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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, 2000
--------------------
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. [ ]
Exhibit Index on page 70. Glossary on page 75.
Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of February 28, 2001 was $17 million.
Registrant's common stock outstanding as of February 28, 2001 was
wholly owned by Enova Corporation.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 2001
annual meeting of shareholders are incorporated by reference into
Part III.
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . .16
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . .17
Item 4. Submission of Matters to a Vote of Security Holders. .17
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . .18
Item 6. Selected Financial Data. . . . . . . . . . . . . . . .18
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . .19
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . .33
Item 8. Financial Statements and Supplementary Data. . . . . .34
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . .66
PART III
Item 10. Directors and Executive Officers of the Registrant . .66
Item 11. Executive Compensation . . . . . . . . . . . . . . . .66
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . .66
Item 13. Certain Relationships and Related Transactions . . . .66
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . .67
Independent Auditors' Consent . . . . . . . . . . . . . . . . .68
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . .69
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . .70
Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . .75
2
This Annual Report contains statements that are not historical fact
and constitute forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995, including
statements regarding San Diego Gas & Electric Company's ability to
finance undercollected costs on reasonable terms, retain its
financial strength, estimates of future accumulated undercollected
costs, and plans to obtain future financing. The words "estimates,"
"believes," "expects," "anticipates," "plans," "intends," "may,"
"would" and "should" or similar expressions, or discussions of
strategy or of plans are intended to identify forward-looking
statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions.
Future results may differ materially from those expressed in these
forward-looking statements.
Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions; actions by the California Public Utilities
Commission, the California Legislature, the California Department of
Water Resources and the Federal Energy Regulatory Commission; the
financial condition of other investor-owned utilities; inflation
rates and interest rates; energy markets, including the timing and
extent of changes in commodity prices; weather conditions; business,
regulatory and legal decisions; the pace of deregulation of retail
natural gas and electricity delivery; the timing and success of
business-development efforts; and other uncertainties, all of which
are difficult to predict and many of which are beyond the control of
the Company. Readers are cautioned not to rely unduly on any forward-
looking statements and are urged to review and consider carefully the
risks, uncertainties and other factors which affect the Company's
business described in this Annual Report and other reports filed by
the Company from time to time with the 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.
GOVERNMENT REGULATION
Local Regulation
SDG&E has electric franchises with the three counties and the 25
cities and gas franchises with two counties and the 25 cities in its
service territory. These franchises allow SDG&E to locate facilities
for the transmission and distribution of electricity and/or natural
gas in the streets and other public places. The franchises do not
have fixed terms, except for the electric and natural gas franchises
with the cities of Chula Vista (2003), Encinitas (2012), San Diego
(2021) and Coronado (2028); and the natural gas franchises with the
city of Escondido (2036) and the county of San Diego (2030).
3
State Regulation
The State of California Legislature, from time to time, passes laws
that regulate SDG&E's operations. For example, in 1996 the
legislature passed an electric industry deregulation bill, then in
2000 and 2001 passed additional bills aimed at addressing problems in
the deregulated electric industry. In addition, the legislature
enacted a law in 1999 addressing natural gas industry restructuring.
The California Public Utilities Commission (CPUC) 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 also 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 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.
Federal Regulation
The Federal Energy Regulatory Commission (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.
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.
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. They require periodic renewal, which results in
continuing regulation by the granting agency.
Other regulatory matters are described in Note 12 of the notes to
Consolidated Financial Statements, herein.
SOURCES OF REVENUE
Industry segment information is contained in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and in
Note 13 of the notes to Consolidated Financial Statements herein.
4
ELECTRIC OPERATIONS
Resource Planning
In 1996, California enacted legislation restructuring California's
investor-owned electric utility industry. The legislation and related
decisions of the CPUC were intended to stimulate competition and
reduce rates. Beginning on March 31, 1998, customers were given the
opportunity to choose to continue to purchase their electricity from
the local utility under regulated tariffs, to enter into contracts
with other energy service providers (direct access) or to buy their
power from the California Power Exchange (PX) that served as a
wholesale power pool allowing all energy producers to participate
competitively. However, a number of factors, including supply/demand
imbalances, resulted in abnormally high wholesale electric prices
beginning in mid-2000. In response to these high commodity prices,
the California legislature has adopted or is proposing to adopt
legislation intended to stabilize the California electric utility
industry and reduce wholesale electric commodity prices.
