
ratings. Both agreements require Sempra Energy to maintain a debt-to-
total capitalization ratio (as identically defined in each agreement) of
not to exceed 65 percent. Global had no commercial paper outstanding at
December 31, 2003 and $422 million of commercial paper outstanding at
December 31, 2002. As of December 31, 2003, a letter of credit for $18
million was outstanding under the second agreement.
SER has a syndicated $400 million revolving credit agreement guaranteed
by Sempra Energy. The agreement requires Sempra Energy to maintain a
debt-to-total capitalization ratio (as defined in the agreement) of not
to exceed 65 percent. The agreement expires in August 2004 and
borrowings bear interest at rates varying with market rates and Sempra
Energy's credit rating. At December 31, 2003, SER had no outstanding
borrowings under the agreement. At December 31, 2002, there was $100
million outstanding under the agreement. See Note 5 for additional
information on SER's borrowings.
The California Utilities have a combined revolving line of credit, under
which each utility individually may borrow up to $300 million, subject
to a combined borrowing limit for both utilities of $500 million.
Borrowings under the agreement bear interest at rates varying with
market rates and the utility's credit rating. The revolving credit
commitment expires in May 2004, at which time outstanding borrowings may
be converted into a one-year term loan subject to any requisite
regulatory approvals related to long-term debt. The agreement requires
each utility to maintain a debt-to-total capitalization ratio (as
defined in the agreement) of not to exceed 60 percent. Borrowings under
the agreement are individual obligations of the borrowing utility and a
default by one utility would not constitute a default or preclude
borrowings by the other. These lines of credit have never been drawn
upon. At December 31, 2003 and 2002, the California Utilities had no
commercial paper outstanding.
PE has a $375 million revolving agreement, guaranteed by Sempra Energy,
for the purpose of providing loans to Global. The revolving credit
commitment, initially $500 million, and $375 million at December 31,
2003, declines semi-annually by $125 million until expiration on April
5, 2005. Borrowings are guaranteed by Sempra and are subject to
71
mandatory repayment prior to the maturity date should SoCalGas'
unsecured long-term credit ratings cease to be at least BBB by Standard
& Poor's (S&P) and Baa2 by Moody's Investor Services, Inc. (Moody's),
should Sempra Energy's or SoCalGas' debt-to-total capitalization ratio
(as defined in the agreement) exceed 65 percent, or should there be a
change in law materially and adversely affecting the ability of SoCalGas
to pay dividends or make distributions to PE. Borrowings bear interest
at rates varying with market rates, PE's credit ratings and the amount
of outstanding borrowings. This line of credit has never been used.
Uncommitted Lines of Credit
SET has $770 million in various uncommitted lines of credit that are
guaranteed by Sempra Energy and bear interest at rates varying with
market rates and Sempra Energy's credit rating. At December 31, 2003,
SET had $420 million of letters of credit, but no short-term borrowings,
outstanding against these lines. The corresponding amounts outstanding
at December 31, 2002 were $345 million and $115 million, respectively.
Other
Sempra Energy Solutions had $28 million of short-term debt with an
average interest rate of 7.56% outstanding at December 31, 2003 and $33
million at December 31, 2002. Sempra Energy had no other short-term debt
at December 31, 2003. The company's weighted average interest rate for
short-term borrowings outstanding at December 31, 2002 was 2.02%
72
NOTE 5. LONG-TERM DEBT
<table>
<caption>
- -------------------------------------------------------------------
December 31,
(Dollars in millions) 2003 2002
- -------------------------------------------------------------------
<s> <c> <c>
First mortgage bonds
4.375% January 15, 2011 $ 100 $ --
Variable rates after
fixed to floating rate swaps (1.43%
at December 31, 2003) January 15, 2011 150 --
4.8% October 1, 2012 250 250
6.8% June 1, 2015 14 14
5.45% April 15, 2018 250 --
5.9% June 1, 2018 68 68
5.9% to 6.4% September 1, 2018 176 176
6.1% September 1, 2019 35 35
Variable rates (1.25% at
December 31, 2003) September 1, 2020 58 58
5.85% June 1, 2021 60 60
6.875% November 1, 2025 175 175
5.25% to 7% December 1, 2027 225 225
5.75% November 15, 2003 -- 100
7.375% March 1, 2023 -- 100
7.5% June 15, 2023 -- 125
-----------------------
Total 1,561 1,386
Other long-term debt
Variable rates due September 2005
(2.02% to 5.12% at December 31, 2003) 630 --
5.60% equity units May 17, 2007 600 600
Notes payable at variable rates after a
fixed-to-floating rate swap (2.49%
at December 31, 2003) July 1, 2004 500 500
7.95% Notes March 1, 2010 500 500
6.0% Notes due February 1, 2013 400 --
6.95% Notes December 1, 2005 300 300
Rate-reduction bonds, 6.31% to 6.37%
annually through 2007 263 329
5.9% June 1, 2014 130 130
Debt incurred to acquire limited
partnerships, secured by real estate, at
7.13% to 9.35% annually through 2009 110 145
Employee Stock Ownership Plan
Bonds at 7.375% November 1, 2014 82 82
Bonds at variable rates (1.65% at
December 31, 2003) November 1, 2014 19 19
Variable rates (1.45% at December 31, 2003)
December 1, 2021 60 60
Variable rates (1.46% at December 31, 2003)
July 1, 2021 39 39
6.75% March 1, 2023 25 25
6.375% May 14, 2006 8 8
5.67% January 18, 2028 5 75
Other variable-rate debt 15 18
Capitalized leases 8 10
SER line of credit at variable rates
August 21, 2004 -- 100
Market value adjustments for interest
rate swaps - net (expires July 1, 2004) 23 42
-----------------------
5,278 4,368
Current portion of long-term debt (1,433) (281)
Unamortized discount on long-term debt (4) (4)
-----------------------
Total $3,841 $4,083
- -------------------------------------------------------------------
</table>
73
Excluding capital leases, which are described in Note 15, and market
value adjustments for interest-rate swaps, maturities of long-term debt
are $1.4 billion in 2004, $397 million in 2005, $101 million in 2006,
$682 million in 2007, $8 million in 2008 and $2.7 billion thereafter.
On January 26, 2004, SoCalGas optionally redeemed its $175 million
6.875% first mortgage bonds. Therefore that liability is classified as
current at December 31, 2003. On January 21, 2004, SER elected to
purchase the assets of Mesquite Trust and extinguish the $630 million
of related debt outstanding. Therefore that liability also is
classified as short-term at December 31, 2003. Holders of variable-rate
bonds may require the issuer to repurchase them prior to scheduled
maturity. However, since repurchased bonds would be remarketed and
funds for repurchase are provided by revolving credit agreements (which
are generally renewed upon expiration and which are described in Note
4), it is expected that the bonds will be held to the maturities stated
above. Interest rates on the $500 million of notes maturing in 2004 can
vary with the company's credit ratings.
Issuances of $900 million, $1.2 billion and $675 million of long-term
debt, and payments of $601 million, $479 million and $681 million on
long-term debt were made in 2003, 2002 and 2001, respectively.
Callable Bonds
At the company's option, certain bonds are callable at various dates.
Of the company's callable bonds, $873 million are callable in 2004, $105
million in 2005, $8 million in 2006 and $45 million thereafter.
First Mortgage Bonds
The first mortgage bonds were issued by the California Utilities and are
secured by a lien on their respective utility plant. The California
Utilities may issue additional first mortgage bonds upon compliance with
the provisions of their bond indentures, which require, among other
things, the satisfaction of pro forma earnings-coverage tests on first
mortgage bond interest and the availability of sufficient mortgaged
property to support the additional bonds, after giving effect to prior
bond redemptions. The most restrictive of these tests (the property
test) would permit the issuance, subject to CPUC authorization, of an
additional $2.8 billion of first mortgage bonds at December 31, 2003.
During the first quarter of 2001, SDG&E remarketed $150 million of
variable-rate first mortgage bonds for various terms at a fixed rate of
7%. $45 million of these bonds came to term on December 1, 2003 and were
remarketed to maturity with a rate of 5.25%. At SDG&E's option, the
remaining bonds may be remarketed at a fixed or floating rate at
December 1, 2005, the expiration of the fixed terms.
In November 2001, SoCalGas optionally redeemed its $150 million 8.75%
first mortgage bonds. In December 2001, SoCalGas entered into an
interest-rate swap which effectively exchanged the fixed rate on its
$175 million 6.875% first mortgage bonds for a floating rate. In
September 2002, SoCalGas terminated the swap, receiving cash proceeds of
$10 million, comprised of $4 million in accrued interest and a $6
million amortizable gain.
74
In June 2002, SDG&E paid at maturity its $28 million 7.625% first
mortgage bonds. In July 2002 the company optionally redeemed its $10
million 8.5% first mortgage bonds.
In August 2002, SoCalGas paid at maturity its $100 million 6.875% first
mortgage bonds. In October 2002, SoCalGas publicly offered and sold $250
million of 4.8% first mortgage bonds, maturing on October 1, 2012. The
bonds are not subject to a sinking fund and are redeemable prior to
maturity only through a make-whole mechanism. Proceeds from the bond
sale were used to replenish amounts previously expended to refund and
retire indebtedness, and for working capital and other general corporate
purposes.
On April 7, 2003, SoCalGas optionally redeemed its $100 million 7.375%
first mortgage bonds. On August 21, 2003, SoCalGas optionally redeemed
its $125 million 7.5% first mortgage bonds.
On October 17, 2003, SoCalGas issued $250 million of 5.45% first
mortgage bonds due in April 2018. The proceeds were used to replenish
amounts previously expended to refund and retire indebtedness and for
general corporate purposes. On November 17, 2003, SoCalGas paid off its
$100 million 5.75% first mortgage bonds.
On December 15, 2003, SoCalGas issued $250 million of 4.375% first
mortgage bonds maturing in January 2011. The proceeds were used to
retire outstanding debt and for other general corporate purposes. On
December 15, 2003, SoCalGas entered into an interest-rate swap which
effectively exchanged the fixed rate on $150 million of the 4.375% first
mortgage bonds for a floating rate.
Mesquite Power
The company consolidated Mesquite Trust, the owner of Mesquite Power, on
its financial statements as of December 31, 2003 as a result of
implementing FIN 46. The debt outstanding was $630 million comprised of
notes payable due in 2005 at various interest rates. On January 21,
2004, SER elected to purchase all of the power plant assets of Mesquite
Trust for $631 million and extinguished the related Mesquite debt.
Therefore the liability is classified as short-term at December 31,
2003. See further discussion under New Accounting Standards in Note 1.
For additional information on the Mesquite Power synthetic lease, refer
to Note 2.
Equity Units
In April and May of 2002, the company publicly offered and issued $600
million of Equity Units. For additional information on Equity Units
refer to Note 12.
Unsecured Long-term Debt
Various long-term obligations totaling $2.7 billion are unsecured at
December 31, 2003.
In February 2001, SDG&E remarketed $25 million of variable-rate
unsecured bonds as 6.75 percent fixed-rate debt for a three-year term.
75
In June 2001, the company issued $500 million of 6.8% notes due July 1,
2004. Sempra Energy has a fixed-to-floating rate swap on these notes. In
October 2001, SoCalGas paid at maturity its $120 million of 6.38%
medium-term notes.
SER borrowed $100 million on its $400 million line of credit in October
2002 and repaid it in March 2003. There were no loans outstanding on
SER's line of credit at December 31, 2003. This agreement expires in
August 2004 and bears interest at rates varying with market rates and
Sempra Energy's credit ratings. For additional information regarding
this line of credit see Note 4.
On January 15, 2003, $70 million of SoCalGas' 5.67% $75 million medium-
term notes were put back to the company. The remaining $5 million
matures in 2028.
In January 2003, the company issued $400 million of long-term 6% notes
due in February 2013. The bonds are not subject to a sinking fund and
are redeemable prior to maturity only through a make-whole mechanism.
The proceeds were used to pay down commercial paper.
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. They are being repaid over ten
years by SDG&E's residential and small-commercial customers through a
specified 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.
Debt of Employee Stock Ownership Plan (ESOP) and Trust (Trust)
The Trust covers substantially all of the employees of the parent
organization, SoCalGas and most of Global's subsidiaries. The Trust is
used to fund part of the retirement savings plan described in Note 8.
The 15-year notes are repriced weekly and subject to repurchase by the
company at the holder's option, depending on market demand. In June
2001, utilizing the term option provisions of the notes, $82 million of
the notes were remarketed at a fixed rate of 7.375 percent for three
years. The variable interest rate and weekly repricing resume in May
2004. ESOP debt was reduced by $4.2 million during the last three years
when 70,000 shares of company common stock were released from the Trust
in order to fund the employer contribution to the company savings plan.
Interest on the ESOP debt amounted to $6 million in 2003, $7 million in
2002 and $6 million in 2001. Dividends used for debt service amounted to
$2 million in 2003, $3 million in 2002, and $3 million in 2001.
Interest-Rate Swaps
The company periodically enters into interest-rate swap agreements to
moderate its exposure to interest-rate changes and to lower its overall
cost of borrowing. The schedule of long-term debt reflects past swap
interest rates. The company believes the swaps have been fully effective
in their purpose of converting the underlying debt's fixed rates to
floating rates and meet the criteria for accounting under one of the
76
methods defined in SFAS 133 for fair value hedges of debt instruments.
Accordingly, market value adjustments to long-term debt of ($19) million
and $20 million were recorded in 2003 and 2002, respectively, to
reflect, without affecting net income or other comprehensive income, the
favorable or (unfavorable) economic consequences (as measured at
December 31, 2003 and 2002) of having entered into the swap
transactions.
During 2002 and 2001, SDG&E had an interest-rate swap agreement that
effectively fixed the interest rate on $45 million of variable-rate
underlying debt at 5.4 percent. This floating-to-fixed-rate swap did not
qualify for hedge accounting and, therefore, the gains and losses
associated with the change in fair value are recorded in the Statements
of Consolidated Income. The effect on net income was a $1 million gain
in 2002 and a $1 million loss in 2001.
Foreign Currency Hedges
The company's primary objective with respect to currency risk is to
reduce net income volatility that would otherwise occur due to exchange-
rate fluctuations.
Sempra Energy's net investment in its Latin American operating companies
and the resulting cash flows are partially protected against normal
exchange-rate fluctuations by rate-setting mechanisms that are intended
to compensate for local inflation and currency exchange-rate
fluctuations. In addition to establishing such tariff-based protections,
the company offsets material cross-currency transactions and net income
exposure through various means, including financial instruments and
short-term investments.
Because the company does not hedge its net investment in foreign
countries, it is susceptible to volatility in other comprehensive
income, as occurred in the last three years primarily as a result of
decoupling the Argentine peso from the U.S. dollar, as discussed in Note
3.
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, 2003, are
as follows:
(Dollars in millions) Southwest
Project SONGS Powerlink
- --------------------------------------------------------------------
Percentage ownership (1) 20% 89%
Utility plant in service $ 11 $237
Accumulated depreciation and amortization $ 5 $141
Construction work in progress $ -- $ 27
- --------------------------------------------------------------------
(1) SDG&E's 20% ownership in SONGS has been fully recovered and is no
longer included under utility plant and accumulated depreciation.
The amounts specified above for SONGS represent wholly owned substation
equipment. As of December 31, 2003, the company has fully recovered its
77
interest in SONGS through the ICIP mechanism. Additional information
concerning the ICIP mechanism is provided in Note 13.
The company and the other owners each hold its interest as an undivided
interest as tenants in common. Each owner is responsible for financing
its share of each project and participates in decisions concerning
operations and capital expenditures.
The company's share of operating expenses is included in the Statements
of Consolidated Income.
SONGS Decommissioning
Objectives, work scope and procedures for the 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 $316 million in 2003 dollars. Cost studies are updated
every three years, with the next update expected to be submitted to the
CPUC for its approval in 2005. Rate recovery of decommissioning costs is
allowed until the time that the costs are fully recovered, and is
subject to adjustment every three years based on the costs allowed by
regulators. Collections are authorized to continue until 2013, but may
be extended by CPUC approval until 2022, at which time the SONGS'
operating license ends and the decommissioning of SONGS 2 and 3 would be
expected to begin. Payments to the nuclear decommissioning trusts
(described in "Nuclear Decommissioning Trusts") are expected to continue
until 2013 at which time sufficient funds are expected to be collected
to fully decommission SONGS. If funds are not sufficient, additional
future rate recovery is expected to occur.
