SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 2002
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OR
[ ] Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 for the transition period from
to
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SEMPRA ENERGY
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(Exact name of registrant as specified in its charter)
CALIFORNIA 1-14201 33-0732627
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(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.)
101 ASH STREET, SAN DIEGO, CALIFORNIA 92101
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(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (619)696-2000
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SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
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Common stock, without par value New York and Pacific
Mandatorily redeemable trust preferred securities New York
Equity units, due 2007 New York
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether the registrant (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities
Exchange Act of 1934 during the preceding 12 months and (2) has been
subject to such filing requirements for the past 90 days.
Yes [ X ] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to
Item 405 of Regulation S-K is not contained herein, and will not be
contained, to the best of registrant's knowledge, in definitive proxy
or information statements incorporated by reference in Part III of
this Form 10-K or any amendment to this Form 10-K. [X]
Exhibit Index on page 38. Glossary on page 45.
Aggregate market value of the voting stock held by non-affiliates of
the registrant as of January 31, 2003 was $4.9 billion.
Registrant's common stock outstanding as of January 31, 2003 was
206,068,905 shares.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the 2001 Annual Report to Shareholders are incorporated by
reference into Parts I, II, and IV.
Portions of the Proxy Statement prepared for the May 2003 annual
meeting of shareholders are incorporated by reference into Part III.
1
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 4
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . .27
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . .28
Item 4. Submission of Matters to a Vote of Security Holders. .28
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . .28
Item 6. Selected Financial Data. . . . . . . . . . . . . . . .28
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . .29
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . .29
Item 8. Financial Statements and Supplementary Data. . . . . .29
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . .29
PART III
Item 10. Directors and Executive Officers of the Registrant . .30
Item 11. Executive Compensation . . . . . . . . . . . . . . . .30
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . .30
Item 13. Certain Relationships and Related Transactions . . . .30
Item 14. Controls and Procedures. . . . . . . . . . . . . . . .31
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . .32
Independent Auditors' Consent and Report on Schedule. . . . . .34
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . .37
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . .38
Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . .45
Certifications. . . . . . . . . . . . . . . . . . . . . . . . .48
2
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,"
"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 (CPUC), the California Legislature, the
California Department of Water Resources (DWR), and the Federal Energy
Regulatory Commission (FERC); 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 pace of deregulation of
retail natural gas and electricity delivery; the timing and success of
business development efforts; and other uncertainties, all of which are
difficult to predict and many of which are beyond the control of the
company. Readers are cautioned not to rely unduly on any forward-
looking statements and are urged to review and consider carefully the
risks, uncertainties and other factors which affect the company's
business described in this report and other reports filed by the
company from time to time with the Securities and Exchange Commission.
3
PART I
ITEM 1. BUSINESS
Description of Business
A description of Sempra Energy and its subsidiaries (the company) is
given in "Management's Discussion and Analysis of Financial Condition
and Results of Operations" of the 2002 Annual Report to Shareholders,
which is incorporated by reference. The company is a holding company,
whose subsidiaries are primarily engaged in the energy business. It has
four separately managed reportable segments comprised of Southern
California Gas Company (SoCalGas), San Diego Gas & Electric (SDG&E),
Sempra Energy Trading (SET) and Sempra Energy Resources (SER). The
company's two principal subsidiaries, SDG&E and SoCalGas, are
collectively referred to as "the California Utilities." During the
third quarter of 2002, SER first met the requirements for disclosure as
a reportable segment. For further discussion, see Note 16 of the notes
to Consolidated Financial Statements of the 2002 Annual Report to
Shareholders, which is incorporated by reference.
Company Website
The company's website address is http://www.sempra.com/investor.htm.
The company makes available free of charge through its website, its
annual report on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K, and any amendments to those reports as soon as
reasonably practicable after such material is electronically filed with
or furnished to the Securities and Exchange Commission.
GOVERNMENT REGULATION
The most significant government regulation affecting Sempra Energy is
that affecting its utility subsidiaries.
Local Regulation
SoCalGas has gas franchises with the 240 legal jurisdictions in its
service territory. These franchises allow SoCalGas to locate facilities
for the transmission and distribution of natural gas in the streets and
other public places. Some franchises have fixed terms, such as that for
the city of Los Angeles, which expires in 2012. Most of the franchises
do not have fixed terms and continue indefinitely. The range of
expiration dates for the franchises with definite terms is 2003 to
2048.
SDG&E has electric franchises with the three counties and the 26 cities
in its electric service territory, and natural gas franchises with the
one county and the 23 cities in its natural gas service territory.
These franchises allow SDG&E to locate facilities for the transmission
and distribution of electricity and/or natural gas in the streets and
other public places. The franchises do not have fixed terms, except for
the electric and natural gas franchises with the cities of Chula Vista
(2003), Encinitas (2012), San Diego (2021) and Coronado (2028); and the
natural gas franchises with the city of Escondido (2036) and the county
of San Diego (2030).
4
California Utility Regulation
The State of California Legislature, from time to time, passes laws
that regulate SDG&E's and SoCalGas' operations. For example, in 1996
the legislature passed an electric industry deregulation bill, and in
subsequent years passed additional bills aimed at addressing problems
in the deregulated electric industry. In addition, the legislature
enacted a law in 1999 addressing natural gas industry restructuring.
The CPUC, which consists of five commissioners appointed by the
Governor of California for staggered six-year terms, regulates SDG&E's
and SoCalGas' rates and conditions of service, sales of securities,
rate of return, rates of depreciation, uniform systems of accounts,
examination of records, and long-term resource procurement. The CPUC
conducts various reviews of utility performance and conducts
investigations into various matters, such as deregulation, competition
and the environment, to determine its future policies. The CPUC also
regulates the relationship of utilities with their holding companies
and is currently conducting an investigation into this relationship.
The California Energy Commission (CEC) has discretion over electric
demand forecasts for the state and for specific service territories.
Based upon these forecasts, the CEC determines the need for additional
energy sources and for conservation programs. The CEC sponsors
alternative-energy research and development projects, promotes energy
conservation programs and maintains a state-wide plan of action in case
of energy shortages. In addition, the CEC certifies power-plant sites
and related facilities within California.
The CEC conducts a 20-year forecast of supply availability and prices
for every market sector consuming natural gas in California. This
forecast includes resource evaluation, pipeline capacity needs, natural
gas demand and wellhead prices, and costs of transportation and
distribution. This analysis is used to support long-term investment
decisions.
California Power Authority
The California Consumer Power and Financing Authority is responsible
for ensuring reliable electricity at reasonable prices. It does so by
diversifying its electricity portfolio to include increased renewable
energy, permanent conservation efforts and cleaner-burning projects.
United States Utility Regulation
The FERC regulates the interstate sale and transportation of natural
gas, the transmission and wholesale sales of electricity in interstate
commerce, transmission access, the uniform systems of accounts, rates
of depreciation, and electric rates involving sales for resale. Both
the FERC and CPUC are currently investigating prices charged to the
California investor-owned utilities (IOUs) by various suppliers of
natural gas and electricity.
The Nuclear Regulatory Commission (NRC) oversees the licensing,
construction and operation of nuclear facilities. NRC regulations
require extensive review of the safety, radiological and environmental
aspects of these facilities. Periodically, the NRC requires that newly
5
developed data and techniques be used to re-analyze the design of a
nuclear power plant and, as a result, requires plant modifications as a
condition of continued operation in some cases.
International Utility Regulation
The company's consolidated and unconsolidated utility affiliates have
locations in Argentina, Chile, Mexico and Peru. These operations are
subject to the local, federal and other regulations of the countries
and/or political subdivisions in which they are located.
Other Regulation
As a trading company, Sempra Energy Trading has locations and/or
operations in North America, Europe and Asia and is subject to
regulation as to its operations and its financial position. Among other
things, its operations are subject to the New York Mercantile Exchange,
the London Metals Exchange, the Commodity Futures Trading Commission,
the FERC and the National Futures Association. Other subsidiaries are
also subject to varying amounts of regulation by various governments,
including various states in the United States (U.S.).
Licenses and Permits
The California Utilities obtain a number of permits, authorizations and
licenses in connection with the transmission and distribution of
natural gas. In addition, SDG&E obtains a number of permits,
authorizations and licenses in connection with the transmission and
distribution of electricity. Both require periodic renewal, which
results in continuing regulation by the granting agency. The company's
unregulated affiliates are also required to obtain permits,
authorizations and licenses in the normal course of business. Some of
these permits, authorizations and licenses require periodic renewal.
SER and its subsidiaries obtain a number of permits, authorizations and
licenses in connection with the construction and operation of power
generation facilities. In addition, SER obtains permits in connection
with wholesale distribution of electricity. Sempra Energy Solutions
(SES) obtains permits in connection with the construction and operation
of various facilities and with the retail sale of electricity and
natural gas.
Other regulatory matters are described in Notes 13 and 14 of the notes
to Consolidated Financial Statements in the 2002 Annual Report to
Shareholders, which is incorporated by reference.
SOURCES OF REVENUE
Industry segment information is contained in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and in
Note 16 of the notes to Consolidated Financial Statements of the 2002
Annual Report to Shareholders, which is incorporated by reference.
Various information concerning revenue and revenue recognition is
provided in Note 1 of the notes to Consolidated Financial Statements of
the 2002 Annual Report to Shareholders, which is incorporated by
reference.
6
CALIFORNIA UTILITY OPERATIONS
NATURAL GAS OPERATIONS
The company purchases, sells, distributes, stores and transports
natural gas. SoCalGas owns and operates a natural gas distribution,
transmission and storage system that supplies natural gas to 18.9
million end-use customers throughout a 23,000-square mile service
territory from San Luis Obispo in the north, to the Mexican border in
the south, and 535 cities, excluding the City of Long Beach and SDG&E's
service territory in the County of San Diego. SoCalGas also transports
gas to about 1,300 utility electric generation (UEG), wholesale, large
commercial, industrial and off-system (outside the company's normal
service territory) customers.
SDG&E purchases and distributes natural gas to 789,000 end-use
customers throughout the western portion of the County of San Diego.
SDG&E also transports natural gas to approximately 300 customers who
procure the natural gas from other sources.
Supplies of Natural Gas
The California Utilities buy natural gas under several short-term and
long-term contracts. Short-term purchases are from various Southwest
United States 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 for firm pipeline capacity under contracts with pipeline
companies that expire at various dates through 2006. SDG&E has long-
term natural gas transportation contracts with various interstate
pipelines which expire on various dates between 2003 and 2023. SDG&E
has a long-term purchase agreement with a Canadian supplier that
expires in August 2003, and in which the delivered cost is tied to the
California border spot-market price. SDG&E purchases natural gas on a
spot basis to fill its additional long-term pipeline capacity. SDG&E
intends to continue using the long-term pipeline capacity in other ways
as well, including the transport of other natural gas for its own use
and the release of a portion of this capacity to third parties.
