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, 20022003
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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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SAN DIEGO GAS & ELECTRIC COMPANY
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(Exact name of registrant as specified in its charter)
CALIFORNIA 1-3779 95-1184800
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(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.
8326 CENTURY PARK COURT, SAN DIEGO, CALIFORNIA 92123
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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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Preference Stock (Cumulative) American
Without Par Value (except $1.70 and $1.7625 Series)
Cumulative Preferred Stock, $20 Par Value
(except 4.60% Series)
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 ]
Indicate by check mark whether the registrant is an accelerated filer
(as defined in Rule 12b-2 of the Exchange Act). Yes [ X ] No [ ]
Exhibit Index on page 89.88. Glossary on page 94.
Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of January 31, 20032004 was $21.7$24.8 million.
Registrant's common stock outstanding as of January 31, 20032004 was wholly
owned by Enova Corporation.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 20032004 annual
meeting of shareholders are incorporated by reference into Part III.
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TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . .33
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 1916
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 2017
Item 4. Submission of Matters to a Vote of Security Holders. . 2017
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 2017
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 2118
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 2118
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 3933
Item 8. Financial Statements and Supplementary Data. . . . . . 4034
Item 9. Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 8381
Item 9A. Controls and Procedures . . . . . . . . . . . . . . . 82
PART III
Item 10. Directors and Executive Officers of the Registrant . . 8483
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 8483
Item 12. Security Ownership of Certain Beneficial Owners
and Management.Management and related Stockholder Matters. . . . . . . . . . . . . . . . . . . 8584
Item 13. Certain Relationships and Related Transactions . . . . 8584
Item 14. ControlsPrincipal Accountant Fees and Procedures.Services . . . . . . . . . . . . . . . 8584
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 8684
Independent Auditors' Consent . . . . . . . . . . . . . . . . . 8786
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 8887
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 8988
Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 94
Certifications. . . . . . . . . . . . . . . . . . . . . . . . . 96
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INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report contains statements that are not historical fact and
constitute forward-looking statements within the meaning of the Private
Securities Litigation Reform Act of 1995. The words "estimates,"
"believes," "expects," "anticipates," "plans," "intends," "may,"
"could," "would" and "should" or similar expressions, or discussions of
strategy or of plans are intended to identify forward-looking
statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions. Future
results may differ materially from those expressed in these forward-lookingforward-
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 internationalnational 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 pacestatus 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-
lookingforward-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.
PART I
ITEM 1. BUSINESS
Description of Business
A description of San Diego Gas & Electric (SDG&E or the company) is
given in "Management's Discussion and Analysis of Financial Condition
and Results of Operations" herein.
SDG&E's common stock is wholly owned by Enova Corporation, which is a
wholly owned subsidiary of Sempra Energy, a California-based Fortune
500 holding company. The financial statements herein are the
Consolidated Financial Statements of SDG&E and its sole subsidiary,
SDG&E Funding LLC. Sempra Energy also indirectly owns the common stock
of Southern California Gas Company (SoCalGas). SDG&E and SoCalGas are
collectively referred to herein as "the California Utilities."
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Company Website
The company's website address is http://www.sdge.com/ and its parent
company's website address is http://www.sempra.com/investor.htm. The
company makes available free of charge via a hyperlink on its website
to its parent company's 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
Local RegulationRISK FACTORS
The following risk factors and all other information contained in this
report should be considered carefully when evaluating SDG&E. These risk
factors could affect the actual results of SDG&E has electric franchisesand cause such results
to differ materially from those expressed in any forward-looking
statements of, or made by or on behalf of, SDG&E. Other risks and
uncertainties, in addition to those that are described below, may also
impair its business operations. If any of the following risks occurs,
SDG&E's business, cash flows, results of operations and financial
condition could be seriously harmed. These risk factors should be read
in conjunction 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 allowother detailed information concerning SDG&E to locate facilities for the transmission
and distribution of electricity and/or natural gasset
forth in the streetsnotes to Consolidated Financial Statements and other public places.in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" herein.
SDG&E is subject to extensive regulation by state, federal and local
legislation and regulatory authorities, which may adversely affect the
operations, performance and growth of its business.
The franchises do not have fixed terms, except forCPUC, which consists of five commissioners appointed by 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).
California Utility Regulation
The StateGovernor of California Legislature,for staggered six-year terms, regulates SDG&E's
rates and conditions of service, sales of securities, rates 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 (including reasonableness and prudency
reviews) and conducts audits and investigations into various matters
which may, from time to time, passes laws
that regulateresult in disallowances and penalties
adversely affecting earnings and cash flows. The CPUC also regulates
the relationship of utilities with their affiliates and is currently
conducting an investigation into this relationship. Various
proceedings involving the CPUC and relating to SDG&E's operations. For example,rates, costs,
incentive mechanisms, performance-based regulation and affiliate and
holding company rule compliance are discussed in 1996 the legislature
passed an electric industry deregulation bill,notes to
Consolidated Financial Statements and in subsequent years
passed additional bills aimed at addressing problems"Management's Discussion and
Analysis of Financial Condition and Results of Operations" herein.
Periodically SDG&E's rates are approved by the CPUC based on forecasts
of capital and operating costs. If SDG&E's actual capital and
operating costs were to exceed the amount included in its base rates
approved by the CPUC, it would adversely affect earnings and cash
flows.
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, the CPUC adopted
Performance-Based Regulation (PBR) effective in 1994. Under PBR,
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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.
Although SDG&E has received significant PBR rewards in the deregulated
electric industry.past, there
can be no assurance that SDG&E will receive rewards at similar levels
in the future, or at all. Additionally, if SDG&E fails to achieve
certain minimum performance levels established under the PBR
mechanisms, it may be assessed financial disallowances or penalties
which could adversely affect its earnings and cash flows.
The FERC regulates the transmission and wholesale sales of electricity
in interstate commerce, transmission access and other similar matters
involving SDG&E.
SDG&E may be impacted by new regulations, decisions, orders or
interpretations of the CPUC, FERC or other regulatory bodies. New
legislation, regulations, decisions, orders or interpretations could
change how SDG&E operates, could affect its ability to recover its
various costs through rates or adjustment mechanisms, or could require
SDG&E to incur additional expenses.
SDG&E may incur substantial costs and liabilities as a result of its
ownership of nuclear facilities.
SDG&E owns a 20% interest in the San Onofre Nuclear Generating Station
(SONGS), a 2,150 megawatt nuclear generating facility near San
Clemente, California. The Nuclear Regulatory Commission has broad
authority under federal law to impose licensing and safety-related
requirements for the operation of nuclear generation facilities.
SDG&E's ownership interest in SONGS subjects it to the risks of nuclear
generation, which include:
- -- the potential harmful effects on the environment and human
health resulting from the operation of nuclear facilities
and the storage, handling and disposal of radioactive
materials;
- -- limitations on the amounts and types of insurance
commercially available to cover losses that might arise in
connection with nuclear operations; and
- -- uncertainties with respect to the technological and
financial aspects of decommissioning nuclear plants at the
end of their licensed lives.
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SDG&E's future results of operations, cash flows and financial
condition may be materially adversely affected by the outcome of
pending litigation against it.
Lawsuits filed in 2000 and currently consolidated in San Diego Superior
Court seek class-action certification and damages, alleging Sempra
Energy and the California Utilities, along with El Paso Energy Corp.
and several of its affiliates, unlawfully sought to control natural gas
markets. Similar lawsuits have been filed by the Attorneys General of
Arizona and Nevada and by others. Although the California Utilities
expect to prevail in these cases, they have expended or accrued
substantial amounts to pay the costs of defending these claims. If the
plaintiffs in these cases were to prevail in their claims, the future
results of operations, cash flows and financial condition of the
company may be materially adversely affected. In addition, various
other lawsuits are pending against SDG&E and other Sempra Energy
subsidiaries alleging that the legislature enactedcompanies unlawfully manipulated the
electric energy market.
In December 2002, the CPUC approved a lawsettlement with SDG&E allocating
between SDG&E's customers and shareholders the profits from certain
intermediate-term power purchase contracts that SDG&E had entered into
during the early stages of California's electric utility industry
restructuring. As a result of the CPUC's decision, SDG&E recognized
additional after-tax income of $65 million in 1999
addressing2003. The Utility
Consumers' Action Network (UCAN) has appealed the decision and the
California Court of Appeals granted the petition for review.
These proceedings are discussed in the notes to Consolidated Financial
Statements and in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" herein.
SDG&E's cash flows, ability to pay dividends and ability to meet its
debt obligations largely depend on the performance of its utility
operations.
SDG&E's utility operations are its major source of liquidity. SDG&E's
cash flows, ability to meet its obligations to creditors and its
ability to pay dividends on its common stock are largely dependent upon
the sufficiency of utility earnings and cash flows in excess of utility
needs.
Natural disasters, catastrophic accidents or acts of terrorism could
materially adversely affect SDG&E's business, earnings and cash flows.
Like other major industrial facilities, SDG&E's SONGS nuclear facility,
electric transmission facilities, and natural gas industry restructuring.pipelines may be
damaged by natural disasters, catastrophic accidents or acts of
terrorism. Any such incidents could result in severe business
disruptions, significant decreases in revenues and/or significant
additional costs to the company, which could have a material adverse
affect on SDG&E's earnings and cash flows. Given the nature and
location of these facilities, any such incidents also could cause
fires, leaks, explosions, spills or other significant damage to natural
resources and/or property belonging to third parties, or personal
injuries, which could lead to significant claims against the company
and its subsidiaries. Insurance coverage may become unavailable for
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certain of these risks and the insurance proceeds received for any loss
of or damage to any of its facilities, or for any loss of or damage to
natural resources or property or personal injuries caused by its
operations, may be insufficient to cover the company's losses or
liabilities without materially adversely affecting the company's
financial condition, earnings and cash flows.
GOVERNMENT REGULATION
California Utility Regulation
The CPUC, which consists of five commissioners appointed by the
Governor of California for staggered six-year terms, regulates SDG&E's
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.
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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 the CPUC are currently investigating prices charged to the
California investor-owned utilities (IOUs) by various suppliers of
natural gas and electricity. See further discussion in Notes 10 and 11
of the notes to Consolidated Financial Statements herein.
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
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.8
Local Regulation
SDG&E has electric franchises with the two counties and the 26 cities
in its electric service territory, and natural gas franchises with the
one county and the 18 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 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). The franchise agreement with the city of Chula Vista
expired during 2003 but continues on a month-to-month basis and a new
agreement is being negotiated.
Licenses and Permits
SDG&E obtains a number of permits, authorizations and licenses in
connection with the transmission and distribution of natural gas and
electricity. 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.
Other regulatory matters are described in Notes 10 and 11 of the notes
to Consolidated Financial Statements herein.
SOURCES OF REVENUE
Information on this topic is provided in Note 1 of the notes to
Consolidated Financial Statements herein.
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ELECTRIC OPERATIONS
Customers
At December 31, 2003 the company had 1.3 million meters consisting of
1,150,000 residential, 136,000 commercial, 450 industrial, 1,800 street
and highway lighting, 8,000 direct access and 24 off-system. The
company's service area covers 4,100 square miles. The company added
18,000 new customer meters in 2003 and 20,000 in 2002, representing
growth rates of 1.4% and 1.6% respectively.
Resource Planning In 1996, California enacted legislation restructuring California's
investor-owned electric utility industry. The legislationand Power Procurement
SDG&E's resource planning, power procurement and related decisions of the CPUC were intended to stimulate competitionregulatory
matters are discussed below 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 NotesNote
10 11 and 12 of the notes to Consolidated Financial Statements herein.
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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 10 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.
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
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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.
Based on generating plants in service andCPUC-approved purchased-power contracts currently in place
with SDG&E's various suppliers and SDG&E's 20-percent share of a
generating plant, as of JanuaryDecember 31, 2003, the mWsupply of electric power
available to SDG&E areis as follows:
Megawatts (MW)
Generation: SONGS 430
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Purchased power contracts:
Expiration
Supplier Source mW
--------------------------------------------------
San Onofre Nuclear Generating Station (SONGS) 430*date
- -------------------------------------------------------------
Long-term contracts:
Portland General
Electric (PGE) Coal December 2013 84
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DWR-allocated contracts:
Williams Energy
Marketing & Trading Natural gas December 2010 1,875
Sunrise Power Co. LLC Natural gas June 2012 572
Other Natural gas/wind 2004 to 2013 328
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Total 2,775
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Other contracts with other utilities 84
DWR allocatedQualifying Facilities (QFs):
Applied Energy Inc. Cogeneration November 2019 107
Yuma Cogeneration Cogeneration May 2024 57
Goal Line Limited
Partnership Cogeneration February 2025 50
Other (73 contracts) Cogeneration Various 16
Total -----
230
-----
Other contracts 2,754
Contracts with others 592renewable sources:
Various (9 contracts) Bio-gas 5-15 year terms
starting in 2003 28
Various (1 contract) Bio-mass 5 year term
starting in 2003 49
Various (5 contracts) Wind 10-15 year terms
starting in 2003 159
-----
Total 3,860sources 236
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Total generation and contracted 3,755
=====
* NetUnder the contract with PGE, SDG&E pays a capacity charge plus a
charge based on the amount of internal usageenergy received and or PGE's costs.
Costs under the contracts with QFs are based on SDG&E's avoided
cost. Charges under the remaining contracts 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.
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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.
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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 recoveryit down. The storage and decommissioning
of its remaining capital investment, with full recovery
completed in April 1996. The unit'sUnit 1'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 mWMW of Unit 2 and 216
mWMW of Unit 3.
During 2002, SDG&E spent $8 million onhas fully recovered its SONGS capital additions and
modifications of Units 2 and 3, and expects to spend $10 million ininvestment through December
31, 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
4, 10, 11 and 12 of the notes to Consolidated Financial Statements
herein.
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Purchased Power:Nuclear Fuel Supply
The following table listsnuclear-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
is expected to be adequate at least 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 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
Williamsthe U.S. Department of
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
=====(DOE) for spent-fuel disposal. Under the contract with PGE,agreement, the DOE is
responsible for the ultimate disposal of spent fuel. SDG&E pays a
capacity charge plus a charge
based ondisposal fee of $1.00 per megawatt-hour of net nuclear generation, or
$3 million per year. The DOE projects that it will not begin accepting
spent fuel until 2010 at 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
underearliest.
To the extent not currently provided by the contracts, with QFs are based onthe availability
and the cost of the various components of the nuclear-fuel cycle for
SDG&E's avoided cost. Charges
under the remaining contracts, which include renewal contracts signed
in the fourth quarter of 2002, bilateral contracts executed in 2000 and
9
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 arenuclear facilities cannot be estimated at the market value at
the time the contracts were negotiated.this time.
Additional information concerning SDG&E's purchased-power contractsnuclear-fuel costs is provided below, and in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and
Note 12 of the notes to Consolidated Financial Statements herein.
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 250280 investor-owned and municipal utilities, state and
federal power agencies, energy brokers, and power marketers share power11
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.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,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 mWMW in the north to south direction and 800 mWMW 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.Independent System Operator(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,In 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 and Analysis of
Financial Condition and Results of Operations" herein.
10
FuelNATURAL GAS OPERATIONS
Resource Planning and Purchased-Power CostsNatural Gas Procurement and Transportation
SDG&E is engaged in the sale and distribution of natural gas. The
following table shows the percentagecompany's resource planning, natural gas procurement, contractual
commitments and related regulatory matters are discussed below and in
"Management's Discussion and Analysis of each electricity source
used by SDG&EFinancial Condition and
compares the kilowatt hour costResults 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 powerOperations" 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 miningin Notes 11 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 12 of the notes to
Consolidated Financial Statements herein.
11Customers
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 electric generation
(EG), wholesale, large commercial, industrial and enhanced oil recovery
customers.
NATURAL GAS OPERATIONS12
Most core customers purchase natural gas directly from the company.
Core customers are permitted to aggregate their natural gas requirement
and purchase directly from brokers or producers. SDG&E continues to be
obligated to purchase reliable supplies of natural gas to serve the
requirements of the core customers.
Natural Gas Procurement and Transportation
Most of the natural gas purchased and delivered by SDG&E is produced
outside of California, primarily in the southwestern U.S. and Canada.
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
SDG&E buys 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-
marketspot-market prices. SDG&E transports natural gas under long-term firm
pipeline capacity agreements that provide for annual reservation
charges, which are recovered in rates.
SDG&E has long-term natural gas transportation contracts with various
interstate pipelines which expire on various dates between 2003 andthrough 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&Ecurrently 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 gasand purchases additional spot market supplies
delivered directly to California for its own use andremaining requirements. SDG&E
continues to evaluate its long-term pipeline capacity portfolio,
including 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
pipeline owned by SoCalGas at the California border 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.
All of SDG&E's natural gas is delivered through SoCalGas pipelines
under a short-term transportation agreement.agreement authorized by the CPUC. In
addition, under a separate agreement expiring in March 2003,2005, SoCalGas
provides SDG&E 4.5 billion cubic feet8 bcf of storage capacity. An agreement is expectedinventory capacity with firm injection
and withdrawal rights.
According to be completed with SoCalGas that
will extend storage services through March 2004.
12
The following table shows"Btu's Daily Gas Wire," the sources of natural gas deliveries from
1998 through 2002.
Years Ended December 31
------------------------------------------
2002 2001 2000 1999 1998
- -----------------------------------------------------------------------------------
Gas purchases (billions of
cubic feet) 54 53 58 75 118
Customer-owned and
exchange receipts 90 104 85 47 19
Storage withdrawal
(injection) - net 2 (2) 1 4 (3)
Company use and
unaccounted for (6) -- (5) -- (2)
------- ------- ------- ------- ------
Net deliveries 140 155 139 126 132
======= ======= ======= ======= ======
Cost of gas purchased*
(millions of dollars) $ 182 $ 482 $ 277 $ 205 $ 327
------- ------- ------- ------- ------
Average Commodity Cost of Purchases
(dollars per thousand cubic feet) $3.37 $9.09 $4.77 $2.73 $2.77
======= ======= ======= ======= =======
* Includes interstate pipeline demand charges
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 nearly all of total
natural gas volumes purchased by the company. The annual average spot price of
natural gas at the California/Arizona border was $3.14/$5.10 per million
British thermal unitsunit (mmbtu) in 2002,2003 ($5.59 in December 2003), compared
with $7.27/$3.14 per mmbtu in 20012002 and $6.25/$7.27 per mmbtu in 2000. Supply/demand imbalances and a2001. 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 and in 2003. The following table
summarizes 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 company delivered 140 billion cubic feet (bcf) of
natural gas. Approximately 64 percent of these deliveries were
customer-owned natural gas for which the company provided
transportation services. The remaining natural gas deliveries were
purchased by the company and resold to customers.
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 utility electric
generating (UEG) plants, wholesale purchasers, and large commercial and
industrial customers. As of December 31, 2002, SDG&E had 789,000 core
customers (760,000 residential and 29,000 small commercial and
industrial) and 100 noncore customers.
13
Most core customers purchase natural gas directly from the company.
Core customers are permitted to aggregate their natural gas requirement
and, for up to 10 percent of the 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. SDG&E continues to be obligated to purchase reliable
suppliescommodity costs of natural gas to servesold for the requirementslast
three years, which are above previous levels:
Years ended December 31,
-----------------------------------
2003 2002 2001
-----------------------------------
Cost 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 company's receipt points for delivery through the
company's transmission and distribution system. The proposed
implementation$ 274 $ 205 $ 457
Volumes delivered (bcf) 49 50 52
Average cost of the order has encountered significant opposition and
the CPUC is reconsidering its decision.
In 2002, 89 percent of the CPUC-authorized natural gas
margin was
allocated(dollars per bcf) $ 5.59 $ 4.10 $ 8.79
With improved delivery capacity to California, the core customers, with 11 percent allocatedcompany expects
adequate resources to the
noncore customers.
Although revenues from transportation throughput is less than forbe available at prices that generally will follow
national natural gas sales, the company generally earns the same margin whether
the company buys the natural gaspricing trends and sells it to the customer or
transports natural gas already owned by the customer.volatility.
Demand for Natural Gas
Natural gas is a principal energy source for residential, commercial,
industrial and UEG plant customers. Natural gas competes with
electricity forSDG&E faces competition in the residential and commercial cooking, water heating,
space heating and clothes drying, and with other fuels for large
industrial, commercial and UEG uses. Growth incustomer
markets based on the natural gas markets
is largely dependent upon the health and expansion of the southern
California economy. The company added 14,000 and 12,000 new customer
meters in 2002 and 2001, respectively, representing growth rates of 1.8
percent and 1.6 percent, respectively. The company expects that its
growth rate for 2003 will approximate that of 2002.
During 2002, 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.
Demandcustomers' preferences 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 100 they accounted for approximately 6 percent of the
authorized natural gas revenues and 63 percent of total natural gas
volumes. External factors such as weather, the price of electricity,
electric deregulation, the use of hydroelectric power, competing
14
pipelines and general economic conditions can result in significant
shifts in demand and market price.compared
with other energy products. The demand for natural gas by large
UEG customerselectric
generators is influenced by a number of factors. In the short-term,
13
natural gas use by EGs is impacted by the availability of alternative
sources of generation. The availability of hydroelectricity is highly
dependent on precipitation in the western United States. In addition,
natural gas use is impacted by the performance of other generation
sources in the western United States, including nuclear and coal, and
other natural gas facilities outside the service area. Natural gas use
is also impacted by changes in end-use electricity demand. For
example, natural gas use generally increases during summer heat waves.
Over the long-term, natural gas use will be greatly affectedinfluenced by
additional factors such as the price and availabilitylocation of electricnew power generated in other areas.plant
construction. More generation capacity currently is being constructed
outside Southern California than within the utility service area. This
new generation will likely displace the output of older, less efficient
local generation, reducing EG natural gas use.
Effective March 31, 1998, electric industry restructuring gave
California electric utilitiesprovided out-
of-state producers the option of purchasingto purchase energy for their
customers from out-of-state producers.California utility
customers. As a result, natural gas demand for electric generation
within southernSouthern California competes with electric power generated
throughout the western United States. Although electric industry
restructuring has no direct impact on the company'sSDG&E's 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 electricityelectric generation from SDG&E's service area.
Growth in the natural gas markets is largely dependent upon the health
and expansion of the Southern California economy and prices of other
energy products. 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 company added 11,000
and 14,000 new customer meters in 2003 and 2002, respectively,
representing growth rates of 1.4 percent and 1.8 percent, respectively.
The company expects that its growth rate for 2004 will approximate that
for 2003.
In the interruptible industrial market, customers are capable of
burning a fuel other than natural gas. Fuel oil is the most
significant competing energy alternative. The company's ability to
maintain its industrial market share is largely dependent on price.
The relationship between natural gas supply and demand has the greatest
impact on the price of the company's 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 ofproduct. With the inspections complete at the
end of five years. Related to these inspections and potential
retrofits, the company estimates that it will have $0.5 million in
operating and maintenance expense each year.
Additional information concerning customer demand and other aspectsreduction of
natural gas operationsproduction from domestic sources, the cost of natural gas
from non-domestic sources may play a greater role in the company's
competitive position in the future. The price of oil depends upon a
number of factors beyond the company's control, including the
relationship between supply and demand, and policies of foreign and
domestic governments.
The natural gas distribution business is provided under "Management's Discussion and
Analysis of Financial Condition and Results of Operations" andseasonal in Notes
11 and 12 ofnature as
variations in weather conditions generally result in greater revenues
during the notes to Consolidated Financial Statements herein.winter months when temperatures are colder. As is prevalent
in the industry, the company injects natural gas into storage during
the summer months (usually April through October) for withdrawal
storage during the winter months (usually November through March) when
customer demand is higher.
14
RATES AND REGULATION
Electric Industry Restructuring
A flawed electric-industry restructuring plan, electricity
supply/demand imbalances,Information concerning rates and legislative and regulatory responses have
significantly impactedregulations applicable to 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 10 of the notes to
Consolidated Financial Statements herein.
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 SDG&E 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 restructuringcompany
is provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in NoteNotes 1, 10 and 11 of the
notes to Consolidated Financial Statements herein.
15
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
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 herein.
Biennial Cost Allocation Proceeding (BCAP)
Rates to recover the changes in the cost of natural gas transportation
services are determined in the BCAP. Additional information on the BCAP
is provided in Note 11 of the notes to Consolidated Financial
Statements herein.
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 SDG&E's cost of capital is provided in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 11 of the notes to Consolidated
Financial Statements herein.
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. PBR has resulted in modification to
the general rate case and certain other regulatory proceedings for
SDG&E. 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.
Rewards resulting from PBR are not included in the company's earnings
before they are approved by the CPUC. Additional information on SDG&E's
PBR mechanism is provided in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and in Note 11 of the
notes to Consolidated Financial Statements herein.
16
ENVIRONMENTAL MATTERS
Discussions about environmental issues affecting the company are
included in Note 12 of the notes to Consolidated Financial Statements
herein. 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.
Cleanup costs at sites related to electric generation were specifically
excluded from the collaborative by the CPUC.
During the early 1900s, SDG&E and its predecessors manufactured gas
from coal or oil. The manufacturing sitesmanufactured-gas plants (MGPs) often have
become contaminated with the hazardous residual by-productsresidues of the process. SDG&E
identified three former manufactured-gas plant sites,MGPs, 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, 20022003 estimated remaining
remediation liability on the third site is $1.5$5.8 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. EstimatedTotal costs to perform the necessary remediation arewere
estimated at $11 million.million at the time of sale. These costs were offset
against the sales price for the facilities, together with other
appropriate costs, and the remaining 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 commenced in 2003 and is expected to commence by the end of 2003 and be completed by 2005. In
2003, at a cost of $0.8 million, cleanup was completed at the site of
a power plant that was sold in 1999. Remaining costs to remediate
these sites are estimated at $8 million at December 31, 2003.
15
SDG&E lawfully disposes 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.
17
At December 31, 2002,2003, the company's estimated remaining investigation
and remediation liability related to hazardous waste sites, including
the manufactured gas sites,MGPs, was $3$6.8 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.
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.
The transmission and distribution of natural gas require the operation
of compressor stations, which are subject to increasingly stringent
16
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 previously 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 kelp reef and restoration of 150 acres of
18
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$34.0 million. These mitigation projects
are expected to be completed byin 2007. Through December 31, 2003, SONGS
mitigation costs arewere recovered through the Incremental Cost Incentive
PricingICIP mechanism. Costs thereafter are anticipatedSONGS
mitigation costs incurred after December 31, 2003, will be capitalized
and recovered from ratepayers over the remaining life of the SONGS
units, subject to be recoveredCPUC approval in customer rates.Edison's general rate case.
Additional information on SONGS cost recovery is provided in Note 10 of
the notes to Consolidated Financial Statements herein.
OTHER MATTERS
Research, Development and Demonstration (RD&D)
For 2002,2003, the CPUC authorized SDG&E to fund $1.2 million and $4.0$5.6
million for its natural gas and electric RD&D programs, respectively,
which includes $3.9including $5.6 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$5.7 million
over the past three years.
Employees of Registrant
As of December 31, 20022003 the company had 4,1304,441 employees, compared to
3,1064,130 at December 31, 2001. The increase is due to transferring certain
central functions for SDG&E and its affiliate, SoCalGas, from Sempra
Energy to SDG&E effective April 1, 2002.
Labor Relations
Certain employees at SDG&E are represented by the Local 465
International Brotherhood of Electrical Workers. The current contract
runs through August 31, 2004.
ITEM 2. PROPERTIES
Electric Properties
SDG&E's generating capacityinterest in SONGS is described in "Electric Resources" herein.
At December 31, 2002,2003, 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 1,8021,805 miles of transmission
lines and 21,09521,353 miles of distribution lines. Periodically, various
areas of the service territory require expansion to accommodate
customer growth.
17
Natural Gas Properties
At December 31, 2002,2003, SDG&E's natural gas facilities, which are located
in San Diego and Riverside counties, consisted of the Moreno and
Rainbow compressor stations, 166 miles of high pressure transmission
pipelines, 7,6177,806 miles of high and low pressure distribution mains, and
6,0796,094 miles of service lines.
19
Other Properties
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.
SDG&EThe company owns or leases other offices, operating and maintenance
centers, shops, service facilities and equipment necessary in the
conduct of its business.
ITEM 3. LEGAL PROCEEDINGS
Except for the matters described in Note 12 of the notes to
Consolidated Financial Statements or referred to elsewhere in this
Annual Report, neither the company nor its subsidiary areis party to, nor
is their 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
All of the issued and outstanding common stock of SDG&E is owned by
Enova Corporation, a wholly owned subsidiary of Sempra Energy. The
information required by Item 5 concerning dividends declared is
included in the "Statements of Consolidated Changes in Shareholders'
Equity" set forth in Item 8 of this Annual Report herein.
20
18
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in millions) At December 31, or for the years then ended
- -----------------------------------------------------------------------------------
2003 2002 2001 2000 1999 1998
------ ------ ------ ------ ------
Income Statement Data:
Operating revenues $ 1,6962,311 $ 1,725 $ 2,362 $ 2,671 $ 2,207
$ 2,249
Operating income $ 381 $ 262 $ 221 $ 235 $ 281 $ 286
Dividends on preferred stock $ 6 $ 6 $ 6 $ 6 $ 6
Earnings applicable to
common shares $ 334 $ 203 $ 177 $ 145 $ 193
$ 185
Balance Sheet Data:
Total assets $ 5,1236,463 $ 5,3996,285 $ 4,7346,542 $ 4,3665,843 $ 4,2575,427
Long-term debt $ 1,087 $ 1,153 $ 1,229 $ 1,281 $ 1,418
$ 1,548
Short-term debt (a) $ 66 $ 66 $ 93 $ 66 $ 66
$ 72
Preferred stock subject to
mandatory redemption (b) $ 25-- $ 25 $ 25 $ 25 $ 25
Shareholders' equity $ 1,343 $ 1,223 $ 1,165 $ 1,138 $ 1,393
$ 1,203
(a) Includes long-term debt due within one year.
(b) At December 31, 2003, $21 million of mandatorily redeemable
preferred stock was reclassified to Deferred Credits and Other
Liabilities and $3 million was reclassified to Other Current
Liabilities.
Since San Diego Gas & Electric CompanySDG&E is a wholly owned subsidiary of Enova Corporation, per
share data is not provided.
This data should be read in conjunction with the Consolidated
Financial Statements and the notes to Consolidated Financial
Statements contained herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
INTRODUCTION
This section includes management's discussion and analysis of operating
results from 20002001 through 2002,2003, and provides information about the
capital resources, liquidity and financial performance of San Diego Gas
& Electric (SDG&E or the company). This section also focuses on the
major factors expected to influence future operating results and
discusses investment and financing activities and plans. It should be
read in conjunction with the Consolidated Financial Statements included
herein.in this Financial Report.
The company is an operating public utility engaged in the electric and
natural gas businesses, whichand provides services to 3.13.2 million customers.consumers.