The amounts collected in rates are invested in the externally managed
trust funds. The securities held by the nuclear decommissioning trusts
are considered available for sale. These trusts are shown on the
Consolidated Balance Sheets at market value. At December 31, 2003,
these trusts reflected unrealized gains of $159 million with the
offsetting credits recorded on the Consolidated Balance Sheets to Asset
Retirement Obligations and the related regulatory liabilities. At
December 31, 2002, these trusts reflected unrealized gains of $95
million with the offsetting credits recorded to Deferred Credits and
Other Liabilities and the related regulatory liabilities.
Unit 1 was permanently shut down in 1992, and physical decommissioning
began in January 2000. Several structures, foundations and large
components have been dismantled, removed and disposed of. Preparations
have been made for the remaining major work to be performed in 2004 and
beyond. That work will include dismantling, removal and disposal of all
remaining Unit 1 equipment and facilities (both nuclear and non-nuclear
components), decontamination of the site and completion of an on-site
storage facility for Unit 1 spent fuel. These activities are expected to
be completed in 2008.
See discussion regarding the impact of SFAS 143 in Note 1.
78
Nuclear Decommissioning Trusts
SDG&E has established a Nonqualified Nuclear Decommissioning Trust and a
Qualified Nuclear Decommissioning Trust to provide funds for the
decommissioning of SONGS as described above. Amounts held by these
trusts are invested in accordance with CPUC regulations that establish
maximum amounts for investments in equity securities (50 percent of the
qualified trust and 60 percent of the nonqualified trust), international
equity securities (20 percent) and securities of electric utilities
having ownership interests in nuclear power plants (10 percent). Not
less than 50 percent of the equity portion of these trusts must be
invested passively.
At December 31, 2003 and 2002, trust assets were allocated as follows
(dollars in millions):
Qualified Trust Nonqualified Trust
-----------------------------------------
2003 2002 2003 2002
------------- ------------------
Domestic equity $ 163 $ 143 $ 43 $ 36
Foreign equity 88 69 -- --
----- ----- ---- ----
Total equity 251 212 43 36
Total fixed income 249 220 27 26
----- ----- ---- ----
Total $ 500 $ 432 $ 70 $ 62
===== ===== ==== ====
Customer contribution amounts are determined by estimates of after-tax
investment returns, decommissioning costs and decommissioning cost
escalation rates. Lower actual investment returns or higher actual
decommissioning costs would result in an increase in customer
contributions.
Additional information regarding SONGS is included in Notes 13 and 15.
79
NOTE 7. INCOME TAXES
The reconciliation of the statutory federal income tax rate to the
effective income tax rate is as follows:
Years ended December 31,
2003 2002 2001
- -----------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Utility depreciation 6.7 5.2 5.9
State income taxes - net of federal
income tax benefit 7.0 7.0 6.4
Tax credits (22.6) (18.5) (13.7)
Income from unconsolidated foreign
subsidiaries (4.3) (2.0) (3.0)
Settlement of Internal Revenue Service audit (11.2) (3.6) --
Other - net (4.3) (2.9) (1.5)
---------------------------
Effective income tax rate 6.3% 20.2% 29.1%
- -----------------------------------------------------------------------
The components of total income (loss) from operations (including
continuing extraordinary items) before income taxes are as follows:
(Dollars in millions) 2003 2002 2001
- -----------------------------------------------------------------------
Domestic $ 551 $ 584 $ 651
Foreign 191 137 80
-------------------------
Total income before income taxes $ 742 $ 721 $ 731
- -----------------------------------------------------------------------
The components of income tax expense are as follows:
(Dollars in millions) 2003 2002 2001
- ----------------------------------------------------------------------
Current:
Federal $ 93 $ 195 $ 36
State 16 30 60
Foreign 11 13 11
------------------------
Total 120 238 107
------------------------
Deferred:
Federal (138) (113) 104
State 53 31 1
Foreign 18 (5) 7
------------------------
Total (67) (87) 112
------------------------
Deferred investment tax credits (6) (5) (6)
------------------------
Total income tax expense $ 47 $ 146 $ 213
- ----------------------------------------------------------------------
80
Accumulated deferred income taxes at December 31 relate to the
following:
(Dollars in millions) 2003 2002
- ----------------------------------------------------------------------
Deferred tax liabilities:
Differences in financial and
tax bases of property, plant and equipment $1,094 $ 883
Balancing accounts and
regulatory assets 314 298
Partnership income 34 45
Unrealized revenue 63 53
Other 211 266
--------------------
Total deferred tax liabilities 1,716 1,545
--------------------
Deferred tax assets:
Investment tax credits 61 62
General business tax credit carryforward 192 148
Net operating losses of foreign entities 112 89
Postretirement benefits 31 32
Other deferred liabilities 190 157
Restructuring costs -- 40
Compensation-related items 134 154
Bad debt allowance 28 --
State income taxes 57 46
Credits from Alternative Minimum Tax 74 19
Valuation allowance (20) (10)
Other 100 28
---------------------
Total deferred tax assets 959 765
---------------------
Net deferred income tax liability $ 757 $ 780
- ----------------------------------------------------------------------
The net deferred income tax liability is recorded on the Consolidated
Balance Sheets at December 31 as follows:
(Dollars in millions) 2003 2002
- ----------------------------------------------------------------------
Current (asset) liability $ 123 $ (20)
Noncurrent liability 634 800
--------------------
Total $ 757 $ 780
- ----------------------------------------------------------------------
In connection with its affordable-housing investments, the company has
$192 million of unused general business tax credits in varying amounts
dating back to 1999. The ability to offset these credits against future
taxable income will expire between the years 2019 and 2022. The company
expects to utilize the credits in future years. In addition, the company
has $74 million of alternative minimum tax credits with no expiration
date. All of these credits have been included in the company's
calculation of income tax expense.
Foreign subsidiaries have $340 million in unused net operating losses
available to reduce future income taxes, primarily in Mexico, Canada and
81
the United Kingdom. Utilization of these losses began to expire in 2002.
Financial statement benefits have been recorded on all but $66 million
of these losses, primarily by offsetting them against deferred tax
liabilities with the same expiration pattern and country of
jurisdiction. No benefits have been recorded on $66 million of the
losses because they have been incurred in jurisdictions where
utilization is sufficiently in doubt.
The company has not provided for U.S. income taxes on foreign
subsidiaries' undistributed earnings ($360 million at December 31,
2003), since they are expected to be reinvested indefinitely outside the
U.S. It is not possible to predict the amount of U.S. income taxes that
might be payable if these earnings were eventually repatriated.
Section 29 Income Tax Credits
In 2003 the Internal Revenue Service (IRS) issued Announcement 2003-46,
stating it has reason to question the scientific validity of testing
procedures and results related to Section 29 income tax credits. The
notice also announced that it would suspend the issuance of new rulings
until its review is complete and that rulings could be revoked if the
IRS did not determine that the test procedures demonstrate a significant
chemical change between the feedstock coal and the synthetic fuel. The
IRS completed its review and on October 29, 2003, announced that it
would again be issuing private letter rulings based on the previous
requirements. Many such rulings have been issued since that date,
including one involving operations owned by the company. The Permanent
Subcommittee on Investigations of the U.S. Senate's Committee on
Governmental Affairs has initiated an investigation on the subject of
these income tax credits. In January 2004, the company received a letter
from the Committee requesting certain information about its synthetic
fuel operations and it is in the process of responding to this inquiry.
As part of its recently commenced normal audit program for the company
for the period 1998-2001, the IRS notified the company of its intention
to audit the synthetic fuel operations of SET and SEF. From acquisition
of the facilities in 1998 through December 31, 2003, the company has
recorded Section 29 income tax credits of $251 million of which $107
million were recorded for the year ended December 31, 2003. The company
believes disallowance of Section 29 income tax credits is unlikely.
Luz del Sur
The Peruvian tax authorities (Sunat) had assessed additional taxes for
1999 based on their challenge of Luz del Sur's revaluation of its assets
and also previously announced that they would assess additional taxes
for the years 1996 through 1998 for the same concept. The Peruvian Tax
Court recently ruled that no additional taxes could be assessed for 1996
through 1998 and that any additional taxes for 1999 could only be
assessed if the Sunat showed that Luz del Sur had revalued its assets
beyond their market value. If Sunat is successful in its challenge,
income tax deductions for depreciation will be reduced, resulting in
additional income taxes, interest and penalties aggregating as much as
$10 million for the company's share for the period being questioned
(1999) and $12 million for subsequent periods. The company believes that
it has substantial defenses to such challenges and that the imposition
of any additional taxes is not probable.
82
Spanish Holding Company
The IRS has issued Notice 2003-50, stating that regulations will be
issued that will adversely affect foreign tax credit utilization by
companies with "stapled-stock" affiliates. The company's intermediate
parent company for many of its non-domestic subsidiaries is such a
company. Although not probable, the most adverse resolution of this
issue could result in a charge to net income of $13 million by the
company.
Resolution of Certain Internal Revenue Service Matters
The company favorably resolved matters related to various prior years'
returns during 2003. The primary issue involving the treatment of
utility balancing accounts for the California Utilities was resolved
following the issuance of an IRS Revenue Ruling and resolution of
factual issues involving these claims with the IRS. The total effect on
after-tax earnings and future cash flows for all IRS issues was $118
million, of which $79 million was at SDG&E and $29 million was at
SoCalGas.
NOTE 8. EMPLOYEE BENEFIT PLANS
The information presented below covers the plans of the company and its
principal subsidiaries.
Pension and Other Postretirement Benefits
The company has funded and unfunded noncontributory defined benefit
plans that together cover substantially all of its employees. The plans
provide defined benefits based on years of service and final average
salary.
The company also has other postretirement benefit plans covering
substantially all of its employees. The life insurance plans are
noncontributory and the health care plans are contributory, with
participants' contributions adjusted annually. Other postretirement
benefits include retiree life insurance, medical benefits for retirees
and their spouses and Medicare Part B reimbursement for certain
retirees.
The company maintains dedicated assets in support of its Supplemental
Executive Retirement Plan.
During 2002, the company had amendments reflecting retiree cost of
living adjustments, which resulted in an increase in the pension plan
benefit obligation of $51 million. Amendments to other postretirement
benefit plans related to the transfer of employees to SDG&E and changes
to their specific benefits resulted in a decrease in the benefits
obligation of $7 million. The amortization of these changes will affect
pension expense in future years.
During 2001, the company participated in a voluntary separation program.
As a result, it recorded a $13 million special termination benefit, a $1
million curtailment cost and a $19 million settlement gain.
83
There were no amendments to the company's pension and other
postretirement benefit plans in 2003.
December 31 is the measurement date for the pension and other
postretirement benefit plans.
The following tables provide a reconciliation of the changes in the
plans' projected benefit obligations during the latest two years, the
fair value of assets and a statement of the funded status as of the
latest two year ends:
<table>
<caption>
Other
Pension Benefits Postretirement Benefits
-------------------------------------------
(Dollars in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------
<s> <c> <c> <c> <c>
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net obligation at January 1 $ 2,290 $ 2,010 $ 797 $ 590
Service cost 52 57 19 13
Interest cost 152 149 55 42
Actuarial loss 285 197 116 191
Benefit payments (201) (187) (33) (32)
Plan amendments -- 51 -- (7)
Other -- 13 -- --
--------------------------------------------
Net obligation at December 31 2,578 2,290 954 797
--------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1 1,984 2,449 409 469
Actual return on plan assets 453 (281) 90 (50)
Employer contributions 27 3 53 22
Benefit payments (201) (187) (33) (32)
--------------------------------------------
Fair value of plan assets at December 31 2,263 1,984 519 409
--------------------------------------------
Benefit obligation, net of plan assets
at December 31 (315) (306) (435) (388)
Unrecognized net actuarial loss 273 283 317 266
Unrecognized prior service cost 83 93 (13) (14)
Unrecognized net transition obligation 1 1 -- --
--------------------------------------------
Net recorded asset (liability)
at December 31 $ 42 $ 71 $ (131) $ (136)
- -----------------------------------------------------------------------------------------
The following table provides the amounts recognized on the Consolidated
Balance Sheets (in Noncurrent Sundry Assets, Deferred Credits and Other
Liabilities, and Postretirement Benefits Other Than Pensions) at
December 31:
Other
Pension Benefits Postretirement Benefits
-------------------------------------------
(Dollars in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------
Prepaid benefit cost $ 178 $ 203 $ -- $ --
Accrued benefit cost (136) (132) (131) (136)
Additional minimum liability (118) (93) -- --
Intangible asset 9 12 -- --
Accumulated other comprehensive
income, pretax 109 81 -- --
-------------------------------------------
Net recorded asset (liability) $ 42 $ 71 $ (131) $ (136)
- -----------------------------------------------------------------------------------------
84
The accumulated benefit obligation for defined benefit pension plans was
$2.4 billion and $2 billion at December 31, 2003 and 2002, respectively.
The following table provides information concerning pension plans with
benefit obligations in excess of plan assets as of December 31.
Projected Benefit Accumulated Benefit
Obligation Exceeds Obligation Exceeds
the Fair Value of the Fair Value of
Plan Assets Plan Assets
-------------------------------------------
(Dollars in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------
Projected benefit obligation $ 2,341 $ 2,091 $ 815 $ 736
Accumulated benefit obligation $ 2,126 $ 1,849 $ 793 $ 684
Fair value of plan assets $ 2,011 $ 1,757 $ 538 $ 468
</table>
The following table provides the components of net periodic benefit
costs (income) for the years ended December 31:
<table>
<caption>
Other
Pension Benefits Postretirement Benefits
--------------------------------------------------
(Dollars in millions) 2003 2002 2001 2003 2002 2001
- -----------------------------------------------------------------------------------------
<s> <c> <c> <c> <c> <c> <c>
Service cost $ 52 $ 57 $ 49 $ 19 $ 13 $ 11
Interest cost 152 149 141 55 42 41
Expected return on assets (161) (204) (219) (35) (39) (39)
Amortization of:
Transition obligation 1 1 1 9 9 10
Prior service cost 9 7 6 (1) (1) (1)
Actuarial (gain) loss 9 (18) (39) 10 -- (3)
Special termination benefit -- -- 13 -- -- --
Curtailment cost (credit) -- -- 1 -- -- --
Settlement credit -- -- (19) -- -- --
Regulatory adjustment (14) 32 51 (4) 25 30
--------------------------------------------------
Total net periodic benefit
cost (income) $ 48 $ 24 $ (15) $ 53 $ 49 $ 49
- -----------------------------------------------------------------------------------------
</table>
85
The significant assumptions related to the company's pension and other
postretirement benefit plans are as follows:
<table>
<caption>
Other
Pension Benefits Postretirement Benefits
-------------------------------------------
2003 2002 2003 2002
- -----------------------------------------------------------------------------------------
<s> <c> <c> <c> <c>
WEIGHTED-AVERAGE ASSUMPTIONS USED
TO DETERMINE BENEFIT OBLIGATION
AS OF DECEMBER 31:
Discount rate 6.00% 6.50% 6.00% 6.50%
Rate of compensation increase 4.50% 4.50% 4.50% 4.50%
WEIGHTED-AVERAGE ASSUMPTIONS USED
TO DETERMINE NET PERIODIC BENEFIT
COSTS FOR YEARS ENDED DECEMBER 31:
Discount rate 6.50% 7.25% 6.50% 7.25%
Expected return on plan assets 7.50% 8.00% 7.30% 7.80%
Rate of compensation increase 4.50% 4.50% 4.50% 4.50%
- ----------------------------------------------------------------------------------------
</table>
The expected long-term rate of return on plan assets is derived from
historical returns for broad asset classes consistent with expectations
from a variety of sources, including pension consultants and investment
advisors.
2003 2002
- ------------------------------------------------------------------------
ASSUMED HEALTH CARE COST
TREND RATES AT DECEMBER 31:
Health-care cost trend rate 30.00%(1) 7.00%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend) 5.50% 6.50%
Year that the rate reaches the ultimate trend 2008 2004
- ------------------------------------------------------------------------
(1) This is the weighted average of the increases for all health plans.