Most of the natural gas purchased and delivered by the company is
produced outside of California. These supplies are delivered to the
company's intrastate transmission system by interstate pipeline
companies, primarily El Paso Natural Gas Company and Transwestern
Natural Gas Company. These interstate companies provide transportation
services for supplies purchased from other sources by the company or
its transportation customers. The rates that interstate pipeline
companies may charge for natural gas and transportation services are
regulated by the FERC.
7
The following table shows the sources of natural gas deliveries for the
California Utilities from 1998 through 2002:
<table>
<caption>
Years Ended December 31
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2002 2001 2000 1999 1998
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<s> <c> <c> <c> <c> <c>
Purchases (billions of cubic feet)
Gas purchases - commodity portion 433 420 418 466 492
Customer-owned and
exchange receipts 568 764 699 560 521
Storage withdrawal
(injection) - net 5 (29) 40 (6) (28)
Company use and
unaccounted for (24) (24) (26) (16) (23)
------- ------- ------- ------- -------
Net deliveries 982 1,131 1,131 1,004 962
======= ======= ======= ======= =======
Purchases (millions of dollars)
Commodity costs $1,261 $2,444 $1,469 $1,084 $1,092
Fixed charges* 134 139 143 147 174
------- ------- ------- ------- -------
Total purchases $1,395 $2,583 $1,612 $1,231 $1,266
======= ======= ======= ======= =======
Average commodity cost of purchases
(dollars per thousand cubic feet)** $ 2.91 $ 5.82 $ 3.51 $ 2.33 $ 2.22
======= ======= ======= ======= =======
* Fixed charges primarily include pipeline demand charges, take or pay settlement costs
and other direct-billed amounts allocated over the quantities delivered by the
interstate pipelines serving the California Utilities.
** The average commodity cost of natural gas purchased excludes fixed charges.
</table>
Market-sensitive natural gas supplies (supplies purchased on the spot
market as well as under longer-term contracts, ranging from one month
to two years, based on spot prices) accounted for 100 percent of total
natural gas volumes purchased by the company. The annual average price
of natural gas at the California/Arizona border was $3.14/million
British thermal units (mmbtu) in 2002, compared with $7.27/mmbtu in
2001 and $6.25/mmbtu in 2000. Supply/demand imbalances and a number of
other factors associated with California's energy crisis from late 2000
through early 2001 resulted in higher natural gas prices during that
period. Prices for natural gas decreased in the later part of 2001 and
increased toward the end of 2002. As of December 31, 2002, the average
spot cash price at the California/Arizona border was $4.47/mmbtu. The
cost of gas purchased may vary and can exceed the annual average price.
During 2002, the California Utilities delivered 982 billion cubic feet
(bcf) of natural gas. Approximately 59 percent of these deliveries were
customer-owned natural gas for which the California Utilities provided
transportation services. The remaining natural gas deliveries were
purchased by the California Utilities and resold to customers.
8
Customers
For regulatory purposes, customers are separated into core and noncore
customers. Core customers are primarily residential and small
commercial and industrial customers, without alternative fuel
capability. Noncore customers consist primarily of UEG, wholesale,
large commercial, industrial and off-system (outside the company's
normal service territory) customers. Of the 6.1 million meters in the
California Utilities' service territories, only 1,400 serve the noncore
market.
Most core customers purchase natural gas directly from the California
Utilities. Core customers are permitted to aggregate their natural gas
requirement and, for up to 10 percent of each company's core market, to
purchase natural gas directly from brokers or producers. The CPUC
tentatively authorized the removal of the 10 percent limit, but this
has yet to be implemented. The California Utilities continue to be
obligated to purchase reliable supplies of natural gas to serve the
requirements of its core customers. In early 2002, the California
Utilities filed an application with the CPUC to combine their core
procurement portfolios. On August 22, 2002, the CPUC issued an interim
decision denying the request, pending completion of the CPUC's ongoing
investigation of market power issues.
The CPUC ordered that utility procurement services offered to noncore
customers be phased out sometime in 2003. Noncore customers would have
the option to either become core customers, and continue to receive
utility procurement services, or remain noncore customers and purchase
their natural gas from other sources, such as brokers or producers.
Noncore customers would also have to make arrangements to deliver their
purchases to the California Utilities' receipt points for delivery
through the California Utilities' transmission and distribution system.
The proposed implementation of the order has encountered significant
opposition and the CPUC is reconsidering its decision.
In 2002, for SoCalGas, 85 percent of the CPUC-authorized natural gas
margin was allocated to the core customers, with 15 percent allocated
to the noncore customers. In 2002, for SDG&E, 89 percent of the CPUC-
authorized natural gas margin was allocated to the core customers, with
11 percent allocated to the noncore customers.
Although revenues from transportation throughput is less than for
natural gas sales, the California Utilities generally earn the same
margin whether they buy the natural gas and sell it to the customer or
transport natural gas already owned by the customer.
SoCalGas also provides natural gas storage services for noncore and
off-system customers on a bid and negotiated contract basis. The
storage service program provides opportunities for customers to store
natural gas on an "as available" basis, usually during the summer to
reduce winter purchases when natural gas costs are generally higher. As
of December 31, 2002, SoCalGas was storing approximately 34 bcf of
customer-owned gas.
9
Demand for Natural Gas
Natural gas is a principal energy source for residential, commercial,
industrial and UEG plant customers. Natural gas competes with
electricity for residential and commercial cooking, water heating,
space heating and clothes drying, and with other fuels for large
industrial, commercial and UEG uses. Growth in the natural gas markets
is largely dependent upon the health and expansion of the southern
California economy. The California Utilities added 75,000 and 71,000
new customer meters in 2002 and 2001, respectively, representing a
growth rate of 1.2 percent in both years. The California Utilities
expect that their growth rate for 2003 will approximate that of 2002.
During 2002, 99 percent of residential energy customers in SoCalGas'
service area used natural gas for water heating, 96 percent for space
heating, 76 percent for cooking and 55 percent for clothes drying. In
SDG&E's service area, 90 percent of residential energy customers used
natural gas for water heating, 73 percent for space heating, 54 percent
for cooking and 38 percent for clothes drying.
Demand for natural gas by noncore customers is very sensitive to the
price of competing fuels. Although the number of noncore customers in
2002 was only 1,400, they accounted for approximately 7 percent of the
authorized natural gas revenues and 58 percent of total natural gas
volumes. External factors such as weather, the price of electricity,
electric deregulation, the use of hydroelectric power, competing
pipelines and general economic conditions can result in significant
shifts in demand and market price. The demand for natural gas by large
UEG customers is also greatly affected by the price and availability of
electric power generated in other areas.
Effective March 31, 1998, electric industry restructuring gave
California electric utilities the option of purchasing energy for their
customers from out-of-state producers. As a result, natural gas demand
for electric generation within southern California competes with
electric power generated throughout the western United States. Although
electric industry restructuring has no direct impact on the California
Utilities' natural gas operations, future volumes of natural gas
transported for electric generating plant customers may be
significantly affected to the extent that regulatory changes divert
electricity generation from the California Utilities' service area.
Other
The Pipeline Safety Improvement Act of 2002, which became public law on
December 17, 2002, requires that baseline inspections be completed over
a ten-year period, with 50 percent of the inspections complete at the
end of five years. Related to these inspections and potential
retrofits, the company estimates that it will have $3.3 million in
operating and maintenance expense each year and $23 million in capital
expenditures.
Additional information concerning customer demand and other aspects of
natural gas operations is provided under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in Notes
14 and 15 of the notes to Consolidated Financial Statements in the 2002
Annual Report to Shareholders, which is incorporated by reference.
10
ELECTRIC OPERATIONS
Resource Planning
In 1996, California enacted legislation restructuring California's
investor-owned electric utility industry. The legislation and related
decisions of the CPUC were intended to stimulate competition and
reduce rates.
Supply/demand imbalances and a number of factors resulted in
abnormally high wholesale electric prices beginning in mid-2000, which
caused SDG&E's monthly customer bills to be substantially higher than
normal. These conditions and the resultant abnormally high electric-
commodity prices continued into 2001 resulting in growth of the
undercollection of SDG&E's electricity costs.
In response to these high commodity prices, the California legislature
adopted legislation intended to stabilize the California electric
utility industry and reduce wholesale electric commodity prices. This
resulted in several legislative and regulatory responses, including
California Assembly Bill (AB) 265, enacted in September 2000 and in
effect through December 31, 2002. AB 265 imposed a ceiling of 6.5
cents/kilowatt hour (kWh) on the cost of the electric commodity that
SDG&E could pass on to its small-usage customers on a current basis,
effective retroactive to June 1, 2000. Further actions included the
DWR's purchasing through December 31, 2002 the net short position of
SDG&E (the power needed by SDG&E's customers, other than that provided
by SDG&E's nuclear generating facilities or its previously existing
purchase power contracts). In addition, implementation of some of the
provisions of the Memorandum of Understanding (MOU) entered into by
representatives of California Governor Davis, the DWR, Sempra Energy
and SDG&E resulted in the cessation of growth in the AB 265
undercollection.
Additional information concerning direct access, the MOU and electric-
industry restructuring in general is provided in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Notes 13, 14 and 15 of the notes to Consolidated
Financial Statements in the 2002 Annual Report to Shareholders, which
is incorporated by reference.
Electric Resources
In connection with California's electric-industry restructuring,
beginning March 31, 1998, the California IOUs were obligated to bid
their power supply, including owned generation and purchased-power
contracts, into the PX. The IOUs also were obligated to purchase from
the PX the power that they sell to their customers. In 1999, SDG&E
completed divestiture of its owned generation other than nuclear. An
Independent System Operator (ISO) schedules power transactions and
access to the transmission system. As discussed in Note 13 of the
notes to Consolidated Financial Statements, due to the conditions in
the California electric utility industry, the PX suspended its trading
operations on January 31, 2001.
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As discussed above, the California Legislature passed laws (e.g.,
Assembly Bill X1 in February 2001), authorizing the DWR to enter into
long-term contracts to purchase the portion of power used by SDG&E
customers that is not provided by SDG&E's existing supply through
December 31, 2002. SDG&E's residual net short requirements have been
met by the DWR since February 7, 2001.
In August 2002, SDG&E was granted authority by the CPUC to once again
procure electric power to meet the load requirements of its customers,
effective January 1, 2003. The California Legislature also passed
several laws (e.g., AB 57, Senate Bill (SB) 1078 and SB 1038) which
required that (a) purchases made by SDG&E beginning January 1, 2003
not be subject to hindsight regulatory review, except for contract
administration functions and (b) SDG&E procure at least one percent of
its annual retail energy supply from renewable producers. Each IOU is
directed to procure from renewable sources at least one percent of its
2003 total energy sales and add at least one percent of energy sales
each year thereafter, such that a 20-percent renewable resources
portfolio is achieved by the year 2017.