Additional information concerning electric-industry restructuring is
provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Notes 11 and 12 of the
notes to Consolidated Financial Statements herein.
Electric Resources
In connection with California's electric-industry restructuring,
beginning March 31, 1998, the California investor-owned utilities
(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. As
discussed in Note 12 of the notes to Consolidated Financial
Statements, due to current conditions in the California electric
utility industry, the PX suspended its trading operations on January
31, 2001. SDG&E has been granted authority by the CPUC to purchase up
to 1,900 megawatts of power through bilateral contracts. Also, the
California legislature recently passed a bill authorizing the
Department of Water Resources (DWR) to enter into long-term contracts
to purchase the portion of power used by SDG&E customers that is not
provided by SDG&E's existing supply. An Independent System Operator
(ISO) schedules power transactions and access to the transmission
system. In 1999, SDG&E completed divestiture of its owned generation
other than nuclear. Based on generating plants in service and
purchased-power contracts currently in place, at February 28, 2001,
the megawatts (mW) of electric power available to SDG&E are as
follows:
Source mW
--------------------------------------------------
Nuclear generating plants 430*
Long-term contracts with other utilities 186
Contracts with others 593
-----
Total 1,209
=====
* Net of plants' internal usage
Natural Gas/Oil Generating Plants: In connection with electric-
industry restructuring, in December 1998, SDG&E entered into
agreements for the sale of its South Bay and Encina power plants and
17 combustion turbines. During the quarter ended June 30, 1999, these
5
sales were completed for total net proceeds of $466 million. The
South Bay Power Plant sale to the San Diego Unified Port District for
$110 million was completed on April 23, 1999. Duke South Bay, a
subsidiary of Duke Energy Power Services, will manage the plant for
the Port District. The sale of the Encina Power Plant and 17
combustion-turbine generators to Dynegy Inc. and NRG Energy Inc. for
$356 million was completed on May 21, 1999. SDG&E is operating and
maintaining both facilities for the new owners for two years.
San Onofre Nuclear Generating Station (SONGS): SDG&E owns 20 percent
of the three nuclear units at SONGS (located south of San Clemente,
California). The cities of Riverside and Anaheim own a total of 5
percent of Units 2 and 3. Southern California Edison (Edison) owns
the remaining interests and operates the units.
Unit 1 was removed from service in November 1992 when the CPUC issued
a decision to permanently shut down the unit. At that time SDG&E
began the recovery of its remaining capital investment, with full
recovery completed in April 1996. The unit's spent nuclear fuel has
been removed from the reactor and is stored on-site. In March 1993,
the NRC issued a Possession-Only License for Unit 1, and the unit was
placed in a long-term storage condition in May 1994. In June 1999,
the CPUC granted authority to begin decommissioning Unit 1.
Decommissioning work is now in progress.
Units 2 and 3 began commercial operation in August 1983 and April
1984, respectively. SDG&E's share of the capacity is 214 mW of Unit 2
and 216 mW of Unit 3.
During 2000, SDG&E spent $4 million on capital additions and
modifications of Units 2 and 3, and expects to spend $7 million in
2001.
SDG&E deposits funds in an external trust to provide for the
decommissioning of all three units.
Additional information concerning the SONGS units, nuclear
decommissioning and industry restructuring (including SDG&E's
divestiture of its electric generation assets) 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 5, 11 and 12 of the notes to Consolidated Financial Statements
herein.
6
Purchased Power: The following table lists contracts with SDG&E's
various suppliers.