It distributes electric energy, purchased from others or generated from
its 20 percent interest in a nuclear facility, through 1.3 million
electric meters in San Diego County and an adjacent portion of southern
Orange County, California. It also purchases and distributes natural
gas through 789,000800,000 meters in San Diego County and 21transports
transports19
electricity and natural gas for others. SDG&E's service area
encompasses 4,100 square miles, covering 26 cities. SDG&E's only
subsidiary is SDG&E Funding LLC, which was formed to facilitate the
issuance of SDG&E's rate reduction bonds described in Note 3 of the
notes to Consolidated Financial Statements. Business Combination
Sempra Energy (the Parent) was formed to serve as a holding company for
Pacific Enterprises (PE), the parent corporation ofSDG&E and an affiliate,
Southern California Gas Company (SoCalGas), and Enova Corporation (Enova), the parent
corporation of SDG&E, in a tax-free business combination that became
effective on June 26, 1998.are collectively referred
to herein as "the California Utilities."
RESULTS OF OPERATIONS
2003 was a successful year for the company. Net income was $340
million, a company record. This is discussed further in the following
pages.
The following chart shows net income for each of the last five years.
(Dollars in millions)
-------------------------------
Net Income
-------------
2003 $ 340
2002 $ 209
2001 $ 183
2000 $ 151
1999 $ 199
To understand the operations and financial results of the company, it
is important to understand the ratemaking procedures applicable to which the
company.
The company is subject.
SDG&Esubject to various regulatory bodies and rules at the
national, state and local levels. The primary California body is regulated primarily by the
California Public Utilities Commission (CPUC), which regulates utility
rates and operations. The primary national bodies are the Federal
Energy Regulatory Commission (FERC) and the Nuclear Regulatory
Commission (NRC). It isThe FERC regulates interstate transportation of
natural gas and electricity and various related matters. The NRC
regulates nuclear generating plants. Local regulators and
municipalities govern the responsibilityplacement of utility assets, including
natural gas pipelines and electric lines.
California's electric utility industry was significantly affected by
California's restructuring of the CPUC to regulate
investor-owned utilities (IOUs)industry during 2000-2001. Beginning
in a manner that serves the best
interests of their customers while providing the IOUs the opportunity
to earn a reasonable return on investment.
In 1996, California enacted legislation restructuring California's
electric industry. The legislationmid-2000 and related decisions of the CPUC
were intended to stimulate competition and reduce electric rates. As
part of the framework for a competitive electric-generation market, the
legislation established the California Power Exchange (PX) and the
Independent System Operator (ISO). The PX served as a wholesale power
pool and the ISO scheduled power transactions and access to the
electric transmission system. Supply/continuing into 2001, supply/demand imbalances and a
number of other factors resulted in abnormally high electric commodity
costs, beginning in mid-2000leading to several legislative and continuing into 2001. Due to subsequent
industry restructuring developments,regulatory responses,
including a ceiling imposed on the PX suspended its trading
operations in January 2001. As a resultcost of the passageelectric commodity that
SDG&E could pass on to its small-usage customers. To obtain adequate
supplies of Assembly
Bill (AB) X1electricity, beginning in February 2001 the California Department of Water and Resources (DWR) began to purchase power from generators and marketers
to supply a portion of the power requirements of the state's population
that is served by IOUs. Throughcontinuing
through December 31, 2002, the DWR wasDepartment of Water Resources (DWR)
began purchasing SDG&E'spower to fulfill the full net short position (the power needed by SDG&E'sof the
investor-owned utilities (IOUs), consisting of all electricity
requirements of the IOUs' customers other than that provided by SDG&E's nucleartheir
existing generating facilities or itstheir previously existing purchasedpurchased-
power contracts).
Startingcontracts.
20
Beginning on January 1, 2003, SDG&E and the other IOUs resumed their
electric commodity procurement function based on afunction. In addition, the CPUC
decision issuedestablished the allocation of the power purchased by the DWR under
long-term contracts for the IOUs' customers and the related cost
responsibility among the IOUs for that power. This is discussed further
in October 2002.Note 10 of the notes to Consolidated Financial Statements.
The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore
customers. In December 2001, the CPUC issued a decision related to
natural gas industry restructuring, adopting several provisions that
the company believes will make natural gas service more reliable, more
efficient and better tailored to the desires of customers. The CPUC
anticipated implementation during 2002; however, implementation has
been delayed.
22
In connection with restructuringRestructuring is again being considered, as discussed in
Note 11 of the electric and natural gas
industries, the company received approval from the CPUC for
Performance-Based Ratemaking (PBR). Under PBR, income potential is tiednotes to achieving or exceeding specific performance and productivity
measures, such as service, safety, reliability, demand side management
and customer growth, rather than solely to expanding utility plant.Consolidated Financial Statements.
See additional discussion of these situationsmatters under "Factors Influencing
Future Performance" and in Notes 10 and 11 of the notes to Consolidated
Financial Statements.
The tables summarize the components of electric and natural gas volumes
and revenues by customer class.
ELECTRIC TRANSMISSION AND DISTRIBUTION
(Dollars in millions, volumes in million kWhs)
for the years ended December 31
2002 2001 2000
-----------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
-----------------------------------------------------------------------
Residential 6,266 $ 649 6,011 $ 775 6,304 $ 730
Commercial 6,053 633 6,107 753 6,123 747
Industrial 1,893 161 2,792 325 2,614 310
Direct access 3,448 117 2,464 84 3,308 99
Street and highway lighting 88 9 89 10 74 7
Off-system sales 5 -- 413 88 899 59
----------------------------------------------------------------------
17,753 1,569 17,876 2,035 19,322 1,952
Balancing and other (295) (359) 232
-----------------------------------------------------------------------
Total 17,753 $1,274 17,876 $1,676 19,322 $2,184
-----------------------------------------------------------------------
Although commodity-related revenues from the DWR's purchasing of the
company's net short position are not included in revenue, the
associated volumes and distribution revenue are included herein.
23
NATURAL GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
for the years ended December 31
Natural Gas Sales Transportation & Exchange Total
----------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
----------------------------------------------------------------------
2002:
Residential 33 $ 246 -- $ 1 33 $ 247
Commercial and industrial 17 98 5 15 22 113
Electric generation plants -- -- 85 16 85 16
---------------------------------------------------------------
50 $ 344 90 $ 32 140 376
Balancing accounts and other 46
--------
Total $ 422
- ---------------------------------------------------------------------------------------------
2001:
Residential 34 $ 461 -- $ -- 34 $ 461
Commercial and industrial 18 233 4 18 22 251
Electric generation plants -- -- 99 23 99 23
---------------------------------------------------------------
52 $ 694 103 $ 41 155 735
Balancing accounts and other (49)
--------
Total $ 686
- ---------------------------------------------------------------------------------------------
2000:
Residential 33 $ 279 -- $ 1 33 $ 280
Commercial and industrial 21 139 22 16 43 155
Electric generation plants -- -- 63 24 63 24
---------------------------------------------------------------
54 $ 418 85 $ 41 139 459
Balancing accounts and other 28
--------
Total $ 487
- ---------------------------------------------------------------------------------------------
2002 Compared to 2001
Electric Revenue and Cost of Electric Fuel and Purchased Power.
Electric revenues increased to $1.8 billion in 2003 from $1.3 billion
in 2002, and the cost of electric fuel and purchased power increased to
$0.5 billion in 2003 from $0.3 billion in 2002. Additionally, for the
fourth quarter electric revenues increased to $424 million in 2003 from
$332 million in 2002, and the cost of electric fuel and purchased power
increased to $113 million in 2003 from $76 million in 2002. These
changes were attributable to several factors, including the effect of
the DWR's purchasing the net short position of SDG&E during 2002,
higher electric commodity costs and volumes in 2003, and the increase
in authorized 2003 distribution revenue. In addition, the increase in
revenue was due to the recognition of $116 million related to the
approved settlement of intermediate-term purchase power contracts and
higher PBR awards during the third quarter or 2003. See discussion of
performance awards in Note 11 of the notes to Consolidated Financial
Statements.
Electric revenues decreased to $1.3 billion in 2002 from $1.7 billion
in 2001, and the cost of electric fuel and purchased power decreased to
$0.3 billion in 2002 from $0.8 billion in 2001. These decreases were
primarily due to the DWR's purchases ofpurchasing SDG&E's net short position for a
full year in 2002 and the effect of lower electric commodity costs and
decreased off-system sales. Under the current regulatory framework,
changes in commodity costs normally do not affect net income. The
commodity costs associated with the DWR's purchases and the
corresponding sale to SDG&E's customers are not included in the
Statements of Consolidated Income as SDG&E was merely transmitting the
electricity from the DWR to the customers. Similarly, in 2001, PX/ISO
power revenues have been netted against purchased-power expense to
avoid double counting as SDG&E sold power to the PX/ISO and then
purchased power therefrom.
For the fourth quarter, electric revenues
increased to $324$332 million in 2002 from $284 million in 2001, and the
cost of electric fuel and purchased power decreased to $76 million in
2002 from $87 million in 2001. The increase in electric revenues was
due primarily to higher electric distribution and transmission revenue
resulting from increased volumes, as well as additional
24
revenues from
the Incremental Cost Incentive Pricing (ICIP) mechanism, while the
decrease in cost of electric fuel and purchased power was due primarily
to a decrease in average electric commodity costs. Refer to Note 10 of
the notes to Consolidated Financial Statements for further discussion
of ICIP and the San Onofre Nuclear Generating Station (SONGS).
Natural Gas Revenue and Cost of Gas Distributed.Natural Gas. Natural gas revenues
increased to $509 million in 2003 from $431 million in 2002, and the
cost of natural gas increased to $274 million in 2003 from $205 million
in 2002. Additionally, natural gas revenues increased to $138 million
for the three months ended December 31, 2003 from $122 million for the
corresponding period in 2002, and the cost of natural gas increased to
$75 million in 2003 from $56 million in 2002. These changes were
21
primarily attributable to natural gas price increases. For the year,
this was partially offset by reduced volumes.
Under the current regulatory framework, the cost of natural gas
purchased for customers and the variations in that cost are passed
through to the customers on a substantially concurrent basis. However,
SDG&E's natural gas procurement Performance-Based Regulation (PBR)
mechanism provides an incentive mechanism by measuring SDG&E's
procurement of natural gas against a benchmark price comprised of
monthly natural gas indices, resulting in shareholder rewards for costs
achieved below the benchmark and shareholder penalties when costs
exceed the benchmark. See further discussion in Notes 1 and 11 of the
notes to Consolidated Financial Statements.
Natural gas revenues decreased to $422$431 million in 2002 from $686
million in 2001, and the cost of natural gas distributed decreased to $205 million
in 2002 from $457 million in 2001. These decreases were primarily due
to lower average natural gas commodity prices as well as lower volumes
of gas sales in 2002. The reduction in natural gas volumes in the
electric generation market is largely attributable to the loss of approximately
100 million cubic feet per day of throughput on the SDG&E system when
the North Baja
pipeline beganpipeline's beginning of service in September 2002 and to the lower
level of electric generation demand.
Under22
The tables below summarize the current regulatory framework, changes in core-marketcomponents of electric and natural gas
prices (natural gas purchasedvolumes and revenues by customer class for customers that are primarily
residentialthe years ended December 31,
2003, 2002 and small commercial and industrial customers, without
alternative fuel capability) or consumption levels do not affect net
income, since core customer rates generally recover the actual cost of
natural gas on a substantially concurrent basis and consumption levels
are fully balanced. See further discussion2001.
ELECTRIC TRANSMISSION AND DISTRIBUTION
(Dollars in millions, volumes in million kilowatt hours)
2003 2002 2001
-------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
-------------------------------------------------------------------
Residential 6,702 $ 731 6,266 $ 649 6,011 $ 775
Commercial 6,263 674 6,053 633 6,107 753
Industrial 1,987 162 1,893 161 2,792 325
Direct access 3,322 87 3,448 117 2,464 84
Street and highway lighting 91 11 88 9 89 10
Off-system sales 8 -- 5 -- 413 88
-------------------------------------------------------------------
18,373 1,665 17,753 1,569 17,876 2,035
Balancing and other 137 (275) (359)
-------------------------------------------------------------------
Total $ 1,802 $ 1,294 $ 1,676
-------------------------------------------------------------------
NATURAL GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
Natural Gas Sales Transportation & Exchange Total
- ---------------------------------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
- ---------------------------------------------------------------------------------------------
2003:
Residential 32 $ 291 -- $ -- 32 $ 291
Commercial and industrial 17 127 4 5 21 132
Electric generation plants -- 3 62 30 62 33
---------------------------------------------------------------
49 $ 421 66 $ 35 115 456
Balancing accounts and other 53
--------
Total $ 509
- ---------------------------------------------------------------------------------------------
2002:
Residential 33 $ 246 -- $ 1 33 $ 247
Commercial and industrial 17 98 5 7 22 105
Electric generation plants -- -- 85 24 85 24
---------------------------------------------------------------
50 $ 344 90 $ 32 140 376
Balancing accounts and other 55
--------
Total $ 431
- ---------------------------------------------------------------------------------------------
2001:
Residential 34 $ 461 -- $ -- 34 $ 461
Commercial and industrial 18 233 4 18 22 251
Electric generation plants -- -- 99 23 99 23
---------------------------------------------------------------
52 $ 694 103 $ 41 155 735
Balancing accounts and other (49)
--------
Total $ 686
- ---------------------------------------------------------------------------------------------
23
As explained in Note 1 of the notes to Consolidated Financial
Statements.Statements commodity-related revenues from the DWR's purchasing of the
company's net short position or from the DWR's allocated contracts are
not included in revenue. However, the associated volumes and
distribution revenue are included herein.
Other Operating Expenses. Other operating expenses increased to $531$637
million in 2003 from $560 million in 2002 and increased to $209 million
in the fourth quarter of 2003 from $176 million in the fourth quarter
of 2002. The changes were due primarily to higher labor and employee
benefit costs, costs associated with the Southern California wildfires
and general operating cost increases, including litigation charges.
Other operating expenses increased to $560 million in 2002 from $491
million in 2001. For the fourth quarter, other operating expenses
increased to $164$176 million in 2002 from $147 million in 2001. These
increases were primarily due to higher labor and employee benefits
costs and increases in other operating costs, including operating costs
that are associated with nuclear generating
facilities.SONGS.
Other Income. Other income and deductions, which primarily consist of
interest income and/or expense from short-term investments and
regulatory balancing accounts, decreased towas $32 million, $24 million in 2002
fromand $54
million in 2001. For2003, 2002 and 2001, respectively. Other income for the
fourth quarter, other income
decreased towas $21 million, $10 million in 2002 fromand $38 million in 2001.2003,
2002 and 2001, respectively. The increases in 2003 were due to higher
interest income resulting from the favorable $37 million before-tax
resolution of income-tax issues with the Internal Revenue Service
(IRS) and reduced balancing account interest expense in 2003. The
decreases in 2002 were primarily due to the reduced interest income from
short-
termshort-term investments, as well as the $19 million gain on sale of
SDG&E's Blythe, California property in 2001 (discussed below in "Cash Flows
From Investing Activities").2001.
Interest Expense. Interest expense was $73 million, $77 million and
$92 million in 2003, 2002 and 2001, respectively. ForThe decrease for the
fourth quarter,year in 2003 was due primarily to lower interest expense decreased to $18 million in 2002 from $22 million in
2001.incurred as the
result of lower average debt. The decrease in interest expense in
2002 was primarily due to lower interest incurred as the result of lower average debt and lower interest rates
in 2002. For the fourth quarter, interest expense was $20 million, $18
million and $22 million in 2003, 2002, and 2001, respectively.
Interest rates on certain of the company's debt can vary with credit
ratings, as described in Notes 2 and 3 of the notes to Consolidated
Financial Statements. In addition, see further discussion of rate-reductionrate-
reduction bonds in Note 3.
25
Income Taxes. Income tax expense was $148 million, $91 million and $141
million for the years ended December 31, 2003, 2002 and 2001,
respectively. The effective income tax rates were 30.3 percent, 30.3
percent and 43.5 percent for the same years. The decrease inincreased income tax
expense in 2003 compared to 2002 was due primarily to higher taxable
income while the low rate in 2003 was due primarily to a $57 million
favorable resolution of income-tax issues in the fourth quarter of
2003. In addition, income before taxes in 2003 included $37 million in
interest income arising from the income tax settlement, resulting in an
offsetting $15 million income tax expense. The lower income tax expense
in 2002 compared to 2001 was due to the
fact that SDG&E receivedlower taxable income and a $25
million favorable resolution of income-prior years' income-tax issues in 2002,
24
while the low rate in 2002 was due to the $25 million favorable
resolution.
Net Income. SDG&E recorded net income of $340 million and $209 million
in 2003 and 2002, respectively, and net income of $130 million and $54
million for the fourth quarters of 2003 and 2002, respectively. The
increase for the year was primarily due to the favorable resolution of
income tax issues in the fourth quarter of 2003, which positively
affected earnings by $79 million, income of $65 million after-tax
related to the approved settlement of certain purchase power contracts
(see Note 10 of the notes to Consolidated Financial Statements), higher
earnings from PBR awards, and higher electric transmission and
distribution revenue. These factors were partially offset by higher
operating expenses (including litigation charges in the third quarter
of 2003), the end of sharing of the merger savings (which positively
impacted earnings by $8 million in 2002) and the $25 million favorable
resolution of prior yearsyears' income tax issues recorded in the second
quarter of 2002. Net Income.The change for the quarter was due to the resolution
of the income tax issues and higher electric transmission and
distribution revenue, offset partially by the end of sharing of the
merger savings (which positively impacted earnings by $2 million for
the 2002 quarter).
Net income increased to $209 million in 2002 from $183 million in 2001.
The increase was primarily due to the $25 million favorable resolution of prior year income-tax issues in the second
quarter of 2002after-tax benefit
noted above and lower interest expense in 2002, partially offset by
lower interest income in 2002 and the 2001 gain on the sale of SDG&E's
Blythe property and lower interest
income in 2002.property. Net income increased to $54 million for the fourth
quarter of 2002, compared to $46 million for the corresponding period
ofin 2001, primarily due to higher natural gas income, an increase in
electric transmission and electric distribution
and transmission revenues, and income-taxincome tax
adjustments in 2002, partially offset by the 2001 Blythe gain.
2001 Compared to 2000
Electric Revenue and Cost of Electric Fuel and Purchased Power.
Electric revenues decreased to $1.7 billion in 2001 from $2.2 billion
in 2000, and the cost of electric fuel and purchased power decreased to
$0.8 billion in 2001 from $1.3 billion in 2000. For the fourth quarter,
electric revenues decreased to $284 million in 2001 from $717 million
in 2000, and the cost of electric fuel and purchased power decreased to
$87 million in 2001 from $485 million in 2000. These decreases were
primarily due to the DWR's purchasing of SDG&E's net short position
starting in February 2001, offset by a $30 million after-tax charge for
regulatory issues in 2000 related to a potential regulatory
disallowance for the acquisition of wholesale power in the newly
deregulated California market.
Natural Gas Revenue and Cost of Gas Distributed. Natural gas
revenues increased to $686 million in 2001 from $487 million in 2000,
and the cost of natural gas distributed increased to $457 million in
2001 from $273 million in 2000. These increases were primarily due to
higher average prices for natural gas in 2001. For the fourth quarter,
natural gas revenues decreased to $105 million in 2001 from $178
million in 2000, and the cost of natural gas distributed decreased to
$55 million in 2001 from $119 million in 2000. These decreases were
attributable to the lower natural gas costs in the fourth quarter of
2001.
Other Operating Expenses. Other operating expenses increased to
$491 million in 2001 from $412 million in 2000. For the fourth quarter,
other operating expenses increased to $147 million in 2001 from $135
million in 2000. These increases were primarily due to increased wages
and employee benefits costs, as well as increases in the operating
costs that are associated with balancing accounts and, therefore, do
not affect net income.
Other Income. Other income and deductions, which primarily
consists of interest income and/or expense from short-term investments
and regulatory balancing accounts, was $54 million and $34 million in
2001 and 2000, respectively. For the fourth quarter, other income
26
increased to $38 million in 2001 from $10 million in 2000. The increase
from 2000 to 2001 was primarily due to the $19 million gain on sale of
SDG&E's Blythe, California property (discussed below in "Cash Flows
From Investing Activities") in 2001, partially offset by lower interest
income from affiliates due to loan repayments by Sempra Energy in 2000.
Interest Expense. Interest expense was $92 million and $118
million in 2001 and 2000, respectively. The decrease in interest
expense in 2001 was primarily due to refunds made to customers in 2000
for the rate-reduction bond liability, and lower interest incurred as
the result of the remarketing of variable-rate debt during the first
quarter of 2001.
Income Taxes. Income tax expense was $141 million and $144 million
for the years ended December 31, 2001 and 2000, respectively. The
effective income tax rates were 43.5 percent and 48.8 percent for the
same years. The decreases in the tax expense and effective rate in 2001
were due primarily to higher state tax depreciation in 2000 and the
2001 income tax issues.
Net Income. Net income increased to $183 million in 2001 from $151
million in 2000. The increase was primarily due to the gain on sale of
SDG&E's Blythe property and lower interest expense, as well as the $30
million after-tax charge for regulatory issues in 2000. These increases
were partially offset by lower interest income from affiliates. Net
income increased to $46 million for the fourth quarter of 2001,
compared to $39 million for the corresponding period in 2000. This
increase was primarily due to the sale of the Blythe property.
CAPITAL RESOURCES AND LIQUIDITY
The company's operations are the major source of liquidity. Beginning
in the third quarter of 2000 and continuing into the first quarter of
2001, SDG&E's liquidity and its ability to make funds available to
Sempra Energy were adversely affected by the electric cost
undercollections resulting from a temporary ceiling on electric rates
legislatively imposed in response to high electric commodity costs.
Growth in these undercollections ceased as a result of an agreement
with the DWR, under which the DWR was obligated to purchase electricity
for SDG&E's customers to fill SDG&E's full net short position
consisting of the power and ancillary services required by SDG&E's
customers that were not provided by SDG&E's nuclear generating
facilities or its previously existing purchased-power contracts. The
agreement with the DWR extended throughAt December
31, 2002. Starting on
January 1, 2003, SDG&E and other California IOUs resumed their electric
commodity procurement function based on a CPUC decision issued in
October 2002. In addition, AB 57 and implementing decisions by the CPUC
provide for periodic adjustments to rates that would reflect the costs
of power and are intended to ensure the timely recovery of any
undercollections.
Another issue with potential implications to capital resources and
liquidity is the ownership of certain power sale contracts. The company
believes that all profits associated with the contracts properly are
for the benefit of SDG&E shareholders rather than customers, whereas
the CPUC asserted that all the profits should accrue to the benefit of
customers. On December 19, 2002, in a 3-to-2 decision, the CPUC
27
approved a proposed settlement that divides the profits from these
contracts, $199 million for SDG&E customers and $173 million for SDG&E
shareholders. Of the $199 million in profits allocated to customers,
$175 million had already been credited to ratepayers in 2001. The
remaining $24 million was applied as a balancing account transfer that
reduced the AB 265 balancing account in December 2002. The profits
allocated to customers reduce SDG&E's AB 265 undercollection, but do
not adversely affect SDG&E's financial position, liquidity or results
of operations. The term of a commissioner who voted to approve the
settlement has expired, and a new commissioner has been appointed. On
January 29, 2003, the CPUC's Office of Ratepayer Advocates, the City of
San Diego and the Utility Consumers' Action Network, a consumer-
advocacy group, filed requests for a CPUC rehearing of the decision. On
February 13, 2003, the company filed its opposition to rehearinghad $148 million in cash and $300 million in
available unused, committed lines of the
decision. Parties requesting a rehearing and parties to any rehearing
may also appeal the CPUC's final decision to the California appellate
courts.
For additional discussion, see "Factors Influencing Future Performance-
Electric Industry Restructuring and Electric Rates" herein and Note 10
of the notes to Consolidated Financial Statements.credit.
Management continues to regularly monitor the company's ability to
adequately meetfinance the needs of its operating, financing and investing activities.activities
in a manner consistent with its intention to maintain strong,
investment-quality credit ratings.
CASH FLOWS FROM OPERATING ACTIVITIES
Net cash provided by operating activities totaled $581 million, $757
million and $557 million for 2003, 2002 and $174 million for2001, respectively.
The decrease in cash flows from operations in 2003 compared to 2002 2001was
attributable to a decrease in overcollected regulatory balancing
accounts and 2000, respectively.higher tax payments, partially offset by a reduction in
deferred income taxes and investment tax credits.
The increase in cash flows from operations in 2002 compared to 2001 was
attributable to SDG&E's collectionhigher customer refunds and payments of a portion of prior purchased-
power costs (the remaining balance of which decreased to $392 million
at December 31, 2001, $215 million at December 31, 2002 and $183
million on January 31, 2003, from a high in mid-2001 of $750 million),
the refunds to large customersaccounts
payable in 2001, resulting from AB 43X and the
increase in accounts payable. The increase was partially offset by the decrease in overcollected
25
regulatory balancing accounts and higher deferred income taxes and
investment tax credits andin 2002.
During 2003, the decrease in regulatory balancing accounts. See further discussion oncompany made a pension plan contribution of $17
million for the 2001 impact of regulatory balancing accounts activity below.
The increase in cash flows from operating activities in 2001 compared
to 2000 was primarily due to lower refunds paid to customers in 2001
and the increase in overcollected regulatory balancing accounts,
partially offset by a decrease in accounts payable. The decrease in
accounts payable was due to decreases in the average prices for natural
gas and the DWR's purchasing of SDG&E's net short position for
electricity.2003 plan year.
CASH FLOWS FROM INVESTING ACTIVITIES
Net cash provided by (used in)used in investing activities totaled $(611)$319 million, $(310)$611
million and $288$310 million for 2003, 2002 and 2001, and 2000,
respectively.
The decrease in cash used in investing activities in 2003 compared to
2002 was primarily due to the $129 million repayment by Sempra Energy
in 2003 compared to $199 million of advances from SDG&E in 2002.
Advances to Sempra Energy are payable on demand.
The increase in cash used in investing activities in 2002 compared to
2001 was primarily due to increased capital expenditures, and advances
to Sempra Energy, which are payable on demand.
28
For 2001, cash flows used in investing activities primarily consisted
of capital expenditures of $307 million for the upgrade and expansion
of utility plant. The decrease in cash flows from investing activities
in 2001 was attributable to loan repayments from Sempra Energy in 2000.
In addition, the increase in proceeds from sale of assets was due to
the sale of property in Blythe, California, for $42 million.Energy.
Capital Expenditures for Utility Plant
Capital expenditures were $444 million in 2003, compared to $400
million and $307 million in 2002 comparedand 2001, respectively. The increase
in capital expenditures in 2003 was mainly due to $307the inclusion of $40
million and $324 millionof capital costs associated with the Southern California
wildfires in 2001 and 2000, respectively.October 2003. Capital expenditures in 2002 were up from 2001 due to
additions and improvements to the company's natural gas and electric
distribution systems.
Capital expenditures for 2001 were only slightly down from
2000.
Future ConstructionCapital Expenditures
Significant capital expenditures in 20032004 are expected to include $400
millionbe for
additions to the company's natural gas and electric distribution
systems. These expenditures are expected to be financed by cash flows
from operations and security issuances.
Over the next five years, the company expects to make capital
expenditures of approximately $2 billion.$2.7 billion, consisting of $400 million in 2004, $450
million in 2005, $1.0 billion in 2006, $400 million in 2007 and $450
million in 2008.
Construction programs are periodically reviewed and revised by the
company in response to changes in economic conditions, competition,
customer growth, inflation, customer rates, the cost of capital, and
environmental and regulatory requirements.
The company's level of construction expenditures in the next few years
may vary substantially, and will depend on the availability of
financing and business opportunities providing desirable rates of
return. The company's intention is to finance any sizeable expenditures
so as to maintain the company's strong investment-grade ratings and
capital structure. Smaller expenditures will be made by the use of
existing liquidity.
CASH FLOWS FROM FINANCING ACTIVITIES
Net cash used in financing activities totaled $273 million, $309
million and $181 million for 2003, 2002 and $543 million for 2002, 2001, and 2000, respectively.
The cash used in financing activities decreased in 2003 due to lower
repayments on long-term debt in 2003.
26
Net cash used for financing activities increased in 2002 from 2001 due
primarily to higher dividend payments and the absence of debt issuances
in 2002.
Net cash used in financing activities decreased in 2001 primarily due
to higher dividends paid to Sempra Energy in 2000 and the increase in
long-term debt issuances in 2001.
Long-Term and Short-Term Debt
In May 2002, SDG&E and SoCalGas replaced their individual revolving
lines of credit with a combined revolving credit agreement under which
29
each utility may individually borrow up to $300 million, subject to a
combined borrowing limit for both utilities of $500 million. Each
utility's revolving credit line expires on May 16, 2003, at which time
it may convert its then outstanding borrowings to a one-year term loan
subject to having obtained any requisite regulatory approvals relating
to long-term debt. Borrowings under the agreement, which are available
for general corporate purposes including back-up support for commercial
paper and variable-rate long-term debt, would bear interest at rates
varying with market rates and the borrowing utility's credit rating.
The agreement requires each utility to maintain a debt-to-total
capitalization ratio (as defined in the agreement) of not to exceed 60
percent. The rights, obligations and covenants of each utility under
the agreement are individual rather than joint with those of the other
utility, and a default by one utility would not constitute a default by
the other.
In 2002, repaymentsRepayments on long-term debt included repayments ofin 2003 were for $66 million of rate-reductionrate-
reduction bonds.
Repayments on long-term debt in 2002 included $38 million of first-
mortgage bonds and $28$66 million of 7.625% first-
mortgage bonds. In addition, in July 2002, SDG&E called $10 million of
its 8.5% first-mortgagerate-reduction bonds.
In 2001, repayments on long-term debt includedconsisted of $66 million of rate-
reduction bonds and $25 million of unsecured variable-rate bonds. During
December 2000, $60 million of variable-rate industrial development bonds
were put back by the holders and remarketed in February 2001 at a fixed
interest rate of 7 percent.
In 2000, repayments on long-termSee Notes 2 and 3 of the notes to Consolidated Financial Statements for
further discussion of debt included $66 millionactivity and lines of rate-
reduction bonds. $10 million of first-mortgage bonds were also repaid
in 2000.credit.
Dividends
Dividends paid to Sempra Energy amounted to $200 million in 2002,2003,
compared to $200 million in 2002 and $150 million in 2001 and $400 million in 2000.2001.
The payment of future dividends and the amount thereof are within the
discretion of the company's board of directors. The CPUC's regulation
of SDG&E's capital structure limits the amounts that are available for
loans and dividends to Sempra Energy from SDG&E. At December 31, 2002,2003,
the company could have provided a total (combined loans and dividends)
of $250$290 million to Sempra Energy. At December 31, 2002,2003, SDG&E had
actual loans, net of payables, to Sempra Energy of $250$75 million.