On September 20, 2002, SDG&E issued a Request for Offer seeking to
purchase a variety of energy products from both renewable and non-
renewable entities. SDG&E did not enter into any contracts with non-
renewable entities but did enter into contracts with 11 renewable
suppliers (for 15 projects) for 237 megawatts (mW) of non-firm power
starting in 2003. On December 5, 2002, the CPUC issued its resolution
approving SDG&E's renewable contract purchases and on December 19,
2003, the CPUC approved SDG&E's 2003 procurement plan. SDG&E has
contracted to procure approximately four percent of its 2003 total
energy sales from renewable sources and, pursuant to the December 2002
CPUC resolution, may credit toward future years' compliance any excess
over its one-percent requirement.
The CPUC also allocated to SDG&E seven of the contracts signed by the
DWR during the energy crisis in 2001. The contracts represent 2,754
mW of capacity available to SDG&E in a combination of must-take and
dispatchable resources. SDG&E will be responsible for scheduling and
dispatching these contracts (where applicable) as well as some
contract administration duties.
12
Based on generating plants in service and purchased-power contracts
currently in place, as of January 31, 2003, the mW of electric power
available to SDG&E are as follows:
Source mW
--------------------------------------------------
San Onofre Nuclear Generating Station (SONGS) 430*
Long-term contracts with other utilities 84
DWR allocated contracts 2,754
Contracts with others 592
-----
Total 3,860
=====
* Net of internal usage
SONGS: SDG&E owns 20 percent of the three nuclear units at SONGS
(located south of San Clemente, California). The cities of Riverside
and Anaheim own a total of 5 percent of Units 2 and 3. Southern
California Edison (Edison) owns the remaining interests and operates
the units.
Unit 1 was removed from service in November 1992 when the CPUC issued
a decision to permanently shut down the unit. At that time SDG&E began
the recovery of its remaining capital investment, with full recovery
completed in April 1996. The unit's spent nuclear fuel has been
removed from the reactor and is stored on-site. In March 1993, the NRC
issued a Possession-Only License for Unit 1, and the unit was placed
in a long-term storage condition in May 1994. In June 1999, the CPUC
granted authority to begin decommissioning Unit 1 and this work is now
in progress.
Units 2 and 3 began commercial operation in August 1983 and April
1984, respectively. SDG&E's share of the capacity is 214 mW of Unit 2
and 216 mW of Unit 3.
During 2002, SDG&E spent $8 million on capital additions and
modifications of Units 2 and 3, and expects to spend $10 million in
2003.
SDG&E deposits funds in external trusts to provide for the
decommissioning of all three units.
Additional information concerning the SONGS units, nuclear
decommissioning and industry restructuring is provided below and in
"Environmental Matters" herein, and in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in
Notes 6, 13, 14 and 15 of the notes to Consolidated Financial
Statements of the 2002 Annual Report to Shareholders, which is
incorporated by reference.
13
Purchased Power: The following table lists contracts with SDG&E's
various suppliers:
Expiration Megawatt
Supplier Date Commitment Source
- ------------------------------------------------------------------
Long-Term Contracts with Other Utilities:
Portland General
Electric (PGE) December 2013 84 Coal
-----
Total 84
=====
Other Contracts:
DWR Allocated Contracts
Williams Energy
Marketing & Trading December 2010 1,875 Gas
Sunrise Power Co. LLC June 2012 560 Gas
Other DWR contracts Various terminations 319 Gas and wind
from 2003 to 2013
-----
2,754
=====
Qualifying Facilities (QFs) --
Applied Energy Inc. November 2019 107 Cogeneration
Yuma Cogeneration May 2024 57 Cogeneration
Goal Line Limited
Partnership February 2025 50 Cogeneration
Other QFs (73) Various terminations 16 Cogeneration
-----
230
Others --
Renewable (15) 5-15 year terms 237 Biomass, bio-gas
starting 2003 and wind
Various (3) December 2003 125 System supply
-----
Total 592
=====
Under the contract with PGE, SDG&E pays a capacity charge plus a
charge based on the amount of energy received. Charges under this
contract are based on PGE's costs, including lease payments, fuel
expenses, operating and maintenance expenses, transmission expenses,
administrative and general expenses, and state and local taxes. Costs
under the contracts with QFs are based on SDG&E's avoided cost.
14
Charges under the remaining contracts, which include renewal contracts
signed in the fourth quarter of 2002, bilateral contracts executed in
2000 and 2001, and the DWR contracts allocated to SDG&E by the CPUC,
are for firm and as-available energy and are based on the amount of
energy received. The prices under these contracts are at the market
value at the time the contracts were negotiated.
Additional information concerning SDG&E's purchased-power contracts is
provided below, and in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note 15 of the
notes to Consolidated Financial Statements in the 2002 Annual Report
to Shareholders, which is incorporated by reference.
Power Pools
SDG&E is a participant in the Western Systems Power Pool, which
includes an electric-power and transmission-rate agreement with
utilities and power agencies located throughout the United States and
Canada. More than 250 investor-owned and municipal utilities, state
and federal power agencies, energy brokers, and power marketers share
power and information in order to increase efficiency and competition
in the bulk power market. Participants are able to make power
transactions on standardized terms that have been pre-approved by
FERC.
Transmission Arrangements
Pacific Intertie (Intertie): The Intertie, consisting of AC and DC
transmission lines, connects the Northwest with SDG&E, Pacific Gas &
Electric (PG&E), Edison and others under an agreement that expires in
July 2007. SDG&E's share of the Intertie is 266 mW.
Southwest Powerlink: SDG&E's 500-kilovolt Southwest Powerlink
transmission line, which is shared with Arizona Public Service Company
and Imperial Irrigation District, extends from Palo Verde, Arizona to
San Diego. SDG&E's share of the line is 970 mW, although it can be
less, depending on specific system conditions.
Mexico Interconnection: Mexico's Baja California Norte system is
connected to SDG&E's system via two 230-kilovolt interconnections with
firm capability of 408 mW in the north to south direction and 800 mW
in the south to north direction.
Due to electric-industry restructuring (see "Transmission Access"
below), the operating rights of SDG&E on these lines have been
transferred to the ISO.
Transmission Access
The FERC has established rules to implement the transmission-access
provisions of the National Energy Policy Act of 1992. These rules
specify FERC-required procedures for others' requests for transmission
service. In October 1997, the FERC approved the California IOUs'
transfer of control of their transmission facilities to the ISO. On
March 31, 1998, operation and control of the transmission lines was
transferred to the ISO. Additional information regarding the ISO and
transmission access is provided below and in "Management's Discussion
15
and Analysis of Financial Condition and Results of Operations" in the
2002 Annual Report to Shareholders, which is incorporated by
reference.
Fuel and Purchased-Power Costs
The following table shows the percentage of each electricity source
used by SDG&E and compares the kilowatt hour cost of nuclear fuel with
the total cost of purchased power:
Percent of kWh Cents per kWh
- ---------------------------------------------------------------
2002 2001 2000 2002 2001 2000
----- ----- ----- ---- ---- ----
Nuclear fuel 23.0 30.1 14.9 0.4 0.5 0.5
Purchased power
and ISO/PX 77.0 69.9 85.1 7.4 9.4 9.7
----- ----- -----
Total 100.0% 100.0% 100.0%
====== ====== ======
The cost of purchased power includes capacity costs as well as the
costs of fuel. The cost of nuclear fuel does not include SDG&E's
capacity costs.
Nuclear Fuel Supply
The nuclear-fuel cycle includes services performed by others under
various contracts through 2008, including mining and milling of
uranium concentrate, conversion of uranium concentrate to uranium
hexafluoride, enrichment services, and fabrication of fuel assemblies.
Spent fuel from SONGS is being stored on site, where storage
capacity will be adequate at least through 2005. Modifications in
fuel storage technology can be implemented to provide on-site
storage capacity for operation through 2022, the expiration date of
the NRC operating license. Pursuant to the Nuclear Waste Policy Act
of 1982, SDG&E entered into a contract with the U.S. Department of
Energy (DOE) for spent-fuel disposal. Under the agreement, the DOE
is responsible for the ultimate disposal of spent fuel. SDG&E pays
a disposal fee of $1.00 per megawatt-hour of net nuclear
generation, or approximately $3 million per year. The DOE projects
it will not begin accepting spent fuel until 2010 at the earliest.
To the extent not currently provided by contract, the availability and
the cost of the various components of the nuclear-fuel cycle for
SDG&E's nuclear facilities cannot be estimated at this time.
Additional information concerning nuclear-fuel costs is provided in
Note 15 of the notes to Consolidated Financial Statements in the 2002
Annual Report to Shareholders, which is incorporated by reference.
16
SEMPRA ENERGY GLOBAL ENTERPRISES
Sempra Energy Global Enterprises (Global) consists of most of the
businesses of Sempra Energy other than the California Utilities, and
serves a broad range of customers' energy needs. Global includes
Sempra Energy Trading, Sempra Energy Resources, Sempra Energy
International (SEI), Sempra Energy Solutions and several smaller
business units. See below for a discussion of each of these business
units.
SEMPRA ENERGY TRADING
Sempra Energy Trading is a full-service trading company that markets
and trades physical and financial commodity products, including
natural gas, power, petroleum products and base metals. SET combines
trading, risk-management and physical commodity expertise to provide
innovative solutions to its customers worldwide.
Earlier this year, SET completed acquisitions that add base
metals trading and warehousing to its business.
For the year ended December 31, 2002, SET recorded net income of $126
million, including an extraordinary gain of $16 million, compared to
net income of $196 million and $155 million in 2001 and 2000,
respectively.
Additional information concerning these and other aspects of SET's
operations is provided under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Notes 1 and 10
of the notes to Consolidated Financial Statements in the 2002 Annual
Report to Shareholders, which is incorporated by reference.
SEMPRA ENERGY RESOURCES
SER develops power plants for the competitive market. In May 2001, SER
entered into a ten-year agreement with the DWR to supply up to 1,900
megawatts of electricity to the state. SER may deliver most of this
electricity from its projected portfolio of plants in the western
United States and Baja California, Mexico. Sales under the contract
comprise more than two-thirds of the projected capacity of these
facilities and the profits therefrom are significant to the company's
ability to increase its earnings.
The company believes that SER's contract prices are just and
reasonable, but has offered to renegotiate certain aspects of the
contract (which would not affect the long-term profitability) in a
manner mutually beneficial to SER and the state. Although the contract
is subject to ongoing litigation and regulatory proceedings, both SER
and the State of California are performing under this contract.
Information concerning the litigation is provided in Note 15 of the
notes to Consolidated Financial Statements of the 2002 Annual Report
to Shareholders, which is incorporated by reference.