Expiration Megawatt
Supplier Date Commitment Source
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Long-Term Contracts with Other Utilities:
Portland General
Electric (PGE) December 2013 86 Coal
Public Service
Company of
New Mexico (PNM) April 2001 100 System Supply
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Total 186
======
Other Contracts:
QFs --
Applied Energy December 2019 102 Cogeneration
Yuma Cogeneration June 2024 50 Cogeneration
Goal Line Limited
Partnership December 2025 50 Cogeneration
Other QFs (73) Various 16 Cogeneration
------
218
Others --
Avista Supply December 2001 150 System Supply
PacifiCorp December 2001 100 System Supply
Others December 2003 125 System Supply
------
Total 593
======
Under the contracts with PGE and PNM, SDG&E pays a capacity charge
plus a charge based on the amount of energy received. Charges under
these contracts are based on the selling utility's costs, including a
return on and depreciation of the utility's rate base (or lease
payments in cases where the utility does not own the property), fuel
expenses, operating and maintenance expenses, transmission expenses,
administrative and general expenses, and state and local taxes. Costs
under the contracts with Qualifying Facilities are based on SDG&E's
avoided cost. Charges under the remaining contracts are for firm
energy only and are based on the amount of energy received. The
prices under these contracts are at the market value at the time the
contracts were negotiated.
Additional information concerning SDG&E's purchased-power contracts
is provided below, and in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" and Note 12 of the
notes to Consolidated Financial Statements herein.
7
Power Pools
SDG&E is a participant in the Western Systems Power Pool (WSPP),
which includes an electric-power and transmission-rate agreement with
utilities and power agencies located throughout the United States and
Canada. More than 200 investor-owned and municipal utilities, state
and federal power agencies, energy brokers, and power marketers share
power and information in order to increase efficiency and competition
in the bulk power market. Participants are able to make power
transactions on standardized terms that have been pre-approved by
FERC.
Transmission Arrangements
Pacific Intertie(Intertie): The Intertie consisting of AC and DC
transmission lines, connects the Northwest with SDG&E, Pacific Gas &
Electric (PG&E), Edison and others under an agreement that expires in
July 2007. SDG&E's share of the Intertie is 266 mW.
Southwest Powerlink: SDG&E's 500-kilovolt Southwest Powerlink
transmission line, which is shared with Arizona Public Service
Company and Imperial Irrigation District, extends from Palo Verde,
Arizona to San Diego. SDG&E's share of the line is 970 mW, although
it can be less, depending on specific system conditions.
Mexico Interconnection: Mexico's Baja California Norte system is
connected to SDG&E's system via two 230-kilovolt interconnections
with firm capability of 408 mW.
Due to electric-industry restructuring (see "Transmission Access"
below), the operating rights of SDG&E on these lines have been
transferred to the ISO.
Transmission Access
As a result of the enactment of the National Energy Policy Act of
1992, the FERC has established rules to implement the Act's
transmission-access provisions. These rules specify FERC-required
procedures for others' requests for transmission service. In October
1997, the FERC approved the California IOUs' transfer of control of
their transmission facilities to the ISO. On March 31, 1998,
operation and control of the transmission lines was transferred to
the ISO. Additional information regarding the ISO and transmission
access is provided below and in "Management's Discussion and Analysis
of Financial Condition and Results of Operations" herein.
Fuel and Purchased-Power Costs
The following table shows the percentage of each electric-fuel source
used by SDG&E and compares the costs of the fuels with each other and
with the total cost of purchased power:
Percent of kWh Cents per kWh
- -------------------------------------------------------------------
2000 1999 1998 2000 1999 1998
----- ----- ----- ---- ---- ----
Natural gas * -- 6.5% 17.3% -- 3.0 3.0
Nuclear fuel 14.9 12.6 11.5 0.5 0.5 0.6
----- ----- -----
Total generation 14.9 19.1 28.8
Purchased power
and ISO/PX 85.1 80.9 71.2 9.7 3.7 3.5
----- ----- -----
Total 100.0% 100.0% 100.0%
====== ====== ======
8
* As described previously, SDG&E sold its South Bay and Encina power
plants and 17 combustion turbines during the quarter ended June 30,
1999.