The 2003 rate for these plans ranged from 15% to 40%.
Assumed health-care cost trend rates have a significant effect on the
amounts reported for the health-care plan costs. 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 $ 13 $ (11)
Effect on the health-care component of the
accumulated other postretirement
benefit obligation $ 152 $ (121)
- ------------------------------------------------------------------------
86
Pension Plan Investment Strategy
The asset allocation for the company's pension trust (which includes
other postretirement benefit plans, except for those described below) at
December 31, 2003 and 2002 and the target allocation for 2004 by asset
categories are as follows:
Target Percentage of Plan
Allocation Assets at December 31
-------------------------------------------
Asset Category 2004 2003 2002
- --------------------------------------------------------------------
U.S. Equity 45% 45% 44%
Foreign Equity 25% 30% 26%
Fixed Income 30% 25% 30%
-------------------------------------------
Total 100% 100% 100%
- --------------------------------------------------------------------
The company's goal is to remain within a reasonable risk tolerance shown
above. Its investment strategy is to stay fully invested at all times
and maintain its strategic asset allocation, keeping the investment
structure relatively simple. The equity portfolio is balanced to
maintain risk characteristics similar to the S&P 1500 with respect to
market capitalization, industry and sector exposures. The foreign equity
portfolios are managed to track the MSCI Europe, Pacific Rim and
Emerging Markets indexes. Bond portfolios are managed with respect to
the Lehman Aggregate Index. The plan does not invest in Sempra Energy
securities.
Investment Strategy for SoCalGas' Other Postretirement Benefit Plans
The asset allocation for SoCalGas' other postretirement benefit plans at
December 31, 2003 and 2002 and the target allocation for 2004 by asset
categories are as follows:
Target Percentage of Plan
Allocation Assets at December 31
-------------------------------------------
Asset Category 2004 2003 2002
- --------------------------------------------------------------------
U.S. Equity 70% 71% 63%
Fixed Income 30% 27% 34%
Cash -- 2% 3%
-------------------------------------------
Total 100% 100% 100%
- --------------------------------------------------------------------
SoCalGas' other postretirement benefit plans, which are distinct from
other postretirement benefit plans included in the company's pension
trust (see above), are funded by cash contributions from SoCalGas and
the retirees. The asset allocation is designed to match the long-term
growth of the plan's liability. This plan is managed using 100% index
funds.
87
Investment Strategy for SDG&E's Postretirement Health Plans
The asset allocation for SDG&E's postretirement health plans at December
31, 2003 and 2002 and the target allocation for 2004 by asset categories
are as follows:
Target Percentage of Plan
Allocation Assets at December 31
-------------------------------------------
Asset Category 2004 2003 2002
- --------------------------------------------------------------------
U.S. Equity 25% 26% 23%
Foreign Equity 5% 5% 4%
Fixed Income 70% 69% 73%
-------------------------------------------
Total 100% 100% 100%
- --------------------------------------------------------------------
SDG&E's postretirement health plans, which also are distinct from other
postretirement benefit plans included in the company's pension trust
(see above), pay premiums to the health maintenance organization and
point-of-service plans from company and participant contributions. The
company's investment strategy is to match the long-term growth rate of
the liability primarily through the use of tax-exempt California
municipal bonds.
Future Payments
The company expects to contribute $32 million to the pension plans and
$62 million to its other postretirement benefit plans in 2004.
The following table reflects the total benefits expected to be paid to
current employees and retirees from the plans or from the company's
assets, including both the company's share of the benefit cost and,
where applicable, the participants' share of the costs, which is funded
by participant contributions to the plans.
Other
(Dollars in millions) Pension Benefits Postretirement Benefits
- -----------------------------------------------------------------------
2004 $ 164 $ 35
2005 $ 167 $ 41
2006 $ 200 $ 44
2007 $ 184 $ 47
2008 $ 192 $ 49
Thereafter $ 1,078 $ 270
Savings Plans
The company offers trusteed savings plans to all eligible employees.
Eligibility to participate in the plans is immediate for salary
deferrals. Employees may contribute, subject to plan provisions, from
one percent to 25 percent of their regular earnings. After one year of
completed service, the company begins to make matching contributions.
Employer contribution amounts and methodology vary by plan, but
generally the contributions are equal to 50 percent of the first 6
percent of eligible base salary contributed by employees and, if certain
company goals are met, an additional amount related to incentive
compensation payments.
88
Employer contributions are invested in company stock and must remain so
invested until termination of employment or until the employee's
attainment of age 55, when they may be transitioned into other
investments. At the direction of the employees, the employees'
contributions are invested in company stock, mutual funds, institutional
trusts or guaranteed investment contracts. The plans of certain non-
wholly owned subsidiaries prohibit investments in Sempra Energy stock.
In this case, the employer matching contributions are invested to mirror
the employee-directed contributions. 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 $22 million in 2003, $20 million in 2002 and $17
million in 2001. The market value of company stock held by the savings
plan was $675 million and $533 million at December 31, 2003 and 2002,
respectively.
Employee Stock Ownership Plan
All contributions to the ESOP Trust (See Note 5) are made by the
company; there are no contributions made by the participants. As the
company makes contributions, 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. Dividends on unallocated shares are used
to pay debt service and are applied against the liability. The Trust
held 2.4 million shares and 2.6 million shares, respectively, of Sempra
Energy common stock, with fair values of $71.6 million and $61.0
million, at December 31, 2003 and 2002, respectively.
NOTE 9. STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans intended to align
employee and shareholder objectives related to the long-term growth of
the company. The plans permit a wide variety of stock-based awards,
including nonqualified stock options, incentive stock options,
restricted stock, stock appreciation rights, performance awards, stock
payments and dividend equivalents.
In 2003, 2002 and 2001, 1,359,500, 544,100, and 777,500 shares of
restricted company stock, respectively, were awarded to key employees.
The corresponding weighted average market values of the shares at the
time of grant were $24.42, $24.77 and $23.37, respectively. Subject to
earlier forfeitures upon termination of employment, the 2003 award is
scheduled to vest at the end of four years if performance-based goals
are satisfied. The 2002 and 2001 awards are scheduled to vest at the end
of seven years, but are also subject to earlier vesting over a four-year
period upon satisfaction of objective performance-based goals. Holders
of restricted stock have full voting and dividend rights except for
senior officers, whose dividends are conditional. Compensation expense
for the issuance of restricted stock was $16 million in 2003, $7 million
in 2002 and $5 million in 2001.
In 2003, 2002 and 2001, Sempra Energy granted to officers and key
employees 1,848,000, 3,444,300 and 2,934,800 stock options,
respectively. The option prices were equal to the market price of common
stock at the dates of grant. The options vest over four-year periods and
expire 10 years from the dates of grant, subject to earlier expiration
89
upon termination of employment. Compensation expense (or reduction
thereof) for stock option grants (all associated with outstanding
options with dividend equivalents that were issued before 2000 - see
below) and similar awards was $6 million, ($2 million) and $7 million in
2003, 2002 and 2001, respectively.
As of December 31, 2003, 13,410,138 shares were authorized and available
for future grants of restricted stock and/or stock options. In addition,
on January 1 of each year, additional shares amounting to 1.5 percent of
the outstanding shares of Sempra Energy common stock become available
for grant.
The plans permit the granting of dividend equivalents with the stock
option grants. This provides grantees the opportunity to receive some or
all of the cash dividends that would have been paid on the shares since
the grant date. All grants that have included dividend equivalents have
made the dividend equivalents dependent on the attainment of certain
performance goals. For grants prior to July 1, 1998, payment of the
dividend equivalents is also contingent upon an in-the-money exercise of
the related options.
In 1995, SFAS 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 123, the company adopted only
its disclosure requirements and continues to account for stock-based
compensation in accordance with the provisions of APB Opinion 25. See
additional discussion of SFAS 148, the amendment to SFAS 123, in Note 1.
STOCK OPTION ACTIVITY
<table>
<caption>
- --------------------------------------------------------------------------------
Weighted
Shares Average Options
Under Exercise Exercisable
Option Price at December 31
- --------------------------------------------------------------------------------
<s> <c> <c> <c>
OPTIONS WITH DIVIDEND EQUIVALENTS
December 31, 2000 4,028,573 $ 22.17 2,462,574
Exercised (588,315) $ 20.92
Cancelled (119,911) $ 22.46
----------
December 31, 2001 3,320,347 $ 22.38 2,508,328
Exercised (172,358) $ 19.87
Cancelled (68,124) $ 24.03
----------
December 31, 2002 3,079,865 $ 22.48 2,777,590
Exercised (876,391) $ 20.81
Cancelled (17,649) $ 24.72
Transfer (see table below) (1,536,775) $ 23.24
----------
December 31, 2003 649,050 $ 22.89 649,050
- --------------------------------------------------------------------------------
90
Weighted
Shares Average Options
Under Exercise Exercisable
Option Price at December 31
- ----- --------------------------------------------------------------------------
OPTIONS WITHOUT DIVIDEND EQUIVALENTS
December 31, 2000 7,565,421 $ 20.61 1,659,244
Granted 2,934,800 $ 22.50
Exercised (421,633) $ 18.79
Cancelled (204,134) $ 23.59
----------
December 31, 2001 9,874,454 $ 21.19 3,143,319
Granted 3,444,300 $ 24.71
Exercised (223,430) $ 17.70
Cancelled (84,137) $ 21.70
----------
December 31, 2002 13,011,187 $ 22.18 5,287,437
Granted 1,848,000 $ 24.44
Exercised (1,050,199) $ 20.16
Cancelled (111,906) $ 23.83
Transfer (see table above) 1,536,775 $ 23.24
----------
December 31, 2003 15,233,857 $ 22.69 8,610,732
- --------------------------------------------------------------------------------
Additional information on options outstanding at December 31, 2003, is
as follows:
- --------------------------------------------------------------------------------
Weighted Weighted
Number Average Average
Range of of Remaining Exercise
Exercise Prices Shares Life Price
- --------------------------------------------------------------------------------
Outstanding Options
$ 16.12 - $ 19.06 3,348,195 6.04 $ 18.79
$ 20.36 - $ 22.65 5,082,028 6.14 $ 21.76
$ 23.45 - $ 27.64 7,452,684 5.12 $ 25.05
----------
15,882,907 5.64 $ 22.68
- --------------------------------------------------------------------------------
Exercisable Options
$ 16.12 - $ 19.06 2,302,520 $ 18.75
$ 20.36 - $ 22.65 3,734,303 $ 21.50
$ 23.45 - $ 27.64 3,222,959 $ 25.65
---------
9,259,782 $ 22.26
- --------------------------------------------------------------------------------
</table>
The grant-date market value of each option grant (including dividend
equivalents where applicable) was estimated using a modified Black-
Scholes option-pricing model. Weighted average grant-date market values
for options granted in 2003, 2002 and 2001 were $4.31, $4.45 and $4.29,
respectively.
91
The assumptions that were used to determine these grant-date market
values are as follows:
- -----------------------------------------------------------------
2003 2002 2001
- -----------------------------------------------------------------
Stock price volatility 25% 22% 24%
Risk-free rate of return 1.8% 4.8% 4.6%
Annual dividend yield 2.2% 4.1% 4.3%
Expected life 6 Years 6 Years 6 Years
- -----------------------------------------------------------------
NOTE 10. FINANCIAL INSTRUMENTS
Fair Value
The fair values of certain of the company's financial instruments (cash,
temporary investments, notes receivable, dividends payable, short-term
debt and customer deposits) approximate their carrying amounts. The
following table provides the carrying amounts and fair values of the
remaining financial instruments at December 31:
<table>
<caption>
(Dollars in millions) 2003 2002
- -----------------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- -----------------------------------------------------------------------------------------
<s> <c> <c> <c> <c>
Investments in limited partnerships $ 236 $ 352 $ 271 $ 346
- -----------------------------------------------------------------------------------------
First mortgage bonds $ 1,561 $ 1,578 $ 1,386 $ 1,452
Notes payable 1,700 1,842 1,300 1,424
Equity units 600 680 600 577
SDG&E rate-reduction bonds 263 284 329 357
Debt incurred to acquire limited partnerships 110 128 145 169
Mesquite Power debt 630 630 -- --
Other long-term debt 414 436 608 623
------- ------- ------- -------
Total long-term debt $ 5,278 $ 5,578 $ 4,368 $ 4,602
- ---------------------------------------------------------------------------------------
Due to unconsolidated affiliates $ 362* $ 392 $ 162 $ 185
- ---------------------------------------------------------------------------------------
Preferred stock of subsidiaries $ 203* $ 184 $ 204 $ 168
- ---------------------------------------------------------------------------------------
Mandatorily redeemable trust preferred
securities $ --* $ -- $ 200 $ 205
- ---------------------------------------------------------------------------------------
* $200 million of mandatorily redeemable trust preferred securities have been
reclassified to Due to Unconsolidated Affiliates and $24 million of mandatorily
redeemable preferred stock of subsidiaries have been reclassified to Deferred
Credits and Other Liabilities and to Other Current Liabilities on the
Consolidated Balance Sheets.
</table>
The fair values of investments in limited partnerships accounted for
under the equity and cost methods were estimated based on the present
value of remaining cash flows, discounted at rates available for similar
investments. The fair values of debt incurred to acquire limited
partnerships were estimated based on the present value of the future
cash flows, discounted at rates available for similar notes with
comparable maturities. The fair values of the other long-term debt,
preferred stock of subsidiaries and mandatorily redeemable trust
92
preferred securities were estimated based on quoted market prices for
them or for similar issues.
Accounting for Derivative Instruments and Hedging Activities
The company follows the guidance of SFAS 133 and related amendments SFAS
138 and 149 (collectively SFAS 133) to account for its derivative
instruments and hedging activities. Derivative instruments and related
hedges are recognized as either assets or liabilities on the balance
sheet, measured at fair value. Changes in the fair value of derivatives
are recognized in earnings in the period of change unless the derivative
qualifies as an effective hedge that offsets certain exposure.
SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges, the
gain or loss is recognized in earnings in the period of change together
with the offsetting gain or loss on the hedged item attributable to the
risk being hedged. For derivative instruments designated as cash flow
hedges, the effective portion of the derivative gain or loss is included
in other comprehensive income, but not reflected in the Statements of
Consolidated Income until the corresponding hedged transaction is
settled. The ineffective portion is reported in earnings immediately.
The effect on other comprehensive income for the years ended December
31, 2003 and 2002 was not material. In instances where derivatives do
not qualify for hedge accounting, gains and losses are recorded in the
Statements of Consolidated Income.
The company utilizes derivative instruments to reduce its exposure to
unfavorable changes in commodity prices, which are subject to
significant and often volatile fluctuation. Derivative instruments
include futures, forwards, swaps, options and long-term delivery
contracts. These contracts allow the company to predict with greater
certainty the effective prices to be received. The company classifies
its forward contracts as follows:
Contracts that meet the definition of normal purchase and sales
generally are long-term contracts that are settled by physical delivery
and, therefore, are eligible for the normal purchases and sales
exception of SFAS 133. The contracts are accounted for under accrual
accounting and recorded in Revenues or Cost of Sales on the Statements
of Consolidated Income when physical delivery occurs. Due to the
adoption of SFAS 149, the company has determined that its natural gas
contracts entered into after June 30, 2003 generally do not qualify for
the normal purchases and sales exception.
Electric and Natural Gas Purchases and Sales: The unrealized gains and
losses related to these forward contracts, as they relate to the
California Utilities, are reflected on the Consolidated Balance Sheets
as regulatory assets and liabilities to the extent derivative gains and
losses will be recoverable or payable in future rates. If gains and
losses at the California Utilities are not recoverable or payable
through future rates, the California Utilities will apply hedge
accounting when certain criteria are met. When a contract no longer
meets the requirements of SFAS 133, the unrealized gains and losses and
the related regulatory asset or liability will be amortized over the
remaining contract life.