On October 31, 2002, SER purchased a 305-megawatt, coal-fired power
plant (renamed Twin Oaks Power) from Texas-New Mexico Power Company
for $120 million. SER has a five-year contract to sell substantially
17
all of the output of the plant. In connection with the acquisition,
SER also assumed a contract which includes annual commitments to
purchase lignite coal either up until an aggregate minimum volume has
been achieved or through 2025.
In February 2001, the company announced plans to construct
Termoelectrica de Mexicali, a $350 million, 600-megawatt power plant
near Mexicali, Mexico. Construction of the power plant began in the
second half of 2001 with completion scheduled for mid-2003.
In December 2000, SER obtained approval from the appropriate state
agencies to construct the Mesquite Power Plant. The plant is expected
to commence commercial operations at 50-percent capacity in June 2003
and at full capacity in January 2004. The project is being financed
via the synthetic lease agreement described in Note 15 of the notes to
Consolidated Financial Statements of the 2002 Annual Report to
Shareholders, which is incorporated by reference.
In December 2000, SER obtained approvals from the appropriate state
agencies to construct the Elk Hills Power Project (Elk Hills). The
plant is expected to commence commercial operations in May 2003.
In mid-2000, El Dorado Energy, a 50/50 partnership between SER and
Reliant Energy Power Generation, completed construction of a $280
million, 440-megawatt merchant power plant near Las Vegas, Nevada.
SER also has contracted for two turbine sets (each consisting of two
gas turbines and one steam turbine), beyond those required for its
plants currently under construction. Six additional sites, two of
which are already permitted, are being evaluated for potential power
plant locations. SER intends to use these turbine sets at two of these
sites.
SER recorded net income of $60 million in 2002, compared to a net loss
of $27 million and net income of $29 million in 2001 and 2000,
respectively.
Additional information concerning these and other aspects of SER's
operations is provided under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Notes 1, 3 and
15 of the notes to Consolidated Financial Statements of the 2002
Annual Report to Shareholders, which is incorporated by reference.
SEMPRA ENERGY INTERNATIONAL
SEI develops, operates and invests in energy-infrastructure systems.
SEI has interests in natural gas and/or electric transmission and
distribution projects in Argentina, Chile, Mexico, Peru and the
eastern United States, and is pursuing other projects, primarily in
Mexico. SEI's interests in utility operations in South America are not
consolidated and, therefore, are not included in these discussions.
In October 2001, Sempra Energy announced its intention to develop a
liquefied natural gas (LNG) receiving terminal on a 300-acre site along
the Pacific Coast, north of Ensenada, Baja California, Mexico. SEI
intends to develop the $400-million facility and related port
18
infrastructure, which will provide one bcf per day of natural gas,
beginning in 2007.
In the third quarter of 2002, SEI completed construction of the 140-
mile Gasoducto Bajanorte Pipeline that connects the Rosarito Pipeline
south of Tijuana, Mexico, with a pipeline being built by PG&E
Corporation that will connect 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
Termoelectrica de Mexicali power plant discussed above. Capacity on
the pipeline is fully subscribed.
In December 1999, Sempra Atlantic Gas (SAG), a subsidiary of SEI, was
awarded a 25-year franchise by the government of Nova Scotia to build
and operate a natural gas distribution system. In September 2001, due
to new conditions required by the government of Nova Scotia, SAG
notified the government that it intended to surrender its natural gas
distribution franchise. SAG recorded an after-tax expense of $25
million in 2001 related to the surrender of the franchise.
Net income for SEI in 2002 was $26 million compared to net income of
$25 million and $33 million for 2001 and 2000, respectively.
Additional information concerning these and other aspects of SEI's
operations is provided under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Notes 3 and 15
of the notes to Consolidated Financial Statements in the 2002 Annual
Report to Shareholders, which is incorporated by reference.
SEMPRA ENERGY SOLUTIONS
SES sells energy commodities and provides integrated energy-related
products and services to commercial, industrial, government and
institutional markets.
In August 2000, SES purchased Connectiv Thermal Systems' 50-percent
interests in Atlantic-Pacific Las Vegas and Atlantic-Pacific Glendale
for $40 million, thereby acquiring full ownership of these companies.
SES recorded net income of $21 million in 2002, compared to net income
of $1 million and a net loss of $14 million in 2001 and 2000,
respectively.
Additional information concerning these and other aspects of SES's
operations is provided under "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Notes 1 and 10
of the notes to Consolidated Financial Statements in the 2002 Annual
Report to Shareholders, which is incorporated by reference.
OTHER OPERATIONS
Sempra Energy Financial (SEF) invests as a limited partner in
affordable-housing properties. SEF's portfolio includes 1,300
properties throughout the United States, including Puerto Rico and the
Virgin Islands. These investments are expected to provide income tax
benefits (primarily from income tax credits) over 10-year periods. SEF
also has invested in a limited partnership that produces synthetic
19
fuel from coal. SEF recorded net income of $36 million for 2002 and
$28 million in each of 2001 and 2000. Whether SEF will invest in
additional properties will depend on Sempra Energy's income-tax
position.
In February 2003, Sempra LNG Corp., a newly created subsidiary of
Global, announced an agreement to acquire the proposed Hackberry, La.,
LNG project from a subsidiary of Dynegy, Inc. Sempra LNG Corp.
initially will pay Dynegy $20 million, with additional payments
contingent on the performance of the project. The project has received
preliminary approval from the FERC and expects a final decision later
this year. If the project is approved, Sempra LNG Corp. will build an
LNG receiving facility capable of processing up to 1.5 bcf per day of
natural gas. The total cost of the project is expected to be about $700
million. The project could begin commercial operations as early as
2007.
RATES AND REGULATION -- CALIFORNIA UTILITIES
Electric Industry Restructuring
A flawed electric-industry restructuring plan, electricity
supply/demand imbalances, and legislative and regulatory responses have
significantly impacted the company's operations. Additional information
on electric-industry restructuring is provided above under "Electric
Operations," in "Management's Discussion and Analysis of Financial
Condition and Results of Operations," and in Note 13 of the notes to
Consolidated Financial Statements in the 2002 Annual Report to
Shareholders, which is incorporated by reference.
Natural Gas Industry Restructuring
The natural gas industry in California experienced an initial phase of
restructuring during the 1980s. In December 2001 the CPUC issued a
decision adopting provisions affecting the structure of the natural gas
industry in California, some of which could introduce additional
volatility into the earnings of the California Utilities and other
market participants. During 2002 the California Utilities filed a
proposed implementation schedule and revised tariffs and rules required
for implementation. However, protests of these compliance filings were
filed, and the CPUC has not yet authorized implementation of most of
the provisions of its decision. Additional information on natural gas
industry restructuring is provided in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in Note
14 of the notes to Consolidated Financial Statements in the 2002 Annual
Report to Shareholders, which is incorporated by reference.
Balancing Accounts
In general, earnings fluctuations from changes in the costs of natural
gas and consumption levels for the majority of natural gas are
eliminated through balancing accounts authorized by the CPUC. As a
result of California's electric restructuring law, overcollections
recorded in the electric balancing accounts were applied to transition
cost recovery, and fluctuations in certain costs and consumption levels
can now affect earnings from electric operations. In addition,
fluctuations in certain costs and consumption levels affect earnings
20
from the California Utilities' natural gas operations. Additional
information on balancing accounts is provided in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 1 of the notes to Consolidated Financial
Statements in the 2002 Annual Report to Shareholders, which is
incorporated by reference.
Biennial Cost Allocation Proceeding (BCAP)
Rates to recover the changes in the cost of natural gas transportation
services are determined in the BCAP. The mechanism in effect through
the end of 2002 largely eliminated the effect on SoCalGas' income of
variances in customer demand and natural gas transportation costs and
is subject to the limitations of the Gas Cost Incentive Mechanism
(GCIM) described below. In December 2002, the CPUC issued a decision
approving 100 percent balancing account treatment for variances between
forecast and actual for SoCalGas' noncore revenues and throughput. The
change eliminates the impact on earnings from any throughput and
revenue variances compared to adopted forecast levels, effective
January 1, 2003. Additional information on the BCAP is provided in Note
14 of the notes to Consolidated Financial Statements in the 2002 Annual
Report to Shareholders, which is incorporated by reference.
Gas Cost Incentive Mechanism
The GCIM is a process SoCalGas uses to evaluate its natural gas
purchases, substantially replacing the previous process of
reasonableness reviews. Additional information on the GCIM is provided
in "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 14 of the notes to Consolidated
Financial Statements in the 2002 Annual Report to Shareholders, which
is incorporated by reference.
Cost of Capital
The authorized cost of capital is determined by an automatic adjustment
mechanism based on changes in certain capital market indices.
Additional information on the California Utilities' cost of capital is
provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Note 14 of the notes to
Consolidated Financial Statements in the 2002 Annual Report to
Shareholders, which is incorporated by reference.
Performance-Based Regulation (PBR)
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. The
three areas that are eligible for PBR rewards 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.
21
Rewards resulting from PBR are not included in the company's earnings
before they are approved by the CPUC. Additional information on the
California Utilities' PBR mechanisms is provided in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 14 of the notes to Consolidated Financial
Statements in the 2002 Annual Report to Shareholders, which is
incorporated by reference.
ENVIRONMENTAL MATTERS
Discussions about environmental issues affecting the company are
included in Note 15 of the 2002 Annual Report to Shareholders, which is
incorporated by reference. The following additional information should
be read in conjunction with those discussions.
Hazardous Substances
In 1994, the CPUC approved the Hazardous Waste Collaborative Memorandum
account, allowing California's IOUs to recover their hazardous waste
cleanup costs, including those related to Superfund sites or similar
sites requiring cleanup. Cleanup costs at sites related to electric
generation were specifically excluded from the collaborative by the
CPUC. Recovery of 90 percent of hazardous waste cleanup costs and
related third-party litigation costs and 70 percent of the related
insurance-litigation expenses is permitted. In addition, the company
has the opportunity to retain a percentage of any insurance recoveries
to offset the 10 percent of costs not recovered in rates.
During the early 1900s, the California Utilities and their predecessors
manufactured gas from coal or oil. The manufacturing sites often have
become contaminated with the hazardous residual by-products of the
process. SoCalGas has identified 42 such sites at which it (together
with other users as to 21 of these sites) may have cleanup obligations.
Preliminary investigations, at a minimum, have been completed on 41 of
the sites. As of December 31, 2002, 22 of these sites have been
remediated, of which 18 have received certification from the California
Environmental Protection Agency (EPA). At December 31, 2002, SoCalGas'
estimated remaining investigation and remediation liability for all of
these sites is $43 million. SDG&E identified three former manufactured-
gas plant sites, remediation of which was completed at two of the sites
in 1998 and 2000. Closure letters have been received for the two sites.