The cost of purchased power includes capacity costs as well as the
costs of fuel. The cost of natural gas includes transportation costs.
The costs of natural gas and nuclear fuel do not include SDG&E's
capacity costs. While fuel costs are significantly less for nuclear
units than for other units, capacity costs are higher.
Electric Fuel Supply
Natural Gas: Information concerning natural gas is provided in
"Natural Gas Operations" herein.
Nuclear Fuel: The nuclear-fuel cycle includes services performed by
others under contract through 2003, including mining and milling of
uranium concentrate, conversion of uranium concentrate to uranium
hexafluoride, enrichment services, and fabrication of fuel
assemblies.
Spent fuel from Units 2 and 3 is being stored on site, where storage
capacity will be adequate at least through 2005. If necessary,
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 $0.99 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.
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 11 of the notes to Consolidated Financial Statements herein.
NATURAL GAS OPERATIONS
SDG&E purchases and distributes natural gas to 760,000 end-use
customers throughout the western portion of San Diego County. The
Company also transports gas to over 1,000 customers who procure their
gas from other sources.
9
Supplies of Natural Gas
SDG&E buys natural gas under several short-term and long-term
contracts. Short-term purchases are from various Southwest U.S. and
Canadian suppliers and are primarily based on monthly spot-market
prices. SDG&E transports gas under long-term firm pipeline capacity
agreements that provide for annual reservation charges. SDG&E
recovers such fixed charges in rates. These contracts expire at
various dates between 2007 and 2023.
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 an SDG&E affiliate, Southern California Gas Company
(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 natural gas is
delivered to SDG&E under a transportation and storage agreement with
SoCalGas.
SDG&E had been involved in negotiations and litigation with four
Canadian suppliers concerning contract terms and prices related to
long-term natural gas supply contracts. In 1999, SDG&E settled with
the last of the four suppliers, terminating the contract. SDG&E
continues to purchase natural gas from one of the suppliers under
terms of the settlement agreement. Additional information regarding
natural gas contracts is provided in Note 11 of the notes to
Consolidated Financial Statements herein.
The following table shows the sources of natural gas deliveries from
1996 through 2000.
Year Ended December 31
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2000 1999 1998 1997 1996
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Purchases in billions of cubic feet 58 75 118 101 97
Customer-owned and
exchange receipts 85 47 19 18 17
Storage withdrawal
(injection) - net 1 4 (3) 1 --
Company use and
unaccounted for (5) -- (2) (1) (1)
------- ------- ------- ------- -------
Net Deliveries 139 126 132 119 113
======= ======= ======= ======= =======
Cost of gas purchased*
(millions of dollars) $ 277 $ 205 $ 327 $ 313 $ 252
------- ------- ------- ------- -------
Average cost of purchases
(Dollars per thousand cubic feet) $4.77 $2.73 $2.77 $3.10 $2.59
======= ======= ======= ======= =======
* Includes interstate pipeline demand charges
Market-sensitive natural gas supplies (supplies purchased on the spot
market as well as under longer-term contracts based on spot prices)
accounted for nearly 100 percent of total natural gas volumes
purchased by the Company during the last five years. Supply/demand
imbalances have increased the price of natural gas in California more
than in the rest of the country because of California's dependence on
natural gas fired electric generation due to air-quality
10
considerations. The average price of natural gas at the
California/Arizona border was $6.25/mmbtu in 2000, compared with
$2.33/mmbtu in 1999. On December 11, 2000, the average spot cash gas
price at the CA/AZ border reached a record high $56.91/mmbtu.
The Company provided transportation services for the customer-owned
natural gas. The Company estimates that sufficient natural gas
supplies will be available to meet the requirements of its customers
for the next several years.
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. There are 763,000 core customers (734,000 residential and
29,000 small commercial and industrial). Noncore customers consist
primarily of utility electric generation (UEG), wholesale, and large
commercial and industrial customers, and total 123.