93
The following were recorded on the Consolidated Balance Sheets at
December 31 related to derivatives:
(Dollars in millions) 2003 2002
- --------------------------------------------------------------------
Fixed-priced contracts and other derivatives:
Current liabilities $ 148 $ 153
Noncurrent liabilities 680 813
------ ------
Total 828 966
------ ------
Current assets 26 3
Noncurrent assets -- 42
------ ------
Total 26 45
------ ------
Net liabilities $ 802 $ 921
====== ======
Regulatory assets and liabilities related to derivatives held by the
California Utilities are as follows:
(Dollars in millions) 2003 2002
- --------------------------------------------------------------------
Regulatory assets and liabilities:
Current regulatory assets $ 144 $ 151
Noncurrent regulatory assets 650 812
------ ------
Total 794 963
------ ------
Current regulatory liabilities 1 2
------ ------
Net regulatory assets $ 793 $ 961
====== ======
As of December 31, 2003, the difference between net liabilities and net
regulatory assets was primarily due to $30 million related to a
derivative contract associated with the purchase of the Cameron LNG
facility offset by $23 million related to a fixed-to-floating interest
rate swap. At December 31, 2002, the difference was primarily due to
market value adjustment of $42 million related to two fixed-to-floating
interest rate swaps. The market value adjustment in 2002 included a
reversing effect for the cancellation of one of the swap agreements on
September 30, 2002. $2 million of losses in 2003 and $4 million of
income in 2002 were recorded in Operating Revenues and $1 million of
income in 2002 was recorded in Other Income - Net in the Statements of
Consolidated Income.
Market Risk
The company's policy is to use physical and financial derivative
instruments to reduce its exposure to fluctuations in interest rates,
foreign currency exchange rates and commodity prices. The company also
uses and trades derivative instruments in its trading and marketing of
energy and other commodities. Transactions involving these instruments
are with major exchanges and other firms believed to be creditworthy.
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The use of these instruments exposes the company to market and credit
risks, which may at times be concentrated with certain counterparties,
although counterparty nonperformance is not anticipated.
Interest-Rate Risk Management
The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall cost
of borrowing. This is described in Note 5.
Energy Derivatives
The company utilizes derivative instruments to reduce its exposure to
unfavorable changes in energy prices, which are subject to significant
and often volatile fluctuation. Derivative instruments are comprised of
futures, forwards, swaps, options and long-term delivery contracts.
These contracts allow the company to predict with greater certainty the
effective prices to be received.
Energy Contracts
The California Utilities record transactions for natural gas and
electric energy contracts in Cost of Natural Gas and Cost of Electric
Fuel and Purchased Power, respectively, in the Statements of
Consolidated Income. For open contracts not expected to result in
physical delivery, changes in market value of the contracts are recorded
in these accounts during the period the contracts are open, with an
offsetting entry to a regulatory asset or liability. The majority of the
California Utilities' contracts result in physical delivery, which is
infrequent at the trading operations.
Sempra Energy Trading and Sempra Energy Solutions
SET derives revenue from market making and trading activities, as a
principal, in natural gas, electricity, petroleum products, metals and
other commodities, for which it quotes bid and ask 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. SET utilizes derivative instruments to
reduce its exposure to unfavorable changes in market prices, which are
subject to significant and often volatile fluctuation. These instruments
include futures, forwards, swaps and options, and represent contracts
with counterparties under which 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. Sempra Energy guarantees
many of SET's transactions.
SES derives a major portion of its revenue from delivering electric and
natural gas supplies to its commercial and industrial customers. Such
contracts are hedged to preserve margin and reduce market risk. The
derivative instruments used to hedge the transactions include swaps,
forwards, futures, options or combinations thereof.
Trading instruments are recorded by both SET and SES on a trade-date
basis and the majority of such derivative instruments are adjusted daily
to current market value with gains and losses recognized in Other
Operating Revenues on the Statements of Consolidated Income. These
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instruments are included on the Consolidated Balance Sheets as Trading
Assets or Liabilities and include amounts due from commodity clearing
organizations, amounts due to or from trading counterparties, unrealized
gains and losses from exchange-traded futures and options, derivative
OTC swaps, forwards and options. Unrealized gains and losses on OTC
transactions reflect amounts that 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 an enforceable
netting arrangement. Other derivatives which qualify as hedges are
accordingly recorded under hedge accounting.
As a result of the rescission of EITF 98-10 (see Note 1), energy
commodity inventory is being recorded at the lower of cost or market;
however metals inventories continue to be recorded at fair value in
accordance with ARB No. 43. As of December 31, 2003 and 2002, trading
assets included commodity inventory of $1.4 billion and $2.0 billion,
respectively. Note 2 discusses SET acquisitions made in 2002, some of
which were affected by EITF 98-10.
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 purchased and
written are recorded on a trade-date basis. 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.
Based on quarterly measurements, the average fair values during 2003 for
trading assets and liabilities approximate $5.1 billion and $4.4
billion, respectively. For 2002, the amounts were $4.9 billion and $3.7
billion, respectively.
96
The carrying values of trading assets and trading liabilities
approximate the following:
December 31,
(Dollars in millions) 2003 2002
- -----------------------------------------------------------------------
TRADING ASSETS
SET:
Unrealized gains on swaps and forwards $ 1,043 $ 1,226
OTC commodity options purchased 459 480
Due from trading counterparties 2,184 1,279
Due from commodity clearing organizations
and clearing brokers 134 49
Commodities owned 1,420 1,968
------- -------
Total 5,240 5,002
SES:
Unrealized gains on swaps and forwards 113 96
Intercompany eliminations (103) (34)
------- -------
Total $ 5,250 $ 5,064
======= =======
- -----------------------------------------------------------------------
TRADING LIABILITIES
SET:
Unrealized losses on swaps and forwards $ 1,095 $ 816
OTC commodity options written 226 569
Due to trading counterparties 2,195 1,196
Repurchase obligations 866 1,511
Commodities not yet purchased 56 --
------- -------
Total 4,438 4,092
SES:
Unrealized losses on swaps and forwards 35 6
Intercompany eliminations (16) (4)
------- -------
Total $ 4,457 $ 4,094
======= =======
- -----------------------------------------------------------------------
At SET, market risk arises from the potential for changes in the value
of physical and financial instruments resulting from fluctuations in
prices and basis for natural gas, electricity, petroleum, petroleum
products, metals and other commodities. Market risk is also affected by
changes in volatility and liquidity in markets in which these
instruments are traded. Market risk for SES from fluctuations in natural
gas or electricity prices is reduced by SES' hedging strategy as
described above.
SET's credit risk from physical and financial instruments as of December
31, 2003 is represented by their positive fair value after consideration
of collateral. Options written do not expose SET to credit risk.
Exchange-traded futures and options are not deemed to have significant
97
credit exposure since the exchanges guarantee that every contract will
be properly settled on a daily basis. For SES, credit risk is associated
with its retail customers.
The following table summarizes the counterparty credit quality and
exposure for SET and SES at December 31, 2003 and 2002, expressed in
terms of net replacement value. These exposures are net of collateral in
the form of customer margin and/or letters of credit of $569 million and
$240 million at December 31, 2003 and 2002, respectively.
December 31,
(Dollars in millions) 2003 2002
- -----------------------------------------------------------------------
Counterparty credit quality*
SET:
Commodity exchanges $ 134 $ 49
AAA 5 69
AA 310 194
A 463 316
BBB 345 559
Below investment grade 357 504
------- -------
Total $ 1,614 $ 1,691
------- -------
SES:
AA $ 6 $ 8
A 21 11
BBB 26 24
Below investment grade and not rated 68 86
------- -------
Total $ 121 $ 129
------- -------
* As determined by rating agencies or internal models intended to
approximate rating-agency determinations.
- -----------------------------------------------------------------------
98
NOTE 11. PREFERRED STOCK OF SUBSIDIARIES
<table>
<caption>
- -----------------------------------------------------------------------------
(Dollars in millions, except call/ Call/Redemption December 31,
redemption price) Price 2003 2002
- -----------------------------------------------------------------------------
<s> <c> <c> <c>
Not subject to mandatory redemption:
Pacific Enterprises:
Without par value,
authorized 15,000,000 shares:
$4.75 Dividend, 200,000 shares outstanding $ 100.00 $ 20 $ 20
$4.50 Dividend, 300,000 shares outstanding $ 100.00 30 30
$4.40 Dividend, 100,000 shares outstanding $ 101.50 10 10
$4.36 Dividend, 200,000 shares outstanding $ 101.00 20 20
$4.75 Dividend, 253 shares outstanding $ 101.00 -- --
----------------
Total 80 80
----------------
SoCalGas:
$25 par value, authorized 1,000,000 shares:
6% Series, 28,041 shares outstanding 1 1
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized 10,000,000 shares -- --
----------------
Total 20 20
----------------
SDG&E:
$20 par value, authorized 1,375,000 shares:
5% Series, 375,000 shares outstanding $ 24.00 8 8
4.5% Series, 300,000 shares outstanding $ 21.20 6 6
4.4% Series, 325,000 shares outstanding $ 21.00 7 7
4.6% 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 79 79
----------------
Total not subject to mandatory redemption 179 179
Subject to mandatory redemption:
SDG&E:
Without par value: $1.7625 Series, 950,000
and 1,000,000 shares outstanding at December
31, 2003 and December 31, 2002, respectively $ 25.00 24* 25
---------------
Total preferred stock $ 203 $ 204
- -----------------------------------------------------------------------------
*Reclassified to Deferred Credits and Other Liabilities and to Other Current
Liabilities.
</table>
PE preferred stock is callable at the applicable redemption price for
each series, plus any unpaid dividends. The preferred stock is subject
99
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 unpaid dividends. All series have one vote per share and
cumulative preferences as to dividends, and have a liquidation value of
$100 per share plus any unpaid dividends.
None of SoCalGas' preferred stock is callable. All series have one vote
per share and cumulative preferences as to dividends, and have a
liquidation value of $25 per share, plus any unpaid dividends.
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, plus any unpaid dividends.
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 callable at December 31, 2003. The $1.7625 Series has a
sinking fund requirement to redeem 50,000 shares at $25 per share per
year from 2004 to 2007; the remaining 750,000 shares must be redeemed in
2008. On January 15, 2004, SDG&E redeemed 50,000 shares at $25 per
share.
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 2003, 2002 and 2001, the effect of
dilutive options was equivalent to an additional 2,742,000, 1,059,000
and 1,745,000 shares, respectively. This is based on using the treasury
stock method, whereby the proceeds from the exercise price are assumed
to be used to repurchase shares on the open market at the average market
price for the year. The calculation excludes options covering 0.1
million, 6.0 million and 2.1 million shares for 2003, 2002 and 2001,
respectively, for which the exercise price was greater than the average
market price for common stock during the respective year.
Additional dilution could arise from the Equity Units described below.
Through December 31, 2003, the price of the company's common stock was
high enough to cause such dilution on only two days and, therefore, the
Equity Units had no dilutive effect. On January 31, 2004, the common
stock price was $31.14. If the price had averaged that for the full year
of 2003, the Equity Units would have reduced the company's earnings per
share in 2003 by $0.01.
100
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, common stock activity consisted of
the following:
<table>
<caption>
2003 2002 2001
----------- ----------- -----------
<s> <c> <c> <c>
Common shares outstanding, January 1 204,911,572 204,475,362 201,927,524
Common stock issuance 16,500,000 -- --
Savings plan issuance* 1,436,526 -- --
Shares released from ESOP 170,613 130,486 134,645
Stock options exercised 1,926,590 395,788 1,009,948
Long-term incentive plan 1,359,500 544,100 777,500
Common stock investment plan** 728,241 212,411 762,439
Shares repurchased (262,286) (818,639) (76,264)
Shares forfeited and other (172,137) (27,936) (60,430)
----------- ----------- -----------
Common shares outstanding, December 31 226,598,619 204,911,572 204,475,362
=========== =========== ===========
* In prior years, the plan purchased shares in the open market to cover
these contributions.
** Participants in the Direct Stock Purchase Plan may reinvest dividends
to purchase newly issued shares.
</table>
The payment of future dividends and the amount thereof are within the
discretion of the company's board of directors. The CPUC's regulation of
the California Utilities' capital structure limits the amounts that are
available for dividends and loans to the company from the California
Utilities. At December 31, 2003, SDG&E and SoCalGas could have provided
a total of $290 million and $175 million, respectively, to Sempra
Energy, through dividends and loans. At December 31, 2003, SDG&E and
SoCalGas had loans to Sempra Energy net of intercompany payables, of $75
million and $21 million, respectively.
Equity Units
During the second quarter of 2002, the company issued $600 million of
Equity Units. Each unit consists of $25 principal amount of the
company's 5.60% senior notes due May 17, 2007 and a contract to purchase
for $25 on May 17, 2005, between .8190 and .9992 of a share of the
company's common stock (with the precise number to be determined by the
then-prevailing market price). The number of shares to be issued ranges
from 20 million to 24 million. The Equity Units are recorded as Long-
Term Debt on the Consolidated Balance Sheets. Through December 31, 2003,
$55 million had been charged to the common stock account in connection
with the transaction.
Common Stock Offering
On October 14, 2003, Sempra Energy completed a common stock offering of
16.5 million shares priced at $28 per common share, resulting in net
101
proceeds of $448 million. The proceeds were used primarily to pay off
short-term debt.
NOTE 13. ELECTRIC INDUSTRY REGULATION
Background
The restructuring of California's electric utility industry has
significantly affected the company's electric utility operations, and
the power crisis of 2000-2001 caused the CPUC to significantly modify
its plan for restructuring the electricity industry. Supply/demand
imbalances and a number of other factors resulted in abnormally high
electric-commodity prices beginning in mid-2000 and continuing into
2001. This caused SDG&E's customer bills to be substantially higher than
normal. These higher prices were initially passed through to customers
and resulted in bills that in most cases were double or triple those
from 1999 and early 2000. This resulted in several legislative and
regulatory responses, including California Assembly Bill (AB) 265. AB
265 imposed a ceiling on the cost of the electric commodity that SDG&E
could pass on to its small-usage customers from June 1, 2000 to December
31, 2002.
SDG&E accumulated the amount that it paid for electricity in excess of
the ceiling rate in an interest-bearing balancing account (the AB 265
undercollection) and began recovering these amounts in rates charged to
customers following the end of the rate-ceiling period. At December 31,
2003, the AB 265 undercollection was $63 million (included in Regulatory
Balancing Accounts - Net on the Consolidated Balance Sheets) and is
being recovered in current rates.
Another legislative response to the power crisis resulted in the
purchase by the DWR of a substantial portion of the power requirements
of California's electricity users. Since early 2001, the DWR has
procured power for the utility procurement customers of each of the
California investor-owned utilities (IOUs) and the CPUC has established
the allocation of the power and its related cost responsibility among
the IOUs. Beginning on January 1, 2003, the IOUs resumed some of its
electric commodity procurement, whereas previously the DWR had been
purchasing the IOUs' entire net short position.
Department of Water Resources
The DWR's operating agreement with SDG&E, approved by the CPUC, governs
SDG&E's administration of the allocated DWR contracts. The agreement
provides that SDG&E is acting as a limited agent on behalf of the DWR in
undertaking energy sales and natural gas procurement functions under the
DWR contracts allocated to SDG&E's customers. Legal and financial
responsibility and risks associated with these activities will continue
to reside with the DWR. Therefore, revenues and costs associated with
the contracts were not included in the Statements of Consolidated Income
during 2003. From February 2001 until December 2002, the DWR was
purchasing similar amounts of power for SDG&E; the cost of that power
was not included in the Statements of Consolidated Income in 2001 or
2002. The reasonableness of the IOU's administration and dispatch of the
allocated contracts will be reviewed by the CPUC in an annual
proceeding.
102
In September 2003, the CPUC approved a $1 billion refund to consumers of
the three major California IOUs as a result of the DWR's lowering its
revenue requirement for 2003. The refund was returned to customers in
the form of a one-time bill credit. SDG&E's portion was 13.51 percent or
about $135 million. The bill credit had no effect on SDG&E's net income
and net cash flows because customer savings are coming from lower
charges by the DWR, and SDG&E is merely transmitting the electricity
from the DWR to the customers, without taking title to the electricity.
On January 8, 2004, the CPUC issued a decision on the final true-up of
DWR's 2001/2002 energy costs among California's three major investor-
owned electric utilities, resulting in SDG&E's customers being allocated
$59 million of additional costs. The amount from this true-up is
recoverable from ratepayers and will be included with SDG&E's allocated
share of DWR's 2004 revenue requirement and incorporated into electric
charges for 2004, which are expected to be decided in the first half of
2004. This true-up will have a short-term effect on SDG&E's cash flow
but will not otherwise affect its results of operations, since SDG&E
merely passes through the costs to its customers.