At December 31, 2002 estimated remaining remediation liability on the
third site is $1.5 million.
SDG&E sold its fossil-fuel generating facilities in 1999. As a part of
its due diligence for the sale, SDG&E conducted a thorough
environmental assessment of the facilities. Pursuant to the sale
agreements for such facilities, SDG&E and the buyers have apportioned
responsibility for such environmental conditions generally based on
contamination existing at the time of transfer and the cleanup level
necessary for the continued use of the sites as industrial sites. While
the sites are relatively clean, the assessments identified some
instances of significant contamination, principally resulting from
hydrocarbon releases, for which SDG&E has a cleanup obligation under
the agreement. Estimated costs to perform the necessary remediation are
$11 million. These costs were offset against the sales price for the
facilities, together with other appropriate costs, and the remaining
22
net proceeds were included in the calculation of customer rates.
Remediation of the plants commenced in early 2001. During 2002, cleanup
was completed at several minor sites at a cost of $0.4 million. In late
2002, additional assessments were started at the primary sites, where
cleanup in expected to commence by the end of 2003 and be completed by
2005.
The California Utilities lawfully dispose of wastes at permitted
facilities owned and operated by other entities. Operations at these
facilities may result in actual or threatened risks to the environment
or public health. Under California law, businesses that arrange for
legal disposal of wastes at a permitted facility from which wastes are
later released, or threaten to be released, can be held financially
responsible for corrective actions at the facility.
The company and certain subsidiaries have been named as potentially
responsible parties (PRPs) for two landfill sites and six industrial
waste disposal sites, from which releases have occurred.
Remedial actions and negotiations with other PRPs and the United States
EPA have been in progress since 1986 and 1993 for the two landfill
sites. The company's share of costs to remediate these sites is
estimated to be $0.7 million for the first site and $10.4 million for
the second site. Since 1987, $11.9 million has been spent ($6.5 million
in 2002), including $6.4 million for two consent decrees to settle and
liquidate all remaining liabilities at the second site.
At December 31, 2002, the company's estimated remaining investigation
and remediation liability related to hazardous waste sites, including
the manufactured gas sites, was $45.6 million, of which 90 percent is
authorized to be recovered through the Hazardous Waste Collaborative
mechanism. This estimated cost excludes remediation costs associated
with SDG&E's former fossil-fuel power plants. The company believes that
any costs not ultimately recovered through rates, insurance or other
means will not have a material adverse effect on the company's
consolidated results of operations or financial position.
Estimated liabilities for environmental remediation are recorded when
amounts are probable and estimable. Amounts authorized to be recovered
in rates under the Hazardous Waste Collaborative mechanism are recorded
as a regulatory asset.
Electric and Magnetic Fields (EMFs)
Although scientists continue to research the possibility that exposure
to EMFs causes adverse health effects, science has not demonstrated a
cause-and-effect relationship between exposure to the type of EMFs
emitted by power lines and other electrical facilities and adverse
health effects. Some laboratory studies suggest that such exposure
creates biological effects, but those effects have not been shown to be
harmful. The studies that have most concerned the public are
epidemiological studies, some of which have reported a weak correlation
between the proximity of homes to certain power lines and equipment and
childhood leukemia. Other epidemiological studies found no correlation
between estimated exposure and any disease. Scientists cannot explain
why some studies using estimates of past exposure report correlations
between estimated EMF levels and disease, while others do not.
23
To respond to public concerns, the CPUC has directed California IOUs to
adopt a low-cost EMF-reduction policy that requires reasonable design
changes to achieve noticeable reduction of EMF levels that are
anticipated from new projects. However, consistent with the major
scientific reviews of the available research literature, the CPUC has
indicated that no health risk has been identified.
Air and Water Quality
California's air quality standards are more restrictive than federal
standards. However, as a result of the sale of the company's fossil-
fuel generating facilities, the company's primary air-quality issue,
compliance with these standards now has less significance to the
company's operation, although that will change as SER constructs more
generating facilities.
The transmission and distribution of natural gas require the operation
of compressor stations, which are subject to increasingly stringent
air-quality standards. Costs to comply with these standards are
recovered in rates.
In connection with the issuance of operating permits, SDG&E and the
other owners of SONGS reached agreement with the California Coastal
Commission to mitigate the environmental damage to the marine
environment attributed to the cooling-water discharge from SONGS Units
2 and 3. This mitigation program includes an enhanced fish-protection
system, a 150-acre artificial reef and restoration of 150 acres of
coastal wetlands. In addition, the owners must deposit $3.6 million
with the state for the enhancement of fish hatchery programs and pay
for monitoring and oversight of the mitigation projects. SDG&E's share
of the cost is estimated to be $34.8 million. These mitigation projects
are expected to be completed by 2007. Through December 31, 2003, SONGS
mitigation costs are recovered through the Incremental Cost Incentive
Pricing mechanism. Costs thereafter are anticipated to be recovered in
customer rates.
OTHER MATTERS
Research, Development and Demonstration (RD&D)
The SoCalGas RD&D portfolio is focused in five major areas: operations,
utilization systems, power generation, public interest and
transportation. Each of these activities provides benefits to customers
and society by providing more cost-effective, efficient natural gas
equipment with lower emissions, increased safety, and reduced
environmental mitigation and other operating costs. The CPUC has
authorized SoCalGas to recover its operating costs associated with
RD&D. SoCalGas' annual RD&D costs have averaged $5.9 million over the
past three years.
For 2002, the CPUC authorized SDG&E to fund $1.2 million and $4.0
million for its natural gas and electric RD&D programs, respectively,
which includes $3.9 million to the CEC for its PIER (Public Interest
Energy Research) Program. SDG&E co-funded several of these projects
with the CEC. SDG&E's annual RD&D costs have averaged $4.4 million over
the past three years.
24
Employees of Registrant
As of December 31, 2002 the company had 12,197 employees, compared to
11,511 at December 31, 2001.
Labor Relations
Field, technical and most clerical employees at SoCalGas are
represented by the Utility Workers' Union of America or the
International Chemical Workers' Council. The new collective bargaining
agreement for field, technical and most clerical employees at SoCalGas
has been negotiated. The new agreement on wages, hours and working
conditions is in effect through December 31, 2004, and the agreement
covering medical, dental and vision benefits is in effect through
December 31, 2003. At December 31, 2002, the agreement covering the
pension plan, savings plan and life insurance expired. The company and
the union have agreed to two successive one-month extensions with the
last extension to expire on February 28, 2003. Negotiations are
continuing and an agreement is expected in the next several weeks.
Certain employees at SDG&E are represented by the Local 465
International Brotherhood of Electrical Workers. The current contract
runs through August 31, 2004. At some of its field operations job sites
Sempra Energy Solutions employs facilities mechanics who are
represented by the International Union of Operating Engineers, Local
501. One Collective Bargaining Agreement runs through July 7, 2003 and
another expires on November 1, 2006.
The company has stock-based compensation plans that 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.
25
The following data is as of December 31, 2002.
Number of
additional
securities
Number of Weighted- remaining
securities to average available for
be issued upon exercise future issuance
exercise of price of under equity
outstanding outstanding compensation
options options plans
- -----------------------------------------------------------------------
Equity compensation
plans approved by
security holders:
Officers and key
employees plan 15,601,052 $ 22.15 2,419,851*
Board of directors
Plan 490,000 24.71 1,005,000
------------- ----------------
16,091,052 3,424,851
Equity compensation
plans not approved by
security holders -- -- 8,825,380
------------- ----------------
16,091,052 12,250,231
- -----------------------------------------------------------------------
*Increasing annually by an amount substantially equal to 1.5 percent of
the company's outstanding shares at the beginning of the year.
See additional discussion of stock-based compensation in Note 9 of the
notes to Consolidated Financial Statements of the 2002 Annual Report to
Shareholders, which is incorporated by reference.
26
ITEM 2. PROPERTIES
Electric Properties
SDG&E's generating capacity is described in "Electric Resources"
herein. At December 31, 2002, SDG&E's electric transmission and
distribution facilities included substations, and overhead and
underground lines. The electric facilities are located in San Diego,
Imperial and Orange counties and in Arizona, and consist of 1,802 miles
of transmission lines and 21,095 miles of distribution lines.
Periodically, various areas of the service territory require expansion
to accommodate customer growth.
Natural Gas Properties
At December 31, 2002, the California Utilities' natural gas facilities
included approximately 3,012 miles of transmission and storage
pipeline, 53,798 miles of distribution pipeline and 51,294 miles of
service piping. They also included 13 transmission compressor stations
and 4 underground storage reservoirs, with a combined working capacity
of 118 bcf.
At December 31 2002, SEI's operations in Mexico included 1,092 miles of
distribution pipeline, 163 miles of transmission pipeline and 1
compressor station.
At December 31 2002, the company's two small natural gas utilities
located in the eastern United States owned approximately 166 miles of
transmission lines and 201 miles of distribution lines.
Other Properties
The 21-story corporate headquarters building at 101 Ash Street, San
Diego is occupied pursuant to a capital lease with an original term
through 2005. The lease has four separate five-year renewal options.
SoCalGas has a 15-percent limited partnership interest in a 52-story
office building in downtown Los Angeles. SoCalGas leases approximately
half of the building through 2011. The lease has six separate five-year
renewal options.
SDG&E occupies an office complex in San Diego pursuant to an operating
lease ending in 2007. The lease can be renewed for two five-year
periods.
At December 31, 2002, Sempra Energy had other power plants under
construction in Arizona, California and Mexico. For additional
information, see Note 15 of the notes to Consolidated Financial
Statements of the 2002 Annual Report to Shareholders, which is
incorporated by reference from Item 8 herein.
The company owns or leases other offices, operating and maintenance
centers, shops, service facilities and equipment necessary in the
conduct of its business.
27
ITEM 3. LEGAL PROCEEDINGS
Except for the matters referred to in the financial statements
incorporated by reference in Item 8 or referred to elsewhere in
Management's Discussion and Analysis of Financial Condition and Results
of Operations or the notes to Consolidated Financial Statements
incorporated by reference in this Annual Report, the company is not
party to, nor is its property the subject of, any material pending legal
proceedings other than routine litigation incidental to their
businesses.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS
Common stock of Sempra Energy is traded on the New York and Pacific stock
exchanges. At January 31, 2003, there were 63,000 registered holders of
the company's common stock and a total of 176,000 record holders. The
quarterly common stock information required by Item 5 is included in the
schedule of Quarterly Financial Data of the 2002 Annual Report to
Shareholders, which is incorporated by reference.