Most core customers purchase natural gas directly from the Company.
Core customers are permitted to aggregate their natural gas
requirement and, up to a limit of 10 percent of the Company's core
market, to purchase natural gas directly from brokers or producers.
The Company continues to be obligated to purchase reliable supplies
of natural gas to serve the requirements of its core customers.
SoCalGas and SDG&E recently filed an application with the CPUC to
combine the two companies' core procurement portfolios.
Noncore customers have the option of purchasing natural gas either
from the Company or from other sources, such as brokers or producers,
for delivery through the Company's transmission and distribution
system. The only natural gas supplies that the Company may offer for
sale to noncore customers are the same supplies that it purchases for
its core customers. Most noncore customers procure their own natural
gas supply.
In 2000, approximately 89 percent of the CPUC-authorized natural gas
margin was allocated to the core customers, with 11 percent allocated
to the noncore customers.
Although revenue from transportation throughput is less than for
natural gas sales, the Company generally earns the same margin
whether the Company buys the gas and sells it to the customer or
transports natural gas already owned by the customer.
Demand for Natural Gas
Natural gas is a principal energy source for residential, commercial,
industrial and UEG customers. Natural gas competes with electricity
for residential and commercial cooking, water heating, space heating
and clothes drying, and with other fuels for large industrial,
commercial and UEG uses. Growth in the natural gas markets is largely
dependent upon the health and expansion of the southern California
economy. The Company added approximately 13,000 and 27,000 new
customer meters in 2000 and 1999, respectively, representing a growth
rate of approximately 1.8 percent and 3.7 percent, respectively. The
Company expects its growth rate for 2001 will be at the 2000 level.
During 2000, 91 percent of residential energy customers in the
Company's service area used natural gas for water heating, 73 percent
11
for space heating, 52 percent for cooking and 35 percent for clothes
drying.
Demand for natural gas by noncore customers is very sensitive to the
price of competing fuels. Although the number of noncore customers in
2000 was only 123, they accounted for approximately 14 percent of the
authorized natural gas revenues and 64 percent of total natural gas
volumes. External factors such as weather, the price of electricity,
electric deregulation, the use of hydroelectric power, competing
pipelines and general economic conditions can result in significant
shifts in demand and market price. The demand for natural gas by
large UEG customers is also greatly affected by the price and
availability of electric power generated in other areas. The increase
in UEG demand in 2000 was due to higher demand for electricity and
increased use of natural gas for electric generation, a colder 2000-
2001 winter and population growth in California. Natural gas demand
in 1999 for UEG customer use increased primarily due to higher
electric energy usage in the summer, as a result of warmer weather.
Effective March 31, 1998, electric industry restructuring gave
California consumers the option of selecting their electric energy
provider from a variety of local and out-of-state producers. As a
result, natural gas demand for electric generation within southern
California competes with electric power generated throughout the
western United States. Although electric industry restructuring has
no direct impact on the Company's natural gas operations, future
volumes of natural gas transported for UEG customers may be adversely
affected to the extent that regulatory changes divert electricity
generation from the Company's service area.
Other
Additional information concerning customer demand and other aspects
of natural gas operations is provided under "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and in
Notes 11 and 12 of the notes to Consolidated Financial Statements
herein.
RATES AND REGULATION
SDG&E is regulated by the CPUC, which consists of five
commissioners appointed by the Governor of California for staggered
six-year terms. It is the responsibility of the CPUC to determine
that utilities operate within the best interests of their
customers. The regulatory structure is complex and has a
substantial impact on the profitability of the Company. Both the
electric and natural gas industries are currently undergoing
transitions to competition and are being impacted by abnormally
high commodity prices resulting from supply/demand imbalances.
Electric Industry Restructuring
A flawed electric-industry restructuring plan, electricity
supply/demand imbalances, and legislative and regulatory responses
significantly impact the Company's operations. Additional information
on electric-industry restructuring is provided in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 12 of the notes to Consolidated Financial
Statements herein.