In October 2003, the CPUC initiated a proceeding to consider a permanent
methodology for allocating DWR's Revenue Requirement beginning in 2004
through the remaining life of the DWR contracts. An interim allocation
based on the current 2003 methodology was utilized beginning January 1,
2004, and is in effect until a decision is reached on a permanent
methodology (expected in the second quarter of 2004). Once a permanent
methodology is established, the impacts of the decision will be applied
retroactively back to January 1, 2004. This delay could have an effect
on SDG&E's rates and cash flows, but not on its net income.
Power Procurement
In October 2001, the CPUC initiated an Order Instituting Ratemaking
(OIR) to establish ratemaking mechanisms that would enable California
investor-owned electric utilities to resume purchasing electric energy
and related services and hedging instruments to fulfill their obligation
to serve and meet the needs of their customers. In so doing, the CPUC
acknowledged that the utilities desired assurance of more timely
regulatory review and cost recovery for their procurement activities and
costs. In connection therewith, the OIR directed the IOUs to resume
electric commodity procurement to cover their net short energy
requirements by January 1, 2003. The net short position is the
difference between the amount of electricity needed to cover a utility's
customer demand and the power provided by owned generation and existing
contracts, including the long-term DWR power contracts allocated to the
customers of each IOU by the CPUC (see above).
The OIR also implemented recent legislation regarding procurement and
renewables portfolio standards and establishes a process for review and
approval of the utilities' long-term (20-year) procurement plans. In
December 2002, the CPUC adopted SDG&E's 2003 short-term procurement
plan. That plan addressed SDG&E's procurement activities in calendar
year 2003, authorized contract terms for up to five years for
transactions entered into under the plans, and allowed for the hedging
of first quarter 2004 residual net short positions with transactions
entered into in 2003. SDG&E was required to purchase approximately 10
percent of its customer requirements in 2003, based on the allocation of
103
the DWR power approved by the CPUC in December 2002. The CPUC authorized
SDG&E to acquire a variety of resource types and demand side resources.
A semiannual cost review and rate revision mechanism is established, and
a trigger is established for more frequent changes if undercollected
commodity costs exceed five percent of annual, non-DWR generation
revenues, to provide for timely recovery of any undercollections.
Approval of SDG&E's 2003 short-term procurement plan provided for
SDG&E's return to procurement of its customers' needs on January 1,
2003, consistent with the intent of the legislature and the CPUC.
SDG&E filed its 20-year long-term resource plan covering its anticipated
procurement needs between 2004 and 2023 and its short-term procurement
plans for its anticipated procurement activities in 2004. In decisions
issued in December 2003 and January 2004, the CPUC approved the 2004
procurement plan and provided policy guidance for the filing of an
updated 20-year resource plan in the spring of 2004.
On December 18, 2003, the CPUC issued a decision adopting SDG&E's
procurement plan for 2004. The decision delayed until 2004 further CPUC
direction on comprehensive policy guidance for the IOUs' long-term
resource plans. In the decision, the CPUC continued its moratorium
(subject to certain exceptions) on the IOUs' ability to deal with their
own affiliates in procurement transactions.
SDG&E's 20-year resource plan identified the near-term need for firm
capacity resources within its service territory to support transmission
grid reliability. As a result, SDG&E issued a Request for Proposals
(RFP) for the years 2005-2007 of 69 MW in 2005 increasing to 291 MWs in
2007.
In October 2003, SDG&E filed a motion in the Procurement OIR that now
requests the CPUC to authorize SDG&E to enter into five new electric
resource contracts. They include:
The 550-megawatt combined-cycle Palomar power plant in Escondido,
California to be constructed by SER for completion in 2006.
The 45-MW Ramco combustion turbine which SDG&E is proposing to
acquire as a turnkey project and intends to use for intermediate
load requirements beginning June 2005.
(SDG&E will not take ownership of these two facilities unless
appropriate cost recovery and ratemaking mechanisms are instituted
by the CPUC to ensure that SDG&E recovers all reasonable costs of,
and a reasonable return on, the investments.)
A power purchase agreement (PPA) to buy up to 570 MW over ten
years starting in 2008 from a power plant that Calpine Corporation
(Calpine) would complete on its site within SDG&E's service
territory. (SDG&E would recommend the Calpine PPA only if the CPUC
orders the implementation of certain critical conditions intended
to make the Calpine PPA a positive economic benefit to SDG&E's
customers.)
One contract each for a demand-response resource and a renewable
resource.
104
The capital cost related to the five contracts proposed by SDG&E is $640
million. Hearings concluded on February 20, 2004, and a decision is
expected in May 2004. Given the CPUC's prior denial of the company's
request for approval of additional transmissions facilities, the company
believes that customer requirements for electricity could not be met
without the requested resources or similar additions.
A June 2003 CPUC decision in the Procurement OIR directed each IOU to
procure from renewable sources at least one percent of its 2003 total
energy sales, increasing to 20 percent by 2017. SDG&E procured four
percent of its 2003 total energy sales from renewable sources and
existing contracts will increase this to five percent in 2004 and nine
percent in 2007. A 2002 CPUC resolution permits the company to credit
toward future years' compliance any excess over its one-percent annual
requirement.
On July 11, 2003, the CPUC adopted a proposed decision continuing the
level of the Direct Access (DA) cost responsibility surcharge (CRS) cap
effective July 1, 2003 at 2.7 cents per kilowatt hour (kWh), subject to
possible revision in the next DA CRS cap review proceeding. In each
periodic DA CRS cap review proceeding, the cap is subject to adjustment
to the extent necessary to maintain the goal of refunding to utility
customers the full amounts to which they are entitled by the end of the
DWR contract term in 2011. The DA CRS has no impact on SDG&E; however,
the surcharge may affect SES' ability to attract and maintain customers
in California.
SONGS
Through December 31, 2003, the operating and capital costs of SONGS
Units 2 and 3 were recovered through the ICIP mechanism which allowed
SDG&E to receive 4.4 cents per kilowatt-hour for SONGS generation. Any
differences between these costs and the incentive price affected net
income. For the year ended December 31, 2003, ICIP contributed $53
million to SDG&E's net income. Beginning in 2004, the CPUC has provided
for traditional rate-making treatment, under which the SONGS ratebase
would start over at January 1, 2004, essentially eliminating earnings
from SONGS except from future increases in ratebase.
FERC Actions
DWR Contract
On June 25, 2003, the FERC issued orders upholding the company's long-
term energy supply contract with the DWR, as well as contracts between
the DWR and other power suppliers. The order affirmed a previous FERC
conclusion that those advocating termination or alteration of the
contract would have to satisfy a "heavy" burden of proof, and cited its
long-standing policy to recognize the sanctity of contracts. In the
order, the CPUC noted that CPUC and court precedent clearly establish
that allegations that contracts have become uneconomic by the passage of
time do not render them contrary to the public interest under the
Federal Power Act. The CPUC pointed out that the contracts were entered
into voluntarily in a market-based environment. The CPUC found no
evidence of unfairness, bad faith or duress in the original contract
negotiations. It said there was no credible evidence that the contracts
placed the complainants in financial distress or that ratepayers will
105
bear an excessive burden. In December 2003, appeals of this matter filed
by a number of parties, including the California Energy Oversight Board
and the CPUC, were consolidated and assigned to the Ninth Circuit Court
of Appeals (the Court). The company expects that the Court will affirm
the FERC decision.
Refund Proceedings
The FERC is investigating prices charged to buyers in the PX and ISO
markets by various electric suppliers. The FERC is seeking to determine
the extent to which individual sellers have yet to be paid for power
supplied during the period of October 2, 2000 through June 20, 2001 and
to estimate the amounts by which individual buyers and sellers paid and
were paid in excess of competitive market prices. Based on these
estimates, the FERC could find that individual net buyers, such as
SDG&E, are entitled to refunds and individual net sellers, such as SET,
are required to provide refunds. To the extent any such refunds are
actually realized by SDG&E, they would reduce SDG&E's rate-ceiling
balancing account. To the extent that SET is required to provide
refunds, they could result in payments by SET after adjusting for any
amounts still owed to SET for power supplied during the relevant period
(or receipts if refunds are less than amounts owed to SET).
In December 2002, a FERC Administrative Law Judge (ALJ) issued
preliminary findings indicating that the California PX and ISO owe power
suppliers $1.2 billion (the $3.0 billion that the California PX and ISO
still owe energy companies less $1.8 billion that the energy companies
charged California customers in excess of the preliminarily determined
competitive market clearing prices). On March 26, 2003, the FERC largely
adopted the ALJ's findings, but expanded the basis for refunds by
adopting a staff recommendation from a separate investigation to change
the natural gas proxy component of the mitigated market clearing price
that is used to calculate refunds. The March 26 order estimates that the
replacement formula for estimating natural gas prices will increase the
refund obligations from $1.8 billion to more than $3 billion. The FERC
recently released its final instructions, and ordered the ISO and PX to
recalculate the precise number through their settlement models.
California is seeking $8.9 billion in refunds from its electricity
suppliers and has appealed the FERC's preliminary findings and requested
rehearing of the March 26 order. SET and other power suppliers have
joined in appeal of the FERC's preliminary findings and requested
rehearing.
SET had established reserves of $29 million for its likely share of the
original $1.8 billion. SET is unable to determine its possible share of
the additional refund amount. Accordingly, it has not recorded any
additional reserves but the company does not believe that any additional
amounts that SET may be required to pay would be material to the
company's financial position or liquidity.
Manipulation Investigation
The FERC is also investigating whether there was manipulation of short-
term energy markets in the West that would constitute violations of
applicable tariffs and warrant disgorgement of associated profits. In
this proceeding, the FERC's authority is not confined to the October 2,
2000 through June 20, 2001 period relevant to the refund proceeding. In
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May 2002, the FERC ordered all energy companies engaged in electric
energy trading activities to state whether they had engaged in various
specific trading activities in violation of the PX and ISO tariffs
(generally described as manipulating or "gaming" the California energy
markets).
On June 25, 2003, the FERC issued several orders requiring various
entities to show cause why they should not be found to have violated
California ISO and PX tariffs. First, FERC directed 43 entities,
including SET and SDG&E, to show cause why they should not disgorge
profits from certain transactions between January 1, 2000 and June 20,
2001 that are asserted to have constituted gaming and/or anomalous
market behavior under the California ISO and/or PX tariffs. Second, the
FERC directed more than 20 entities, including SET, to show cause why
their activities during the period January 1, 2000 to June 20, 2001 did
not constitute gaming and/or anomalous market behavior in violation of
the tariffs. Remedies for confirmed violations could include
disgorgement of profits and revocation of market-based rate authority.
The FERC has encouraged the entities to settle the issues and on October
31, 2003, SET agreed to pay $7.2 million in full resolution of these
investigations. The entire amount has been recorded as of December 31,
2003. The entire proceeding, including the settlement, is subject to
final approval by the FERC, which is expected during 2004. SDG&E and the
FERC resolved the matter by SDG&E's paying $28 thousand into a FERC-
established fund.
On June 25, 2003, the FERC also determined that it was appropriate to
initiate an investigation into possible physical and economic
withholding in the California ISO and PX markets. For the purpose of
investigating economic withholding, the FERC used an initial screen of
all bids exceeding $250 per MW between May 1, 2000 and October 2, 2001.
Both SDG&E and SET have received data requests from the FERC staff and
have provided responses. The FERC staff will prepare a report to the
FERC, which will be the basis to decide whether additional proceedings
are warranted. SET and SDG&E believe that their bids and bidding
procedures were consistent with ISO and PX tariffs and protocols and
applicable FERC price caps. On August 1, 2003, the FERC staff issued an
initial report that determined there was no need to further investigate
particular entities, including SET, for physical withholding of
generation.
NOTE 14. OTHER REGULATORY MATTERS
Natural Gas Industry Restructuring
In December 2001 the CPUC issued a decision related to natural gas
industry restructuring (GIR), with implementation anticipated during
2002. On January 12, 2004, after many delays and changes, an ALJ issued
a proposed decision that would implement the 2001 decision. The proposed
decision would result in revising noncore balancing account treatment to
exclude the balancing of SoCalGas' transmission costs; other noncore
costs/revenues would continue to be fully balanced until the decision in
the next Biennial Cost Allocation Proceeding (BCAP) (see below). On
February 11, 2004, a member of the CPUC issued an alternative decision
that would vacate the December 2001 decision and defer GIR matters to
the Natural Gas Market OIR (see below). A CPUC decision could be issued
in March 2004.
107
Natural Gas Market OIR
The Natural Gas Market OIR was approved on January 22, 2004, and will be
addressed in two concurrent phases. The schedule calls for a Phase I
decision by summer 2004 and a Phase II decision by the end of 2004. In
Phase I the CPUC's objective is to develop a process enabling the CPUC
to review and pre-approve new interstate capacity contracts before they
are executed. In addition, the California Utilities must submit
proposals on any LNG project to which interconnection is planned,
providing costs and terms, including access to the pipelines in Mexico.
Phase II will primarily address emergency reserves and ratemaking
policies. The OIR invites proposals on how utilities should provide
emergency reserves consisting of slack intrastate pipeline capacity,
contracts for additional capacity on the interstate pipelines and an
emergency supply of natural gas storage. The CPUC's objective in the
ratemaking policy component of Phase II is to identify and propose
changes to policies that create incentives that are consistent with the
goal of providing adequate and reliable long-term supplies and that do
not conflict with energy efficiency programs. The focus of the Gas OIR
is 2006 to 2016. Since GIR (see above) would end in August 2006 and
there is overlap between GIR and the Gas OIR issues, a number of parties
(including SoCalGas) are advising the CPUC not to implement GIR.
The company believes that regulation needs to consider sufficiently the
adequacy and diversity of supplies to California, transportation
infrastructure and cost recovery thereof, hedging opportunities to
reduce cost volatility, and programs to encourage and reward
conservation.
Cost of Service
The California Utilities have filed cost of service applications with
the CPUC, seeking rate increases reflecting forecasts of 2004 capital
and operating costs. The California Utilities are requesting revenue
increases of $121 million. The CPUC's Office of Ratepayer Advocates
(ORA) filed its prepared testimony on the applications in August 2003,
recommending numerous rate decreases that would reduce annual revenues
by $162 million from their current level. The Utility Consumers' Action
Network (UCAN), a consumer-advocacy group, has proposed rates for SDG&E
and The Utility Reform Network has proposed rates for SoCalGas that
would reduce annual revenues by $88 million and $178 million,
respectively, from their current level. Hearings concluded in November
2003. On December 19, 2003, settlements were filed with the CPUC that,
if approved, would resolve most of the cost of service issues. The
SoCalGas settlement was signed by SoCalGas and all parties active in its
application. The SDG&E settlement was signed by SDG&E, ORA and other
parties, but not by UCAN, the City of Chula Vista and other parties. The
CPUC adopted a schedule for briefing and commenting on the proposed
settlements that concluded on February 19, 2004. The SoCalGas settlement
would reduce rates by $33 million from 2003 rates. The SDG&E settlement
would reduce its electric rates by $19.6 million from 2003 rates and
increase its natural gas rates by $1.8 million from 2003 rates. As part
of the proposed settlement, SDG&E and the ORA would resolve their
dispute concerning the allocation of the gain on sale of SDG&E's surplus
property in Blythe, California, by increasing SDG&E's forecast of
miscellaneous revenues by $1.3 million annually, thereby lowering its
retail revenue requirement by that amount. The CPUC may accept one or
108
both of the settlements or may adopt an outcome differing from both of
the settlements. Resolution is likely in the second quarter of 2004.
On December 18, 2003, the CPUC issued a decision that creates memorandum
accounts as of January 1, 2004, to record the difference between actual
revenues and those that are later authorized in the CPUC's final
decision in this case. The difference would then be amortized in rates.
The California Utilities have also filed for continuation through 2004
of existing performance-based regulation (PBR) mechanisms for service
quality and safety that would otherwise expire at the end of 2003. In
January 2004, the CPUC issued a decision that extended 2003 service and
safety targets through 2004, but deferred action on applying any rewards
or penalties for performance relative to these targets to a decision to
be issued later in 2004 in a second phase of these applications
discussed below.