ITEM 6. SELECTED FINANCIAL DATA
<table>
<caption>
(Dollars in millions) At December 31, or for the years then ended
- -----------------------------------------------------------------------------------
2002 2001 2000 1999 1998
------- ------- ------- ------- -------
<s> <c> <c> <c> <c> <c>
Income Statement Data:
Operating revenues $ 6,020 $ 7,730 $ 6,760 $ 5,360 $ 4,981
Operating income $ 987 $ 997 $ 884 $ 763 $ 626
Net income $ 591 $ 518 $ 429 $ 394 $ 294
Balance Sheet Data:
Total assets $17,757 $15,080 $15,540 $11,124 $10,456
Long-term debt $ 4,083 $ 3,436 $ 3,268 $ 2,902 $ 2,795
Short-term debt (a) $ 851 $ 1,117 $ 936 $ 337 $ 373
Shareholders' equity $ 2,825 $ 2,692 $ 2,494 $ 2,986 $ 2,913
Per Common Share Data:
Income before extraordinary item
per common share:
Basic $ 2.80 $ 2.54 $ 2.06 $ 1.66 $ 1.24
Diluted $ 2.79 $ 2.52 $ 2.06 $ 1.66 $ 1.24
Net income per common share:
Basic $ 2.88 $ 2.54 $ 2.06 $ 1.66 $ 1.24
Diluted $ 2.87 $ 2.52 $ 2.06 $ 1.66 $ 1.24
Dividends declared $ 1.00 $ 1.00 $ 1.00 $ 1.56 $ 1.56
Book value $ 13.79 $ 13.16 $ 12.35 $ 12.58 $ 12.29
</table>
(a) Includes long-term debt due within one year.
28
This data should be read in conjunction with the Consolidated Financial
Statements and the notes to Consolidated Financial Statements contained
in the 2002 Annual Report to Shareholders, which is incorporated by
reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The information required by Item 7 is incorporated by reference from
pages 1 through 32 of the 2002 Annual Report to Shareholders.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A is incorporated by reference from
pages 27 through 30 of the 2002 Annual Report to Shareholders.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required by Item 8 is incorporated by reference from
pages 36 through 103 of the 2002 Annual Report to Shareholders. Item
15(a)1 includes a listing of financial statements included in the 2002
Annual Report to Shareholders.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURES
None.
29
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required on Identification of Directors is incorporated
by reference from "Election of Directors" in the Proxy Statement
prepared for the May 2003 annual meeting of shareholders. The
information required on the company's executive officers is provided
below.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* Position
- ---------------------------------------------------------------------
Stephen L. Baum 61 Chairman, Chief Executive Officer and
President
Donald E. Felsinger 55 Group President, Sempra Energy Global
Enterprises
Edwin A. Guiles 53 Group President, Sempra Energy
Utilities
John R. Light 61 Executive Vice President and General
Counsel
Neal E. Schmale 56 Executive Vice President and Chief
Financial Officer
Frank H. Ault 58 Senior Vice President and Controller
Frederick E. John 56 Senior Vice President, External
Affairs and Communications
G. Joyce Rowland 48 Senior Vice President, Human Resources
* As of December 31, 2002.
Each Executive Officer has been an officer of the company or one of its
subsidiaries for more than five years, with the exception of Mr. Light.
Prior to joining the company in 1998, Mr. Light was a partner in the
law firm of Latham & Watkins.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference from
"Election of Directors" and "Executive Compensation" in the Proxy
Statement prepared for the May 2003 annual meeting of shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information required by Item 12 is incorporated by reference from
"Share Ownership" in the Proxy Statement prepared for the May 2003
annual meeting of shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
30
ITEM 14. CONTROLS AND PROCEDURES.
The company has designed and maintains disclosure controls and
procedures to ensure that information required to be disclosed in the
company's reports under the Securities Exchange Act of 1934 is
recorded, processed, summarized and reported within the time periods
specified in the rules and forms of the Securities and Exchange
Commission and is accumulated and communicated to the company's
management, including its Chief Executive Officer and Chief Financial
Officer, as appropriate, to allow timely decisions regarding required
disclosure. In designing and evaluating these controls and procedures,
management recognizes that any system of controls and procedures, no
matter how well designed and operated, can provide only reasonable
assurance of achieving the desired objectives and necessarily applies
judgment in evaluating the cost-benefit relationship of other possible
controls and procedures. In addition, the company has investments in
unconsolidated entities that it does not control or manage and,
consequently, its disclosure controls and procedures with respect to
these entities are necessarily substantially more limited than those
it maintains with respect to its consolidated subsidiaries.
Under the supervision and with the participation of management,
including the Chief Executive Officer and the Chief Financial Officer,
the company within 90 days prior to the date of this report has
evaluated the effectiveness of the design and operation of the
company's disclosure controls and procedures. Based on that
evaluation, the company's Chief Executive Officer and Chief Financial
Officer have concluded that the controls and procedures are effective.
There have been no significant changes in the company's internal
controls or in other factors that could significantly affect the
internal controls subsequent to the date the company completed
its evaluation.
31
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial statements
Page in
Annual Report*
Statement of Management Responsibility for
Consolidated Financial Statements. . . . . . . . . . . 34
Independent Auditors' Report . . . . . . . . . . . . . . 35
Statements of Consolidated Income for the years
ended December 31, 2002, 2001 and 2000 . . . . . . . . 37
Consolidated Balance Sheets at December 31,
2002 and 2001. . . . . . . . . . . . . . . . . . . . . 38
Statements of Consolidated Cash Flows for the
years ended December 31, 2002, 2001 and 2000 . . . . . 40
Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2002, 2001 and 2000 . . . . . . . . . . . 42
Notes to Consolidated Financial Statements . . . . . . . 43
*Incorporated by reference from the indicated pages of the 2002
Annual Report to Shareholders.
2. Financial statement schedules
The following document may be found in this report at the indicated
page number.
Schedule I--Condensed Financial Information of Parent. . 35
Any other schedules for which provision is made in Regulation S-X
are not required under the instructions contained therein or are
inapplicable.
32
3. Exhibits
See Exhibit Index on page 38 of this report.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed after September 30, 2002:
Current Report on Form 8-K filed October 25, 2002, filing as an
exhibit Sempra Energy's press release of October 22, 2002, giving the
financial results for the three-month period ended September 30, 2002.
Current Report on Form 8-K filed February 21, 2003, filing as an
exhibit Sempra Energy's press release of February 20, 2003, giving the
financial results for the three-month period ended December 31, 2002.
33
INDEPENDENT AUDITORS' CONSENT AND REPORT ON SCHEDULE
To the Board of Directors and Shareholders of Sempra Energy:
We consent to the incorporation by reference in Registration Statement
Numbers 333-51309, 333-52192, 333-77843 and 333-70640 on Form S-3 and
Registration Statement Numbers 333-56161, 333-50806 and 333-49732 on
Form S-8 of Sempra Energy of our report dated February 14, 2003,
incorporated by reference in this Annual Report on Form 10-K of Sempra
Energy for the year ended December 31, 2002.
Our audits of the financial statements referred to in our
aforementioned report also included the financial statement schedule
of Sempra Energy, listed in Item 15. This financial statement schedule
is the responsibility of the company's management. Our responsibility
is to express an opinion based on our audits. In our opinion, such
financial statement schedule, when considered in relation to the basic
financial statements taken as a whole, presents fairly in all material
respects the information set forth therein.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 25, 2003
34
Schedule I -- CONDENSED FINANCIAL INFORMATION OF PARENT
<table>
SEMPRA ENERGY
Condensed Statements of Income
(Dollars in millions, except per share amounts)
<caption>
For the years ended December 31 2002 2001 2000
-------- -------- --------
<s> <c> <c> <c>
Other income $ 52 $ 52 $ 52
Interest expense (152) (148) (152)
Operating expenses and income tax benefits 24 30 (19)
-------- -------- --------
Loss before subsidiary earnings (76) (66) (119)
Subsidiary earnings before
extraordinary item 651 584 548
-------- -------- --------
Income before extraordinary item 575 518 429
Extraordinary item, net of tax 16 -- --
-------- -------- --------
Net income $ 591 $ 518 $ 429
======== ======== ========
Weighted-average number of shares
outstanding:
Basic 205,003 203,593 208,155
-------- -------- --------
Diluted 206,062 205,338 208,345
-------- -------- --------
Income before extraordinary item
per share of common stock
Basic $ 2.80 $ 2.54 $ 2.06
-------- -------- --------
Diluted $ 2.79 $ 2.52 $ 2.06
======== ======== ========
Net income per share of common stock
Basic $ 2.88 $ 2.54 $ 2.06
-------- -------- --------
Diluted $ 2.87 $ 2.52 $ 2.06
======== ======== ========
</table>
35
<table>
SEMPRA ENERGY
Condensed Balance Sheets
(Dollars in millions)
<caption>
Balance at December 31 2002 2001
-------- --------
<s> <c> <c>
Assets:
Cash and cash equivalents $ 3 $ 72
Due from affiliates 1,786 367
Other current assets 7 9
-------- --------
Total current assets 1,796 448
Investments in subsidiaries 5,003 4,513
Other assets 389 435
-------- --------
Total Assets $ 7,188 $ 5,396
======== ========
Liabilities and Shareholders' Equity:
Dividends payable $ 52 $ 52
Due to affiliates 1,484 693
Other current liabilities 353 145
-------- --------
Total current liabilities 1,889 890
Long-term debt 2,243 1,654
Other long-term liabilities 231 160
Common equity 2,825 2,692
-------- --------
Total Liabilities and Shareholders' Equity $ 7,188 $ 5,396
======== ========
</table>
<table>
Condensed Statements of Cash Flows
(Dollars in millions)
<caption>
For the years ended December 31 2002 2001 2000
-------- -------- --------
<s> <c> <c> <c>
Net cash provided by (used in)
operating activities $ 144 $ (253) $ 74
-------- -------- --------
Dividends received from subsidiaries 100 340 250
Expenditures for property, plant and equipment (12) (35) (58)
Increase in investments and other assets (20) (30) (25)
-------- -------- --------
Cash provided by investing activities 68 275 167
-------- -------- --------
Common stock dividends paid (205) (203) (244)
Repurchase of common stock (16) (1) (725)
Sale of common stock 13 41 12
Issuances of long-term debt 600 581 1,000
Payment on long-term debt (26) (84) (1)
Loans from (payments to) affiliates - net (628) (345) (220)
Other (19) (2) --
-------- -------- --------
Cash used in financing activities (281) (13) (178)
-------- -------- --------
Increase (Decrease) in Cash and Cash Equivalents (69) 9 63
Cash and Cash Equivalents, January 1 72 63 --
-------- -------- --------
Cash and Cash Equivalents, December 31 $ 3 $ 72 $ 63
======== ======== ========
</table>
36
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, hereunto duly authorized.
SEMPRA ENERGY
By: /s/ Stephen L. Baum
Stephen L. Baum
Chairman, Chief Executive Officer
and President
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report is signed below by the following persons on behalf of the
Registrant in the capacities and on the dates indicated.