Natural Gas Industry Restructuring
The natural gas industry experienced an initial phase of
12
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. The CPUC is currently assessing the current market
and regulatory framework for California's natural gas industry.
Supply/demand imbalances are affecting the price of natural gas in
California more than in the rest of the country because of
California's dependence on natural gas fired electric generation due
to air-quality considerations. Additional information on natural gas
industry restructuring is provided in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in
Note 12 of the notes to Consolidated Financial Statements herein.
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.
Additional information on balancing accounts is provided in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 2 of the notes to Consolidated
Financial Statements herein.
Performance-Based Regulation (PBR)
In recent years, the CPUC has directed utilities to use PBR. To
promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, PBR has replaced
the general rate case and certain other regulatory proceedings for
SDG&E. Additional information on PBR is provided in "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Note 12 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. The BCAP adjusts
rates to reflect variances in customer demand from estimates
previously used in establishing customer natural gas transportation
rates. The mechanism substantially eliminates the effect on income of
variances in market demand and natural gas transportation costs. The
BCAP will continue under PBR. Additional information on the BCAP is
provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Note 12 of the notes to
Consolidated Financial Statements herein.
Cost of Capital
Under PBR, annual Cost of Capital proceedings have been replaced by
an automatic adjustment mechanism if changes in certain indices
exceed established tolerances. 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 12 of the
notes to Consolidated Financial Statements herein.
ENVIRONMENTAL MATTERS
Discussions about environmental issues affecting SDG&E are included
in "Management's Discussion and Analysis of Financial Condition and
Results of Operations" herein. The following additional information
should be read in conjunction with those discussions.
13
Hazardous Substances
In 1994, the CPUC approved the Hazardous Waste Collaborative
Memorandum account, a mechanism that allows SDG&E and other utilities
to recover in rates the costs associated with the cleanup of sites
contaminated with hazardous waste. In general, utilities are allowed
to recover 90 percent of their cleanup costs and any related costs of
litigation. In early 1998, the CPUC modified this mechanism to
exclude these costs related to electric generation activities. These
costs are now eligible for inclusion in the competition transition
cost recovery process. The effect of this decision is that SDG&E's
costs of compliance with environmental regulations may not be fully
recoverable if they exceed the estimates included in the transaction
costs (see "Electric Resources" above).
During the early 1900s, SDG&E and its predecessors manufactured gas
from coal or oil. The manufacturing sites often have become
contaminated with the hazardous residual by-products of the process.
SDG&E has identified three former manufactured-gas plant sites. These
sites have been remediated and closure letters have been received for
two of the sites (discussed below).
Under authority from the Redevelopment Agency for the City of San
Diego, and under oversight by the County of San Diego, Station A has
been undergoing remediation since 1998. The vast majority of remedial
activities were completed in 1999 and early 2000. $8.7 million was
spent in 1999, with an additional $1.3 million spent in 2000.
Included in the 2000 activity was remediation of several underground
storage tanks, cleanup of lead-contaminated soil on one block of
Station A, and remediation of fuel oil believed to have leaked from
pipelines under City streets. All closure letters have been received
from the County, with the exception of one open case related to
ongoing groundwater monitoring. At December 31, 2000, it is estimated
that less than $300,000 worth of work remains to resolve known
liabilities. As properties are developed, there remains a possibility
that additional contaminated soil will be found.
Remediation was completed in 2000 at SDG&E's former manufactured-gas
plant site in Oceanside at the cost of $450,000. Offsite cleanup in
2001 is not expected to be significant.
SDG&E sold its fossil-fuel power plants and combustion turbines in
1999. As a part of its due diligence for the sale, SDG&E conducted a
thorough environmental assessment of the South Bay and Encina power
plants and 17 combustion turbine sites. 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 for electric generation.