Capitalization
Total capitalization, including the current portion of long-term debt
and excluding the rate-reduction bonds (which are non-recourse to the
company) at December 31, 20022003 was $2.1$2.2 billion. The debt-to-
capitalization ratio was 4240 percent at December 31, 2002.2003. Significant
changes in capitalization during 20022003 included long-term borrowings and
dividends.
Cashrepayments, income and Cash Equivalents
At December 31, 2002, the company had $159 million of cash and $300
million of revolving lines of credit. Management believes these amounts
30
and cash flows from operations and new debt issuances will be adequate
to finance capital expenditures and other commitments.dividends.
Commitments
The following is a summary of the company's principal contractual
commitments at December 31, 2002 (dollars in millions).2003. Liabilities reflecting fixed pricefixed-price
contracts and other derivatives are excluded as they are primarily
offset against regulatory assets and would be recovered from customers
through the ratemaking process. Additional information concerning
commitments is provided above and in Notes 3, 4, 9 and 12 of the notes
to Consolidated Financial Statements.
27
By Period
----------------------------------------------------
2004 2006- -------------------------------------------------------------------------------
2005 2007
(Dollars in millions) and and
Description 2003 2005 20072004 2006 2008 Thereafter Total
- --------------------------------------------------------------------------------
Long-term debt $ 66 $ 132 $ 13265 $ 889 $1,219890 $1,153
Operating leases 16 26 16 17 7529 17 23 86
Purchased-power contracts 257 455 437 2,285 3,434214 457 458 2,235 3,364
Natural gas contracts 31 27 23 153 23420 39 28 142 229
Preferred stock subject to
mandatory redemption 1 3 20 -- 3 3 19 2524
Construction commitments 3 -- -- 95 9812 16 14 48 90
SONGS decommissioning 20 22 9 258 309265 316
Asset retirement obligations 3 6 1 -- 10
Environmental commitments 5 108 9 -- -- 1517
---------------------------------------------------
Totals $ 398361 $ 675713 $ 620 $3,716 $5,409612 $3,603 $5,289
===================================================
Credit Ratings
As of January 31, 2003, credit ratings for SDG&E were as follows:
S&P Moody's Fitch
- -----------------------------------------------------------
Secured Debt A+ A1 AA
Unsecured Debt A A2 AA-
Preferred Stock A- Baa1 A+
Commercial Paper A-1 P-1 F1+
-------------------------------
Credit Ratings
Several credit ratings of the company declined in 2003, but remain
investment grade. As of January 31, 2003,2004, credit ratings for SDG&E were
as follows:
S&P* Moody's** Fitch
- ----------------------------------------------------------------
Secured debt A+ A1 AA
Unsecured debt A- A2 AA-
Preferred stock BBB+ Baa1 A+
Commercial paper A-1 P-1 F1+
------------------------------------
* Standard & Poor's
** Moody's Investor Services, Inc.
As of January 31, 2004, the company has a stable outlook rating from
all three credit rating agencies.
31
FACTORS INFLUENCING FUTURE PERFORMANCE
ThePerformance of the company will depend primarily on the ratemaking and
regulatory process, electric and natural gas industry restructuring,
and the changing energy marketplace. These factors influencing future performance are summarized below.discussed in
Notes 10 and 11 of the notes to Consolidated Financial Statements
herein.
Electric Industry Restructuring and Electric Rates
Supply/Subsequent to the electric capacity shortages of 2000-2001, SDG&E's
service territory had and continues to have an adequate supply of
electricity. However, various projections of electricity demand imbalancesin
SDG&E's service territory indicate that, without additional electrical
generation and a number of other factors resultedtransmission, and reductions in abnormally high electric-commodity costselectrical usage,
beginning in mid-20002005 electricity demand could begin to outstrip available
resources. SDG&E has issued a request for proposals (RFP) to meet the
electric capacity shortfall, estimated at 69 megawatts (MW) in 2005 and
continuing into 2001. This caused SDG&E's customer bills to be
substantially higher than normal. In response, legislation enacted in
September 2000 imposedincreasing annually by approximately 100 MW, and has filed a ceiling of 6.5 cents/kilowatt hour (kWh) onproposed
28
plan at the cost of electricity that SDG&E could pass on to its small-usage
customers on a current basis. SDG&E accumulated the amount that it paidCPUC for electricity in excessmeeting these capacity requirements. See Note 10
of the ceiling rate in an interest-bearing
balancing account. This undercollection amountednotes to $447 million, $392
million and $215 million atConsolidated Financial Statements for additional
information regarding the RFP results.
Through December 31, 2000, 2001 and 2002,
respectively.
In February 2001, the DWR began to purchase power from generators and
marketers to supply a portion of the state's power requirements that is
served by IOUs. From early 2001 to December 31, 2002, the DWR purchased
SDG&E's full net short position (the power needed by SDG&E's customers,
other than that provided by SDG&E's nuclear generating facilities or
its previously existing purchase power contracts). In October 2002, the
CPUC issued a decision directing the resumption of the electric
commodity procurement function by IOUs by January 1, 2003.
An unresolved issue is the ownership of certain power sale profits
stemming from intermediate term purchase power contracts entered into
by SDG&E during the early stages of California's electric utility
industry restructuring. On December 19, 2002, the CPUC rendered a 3-to-
2 decision approving the June 2002 proposed settlement previously
described in the company's Quarterly Report on Form 10-Q for the
quarter ended September 30, 2002, that divides the profits from these
contracts, $199 million for SDG&E customers and $173 million for SDG&E
shareholders. Of the $199 million in profits allocated to customers,
$175 million had already been credited to ratepayers in 2001. The
remaining $24 million was applied as a balancing account transfer that
reduced the AB 265 balancing account in December 2002. The profits
allocated to customers reduce SDG&E's AB 265 undercollection, but do
not adversely affect SDG&E's financial position, liquidity or results
of operations. The term of a commissioner who voted to approve the
settlement has expired, and a new commissioner has been appointed. On
January 29, 2003, the CPUC's Office of Ratepayer Advocates, the City of
San Diegooperating and the Utility Consumers' Action Network, a consumer-
advocacy group, filed requests for a CPUC rehearing of the decision. On
February 13, 2003, the company filed its opposition to rehearing of the
decision. Parties requesting a rehearing and parties to any rehearing
may also appeal the CPUC's final decision to the California appellate
courts.
Operatingcapital costs of SONGS
Units 2 and 3 (including nuclear fuel and
related financing costs) and incremental capital expenditures arewere recovered through the ICIP mechanism which allowsallowed
SDG&E to receive
approximately 4.4 cents per kilowatt-hour for SONGS generation. Any
differences between the actual amounts of these costs and the incentive price affectaffected net
income. For the year ended December 31, 2002,2003, ICIP 32
contributed $50$53
million to SDG&E's net income. The CPUC has rejected an
administrative law judge's proposed decision to end ICIP prior to its
December 31, 2003 scheduled expiration date. However,Beginning in 2004 the CPUC has also
denied the previously approved market-based pricing for SONGS beginning
in 2004 and instead provided
for traditional rate-making treatment, under which the SONGS ratebase
would beginstart over at zero,January 1, 2004, essentially eliminating earnings
from SONGS until ratebase grows. The company has
applied for rehearing of this decision.except from future increases in ratebase.
See additional discussion of this and related topics, including the
CPUC's adjustment to its plan for deregulation of electricity, in Note
10 of the notes to Consolidated Financial Statements.
Natural Gas Restructuring and Gas Rates
OnIn December 11, 2001 the CPUC issued a decision adopting the following
provisions affecting the structure of therelated to natural gas
industry in
California, some of which could introduce additional volatility into
the earnings of the company and other market participants: a system for
shippers to hold firm, tradable rights to capacity on SoCalGas' major
gas transmission lines; new balancing services, including separate core
and noncore balancing provisions; a reallocation among customer classes
of the cost of interstate pipeline capacity held by SoCalGas and an
unbundling of interstate capacity for natural gas marketers serving
core customers; and the elimination of noncore customers' option to
obtain natural gas procurement service from SDG&E and SoCalGas. During
2002 the California Utilities filed a proposedrestructuring; however, 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. On December 30, 2002, the CPUC deferred acting on a plan to
implement its decision.
Allowed Rate of Return
Effective January 1, 2003, SDG&E's authorized rate of return on equity
is 10.9 percent (increased from 10.6 percent) for SDG&E's electric
distribution and natural gas businesses. This change results in a
revenue requirement increase of $2.4 million ($1.9 million electric and
$0.5 million natural gas) and increases SDG&E's overall rate of return
from 8.75 percent to 8.77 percent. These rates remain in effect through
2003. The company can earn more than the authorized rate by controlling
costs below approved levels or by achieving favorable results in
certain areas such as various incentive mechanisms. In addition,
earnings are affected by customer growth.
Cost of Service (COS) and Performance-Based Regulation
The COS and PBR cases for SDG&E were filed on December 20, 2002. The
filings outline projected expenses (excluding the commodity cost of
electricity or natural gas consumed by customers or expenses for
programs such as low-income assistance) and revenue requirements for
2004 and a formula for 2005 through 2008. SDG&E's cost of service study
proposes increases in electric and natural gas base rate revenues of
$58.9 million and $21.6 million, respectively. The filings also
requested a continuance and expansion of PBR in terms of earnings
sharing and performance service standards that include both reward and
penalty provisions related to customer satisfaction, employee safety
33
and system reliability. The resulting new base rates are expected to be
effective on January 1, 2004.been delayed. A
CPUC decision could be issued in the first quarter of 2004. With the
company's natural gas supply contracts nearing expiration, the company
believes that regulation needs to consider sufficiently the adequacy
and diversity of supplies to California, transportation infrastructure
and cost recovery thereof, hedging opportunities to reduce cost
volatility, and programs to encourage and reward conservation.
Additional information on natural gas industry restructuring is
expectedprovided in late 2003.
SDG&E's profitability is dependent upon its ability to control costs
within base rates. SDG&E's PBR mechanism is in effect through December
31, 2003, at which time the mechanism will be updated. That update will
include, among other things, a reexaminationNote 11 of the company's
reasonable costsnotes to Consolidated Financial Statements.
CPUC Investigation of operation to be allowed in rates. The October 10,
2001 decision also deniedCompliance with Affiliate Rules
In February 2003, the company's request to continue equal
sharing between ratepayers and shareholdersCPUC opened an investigation of the estimated savings
forbusiness
activities of SDG&E, SoCalGas and Sempra Energy to ensure that they
have complied with statutes and CPUC decisions in the merger discussed in Note 1management,
oversight and instead, ordered that alloperations of the estimatedtheir companies. In September 2003, merger savings go to ratepayers. This decision will
adversely affect the company's 2003 net income by $11 million.
Utility Integration
On September 20, 2001, the
CPUC approvedsuspended the procedural schedule until it completes an
independent audit to evaluate energy-related holding company systems
and affiliate activities undertaken by Sempra Energy's request to
integrateEnergy within the management teamsservice
territories of SDG&E and SoCalGas. The decision
retains the separate identities of each utility and is not a merger.
Instead, utility integration is a reorganization that consolidates
senior management functions of the two utilities and returns to the
utilities the majority of shared support services previously provided
by Sempra Energy's centralized corporate center. Once implementation is
completed, the integrationaudit will cover years 1997
through 2003, is expected to resultcommence in more efficientMarch 2004 and effective operations.should be
completed by the end of 2004. In a related development,accordance with existing CPUC
requirements, the California Utilities' transactions with other Sempra
Energy affiliates have been audited by an August 2002independent auditing firm
each year, with results reported to the CPUC, interim decision denied a
request byand there have been no
material adverse findings in those audits.
Cost of Service Filing
The California Utilities have filed cost of service applications with
the CPUC, seeking rate increases designed to reflect forecasts of 2004
capital and operating costs. SDG&E is requesting revenue increases of
$76 million. On December 19, 2003, settlements were filed with the CPUC
for SoCalGas and SoCalGas to combine their natural gas procurement
activities at this time, pending completionfor SDG&E that, if approved, would resolve most of the
CPUC's ongoing
investigationcost of market powerservice issues. A CPUC decision is likely in the second quarter
of 2004. The California Utilities have also filed for continuation
through 2004 of existing Performance-Based Regulation mechanisms for
29
service quality and safety that would otherwise expire at the end of
2003. In January 2004, the CPUC issued a decision that extended 2003
service and safety targets through 2004, but deferred action on
applying any rewards or penalties for performance relative to these
targets to a decision to be issued later in 2004 in a second phase of
these applications. This is discussed in Note 11 of the notes to
Consolidated Financial Statements.
MARKET RISK
Market risk is the risk of erosion of the company's cash flows, net
income, asset values and equity due to adverse changes in prices for
various commodities, and in interest rates.
The company's policy is to use derivative physical and financial
instruments to reduce its exposure to fluctuations in interest rates,
and commodity prices. Transactions involving these financial
instruments are with major exchanges and other firms believed to be
credit worthy. The use of these instruments exposes the company to
market and credit risks which, at times, may be concentrated with
certain counterparties. There were no unusual concentrations at
December 31, 2002, that would indicate an unacceptable level of risk.
Credit risks associated with concentration are discussed below under
"Credit Risk."
The companySempra Energy has adopted corporate-wide policies governing its market-market
risk management and trading activities. Assisted by the company'sSempra Energy's Energy Risk
Management Group (ERMG), the company'sSempra Energy's Energy Risk Management
Oversight Committee (ERMOC), consisting of senior officers, oversees
company-wide energy risk management activities and monitors the results
of trading activities to ensure compliance with the company's stated energy-riskenergy
risk management and trading policies. Utility management receives daily information
on positions and the ERMG receives information on a delayed basis detailing positions
creating market and
34
credit risk for the company, consistent with
affiliate rules. The ERMG independently measures and reports the market
and credit risk associated with these positions. In addition, the company's risk-
management committeeERMOC
monitors energy-priceenergy price risk management and trading activities independently from the
groups responsible for creating or actively managing these risks.
Along with other tools, the company uses Value at Risk (VaR) to measure
its exposure to market risk. VaR is an estimate of the potential loss
on a position or portfolio of positions over a specified holding
period, based on normal market conditions and within a given
statistical confidence interval. The company has adopted the
variance/covariance methodology in its calculation of VaR, and uses
both the 95-percent and 99-percent confidence intervals. VaR is
calculated independently by the ERMG for the company. Historical
volatilities and correlations between instruments and positions are
used in the calculation. As of December 31, 2002,2003, the total VaR of the
company's natural gas and power positions was not material.
The company uses energyelectric and natural gas derivatives to manage natural gas price
risk associated with servicing their load requirements. In addition, the
company makes limited use of natural gas derivatives for trading
purposes. These instruments can include forward contracts, futures,
swaps, options and other contracts. In the case of both price-risk
management and trading activities, theThe use of
derivative financial instruments is subject to certain limitations
imposed by company policy and regulatory requirements.
See the continuingrevenue recognition discussion belowin Note 1 and Note 8 of the notes to Consolidated Financial Statements for furtheradditional
market risk information regarding the use of energy derivatives by the company.
Additional information is providedderivative instruments in Note 8 of
the notes to Consolidated Financial Statements.
The following discussion of the company's primary market-riskmarket risk exposures
as of December 31, 20022003 includes a discussion of how these exposures
are managed.
Commodity-PriceCommodity Price Risk
Market risk related to physical commodities is created by volatility in
the prices and basis of natural gas and electricity. The company's30
market risk is impacted by changes in volatility and liquidity in the
markets in which these commodities or related financial instruments are
traded. The company is exposed, in varying degrees, to price risk
primarily in the natural gas and electricity markets. The company's
policy is to manage this risk within a framework that considers the
unique markets, and operating and regulatory environmentsenvironments.
The company's market risk exposure is limited due to CPUC authorized
rate recovery of electric procurement and natural gas purchase, sale,
intrastate transportation and storage activity. However, the company
may, at times, be exposed to market risk as a result of activities under SDG&E's natural
gas PBR and electric procurement activities, which is discussed in
Notes 10 and 11 of the notes to Consolidated Financial Statements. The
company manages its risk within the parameters of the company's market-riskmarket
risk management and
trading framework. As of December 31, 2002,2003, the company's
exposure to market risk was not material. 35
Interest-RateHowever, if commodity prices
rose too rapidly, it is likely that volumes would decline. This would
increase the per-unit fixed costs, which could lead to further volume
declines, leading to increased per-unit fixed costs and so forth.
Interest Rate Risk
The company is exposed to fluctuations in interest rates primarily as a
result of its long-term debt. The company historically has funded
operations through long-term debt issues with fixed interest rates and
these interest ratescosts are recovered in utility rates. With the
restructuring of the regulatory process, the CPUC has permitted greater
flexibility in the use of debt. As a result, some
recent debt offerings have been selected with short-term maturities to take advantage of
yield curves, or have used a combination of fixed-rate and
floating-
ratefloating-rate debt. Subject to regulatory constraints, interest-rate
swaps may be used to adjust interest-rate exposures when appropriate,
based upon market conditions.
At December 31, 2002,2003, the company had $1,062$996 million of fixed-rate debt
and $157 million of variable-rate debt. Interest on fixed-rate utility
debt is fully recovered in rates on a historical cost basis and
interest on variable-rate debt is provided for in rates on a forecasted
basis. At December 31, 2002,2003, SDG&E's fixed-rate debt had a one-year VaR
of $200$149 million and SDG&E's variable-rate debt had a one-year VaR of
$0.1$0.02 million.
At December 31, 2002,2003, the company did not have any outstanding
interest-rate swap transactions. See NotesNote 3 and 8 of the notes to
Consolidated Financial Statements for further information regarding
theseinterest rate swap transactions.
In addition the company is ultimately subject to the effect of interest
rate fluctuation on the assets of its pension plan.plan and other
postretirement plans.
Credit Risk
Credit risk is the risk of loss that would be incurred as a result of
nonperformance by counterparties of their contractual obligations. As
with market risk, the company has adopted corporate-wide policies
governing the management of credit risk. Credit risk management is
under the oversight of the Energy Risk Management Oversight Committee,
assistedperformed by the ERMG and the company's credit department.department and overseen
by the ERMOC. Using rigorous models, the company's credit departmentgroups continuously calculatescalculate
current and potential credit risk to counterparties to ensure the risk stays withinmonitor actual
31
balances in comparison to approved limits and reports this information
to the ERMG. The company avoids concentration of counterparties
whenever possible and management believes its credit policies with
regard to counterparties significantly reduce overall credit risk.
These policies include an evaluation of prospective counterparties'
financial condition (including credit ratings), collateral requirements
under certain circumstances, and the use of standardized agreements that
allow for the netting of positive and negative exposures associated
with a single counterparty.counterparty and other security such as lock-box liens
and downgrade triggers.
The company monitors credit risk through a credit-approvalcredit approval process and
the assignment and monitoring of credit limits. These credit limits are
established based on risk and return considerations under terms
customarily available in the industry.
36
The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall
cost of borrowing. The company would be exposed to interest-rate
fluctuations on the underlying debt should other parties to the
agreement not perform. See the "Interest-Rate Risk" section above for
additional information regarding the company's use of interest-rate
swap agreements.
CRITICAL ACCOUNTING POLICIES AND KEY NON-CASH PERFORMANCE
INDICATORS
Certain accounting policies are viewed by management as critical
because their application is the most relevant, judgmental and/or
material to the company's financial position and results of
operations, and/or because they require the use of material
judgments and estimates.
The company's most significant accounting policies are described in
Note 1 of the notes to Consolidated Financial Statements. The most
critical policies, all of which are mandatory under generally accepted
accounting principles and the regulations of the Securities and
Exchange Commission, are the following:
Statement of Financial Accounting Standards (SFAS) No. 5
"Accounting for Contingencies," establishes the amounts and
timing of when the company provides for contingent losses.
Details of the company's issues in this area are discussed in
Note 12 of the notes to Consolidated Financial Statements.
SFAS 71 "Accounting for the Effects of Certain Types of
Regulation," has a significant effect on the way the California
Utilities record assets and liabilities, and the related revenues
and expenses, that would not otherwise be recorded absent the principles
contained in SFAS 71.
SFAS 109 "Accounting for Income Taxes," governs the way the
company provide for income taxes. Details of the company's issues
in this area are discussed in Note 5 of the notes to Consolidated
Financial Statements.
SFAS 123 "Accounting for Stock-Based Compensation" and SFAS 148
"Accounting for Stock-Based Compensation - Transition and
Disclosure," give companies the choice of recognizing a cost at
the time of issuance of stock options or merely disclosing what
that cost would have been and not recognizing it in its financial
statements. Sempra Energy, like most U.S. companies, has elected
the disclosure option for all options that are so eligible. The
subsidiaries record an expense for the plans to the extent that
subsidiary employees participate in the plans, or that
32
subsidiaries are allocated a portion of Sempra Energy's costs of
the plans. The effect of this is discussed in Note 1 of the notes
to Consolidated Financial Statements.
SFAS 133 "Accounting for Derivative Instruments and Hedging
Activities" andActivities," SFAS 138 "Accounting for Certain Derivative
Instruments and Certain Hedging Activities,"Activities" and SFAS 149
"Amendment of Statement 133 on Derivative Instruments and Hedging
Activities" have a significant effect on the balance sheets of
the California Utilitiescompany but have no significant effect on theirits income
statements because of the principles contained in SFAS 71.
In connection with the application of these and other accounting
policies, the company makes estimates and judgments about various
matters. The most significant of these involve:
The collectibility of receivables, regulatory assets, deferred
tax assets and other assets.
The various assumptions used in actuarial calculations for
pension and other postretirement benefit plans.
The likelihood of recovery of various deferred tax assets.
The probable costs to be incurred in the resolution of
litigation.
Differences between estimates and actual amounts have had significant
impacts in the past and are likely to do so in the future.
As discussed elsewhere herein, the company uses exchange quotations or
other third-party pricing to estimate fair values whenever possible.
When no such data is available, it uses internally developed models and
other techniques. The assumed collectibility of receivables considers
the aging of the receivables, the creditworthiness of customers and the
enforceability of contracts, where applicable. The assumed
collectibility of regulatory assets considers legal and regulatory
decisions involving the specific items or similar items. The assumed
collectibility of other assets considers the nature of the item, the
enforceability of contracts where applicable, the creditworthiness of
the other parties and other factors. Costs to fulfill marked-to-market contracts that
are carried at fair value are based on prior 37
experience. Actuarial
assumptions are based on the advice of the company's independent
actuaries. The likelihood of deferred tax recovery is based on analyses
of the deferred tax assets and the company's expectation of future
financial and/or taxable income, based on its strategic planning.
Choices among alternative accounting policies that are material to the
company's financial statements and information concerning significant
estimates have been discussed with the audit committee of the board of
directors.
Key non-cash performance indicators for the company include numbers of
customers and quantities of natural gas and electricity sold. The
information is provided in "Introduction" and "Results of Operations."
33
NEW ACCOUNTING STANDARDS
NewRelevant pronouncements by the Financial Accounting Standards Board (FASB) that have recently become effective or are yet to be effectiveand have
had a significant effect on the company are SFAS 142 through SFAS143, 148, 149 and Interpretations 45150,
and 46.FIN 45. They are described in Note 1 of the notes to Consolidated
Financial Statements. SFAS 142
affects net income by replacing the amortization of goodwill with
periodic reviews thereof for impairment with charges against income
when impairment is found. SFAS 143 requires accounting and disclosure
changes concerning legal obligations related to future asset
retirements. SFAS 144 supercedes SFAS 121 in dealing with other asset
impairment issues. SFAS 145 makes technical corrections to previous
statements. SFAS 146 deals with exit and disposal activities, replacing
EITF Issue 94-3. SFAS 147 deals with acquisitions of financial
institutions. SFAS 148 amends SFAS 123 and adds two additional
transition methods to the fair value method of accounting for stock-
based compensation. SFAS 149 establishes standards for accounting for
financial instruments with characteristics of liabilities and equity.
Interpretation 45 clarifies that a guarantor is required to recognize a
liability for the fair value of the obligation undertaken in issuing a
guarantee. Interpretation 46 addresses consolidation by business
enterprises of variable-interest entities (previously referred to as
"special-purpose entities" in most cases). Pronouncements that have or
potentially could have a material effect
on future earningsthe company are described below.
SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143
issued in July 2001, addresses financial accounting and reporting for
legal obligations associated with the retirement of tangible long-lived
assets. It requires entities to record the fair value of a liabilityliabilities for anlegal
obligations related to asset retirement obligationretirements in the period in which it isthey
are incurred. It also requires the company to reclassify amounts
recovered in rates for future removal costs not covered by a legal
obligation from accumulated depreciation to a regulatory liability.
SFAS 143 is effective149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": SFAS 149 amends and clarifies accounting for
derivative instruments, including certain derivative instruments
embedded in other contracts, and for hedging activities under SFAS 133.
Under SFAS 149 natural gas forward contracts that are subject to
unplanned netting do not qualify for the normal purchases and normal
sales exception. The company beginning in 2003. See
further discussion inhas determined that all natural gas
contracts are subject to unplanned netting and as such, these contracts
will be marked to market. In addition, effective January 1, 2004, power
contracts that are subject to unplanned netting (see Note 1 of the
notes to Consolidated Financial Statements.
SFAS 149, "Accounting for Certain Financial Instruments with
Characteristics of LiabilitiesStatements) and Equity": On January 22, 2003,that do not meet the
FASB directed its staff to prepare a draft of SFAS 149. The final draft
is expected to be issued in March 2003. The statement will establish
standards for accounting for financial instruments with characteristics
of liabilities, equity, or both. The FASB decided thatnormal purchases and normal sales exception under SFAS 149 will prohibit the presentation of certain items in the mezzanine section
(the portion of the balance sheet between liabilities and equity) of
the statement of financial position. As such, certain mandatorily
redeemable preferred stock, which is currently included in the
mezzanine section, may be
classified as a liability once SFAS 149 goes
38
into effect. The proposed effective datefurther marked to market. Implementation of SFAS 149 ison July 1, 2003
for the company.
INFORMATION REGARDING FORWARD-LOOKING STATEMENTS
This Annual Report contains statements that aredid 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 CPUC, the
California Legislature, the DWR and the 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 undulyhave a material impact 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.reported net income.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK
The information required by Item 7A is set forth under "Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Market Risk."
39
34
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of San Diego Gas & Electric
Company:
We have audited the accompanying consolidated balance sheets of San
Diego Gas & Electric Company and subsidiary (the "Company") as of
December 31, 20022003 and 2001,2002, and the related statements of consolidated
income, cash flows and changes in shareholders' equity for each of the
three years in the period ended December 31, 2002.2003. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements
based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence
supporting the amounts and disclosures in the financial statements.
An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the
overall financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly,
in all material respects, the financial position of San Diego Gas &
Electric Company and subsidiary as of December 31, 20022003 and 2001,2002, and
the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2002,2003, in conformity with
accounting principles generally accepted in the United States of
America.
As described in Note 1 to the financial statements, the Company
adopted Statement of Financial Accounting Standards No. 143,
Accounting for Asset Retirement Obligations, effective January 1,
2003.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 14, 2003
4023, 2004
35
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME
Dollars(Dollars in millionsmillions)
Years ended December 31,
2003 2002 2001 2000
------ ------ ------
OPERATING REVENUES
Electric $1,274 $1,676 $2,184$ 1,802 $ 1,294 $ 1,676
Natural gas 422509 431 686
487
------ ------ ------------- ------- -------
Total operating revenues 1,6962,311 1,725 2,362
2,671
------ ------ ------------- ------- -------
OPERATING EXPENSES
ElectricCost of electric fuel and net purchased power 541 297 782 1,326
Cost of natural gas distributed274 205 457 273
Other operating expenses 531637 560 491 412
Depreciation and decommissioning 242 230 207
210
Income taxes 122 93 122 134
Franchise fees and other taxes 114 78 82
81
------ ------ ------------- ------- -------
Total operating expenses 1,4341,930 1,463 2,141
2,436
------ ------ ------------- ------- -------
Operating Incomeincome 381 262 221
235
------ ------ ------------- ------- -------
Other Incomeincome and (Deductions)(deductions)
Interest income 42 10 21
51
Regulatory interest - net (5) (7) 5 (8)
Allowance for equity funds used
during construction 12 15 5
6
TaxesIncome taxes on non-operating income (26) 2 (19) (10)
Other - net 9 4 42
(5)
------ ------ ------------- ------- -------
Total 32 24 54
34
------ ------ ------------- ------- -------
Interest Chargescharges
Long-term debt 67 75 84
81
Other 11 8 12 39
Allowance for borrowed funds
used during construction (5) (6) (4)
(2)
------ ------ ------------- ------- -------
Total 73 77 92
118
------ ------ ------------- ------- -------
Net Incomeincome 340 209 183
151
Preferred Dividend Requirementsdividend requirements 6 6 6
------ ------ ------------- ------- -------
Earnings Applicableapplicable to Common Sharescommon shares $ 334 $ 203 $ 177
$ 145
====== ====== ============= ======= =======
See notes to Consolidated Financial Statements.
41
36
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
Dollars(Dollars in millionsmillions)
December 31,
---------------------------------------------
2003 2002
2001
------ ---------------- ----------
ASSETS
Utility plant - at original cost $5,408 $5,009$ 5,773 $ 5,408
Accumulated depreciation and decommissioning (2,775) (2,642)
------ ------amortization (1,737) (1,613)
------- -------
Utility plant - net 2,633 2,367
------ ------4,036 3,795
------- -------
Nuclear decommissioning trusts 570 494
526
------ ------------- -------
Current assets:
Cash and cash equivalents 148 159 322
Accounts receivable - trade 173 163 160
Accounts receivable - other 17 18
27Interest receivable 37 --
Due from unconsolidated affiliates 151 292 28
Income taxes receivable -- 73
Regulatory assets arising from fixed-price contracts
and other derivatives 59 8359
Other regulatory assets 7581 75
Inventories 60 46
70
Other 27 11
4
------ ------------- -------
Total current assets 753 823
842
------ ------------- -------
Other assets:
Deferred taxes recoverable in rates 273 190 162
Regulatory assets arising from fixed-price contracts
and other derivatives 502 579 634
Other regulatory assets 281 342
842
Sundry 48 62
26
------ ------------- -------
Total other assets 1,104 1,173
1,664
------ ------------- -------
Total assets $5,123 $5,399
====== ======$ 6,463 $ 6,285
======= =======
See notes to Consolidated Financial Statements.