<table>
<caption>
Name/Title Signature Date
<s> <c> <c>
Principal Executive Officer:
Stephen L. Baum
Chairman, Chief Executive Officer
and President /s/ Stephen L. Baum February 18, 2003
Principal Financial Officer:
Neal E. Schmale
Executive Vice President and
Chief Financial Officer /s/ Neal E. Schmale February 18, 2003
Principal Accounting Officer:
Frank H. Ault
Senior Vice President and
Controller /s/ Frank H. Ault February 18, 2003
Directors:
Stephen L. Baum, Chairman /s/ Stephen L. Baum February 18, 2003
Hyla H. Bertea, Director /s/ Hyla H. Bertea February 18, 2003
James G. Brocksmith, Jr., Director /s/ James G. Brocksmith, Jr. February 18, 2003
Herbert L. Carter, Director /s/ Herbert L. Carter February 18, 2003
Richard A. Collato, Director /s/ Richard A. Collato February 18, 2003
Wilford D. Godbold, Jr., Director /s/ Wilford D. Godbold, Jr. February 18, 2003
William D. Jones, Director /s/ William D. Jones February 18, 2003
Richard G. Newman, Director /s/ Richard G. Newman February 18, 2003
Ralph R. Ocampo, Director /s/ Ralph R. Ocampo February 18, 2003
William G. Ouchi, Director /s/ William G. Ouchi February 18, 2003
William P. Rutledge, Director /s/ William P. Rutledge February 18, 2003
Thomas C. Stickel, Director /s/ Thomas C. Stickel February 18, 2003
Diana L. Walker, Director /s/ Diana L. Walker February 18, 2003
</table>
37
EXHIBIT INDEX
The Forms 8, 8-B/A, 8-K, S-4, 10-K and 10-Q referred to herein were
filed under Commission File Number 1-14201 (Sempra Energy), Commission
File Number 1-40 (Pacific Enterprises), Commission File Number 1-3779
(San Diego Gas & Electric), Commission File Number 1-1402 (Southern
California Gas Company), Commission File Number 1-11439 (Enova
Corporation) and/or Commission File Number 333-30761 (SDG&E Funding
LLC).
3.a The following exhibits relate to Sempra Energy and its subsidiaries
Exhibit 1 -- Underwriting Agreements
Enova Corporation and San Diego Gas & Electric Company
- ------------------------------------------------------
1.01 Underwriting Agreement dated December 4, 1997 (Incorporated by
reference from Form 8-K filed by SDG&E Funding LLC on
December 23, 1997 (Exhibit 1.1)).
Exhibit 3 -- Bylaws and Articles of Incorporation
Bylaws
Sempra Energy
- -------------
3.01 Amended and Restated Bylaws of Sempra Energy effective May 26,
1998 (Incorporated by reference from the Registration Statement
on Form S-8 Sempra Energy Registration No. 333-56161 dated June
5, 1998 (Exhibit 3.2)).
Articles of Incorporation
Sempra Energy
- -------------
3.02 Amended and Restated Articles of Incorporation of Sempra Energy
(Incorporated by reference to the Registration Statement on Form
S-3 File No. 333-51309 dated April 29, 1998, Exhibit 3.1).
Exhibit 4 -- Instruments Defining the Rights of Security Holders,
Including Indentures
The company agrees to furnish a copy of each such instrument to the
Commission upon request.
Enova Corporation and San Diego Gas & Electric Company
- ------------------------------------------------------
4.01 Mortgage and Deed of Trust dated July 1, 1940. (Incorporated
by reference from SDG&E Registration No. 2-49810, Exhibit 2A.)
4.02 Second Supplemental Indenture dated as of March 1, 1948.
(Incorporated by reference from SDG&E Registration No. 2-49810,
Exhibit 2C.)
38
4.03 Ninth Supplemental Indenture dated as of August 1, 1968.
(Incorporated by reference from SDG&E Registration No. 2-68420,
Exhibit 2D.)
4.04 Tenth Supplemental Indenture dated as of December 1, 1968.
(Incorporated by reference from SDG&E Registration No. 2-36042,
Exhibit 2K.)
4.05 Sixteenth Supplemental Indenture dated August 28, 1975.
(Incorporated by reference from SDG&E Registration No. 2-68420,
Exhibit 2E.)
4.06 Thirtieth Supplemental Indenture dated September 28, 1983.
(Incorporated by reference from SDG&E Registration No. 33-34017,
Exhibit 4.3.)
Pacific Enterprises and Southern California Gas
- -----------------------------------------------
4.07 First Mortgage Indenture of Southern California Gas Company to
American Trust Company dated as of October 1, 1940 (Registration
Statement No. 2-4504 filed by Southern California Gas Company on
September 16, 1940; Exhibit B-4).
4.08 Supplemental Indenture of Southern California Gas Company to
American Trust Company dated as of July 1, 1947 (Registration
Statement No. 2-7072 filed by Southern California Gas Company on
March 15, 1947; Exhibit B-5).
4.09 Supplemental Indenture of Southern California Gas Company to
American Trust Company dated as of August 1, 1955 (Registration
Statement No. 2-11997 filed by Pacific Lighting Corporation on
October 26, 1955; Exhibit 4.07).
4.10 Supplemental Indenture of Southern California Gas Company to
American Trust Company dated as of June 1, 1956 (Registration
Statement No. 2-12456 filed by Southern California Gas Company
on April 23, 1956; Exhibit 2.08).
4.11 Supplemental Indenture of Southern California Gas Company to
Wells Fargo Bank, National Association dated as of August 1,
1972 (Registration Statement No. 2-59832 filed by Southern
California Gas Company on September 6, 1977; Exhibit 2.19).
4.12 Supplemental Indenture of Southern California Gas Company to
Wells Fargo Bank, National Association dated as of May 1, 1976
(Registration Statement No. 2-56034 filed by Southern California
Gas Company on April 14, 1976; Exhibit 2.20).
4.13 Supplemental Indenture of Southern California Gas Company to
Wells Fargo Bank, National Association dated as of September 15,
1981 (Pacific Enterprises 1981 Form 10-K; Exhibit 4.25).
4.14 Supplemental Indenture of Southern California Gas Company to
Manufacturers Hanover Trust Company of California, successor to
Wells Fargo Bank, National Association, and Crocker National
Bank as Successor Trustee dated as of May 18, 1984 (Southern
California Gas Company 1984 Form 10-K; Exhibit 4.29).
39
4.15 Supplemental Indenture of Southern California Gas Company to
Bankers Trust Company of California, N.A., successor to Wells
Fargo Bank, National Association dated as of January 15, 1988
(Pacific Enterprises 1987 Form 10-K; Exhibit 4.11).
4.16 Supplemental Indenture of Southern California Gas Company to
First Trust of California, National Association, successor to
Bankers Trust Company of California, N.A. dated as of August 15,
1992 (Registration Statement No. 33-50826 filed by Southern
California Gas Company on August 13, 1992; Exhibit 4.37).
4.17 Supplemental Indenture of Southern California Gas Company to
U.S. Bank, N.A., successor to First Trust of California, N.A.,
dated as of October 1, 2002.
Exhibit 10 -- Material Contracts (Previously filed exhibits are
incorporated by reference from Forms 8-K, S-4, 10-K or
10-Q as referenced below).
Sempra Energy
- -------------
10.01 Energy Purchase Agreement between Sempra Energy Resources and
the California Department of Water Resources, executed
May 4, 2001 (2001 Form 10-K Exhibit 10.01).
10.02 Form of Employment Agreement between Sempra Energy and
Stephen L. Baum (Form 10-Q for the three months ended
September 30, 2002, Exhibit 10.1).
10.03 Amendment to Employment Agreement, effective December 1, 1998.
(Employment agreement, dated as of October 12, 1996 between
Mineral Energy Company and Stephen L. Baum (Enova 8-K filed
October 15, 1996, Exhibit 10.2))
10.04 Form of Employment Agreement between Sempra Energy and
Donald E. Felsinger (Form 10-Q for the three months ended
September 30, 2002, Exhibit 10.2).
10.05 Amendment to Employment Agreement effective December 1, 1998.
(Employment contract, dated as of October 12, 1996 between
Mineral Energy Company and Donald E. Felsinger (Enova 8-K filed
October 15, 1996, Exhibit 10.4))
Enova Corporation and San Diego Gas & Electric Company
- ------------------------------------------------------
10.06 Restated Letter Agreement between San Diego Gas & Electric
Company and the California Department of Water Resources dated
April 5, 2001 (2001 Form 10-K Exhibit 10.04).
10.07 Transition Property Purchase and Sale Agreement dated December
16, 1997 (Incorporated by reference from Form 8-K filed by SDG&E
Funding LLC on December 23, 1997 (Exhibit 10.1)).
10.08 Transition Property Servicing Agreement dated December 16, 1997
(Incorporated by reference from Form 8-K filed by SDG&E Funding
LLC on December 23, 1997 (Exhibit 10.2)).
40
Compensation
Sempra Energy
- -------------
10.09 Sempra Energy Executive Incentive Plan effective January 1,
2003.
10.10 Amended Sempra Energy Retirement Plan for Directors.
10.11 Amended and Restated Sempra Energy Deferred Compensation and
Excess Savings Plan (Form 10-Q for the three months ended
September 30, 2002, Exhibit 10.3).
10.12 Form of Sempra Energy Severance Pay Agreement for Executives
(2001 Form 10-K Exhibit 10.07).
10.13 Sempra Energy Executive Security Bonus Plan effective January 1,
2001 (2001 Form 10-K Exhibit 10.08).
10.14 Sempra Energy Deferred Compensation and Excess Savings Plan
effective January 1, 2000 (2000 Form 10-K Exhibit 10.07).
10.15 Sempra Energy 1998 Long Term Incentive Plan (Incorporated by
reference from the Registration Statement on Form S-8 Sempra
Energy Registration No. 333-56161 dated June 5, 1998 (Exhibit
4.1)).
10.16 Sempra Energy 1998 Non-Employee Directors' Stock Plan
(Incorporated by reference from the Registration Statement on
Form S-8 Sempra Energy Registration No. 333-56161 dated June 5,
1998 (Exhibit 4.2)).
Pacific Enterprises/Southern California Gas Company
- ---------------------------------------------------
10.17 Pacific Enterprises Employee Stock Ownership Plan and Trust
Agreement as amended effective October 1, 1992 (Pacific
Enterprises 1992 Form 10-K Exhibit 10.18).
Financing
Enova Corporation and San Diego Gas & Electric
- ----------------------------------------------
10.18 Loan agreement with the City of Chula Vista in connection
with the issuance of $25 million of Industrial Development
Bonds, dated as of October 1, 1997 (Enova 1997 Form 10-K
Exhibit 10.34).