While the sites are relatively clean, the assessments identified some
instances of significant contamination, principally resulting from
hydrocarbon releases, for which SDG&E has a cleanup obligation under
the agreement. Estimated costs to perform the necessary remediation
are $7 million to $8 million at the South Bay power plant, $0.9
million at the Encina power plant, and $1.9 million at the combustion
turbine sites. These costs were offset against the sales price for
the facilities, together with other appropriate costs, and the
remaining net proceeds were offset against SDG&E's other transition
costs. Remediation of the plants commenced in early 2001; completion
is expected in mid-2001.
Cleanup of Station B, a steam and electric generating facility
14
operated in San Diego between 1911 and 1993, was completed during
1999. Activities included removal of asbestos and lead-based paint
and the removal or cleanup of other substances. The sale of the
facility was completed in December 1999.
SDG&E lawfully disposed 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.
SDG&E and 10 other entities have been named potentially responsible
parties (PRPs) by the California Department of Toxic Substances
Control (DTSC) as liable for any required corrective action regarding
contamination at a site in Pico Rivera, California. DTSC has taken
this action because SDG&E and others sold used electrical
transformers to the site's owner. SDG&E and the other PRPs have
entered into a cost-sharing agreement to provide funding for the
implementation of a consent order between DTSC and the site owner for
the development of a cleanup plan. SDG&E's interim share under the
agreement is 10.1 percent, subject to adjustment based on ultimate
responsibility allocations. The total estimate for all PRPs is $1
million for the development of the cleanup plan and $2 million to $8
million for the actual cleanup.
At December 31, 2000, SDG&E's estimated remaining investigation and
remediation liability related to hazardous waste sites was $1
million, of which 90 percent is authorized to be recovered through
the Hazardous Waste Collaborative mechanism. Any costs not ultimately
recovered through rates, insurance or other means will not have a
material adverse effect on SDG&E'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 adverse health
effects and exposure to the type of EMFs emitted by power lines and
other electrical facilities. 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 childhood leukemia and the proximity of
homes to certain power lines and equipment. 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
utilities 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
15
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 power plants and combustion turbines, the Company's primary air-
quality issue, compliance with these standards is less significant to
the Company's operations.
The transmission and distribution of natural gas require the
operation of compressor stations, which are subject to increasingly
stringent air-quality standards. Costs to comply with these standards
are recovered in rates.
In connection with the issuance of operating permits, SDG&E and the
other owners of SONGS reached agreement with the California Coastal
Commission to mitigate the environmental damage to the marine
environment attributed to the cooling-water discharge from SONGS
Units 2 and 3. This mitigation program includes an enhanced fish-
protection system, a 150-acre artificial reef and restoration of 150
acres of coastal wetlands. In addition, the owners must deposit $3.6
million with the state for the enhancement of fish hatchery programs
and pay for monitoring and oversight of the mitigation projects.
SDG&E's share of the cost is estimated to be $27.4 million. The
pricing structure contained in the CPUC's decision regarding
accelerated recovery of SONGS Units 2 and 3 (described in "Electric
Resources" above) is expected to accommodate these added mitigation
costs.
OTHER MATTERS
Research, Development and Demonstration (RD&D)
For 2000, the CPUC authorized SDG&E to fund $1.2 million and $4.2
million for its gas and electric RD&D programs, respectively, which
includes $3.9 million to the CEC for its PIER (Public Interest Energy
Research) program. SDG&E co-funded several of these projects with the
CEC. Annual RD&D costs have averaged $4.5 million over the past three
years.
Employees of Registrant
As of December 31, 2000, SDG&E had 3,248 employees, compared to 3,071
at December 31, 1999.
Wages
Certain employees at SDG&E are represented by the International
Brotherhood of Electrical Workers, Local 465, under two labor
agreements. The current generation contract runs through May 25,
2001. The transmission and distribution contract runs through August
31, 2001.
ITEM 2. PROPERTIES
Electric Properties
SDG&E's generating capacity is described in "Electric Resources"
herein.
SDG&E's electric transmission and distribution facilities include
16
substations, and overhead and underground lines. Periodically various
areas of the service territory require expansion to handle customer
growth.