42
37
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
Dollars(Dollars in millionsmillions)
December 31,
--------------------------------------------
2003 2002
2001
------ ---------------- ----------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common stock (255,000,000(255 million shares authorized;
116,583,358117 million shares outstanding) $ 943938 $ 857943
Retained earnings 369 235 232
Accumulated other comprehensive income (loss) (43) (34)
(3)
------ ------------- -------
Total common equity 1,264 1,144 1,086
Preferred stock not subject to mandatory redemption 79 79
------ ------------- -------
Total shareholders' equity 1,343 1,223 1,165
Preferred stock subject to mandatory redemption 25-- 25
Long-term debt 1,087 1,153
1,229
------ ------------- -------
Total capitalization 2,430 2,401
2,419
------- -------------
Current liabilities:
Accounts payable 193 159 139
Interest payable 12 12
Due to unconsolidated affiliates -- 3
--Interest payable 10 12
Income taxes payable 30 41 --
Deferred income taxes 83 53 128
Regulatory balancing accounts - net 338 394 575
Fixed-price contracts and other derivatives 59 8459
Current portion of long-term debt 66 9366
Other 294 170
174
------ ------------- -------
Total current liabilities 1,073 957
1,205
------ ------------- -------
Deferred credits and other liabilities:
Due to unconsolidated affiliates 21 16
Customer advances for construction 49 54 42
Deferred income taxes 617 602 639
Deferred investment tax credits 40 42
45Regulatory liabilities arising from cost
of removal obligations 846 1,162
Regulatory liabilities arising from asset
retirement obligations 281 --
Fixed-price contracts and other derivatives 502 579
634
Due to unconsolidated affiliates 16 5Asset retirement obligations 303 --
Mandatorily redeemable preferred securities 21 --
Deferred credits and other liabilities 280 472
410
------ ------------- -------
Total deferred credits and other liabilities 1,765 1,775
------ ------2,960 2,927
------- -------
Contingencies and commitments (Note 12)
Total liabilities and shareholders' equity $5,123 $5,399
====== ======$ 6,463 $ 6,285
======= =======
See notes to Consolidated Financial Statements.
43
38
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars(Dollars in millionsmillions)
Years Endedended December 31,
2003 2002 2001 2000
------- ------- -------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income $ 340 $ 209 $ 183 $ 151
Adjustments to reconcile net income
to net cash provided by operating activities:
Depreciation and amortization 242 230 207 210
Customer refunds paid -- -- (127) (628)
Deferred income taxes and investment tax credits (7) (114) (9) 300
Non-cash rate reduction bond expense 68 82 66
32
GainLoss (gain) on disposition of assets 4 -- (22) --
Changes in other assets -- 123 (142) (152)
Changes in other liabilities (6) 46 5 (18)
Changes in working capital components:
Accounts receivable (9) 6 66
(55)Interest receivable (37) -- --
Due to/from affiliates - net 2 (61) (3)
(6)
Inventories (14) 23 (20)
--
Income taxes (14) 114 163 (149)
Other current assets (23) (6) 7
(3)
Accounts payable 34 21 (268) 252
Regulatory balancing accounts (56) 89 426 213
Other current liabilities 57 (5) 25 27
------- ------- -------
Net cash provided by operating activities 581 757 557 174
------- ------- -------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (444) (400) (307) (324)
Loan to/from affiliate - net 129 (199) (33) 593
Net proceeds from sale of assets 4 -- 42 24
Contributions to decommissioning funds (5) (5) (5)
Other - net (3) (7) (7) --
------- ------- -------
Net cash provided by (used in)used in investing activities (319) (611) (310) 288
------- ------- -------
CASH FLOWS FROM FINANCING ACTIVITIES
Dividends paid (206) (206) (156) (406)
Payments on long-term debt (66) (103) (118)
(149)Redemptions of preferred stock (1) -- --
Issuances of long-term debt -- -- 93 12
------- ------- -------
Net cash used in financing activities (273) (309) (181) (543)
------- ------- -------
Increase (decrease) in cash and cash equivalents (11) (163) 66 (81)
Cash and cash equivalents, January 1 159 322 256 337
------- ------- -------
Cash and cash equivalents, December 31 $ 148 $ 159 $ 322 $ 256
======= ======= =======
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION
Interest payments, net of amounts capitalized $ 68 $ 71 $ 83 $ 113
======= ======= =======
Income tax payments (refunds) - net $ 167 $ 92 $ (11) $ (8)
======= ======= =======
SUPPLEMENTAL SCHEDULE OF NON-CASH INVESTING
AND FINANCING ACTIVITIES
Property, plant and equipment contribution
fromAssets contributed by Sempra Energy $ 1 $ 86 $ --
Liabilities assumed (6) -- --
------- ------- -------
Net assets (liabilities) contributed
by Sempra Energy $ (5) $ 86 $ --
======= ======= =======
See notes to Consolidated Financial Statements.
44
39
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
For the yearsYears ended December 31, 2003, 2002 2001 and 20002001
(Dollars in millions)
Preferred Stock Accumulated
Not Subject Other Total
Comprehensive to Mandatory Common Retained Comprehensive Shareholders'
Income Redemption Stock Earnings Income(Loss) Equity
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 19992000 $ 79 $ 857 $ 460205 $ (3) $1,393
Net income/comprehensive income $ 151 151 151
Common stock dividends declared ===== (400) (400)
Preferred dividends declared (6) (6)
- ---------------------------------------------------------------------------------------------------------------
Balance at December 31, 2000 79 857 205 (3) 1,138$1,138
Net income/comprehensive income $ 183 183 183
Common stock dividends declared ===== (150) (150)====
Preferred dividends declared (6) (6)
Common stock dividends declared (150) (150)
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2001 79 857 232 (3) 1,165
Net income $ 209 209 209
Other comprehensive income
adjustment-pensionadjustment - pension (31) (31) (31)
---------
Comprehensive income $ 178
====
Preferred dividends declared ===== (6) (6)
Common stock dividends declared (200) (200)
Capital contribution 86 86
- -------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
Balance at December 31, 2002 79 943 235 (34) 1,223
Net income $ 340 340 340
Other comprehensive income
adjustment - pension (9) (9) (9)
----
Comprehensive income $ 331
====
Preferred dividends declared (6) (6)
Common stock dividends declared (200) (200)
Capital contribution (5) (5)
- ----------------------------------------------------------------------------------------------------------
Balance at December 31, 2003 $ 79 $ 943938 $ 235369 $ (34) $1,223
===============================================================================================================(43) $1,343
==========================================================================================================
See notes to Consolidated Financial Statements.
45
40
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SIGNIFICANT ACCOUNTING POLICIES
Business Combination
Sempra Energy was formed as a holding company for Enova Corporation
(Enova), the parent corporation of San Diego Gas & Electric (SDG&E),
and Pacific Enterprises (PE), the parent corporation of Southern
California Gas Company (SoCalGas), in connection with a business
combination of Enova and PE that was completed on June 26, 1998.
Principles of Consolidation
The Consolidated Financial Statements include the accounts of SDGSan
Diego Gas & Electric (SDG&E or the company) and its sole subsidiary,
SDG&E Funding LLC. All material intercompany accounts and transactions
have been eliminated.
As a subsidiary of Sempra Energy, the company receives certain
services therefrom, for which it is charged its allocable share of the
cost of such services. Management believes that cost is reasonable,
but probably less than if the company had to provide those services
itself.
Use of Estimates in the Preparation of the Financial Statements
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates
and assumptions that affect the reported amounts of revenues and
expenses during the reporting period, and the reported amounts of
assets and liabilities and the disclosure of contingent assets and
liabilities at the date of the financial statements. Actual amounts can
differ significantly from those estimates.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the
current year's presentation.
Regulatory Matters
Effects of Regulation
The accounting policies of the company conform with generally accepted
accounting principles for regulated enterprises and reflect the
policies of the California Public Utilities Commission (CPUC) and the
Federal Energy Regulatory Commission (FERC). SDG&E and its affiliate,
Southern California Gas Company (SoCalGas), are collectively referred
to herein as "the California Utilities."
The company prepares its financial statements in accordance with the
provisions of Statement of Financial Accounting Standards (SFAS) 71,
"Accounting for the Effects of Certain Types of Regulation," under
which a regulated utility records a regulatory asset if it is probable
that, through the ratemaking process, the utility will recover that
asset from customers. Regulatory liabilities represent future
reductions in
future rates for amounts due to customers. To the extent that portions
of the utility operations cease to be subject to SFAS 71, or recovery
is no longer probable as a result of changes in regulation or the
utility's competitive position, the related regulatory assets and
46
liabilities would be written off. In addition, SFAS 144, "Accounting
for the Impairment or Disposal of Long-Lived Assets" affects utility
plant and regulatory assets suchrequires that a
loss must be recognized whenever a regulator excludes all or part of
an asset's costutility plant or regulatory assets from ratebase. The application of SFAS 144 continues to be evaluated in
connection with industry restructuring. Information41
concerning regulatory assets and liabilities is described below in
"Revenues","Revenues," "Regulatory Balancing Accounts," and "Regulatory Assets and
Liabilities,Liabilities." and industry restructuring is described in Notes 10 and
11.
Regulatory Balancing Accounts
The amounts included in regulatory balancing accounts at December 31,
2002,2003, represent net payables (payables net of receivables) of $394$338
million and $575$394 million at December 31, 20022003 and 2001,2002, respectively.
The undercollected electric commodity costs accumulated under Assembly
Bill (AB) 265payables normally are anticipated to be recovered in rates (recovery is
expected to occur before the end of 2005) and are included in
"regulatory balancing accounts - net" at December 31, 2002.returned by reducing future rates.
Balancing accounts provide a mechanism for charging utility customers
the amount actually incurred for certain costs, primarily commodity
costs. As a result of California's electric-restructuring law,However, fluctuations in certainmost operating and maintenance costs
and consumption levels that had been
balanced now affect earnings from electric operations. In addition,
fluctuations in certain costs and consumption levels affect earnings
for SDG&E's natural gas operations.earnings. Additional information on
regulatory matters is included in Notes 10 and 11.
Regulatory Assets and Liabilities
In accordance with the accounting principles of SFAS 71, the company
records regulatory assets (which represent probable future revenues
associated with certain costs that will be recovered from customers
through the rate-making process) and regulatory liabilities (which
represent probable future reductions in revenue associated with amounts
that are to be credited to customers through the rate-making process).
They are amortized over the periods in which the costs are recovered
from or refunded to customers in regulatory revenues.as discussed
above.
Regulatory assets (liabilities) as of December 31 consist ofrelate to the
following:following matters:
(Dollars in millions) 2003 2002
2001
- ---------------------------------------------------------------------------------------------------------------------------------------------
Fixed-price contracts and other derivatives $ 638560 $ 715636
Recapture of temporary discount*rate reduction* 259 326 409
Undercollected electric commodity costs** -- 392
Deferred taxes recoverable in rates 273 190 162
Unamortized loss on retirement of debt - net 44 49 52
Employee benefit costs 35 3935
Cost of removal obligations** (846) (1,162)
Asset retirement obligations** (303) --
Other 5 2624 7
------- ---------------
Total $1,243 $1,795$ 46 $ 81
======= =======
47
========
- ----------------------------------------------------------------------
* In connection with electric industry restructuring, which is
described in Note 10, SDG&E temporarily reduced rates to its
small-usage customers. That reduction is being recovered in
rates through 2004.2007.
** The undercollected electric commodity costs accumulated under Assembly Bill
265 are anticipated to be recoveredSee discussion of SFAS 143 in rates before the end of 2005 and are
included in regulatory balancing accounts - net at December 31, 2002."New Accounting Standards".
42
Net regulatory assets are recorded on the Consolidated Balance Sheets
at December 31 as follows (dollarsfollows:
(Dollars in millions): 2003 2002 2001
- -----------------------------------------------------------------------
Current regulatory assets $ 134140 $ 158134
Noncurrent regulatory assets 1,056 1,111 1,638
Current regulatory liabilities* (23) (2)
(1)
------- -------Noncurrent regulatory liabilities (1,127) (1,162)
-------- --------
Total $1,243 $1,795
======= =======$ 46 $ 81
======== ========
- -----------------------------------------------------------------------
* IncludedAmount is included in other current liabilitiesOther Current Liabilities.
All theof these assets either earn a return, generally at short-term
rates, or the cash has not yet been expended and the assets are offset
by liabilities that do not incur a carrying cost.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with maturities of three
months or less at the date of purchase.
Collection AllowanceAllowances
The allowance for doubtful accounts receivable was $3$2 million, $5$3 million and $5
million at December 31, 2003, 2002 2001 and 2000,2001, respectively. The company
recorded a provision for doubtful accounts of $1 million, $4 million
and $9 million in 2003, 2002 and $6 million in 2002, 2001, and 2000, respectively.
Inventories
At December 31, 2002,2003, inventory shown on the Consolidated Balance
Sheets included natural gas of $9$21 million, and materials and supplies
of $37$39 million. The corresponding balances at December 31, 20012002 were $34$9
million and $36$37 million, respectively. Natural gas is valued by the
last-in first-out (LIFO) method. When the inventory is consumed,
differences between thisthe LIFO valuation and replacement cost will beare
reflected in customer rates. Materials and supplies at SDG&Ethe company are
generally valued at the lower of average cost or market.
UtilityProperty, Plant and Equipment
Utility plant primarily represents the buildings, equipment and other
facilities used by the company to provide natural gas and electric
utility services.
48
The cost of utility plant includes labor, materials, contract services and
related items, anditems. In addition, the cost of plant includes an allowance for
funds used during construction (AFUDC). The cost of most retired
depreciable utility plant, plus
removal costs minus salvage value is charged to
accumulated depreciation.43
Utility plant balances by major functional categories are as follows:
- -----------------------------------------------------------------------
Depreciation rates
Utility Plant for years ended
at December 31 December 31
- ---------------------------------------------------------------------------------------------------------------------------------------------
(Dollars in billions) 2003 2002 2003 2002 2001
2002 2001 2000
- ---------------------------------------------------------------------------------------------------------------------------------------------
Natural gas operations $ 1.0 $ 1.0 3.63% 3.62% 3.71%
3.79%
Electric distribution 3.2 3.0 2.94.70% 4.66% 4.67% 4.67%
Electric transmission 0.9 0.80.9 3.09% 3.17% 3.19%
3.21%
Other electric 0.7 0.5 0.39.53% 9.37% 8.46% 8.33%
------ ------
Total $ 5.45.8 $ 5.05.4
====== ======
- -----------------------------------------------------------------------
Accumulated depreciation and decommissioning of natural gas and
electric utility plant in service were $0.6$0.3 billion and $2.2$1.4 billion,
respectively, at December 31, 2002,2003, and were $0.5$0.3 billion and $2.1$1.3
billion, respectively, at December 31, 2001.2002. See discussion of SFAS 143
under "New Accounting Standards." Depreciation expense is based on the
straight-line method over the useful lives of the assets or a shorter
period prescribed by the CPUC. See Note 10 for discussion of the sale
of generation facilities and industry restructuring. Maintenance costs
are expensed as incurred.
AFUDC, which represents the cost of funds used to finance the
construction of utility plant, is added to the cost of utility plant.
AFUDC also increases income, partly as an offset to interest charges
and partly as a component of other income, shownOther Income - Net in the Statements of
Consolidated Income, although it is not a current source of cash.
AFUDC amounted to $17 million, $21 million and $9 million for 2003,
2002 and $8 million for 2002, 2001, and 2000, respectively.
Long-Lived Assets
The company periodically evaluates whether events or circumstances have
occurred that may affect the recoverability or the estimated useful
lives of long-lived assets. Impairment occurs when the estimated future
undiscounted cash flows is less than the carrying amount of the assets.
If that comparison indicates that the assets' carrying value may be
permanently impaired, such potential impairment is measured based on
the difference between the carrying amount and the fair value of the
assets based on quoted market prices or, if market prices are not
available, on the estimated discounted cash flows. This calculation is
performed at the lowest level for which separately identifiable cash
flows exist. See further discussion of SFAS 144 in "New Accounting
Standards".
49
Nuclear-DecommissioningNuclear Decommissioning Liability
At December 31, 2002, in accordance with SFAS 71, the company had
recorded a $355 million regulatory liability representing its share of
the estimated future decommissioning costs of the San Onofre Nuclear
Generating Station (SONGS). In addition, Deferred Credits and 2001, deferred credits and other liabilities
includeOther
Liabilities included $139 million and $151 million, respectively, of accrued decommissioning costs
associated with SONGS. As of December 31, 2003, as the company's interest in San
Onofre Nuclear Generating Station (SONGS) Unit 1, which was permanently
shut down in 1992. The corresponding liabilityresult of
implementing SFAS 143, "Accounting for SONGS Units 2Asset Retirement Obligations,"
the company had asset retirement obligations and 3
decommissioning (included in accumulated depreciation and amortization)
is $355related regulatory
liabilities of $316 million and $375$303 million, at December 31, 2002 and 2001, respectively. Additional
information on SONGS decommissioning costs is included below in "New
Accounting Standards".Standards."
Legal Fees
Legal fees that are associated with a past event and not expected to be
recovered in the future are accrued when it is probable that they will
be incurred.
44
Comprehensive Income
Comprehensive income includes all changes, except those resulting from
investments by owners and distributions to owners, in the equity of a
business enterprise from transactions and other events, including
foreign-currency translation adjustments, minimum pension liability
adjustments, unrealized gains and losses on marketable securities that
are classified as available-for-sale, and certain hedging activities. The components of other
comprehensive income are shown in the Statements of Consolidated
Changes in Shareholders' Equity.
Revenues
Revenues are primarily derived from deliveries of electricity and
natural gas to customers and changes in related regulatory balancing
accounts. Revenues from electricity and natural gas sales and services
are generally recorded under the accrual method and these revenues are
recognized upon
delivery. The portion of SDG&E's electric commodity that was procured
for its customers by the California Department of Water Resources (DWR)
and delivered by SDG&E is not included in SDG&E's revenues or costs.
For 2001, California Power Exchange (PX) and Independent System
Operator (ISO) power revenues have been netted against purchased-power
expense to avoid double-counting asof power sold into and then
repurchased from the PX/ISO. During 2003, costs associated with long-
term contracts allocated to SDG&E sold power intofrom the PX/ISODWR were also not included
in the Statements of Consolidated Income, since the DWR retains legal
and then
purchased power therefrom.financial responsibility for these contracts. Refer to Note 10 for
a discussion of the electric industry restructuring. Operating revenue
includes amounts for services rendered but unbilled (approximately one-halfone-
half month's deliveries) at the end of each year.
OperatingThrough 2003, operating costs of SONGS Units 2 and 3, (includingincluding nuclear
fuel and nuclear fuelrelated financing costs)costs, and incremental capital expenditures
arewere recovered through the Incremental Cost Incentive Pricing (ICIP)
mechanism which allowsallowed SDG&E to receive approximately 4.4 cents per kilowatt-hour
(kWh) through 2003.for SONGS generation. Any differences between these costs and the
incentive price affectaffected net income and, forincome. For the year ended December 31,
2002, the2003, ICIP contributed $50$53 million to SDG&E's net income. The CPUC has rejected an administrative law judge's proposed
decision to end ICIP prior to its December 31, 2003 scheduled
expiration date. However,Beginning in
2004 the CPUC has also denied the previously
approved market-based pricing for SONGS beginning in 2004 and instead provided for traditional rate-making treatment, under
which the SONGS ratebase would beginstart over at zero,January 1, 2004,
essentially eliminating earnings from SONGS until ratebase grows. The company has applied for rehearing of
this decision.
50
except from future
increases in ratebase.
Additional information concerning utility revenue recognition is
discussed above under "Regulatory Matters."
Related Party Transactions - Loans to Unconsolidatedwith Affiliates
SDG&E has a promissory note receivable from Sempra Energy which bears a
variable interest rate based on short-term commercial paper rates, and
is due on demand. The note balance (net of intercompany payables) was
$250$96 million and $52$259 million at December 31, 2003 and 2002,
and 2001, respectively. At December 31, 2001, the
"Due from unconsolidated affiliates" account balance also included $24
million of offsetting working capital balances with Sempra Energy
affiliates. In addition, at December 31, 2003 and 2002, SDG&E had $42$55
million and $33 million due from affiliates, and at December 31, 2002
had $3 million due to Sempra Energy affiliates. SDG&E also had $16$21 million and $5$16
million in non-current liabilities due to Sempra Energy at December 31,
2003 and 2002, and 2001, respectively.45
New Accounting Standards
SFAS 132 (revised 2003), "Employers Disclosures about Pensions and
Other Postretirement Benefits": This statement revised employers'
disclosures about pension plans and other postretirement benefit plans.
It requires disclosures beyond those in the original SFAS 132 about the
assets, obligations, cash flows and net periodic benefit cost of
defined benefit pension plans and other defined postretirement plans.
It does not change the measurement or recognition of those plans.
SFAS 143, "Accounting for Asset Retirement Obligations": SFAS 143,
issued in July 2001, addresses financial accounting and reporting for
obligations associated with the retirement of tangible long-lived
assets and the associated asset retirement costs. ThisIt applies to legal
obligations associated with the retirement of long-lived assets that
result from the acquisition, construction, development and/or normal
operation of long-lived assets, such as nuclear plants. It requires
entities to record the fair value of a liability for an asset
retirement obligation in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying
amount of the related long-lived asset by the present value of the
future retirement cost. Over time, the liability is accreted to its
full value and paid, and the capitalized cost is depreciated over the
useful life of the related asset.
SFAS 143 is effective for financial
statements issued for fiscal years beginning after June 15, 2002. The
items noted below were identified by the company to have a material
asset retirement obligation.
Adoption of SFAS 143 will change the accounting for the decommissioning
of the company's share of SONGS. Prior to the adoption of SFAS 143 the
company recorded the obligation for decommissioning over the lives of
the plants. At December 31, 2002, the company's share of
decommissioning cost for the SONGS' units has been estimated to be $309
million in 2002 dollars, based on a 2001 cost study filed with the
CPUC. The adoption of this standard, effective January 1, 2003 will
require a cumulative adjustment to adjust plant assets and
decommissioning liabilities toresulted in the values they would have been had this
standard been employed from the in-service datesrecording
of the plants. Upon
adoption of SFAS 143 in 2003, the company will record an addition of
$70 million to utility plant of $71 million, representing the
company's share of SONGS estimated future decommissioning costs (as
discounted to the present value at the datedates the various units began
operation), and accumulated depreciation of $41 million related to the
increase to utility plant, for a net increase of $30 million. In
addition, the company recorded a corresponding retirement obligation
liability of $309 million. The
nuclear decommissioning trusts' balancemillion (which includes accretion of $494 million atthat discounted
value to December 31, 2002 represents amounts collected for future decommissioning costs2002) and
earnings thereon, and has a corresponding offset in accumulated
depreciation ($355 million related to SONGS Units 2 and 3) and deferred
credits ($139 million related to SONGS Unit 1). The difference between
the amounts results in a regulatory liability of $214$215 million
to
51
reflect that SDG&E has collected the funds from its customers more
quickly than SFAS 143 would accrete the retirement liability and
depreciate the asset. These liabilities, less the $494 million recorded
as accumulated depreciation prior to January 1, 2003 (which represents
amounts collected for future decommissioning costs), comprise the
offsetting $30 million. See further discussion of SONGS'
decommissioning and the related nuclear decommissioning trusts
in Note 4.
As ofOn January 1, 2003, the company hadrecorded additional asset retirement
obligations estimated to be $12of $10 million associated with the future retirement of a
former power plant.46
The change in the asset retirement obligations for the year ended
December 31, 2003 is as follows (dollars in millions):
Balance as of January 1, 2003 $ --
Adoption of SFAS 143 319
Accretion expense 21
Payments (14)
------
Balance as of December 31, 2003 $ 326*
======
* The current portion of the obligation is included in Other Current
Liabilities on the Consolidated Balance Sheets.
Had SFAS 143 been in effect on January 1, 2002, the asset retirement
obligation liability would have been $354 million as of that date.
Except for the items noted above, the company has determined that there
is no other material retirement obligation associated with tangible
long-lived assets.
Implementation of SFAS 143 has had no effect on results of operations
and is not expected to have a significant effect in the future.
The company collects estimated removal costs in rates through
depreciation in accordance with regulatory treatment. SFAS 143 also
requires the company to reclassify estimated removal costs, which have
historically been recorded in accumulated depreciation, to a regulatory
liability. At December 31, 2003 and 2002, the estimated removal costs
recorded as a regulatory liability were $846 million and $1.2 billion,
respectively. The decrease in the amount during 2003 is due to SFAS 143
requiring further reclassification of those costs to a legal obligation
(primarily SONGS costs) to Asset Retirement Obligations.
SFAS 144, "Accounting for Impairment or Disposal of Long-Lived Assets":
In August 2001, the Financial Accounting Standards Board (FASB) issued
SFAS 144, which replaces SFAS 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of." SFAS 144It
applies to all long-lived assets, including
discontinued operations.assets. Among other things, SFAS 144 requires
that those long-lived assets classified as held for sale be measured at
the lower of carrying amount (cost less accumulated depreciation) or
fair value less cost to sell. Discontinued operations willAdoption of this statement on January 1,
2002 had no longer be measured at net realizable
value or include amounts for operating losses that have not yet
occurred. SFAS 144 also broadensimpact on the reporting of discontinued
operations to include all components of an entity with operations that
can be distinguished from the rest of the entity and that will be
eliminated from the ongoing operations of the entity in a disposal
transaction. The company has identified no material effects to thecompany's financial statements from the implementation of SFAS 144.statements.
SFAS 148, "Accounting for Stock-Based Compensation - Transition and
Disclosure": In December 2002, the FASB issued SFAS 148, an amendment
to SFAS 123, "Accounting for Stock-Based Compensation," which gives
companies electing to expense employee stock options three methods to
do so. In addition, the statement amends the disclosure requirements to
require more prominent disclosure about the method of accounting for
stock-based employee compensation and the effect of the method used on
reported results in both annual and interim financial statements.
The companySempra Energy has elected to continue using the intrinsic value method
of accounting for stock-based compensation. Therefore, the amendment to
SFAS 123148 will
not have any effect on the company's financial statements. See Note 7
for additional information regarding stock-based compensation.
47
SFAS 149, "Amendment of Statement 133 on Derivative Instruments and
Hedging Activities": Effective July 1, 2003, SFAS 149 amended and
clarified accounting for derivative instruments, including certain
derivative instruments embedded in other contracts, and for hedging
activities under SFAS 133. Under SFAS 149 natural gas forward contracts
that are subject to unplanned netting generally do not qualify for the
normal purchases and normal sales exception. ("Unplanned netting"
refers to situations whereby contracts are settled by paying or
receiving money for the difference between the contract price and the
market price at the date on which physical delivery would have
occurred.) In addition, effective January 1, 2004, power contracts that
are subject to unplanned netting and that do not meet the normal
purchases and normal sales exception under SFAS 149 will continue to be
marked to market. Implementation of SFAS 149 did not have a material
impact on reported net income.
SFAS 150, "Accounting for Certain Financial Instruments with
Characteristics of Liabilities and Equity": On January 22, 2003, the
FASB directed its staff to prepare a draft of SFAS 149. The final draft
is expected to be issued in March 2003. TheThis statement will establishestablishes
standards for accounting forhow an issuer classifies and measures certain financial
instruments with characteristics of both liabilities equity, or both. Subsequent to the issuance ofand equity. SFAS
149,150 requires that certain investments that are currentlymandatorily redeemable financial instruments
previously classified as equity in the financial statements might have tomezzanine section of the balance sheet be
reclassified as liabilities. In
addition, the FASB decided thatThe company adopted SFAS 149 will prohibit the presentation150 beginning
July 1, 2003 by reclassifying $24 million of certain items in the mezzanine section (the portion of the balance
sheet between liabilities and equity) of the statement of financial
position. For example, certain mandatorily redeemable
preferred stock which is currently includedto Deferred Credits and Other Liabilities and to Other
Current Liabilities on the Consolidated Balance Sheets.
Emerging Issues Task Force (EITF) 03-11, "Reporting Realized Gains and
Losses on Derivative Instruments that are Subject to FASB Statement No.
133, Accounting for Derivative Instruments and Hedging Activities and
Not 'Held for Trading Purposes' as Defined in EITF 02-3, Issues
Involved in Accounting for Derivative Contracts Held for Trading
Purposes and Contracts Involved in Energy Trading and Risk Management
Activities": During 2003, the EITF reached a consensus that determining
whether realized gains and losses on physically settled derivative
contracts not held for trading purposes should be reported in the
mezzanine section, may be classified
asincome statement on a liability once SFAS 149 goes into effect. The proposed effective
dategross or net basis is a matter of SFAS 149 is July 1,judgment that
depends on the relevant facts and circumstances. Adoption of EITF 03-11
in 2003 fordid not have a significant impact to the company.
52
company's financial
statements and the company does not expect a significant impact in the
future.
FASB Interpretation No. (FIN) 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees": In November 2002, the FASB
issued InterpretationFIN 45, which elaborates on the disclosures to be made in
interim and annual financial statements of a guarantor about its
obligations under certain guarantees that it has issued. It also
clarifies that a guarantor is required to recognize, at the inception
of a guarantee, a liability for the fair value of the obligation
undertaken in issuing a guarantee. Initial recognition and measurement
provisions of the Interpretation are applicable on a prospective basis
to guarantees issued or modified after December 31, 2002. The
disclosure requirements are effective for financial statements of
interim or annual periods ending after December 15, 2002. As of December 31, 2002,2003, the company
did not have any outstanding guarantees.
FASB Staff Position (FSP) 106-1, "Accounting and Disclosure
Requirements Related to the Medicare Prescription Drug, Improvement and
Modernization Act of 2003": Issued January 12, 2004, FSP 106-1 permits
a sponsor of a postretirement health care plan that provides a
48
prescription drug benefit to make a one-time election to defer
accounting for the effects of the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (the Act). The company has
elected to defer the effects of the Act as provided by FSP 106-1. Any
measure of the accumulated postretirement benefit obligation or net
periodic postretirement benefit cost in the financial statements or the
accompanying notes do not reflect the impact of the Act on the plans.
At this time, specific authoritative guidance on the accounting for the
federal subsidy provided by the Act is pending and that guidance could
require the company to change previously reported information.
Other Accounting Standards: During 20022003 and 20012002 the FASB and the Emerging Issues Task Force (EITF)EITF
issued several statements that are currently not applicable to the company.company but
could be in the future. In July 2001, the FASB issued SFAS 142,
"Goodwill and Other Intangible Assets,Assets." which addresses how
intangible assets that are acquired individually or with a group of
other assets (but not those acquired in a business combination) should
be accounted for in financial statements upon their acquisition. In April 2002, the FASB issued
SFAS 145, which rescinds SFAS 4, "Reporting Gains and Losses from
Extinguishment of Debt", and SFAS 64, "Extinguishments of Debt Made to
Satisfy Sinking-Fund Requirements." In June 2002, the FASB issued SFAS
146, "Accounting for Costs Associated with Exit or Disposal
Activities,Activities." which addresses accounting for
restructuring and similar costs. SFAS 146 supersedes previous accounting guidance,
principally EITF Issue 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including
Certain Costs Incurred in a Restructuring)." In October 2002, the FASB issued SFAS 147, "Accounting
for Certain Financial Institutions - an amendment of SFAS 72 and 144
and FASB Interpretation 9," which applies to acquisitions of financial
institutions. In June 2002, a consensus wasconsensuses were
reached in EITF Issue 02-3 which codifies and reconciles existing guidance on the recognition and
reportingrescission of gains and losses on energy trading contracts and addresses
other aspects of theEITF 98-10, both dealing
with mark-to-market accounting for contracts involved in energy
trading and risk management activities. In October 2002, the EITF
reached a consensus to rescind EITF Issue 98-10, "Accounting for Energy
Trading Contracts," the basis for mark-to-market accounting used for
recording energy-trading activities. In
January 2003, the FASB issued Interpretation 46, "Consolidation of
Variable Interest Entities" which
addresses consolidation by business enterprises an interpretation of variable interest
entities.ARB No. 51."