The CPUC has established a procedural schedule for the second phase of
these applications, addressing issues related to PBR (see below). The
procedural schedule calls for hearings to be held in June 2004, with a
decision during 2004. The scope of the second phase includes: (a) a
formula for setting authorized cost of service for 2005 and succeeding
years until the next full Cost of Service proceeding is scheduled; (b)
whether and how rates should be adjusted if earned returns vary from
authorized returns; and (c) prospective targets and rewards/penalties
for service quality and safety.
An October 2001 decision denied the California Utilities' request to
continue equal sharing between ratepayers and shareholders of the
estimated savings for the 1998 business combination that created Sempra
Energy and, instead, ordered that all of the estimated 2003 merger
savings go to ratepayers. In 2002, merger savings to shareholders for
the fourth quarter and for the year were $4 million and $17 million,
respectively, at SoCalGas and $2 million and $8 million, respectively,
at SDG&E. Pursuant to the decision, SoCalGas and SDG&E will return the
2003 merger savings related to natural gas operations of $83 million and
$15 million, respectively, to ratepayers over a twelve-month period
beginning January 1, 2004. The merger savings related to electric
operations were previously returned to ratepayers.
Performance-Based Regulation
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted PBR
for SDG&E effective in 1994 and for SoCalGas effective in 1997. PBR has
resulted in modification to the general rate case and certain other
regulatory proceedings for the California Utilities. Under PBR,
regulators require future income potential to be tied to achieving or
exceeding specific performance and productivity goals, rather than
relying solely on expanding utility plant to increase earnings.
PBR consists of three primary components. The first is a mechanism to
adjust rates in years between general rate cases or cost of service
cases. Similar to the pre-PBR Attrition Proceeding, it annually adjusts
general rates from those of the prior year to provide for inflation,
changes in the number of customers and efficiencies.
109
The second component is a mechanism whereby any earnings in excess of
those authorized plus a narrow band above that are shared with customers
in varying degrees depending upon the amount of the additional earnings.
The third component consists of a series of measures of utility
performance. Generally, if performance is outside of a band around the
specified benchmark, the utility is rewarded or penalized certain dollar
amounts.
The three areas that are eligible for PBR rewards or penalties are
operational incentives based on measurements of safety, reliability and
customer satisfaction; demand-side management (DSM) rewards based on the
effectiveness of the programs; and natural gas procurement rewards or
penalties. The CPUC is also considering a new reward/penalty related to
electricity procurement, now that the utilities are resuming this
activity. However, as noted under Cost of Service, Phase II of the
California Utilities' current cost of service proceeding is not
scheduled for completion until late 2004. As a result, it is possible
that some or all of the safety, reliability and customer satisfaction
incentive mechanisms (i.e., those that are reviewed in the Cost of
Service proceeding) would not be in effect for 2004. Even if that were
to occur, it is not expected that the effect would be other than a one-
year moratorium on the mechanisms.
In July 2003, the CPUC issued a decision relative to SDG&E's Year 11
natural gas PBR application, which will permanently extend the PBR
mechanism with some modification. The decision approved the Joint
Parties' Motion for an Order Adopting Settlement Agreement filed by
SDG&E and the ORA, which will apply to Year 10 and beyond. The effect of
the modifications is to reduce slightly the potential size of future PBR
rewards or penalties.
The Gas Cost Incentive Mechanism (GCIM) allows SoCalGas to receive a
share of the savings it achieves by buying natural gas for customers
below monthly benchmarks. The mechanism permits full recovery of all
costs within a tolerance band above the benchmark price and refunds
savings within a tolerance band below the benchmark price. The costs
outside the tolerance band are shared between customers and
shareholders.
Since the 1990s, IOUs have been eligible to earn awards for implementing
and administering energy conservation and efficiency programs. The
California Utilities have offered these programs to customers and have
consistently achieved significant earnings from the program. On October
16, 2003, the CPUC issued a decision that the pre-1998 DSM earnings
proceeding would not be reopened, leaving the earnings mechanism
unchanged. The CPUC may adjust amounts determined pursuant to the
earnings mechanism consistent with the application of known, standard
measurement and verification protocols.
The CPUC has consolidated the 2000, 2001 and 2002 award applications.
The 2003 award applications were filed on May 1, 2003. On May 2, 2003,
the CPUC released RFPs to conduct a review of the IOUs' studies and
reported program milestones/accomplishments used as the basis for the
awards claims and program expenditures. The review should be completed
in the second quarter of 2004. Additionally, the low-income awards will
be subject to an independent review expected to commence in 2005. The
110
majority of the outstanding claims are on hold pending completion of the
independent review.
Incentive Awards Approved in 2003
PBR and GCIM rewards are not included in the company's earnings before
CPUC approval is received. The following table reflects awards approved
in 2003 (dollars in millions):
Program SoCalGas SDG&E Total
- -----------------------------------------------------------
GCIM/Natural Gas PBR $ 48.2 $ 5.3 $ 53.5
Distribution/Other PBR 1.1 18.2 19.3
- -----------------------------------------------------------
Total $ 49.3 $ 23.5 $ 72.8
===========================================================
Pending Incentive Awards
At December 31, 2003, the following performance incentives were pending
CPUC approval and, therefore, were not included in the company's
earnings (dollars in millions):
Program SoCalGas SDG&E Total
- -----------------------------------------------------------
GCIM/Natural Gas PBR $ 6.3 $ 1.9 $ 8.2
DSM/Energy Efficiency* 9.8 35.6 45.4
- -----------------------------------------------------------
Total $ 16.1 $ 37.5 $ 53.6
===========================================================
* Dollar amounts shown do not include interest, franchise fees or
uncollectible amounts.
Cost of Capital
Effective January 1, 2003, SoCalGas' authorized rate of return on common
equity (ROE) is 10.82 percent and its return on ratebase (ROR) is 8.68
percent. Effective January 1, 2003, SDG&E's authorized ROE is 10.9
percent and its ROR is 8.77 percent, for SDG&E's electric distribution
and natural gas businesses. The electric-transmission cost of capital is
determined under a separate FERC proceeding discussed below. These rates
will continue to be effective until market interest-rate changes are
large enough to trigger an automatic adjustment or until the CPUC orders
a periodic review.
The objective of SDG&E's market-indexed capital adjustment mechanism is
to revise SDG&E's rates to reflect changes in the six-month average of
double-A rated utility bond rates, without lengthy Commission
proceedings. The benchmark average is currently 7.24 percent, the six-
month average at September 30, 2002, the year of SDG&E's last cost of
capital proceeding. If in any year the difference between the current
six-month average at September 30th and the benchmark exceeds 100 basis
points, SDG&E's authorized ROE is adjusted by one-half of the
difference, and the embedded costs of debt and preferred equity are
adjusted to current levels. In addition, the triggering six-month
average becomes the new benchmark until another automatic adjustment
111
occurs. The six-month average was 6.32 percent at September 30, 2003
and, therefore, no triggering has occurred. The rate has not changed
significantly since then.
SoCalGas' automatic adjustment mechanism provides for a trigger in any
month when the 12-month trailing average of 30-year Treasury bond rates
varies by greater than 150 basis points from the benchmark, and the
current Global Insight forecast of the 30-year Treasury bond rate 12
months ahead varies by greater than 150 basis points from the benchmark.
When these criteria are met, SoCalGas' authorized ROE is adjusted by
one-half of the difference between the trailing 12-month average and the
benchmark, and the embedded costs of debt and preferred equity are
adjusted to current levels. Any time an automatic adjustment occurs, the
new trailing 12-month average becomes the new benchmark. The benchmark
is currently 5.38 percent, the 12-month trailing average of the 30-year
Treasury bond as of October 2002. At December 31, 2003, the 12-month
average of the 30-year Treasury bond was 4.92 percent and the estimated
Global Insight year-ahead forecast was 5.90 percent and, therefore, no
triggering has occurred. The rates have not changed significantly since
then.
Border Price Investigation
In November 2002, the CPUC instituted an investigation into the Southern
California natural gas market and the price of natural gas delivered to
the California-Arizona border between March 2000 and May 2001. If the
investigation determines that the conduct of any party to the
investigation contributed to the natural gas price spikes, the CPUC may
modify the party's natural gas procurement incentive mechanism, reduce
the amount of any shareholder award for the period involved, and/or
order the party to issue a refund to ratepayers. On December 10, 2003,
Southern California Edison filed testimony alleging that SoCalGas
significantly contributed to the price spikes and exercised market power
and recommended to the CPUC that SoCalGas divest its storage assets and
revise its GCIM to an incentive mechanism that would simply reward
SoCalGas if it managed to procure natural gas supplies in the producing
basins at a price below market. Hearings are scheduled to begin in late
March 2004 with a decision expected by late 2004. The company believes
that the CPUC will find that SoCalGas acted in the best interests of its
core customers.
Biennial Cost Allocation Proceeding
The BCAP determines the allocation of authorized costs between customer
classes for natural gas transportation service provided by the
California Utilities and adjusts rates to reflect variances in customer
demand as compared to the forecasts previously used in establishing
transportation rates. SoCalGas and SDG&E filed with the CPUC their 2005
BCAP applications in September 2003, requesting updated transportation
rates effective January 1, 2005. The most recent BCAP decision
allocating the California Utilities non-commodity natural gas costs of
service and revising their respective natural gas transportation rates
and rate designs was issued in April 2000 and is still in effect. In
November 2003, an Assigned Commissioner Ruling delayed the current BCAP
applications until a decision is issued in the GIR implementation
proceeding discussed above. As a result, SoCalGas is required to amend
its BCAP application within 21 days of a decision in the GIR and SDG&E
112
is required to amend its BCAP application seven days thereafter. As a
result of the deferrals and the forecasted significant decline in
noncore gas throughput on SoCalGas' system, in December 2002 the CPUC
issued a decision approving 100 percent balancing account protection for
SoCalGas' risk on local transmission and distribution revenues from
January 1, 2003 until the CPUC issues its next BCAP decision. SoCalGas
is seeking to continue this balancing account protection through 2006. A
CPUC decision on GIR could result in revising noncore balancing account
treatment to exclude the balancing of transmission costs; other noncore
costs/revenues would continue to be fully balanced until the BCAP
decision.
CPUC Investigation of Energy-Utility Holding Companies
The CPUC has initiated an investigation into the relationship between
California's IOUs and their parent holding companies. Among the matters
to be considered in the investigation are utility dividend policies and
practices and obligations of the holding companies to provide financial
support for utility operations under the agreements with the CPUC
permitting the formation of the holding companies. In January 2002 the
CPUC issued a decision to clarify under what circumstances, if any, a
holding company would be required to provide financial support to its
utility subsidiaries. The CPUC broadly determined that it would require
the holding company to provide cash to a utility subsidiary to cover its
operating expenses and working capital to the extent they are not
adequately funded through retail rates. This would be in addition to the
requirement of holding companies to cover their utility subsidiaries'
capital requirements, as the IOUs have previously acknowledged in
connection with the holding companies' formations. In January 2002 the
CPUC ruled on jurisdictional issues, deciding that it had jurisdiction
to create the holding company system and, therefore, retains
jurisdiction to enforce conditions to which the holding companies had
agreed. The company's request for rehearing on the issues was denied by
the CPUC and the company subsequently filed appeals in the California
Court of Appeal. On November 26, 2003 the California Court of Appeal
agreed to hear the company's appeal. Oral argument is set for March 5,
2004.
CPUC Investigation of Compliance with Affiliate Rules
In February 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to determine if they
have complied with statutes and CPUC decisions in the management,
oversight and operations of their companies. In September 2003, the CPUC
suspended the procedural schedule until it completes an independent
audit to evaluate energy-related holding company systems and affiliate
activities undertaken by Sempra Energy within the service territories of
SDG&E and SoCalGas. The audit will cover years 1997 through 2003, is
expected to commence in March 2004 and should be completed by the end of
2004. The scope of the audit will be broader than the annual affiliate
audit. In accordance with existing CPUC requirements, the California
Utilities' transactions with other Sempra Energy affiliates have been
audited by an independent auditing firm each year, with results reported
to the CPUC, and there have been no material adverse findings in those
audits.
113
FERC Standards of Conduct
On November 25, 2003, the FERC established standards of conduct
governing the relationship between transmission providers and their
energy affiliates. They broaden the definition of an energy affiliate.
Under the standards, SDG&E is a transmission provider and SoCalGas is an
energy affiliate of SDG&E. The standards require transmission providers
to offer service to all customers on a non-discriminatory basis. SER,
SES and SET are also considered energy affiliates of SDG&E, and, among
other things, SDG&E must apply the standards of conduct prohibiting
unduly preferential information sharing with the energy affiliates.
Impacts, if any, of the standards are being determined for SEI and SER.
FERC Transmission Cost of Service
On May 2, 2003, the FERC accepted SDG&E's request for modification of
its Transmission Owner Tariff to adopt a transmission rate formula that
would allow SDG&E to recover its actual prudent costs for transmission
service. New transmission rates, which are subject to refund based on
the FERC's final order, became effective October 1, 2003.
On December 18, 2003, the FERC approved the transmission formula, with
rates effective October 1, 2003, whereby SDG&E's rates would be adjusted
annually to cover actual prudent costs, including an ROE of 11.25
percent on its actual equity as of December 31 of the prior year.
SDG&E's revenue requirements for its retail customers for the initial
12-month period beginning October 1, 2003, will be $142.1 million. SDG&E
will fully recover its cancelled Valley-Rainbow Project costs of $19
million over a ten-year amortization period, with no return component.
The transmission rate formula will be in effect through June 30, 2007.
Recovery of Certain Disallowed Transmission Costs
In August 2002 the FERC issued Opinion No. 458, which effectively
disallowed SDG&E's recovery of the differentials between certain
payments to SDG&E by its co-owners of the Southwest Powerlink under the
Participation Agreements and charges assessed to SDG&E under the ISO
FERC tariff for transmission line losses and grid management charges
related to energy schedules of Arizona Public Service Co. (APS) and the
Imperial Irrigation District (IID), its Southwest Powerlink co-owners.
As a result, SDG&E is incurring unreimbursed costs of $4 million to $8
million per year. On November 17, 2003, SDG&E petitioned the United
States Court of Appeals for review of these FERC orders and argued that
the disallowed costs should be allowed for recovery through the
Transmission Revenue Balancing Account Adjustment. On February 12, 2004,
on the FERC's motion, the court remanded the case back to the FERC for
further consideration, "based on the FERC's representation that it
intends to act expeditiously on remand." The FERC has not yet issued
further orders in this matter.
In a separate but related matter, on July 6, 2001, SDG&E filed an
arbitration claim against the ISO, claiming the ISO should not charge
SDG&E for the transmission losses attributable to energy schedules on
the APS and IID shares of the Southwest Powerlink. As of October 2003
amounts under the claim totaled $22 million, including interest. The
independent arbitrator found in SDG&E's favor on this matter. The ISO
appealed this result to the FERC and a FERC decision is expected in
114
2004. SDG&E has also commenced a private arbitration to reform the
Participation Agreements to remove prospectively SDG&E's obligation to
provide services giving rise to unreimbursed ISO tariff charges.
Southern California Fires
Several major wildfires that began on October 26, 2003 severely damaged
some of SDG&E's infrastructure, causing a significant number of
customers to be without utility services. On October 27, 2003, Governor
Gray Davis declared a "state of emergency" for counties within SoCalGas'
and SDG&E's service territory.
The declaration of a state of emergency authorizes a public utility to
establish a catastrophic event memorandum account (CEMA) to record all
incremental costs (costs not already included in rates) associated with
the repair of facilities and the restoration of service. Electric
distribution and natural gas related costs are recovered through the
CEMA. Electric transmission related costs are recovered through the
annual true-up FERC proceeding. The CEMA related costs are recoverable
in rates separate from ordinary costs currently recovered in rates. The
CPUC is required to hold expedited hearings in response to the
utilities' request for recovery. Total fire-related costs are estimated
to be $70 million and $5 million for SDG&E and SoCalGas, respectively,
with $60 million and $1 million, respectively, incurred during 2003, the
majority of which were capital related. At December 31, 2003, the CEMA
account included $14 million of incremental operating and maintenance
costs. The company expects to file a CEMA application sometime in 2004.