10.19 Loan agreement with the City of Chula Vista in connection
with the issuance of $38.9 million of Industrial Development
Bonds, dated as of August 1, 1996 (Enova 1996 Form 10-K
Exhibit 10.31).
41
10.20 Loan agreement with the City of Chula Vista in connection
with the issuance of $60 million of Industrial Development
Bonds, dated as of November 1, 1996 (Enova 1996 Form 10-K
Exhibit 10.32).
10.21 Loan agreement with City of San Diego in connection with
the issuance of $57.7 million of Industrial Development
Bonds, dated as of June 1, 1995 (June 30, 1995 SDG&E
Form 10-Q Exhibit 10.3).
10.22 Loan agreement with the City of San Diego in connection with
the issuance of $92.9 million of Industrial Development
Bonds 1993 Series C dated as of July 1, 1993 (June 30, 1993
SDG&E Form 10-Q Exhibit 10.2).
10.23 Loan agreement with the City of San Diego in connection with
the issuance of $70.8 million of Industrial Development Bonds
1993 Series A dated as of April 1, 1993 (March 31, 1993 SDG&E
Form 10-Q Exhibit 10.3).
10.24 Loan agreement with the City of San Diego in connection with
the issuance of $118.6 million of Industrial Development
Bonds dated as of September 1, 1992 (Sept. 30, 1992 SDG&E
Form 10-Q Exhibit 10.1).
10.25 Loan agreement with the City of Chula Vista in connection
with the issuance of $250 million of Industrial Development
Bonds, dated as of December 1, 1992 (1992 SDG&E Form 10-K
Exhibit 10.5).
10.26 Loan agreement with the California Pollution Control Financing
Authority in connection with the issuance of $129.82 million
of Pollution Control Bonds, dated as of June 1, 1996
(Enova 1996 Form 10-K Exhibit 10.41).
10.27 Loan agreement with the California Pollution Control
Financing Authority in connection with the issuance of $60
million of Pollution Control Bonds dated as of June 1, 1993
(June 30, 1993 SDG&E Form 10-Q Exhibit 10.1).
10.28 Loan agreement with the California Pollution Control Financing
Authority, dated as of December 1, 1991, in connection with
the issuance of $14.4 million of Pollution Control Bonds
(1991 SDG&E Form 10-K Exhibit 10.11).
Natural Gas Transportation
Enova Corporation and San Diego Gas & Electric
- ----------------------------------------------
10.29 Amendment to Firm Transportation Service Agreement, dated
December 2, 1996, between Pacific Gas and Electric Company
and San Diego Gas & Electric Company (1997 Enova Corporation
Form 10-K Exhibit 10.58).
42
10.30 Firm Transportation Service Agreement, dated December 31,
1991 between Pacific Gas and Electric Company and San Diego
Gas & Electric Company (1991 SDG&E Form 10-K Exhibit 10.7).
10.31 Firm Transportation Service Agreement, dated October 13, 1994
between Pacific Gas Transmission Company and San Diego Gas
& Electric Company (1997 Enova Corporation Form 10-K Exhibit
10.60).
Nuclear
Enova Corporation and San Diego Gas & Electric
- ----------------------------------------------
10.32 Uranium enrichment services contract between the U.S.
Department of Energy (DOE assigned its rights to the U.S.
Enrichment Corporation, a U.S. government-owned corporation,
on July 1, 1993) and Southern California Edison Company, as
agent for SDG&E and others; Contract DE-SC05-84UEO7541,
dated November 5, 1984, effective June 1, 1984, as amended
(1991 SDG&E Form 10-K Exhibit 10.9).
10.33 Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station,
approved November 25, 1987 (1992 SDG&E Form 10-K Exhibit 10.7).
10.34 Amendment No. 1 to the Qualified CPUC Decommissioning Master
Trust Agreement dated September 22, 1994 (see Exhibit 10.33
herein)(1994 SDG&E Form 10-K Exhibit 10.56).
10.35 Second Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.33 herein)(1994 SDG&E Form 10-K Exhibit 10.57).
10.36 Third Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.33 herein)(1996 SDG&E Form 10-K Exhibit 10.59).
10.37 Fourth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.33 herein)(1996 SDG&E Form 10-K Exhibit 10.60).
10.38 Fifth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generation Station
(see Exhibit 10.33 herein)(1999 SDG&E Form 10-K Exhibit 10.26).
10.39 Sixth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.33 herein)(1999 SDG&E Form 10-K Exhibit 10.27).
43
10.40 Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station,
approved November 25, 1987 (1992 SDG&E Form 10-K Exhibit 10.8).
10.41 First Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.40 herein)(1996 Form 10-K Exhibit 10.62).
10.42 Second Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.40 herein)(1996 Form 10-K Exhibit 10.63).
10.43 Third Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.40 herein)(1999 SDG&E Form 10-K Exhibit 10.31).
10.44 Fourth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Non-Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.40 herein)(1999 SDG&E Form 10-K Exhibit 10.32).
10.45 Second Amended San Onofre Agreement among Southern
California Edison Company, SDG&E, the City of Anaheim and
the City of Riverside, dated February 26, 1987 (1990 SDG&E
Form 10-K Exhibit 10.6).
10.46 U. S. Department of Energy contract for disposal of spent
nuclear fuel and/or high-level radioactive waste, entered
into between the DOE and Southern California Edison Company,
as agent for SDG&E and others; Contract DE-CR01-83NE44418,
dated June 10, 1983 (1988 SDG&E Form 10-K Exhibit 10N).
Exhibit 12 -- Statement re: Computation of Ratios
12.01 Computation of Ratio of Earnings to Combined Fixed Charges
and Preferred Stock Dividends for the years ended December
31, 2002, 2001, 2000, 1999 and 1998.
Exhibit 13 -- Annual Report to Security Holders
13.01 Sempra Energy 2002 Annual Report to Shareholders. (Such report,
except for the portions thereof which are expressly incorporated
by reference in this Annual Report, is furnished for the
information of the Securities and Exchange Commission and is not
to be deemed "filed" as part of this Annual Report).
Exhibit 21 -- Subsidiaries
21.01 Schedule of Significant Subsidiaries at December 31, 2002.
Exhibit 23 -- Independent Auditors' Consent, page 34.
44
GLOSSARY (including terms used in the sections of the 2002 Annual
Report to Shareholders incorporated herein by reference)
AB X1 A California Assembly bill authorizing the
California Department of Water Resources to
purchase energy for California consumers.
AB California Assembly Bill
AFUDC Allowance for Funds Used During Construction
ALJ Administrative Law Judge
BCAP Biennial Cost Allocation Proceeding
Bcf Billion Cubic Feet (of natural gas)
CA/AZ California/Arizona
CEC California Energy Commission
CFTC Commodity Futures Trading Commission
COS Cost of Service
CPUC California Public Utilities Commission
DA Direct Access
DGN Distribuidora de Gas Natural
DOE Department of Energy
DSM Demand Side Management
DWR Department of Water Resources
Edison Southern California Edison Company
EITF Emerging Issues Task Force
Elk Hills Elk Hills Power Plant
EMFs Electric and Magnetic Fields
Energia Chilquinta Energia S.A.
Enova Enova Corporation
ERMG Energy Risk Management Group
EPA Environmental Protection Agency
ESOP Employee Stock Ownership Plan
FASB Financial Accounting Standards Board
45
FERC Federal Energy Regulatory Commission
FIN FASB Interpretation
GCIM Gas Cost Incentive Mechanism
Global Sempra Energy Global Enterprises
ICIP Incremental Cost Incentive Pricing Mechanism
Intertie Pacific Intertie
IOUs Investor-Owned Utilities
ISO Independent System Operator
kWh Kilowatt Hour
LIBOR London Interbank Offer Rate
LIFO Last-in, first-out inventory costing method
LNG Liquefied Natural Gas
Luz Luz del Sur S.A.A.
mmbtu Million British Thermal Units (of natural gas)
MOU Memorandum of Understanding
mW Megawatt
NRC Nuclear Regulatory Commission
Occidental Occidental Energy Ventures Corporation
ORA Office of Ratepayer Advocates
OTC Over the counter
PBR Performance-Based Ratemaking/Regulation
PE Pacific Enterprises
PG&E Pacific Gas and Electric Company
PGA Purchased Gas Balancing Account
PGE Portland General Electric Company
PRP Potentially Responsible Party
PSEG Public Service Enterprise Group
PX Power Exchange
QFs Qualifying Facilities
46
QUIPS Quarterly Income Preferred Securities
RD&D Research, Development and Demonstration
ROE Return on Equity
ROR Rate of Return
S&P Standard & Poor's
SAG Sempra Atlantic Gas
SB California Senate Bill
SDG&E San Diego Gas & Electric Company
SEC Securities and Exchange Commission
SEF Sempra Energy Financial
SEI Sempra Energy International
SER Sempra Energy Resources
SES Sempra Energy Solutions
SET Sempra Energy Trading
SFAS Statement of Financial Accounting Standards
SoCalGas Southern California Gas Company
SONGS San Onofre Nuclear Generating Station
Southwest Powerlink A transmission line connecting San Diego to
Phoenix and intermediate points.
TCBA Transition Cost Balancing Account
TURN The Utility Reform Network
UEG Utility Electric Generation
VaR Value at Risk
47
CERTIFICATIONS
I, Stephen L. Baum, certify that:
1. I have reviewed this Annual Report on Form 10-K of Sempra Energy;
2. Based on my knowledge, this Annual Report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this Annual Report;
3. Based on my knowledge, the financial statements and other financial
information included in this Annual Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this Annual Report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
Annual Report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this Annual Report (the "Evaluation Date"); and
c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in
this Annual Report whether or not there were significant changes in
internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
February 26, 2003
/s/ Stephen L. Baum
Stephen L. Baum
Chief Executive Officer
48
I, Neal E. Schmale, certify that:
1. I have reviewed this Annual Report on Form 10-K of Sempra Energy;
2. Based on my knowledge, this Annual Report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect
to the period covered by this Annual Report;
3. Based on my knowledge, the financial statements and other financial
information included in this Annual Report fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented
in this Annual Report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:
a) designed such disclosure controls and procedures to ensure
that material information relating to the registrant,
including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the
period in which this Annual Report is being prepared;
b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to
the filing date of this Annual Report (the "Evaluation Date");
and
c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures based
on our evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors
and the audit committee of registrant's board of directors (or
persons performing the equivalent function):
a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the
registrant's ability to record, process, summarize and report
financial data and have identified for the registrant's
auditors any material weaknesses in internal controls; and
b) any fraud, whether or not material, that involves management
or other employees who have a significant role in the
registrant's internal controls; and
6. The registrant's other certifying officers and I have indicated in
this Annual Report whether or not there were significant changes in
internal controls or in other factors that could significantly
affect internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.
February 26, 2003
/s/ Neal E. Schmale
Neal E. Schmale
Chief Financial Officer
49