NOTE 2. SHORT-TERM BORROWINGS
At December 31, 2002,Committed Lines of Credit
SDG&E and its affiliate SoCalGas hadhave a combined revolving line of
credit, under which each utility individually couldmay borrow up to $300
million, subject to a combined borrowing limit for both utilities of
$500 million. Borrowings under the agreement which
are available for general corporate purposes including support for
commercial paper and variable-rate long-term debt, bear interest at rates
varying with market rates and SDG&E's credit rating. ThisThe revolving
credit commitment expires in May 2003,2004, at which time the outstanding
borrowings may be converted into a one-year term loan 53
subject to any
requisite regulatory approvals related to long-term debt. ThisThe agreement
requires SDG&E to maintain a debt-to-total capitalization ratio (as
defined in the agreement) of not to exceed 60 percent. The rights, obligations and covenants of each utilityBorrowings under
the agreement are individual rather than joint with thoseobligations of the otherborrowing utility and a
default by one utility would not constitute a default or preclude
borrowings by the other. These lines of credit were unused at December 31, 2002. At
December 31, 2002, SDG&E had no commercial paper outstanding.have never been drawn
upon.
49
NOTE 3. LONG-TERM DEBT
- -------------------------------------------------------------------
December 31,
(Dollars in millions) 2003 2002 2001
- -------------------------------------------------------------------
First-mortgageFirst Mortgage bonds
6.8% June 1, 2015 $ 14 $ 14
5.9% June 1, 2018 68 68
5.9% to 6.4% September 1, 2018 176 176
6.1% September 1, 2019 35 35
Variable rates (1.34% to 1.35%(1.25% at
December 31, 2002)2003) September 1, 2020 58 58
5.85% June 1, 2021 60 60
6.4% and5.25% to 7% December 1, 2027 225 225
8.5% April 1, 2022 -- 10
7.625% June 15, 2002 -- 28
------------------------
636 674636
------------------------
UnsecuredOther long-term debt
5.9% June 1, 2014 130 130
Variable rates (1.75%(1.46% at
December 31, 2002)2003) July 1, 2021 39 39
Variable rates (2.00%(1.45% at
December 31, 2002)2003) December 1, 2021 60 60
6.75% March 1, 2023 25 25
------------------------
254 254
------------------------
Rate-reduction bonds, 6.19%6.31% to 6.37% at
December 31, 20022003 payable annually
through 2007 263 329
395
------------------------
1,153 1,219 1,323
Less:
Current portion of long-term debt 66 93
Unamortized discount on long-term debt -- 1(66) (66)
------------------------
Total $1,087 $1,153 $1,229
- -------------------------------------------------------------------
Maturities of long-term debt are $66 million in 2003, $66 million in
2004, $66 million in 2005 $66 million inand 2006,
$66$65 million in 2007 and $889$890 million thereafter. Holders of variable-ratevariable-
rate bonds may require the issuer to repurchase them prior to scheduled
maturity. However, since repurchased bonds would be remarketed and
funds for repurchase are 54
provided by revolving lines of credit agreements (which
are generally renewed upon expiration and which are described in Note
2), it is assumedexpected that the bonds will be held to maturity for purposes of determining the maturities listedstated
above.
First-mortgageCallable Bonds
At the company's option, certain bonds are callable at various dates.
Of SDG&E's callable bonds, $597 million are callable in 2004, $105
million in 2005 and $45 million thereafter.
50
First Mortgage Bonds
The first-mortgagefirst mortgage bonds are secured by a lien on SDG&E's utility
plant. SDG&E may issue additional first-mortgagefirst mortgage bonds upon compliance
with the provisions of its bond indenture, which requires, among other
things, the satisfaction of pro forma earnings-coverage tests on first-first
mortgage bond interest and the availability of sufficient mortgaged
property to support the additional bonds.bonds, after giving effect to prior
bond redemptions. The most restrictive of these tests (the property
test) would permit the issuance, subject to CPUC authorization, of an
additional $2.1$2.3 billion of first-mortgagefirst mortgage bonds at December 31, 2002.2003.
During the first quarter of 2001, SDG&E remarketed $150 million of
variable-rate first-mortgagefirst mortgage bonds for a five-year termvarious terms at a fixed rate of
7%. $45 million of these bonds came to term on December 1, 2003 and
were remarketed to maturity with a rate of 5.25%. At SDG&E's option,
the remaining bonds may be remarketed at a fixed or floating rate at
December 1, 2005, the expiration of the fixed term.terms.
In June and July 2002, SDG&E paid offat maturity its $28 million 7.625% first-first
mortgage bonds andbonds. In July 2002 the company optionally redeemed its $10
million 8.5% first-mortgage bonds, respectively.
Callable Bonds
Atfirst mortgage bonds.
Unsecured Long-term Debt
Various long-term obligations totaling $254 million are unsecured at
December 31, 2003.
In February 2001, SDG&E's option, certain bonds may be called at a premium, including
$157&E remarketed $25 million of variable-rate
unsecured bonds that are callable at various dates
in 2003. Of SDG&E's remaining callable bonds, $460 million are callable
in 2003, $25 million in 2004, and $105 million in 2005.as 6.75 percent fixed-rate debt for a three-year term.
Rate-Reduction Bonds
In December 1997, $658 million of rate-reduction bonds were issued on
behalf of SDG&E at an average interest rate of 6.26 percent. These
bonds were issued to facilitate the 10%10 percent rate reduction mandated
by California's electric-restructuring law, which is described in Note 10.
These bondslaw. They are being repaid over
ten years by SDG&E's residential and small-commercial customers viathrough
a specified charge on their electricity bills. These bonds are secured
by the revenue streams collected from customers and are not secured by,
or payable from, utility assets.
The sizes of the rate-reduction bond issuances were set so as to make
the investor owned utilities (IOUs) neutral as to the 10% rate
reduction, and were based on a four-year period to recover stranded
costs. Because SDG&E recovered its stranded costs in only 18 months
(due to the greater-than-anticipated plant-sale proceeds), the bond
sale proceeds were greater than needed. Accordingly, during the third
quarter of 2000, SDG&E returned to its customers $388 million of
surplus bond proceeds in accordance with a June 8, 2000 CPUC decision.
The bonds and their repayment schedule are not affected by this refund.
Unsecured Long-term Debt
In February 2001, SDG&E remarketed $25 million of variable-rate
unsecured bonds as 6.75 percent fixed-rate debt for a three-year term.
At SDG&E's option, the bonds may be remarketed at a fixed or floating
55
rate at February 29, 2004, the expiration of the fixed term. Various
long-term obligations totaling $254 million are unsecured at December
31, 2002.
Interest-Rate Swaps
The company periodically enters into interest-rate swap agreements to
moderate its exposure to interest-rate changes and to lower its overall
cost of borrowing. As of December 31, 2003, the company did not have
any outstanding swap agreements.
During 2002 and 2001, SDG&E had an interest-rate swap agreement that matured in 2002 that
effectively fixed the interest rate on $45 million of variable-rate
underlying debt at 5.4 percent. This floating-to-fixed-rate swap did
not qualify for hedge accounting and, therefore, the gains and losses
associated with the change in fair value are recorded in the Statements
of Consolidated Income. The effect on net income was a $1 million gain
in 2002 and a $1 million loss in 2001.
See additional discussion of interest-rate swaps in Note 8.
Financial Covenants
SDG&E's first-mortgage bond indenture requires the satisfaction of
certain bond interest coverage ratios and the availability of
sufficient mortgaged property to issue additional first-mortgage bonds,
but do not restrict other indebtedness. Note 2 discusses the financial
covenants applicable to short-term debt.51
NOTE 4. FACILITIES UNDER JOINT OWNERSHIP
SONGS and the Southwest Powerlink transmission line are owned jointly
with other utilities. The company's interests at December 31, 2002,2003, are
as follows:
(Dollars in millions) Southwest
Project SONGS Powerlink
- --------------------------------------------------------------------
Percentage ownership (1) 20% 88%89%
Utility plant in service $ 76 $22211 $237
Accumulated depreciation and amortization $ 53 $1345 $141
Construction work in progress $ 5-- $ 1227
- --------------------------------------------------------------------
(1) SDG&E's 20% ownership in SONGS has been fully recovered and is no
longer included under utility plant and accumulated depreciation.
The amounts specified above for SONGS represent wholly owned substation
equipment. As of December 31, 2003, the company has fully recovered its
interest in SONGS through the ICIP mechanism, which ended in December
31, 2003. Additional information concerning the ICIP mechanism is
provided in Note 10.
The company and the other owners each hold its interest as an undivided
interest as tenants in common. Each owner is responsible for financing
its share of each project and participates in decisions concerning
operations and capital expenditures.
The company's share of operating expenses is included in the Statements
of Consolidated Income.
Participants in each project must provide their
own financing. The amounts specified above for SONGS include nuclear
production, transmission and other facilities. Certain substation
equipment at SONGS is wholly owned by the company.
SONGS Decommissioning
Objectives, work scope and procedures for the future dismantling and
decontamination of the SONGS units must meet the requirements of the
56
Nuclear Regulatory Commission, the Environmental Protection Agency, the
CPUC and other regulatory bodies.
The company's share of decommissioning costs for the SONGS units is
estimated to be $309$316 million in 2002 dollars, based on a 2001 cost
study completed and filed with the CPUC in 2002. At this time, the
cost study and resulting contributions are expected to be finalized and
approved or disapproved by the CPUC in April of 2003.2003 dollars. Cost studies are updated
every three years, and approved bywith the CPUC. The next such
update is expected to occurbe submitted to the
CPUC for its approval in 2005. Rate recovery of decommissioning costs is
allowed until the time that the costs are fully recovered, and is subject
to adjustment every three years based on the costs allowed by regulators.
The amount accrued each year is currently being collected
in rates. Currently, collectionsCollections are authorized to continue until 2013, but may be extended upon requestby
CPUC approval until 2022, at which time the SONGS' operating license ends
and the decommissioning of SONGS 2 and 3 would be expected to the CPUC until 2022. The requested
amount is considered sufficient to cover the company's share of future
decommissioning costs.begin.
Payments to the nuclear decommissioning trusts (described below underin "Nuclear
Decommissioning Trusts") are expected to continue until 2013 at which time
sufficient funds have beenare expected to be collected to fully decommission SONGS, whichSONGS.
If funds are not sufficient, additional future rate recovery is not expected
to begin before 2022.occur.
52
The amounts collected in rates are invested in the externally managed
trust funds. The securities held by these trusts are considered
available for sale. These trusts are shown on the Consolidated Balance
Sheets at market value. At December 31, 2003, these trusts reflected
unrealized gains of $159 million with the offsetting credits recorded
on the Consolidated Balance Sheets to Asset Retirement Obligations and
the related regulatory liabilities. At December 31, 2002, these trusts
reflected unrealized gains of $95 million with the offsetting credits
recorded to Deferred Credits and Other Liabilities and the related
regulatory liabilities.
Unit 1 was permanently shut down in 1992, and physical decommissioning
began in January 2000. Several structures, foundations and large
components have been dismantled, removed, and removed.disposed of. Preparations
have been made for the remaining major work to be performed in 20032004 and
beyond. That work will include dismantling, removal and disposal of all
remaining Unit 1 equipment and facilities (both nuclear and non-nuclear
components), decontamination of the site and completion of an on-site
storage facility for Unit 1 spent fuel. These activities are expected
to be completed byin 2008.
The amounts collected in rates are invested in externally managed trust
funds (described below under "Nuclear Decommissioning Trusts"). The
securities held by the trust are considered available for sale and the
trust is shown on the Consolidated Balance Sheets at market value.
These values reflect unrealized gains of $95 million and $122 million
at December 31, 2002, and 2001, respectively, with the offsetting
credit recorded to accumulated depreciation and amortization on the
Consolidated Balance Sheets.
See discussion regarding the impact of SFAS 143 in Note 1.
Nuclear Decommissioning Trusts
SDG&E has established a Nonqualified Nuclear Decommissioning Trust and
a Qualified Nuclear Decommissioning Trust.Trust to provide funds for the
decommissioning of SONGS as described above. Amounts held by these
trusts are invested in accordance with CPUC guidelines prohibit investments in
derivatives and securities of Sempra Energy or related companies. They
alsoregulations that establish
maximum amounts for investments in equity securities (50 percent of the
qualified trust and 60 percent of the nonqualified trust),
international equity securities (20 percent) and securities of electric
utilities having ownership interests in nuclear power plants (10
percent). Not less than 50 percent of the equity portion of the
Trusts shallthese
trusts must be invested passively.
57
At December 31, 20022003 and 2001,2002, trust assets were allocated as follows
(dollars in millions):
Qualified Trust Nonqualified Trust
-----------------------------------------
2003 2002 20012003 2002
2001
------------- -------------------------------
Domestic equity $143 $144$ 163 $ 143 $ 43 $ 36
$ 48
Foreign equity 88 69 76 -- --
---- --------- ----- ---- ----
Total equity 251 212 22043 36 48
Total fixed income 249 220 22527 26
33
---- --------- ----- ---- ----
Total $432 $445$ 500 $ 432 $ 70 $ 62
$ 81===== ===== ==== ==== ==== ====
Decommissioning cost studies are conducted every three years to
determine the appropriate level of contributions to be collected in
utility-customer rates to ensure adequate funding at the
decommissioning date.
Customer contribution amounts are determined by estimates of after-tax
investment returns, decommissioning costs and decommissioning cost
escalation rates. Lower actual investment returns or higher actual53
decommissioning costs would result in an increase in customer
contributions.
Additional information regarding SONGS is included in Notes 10 and 12.
NOTE 5. INCOME TAXES
The reconciliation of the statutory federal income tax rate to the
effective income tax rate is as follows:
Years ended December 31,
2003 2002 2001
2000
- --------------------------------------------------------------------------------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 3.9 2.3 5.9 6.6
State income taxes - net of
federal income tax benefit 6.4 6.1 5.8
8.5
Tax credits (0.6) (0.9) (0.9) (1.5)
Settlement of Internal Revenue Service audit (11.7) (8.6) -- --
Other - net (2.7) (3.6) (2.3)
0.2
---------------------------------------------------
Effective income tax rate 30.3% 30.3% 43.5%
48.8%
- ---------------------------------------------------------------------
58
-----------------------------------------------------------------------
The components of income tax expense are as follows:
(Dollars in millions) 2003 2002 2001 2000
- ---------------------------------------------------------------------
Current
Federal $ 122 $ 164 $ 120
$(115)
State 33 41 30
(41)
-----------------------------------------------
Total current taxes 155 205 150
(156)
-----------------------------------------------
Deferred
Federal (9) (93) 7
244
State 5 (18) (13) 59
------------------------
Total deferred taxes (4) (111) (6) 303
------------------------
Deferred investment tax credits - net (3) (3) (3)
------------------------
Total income tax expense $ 148 $ 91 $ 141
$ 144
- ---------------------------------------------------------------------
Federal----------------------------------------------------------------------
On the Statements of Consolidated Income, federal and state income
taxes are allocated between operating income and other income.
SDG&E is included in the consolidated income tax return of Sempra
Energy and is allocated income tax expense from Sempra Energy in an
amount equal to that which would result from SDG&E's having always
filed a separate return.54
Accumulated deferred income taxes at December 31 consist ofrelate to the
following:
(Dollars in millions) 2003 2002 2001
- ----------------------------------------------------------------------
Deferred tax liabilities:
Differences in financial and
tax bases of utility plant $ 552699 $ 391552
Regulatory balancing accounts 189 212 432
Loss on reacquired debt 19 22
24
Other 10 85 75
--------------------
Total deferred tax liabilities 917 871 922
--------------------
Deferred tax assets:
Investment tax credits 29 3129
Unbilled revenue -- 29
Deferred compensation 76 46
Contingent liabilities 44 44
State income taxes 24 20
Federal benefit of state income taxes 29 24
Other 187 12415 24
--------------------
Total deferred tax assets 217 216 155
--------------------
Net deferred income tax liability $ 655700 $ 767655
- ----------------------------------------------------------------------
59
The net deferred income tax liability is recorded on the Consolidated
Balance Sheets at December 31 as follows:
(DollarsDollars in millions) 2003 2002
2001
- ------------------------------------------------------------------------------------------------------------------------------------------
Current liability $ 5383 $ 12853
Noncurrent liability 617 602
639
--------------------------------------
Total $ 700 $ 655
$ 767
- ------------------------------------------------------------------------------------------------------------------------------------------
Resolution of Certain Internal Revenue Service Matters
The company favorably resolved matters related to various prior years'
returns during 2003. The primary issue involving the treatment of
utility balancing accounts for the company was resolved following the
issuance of an IRS Revenue Ruling and resolution of factual issues
involving these claims with the IRS. The total after-tax earnings and
future cash flows for all IRS issues was $79 million.
NOTE 6. EMPLOYEE BENEFIT PLANS
Pension and Other Postretirement Benefits
The company sponsors several qualifiedhas funded and nonqualified pensionunfunded noncontributory defined benefit
plans that together cover substantially all of its employees. The
plans provide defined benefits based on years of service and final
average salary.
55
The company also has other postretirement benefit plans forcovering
substantially all of its employees. The life insurance plans are
noncontributory and the health care plans are contributory, with
participants' contributions adjusted annually. Other postretirement
benefits include retiree life insurance, medical benefits for retirees
and their spouses.
During 2002, the company had amendments to other postretirement
benefit plans related to the transfer of employees to SDG&E from the
affiliates, and changes to their specific benefits which resulted in a
decrease in the benefits obligation of $7 million. The amortization of
these changes will affect pension expense in future years.
During 2001, the company participated in a voluntary separation
program. As a result, the companyit recorded a $13 million special termination
benefit, a $1 million curtailment cost and a $19 million settlement
gain.
During 2000,There were no amendments to the company participatedcompany's pension and other
postretirement benefit plans in another voluntary separation
program. As a result,2003.
December 31 is the company recorded a $5 million special
termination benefit.
60
measurement date for the pension and other
postretirement benefit plans.
The following tables provide a reconciliation of the changes in the
plans' projected benefit obligations andduring the latest two years, the
fair value of assets over
the two years, and a statement of the funded status as of eachthe
latest two year end:ends:
Other
Pension Benefits Postretirement Benefits
---------------------------------------------------------------------------------------
(Dollars in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------
CHANGE IN PROJECTED BENEFIT OBLIGATION:
Net obligation at January 1 $ 613 $ 448 $ 60 $ 45
Service cost 14 16 2 1
Interest cost 40 40 4 4
Actuarial loss 49 62 14 9
Transfer of liability from Sempra Energy 7 109 -- 11
Benefit payments (61) (62) (4) (3)
Plan amendments -- -- -- (7)
-------------------------------------------
Net obligation at December 31 662 613 76 60
-------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value of plan assets at January 1 468 465 28 24
Actual return on plan assets 107 (53) 3 --
Employer contributions 17 -- 7 3
Transfer of assets from Sempra Energy 7 118 -- 4
Benefit payments (61) (62) (4) (3)
-------------------------------------------
Fair value of plan assets at December 31 538 468 34 28
-------------------------------------------
Benefit obligation net of plan assets
at December 31 (124) (145) (42) (32)
Unrecognized net actuarial loss 53 79 17 6
Unrecognized prior service cost 9 11 (8) (9)
-------------------------------------------
Net recorded liability at December 31 $ (62) $ (55) $ (33) $ (35)
- -----------------------------------------------------------------------------------------
56
The following table provides the amounts recognized on the Consolidated
Balance Sheets (in Deferred Credits and Other Liabilities) at
December 31:
Other
Pension Benefits Postretirement Benefits
-------------------------------------------
(Dollars in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------
Accrued benefit cost $ (62) $ (55) $ (33) $ (35)
Additional minimum liability (61) (52) -- --
Intangible asset 9 11 -- --
Accumulated other comprehensive
income, pretax 52 41 -- --
-------------------------------------------
Net recorded liability $ (62) $ (55) $ (33) $ (35)
- -----------------------------------------------------------------------------------------
At December 31, 2003, the company's pension plan had benefit
obligations in excess of its plan assets. The following table provides
certain information for that plan at December 31:
Projected Benefit Accumulated Benefit
Obligation Exceeds Obligation Exceeds
the Fair Value of the Fair Value of
Plan Assets Plan Assets
-------------------------------------------
(Dollars in millions) 2003 2002 2003 2002
- -----------------------------------------------------------------------------------------
Projected benefit obligation $ 662 $ 613 $ 662 $ 613
Accumulated benefit obligation $ 661 $ 575 $ 661 $ 575
Fair value of plan assets $ 538 $ 468 $ 538 $ 468
The following table provides the components of net periodic benefit
costs (income) for the years ended December 31:
Other
Pension Benefits Postretirement Benefits
---------------------------------------------------
(Dollars in millions) 2003 2002 2001 2003 2002 2001
- -----------------------------------------------------------------------------------------
Service cost $ 14 $ 16 $ 13 $ 2 $ 1 $ 1
Interest cost 40 40 32 4 4 3
Expected return on assets (34) (43) (42) (1) (1) (1)
Amortization of:
Transition obligation -- -- -- 1 1 2
Prior service cost 2 2 3 (1) (1) --
Actuarial (gain) loss 2 -- (7) 1 -- --
Special termination benefits -- -- 13 -- -- --
Curtailment cost -- -- 1 -- -- 1
Settlement credit -- -- (19) -- -- --
Regulatory adjustment -- -- -- -- 1 1
--------------------------------------------------
Total net periodic benefit cost
(income) $ 24 $ 15 $ (6) $ 6 $ 5 $ 7
- -----------------------------------------------------------------------------------------
57
The significant assumptions related to the company's pension and other
postretirement benefit plans are as follows:
Other
Pension Benefits Postretirement Benefits
-------------------------------------------
2003 2002 2003 2002
- ------------------------------------------------------------------------------------------
WEIGHTED-AVERAGE ASSUMPTIONS USED
TO DETERMINE BENEFIT OBLIGATION
AS OF DECEMBER 31:
Discount rate 6.00% 6.50% 6.00% 6.50%
Rate of compensation increase 4.50% 4.50% 4.50% 4.50%
WEIGHTED-AVERAGE ASSUMPTIONS USED
TO DETERMINE NET PERIODIC BENEFIT
COSTS FOR YEARS ENDED DECEMBER 31:
Discount rate 6.50% 7.25% 6.50% 7.25%
Expected return on plan assets 7.50% 8.00% 8.00% 4.00%3.75% 4.00%
Rate of compensation increase 4.50% 5.00% 4.50% 5.00%
Cost4.50% 4.50%
- ------------------------------------------------------------------------------------------
The expected long-term rate of return on plan assets is derived from
historical returns for broad asset classes consistent with
expectations from a variety of sources, including pension consultants
and investment advisors.
2003 2002
- -----------------------------------------------------------------------------------------
ASSUMED HEALTH CARE COST
TREND RATES AT DECEMBER 31:
Health-care cost trend rate 30.00%(1) 7.00%
Rate to which the cost trend rate is assumed to
decline (the ultimate trend) 5.50% 6.50%
Year that the rate reaches the ultimate trend 2008 2004
- ----------------------------------------------------------------------------------------
(1) This is the weighted average of coveredthe increases for all health plans.
The 2003 rate for these plans ranged from 15% to 40%.
Assumed health-care chargescost trend rates have a significant effect on the
amounts reported for the health-care plan costs. A one-percent change
in assumed health-care cost trend rates would have the following
effects:
- -----------------------------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- -----------------------------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health-care benefit cost $ -- $ --
7.00%(1) 7.25%(1)
CHANGE IN PROJECTED BENEFIT OBLIGATION:
NetEffect on the health-care component of the
accumulated other postretirement
benefit obligation at January 1 $ 4484 $ 477 $ 45 $ 49
Service cost 16 13 1 1
Interest cost 40 32 4 3(3)
- -----------------------------------------------------------------------------------------
58
Pension Plan Investment Strategy
The asset allocation for the Sempra Energy's pension trust (which
includes SDG&E's pension plan and other postretirement benefit plans,
except for the plans described below) at December 31, 2003 and 2002
and the target allocation for 2004 by asset categories are as follows:
Target Percentage of Plan
amendments -- -- (7) --
Actuarial (gain) loss 62 4 9 (5)
Transfer of liability (2) 109 -- 11 --
Curtailments -- (7) -- --
Settlements -- 1 -- --
Special termination benefits -- 13 -- --
Benefits paid (62) (85) (3) (3)
--------------------------------------------
Net obligationAllocation Assets at December 31
613 448 60 45
--------------------------------------------
CHANGE IN PLAN ASSETS:
Fair value-------------------------------------------
Asset Category 2004 2003 2002
- ------------------------------------------------------------------------------------------
U.S. Equity 45% 45% 44%
Foreign Equity 25% 30% 26%
Fixed Income 30% 25% 30%
-------------------------------------------
Total 100% 100% 100%
- ------------------------------------------------------------------------------------------
The company's goal is to stay fully invested at all times and maintain its
strategic asset allocation, keeping the investment structure relatively
simple. The equity portfolio is balanced to maintain risk characteristics
similar to the S&P 1500 with respect to market capitalization, industry and
sector exposures. The foreign equity portfolios are managed to track the MSCI
Europe, Pacific Rim and Emerging Markets indexes. Bond portfolios are
managed with respect to the Lehman Aggregate Index. The plan does not invest
in Sempra Energy securities.
Investment Strategy for Postretirement Health Plans
The asset allocation for the company's postretirement health plans at
December 31, 2003 and 2002, and the target allocation for 2004 by
asset categories are as follows:
Target Percentage of plan assets at January 1 465 604 24 22
Actual return on plan assets (53) (55) -- 1
Employer contributions -- -- 3 4
Transfer of assets (2) 118 1 4 --
Benefits paid (62) (85) (3) (3)
--------------------------------------------
Fair value of plan assetsPlan
Allocation Assets at December 31
468 465 28 24
--------------------------------------------
Plan assets net of obligation
at December 31 (145) 17 (32) (21)
Unrecognized net actuarial (gain) loss 79 (62) 6 (6)
Unrecognized prior service cost 11 13 (9) --
--------------------------------------------
Net recorded liability at December 31 $ (55) $ (32) $ (35) $ (27)-------------------------------------------
Asset Category 2004 2003 2002
- -----------------------------------------------------------------------------------------
(1) Decreasing to ultimate trend of 6.50%------------------------------------------------------------------------------------------
U.S. Equity 25% 26% 23%
Foreign Equity 5% 5% 4%
Fixed Income 70% 69% 73%
-------------------------------------------
Total 100% 100% 100%
- ------------------------------------------------------------------------------------------
The company's postretirement health plans, which also are distinct from
other postretirement benefit plans included in Sempra Energy's pension
trust (see above), pay premiums to the health maintenance organization
and point-of-service plans from company and participant contributions.
The company's investment strategy is to match the long-term growth rate
of the liability primarily through the use of tax-exempt California
municipal bonds.
59
Future Payments
The company expects to contribute $23 million to its pension plan and
$7 million to its other postretirement benefit plans in 2004.
(2) To reflect transfer of plan assets and liability from Sempra Energy.
The following table provides the amounts recognized on the Consolidated
Balance Sheets (under deferred credits and other liabilities) at
December 31:
Other
Pension Benefits Postretirement Benefits
-------------------------------------------
(Dollars in millions) 2002 2001 2002 2001
- -----------------------------------------------------------------------------------------
Accrued benefit cost $ (55) $ (32) $ (35) $ (27)
Additional minimum liability (52) -- -- --
Intangible asset 11 -- -- --
Accumulated other comprehensive
income, pretax 41 -- -- --
-------------------------------------------
Net recorded liability $ (55) $ (32) $ (35) $ (27)
- -----------------------------------------------------------------------------------------
61
The following table providesreflects the componentstotal benefits expected to be paid to
current employees and retirees from the plans or from the company's
assets, including both the company's share of net periodicthe benefit cost (income) forand,
where applicable, the plans:participants' share of the costs, which is
funded by participant contributions to the plans.
Other
(Dollars in millions) Pension Benefits Postretirement Benefits
---------------------------------------------------
Years ended December 31 2002 2001 2000 2002 2001 2000
- --------------------------------------------------------------------------------------------------------------------------------------------------------------------
Service cost2004 $ 16 $ 13 $ 10 $ 1 $ 1 $ 1
Interest cost 40 32 36 4 3 3
Expected return on assets (43) (42) (57) (1) (1) (1)
Amortization of:
Transition obligation -- -- -- 1 2 2
Prior service cost 2 3 3 (1) -- --
Actuarial (gain) loss -- (7) (17) -- -- --
Special termination benefits -- 13 5 -- -- 1
Curtailment cost -- 1 -- -- 1 --
Settlement credit -- (19) -- -- -- --
Regulatory adjustment -- -- -- 1 1 (2)
--------------------------------------------------
Total net periodic benefit cost
(income) $ 15 $ (6) $ (20)45 $ 5
2005 $ 746 $ 4
- -----------------------------------------------------------------------------------------6
2006 $ 49 $ 6
2007 $ 52 $ 6
2008 $ 55 $ 6
Thereafter $ 299 $ 32
Assumed health-care cost trend rates have a significant effect on the
amounts reported for the health-care plans. A one-percent change in
assumed health-care cost trend rates would have the following effects:
- -----------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- -----------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health-care benefit cost $ -- $ --
Effect on the health-care component of the
accumulated other postretirement
benefit obligation $ 3 $ (2)
- -----------------------------------------------------------------------
The company's funded pension plan had plan assets less than accumulated
benefit obligations. The projected benefit obligation and accumulated
benefit obligation were $613 million and $575 million, respectively, as
of December 31, 2002, and $448 million and $442 million, respectively,
as of December 31, 2001.
The company maintains dedicated assets in support of its Supplemental
Executive Retirement Plan.
Other postretirement benefits include retiree life insurance and
medical benefits for retirees and their spouses.
Savings PlansPlan
The company offers trusteed savings plans, administered by plan trustees, to all eligible employees.
Eligibility to participate in the plansplan is immediate for salary
deferrals. Employees may contribute, subject to
62
plan provisions, from
one percent to 25 percent of their regular earnings. After one year of
completed service, the company begins to make matching contributions.