The company expects no significant effect on earnings from the fires.
NOTE 15. COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts
The California Utilities buy natural gas under short-term contracts.
Short-term purchases are from various Southwest U.S. and Canadian
suppliers and are primarily based on monthly spot-market prices. The
California Utilities transport natural gas under long-term firm pipeline
capacity agreements that provide for annual reservation charges, which
are recovered in rates. SoCalGas has commitments with pipeline companies
for firm pipeline capacity under contracts that expire at various dates
through 2007.
SDG&E has long-term natural gas transportation contracts with various
interstate pipelines that expire on various dates between 2004 and 2023.
SDG&E currently purchases natural gas on a spot basis to fill its long-
term pipeline capacity and purchases additional spot market supplies
delivered directly to California for its remaining requirements. SDG&E
continues its ongoing assessment of its long-term pipeline capacity
portfolio, including the release of a portion of this capacity to third
parties.
115
At December 31, 2003, the future minimum payments under natural gas
contracts were:
<table>
<caption>
Storage and Natural
(Dollars in millions) Transportation Gas Total
- -----------------------------------------------------------------------------
<s> <c> <c> <c>
2004 $ 221 $ 767 $ 988
2005 211 11 222
2006 125 11 136
2007 21 2 23
2008 20 3 23
Thereafter 207 -- 207
-------------------------------------------
Total minimum payments $ 805 $ 794 $1,599
- -----------------------------------------------------------------------------
</table>
Total payments under natural gas contracts were $2.2 billion in 2003,
$1.4 billion in 2002 and $2.6 billion in 2001.
Purchased-Power Contracts
In January 2001, the California Assembly passed AB X1 to allow the DWR
to purchase power under long-term contracts for the benefit of
California consumers. In accordance with AB X1, SDG&E entered into an
agreement with the DWR under which the DWR purchased SDG&E's full net
short position (the power needed by SDG&E's customers, other than that
provided by SDG&E's nuclear generating facilities or its previously
existing purchased-power contracts) through December 31, 2002. Starting
on January 1, 2003, SDG&E and the other IOUs resumed their electric
commodity procurement function based on a CPUC decision issued in
October 2002. In April 2003, the CPUC approved an operating agreement
between the DWR and SDG&E that bestows upon SDG&E the role of a limited
agent on behalf of the DWR in undertaking energy sales and natural gas
procurement functions for the DWR contracts. For additional discussion
of this matter see Note 13.
For 2004, SDG&E expects to receive 49 percent of its customer power
requirement from DWR allocations. Of the remaining requirements, SONGS
is expected to account for 21 percent, long-term contracts for 19
percent and spot market purchases for 11 percent. The contracts expire
on various dates through 2025. Prior to January 1, 2001, the cost of
these contracts was recovered by bidding them into the PX and receiving
revenue from the PX for bids accepted. As of January 1, 2001, in
compliance with a FERC order prohibiting sales to the PX, SDG&E no
longer bids those contracts into the PX. Those contracts are now used to
serve customers in compliance with a CPUC order. In addition, during
2002 SDG&E entered into contracts which will provide five percent of its
2004 total energy sales from renewable sources. These contracts expire
on various dates through 2021.
116
At December 31, 2003, the estimated future minimum payments under the
long-term contracts (not including the DWR allocations) were:
(Dollars in millions)
- --------------------------------------------------------------------
2004 $ 214
2005 224
2006 233
2007 240
2008 218
Thereafter 2,235
-------
Total minimum payments $ 3,364
- --------------------------------------------------------------------
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. Excluding DWR-
allocated contracts, total payments under the contracts were $396
million in 2003, $235 million in 2002 and $512 million in 2001.
Leases
The company has leases (primarily operating) on real and personal
property expiring at various dates from 2004 to 2045. Certain leases on
office facilities contain escalation clauses requiring annual increases
in rent ranging from 3 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 on real property.
Property, plant and equipment included $36 million at December 31, 2003
and $35 million at December 31, 2002, related to these leases. The
associated accumulated amortization was $23 million and $21 million,
respectively. SDG&E terminated its capital lease agreement for nuclear
fuel in mid-2001 and now owns its nuclear fuel.
At December 31, 2003, the minimum rental commitments payable in future
years under all noncancellable leases were as follows:
Operating Capitalized
(Dollars in millions) Leases Leases
- --------------------------------------------------------------------
2004 $ 97 $ 4
2005 85 3
2006 77 1
2007 76 1
2008 69 1
Thereafter 213 1
----------------------
Total future rental commitments $ 617 11
-------
Imputed interest (6% to 10%) (3)
------
Net commitments $ 8
- --------------------------------------------------------------------
117
In connection with the quasi-reorganization described in Note 1, PE
recorded liabilities of $102 million to adjust to fair value the
operating leases related to its headquarters and other facilities at
December 31, 1992. The remaining amount of these liabilities was $35
million at December 31, 2003. These leases are included in the above
table at the amounts provided in the lease.
Rent expense for operating leases totaled $98 million in 2003, $90
million in 2002 and $92 million in 2001. Depreciation expense for
capitalized leases is included in Depreciation and Amortization on the
Consolidated Statements of Income.
Global Construction Projects
Global has several subsidiaries which have developed or are in the
process of constructing various capital projects in the United States
and in Mexico. The following is a summary of construction projects
developed or under development by the respective business units.
SER
SER acquires, develops and operates power plants throughout the U.S. and
Mexico. As of the end of 2003, SER had five power plants in operations.
The 1,250-MW Mesquite Power plant commenced operations in two phases
during 2003; the first phase of commercial operations began in June 2003
and the second phase started in December 2003. See further discussion
on the Mesquite Power plant in Notes 1 and 2.
In the third quarter of 2003, SER completed construction and commenced
operations of its $350 million 600-MW TDM power plant. The
environmental issues concerning this facility are described under
"Litigation" and in Note 2. TDM's natural gas from Ehrenberg, Arizona to
the interconnection with Gasoducto Bajanorte is being delivered via the
North Baja Pipeline. The transportation is provided through an agreement
between SER and North Baja Pipeline LLC. Under the agreement, SER is
obligated to pay a monthly reservation charge for the transport of
certain quantities over a 20-year period. The future commitments
related to this contract are $83 million.
In the third quarter of 2003, SER completed construction of the 550-MW
Elk Hills power project located in Bakersfield, California. SER owns 50
percent of Elk Hills and has invested $219 million in Elk Hills through
December 31, 2003.
On October 31, 2002, SER acquired the 305-MW Twin Oaks Power plant. In
connection with the acquisition, SER also assumed a contract which
includes annual commitments to purchase lignite coal either until an
aggregate minimum volume has been achieved or through 2025. As of
December 31, 2003, SER's future minimum payments under the lignite coal
agreement totaled $455 million, for which payments of $29 million are
due for 2004, $29 million for 2005, $25 million for 2006, $25 million
for 2007, $25 million for 2008 and $322 million thereafter. The minimum
payments have been adjusted for allowed shortfalls and 90 percent
minimum contract requirements under the contract.
118
In August 2003, SER obtained approvals by the California Energy
Commission for the company's planned 550-MW Palomar power plant in
Escondido, California. The estimated two-year construction project will
commence when power contracts for the project have been signed. SER
currently is seeking contracts that would support advancement of the
project. In January 2004, SDG&E contracted with SER to purchase the
power plant from SER when construction is complete in 2006. The plant
will then be owned and operated by SDG&E under CPUC regulation.
As of December 31, 2003, SER has no additional construction commitments
concerning the facilities described above but has additional commitments
of $7 million related to two natural gas turbines for use in future
power plant development.
SELNG
SELNG is in the process of developing Energia Costa Azul, a major new
LNG receiving terminal that will bring natural gas supplies into
northwestern Mexico and Southern California. This is discussed in Note
2.
In April 2003, SELNG acquired Cameron LNG for $36 million. Additional
payments are contingent on meeting certain benchmarks and milestones and
the performance of the project. At December 31, 2003, the company has
recorded a liability of $30 million related to this matter. The total
cost of the project is expected to be about $700 million. The project
could begin commercial operations as early as 2007.
SELNG currently leases land in Hackberry, Louisiana for the development
of the Cameron LNG terminal. In connection with the purchase of Cameron
LNG, SELNG and the lessor agreed to certain lease amendments, including
an increase in the annual rent, addition of wharfage fees and extension
of the lease term for another 30 years. The lease amendments are
contingent upon obtaining project financing or commencement of
construction. As of December 31, 2003, SELNG is still operating under
the original land lease, which is up for renewal in February 2005.
Accordingly, rent payments subsequent to January 2005 are not included
in the table of future minimum rental payment obligations. Should the
terms of the amended lease be triggered, total rent payments and
wharfage fees would be $38 million over 30 years. See Note 2 for further
discussion on the LNG facilities.
SEI
In 2002, SEI completed construction of the 140-mile Gasoducto Bajanorte
Pipeline that connects the Rosarito Pipeline south of Tijuana, Mexico
with a pipeline built by PG&E Corporation (PG&E) that connects to
Arizona. The 30-inch pipeline can deliver up to 500 million cubic feet
per day of natural gas to new generation facilities in Baja California,
including SER's TDM power plant discussed above. Capacity on the
pipeline is over 90 percent subscribed. The company had no additional
construction costs or other commitments for this pipeline at December
31, 2003.
119
SER's Contract with DWR
In May 2001, SER entered into a ten-year agreement with the DWR to
supply up to 1,900 MW of power to the state. SER may, but is not
obligated to, deliver this electricity from its portfolio of plants in
the western United States and Baja California, Mexico. If SER elects to
use these plants to supply the DWR, those sales would comprise more than
two-thirds of the projected capacity of the plants. Subsequent to the
state's signing of this contract and electricity-supply contracts with
other vendors, various state officials have contended that the rates
called for by the contracts are too high. These rates substantially
exceed current spot-market prices for electricity, but are substantially
lower than those prevailing at the time the contracts were signed.
Information concerning the validity of this contract is provided under
"Litigation - DWR Contract." Information concerning the FERC's orders
upholding this contract and the pending appeal is provided in FERC
Actions in Note 13.
Impact of Direct Access on SES
On March 21, 2002, the CPUC affirmed its decision prohibiting new direct
access contracts after September 20, 2001, but rejected a proposal to
make the prohibition retroactive to July 1, 2001. Contracts in place as
of September 20, 2001 may be renewed or assigned to new parties. On
November 7, 2002, the CPUC issued a decision adopting DA exit fees with
an interim cap of 2.7 cents per kWh for rates effective January 1, 2003.
The CPUC is conducting further proceedings to determine whether, and to
what extent, the interim cap should be revised after July 1, 2003. The
CPUC's decisions concerning direct access could affect the motivation of
potential customers to enter into contracts for SES to sell them
electricity in California.
Environmental Issues
The company has identified no significant environmental issues outside
the United States, except for the additional environmental impact
studies the DOE is conducting of the TDM power plant. Additional
information regarding the environmental studies is provided below under
"Litigation." The following discussion is related to environmental
matters within the United States.
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. Most of the environmental issues faced by the company have
occurred at the California Utilities. However, now that SER owns and
operates several power plants and SELNG is developing LNG regasification
terminals, additional environmental issues may arise. As applicable,
appropriate and relevant, these laws and regulations require that the
company investigate and remediate the effects of the release or disposal
of materials at sites associated with past and present operations,
including sites at which the company has been identified as a
Potentially Responsible Party (PRP) under the federal Superfund laws and
comparable state laws. Costs incurred at the California Utilities to
operate the facilities in compliance with these laws and regulations
generally have been recovered in customer rates.
120
Significant costs incurred to mitigate or prevent future environmental
contamination or extend the life, increase the capacity, or improve the
safety or efficiency of property utilized in current operations are
capitalized. The company's capital expenditures to comply with
environmental laws and regulations were $14 million in 2003, $8 million
in 2002 and $6 million in 2001. The cost of compliance with these
regulations over the next five years is not expected to be significant.
At the California Utilities, costs that relate to current operations or
an existing condition caused by past operations are generally recorded
as a regulatory asset due to the expectation that these costs will be
recovered in rates.
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 (29 completed as of
December 31, 2003 and 16 to be completed), 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
PRP (investigations and remediations are continuing) and mitigation of
damage to the marine environment caused by the cooling-water discharge
from SONGS (the requirements for enhanced fish protection, a 150-acre
artificial reef and restoration of 150 acres of coastal wetlands are in
process).
Environmental liabilities are recorded when the company's liability is
probable and the costs are reasonably estimable. In many cases, however,
investigations are not yet at a stage where the company has been able to
determine whether it is liable or, if the liability is probable, to
reasonably estimate the amount or range of amounts of the cost or
certain components thereof. Estimates of the company's liability are
further subject to other uncertainties, such as the nature and extent of
site contamination, evolving remediation standards and imprecise
engineering evaluations. The accruals are reviewed periodically and, as
investigations and remediation proceed, adjustments are made as
necessary. At December 31, 2003, the company's accrued liability for
environmental matters was $61.4 million, of which $48.7 million related
to manufactured-gas sites, $10.5 million to cleanup at SDG&E's former
fossil-fueled power plants, $2.1 million to waste-disposal sites used by
the company (which has been identified as a PRP) and $0.1 million to
other hazardous waste sites. The accruals for the manufactured-gas and
waste-disposal sites are expected to be paid ratably over the next three
years. The accruals for SDG&E's former fossil-fueled power plants are
expected to be paid ratably over the next two years.
Nuclear Insurance
SDG&E and the other owners of SONGS have insurance to respond to nuclear
liability claims related to SONGS. The insurance policy provides $300
million in coverage, which is the maximum amount available. In addition
to this primary financial protection, the Price-Anderson Act provides
for up to $10.6 billion of secondary financial protection if the
liability loss exceeds the insurance limit. Should any of the
licensed/commercial reactors in the United States experience a nuclear
liability loss which exceeds the $300 million insurance limit, all
utilities owning nuclear reactors could be assessed under the Price-
121
Anderson Act to provide the secondary financial protection. SDG&E and
the other co-owners of SONGS could be assessed up to $201 million under
the Price-Anderson Act. SDG&E's share would be $40 million unless a
default were to occur by any other SONGS co-owner. In the event the
secondary financial protection limit were insufficient to cover the
liability loss, the Price-Anderson Act provides for Congress to enact
further revenue-raising measures to pay claims. These measures could
include an additional assessment on all licensed reactor operators.
SDG&E and the other owners of SONGS have $2.75 billion of nuclear
property, decontamination and debris removal insurance. The coverage
also provides the SONGS owners up to $490 million for outage
expenses/replacement power incurred because of accidental property
damage. This coverage is limited to $3.5 million per week for the first
52 weeks, and $2.8 million per week for up to 110 additional weeks.
There is a deductible waiting period of 12 weeks prior to receiving
indemnity payments. The insurance is provided through a mutual insurance
company owned by utilities with nuclear facilities. Under the policy's
risk sharing arrangements, insured members are subject to retrospective
premium assessments if losses at any covered facility exceed the
insurance company's surplus and reinsurance funds. Should there be a
retrospective premium call, SDG&E could be assessed up to $7.4 million.
Both the nuclear liability and property insurance programs include
industry aggregate limits for terrorism-related SONGS losses, including
replacement power costs.
Litigation
During 2003, the company recorded $49 million of after-tax charges
related to litigation costs and a SoCalGas sublease. Management believes
that none of these matters will have further material adverse effect on
the company's financial condition or results of operations. Except for
the matters referred to below, 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.
DWR Contract
In May 2003, the San Diego Superior Court granted SER's motion for
summary judgment on its complaint regarding its contract with the DWR
(and the DWR's cross-complaint seeking to void the 10-year energy-supply
contract). The court determined that "(a) Sempra is entitled to provide
electrical energy from any source, including Market Sources, (b) Sempra
is not in breach of the Agreement as framed by the pleadings in this
matter, (c) DWR is obligated to take delivery and pay for deliveries
under the Agreement, and (d) Sempra has no obligation to complete any
specific Project." The DWR filed a motion for a new trial claiming
irregularities in the Court's judgment. The Court subsequently clarified
its earlier summary judgment ruling and effectively denied the motion
for new trial. An amended judgment was entered by the Court. The DWR has
filed a notice of appeal on the judgments and the Court's clarification.