Employer contributions are equal to 50 percent of the first 6six
percent of eligible base salary contributed by employees and, if
certain company goals are met, an additional amount related to
incentive compensation payments.
Employer contributions are invested in Sempra Energy common stock and
must remain so invested until termination of employment.employment or until the
employee's attainment of age 55, when they may be transitioned into
other investments. At the direction of the employees, the employees'
contributions are invested in Sempra Energy stock, mutual funds, or
institutional trusts. Company contributions to the savings plansplan were
$8 million in 2003, $7 million in 2002 $5 million in 2001 and $5 million in 2000.
Employee Stock Ownership Plan
All contributions to the Trust are made by the company; there are no
contributions made by the participants.
As the company makes contributions to the ESOP, the ESOP debt service
is paid and shares are released in proportion to the total expected
debt service. Compensation expense is charged and equity is credited
for the market value of the shares released. Income tax deductions are
based on the cost of the shares. Dividends on unallocated shares are
used to pay debt service and are applied against the liability. The
Trust held 2.6 million shares and 2.7 million shares of Sempra Energy
common stock, with fair values of $61.0 million and $65.9 million, at
December 31, 2002 and 2001, respectively.2001.
NOTE 7. STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans intended to align
employee and shareholder objectives related to the long-term growth of
the company. The plans permit a wide variety of stock-based awards,
including nonqualified stock options, incentive stock options,
restricted stock, stock appreciation rights, performance awards, stock
payments and dividend equivalents.
In 1995, SFAS 123, "Accounting for Stock-Based Compensation," was
issued. It encourages a fair-value-based method of accounting for
stock-based compensation. As permitted by SFAS 123, Sempra Energy and
its subsidiaries adopted only its disclosure requirements and continue
to account for stock-based compensation in accordance with the
60
provisions of Accounting Principles Board Opinion 25, "Accounting for
Stock Issued to Employees."25. See additional
discussion of SFAS 148, the amendment to SFAS 123, in Note 1.
TheSempra Energy's subsidiaries record an expense for the plans to the
extent that
subsidiarytheir employees participate in the plans, or that subsidiaries
are allocated a portion of Sempra Energy's costs of the plans. SDG&E
recorded expenses of $7 million, $1 million and $2 million in 2003,
2002 and $1 million in 2002,
2001, and 2000, respectively.
63
NOTE 8. FINANCIAL INSTRUMENTS
Fair Value
The fair values of certain of the company's financial instruments
(cash, temporary investments, notes receivable, dividends payable, and
customer deposits) approximate thetheir carrying amounts. The following
table provides the carrying amounts and fair values of the remaining
financial instruments at December 31:
(Dollars in millions) 2003 2002 2001
- -------------------------------------------------------------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
- -------------------------------------------------------------------------------
First-mortgage bonds $ 636 $ 689653 $ 674636 $ 704689
Rate-reduction bonds 263 284 329 357 395 411
Other long-term debt 254 278 254 273
254 265
-------- -------- -------- --------------- ------- ------- -------
Total long-term debt $1,219 $1,319 $1,323 $1,380$ 1,153 $ 1,215 $ 1,219 $ 1,319
- ------------------------------------------------------------------------------------------------------------------------------------------------------------
Preferred stock $ 104103* $ 98100 $ 104 $ 98
- -------------------------------------------------------------------------------
* $24 million of mandatorily redeemable preferred stock has been reclassified
to Deferred Credits and Other Liabilities and to Other Current Liabilities
on the Consolidated Balance Sheets.
The fair values of long-term debt and preferred stock were estimated
based on quoted market prices for them or for similar issues.
Accounting for Derivative Instruments and Hedging Activities
The company follows the guidance of SFAS 133 "Accounting for Derivative Instruments and Hedging
Activities," as amended byrelated amendments
SFAS 138 "Accountingand 149 (collectively SFAS 133) to account for Certainits derivative
instruments and hedging activities. Derivative Instrumentsinstruments and Certain Hedging Activities" recognizes all derivativesrelated
hedges are recognized as either assets or liabilities inon the statement of financial position,
measures those instrumentsbalance
sheet, measured at fair value and recognizes changesvalue. Changes in the fair value of derivatives
are recognized in earnings in the period of change unless the
derivative qualifies as an effective hedge that offsets certain
exposure.
SFAS 133 provides for hedge accounting treatment when certain criteria
are met. For derivative instruments designated as fair value hedges,
the gain or loss is recognized in earnings in the period of change
together with the offsetting gain or loss on the hedged item
61
attributable to the risk being hedged. For derivative instruments
designated as cash flow hedges, the effective portion of the derivative
gain or loss is included in other comprehensive income, but not
reflected in the Statements of Consolidated Income until the
corresponding hedged transaction is settled. The ineffective portion is
reported in earnings immediately. There was no effect on other
comprehensive income for the years ended December 31, 2003 and 2002. In
instances where derivatives do not qualify for hedge accounting, gains
and losses are recorded in the Statements of Consolidated Income.
The company utilizes derivative financial instrumentsenergy and natural gas derivatives to reduce its
exposure to unfavorable changes inmanage
commodity prices, which are subject
to significant and often volatile fluctuation. Derivative financial
instruments include futures, forwards, swaps, options and long-term
delivery contracts.price risk associated with servicing their load requirements.
These contracts allow the company to predict with greater certainty the
effective prices to be received by the company and the prices to be
charged to its customers. Since adoptionThe use of SFAS
133 on January 1, 2001, thederivative financial instruments
is subject to certain limitations imposed by company policy and
regulatory requirements. The company classifies its forward contracts
as follows:
Normal PurchaseContracts that meet the definition of normal purchase and Sales: These contractssales
generally are long-term contracts that are settled by physical delivery
and, therefore, are eligible for the normal purchases and sales
exception of SFAS 133. The contracts are accounted for at historical cost with gainsunder accrual
accounting and losses
reflectedrecorded in Revenues or Cost of Sales in the StatementsStatement
of Consolidated Income atwhen physical delivery occurs. Due to the
contract
settlement date.
64
adoption of SFAS 149, the company has determined that its natural gas
contracts entered into after June 30, 2003 generally do not qualify for
the normal purchases and sales exception.
Electric and Natural Gas Purchases and Sales: The unrealized gains and
losses related to these forward contracts are reflectedoffset against regulatory
assets and liabilities on the Consolidated Balance Sheets as regulatory assets and liabilities to the extent
derivative gains and losses will be recoverable or payable in future
rates. If gains and losses are not recoverable or payable through
future rates, the company applies hedge accounting if certain criteria
are met. When a contract no longer meets the requirements of SFAS 133,
the unrealized gains and losses and the related regulatory asset or
liability will be amortized over the remaining contract life.
In instances where hedge accounting is applied to derivatives, cash
flow hedge accounting is elected and, accordingly, changes in fair
values of the derivatives are included in other comprehensive income,
but not reflected in the Statements of Consolidated Income until the
corresponding hedged transaction is settled. The effect on other
comprehensive income for the years ended December 31, 2002 and 2001 was
not material. In instances where derivatives do not qualify for hedge
accounting, gains and losses are recorded in the Statements of
Consolidated Income.62
The following were recorded in the Consolidated Balance Sheets at
December 31:31 related to derivatives:
(Dollars in millions) 2003 2002
2001
- --------------------------------------------------------------------------------------------------------------------------------------------
Fixed-priced contracts and other derivatives:
Current assetsliabilities $ 259 $ 159
Noncurrent liabilities 502 579
----- -----
Total 2 1
----- -----561 638
Current liabilities 59 84
Noncurrent liabilities 579 634
----- -----
Total 638 718assets (1) (2)
----- -----
Net liabilities $ 636560 $ 717636
===== =====
Regulatory assets and liabilities:
Current regulatory assets $ 59 $ 8359
Noncurrent regulatory assets 502 579 634
----- -----
Total 561 638 717
----- -----
Current regulatory liabilities 2 1(1) (2)
----- -----
Net regulatory assets $ 636560 $ 716636
===== =====
- -----------------------------------------------------------------------The above had no impact on net income during 2003 and a $1 million
impact in income and $1 million in losses were recorded in 2002 and
2001, respectively, in "other income - net" in the Statements of
Consolidated Income.
65
2002.
Market Risk
The company's policy is to use derivative physical and financial
instruments to managereduce its exposure to fluctuations in interest rates
foreign-currency exchange
rates and commodity prices. Transactions involving these instruments are
with major exchanges and other firms believed to be credit-worthy. The
use of these instruments exposes the company to market and credit risk,
which may at times be concentrated with certain counterparties,
although counterparty nonperformance is not anticipated.
Interest-Rate Risk Management
The company periodically enters into interest-rate swap agreements to
moderate exposure to interest-rate changes and to lower the overall
cost of borrowing. SDG&E had an interest-rate swap agreement that maturedThis is described in December 2002
and effectively fixed the interest rate on $45 million of variable-rate
underlying debt at 5.42 percent. This floating-to-fixed-rate swap did
not qualify for hedge accounting and, therefore, the gains and losses
associated with the change in fair value were recorded in the
Statements of Consolidated Income. The effect on income was a $1
million gain and a $1 million loss for the years ended December 31,
2002 and 2001, respectively. Although this financial instrument did not
meet the hedge accounting criteria of SFAS 133, it was effective in
achieving the risk management objectives for which it was intended.
Energy Derivatives
SDG&E utilizes derivative instruments to reduce its exposure to
unfavorable changes in energy prices, which are subject to significant
and often volatile fluctuation. Derivative instruments are comprised of
futures, forwards, swaps, options and long-term delivery contracts.
These contracts allow SDG&E to predict with greater certainty the
effective prices to be received and the prices to be charged to their
customers. See Note 1 for discussion of how these derivatives are
classified under SFAS 133.3.
Energy Contracts
SDG&E records transactions for natural gas and electric energy
contracts in "CostCost of natural gas distributed"Natural Gas and "Electric fuelCost of Electric Fuel and
net purchased power,"Purchased Power, respectively, in the Statements of Consolidated
Income. For open contracts not expected to result in physical delivery,
changes in market value of the contracts are recorded in these accounts
during the period the contracts are open, with an offsetting entry to a
regulatory asset or liability. The majority of the company's contracts
result in physical delivery. There was no impact on the Statements of
Consolidated Income for changes in the fair value of derivative
instruments, other than the $1 million gain and $1 million loss for the yearsyear ended December
31, 2002 and 2001, respectively, from thedue to an interest-rate swap noted above.
66as discussed in Note 3.
63
NOTE 9. PREFERRED STOCK
- ----------------------------------------------------------------------------------
CallCall/Redemption December 31,
(Dollars in millions, except call price) Price 2003 2002 2001
- ----------------------------------------------------------------------------------
Not Subjectsubject to mandatory redemption
$20 par value, authorized 1,375,000 shares:
5% Series, 375,000 shares outstanding $ 24.00 $ 8 $ 8
4.5% Series, 300,000 shares outstanding $ 21.20 6 6
4.4% Series, 325,000 shares outstanding $ 21.00 7 7
4.6% Series, 373,770 shares outstanding $ 20.25 7 7
Without par value:
$1.70 Series, 1,400,000 shares outstanding $ 25.85 35 35
$1.82 Series, 640,000 shares outstanding $ 26.00 16 16
------------------------------------
Total $ 79 $ 79
------------------------------------
Subject to mandatory redemptionredemption:
Without par value,value: $1.7625 Series, 950,000
and 1,000,000 shares outstanding December 31,
2003 and December 31, 2002, respectively $ 25.00 $ 2524* $ 25
- ----------------------------------------------------------------------------------
*Reclassified to Deferred Credits and Other Liabilities and to Other
Current Liabilities.
All series of SDG&E's preferred stock have cumulative preferences as to
dividends. The $20 par value preferred stock has two votes per share on
matters being voted upon by shareholders of SDG&E and a liquidation
value at par, whereas the no-par-value preferred stock is nonvoting and
has a liquidation value of $25 per share, plus any unpaid dividends.
SDG&E is authorized to issue 10,000,000 shares of no-par-value
preferred stock (both subject to and not subject to mandatory
redemption). All series are callable at December 31, 2002, except for
the $1.7625 and $1.70 Series (callable in January and October 2003,
respectively).2003. The $1.7625
Series has a sinking fund requirement to redeem 50,000 shares at $25
per share per year from 20032004 to 2007; the remaining 750,000 shares must
be redeemed in 2008. On January 15, 2004, SDG&E redeemed 50,000 shares
at $25 per share.
NOTE 10. ELECTRIC INDUSTRY REGULATION
Background
The restructuring of California's electric utility industry has
significantly affected the company's electric utility operations, and
the power crisis of 2000-2001 caused the CPUC to significantly modify
its plan for restructuring the electricity industry. Supply/demand
imbalances and a number of other factors resulted in abnormally high
electric-commodity prices beginning in mid-2000 and continuing into
2001. This caused SDG&E's customer bills to be substantially higher
than normal. These higher prices were initially passed through to
customers and resulted in bills that in most cases were double or
triple those from 1999 and early 2000. This resulted in several
legislative and regulatory responses, including AB 265, enacted
in September 2000 and in effect through December 31, 2002.California Assembly
Bill (AB) 265. AB 265 imposed a ceiling of 6.5 cents/kWh on the cost of the electric64
commodity that SDG&E could pass on to its small-usage customers on a
current basis, effective retroactive tofrom
June 1, 2000.2000 to December 31, 2002.
SDG&E accumulated the amount that it paid for electricity in excess of
the ceiling rate in an interest-bearing balancing account (the AB 265
undercollection). It increased and began recovering these amounts in rates charged
to approximately $750 million incustomers following the 67
first quarterend of 2001 and decreased to $392 million atthe rate-ceiling period. At December
31, 2001 and $215 million at December 31, 2002 (included in current
"regulatory balancing accounts - net").
In June 2001, representatives of California Governor Davis, the DWR,
Sempra Energy and SDG&E entered into a Memorandum of Understanding
(MOU) contemplating the implementation of a series of transactions and
regulatory settlements and actions to resolve many of the issues
affecting SDG&E and its customers arising out of the California energy
crisis. During 2001, implementation of some of the MOU's provisions
(with the rest no longer likely to be implemented) resulted in a
partial reduction of2003, the AB 265 undercollection (see above). In
addition,was $63 million (included in
Regulatory Balancing Accounts - Net on the DWR's procurement of SDG&E's full net short position
during 2001Consolidated Balance
Sheets) and 2002 (see below)is being recovered in current rates.
Another legislative response to the power crisis resulted in the
cessation of growth in
the AB 265 undercollection.
The Department of Water Resources and Power Procurement
In February 2001, through the passage of Assembly Bill 1, Chapter 4,
Statutes of the 2001 First Extraordinary Session (AB X1),purchase by the DWR began
to purchase power from generators and marketers and entered into long-
term contracts for the purchase of a substantial portion of the state's power requirements
that is served by the IOUs. SDG&E and the DWR had an
agreement under which the DWR purchased the net short supply for
bundled SDG&E customers through December 31, 2002.of California's electricity users. Since early 2001, the DWR has
procured power for the utility procurement customers of each of the
California IOUsinvestor-owned utilities (IOUs) and the CPUC has
established the allocation of the power and theits related cost
responsibility among the IOUs for that power. SDG&E's
allocation results in its overall rates being comparable to those of
the other two California electric IOUs, Southern California Edison
(Edison) and Pacific Gas and Electric (PG&E). On December 17, 2002, the
CPUC issued a decision allocating the cost of the DWR's revenue
requirement for its 2003 power purchases. The decision pools the total
fixed costs of the DWR's contracts and allocates these costs among the
IOUs on the basis of the quantity of the energy supplied to each IOU
from the contracts. Variable costs related to the energy supplied under
each contract go to the IOU assigned each contract. This decision
allocates $643 million to SDG&E and will be handled within existing
utility rates. That amount is currently under additional review as the
DWR revenue requirement was reduced when the IOUs began power
procurementIOUs. Beginning on January 1, 2003, (see discussion below).
The CPUC's objective was for the IOUs
to take theresumed some of its electric commodity procurement, function
back fromwhereas previously
the DWR had been purchasing the IOUs' entire net short position.
Department of Water Resources
The DWR's operating agreement with SDG&E, approved by the beginningCPUC, governs
SDG&E's administration of the allocated DWR contracts. The agreement
provides that SDG&E is acting as a limited agent on behalf of the DWR in
undertaking energy sales and natural gas procurement functions under the
DWR contracts allocated to SDG&E's customers. Legal and financial risks
associated with these activities will continue to reside with the DWR.
Therefore, the revenues and costs associated with the contracts were not
included in the Statements of Consolidated Income during 2003. On September 19,From
February 2001 until December 2002, the CPUC issued a decision on howDWR was purchasing similar
amounts of power for SDG&E; the cost of that power fromwas not included in
the long-term contracts
signed by the DWR should be allocated to the customersStatements of each of the
IOUs for purposes of determining the amount of additional power each
utility is required to procureConsolidated Income in 2003 and thereafter to fulfill its
resource needs.2001 or 2002. The
reasonableness of the IOUs'IOU's administration and dispatch of the allocated
contracts will be reviewed by the CPUC in an annual proceeding.
AB 57, signed by California Governor Davis onIn September 24, 2002, requires2003, the CPUC approved a $1 billion refund to make this determination,consumers
of the three major California IOUs as a result of the DWR's lowering
its revenue requirement for 2003. The refund was returned to customers
in the form of a one-time bill credit. SDG&E's portion was 13.51
percent or about $135 million. The bill credit had no effect on SDG&E's
net income and to establish procedures that will allownet cash flows because customer savings are coming from
lower charges by the IOUs to recover their
electric procurement costs in a timely fashion without the need for
retrospective reasonableness reviews.DWR, and SDG&E believes thatis merely transmitting the
returnelectricity from the DWR to 68
the procurement function in accordance with AB 57 will have no adverse
impact on its financial position or results of operations.customers, without taking title to the
electricity.
On August 22, 2002,January 8, 2004, the CPUC issued a decision on the final true-up of
DWR's 2001/2002 energy costs among California's three major investor-
owned electric utilities, resulting in SDG&E's customers being
allocated $59 million of additional costs. The amount from this true-up
is recoverable from ratepayers and will be included with SDG&E's
allocated share of DWR's 2004 Revenue Requirement and incorporated into
electric charges for 2004, which are expected to be decided in the
first half of 2004. This true-up will have a short-term effect on
SDG&E's cash flow but will not otherwise affect its results of
65
operations, since SDG&E merely passes through the costs to its
customers.
In October 2003, the CPUC initiated a proceeding to consider a
permanent methodology for allocating DWR's Revenue Requirement
beginning in 2004 through the remaining life of the DWR contracts. An
interim allocation based on the current 2003 methodology was utilized
beginning January 1, 2004, and is in effect until a decision is reached
on a permanent methodology (expected in the second quarter of 2004).
Once a permanent methodology is established, the impacts of the
decision will be applied retroactively back to January 1, 2004. This
delay could have an effect on SDG&E's rates and cash flows, but not on
its net income.
Power Procurement
In October 2001, the CPUC initiated an Order Instituting Ratemaking
(OIR) to establish ratemaking mechanisms that authorizedwould enable California
investor-owned electric utilities to resume purchasing electric energy
and related services and hedging instruments to fulfill their
obligation to serve and meet the Californianeeds of their customers. In so doing,
the CPUC acknowledged that the utilities desired assurance of more
timely regulatory review and cost recovery for their procurement
activities and costs. In connection therewith, the CPUC OIR directed
the IOUs to begin interimresume electric commodity procurement of power to cover their net
short energy requirements starting onby January 1, 2003. The net short position is
the difference between the amount of electricity needed to cover a
utility's customer demand and the power provided by owned generation
and existing contracts, including the long-term DWR power contracts
allocated to the customers of each IOU by the DWRCPUC (see above).
The IOUs areOIR also implemented recent legislation regarding procurement and
renewables portfolio standards and establishes a process for review
and approval of the IOUs' long-term (20-year) procurement plans. In
December 2002, the CPUC adopted SDG&E's 2003 short-term procurement
plan. That plan addressed SDG&E's procurement activities in 2003,
authorized to enter into contracts ofcontract terms for up to five years for power from traditional sources,transactions
entered into under the plans, and up to 15 yearsallowed for power
from renewable sources.the hedging of first
quarter 2004 residual net short positions with transactions entered
into in 2003. SDG&E iswas required to purchase approximately 10 percent
of its customer requirements in 2003, based on the allocation of the
DWR power approved by the CPUC onin December 17, 2002.
On October 24, 2002, the CPUC issued a decision in the Electric
Procurement proceeding that officially directs the resumption of the
electric commodity procurement function by IOUs by January 1, 2003, and
begins the implementation of recent legislation regarding procurement
and renewables portfolio standards addressed in AB 57 and Senate Bill
1078. The decision established a process for review and approval of the
utilities' updated 2003 and long-term (20-year) procurement plans. The CPUC approvedauthorized
SDG&E's 2003 procurement plan in December 2002 and
approval of the long-term plan is expected during 2003. The CPUC has
authorized the utilities to use derivatives to manage procurement risk
and&E to acquire a variety of resource types including utility ownership,
conventional generation, distributed generation, self generation,and demand side
resources, transmission and renewables.resources. A semiannualsemi-annual cost review and rate revision mechanism is
established, and a trigger is established for more frequent changes if
undercollected commodity costs exceed five percent of annual, non-DWR
generation revenues, to provide for timely recovery of any
undercollections. Approval of SDG&E's 2003 short-term procurement plan
provided for SDG&E's return to procurement of its customers' needs on
January 1, 2003, consistent with the intent of the legislature and the
CPUC.
SDG&E filed its 20-year long-term resource plan covering its
anticipated procurement needs between 2004 and 2023 and its short-term
procurement plans for its anticipated procurement activities in 2004.
In decisions issued in December 2003 and January 2004, the CPUC
66
approved the 2004 procurement plan and provided policy guidance for
the filing of an updated 20-year resource plan in the spring of 2004.
On December 18, 2003, the CPUC issued a decision adopting SDG&E's
procurement plan for 2004. The Electricdecision delayed until 2004 further
CPUC direction on comprehensive policy guidance for the IOUs' long-
term resource plans. In the decision, the CPUC continued its
moratorium (subject to certain exceptions) on the IOUs' ability to
deal with their own affiliates in procurement transactions.
SDG&E's 20-year resource plan identified the near-term need for firm
capacity resources within its service territory to support transmission
grid reliability. As a result, SDG&E issued a Request for Proposals
(RFP) for the years 2005-2007 of 69 megawatts (MW) in 2005 increasing
to 291 MWs in 2007.
In October 2003, SDG&E filed a motion in the Procurement OIR that now
requests the CPUC to authorize SDG&E to enter into five new electric
resource contracts. They include:
The 550-megawatt combined-cycle Palomar power plant
in Escondido, California, to be constructed by Sempra
Energy Resources, an affiliate, for completion in
2006.
The 45-MW Ramco combustion turbine which SDG&E is
proposing to acquire as a turnkey project and intends
to use for intermediate load requirements beginning
June 2005.
(SDG&E will not take ownership of these two
facilities unless appropriate cost recovery and
ratemaking mechanisms are instituted by the CPUC to
ensure that SDG&E recovers all reasonable costs of,
and a reasonable return on, the investments.)
A power purchase agreement (PPA) to buy up to 570
megawatts over ten years starting in 2008 from a
power plant that Calpine Corporation (Calpine) would
complete on its site within SDG&E's service
territory. (SDG&E would recommend the Calpine PPA
only if the CPUC orders the implementation of certain
critical conditions intended to make the Calpine PPA
a positive economic benefit to SDG&E's customers.)
One contract each for a demand-response resource and
a renewable resource.
The capital cost related to the five contracts proposed by
SDG&E is $640 million. Hearings concluded on February 20,
2004, and a decision also described aboveis expected in May 2004. Given the
CPUC's prior denial of the company's request for approval
of additional transmissions facilities, the company
believes that customer requirements for electricity could
not be met without the requested resources or similar
additions.
67
A June 2003 CPUC decision in the Procurement OIR directed each IOU to
procure from renewable sources at least one percent of its 2003 total
energy sales, and an additional oneincreasing to 20 percent of energy sales each
year thereafter, until a 20-percent renewable resources portfolio is
achieved by the year 2017. SDG&E has contracted to procure
approximatelyprocured four
percent of its 2003 total energy sales from renewable sources and
pursuantexisting contracts will increase this to a Decemberfive percent in 2004 and nine
percent in 2007. A 2002 CPUC resolution may
"bank" orpermits the company to credit
toward future years' compliance any excess over its one-percent annual
requirement.
The CPUC has placed a moratorium onSONGS
Through December 31, 2003, the IOUs' purchasing electricity
from their affiliates for the earlier of two years or until the CPUC
completes a rulemaking on this matter. SDG&E believes that this
moratorium will have no adverse impact on its financial position or
results of operations. During 2002, SDG&E's purchases of electricity
from its affiliate Sempra Energy Trading were less than one percent of
total electricity purchases.
DWR Operating and Servicing Agreements
On December 19, 2002, the CPUC issued an Operating Order setting the
terms by which the IOUs will administer the DWR contracts allocated to
the customers of each of the utilities (see above). The DWR continues
69
to bear the credit risk on the contracts and the IOUs have assumed the
administrative burden of the contracts. The order requires the IOUs to
take financial responsibility for acquiring natural gas supplies for
the generation facilities that are subject to the DWR contracts.
SDG&E currently has pending an operating and servicing agreement signed
by the DWR and SDG&E which, if approved by the CPUC, will supercede the
CPUC's operating order referred to above. The pending agreement will
clearly delineate that the natural gas procurement and associated risk
will continue to reside with the DWR.
Effect on Customer Rates
On December 19, 2002, the CPUC issued a decision denying SDG&E's
application for a rate surcharge to expedite recovery of the AB 265
undercollection. However, even at current rates and allocation of the
resulting revenues between the DWR and SDG&E, the balance is expected
to be completely recovered before the end of 2005. Also at issue is the
ownership of certain power sale profits stemming from intermediate term
purchase power contracts entered into by SDG&E during the early stages
of California's electric utility industry restructuring. The company
believes that all profits associated with these contracts properly are
for the benefit of SDG&E shareholders rather than customers, whereas
the CPUC asserted that all the profits should accrue to the benefit of
customers. Accordingly, SDG&E challenged the CPUC's disallowance of
profits from the contracts in both the California Court of Appeals and
in Federal District Court.
These court proceedings have been held in abeyance pending the CPUC's
consideration of various other proposed settlements. On December 19,
2002, the CPUC rendered a 3-to-2 decision approving the June 2002
proposed settlement, previously described in the company's Quarterly
Report on Form 10-Q for the quarter ended September 30, 2002, that
divides the profits from these contracts, $199 million for SDG&E
customers and $173 million for SDG&E shareholders. Of the $199 million
in profits allocated to customers, $175 million had already been
credited to ratepayers in 2001. The remaining $24 million was applied
as a balancing account transfer that reduced the AB 265 balancing
account in December 2002. The profits allocated to customers reduce
SDG&E's AB 265 undercollection, but do not adversely affect SDG&E's
financial position, liquidity or results of operations. The term of a
commissioner who voted to approve the settlement has expired, and a new
commissioner has been appointed. On January 29, 2003, the CPUC's Office
of Ratepayer Advocates (ORA), the City of San Diego and the Utility
Consumers' Action Network, a consumer-advocacy group, filed requests
for a CPUC rehearing of the decision. On February 13, 2003, the company
filed its opposition to rehearing of the decision. Parties requesting a
rehearing and parties to any rehearing may also appeal the CPUC's final
decision to the California appellate courts.
Direct Access
On March 21, 2002, the CPUC affirmed its decision prohibiting new
direct access (DA) contracts after September 20, 2001, but rejected a
proposal to make the prohibition retroactive to July 1, 2001. Contracts
in place as of September 20, 2001 may be renewed or assigned to new
parties. On November 7, 2002, the CPUC issued a decision adopting DA
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exit fees with an interim cap of 2.7 cents per kWh, effective January
1, 2003. This decision will have no effect on SDG&E's cash flows or
results of operations, because any shortfall due to the cap on the exit
fees will be funded by bundled customers in current rates. The CPUC is
conducting further proceedings to determine whether, or to what extent,
the interim cap should be revised after July 1, 2003.
SONGS
Operatingcapital costs of SONGS
Units 2 and 3 including nuclear fuel and
related financing costs, and incremental capital expenditures arewere recovered through the ICIP mechanism which allowsallowed
SDG&E to receive
approximately 4.4 cents per kilowatt-hour for SONGS generation. Any
differences between these costs and the incentive price affectaffected net
income. For the year ended December 31, 2002,2003, ICIP contributed $50$53
million to SDG&E's net income. The CPUC has rejected an administrative
law judge's proposed decision to end ICIP prior to its December 31,
2003 scheduled expiration date. However,Beginning in 2004, the CPUC has also denied the
previously approved market-based pricing for SONGS beginning in 2004
and instead provided
for traditional rate-making treatment, under which the SONGS ratebase
would beginstart over at zero,January 1, 2004, essentially eliminating earnings
from SONGS until ratebase grows. The company has applied for
rehearing of this decision.except from future increases in ratebase.
FERC Actions
Refund Proceedings
The FERC is investigating prices charged to buyers in the California PX and ISO
markets by various electric suppliers. ItThe FERC is seeking to determine
the extent to which individual sellers have yet to be paid for power
supplied during the period of October 2, 2000 through June 20, 2001 and
to estimate the amounts by which individual buyers and sellers paid and
were paid in excess of competitive market prices. Based on these
estimates, the FERC could find that individual net buyers, such as
SDG&E, are entitled to refunds and individual net sellers are obligedrequired
to provide refunds. To the extent any such refunds are actually
realized by SDG&E, they would reduce SDG&E's rate-ceiling balancing
account.
In December 2002, a FERC administrative law judge'sAdministrative Law Judge (ALJ) issued
preliminary findings indicateindicating that the California owesPX and ISO owe
power suppliers $1.2 billion (the $3$3.0 billion that the California PX
and ISO still owesowe energy companies less $1.8 billion the ALJ findsthat the energy
companies overcharged California)charged California customers in excess of the preliminarily
determined competitive market clearing prices). On March 26, 2003, the
FERC largely adopted the ALJ's findings, but expanded the basis for
refunds by adopting a staff recommendation from a separate
investigation to change the natural gas proxy component of the
mitigated market clearing price that is used to calculate refunds. The
March 26 order estimates that the replacement formula for estimating
natural gas prices will increase the refund obligations from $1.8
billion to more than $3 billion. The FERC recently released its final
instructions, and ordered the ISO and PX to recalculate the precise
number through their settlement models. California is seeking $8.9
billion in refunds from its electricity suppliers and indicated it would appeal ifhas appealed the
ALJ'sFERC's preliminary findings are adopted. Aand requested rehearing of the March 26
order.
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Manipulation Investigation
The FERC decision is not expected before the second half of 2003. More recently,
FERC has launched an investigation intoalso investigating whether there was manipulation of short-termshort-
term energy pricesmarkets in the West that resulted in unjustwould constitute violations of
applicable tariffs and unreasonable long-term power sales contracts.warrant disgorgement of associated profits. In
addition, in February 2002this proceeding, the CPUC andFERC's authority is not confined to the California Electricity
Oversight Board petitionedOctober 2,
2000 through June 20, 2001 period relevant to the FERC to determine that the long-term
power contracts the DWR signed with energy companies during the height
of the energy crisis do not provide just and reasonable rates, and to
abrogate or reform the contracts.refund proceeding. In
AprilMay 2002, the FERC ordered hearings on the complaints. The order requires the complainantsall energy companies engaged in electric
energy trading activities to satisfy a "heavy" burden of proof to support a revisionstate whether they had engaged in various
specific trading activities in violation of the contracts,PX and citedISO tariffs
(generally described as manipulating or "gaming" the FERC's long-standing policyCalifornia energy
markets).
On June 25, 2003, the FERC issued several orders requiring various
entities to recognizeshow cause why they should not be found to have violated
California ISO and PX tariffs. FERC directed 43 entities, including
SDG&E, to show cause why they should not disgorge profits from certain
transactions between January 1, 2000 and June 20, 2001 that are
asserted to have constituted gaming and/or anomalous market behavior
under the sanctity of contracts, from which it has deviated only in "extreme
circumstances." In December 2002, a FERC administrative law judge held
71
formal hearings and in January 2003 issued a partial, initial decision
recommending that the validity of their contracts be determined under a
"public interest" standard that requires the complainants to satisfy a
significantly higher standard of review to invalidate the contracts
than would a just and reasonable standard. Final briefs were submitted
to the full FERC commission later in January with respect to the public
interest standard of reviewCalifornia ISO and/or PX tariffs. SDG&E and the FERC has indicatedresolved
the matter by SDG&E's paying $28 thousand into a FERC-established fund.
On June 25, 2003, the FERC also determined that it expectswas appropriate to
issueinitiate an investigation into possible physical and economic
withholding in the California ISO and PX markets. For the purpose of
investigating economic withholding, the FERC used an initial screen of
all bids exceeding $250 per MW between May 1, 2000 and October 2, 2001.
SDG&E has received data requests from the FERC staff and has provided
responses. The FERC staff will prepare a final decision by March 2003.report to the FERC, which will
be the basis to decide whether additional proceedings are warranted.
SDG&E believes that its bids and bidding procedures were consistent
with ISO and PX tariffs and protocols and applicable FERC price caps.
On August 1, 2003, the FERC staff issued an initial report that
determined there was no need to further investigate particular entities
for physical withholding of generation.
NOTE 11. OTHER REGULATORY MATTERS
Natural Gas Industry Restructuring
In January 1998, the CPUC released a staff report initiating a project
to assess the current market and regulatory framework for California's
natural gas industry. In July 1999, after hearings, the CPUC issued a
decision stating which natural gas regulatory changes it found most
promising, encouraging parties to submit settlements addressing those
changes, and providing for further hearings if necessary.
On December 11, 2001 the CPUC issued a decision adopting much of a
settlement that had been submitted in 2000 by SDG&E and approximately
30 other parties representing all segments of therelated to natural gas
industry restructuring (GIR), with implementation anticipated during
2002. On January 12, 2004, after many delays and changes, an ALJ issued
a proposed decision that would implement the 2001 decision. The
proposed decision would result in Southern California, but opposed by some parties. Therevising noncore balancing account
treatment to exclude the balancing of SoCalGas' transmission costs;
other noncore costs/revenues would continue to be fully balanced until
the decision in the next Biennial Cost Allocation Proceeding (BCAP)
(see below). On February 11, 2004, a member of the CPUC issued an
alternative decision that would vacate the December 2001 decision and
defer GIR matters to the Natural Gas Market OIR (see below). A CPUC
decision adoptscould be issued in March 2004.
Natural Gas Market OIR
The Natural Gas Market OIR was approved on January 22, 2004, and will
be addressed in two concurrent phases. The schedule calls for a Phase I
69
decision by summer 2004 and a Phase II decision by the following provisions:end of 2004. In
Phase I the CPUC's objective is to develop a systemprocess enabling the CPUC
to review and pre-approve new interstate capacity contracts before they
are executed. In addition, the California Utilities must submit
proposals on any LNG project to which interconnection is planned,
providing costs and terms, including access to the pipelines in Mexico.
Phase II will primarily address emergency reserves and ratemaking
policies. The OIR invites proposals on how utilities should provide
emergency reserves consisting of slack intrastate pipeline capacity,
contracts for shippers to hold firm,
tradable rights toadditional capacity on SoCalGas' majorthe interstate pipelines and an
emergency supply of natural gas transmission
lines; new balancing services, including separate corestorage. The CPUC's objective in the
ratemaking policy component of Phase II is to identify and noncore
balancing provisions;propose
changes to policies that create incentives that are consistent with the
goal of providing adequate and reliable long-term supplies and that do
not conflict with energy efficiency programs. The focus of the Gas OIR
is 2006 to 2016. Since GIR (see above) would end in August 2006 and
there is overlap between GIR and the Gas OIR issues, a reallocation among customer classesnumber of
parties (including SoCalGas) are advising the CPUC not to implement
GIR.
The company believes that regulation needs to consider sufficiently the
adequacy and diversity of supplies to California, transportation
infrastructure and cost recovery thereof, hedging opportunities to
reduce cost volatility, and programs to encourage and reward
conservation.
Cost of Service
The California Utilities have filed cost of service applications with
the CPUC, seeking rate increases reflecting forecasts of 2004 capital
and operating costs. SDG&E is requesting revenue increases of $76
million. The CPUC's Office of Ratepayer Advocates (ORA) filed its
prepared testimony on the applications in August 2003, recommending
numerous rate decreases that would reduce annual revenues by $41
million from their current level. The Utility Consumers' Action Network
(UCAN), a consumer-advocacy group, has proposed rates for SDG&E that
would reduce annual revenues by $88 million from their current level.
Hearings concluded in November 2003. On December 19, 2003, settlements
were filed with the CPUC that, if approved, would resolve most of the
cost of interstate pipeline capacity heldservice issues. The SDG&E settlement was signed by SoCalGasSDG&E, ORA
and an unbundlingother parties, but not by UCAN, the City of interstate capacityChula Vista and other
parties. The CPUC adopted a schedule for briefing and commenting on the
proposed settlements that concluded on February 19, 2004. The SDG&E
settlement would reduce its electric rates by $19.6 million from 2003
rates and increase its natural gas marketers serving core customers;rates by $1.8 million from 2003
rates. As part of the proposed settlement, SDG&E and the eliminationORA would
resolve their dispute concerning the allocation of noncore customers' option to obtain natural gas
procurement service fromthe gain on sale of
SDG&E.&E's surplus property in Blythe, California, by increasing SDG&E's
forecast of miscellaneous revenues by $1.3 million annually, thereby
lowering its retail revenue requirement by that amount. The CPUC modifiedmay
accept one or both of the settlementsettlements or may adopt an outcome differing
from both of the settlements. Resolution is likely in the second
quarter of 2004.
On December 18, 2003, the CPUC issued a decision that creates
memorandum accounts as of January 1, 2004, to provide increased protection againstrecord the exercisedifference
between actual revenues and those that are later authorized in the
70
CPUC's final decision in this case. The difference would then be
amortized in rates. The California Utilities have also filed for
continuation through 2004 of market power by
persons whoexisting performance-based regulation
(PBR) mechanisms for service quality and safety that would acquire rightsotherwise
expire at the end of 2003. In January 2004, the CPUC issued a decision
that extended 2003 service and safety targets through 2004, but
deferred action on the SoCalGas natural gas
transmission system.applying any rewards or penalties for performance
relative to these targets to a decision to be issued later in 2004 in a
second phase of these applications discussed below.
The CPUC also rejected certain aspectshas established a procedural schedule for the second phase of
these applications, addressing issues related to PBR (see below). The
procedural schedule calls for hearings to be held in June 2004, with a
decision during 2004. The scope of the settlement that would have provided more optionssecond phase includes: (a) a
formula for natural gas
marketers serving core customers.
During 2002setting authorized cost of service for 2005 and succeeding
years until 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. On December 30, 2002, the CPUC deferred acting on a plan to
implement its decision.
SDG&E believes that implementation of the decision would make natural
gas service more reliable, more efficient and better tailored to meet
the needs of customers. The decision is not expected to adversely
affect SDG&E's earnings.next full Cost of Service (COS)proceeding is scheduled; (b)
whether and how rates should be adjusted if earned returns vary from
authorized returns; and (c) prospective targets and rewards/penalties
for service quality and safety.
An October 2001 decision denied the California Utilities' request to
continue equal sharing between ratepayers and shareholders of the
estimated savings for the 1998 business combination that created Sempra
Energy and, instead, ordered that all of the estimated 2003 merger
savings go to ratepayers. In 2002, merger savings to shareholders for
the fourth quarter and for the year were $2 million and $8 million,
respectively. Pursuant to the decision, SDG&E will return the 2003
merger savings related to natural gas operations of $15 million to
ratepayers over a twelve-month period beginning January 1, 2004. The
merger savings related to electric operations were previously returned
to ratepayers.
Performance-Based Regulation (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 19941994. PBR has resulted in modification to
the general rate case and certain other regulatory proceedings for
SDG&E. Under PBR, regulators require future income potential to be
tied to 72
achieving or exceeding specific performance and productivity
goals, rather than relying solely on expanding utility plant to
increase earnings.
PBR consists of three primary components. The first is a mechanism to
adjust rates in years between general rate cases or cost of service
cases. Similar to the pre-PBR Attrition Proceeding, it annually
adjusts general rates from those of the prior year to provide for
inflation, changes in the number of customers and efficiencies.
The second component is a mechanism whereby any earnings in excess of
those authorized plus a narrow band above that are shared with
customers in varying degrees depending upon the amount of the
additional earnings.
The third component consists of a series of measures of utility
performance. Generally, if performance is outside of a band around the
71
specified benchmark, the utility is rewarded or penalized certain
dollar amounts.
The three areas that are eligible for PBR rewards or penalties are
operational incentives based on measurements of safety, reliability
and customer satisfaction; demand-side management (DSM) rewards based
on the effectiveness of the programs; and natural gas procurement
rewards.
Theserewards or penalties. The CPUC is also considering a new
reward/penalty related to electricity procurement, now that the
utilities are resuming this activity. However, as noted under "Cost of
Service," Phase II of the California Utilities' current cost of
service proceeding is not scheduled for completion until late 2004. As
a result, it is possible that some or all of the safety, reliability
and customer satisfaction incentive mechanisms (i.e., those that are
reviewed in the Cost of Service proceeding) would not be in effect for
2004. Even if that were to occur, it is not expected that the effect
would be other than a one-year moratorium on the mechanisms.
In July 2003, the CPUC issued a decision relative to SDG&E's Year 11
natural gas PBR application, which will permanently extend the PBR
mechanism with some modification. The decision approved the Joint
Parties' Motion for an Order Adopting Settlement Agreement filed by
SDG&E and the ORA, which will apply to Year 10 and beyond. The effect
of the modifications is to reduce slightly the potential size of future
PBR rewards or penalties.
Since the 1990s, IOUs have been eligible to earn awards for
implementing and administering energy conservation and efficiency
programs. The California Utilities have offered these programs to
customers and have consistently achieved significant earnings from the
program. On October 16, 2003, the CPUC issued a decision that the pre-
1998 DSM earnings proceeding would not be reopened, leaving the
earnings mechanism unchanged. The CPUC may adjust amounts determined
pursuant to the earnings mechanism consistent with the application of
known, standard measurement and verification protocols.
The CPUC has consolidated the 2000, 2001 and 2002 award applications.
The 2003 award applications were filed on May 1, 2003. On May 2, 2003,
the CPUC released RFPs to conduct a review of the IOUs' studies and
reported program milestones/accomplishments used as the basis for the
awards claims and program expenditures. The review should be completed
in the second quarter of 2004. Additionally, the low-income awards
will be subject to an independent review expected to commence in 2005.
The majority of the outstanding claims are on hold pending completion
of the independent review.
72
Incentive Awards Approved in 2003
PBR rewards are not included in the company's earnings before they areCPUC
approval is received. The following table reflects awards approved by the CPUC.
The COS andin
2003 (dollars in millions):
Program
-----------------------------------
Natural gas PBR cases for SDG&E were filed on December 20, 2002. The
filings outline projected expenses (excluding the commodity cost of
electricity or natural gas consumed by customers or expenses for
programs such as low-income assistance) and revenue requirements for
2004 and a formula for 2005 through 2008. SDG&E's cost of service study
proposes increases in electric and natural gas base rate revenues of
$58.9 million and $21.6 million, respectively. The filings also
requested a continuance and expansion of PBR in terms of earnings
sharing and performance service standards that include both reward and
penalty provisions related to customer satisfaction, employee safety
and system reliability. The resulting new base rates are expected to be
effective on January 1, 2004. A CPUC decision is expected in late 2003.
SDG&E's in effect through December 31, 2003, at which time the
mechanism will be updated. That update will include, among other
things, a reexamination of SDG&E's reasonable costs of operation to be
allowed in rates.
An October 10, 2001 decision denied SDG&E's request to continue equal
sharing between ratepayers and shareholders of the estimated savings
for the PE/Enova merger as more fully discussed in Note 1 and, instead,
ordered that all of the estimated 2003 merger savings go to ratepayers.
This decision will adversely affect the company's net income by $11
million.
In August 2002, the CPUC issued a resolution approving SDG&E's 2000 PBR
report. The resolution approved SDG&E's request for a total net reward
of $11.7 million (pretax), as well as SDG&E's actual 2000 rate of
return (applicable only to electric distribution and natural gas
transportation) of 8.74 percent, which is below the authorized 8.75
percent. This results in no sharing of earnings in 2000 under the PBR
sharing mechanism. The financial results herein include the reward
during the third quarter of 2002.
During 2002, SDG&E filed its 2001 PBR report with the CPUC. Based on
the results against the performance indicator benchmarks, SDG&E
requested a total net reward of $12.2 million.
These proceedings do not encompass electric transmission issues. By the
end of February 2003, SDG&E will file an electric transmission rate
request with the FERC, updating its ratebase and its revenue
requirement for operating and maintenance costs.
Natural Gas Procurement PBR
SDG&E has a Natural Gas Procurement PBR mechanism that allows SDG&E to
receive a share of the savings it achieves by buying natural gas for
customers below a monthly benchmark. SDG&E's request for a reward of
$6.7 million for the PBR natural gas procurement period ended July 31,
73
2001 (Year 8) was approved by the CPUC on January 30, 2003. As part of
the reward calculation is based on California-Arizona natural gas
border price indices, the decision reserved the right to revise the
reward in the future, depending on the outcome of the CPUC's border
price investigation (see below) and the FERC's investigation into
alleged energy price manipulation (see Note 10 above). In October 2002,
SDG&E filed its Year 9 report for the$ (1.4)
Natural gas PBR natural gas procurement
period ended July 31,Year 8 6.7
Distribution PBR 2001 12.2
Distribution PBR 2002 reporting a $1.4 million disallowance,
which was recorded during the three-month period ended September 30,
2002. SDG&E also filed an application on October 31, 2002, seeking to
modify and extend the Natural Gas PBR mechanism beyond Year 10, which
ends July 31, 2003.
Demand Side Management (DSM) and Energy Efficiency Awards
Since the 1990s, the IOUs have been eligible to earn awards for
implementing and/or administering energy-conservation programs. SDG&E
has offered these programs to customers and has consistently achieved
significant earnings therefrom. Beginning in 2002, earnings for non-
low-income energy-efficiency programs were eliminated; however, awards
related to DSM and low-income energy-efficiency programs may still be
requested.
SDG&E has outstanding before the CPUC applications to recover
shareholder rewards earned for performance under the DSM programs for
1995 through 2001. Reward requests in these applications total $35.5
million.
A CPUC Administrative Law Judge has scheduled a pre-hearing conference
to review the IOU's DSM programs. The review may include reanalyzing
the uncollected portion of past rewards earned by IOUs (which have not
been included in SDG&E's income), and potentially recompute the amount
of the DSM rewards. The California Utilities have opposed such a
recalculation. The issue is still pending before the CPUC.6.0
-----------------------------------
Total $ 23.5
===================================
Pending Incentive Awards
At December 31, 2002,2003, the following performance incentives were
pending CPUC approval and, therefore, were not included in the
company's earnings (dollars in millions):
Program
---------------------------------
PBR $ 12.2-----------------------------------
Natural gas procurement 6.7
DSM 35.5
---------------------------------PBR Year 10 $ 1.9
DSM/Energy Efficiency* 35.6
-----------------------------------
Total $ 54.4
=================================37.5
===================================
* Dollar amounts shown do not include interest, franchise fees
or uncollectible amounts.
Cost of Capital
Effective January 1, 2003, SDG&E's authorized rate of return on equity
(ROE) is 10.9 percent (increased from 10.6 percent)and its return on ratebase is 8.77 percent, for
SDG&E's electric distribution and natural gas businesses. This change results in an
annual revenue requirement increase of $2.4 million ($1.9 million
electric and $0.5 million natural gas) and increases SDG&E's overall
74
rate of return from 8.75 percent to 8.77 percent. These rates remain in
effect through 2003. The
electric-transmission cost of capital is determined under a separate
FERC proceeding (see below). These rates will continue to be effective
until market interest-rate changes are large enough to trigger an
automatic adjustment or until the CPUC orders a periodic review.
The objective of SDG&E's market-indexed capital adjustment mechanism
is to revise SDG&E's rates to reflect changes in the six-month average
of double-A rated utility bond rates, without lengthy CPUC
proceedings. The benchmark average is currently 7.24 percent, the six-
month average at September 30, 2002, the year of SDG&E's last cost of
capital proceeding. If in any year the difference between the current
six-month average at September 30th and the benchmark exceeds 100
basis points, SDG&E's authorized ROE is adjusted by one-half of the
difference, and the embedded costs of debt and preferred equity are
adjusted to current levels. In addition, the triggering six-month
average becomes the new benchmark until another automatic adjustment
occurs. The six-month average was 6.32 percent at September 30, 2003
and, therefore, no triggering has occurred. The rate has not changed
significantly since then.
73
Border Price Investigation
OnIn November 21, 2002, the CPUC instituted an investigation into the
Southern California natural gas market and the price of natural gas
delivered to the California-Arizona (CA-AZ) border during the period ofbetween March 2000 throughand May
2001. The CPUC intends to examine the possible
reasons for and issues potentially related to the elevated border
prices that affected California consumers during this period.
SDG&E is included among the respondents to the investigation. If the investigation determines that the conduct of any respondentparty to
the investigation contributed to the natural gas price spikes, at the CA-AZ border during this period,
the
CPUC may modify the respondent's applicableparty's natural gas procurement incentive
mechanism, reduce the amount of any shareholder award for the period
involved, and/or order the respondentparty to issue a refund to ratepayersratepayers.
Hearings are scheduled to offset the higher rates paid. SDG&E is fully cooperatingbegin in late March 2004 with the CPUC in the investigation and believea decision
expected by late 2004. The company believes that the CPUC will ultimately determinefind
that they were not responsible forSoCalGas acted in the high border
prices during this period.best interests of its core customers.
Biennial Cost Allocation Proceeding (BCAP)
The BCAP determines the allocation of authorized costs between
customer classes and the rates and rate design applicable to such classes for natural gas transportation service.service provided by
the company and adjusts rates to reflect variances in customer demand
as compared to the forecasts previously used in establishing
transportation rates. SDG&E filed with the CPUC its 2005 BCAP
application in September 2003, requesting updated transportation rates
effective January 1, 2005. The most recent BCAP on
October 5, 2001.decision allocating
the California Utilities non-commodity natural gas costs of service
and revising their respective natural gas transportation rates and
rate designs was issued in April 2000 and is still in effect. In
FebruaryNovember 2003, an Assigned Commissioner Ruling delayed the current
BCAP applications until a CPUC Administrative Law Judge
granteddecision is issued in the GIR implementation
proceeding discussed above. As a motion to defer the BCAP.result, SDG&E must submit an amendedis required to amend
its BCAP application by September 2003, with new rates scheduled to be
implemented by September 2004.
Nuclear Decommissioning Trusts
On June 17, 2002, SDG&E amended its March 21, 2002 joint application
with Edison, requesting28 days after a decision in the CPUC to set contribution levels for the
SONGS nuclear decommissioning trust funds. SDG&E requested a rate
increase to cover its share of projected increased decommissioning
costs for SONGS. If approved, the current annual contribution to
SDG&E's trust funds, which is recovered in rates, would increase to
$11.5 million annually from $4.9 million. Prior to August 1999, SDG&E's
annual contribution had been $22 million.
Utility Integration
On September 20, 2001, the CPUC approved Sempra Energy's request to
integrate the management teams of SDG&E and SoCalGas. The decision
retains the separate identities of each utility and is not a merger.
Instead, utility integration is a reorganization that consolidates
senior management functions of the two utilities and returns to the
utilities the majority of shared support services previously provided
by Sempra Energy's centralized corporate center. Once implementation is
completed, the integration is expected to result in more effective
operations.
75
In a related development, an August 2002 CPUC interim decision denied a
request by SDG&E and SoCalGas to combine their natural gas procurement
activities at this time, pending completion of the CPUC's Border Price
Investigation referred to above.GIR.
CPUC Investigation of Energy-Utility Holding Companies
The CPUC has initiated an investigation into the relationship between
California's IOUs and their parent holding companies. Among the
matters to be considered in the investigation are utility dividend
policies and practices and obligations of the holding companies to
provide financial support for utility operations under the agreements
with the CPUC permitting the formation of the holding companies. OnIn
January 11, 2002 the CPUC issued a decision to clarify under what
circumstances, if any, a holding company would be required to provide
financial support to its utility subsidiaries. The CPUC broadly
determined that it would require the holding company to provide cash
to a utility subsidiary to cover its operating expenses and working
capital to the extent they are not adequately funded through retail
rates. This would be in addition to the requirement of holding
companies to cover their utility subsidiaries' capital requirements,
as the IOUs have previously acknowledged in connection with the
holding companies' formations. OnIn January 14, 2002 the CPUC ruled on
jurisdictional issues, deciding that the CPUCit had jurisdiction to create the
holding company system and, therefore, retains jurisdiction to enforce
conditions to which the holding companies had agreed. The company's
request for rehearing on the issues was denied by the CPUC and the
company subsequently filed appeals in the California Court of Appeal.
On November 26, 2003 the California Court of Appeal agreed to hear the
company's appeal. Oral argument is set for March 5, 2004.
74
CPUC Investigation of Compliance with Affiliate Rules
In February 2003, the CPUC opened an investigation of the business
activities of SDG&E, SoCalGas and Sempra Energy to determine if they
have complied with statutes and CPUC decisions in the management,
oversight and operations of their companies. In September 2003, the
CPUC suspended the procedural schedule until it completes an
independent audit to evaluate energy-related holding company systems
and affiliate activities undertaken by Sempra Energy within the service
territories of SDG&E and SoCalGas. The audit will cover years 1997
through 2003, is expected to commence in March 2004 and should be
completed by the end of 2004. The scope of the audit will be broader
than the annual affiliate audit. In accordance with existing CPUC
requirements, the California Utilities' transactions with other Sempra
Energy affiliates have been audited by an independent auditing firm
each year, with results reported to the CPUC, and there have been no
material adverse findings in those audits.
FERC Standards of Conduct
On November 25, 2003, the FERC established standards of conduct
governing the relationship between transmission providers and their
energy affiliates. They broaden the definition of an energy affiliate.
Under the standards, SDG&E is a transmission provider and SoCalGas is
an energy affiliate of SDG&E. The standards require transmission
providers to offer service to all customers on a non-discriminatory
basis.
FERC Transmission Cost of Service
On May 2, 2003, the FERC accepted SDG&E's request for modification of
its Transmission Owner Tariff to adopt a transmission rate formula that
would allow SDG&E to recover its actual prudent costs for transmission
service. New transmission rates, which are still pending.
Valley-Rainbow Interconnectsubject to refund based on
the FERC's final order, became effective October 1, 2003.
On December 19,18, 2003, the FERC approved the transmission formula, with
rates effective October 1, 2003, whereby SDG&E's rates would be
adjusted annually to cover actual prudent costs, including an ROE of
11.25 percent on its actual equity as of December 31 of the prior year.
SDG&E's revenue requirements for its retail customers for the initial
12-month period beginning October 1, 2003, will be $142.1 million.
SDG&E will fully recover its cancelled Valley-Rainbow Project costs of
$19 million over a ten-year amortization period, with no return
component. The transmission rate formula will be in effect through June
30, 2007.
Recovery of Certain Disallowed Transmission Costs
In August 2002 the CPUCFERC issued Opinion No. 458, which effectively
disallowed SDG&E's recovery of the differentials between certain
payments to SDG&E by its co-owners of the Southwest Powerlink under the
Participation Agreements and charges assessed to SDG&E under the ISO
FERC tariff for transmission line losses and grid management charges
related to energy schedules of Arizona Public Service Co. (APS) and the
Imperial Irrigation District (IID), its Southwest Powerlink co-owners.
75
As a decision findingresult, SDG&E is incurring unreimbursed costs of $4 million to $8
million per year. On November 17, 2003, SDG&E petitioned the United
States Court of Appeals for review of these FERC orders and argued that
the Valley-Rainbow Interconnect,disallowed costs should be allowed for recovery through the
Transmission Revenue Balancing Account Adjustment. On February 12,
2004, on the FERC's motion, the court remanded the case back to the
FERC for further consideration, "based on the FERC's representation
that it intends to act expeditiously on remand." The FERC has not yet
issued further orders in this matter.
In a proposed 500-kvseparate but related matter, on July 6, 2001 SDG&E filed an
arbitration claim against the ISO claiming the ISO should not charge
SDG&E for the transmission line
connectinglosses attributable to energy schedules on
the APS and IID shares of the Southwest Powerlink. As of October 2003
amounts under the claim totaled $22 million, including interest. The
independent arbitrator found in SDG&E's favor on this matter. The ISO
appealed this result to the FERC and Edison's transmission systems,a FERC decision is not neededexpected in
2004. SDG&E has also commenced a private arbitration to meetreform the
Participation Agreements to remove prospectively SDG&E's projected resource needsobligation to
provide services giving rise to unreimbursed ISO tariff charges.
Southern California Fires
Several major wildfires that began on October 26, 2003 severely damaged
some of SDG&E's infrastructure, causing a significant number of
customers to be without utility services. On October 27, 2003, Governor
Gray Davis declared a "state of emergency" for counties within SDG&E's
service territory.
The declaration of a planning horizon thatstate of emergency authorizes a public utility to
establish a catastrophic event memorandum account (CEMA) to record all
incremental costs (costs not already included in rates) associated with
the CPUC deemed appropriate (five years). If it chooses to, SDG&E can
refile at a later date. In January 2003, SDG&Erepair of facilities and the ISO filed
applicationsrestoration of service. Electric
distribution and natural gas related costs are recovered through the
CEMA. Electric transmission related costs are recovered through the
annual true-up FERC proceeding. The CEMA related costs are recoverable
in rates separate from ordinary costs currently recovered in rates. The
CPUC is required to hold expedited hearings in response to the
utilities' request for rehearingrecovery. Total fire-related costs are estimated
to be $70 million with $60 million incurred during 2003, the majority
of the decision. If this project is
abandoned SDG&E plans to seek recovery of its costs ($20 million
throughwhich were capital related. At December 31, 2002)2003, the CEMA account
included $14 million of incremental operating and maintenance costs.
The company expects to file a CEMA application sometime in a FERC filing to be made in February
2003.2004. The
company expects no significant effect on earnings from the fires.
NOTE 12. COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts
SDG&E buys natural gas under short-term and long-term contracts. Short-
termShort-term purchases
are from various Southwest U.S. and Canadian suppliers and are
primarily based on monthly spot-market prices. SDG&E transports natural
gas under long-term firm pipeline capacity agreements that provide for
annual reservation charges, which are recovered in rates.
SDG&E has long-term natural gas transportation contracts with various
interstate pipelines that expire on various dates between 20032004 and76
2023. SDG&E has a long-term purchase agreement with a Canadian supplier
that expires in August 2003, and in which the delivered cost of natural
gas is tied to the California border spot-market price. SDG&Ecurrently purchases
76
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 gasand purchases additional spot market
supplies delivered directly to California for its own use andremaining
requirements. SDG&E continues its ongoing assessment of its long-term
pipeline capacity portfolio, including the release of a portion of this
capacity to third parties.
All of SDG&E's natural gas is delivered through SoCalGas' pipelines
under a short-term transportation agreement. In addition, under a
separate agreement expiring in March 2003,2005, SoCalGas provides SDG&E
4.5eight billion cubic feet of storage capacity.
An agreement is expected to be
completed with SoCalGas that will extend storage services through March
2004.
At December 31, 2002,2003, the future minimum payments under natural gas
storage and transportation contracts were:
Storage and Natural
(Dollars in millions)
Transportation Gas Total
- --------------------------------------------------------------------
2003----------------------------------------------------------------
2004 $ 20
2005 23
2006 16
2007 14
$ 17 $ 31
20042008 14
-- 14
2005 13 -- 13
2006 12 -- 12
2007 11 -- 11
Thereafter 153 -- 153
----------------------------------------------142
------
Total minimum payments $ 217 $ 17 $ 234229
- ------------------------------------------------------------------------------------------------------------------------------------
Total payments under natural gas contracts were $274 million in 2003,
$205 million in 2002 and $457 million in 2001 and $273 million in 2000.2001.
Purchased-Power Contracts
OnIn January 17, 2001, the California Assembly passed AB X1 to allow the DWR
to purchase power under long-term contracts for the benefit of
California consumers. In accordance with AB X1, SDG&E entered into an
agreement with the DWR under which the DWR purchases SDG&E's full net
short position (the power needed by SDG&E's customers, other than that
provided by SDG&E's nuclear generating facilities or its previously
existing purchased powerpurchased-power contracts) through December 31, 2002. Starting
on January 1, 2003, SDG&E and the other IOUs resumed their electric
commodity procurement function based on a CPUC decision issued in
October 2002. In April 2003, the CPUC approved an operating agreement
between the DWR and SDG&E that bestows upon SDG&E the role of a limited
agent on behalf of the DWR in undertaking energy sales and natural gas
procurement functions for the DWR contracts. For additional discussion
of this matter see Note 10.