A decision by the appellate court is expected sometime during 2005. The
DWR continues to accept all scheduled power from SER and, although it
has disputed billings in an immaterial amount and the manner of certain
122
deliveries, it has paid all amounts that have been billed under the
contract.
Antitrust Litigation
Class-action and individual lawsuits filed in 2000 and currently
consolidated in San Diego Superior Court seek damages, alleging that
Sempra Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El
Paso) and several of its affiliates, unlawfully sought to control
natural gas and electricity markets. In March 2003, plaintiffs in these
cases and the applicable El Paso entities announced that they had
reached a $1.5 billion settlement, of which $125 million is allocated to
customers of the California Utilities. The Court approved that
settlement in December 2003. The proceeding against Sempra Energy and
the California Utilities has not been settled and continues to be
litigated.
Natural Gas Cases: Similar lawsuits have been filed by the Attorneys
General of Arizona and Nevada, alleging that El Paso and certain Sempra
Energy subsidiaries unlawfully sought to control the natural gas market
in their respective states. In April 2003, Sierra Pacific Resources and
its utility subsidiary Nevada Power filed a lawsuit in U.S. District
Court in Las Vegas against major natural gas suppliers, including Sempra
Energy, the California Utilities and other company subsidiaries, seeking
damages resulting from an alleged conspiracy to drive up or control
natural gas prices, eliminate competition and increase market
volatility, breach of contract and wire fraud. On January 27, 2004, the
U.S. District Court dismissed the Sierra Pacific Resources case against
all of the defendants, determining that this is a matter for the FERC.
Electricity Cases: Various lawsuits, which seek class-action
certification, allege that Sempra Energy and certain company
subsidiaries (SDG&E, SET and SER, depending on the lawsuit) unlawfully
manipulated the electric-energy market. In January 2003, the applicable
federal court granted a motion to dismiss a similar lawsuit on the
grounds that the claims contained in the complaint were subject to the
Filed Rate Doctrine and were preempted by the Federal Power Act. That
ruling has been appealed in the Ninth Circuit Court of Appeals, which is
expected to hear the appeal in the first quarter of 2004. Similar suits
filed in Washington and Oregon were voluntarily dropped by the
plaintiffs without court intervention in June 2003. In addition, in May
2003, the Port of Seattle filed an action alleging that a number of
energy companies, including Sempra Energy, SER and SET, unlawfully
manipulated the electric energy market and committed wire fraud. That
action has been transferred to San Diego Federal District Court and is
currently pending a motion to dismiss on the grounds that the claims
contained in the complaint were subject to the Filed Rate Doctrine and
were preempted by the Federal Power Act.
SER, SET and SDG&E, along with all other sellers in the western power
market, have been named defendants in a complaint filed at the FERC by
the California Attorney General's office seeking refunds for electricity
purchases based on alleged violations of FERC tariffs. The FERC has
dismissed the complaint. The California Attorney General has filed an
appeal in the 9th Circuit.
123
Price Reporting Practices
In the fourth quarter of 2002, Sempra Energy and SoCalGas were named as
defendants in a lawsuit filed in Los Angeles Superior Court against
various trade publications and other energy companies alleging that
energy prices were unlawfully manipulated by defendants' reporting
artificially inflated natural gas prices to trade publications. On July
8, 2003, the Superior Court granted the defendants' demurrer on the
grounds that the claims contained in the complaint were subject to the
Filed Rate Doctrine and were preempted by the Federal Power Act.
Plaintiffs filed an amended complaint, and in September 2003 defendants
filed a demurrer to the amended complaint, which was granted in part.
In December 2003, the plaintiffs dismissed both Sempra Energy and
SoCalGas from the lawsuit. In May 2003 and again in February 2004,
similar actions were filed in San Diego Superior Court against Sempra
Energy and SET, and the May 2003 action has been removed to Federal
District Court. Another lawsuit containing identical allegations was
filed against Sempra Energy and SET in Federal District Court in
November of 2003. In addition, in August 2003, a lawsuit was filed in
the Southern District of New York against Sempra Energy and SES,
alleging that the prices of natural gas options traded on the NYMEX were
unlawfully increased under the Federal Commodity Exchange Act by
defendants' manipulation of transaction data to natural gas trade
publications. In November of 2003, another suit containing identical
allegations was filed and consolidated with the New York action. In
December 2003, plaintiffs dismissed Sempra Energy from these cases and
in January 2004, SES was also dismissed. On January 20, 2004, plaintiffs
filed an amended consolidated complaint that named SET as a defendant in
this lawsuit.
In January 2004, the Commodity Futures Trading Commission (CFTC) issued
a subpoena to SoCalGas and SET in connection with the CFTC's "Activities
Affecting the Price of Natural Gas in the Fall of 2003"
investigation. The company is cooperating with the CFTC in the
investigation.
Other
On August 21, 2003, the CPUC denied a rehearing requested by opponents
of its December 2002 decision that had approved a settlement with SDG&E
allocating between SDG&E customers and shareholders the profits from
intermediate-term purchase power contracts that SDG&E had entered into
during the early stages of California's electric utility industry
restructuring. As previously reported, the settlement provided $199
million of these profits to customers, by reductions to balancing
account undercollections in prior years. The settlement provided the
remaining $173 million of profits to SDG&E shareholders, of which $57
million had been recognized for financial reporting purposes in prior
years. As a result of the decision, SDG&E recognized additional after-
tax income of $65 million in the third quarter of 2003. UCAN, a
consumer-advocacy group which had requested the CPUC rehearing, appealed
the decision to the California Court of Appeals and the court agreed to
hear the case. Oral arguments are likely to occur in March or April
2004. A decision is expected by the third quarter of 2004. The company
expects that the Court of Appeals will affirm the CPUC's decision.
124
SER was a defendant in an action brought by Occidental Energy Ventures
Corporation (Occidental) with respect to the Elk Hills power project
being jointly developed by the two companies. On September 30, 2003, the
arbitration proceeding found in favor of SER, determining that SER had
not breached its joint development contract with Occidental.
In May 2003, a federal judge issued an order finding that the DOE's
abbreviated assessment of two Mexicali power plants, including SER's TDM
plant, failed to evaluate the plants' environmental impact adequately
and called into question the U.S. permits they received to build their
cross-border transmission lines. In July 2003, the judge ordered the DOE
to conduct additional environmental studies and denied the plaintiffs'
request for an injunction blocking operation of the transmission lines,
thus allowing the continued operation of the TDM plant. The DOE has
until May 15, 2004, to demonstrate why the court should not set aside
the permits.
In 1999, Sempra Energy and PSEG each acquired a 44-percent interest in
Luz Del Sur, a Peruvian electric distribution company. Local law
required that assets built with government funds be purchased by the
local utility and added to rate base. A dispute arose between the
government and Luz Del Sur over the amount of compensation due for the
194 projects transferred to Luz Del Sur by the government. The
government claims the amount owed was $36 million. Luz Del Sur argued
that the amount was less and the matter was settled with the government
for approximately $10 million. Following a change in the Peruvian
government, a criminal charge was filed against certain government
officials, and utility officials as accomplices, including the chief
executive officer and chief financial officer of Luz Del Sur, alleging
that the settlements were inadequate. In September 2003 a Peruvian court
ordered the prosecutor's case to be dismissed. Although the prosecutor
has indicated no evidence of wrongdoing in the case, the prosecutor has
appealed this decision and the case rests in a higher Peruvian court. A
decision is expected during the first half of 2004.
At December 31, 2003, SET remains due approximately $100 million from
energy sales made in 2000 and 2001 through the ISO and the PX markets.
The collection of these receivables depends on satisfactory resolution
of the financial difficulties being experienced by other California IOUs
as a result of the California electric industry crisis. SET has
submitted relevant claims in the PG&E and PX bankruptcy proceedings. The
company believes adequate reserves have been recorded.
FERC Actions
Information regarding FERC actions related to the company is provided in
Note 13.
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. This delay by the
DOE will lead to increased cost for spent fuel storage. This cost will
be recovered through SONGS revenue unless the company is able to recover
the increased cost from the federal government.
125
Electric Distribution System Conversion
Under a CPUC-mandated program, the cost of which is included in utility
rates, 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, 2003, the aggregate
unexpended amount of this commitment was $90 million. Capital
expenditures for underground conversions were $28 million in 2003, $33
million in 2002 and $12 million in 2001.
Concentration Of Credit Risk
The company maintains credit policies and systems to manage overall
credit risk. These policies include 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. The
California Utilities grant credit to utility customers and
counterparties, substantially all of whom are located in their service
territories, which together cover most of Southern California and a
portion of central California.
As described above, SER has a contract with the DWR to supply up to
1,900 MW of power to the state over 10 years, beginning in 2001. SER
would be at risk for the amounts of outstanding billings and the
continued viability of the contract if the DWR were to default on its
payments under this contract. At any given time, the average outstanding
billings related to this contract is $50 million to $60 million.
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 netting
arrangements whenever possible and, where appropriate, obtains
collateral or other security such as lock-box liens and downgrade
triggers. 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 16. SEGMENT INFORMATION
The company has four separately managed reportable segments comprised of
SoCalGas, SDG&E, SET and SER. The California Utilities operate in
essentially separate service territories under separate regulatory
frameworks and rate structures set by the CPUC. SoCalGas is a natural
gas distribution utility, serving customers throughout most of Southern
California and part of central California. SDG&E provides electric
service to San Diego and southern Orange counties and natural gas
service to San Diego County. SET, based in Stamford, Connecticut, is a
wholesale trader of physical and financial energy products and other
commodities, and a trader and wholesaler of metals, serving a broad
range of customers in the United States, Canada, Europe and Asia. SER
acquires, develops and operates power plants throughout the U.S. and
Mexico.
126
The accounting policies of the segments are described in Note 1, and
segment performance is evaluated by management based on reported net
income. California Utility transactions are based on rates set by the
CPUC and FERC.
<table>
<caption>
Years ended December 31,
----------------------------
(Dollars in millions) 2003 2002 2001
- ------------------------------------------------------------------------------------
<s> <c> <c> <c>
OPERATING REVENUES
Southern California Gas $ 3,544 $ 2,858 $ 3,716
San Diego Gas & Electric 2,311 1,725 2,362
Sempra Energy Trading 1,144 821 1,047
Sempra Energy Resources 671 349 178
All other 274 332 458
Intersegment revenues (57) (37) (31)
----------------------------
Total $ 7,887 $ 6,048 $ 7,730
----------------------------
INTEREST INCOME
Southern California Gas $ 34 $ 5 $ 22
San Diego Gas & Electric 42 10 21
Sempra Energy Trading 12 11 11
Sempra Energy Resources 14 4 6
All other 132 84 73
Intercompany elimination (130) (72) (50)
----------------------------
Total $ 104 $ 42 $ 83
----------------------------
DEPRECIATION AND AMORTIZATION
Southern California Gas $ 289 $ 276 $ 268
San Diego Gas & Electric 242 230 207
Sempra Energy Trading 23 21 27
Sempra Energy Resources 13 2 1
All other 48 67 76
----------------------------
Total $ 615 $ 596 $ 579
----------------------------
INTEREST EXPENSE
Southern California Gas $ 45 $ 44 $ 68
San Diego Gas & Electric 73 77 92
Sempra Energy Trading 30 43 14
Sempra Energy Resources 25 6 7
All other 265 196 192
Intercompany elimination (130) (72) (50)
----------------------------
Total $ 308 $ 294 $ 323
----------------------------
INCOME TAX EXPENSE (BENEFIT)
Southern California Gas $ 150 $ 178 $ 169
San Diego Gas & Electric 148 91 141
Sempra Energy Trading 62 60 131
Sempra Energy Resources 29 36 (18)
All other (342) (219) (210)
----------------------------
Total $ 47 $ 146 $ 213
----------------------------
NET INCOME (LOSS)
Southern California Gas $ 209 $ 212 $ 207
San Diego Gas & Electric 334 203 177
Sempra Energy Trading 98 126 196
Sempra Energy Resources 94 60 (27)
All other (86) (10) (35)
----------------------------
Total $ 649 $ 591 $ 518
- ------------------------------------------------------------------------------------
127
At December 31 or years
ended December 31,
----------------------------
(Dollars in millions) 2003 2002 2001
- ------------------------------------------------------------------------------------
ASSETS
Southern California Gas $ 5,412 $ 5,403 $ 4,986
San Diego Gas & Electric 6,463 6,285 6,542
Sempra Energy Trading 5,923 5,614 2,997
Sempra Energy Resources 2,252 1,347 577
All other 2,780 2,579 3,094
Intersegment receivables (821) (986) (720)
----------------------------
Total $ 22,009 $ 20,242 $ 17,476
----------------------------
CAPITAL EXPENDITURES
Southern California Gas $ 318 $ 331 $ 294
San Diego Gas & Electric 444 400 307
Sempra Energy Trading 51 21 45
Sempra Energy Resources 142 356 225
All other 94 106 197
----------------------------
Total $ 1,049 $ 1,214 $ 1,068
----------------------------
GEOGRAPHIC INFORMATION
Long-lived assets
United States $ 10,380 $ 9,548 $ 8,911
Latin America 1,121 1,062 836
Europe 87 18 10
Canada -- 3 24
----------------------------
Total $ 11,588 $ 10,631 $ 9,781
----------------------------
Operating revenues
United States $ 7,211 $ 5,503 $ 7,169
Latin America 315 168 280
Europe 323 328 250
Canada 10 28 15
Asia 28 21 16
----------------------------
Total $ 7,887 $ 6,048 $ 7,730
- ------------------------------------------------------------------------------------
</table>
128
NOTE 17. QUARTERLY FINANCIAL DATA (UNAUDITED)
<table>
<caption>
Quarters ended
(Dollars in millions, ------------------------------------------------
except per share amounts) March 31 June 30 September 30 December 31
- --------------------------------------------------------------------------------------------
<s> <c> <c> <c> <c>
2003
Operating revenues $ 1,923 $ 1,840 $ 2,058 $ 2,066
Operating expenses 1,708 1,637 1,751 1,852
------------------------------------------------
Operating income $ 215 $ 203 $ 307 $ 214
------------------------------------------------
Income before cumulative effect of changes
in accounting principles $ 117 $ 116 $ 211 $ 251
Net income $ 88 $ 116 $ 211 $ 234
Average common shares outstanding
(diluted) 207.8 210.2 212.3 227.2
Income per common share before cumulative
effect of changes in accounting principles
(diluted) $ 0.56 $ 0.55 $ 1.00 $ 1.11
Net income per common share (diluted) $ 0.42 $ 0.55 $ 1.00 $ 1.03
- --------------------------------------------------------------------------------------------
2002
Operating revenues $ 1,475 $ 1,488 $ 1,385 $ 1,700
Operating expenses 1,224 1,260 1,075 1,502
------------------------------------------------
Operating income $ 251 $ 228 $ 310 $ 198
------------------------------------------------
Income before extraordinary item $ 146 $ 145 $ 150 $ 134
Net income $ 146 $ 147 $ 150 $ 148
Average common shares outstanding
(diluted) 206.4 207.1 205.4 205.6
Income per common share before
extraordinary item (diluted) $ 0.71 $ 0.70 $ 0.73 $ 0.65
Net income per common share (diluted) $ 0.71 $ 0.71 $ 0.73 $ 0.72
- --------------------------------------------------------------------------------------------
Reclassifications have been made to certain of the amounts since they were presented in the
Quarterly Reports on Form 10-Q.
</table>
QUARTERLY COMMON STOCK DATA (UNAUDITED)
<table>
<caption>
First Quarter Second Quarter Third Quarter Fourth Quarter
- -----------------------------------------------------------------------------------
<s> <c> <c> <c> <c>
2003
Market price
High $26.00 $29.40 $30.33 $30.90
Low $22.25 $24.05 $27.31 $26.36
- -----------------------------------------------------------------------------------
2002
Market price
High $25.92 $26.25 $24.11 $24.62
Low $22.15 $21.52 $15.50 $16.70
- -----------------------------------------------------------------------------------
</table>
Dividends declared were $0.25 in each quarter.
129
FORM 10-K
Sempra Energy's annual report to the Securities and Exchange Commission
on Form 10-K is available to shareholders at no charge by writing to
Shareholder Services at 101 Ash Street, San Diego, CA 92101.