For 2003,2004, SDG&E expects to receive 4349 percent of its customer power
requirement from DWR allocations. Of the remaining requirements, that
SDG&E must provide, SONGS
willis expected to account for 21 percent, long-term contracts for 2619
percent and spot market purchases for 1011 percent. As
of January 2003, SDG&E has approximately 90 percent of its electric
power requirements met by a combination of long-term contracts, DWR-
allocated contracts and its share of nuclear generating facilities. The contracts expire
on various dates between 2003 andthrough 2025. Prior to January 1, 2001, the cost of
these contracts was recovered by bidding them into the PX and receiving
revenue from the PX for bids accepted. As of January 1, 2001, in
compliance with a FERC order prohibiting sales to the PX, SDG&E no
longer bids those contracts into the PX. 77
Those contracts are now used
to serve customers in compliance with a CPUC order. In late 2000, SDG&E entered into additional contracts to
serve customers instead of buying all of its power from the PX. These
contracts expire in 2003. In addition, during77
2002 SDG&E entered into contracts which will provide approximately fourfive percent of
its 20032004 total energy sales from renewable sources. These contracts
expire from
2008on various dates through 2018.2021.
At December 31, 2002,2003, the estimated future minimum payments under the
long-term contracts (not including the DWR allocation)allocations) were:
(Dollars in millions)
- --------------------------------------------------------------------
20032004 $ 257
2004 227214
2005 228224
2006 224233
2007 213240
2008 218
Thereafter 2,2852,235
--------
Total minimum payments $ 3,4343,364
- --------------------------------------------------------------------
The payments represent capacity charges and minimum energy purchases.
SDG&E is required to pay additional amounts for actual purchases of
energy that exceed the minimum energy commitments. TotalExcluding DWR-
allocated contracts, total payments under the contracts were $396
million in 2003, $235 million in 2002 and $512 million in 2001 and $257
million in 2000.2001.
Leases
SDG&E has operating leases on real and personal property expiring at
various dates from 20032004 to 2045. Certain leases on office facilities
contain escalation clauses requiring annual increases in rent ranging
from 3 percent to 56 percent. The rentals payable under these leases are
determined on both fixed and percentage bases, and most leases contain
extension options which are exercisable by SDG&E. SDG&E terminated its
capital lease agreement for nuclear fuel in mid-2001 and now owns its
nuclear fuel.
At December 31, 2002,2003, the minimum rental commitments payable in future
years under all noncancellable leases were as follows:
(Dollars in millions)
- ------------------------------------------------------------
2003 $16
2004 14$ 17
2005 1216
2006 1013
2007 11
2008 6
Thereafter 17
--------23
-----
Total future rental commitments $75$ 86
- ------------------------------------------------------------
Rent expense for operating leases totaled $28 million in 2003, $27 million in 2002 and $21
million in 2001 and $32 million in 2000.
2001.
78
Environmental Issues
The company's operations are subject to federal, state and local
environmental laws and regulations governing hazardous wastes, air and
water quality, land use, solid waste disposal and the protection of
wildlife. As applicable, appropriate and relevant, theseThese laws and regulations require that the company
investigate and remediate the effects of the release or disposal of
materials at sites associated with past and present operations,
including sites at which the company has been identified as a
Potentially Responsible Party (PRP) under the federal Superfund laws
and comparable state laws. Costs incurred to operate the facilities in
compliance with these laws and regulations generally have been
recovered in customer rates.
Significant costs incurred to mitigate or prevent future environmental
contamination or extend the life, increase the capacity, or improve the
safety or efficiency of property utilized in current operations, are
capitalized. The company's capital expenditures to comply with
environmental laws and regulations were $5 million in 2003, $4 million
in 2002 and $1 million in 2001 and $2 million in 2000.2001. The cost of compliance with these
regulations over the next five years is not expected to be significant.
Costs that relate to current operations or an existing condition caused
by past operations are generally recorded as a regulatory asset due to
the assuranceexpectation that these costs will be recovered in rates.
The environmental issues currently facing the company or resolved
during the latest three-year period include investigation and
remediation of its manufactured-gas sites (three completed as of
December 31, 20022003 and site-closure letters received for two), cleanup
at SDG&E's former fossil fuel power plants (all sold in 1999 and actual
or estimated cleanup costs included in the transactions), cleanup of
third-party waste-disposal sites used by the company, which has been
identified as a PRP (investigations and remediations are continuing)
and mitigation of damage to the marine environment caused by the
cooling-water discharge from SONGS (the requirements for enhanced fish
protection, a 150-acre artificial reef and restoration of 150 acres of
coastal wetlands are in process). Through December 31, 2003, the SONGS
mitigation costs are recovered through the ICIP mechanism.
Environmental liabilities are recorded when the company's liability is
probable and the costs are reasonably estimable. In many cases,
however, investigations are not yet at a stage where the company has
been able to determine whether it is liable or, if the liability is
probable, to reasonably estimate the amount or range of amounts of the
cost or certain components thereof. Estimates of the company's
liability are further subject to other uncertainties, such as the
nature and extent of site contamination, evolving remediation standards
and imprecise engineering evaluations. The accruals are reviewed
periodically and, as investigations and remediation proceed,
adjustments are made as necessary. At December 31, 2002,2003, the company's
accrued liability for environmental matters was $14.8$17.3 million, of which
$1.5$5.8 million related to manufactured-gas sites, $12.1$10.5 million to
cleanup at SDG&E's former fossil-fueled power plants, $0.9 million to
waste-disposal sites used by the company (which has been identified as
79
a PRP) and $0.3$0.1 million to other hazardous waste sites. These accruals
are expected to be paid ratably over the next threetwo years.79
Nuclear Insurance
SDG&E and the other co-ownersowners of SONGS have insurance to respond to any
nuclear liability claims related to SONGS. The insurance policy
provides $200$300 million in coverage, which is the maximum amount
available. In addition to this primary financial protection, the Price-
Anderson Act provides for up to $9.25$10.6 billion of secondary financial
protection if the liability loss exceeds the insurance limit. Should
any of the licensed/commercial reactors in the United States experience
a nuclear liability loss which exceeds the $200$300 million insurance
limit, all utilities owning nuclear reactors could be assessed under
the Price-Anderson Act to provide the secondary financial protection.
SDG&E and the other co-owners of SONGS could be assessed up to $176$201
million under the Price-Anderson Act. SDG&E's share would be $36$40
million unless a default occurswas to occur by any other SONGS co-owner. In
the event the secondary financial protection limit iswere insufficient to
cover the liability loss, the Price-Anderson Act provides for Congress
to enact further revenue raisingrevenue-raising measures to pay claims. These measures
could include an additional assessment on all licensed reactor
operators.
SDG&E and the other co-ownersowners of SONGS have $2.75 billion of nuclear
property, decontamination and debris removal insurance. The coverage
also provides the SONGS owners up to $490 million for outage
expensesexpenses/replacement power incurred because of accidental property
damage. This coverage is limited to $3.5 million per week for the first
52 weeks, and $2.8 million per week for up to 110 additional weeks.
CoverageThere is also
provided for the cost of replacement power, which includes indemnity
payments for up to three years, after a deductible waiting period of 12 weeks.weeks prior to receiving
indemnity payments. The insurance is provided through a mutual
insurance company owned by utilities with nuclear facilities. Under the
policy's risk sharing arrangements, insured members are subject to
retrospective premium assessments if losses at any covered facility
exceed the insurance company's surplus and reinsurance funds. Should
there be a retrospective premium call, SDG&E could be assessed up to
$7.6$7.4 million.
Both the nuclear liability and property insurance programs include
industry aggregate limits for terrorism-related SONGS losses, resulting from actsincluding
replacement power costs.
Litigation
During 2003, the company recorded $11 million of terrorism.
Department Of Energy Decommissioning
The Energy Policy Actafter-tax charges
against income for litigation costs and possible resolution of 1992 established a fundcertain
cases. Management believes that none of these matters will have further
material adverse effect on the company's financial condition or results
of operations. Except for the decontamination and decommissioning of the Department of Energy (DOE)
nuclear fuel enrichment facilities. Utilities which have used DOE
enrichment services are being assessed a total of $2.3 billion, subjectmatters referred to adjustment for inflation, over a 15-year period ending in 2006. Each
utility's share is based on its share of enrichment services purchased
from the DOE through 1992. SDG&E's annual assessment is approximately
$1 million, which is recovered through SONGS revenue.
80
Department Of Energy Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 made the DOE responsible for the
disposal of spent nuclear fuel. However, it is uncertain when the DOE
will begin accepting spent nuclear fuel from SONGS. This delay by the
DOE will lead to increased cost for spent fuel storage. This cost will
be recovered through SONGS revenue unlessbelow, neither the
company nor its subsidiary is ableparty to, recovernor is its property the increased cost from the federal government.subject
of, any material pending legal proceedings other than routine
litigation incidental to its businesses.
Antitrust Litigation
LawsuitsClass-action and individual lawsuits filed in 2000 and currently
consolidated in San Diego Superior Court seek class-action certification and damages, alleging that
Sempra Energy, SoCalGas and SDG&E, along with El Paso Energy Corp. (El
Paso) and several of its affiliates, unlawfully sought to control
and have manipulated80
natural gas and electricity markets. On October 16, 2002,In March 2003, plaintiffs in these
cases and the assigned
San Diego Superior Court judge ruledapplicable El Paso entities announced that the case can proceed with
discovery and thatthey had
reached a $1.5 billion settlement, of which $125 million is allocated
to customers of the California courts, rather than the FERC, have
jurisdictionUtilities. The Court approved that
settlement in the case. This was a preliminary ruling and not a
ruling on the merits or facts of the case. Northern California cases,
which only name El Paso as a defendant, are scheduled for trial in
September 2003December 2003. The proceeding against Sempra Energy and
the remainder of the cases is set for trial in
January 2004. During the fourth quarter of 2002, additional similarCalifornia Utilities has not been settled and continues to be
litigated.
Natural Gas Cases: Similar lawsuits have been filed by the Attorneys
General of Arizona and Nevada, alleging that El Paso and certain Sempra
Energy subsidiaries unlawfully sought to control the natural gas market
in various jurisdictions.their respective states. In April 2003, Sierra Pacific Resources and
its utility subsidiary Nevada Power filed a lawsuit in U.S. District
Court in Las Vegas against major natural gas suppliers, including
Sempra Energy, the California Utilities and other company subsidiaries,
seeking damages resulting from an alleged conspiracy to drive up or
control natural gas prices, eliminate competition and increase market
volatility, breach of contract and wire fraud. On January 27, 2004, the
U.S. District Court dismissed the Sierra Pacific Resources case against
all of the defendants, determining that this is a matter for the FERC.
Electricity Cases: Various lawsuits, which seek class-action
certification, allege that Sempra Energy and certain company
subsidiaries, including SDG&E, unlawfully manipulated the electric-
energy market. In January 2003, the applicable federal court granted a
motion to dismiss a similar lawsuit on the grounds that the claims
contained in the complaint were subject to the Filed Rate Doctrine and
were preempted by the Federal Power Act. That ruling has been appealed
in the Ninth Circuit Court of Appeals, which is expected to hear the
appeal in the first quarter of 2004. Similar suits filed in Washington
and Oregon were voluntarily dropped by the plaintiffs without court
intervention in June 2003.
SDG&E and two other subsidiaries of Sempra Energy, along with all other
sellers in the western power market, have been named defendants in a
complaint filed at the FERC by the California Attorney General's office
seeking refunds for electricity purchases based on alleged violations
of FERC tariffs. The FERC has dismissed the complaint. The California
Attorney General's office requested a rehearing, which the FERC denied.
The California Attorney General has filed an appeal in the 9th Circuit.
ExceptFERC Actions
Information regarding FERC actions related to the company is provided
in Note 10 of the notes to Consolidated Financial Statements.
Department Of Energy Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 made the DOE responsible for the
matters referreddisposal of spent nuclear fuel. However, it is uncertain when the
Department of Energy (DOE) will begin accepting spent nuclear fuel from
SONGS. This delay by the DOE will lead to above, neitherincreased cost for spent fuel
storage. This cost will be recovered through SONGS revenue unless the
company nor its
subsidiary is partyable to nor is their propertyrecover the subject of, any
material pending legal proceedings other than routine litigation
incidental to their businesses.
Management believesincreased cost from the above allegations are without merit and will
not have a material adverse effect on the company's financial condition
or results of operations.
Other Legal Proceedings
In connection with its investigation into California energy prices, in
May 2002 the FERC ordered all energy companies engaged in electric
energy trading activities to state whether they had engaged in "death
star," "load shift," "wheel out," "ricochet," "inc-ing load" and
various other specific trading activities as described in memos
prepared by attorneys retained by Enron Corporation and in which it was
asserted that Enron was manipulating or "gaming" the California energy
markets. In response to the inquiry, SDG&E has denied using any of
these strategies. It did disclose and explain a single de minimus 100-
mW transaction for the export of electricity out of California. In
response to a related FERC inquiry regarding natural gas trading, it
has also denied engaging in "wash" or "round trip" trading activities.
federal
government.
81
SDG&E is also cooperating with the FERC and other governmental agencies
and officials in their various investigations of the California energy
markets. Management believes that this matter will not have a material
adverse effect on the company's financial condition or results of
operations.
Electric Distribution System Conversion
Under a CPUC-mandated program, the cost of which is included in utility
rates, and through franchise agreements with various cities, SDG&E is
committed, in varying amounts, to converting overhead distribution
facilities to underground. As of December 31, 2002,2003, the aggregate
unexpended amount of this commitment was $98$90 million. Capital
expenditures for underground conversions were $28 million in 2003, $33
million in 2002 and $12 million in 2001 and $26 million in 2000.2001.
Concentration Of Credit Risk
The company maintains credit policies and systems to manage overall
credit risk. These policies include an evaluation of potential
counterparties' financial condition and an assignment of credit limits.
These credit limits are established based on risk and return
considerations under terms customarily available in the industry.
The company grants credit to customers and counterparties,
substantially all of whom are located in its service territories, which
covers all of San Diego County and an adjacent portion of Orange
County.
As discussed in Note 10, SDG&E accumulated certain costs of electricity
purchases in a balancing account (the AB 265 undercollection). SDG&E
may experience an increase in customer credit risk as it passes on
these costs to customers, as well as charges on behalf of the state of
California to repay the state bonds issued in connection with its past
purchases of power for IOU customers. However, mitigating this increase
in customer credit risk are the decline in the cost of the electric
commodity and return to stability thereof, and the October 2002 CPUC
decision which allows SDG&E to enter into new contracts to procure
electric energy and to establish a cost recovery mechanism. The
decision establishes a semiannual cost review and rate recovery
mechanism with a trigger for more frequent rate changes if balances
exceed five percent of annual, non-DWR generation revenues, to provide
for timely recovery of any undercollections.
82
NOTE 13. QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarters ended
------------------------------------------------
Dollars(Dollars in millionsmillions) March 31 June 30 September 30 December 31
- --------------------------------------------------------------------------------------
2003
Operating revenues $ 562 $ 520 $ 667 $ 562
Operating expenses 497 467 533 433
-----------------------------------------------
Operating income $ 65 $ 53 $ 134 $ 129
-----------------------------------------------
Net income $ 47 $ 42 $ 121 $ 130
Dividends on preferred stock 2 1 1 2
-----------------------------------------------
Earnings applicable
to common shares $ 45 $ 41 $ 120 $ 128
===============================================
2002
Operating revenues $ 427432 $ 407414 $ 420425 $ 442454
Operating expenses 358 340 356 380
------------------------------------------------363 347 361 392
-----------------------------------------------
Operating income $ 69 $ 67 $ 64 $ 62
-----------------------------------------------------------------------------------------------
Net income $ 55 $ 52 $ 48 $ 54
Dividends on preferred stock 2 1 2 1
-----------------------------------------------------------------------------------------------
Earnings applicable
to common shares $ 53 $ 51 $ 46 $ 53
================================================
2001
Operating revenues $ 1,129 $ 511 $ 333 $ 389
Operating expenses 1,056 454 271 360
------------------------------------------------
Operating income $ 73 $ 57 $ 62 $ 29
------------------------------------------------
Net income $ 54 $ 38 $ 45 $ 46
Dividends===============================================
Reclassifications have been made to certain of the amounts since they were
presented in the Quarterly Reports on preferred stock 2 1 2 1
------------------------------------------------
Earnings applicable
to common shares $ 52 $ 37 $ 43 $ 45
================================================Form 10-Q.
The sum of the quarterly amounts does not necessarily equal the annual
totals due to rounding.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURES
None.
83
PART III82
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 Information 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
- -------------------------------------------------------------------
Edwin A. Guiles 53 Chairman and Chief Executive Officer
Debra L. Reed 46 President and Chief Financial Officer
James P. Avery 46 Senior Vice President, Electric
Transmission
Steven D. Davis 46 Senior Vice President, Customer
Service and External Relations
Margot A. Kyd 49 Senior Vice President, Corporate
Business Solutions
Roy M. Rawlings 58 Senior Vice President, Distribution
Operations
William L. Reed 50 Senior Vice President, Regulatory
Affairs
Lee M. Stewart 57 Senior Vice President, Gas
Transmission
Terry M. Fleskes 46 Vice President and Controller
* As of December 31, 2002.
Except for Mr. Avery, each Executive Officer has been an officer or
employee of Sempra Energy or one of its subsidiaries for more than five
years. Prior to joining SDG&E in 2001, Mr. Avery was a consultant with
R.J. Rudden Associates. Except for Mr. Avery, each executive officer of
San Diego Gas & Electric Company holds the same position at Southern
California Gas Company.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference from
"Election of Directors" and "Executive Compensation" in the Information
Statement prepared for the May 2003 annual meeting of shareholders.
84
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 Information Statement prepared for the May
2003 annual meeting of shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
ITEM 14.9A. CONTROLS AND PROCEDURES.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 dateas of this reportDecember 31, 2003 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.
85evaluation..
83
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
Information Statement prepared for the May 2004 annual meeting of
shareholders. The information required on the company's executive
officers is provided below.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* Position
- -------------------------------------------------------------------
Edwin A. Guiles 54 Chairman and Chief Executive Officer
Debra L. Reed 47 President and Chief Financial Officer
James P. Avery 47 Senior Vice President, Electric
Transmission
Steven D. Davis 47 Senior Vice President, Customer
Service and External Relations
Margot A. Kyd 50 Senior Vice President, Corporate
Business Solutions
Roy M. Rawlings 59 Senior Vice President, Distribution
Operations
William L. Reed 51 Senior Vice President, Regulatory
Affairs
Lee M. Stewart 58 Senior Vice President, Gas
Transmission
Terry M. Fleskes 47 Vice President and Controller
* As of December 31, 2003.
Except for Mr. Avery, each executive officer of San Diego Gas &
Electric Company holds the same position at Southern California Gas
Company and has been an officer or employee of Sempra Energy or one of
its subsidiaries for more than five years. Prior to joining SDG&E in
2001, Mr. Avery was a consultant with R.J. Rudden Associates.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference from
"Election of Directors" and "Executive Compensation" in the Information
Statement prepared for the May 2004 annual meeting of shareholders.
84
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The security ownership information required by Item 12 is
incorporated by reference from "Share Ownership" in the
Information Statement prepared for the May 2004 annual meeting of
shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Information regarding principal accountant fees and services as
required by Item 14 is incorporated by reference from "Proposal
3: Ratification of Independent Auditors" in the Proxy Statement
prepared for the May 2004 annual meeting of shareholders.
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
This Report
Independent Auditors' Report . . . . . . . . . . . . . . 4034
Statements of Consolidated Income for the years
ended December 31, 2003, 2002 2001 and 20002001 . . . . . . . . 4135
Consolidated Balance Sheets at December 31,
20022003 and 2001.2002. . . . . . . . . . . . . . . . . . . . . 4236
Statements of Consolidated Cash Flows for the
years ended December 31, 2003, 2002 2001 and 20002001 . . . . . 4438
Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2003, 2002 2001 and 20002001 . . . . . . . . . . . 4539
Notes to Consolidated Financial Statements . . . . . . . 4640
2. Financial statement schedules
Other schedules for which provision is made in Regulation S-X are
not required under the instructions contained therein, are
inapplicable or the information is included in the Consolidated
Financial Statements and notes thereto.
85
3. Exhibits
See Exhibit Index on page 8988 of this report.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed after September 30,
2002:
None.
2003:
Current Report on Form 8-K filed November 6, 2003, filing as an
exhibit Sempra Energy's press release of November 6, 2003, giving
the financial results for the three months ended September 30,
2003.
Current Report on Form 8-K filed December 31, 2003, to update
information on the August 25, 2003 CPUC decision regarding the
allocation of profits from intermediate-term purchase power
contracts. Updates when the Court of Appeals will have a decision
on the petition submitted by an advocacy group for small
consumers.
Current Report on Form 8-K filed February 24, 2004, filing as an
exhibit Sempra Energy's press release of February 24, 2004, giving
the financial results for the three months ended December 31, 2003.
86
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in
Registration Statement Numbers 33-45599, 33-52834, 333-52150,333-
52150, and 33-49837 on Form S-3 of our report dated
February 14, 2003,23, 2004, appearing in thisthe Annual Report on Form
10-K of San Diego Gas and Electric Company for the year
ended December 31, 2002.2003.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
February 25, 2003
24, 2004
87
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.
SAN DIEGO GAS & ELECTRIC COMPANY
By: /s/ Edwin A. Guiles
.
Edwin A. Guiles
Chairman and Chief Executive Officer
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.
Name/Title Signature Date
Principal Executive Officer:
Edwin A. Guiles
Chairman and
Chief Executive Officer /s/ Edwin A. Guiles February 17, 200323, 2004
Principal Financial Officer:
Debra L. Reed
President and
Chief Financial Officer /s/ Debra L. Reed February 17, 200323, 2004
Principal Accounting Officer:
Terry M. Fleskes
Vice President and
Controller /s/ Terry M. Fleskes February 17, 200323, 2004
Directors:
Edwin A. Guiles, Chairman /s/ Edwin A. Guiles February 17, 200323, 2004
Debra L. Reed, Director /s/ Debra L. Reed February 17, 200323, 2004
Frank H. Ault, Director /s/ Frank H. Ault February 17, 200323, 2004
88
EXHIBIT INDEX
The Forms 8-K, 10-K and 10-Q referred to herein were filed under
Commission File Number 1-3779 (SDG&E), Commission File Number 1-114391-
11439 (Enova Corporation,Corporation), Commission File Number 1-14201 (Sempra
Energy) and/or Commission File Number 333-30761, (SDG&E Funding
LLC).
Exhibit 1 -- Underwriting Agreements
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
3.01 Restated Bylaws of San Diego Gas & Electric as of November 6,
2001. (2001 Form 10-K Exhibit 3.01)
Articles of Incorporation
3.02 Amended and Restated Articles of Incorporation of San Diego Gas
& Electric Company (Incorporated by reference from the SDG&E
Form 10-Q for the three months ended March 31, 1994
(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.
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.)
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.)
89
Exhibit 10 -- Material Contracts
10.01 Restated LetterOperating Agreement between San Diego Gas & Electric
Company and the
California Department of Water Resources dated April 5, 2001 (200117, 2003
(2003 Sempra Energy Form 10-K, Exhibit 10.04)10.06).
89
10.02 Servicing Agreement between San Diego Gas & Electric and the
California Department of Water Resources dated December 19, 2002
(2003 Sempra Energy Form 10-K, Exhibit 10.07).
10.03 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).
10.0310.04 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).
Compensation
10.0410.05 2003 Sempra Energy Executive Incentive Plan B (2003 Sempra Energy
Form 10-K, Exhibit 10.10).
10.06 2003 Executive Incentive Plan (June 30, 2003 Sempra Energy
Form 10-Q Exhibit 10.1)
10.07 Amended 1998 Long-Term Incentive Plan (June 30, 2003 Sempra
Energy Form 10-Q Exhibit 10.2)
10.08 Sempra Energy Executive Incentive Plan effective January 1, 2003
(2002 Sempra Energy Form 10-K, Exhibit 10.09).
10.0510.09 Amended Sempra Energy Retirement Plan for Directors (2002 Sempra
Energy Form 10-K, Exhibit 10.10).
10.0610.10 Amended and Restated Sempra Energy Deferred Compensation and
Excess Savings Plan (Sempra Energy September(September 30, 2002 Sempra Energy Form
10-Q , Exhibit 10.3).
10.0710.11 Form of Sempra Energy Severance Pay Agreement for Executives
(2001 Sempra Energy Form 10-K, Exhibit 10.07).
10.0810.12 Sempra Energy Executive Security Bonus Plan effective
January 1, 2001 (2001 Sempra Energy Form 10-K, Exhibit 10.08).
10.0910.13 Sempra Energy Deferred Compensation and Excess Savings Plan
effective January 1, 2000 (2000 Sempra Energy Form 10-K,
Exhibit 10.07).
10.1010.14 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(Exhibit1998 (Exhibit
4.1)).
90
Financing
10.1110.15 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).
10.1210.16 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 (1996 Form 10-K, Exhibit
10.31).
10.1310.17 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 (1996 Form 10-K,
Exhibit 10.32).
10.1410.18 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).
90
10.1510.19 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).
10.1610.20 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).
10.1710.21 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).
10.1810.22 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).
10.1910.23 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
(1996 Form 10-K, Exhibit 10.41).
10.2010.24 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).
10.2110.25 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).
91
Nuclear
10.22 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).
10.2310.26 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).
10.2410.27 Amendment No. 1 to the Qualified CPUC Decommissioning Master
Trust Agreement dated September 22, 1994 (see Exhibit 10.2310.26
herein)(1994 SDG&E Form 10-K, Exhibit 10.56).
10.2510.28 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 10.2310.26 herein)(1994 SDG&E Form 10-K, Exhibit 10.57).
91
10.2610.29 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 10.2310.26 herein)(1996 Form 10-K, Exhibit 10.59).
10.2710.30 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 10.2310.26 herein)(1996 Form 10-K, Exhibit 10.60).
10.2810.31 Fifth Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.2310.26 herein)(1999 Form 10-K, Exhibit 10.26).
10.2910.32 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 10.2310.26 herein)(1999 Form 10-K, Exhibit 10.27).
10.3010.33 Seventh Amendment to the San Diego Gas & Electric Company
Nuclear Facilities Qualified CPUC Decommissioning Master
Trust Agreement for San Onofre Nuclear Generating Station
(see Exhibit 10.26 herein)(2003 Sempra Energy Form 10-K,
Exhibit 10.42).
10.34 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).
10.3110.35 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 10.3010.34 herein)(1996 Form 10-K, Exhibit 10.62).
10.3210.36 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 10.3010.34 herein)(1996 Form 10-K, Exhibit 10.63).
10.3392
10.37 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 10.3010.34 herein)(1999 Form 10-K, Exhibit 10.31).
10.3410.38 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 10.3010.34 herein)(1999 Form 10-K, Exhibit 10.32).
10.3510.39 Fifth 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 10.34 herein)(2003 Sempra Energy Form 10-K,
Exhibit 10.48).
10.40 Second Amended San Onofre Operating 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).
10.3610.41 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).
92
Natural Gas Transportation and Storage
10.37 Master Services Contract, Schedule J, Transaction Based Storage
Service Agreement dated April 1, 2002 and expiring March 31,
2003 between San Diego Gas & Electric Company and Southern
California Gas Company.
10.3810.42 Master Services Contract (Intrastate Transmission Service),
dated JulyAugust 1, 1998 (month2003(month to month) to August 1, 2005 between
San Diego Gas & Electric Company and Southern California Gas Company.
(1998 10-K, Exhibit 10.64)
10.3910.43 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).
10.4010.44 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).
10.4110.45 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).
Other
10.4210.46 Lease agreement dated as of March 25, 1992 with CarrAmerica
Development and Construction as lessor of an office
complex at Century Park (1994 SDG&E Form 10-K, Exhibit 10.70).
93
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, 2003, 2002, 2001, 2000, 1999 and 1998.1999.
Exhibit 21 - Subsidiaries
21.01 Schedule of Subsidiaries at December 31, 2002.2003.
Exhibit 23 - Independent Auditors' Consent, page 87.
9386.
Exhibit 31 -- Section 302 Certifications
31.1 Statement of Registrant's Chief Executive Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
31.2 Statement of Registrant's Chief Financial Officer pursuant
to Rules 13a-14 and 15d-14 of the Securities Exchange Act of 1934.
Exhibit 32 -- Section 906 Certifications
32.1 Statement of Registrant's Chief Executive Officer pursuant
to 18 U.S.C. Sec. 1350.
32.2 Statement of Registrant's Chief Financial Officer pursuant
to 18 U.S.C. Sec. 1350.
94
GLOSSARY
AB California Assembly Bill
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
APS Arizona Public Service Co.
BCAP Biennial Cost Allocation Proceeding
Bcf One Billion Cubic Feet (of natural gas)
Calpine Calpine Corporation
CEC California Energy Commission
COS Cost of ServiceCEMA Catastrophic Event Memorandum Act
CPUC California Public Utilities Commission
DA Direct Access
DOE Department of Energy
DSM Demand SideDemand-Side Management
DWR Department of Water Resources
Edison Southern California Edison Company
EG Electric Generation
EITF Emerging Issues Task Force
El Paso El Paso Energy Corp.
EMFs Electric and Magnetic Fields
Enova Enova Corporation
ERMG Energy Risk Management
GroupERMOC Energy Risk Management Oversight Committee
EPA Environmental Protection Agency
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
FIN FASB Interpretation No.
FSP FASB Staff Position
95
GIR Gas Industry Restructuring
ICIP Incremental Cost Incentive Pricing mechanismMechanism
IID Imperial Irrigation District
Intertie Pacific Intertie
IOUs Investor-Owned Utilities
IRS Internal Revenue Service
ISO Independent System Operator
kWh Kilowatt Hour
LIFO Last-in first-outLast in first out inventory costing method
LNG Liquefied Natural Gas
MGP Manufactured-Gas Plants
mmbtu Million British Thermal Units (of natural gas)
MOU Memorandum of Understanding
94
mWMoody's Moody's Investor Service, Inc.
MW Megawatt
NRC Nuclear Regulatory Commission
OIR Order Instituting Ratemaking
ORA Office of Ratepayers Advocates
Parent Enova Corporation
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
PRPPIER Public Interest Energy Research
PPA Purchase Power Agreement
PRPs Potentially Responsible PartyParties
PX Power Exchange
QFs Qualifying Facilities
RD&D Research, Development and Demonstration
RFP Requests For Proposals
ROE Return on Equity
ROR Rate of Return
S&P Standard & Poor's
SB California Senate Bill96
SDG&E San Diego Gas & Electric Company
SEC Securities and Exchange Commission
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 TheUCAN Utility ReformConsumers Action Network
UEG Utility Electric Generation
VaR Value at Risk
95
CERTIFICATIONS
I, Edwin A. Guiles, certify that:
1. I have reviewed this Annual Report on Form 10-K of San Diego Gas &
Electric Company;
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/ Edwin A. Guiles
Edwin A. Guiles
Chief Executive Officer
96
I, Debra L. Reed, certify that:
1. I have reviewed this Annual Report on Form 10-K of San Diego Gas &
Electric Company;
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/ Debra L. Reed
Debra L. Reed
Chief Financial Officer
97