Natural Gas Properties
SDG&E's natural gas facilities are located in San Diego and Riverside
counties and consist of the Moreno and Rainbow compressor stations,
171 miles of high pressure transmission pipelines, 7,068 miles of high
and low pressure distribution mains, and 5,859 miles of service lines.
Other Properties
SDG&E occupies an office complex at Century Park Court in San Diego
pursuant to an operating lease ending in the year 2007. The lease can
be renewed for two five-year periods.
SDG&E owns or leases other offices, operating and maintenance centers,
shops, service facilities, and equipment necessary in the conduct of
business.
ITEM 3. LEGAL PROCEEDINGS
Except for the matters described in Note 11 of the notes to
Consolidated Financial Statements or referred to elsewhere in this
Annual Report, neither the Company nor its subsidiary are 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
17
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.
Dividend Restrictions
CPUC regulation of SDG&E's capital structure limits to $154 million
the portion of the Company's December 31, 2000 retained earnings that
is available for dividends. Additional information is provided in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" herein.
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in millions)
At December 31, or for the years then ended
------------------------------------------------
2000 1999 1998 1997 1996
-------- ------- ------- ------- -------
Income Statement Data:
Operating revenues $2,671 $2,207 $2,249 $2,167 $1,939
Operating income $ 235 $ 281 $ 286 $ 317 $ 309
Dividends on preferred stock $ 6 $ 6 $ 6 $ 6 $ 6
Earnings applicable to
common shares $ 145 $ 193 $ 185 $ 232 $ 216
Balance Sheet Data:
Total assets $4,734 $4,366 $4,257 $4,654 $4,161
Long-term debt $1,281 $1,418 $1,548 $1,788 $1,285
Short-term debt (a) $ 66 $ 66 $ 72 $ 73 $ 34
Shareholders' equity $1,138 $1,393 $1,203 $1,465 $1,483
(a) Includes long-term debt due within one year.
Since San Diego Gas & Electric Company is a wholly owned subsidiary of
Enova Corporation, per share data has been omitted.
This data should be read in conjunction with the consolidated
financial statements and the notes to Consolidated Financial
Statements contained herein.
18
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 1998 through 2000, 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 plans. It should be
read in conjunction with the consolidated financial statements
included in this Annual Report.
The Company is an operating public utility engaged in the
electric and natural gas businesses. It generates and purchases
electric energy and distributes it to 1.2 million customers in San
Diego County and an adjacent portion of southern Orange County,
California. It also purchases and distributes natural gas to 0.8
million customers in San Diego County and transports electricity and
gas for others. The Company is the principal subsidiary of Enova
Corporation (Enova or the Parent), which is wholly owned by Sempra
Energy. SDG&E's only subsidiary is SDG&E Funding LLC, which is
described below under "Electric Rates."
The uncertainties shaping California's electric industry and
business environment significantly affect the Company's operations. A
flawed electric-industry restructuring plan, electricity supply/demand
imbalances, and legislative and regulatory responses, including a
temporary rate ceiling on the cost of electricity that SDG&E can pass
on to its small-usage customers on a current basis, have materially
and adversely affected the timing of revenue collections by the
Company and related cash flows. These, together with concerns with
California utility regulation generally and increased electricity cost
undercollections, have significantly impaired the Company's access to
the capital markets and ability to obtain financing on commercially
reasonable terms. In addition, supply/demand imbalances are affecting
the price of natural gas in California more than in the rest of the
country because of California's dependence on natural gas fired
electric generation due to air-quality considerations. These recent
developments are continuing to change rapidly. Information as of March
7, 2001, the date this report was prepared, is found herein, primarily
under "Results of Operations" and "Factors Influencing Future
Performance" and in Note 12 of the notes to Consolidated Financial
Statements.
Business Combination
Sempra Energy was formed to serve as a holding company for Pacific
Enterprises (PE), the parent corporation of the Southern California
Gas Company, and Enova, in connection with a business combination that
became effective on June 26, 1998 (the PE/Enova business combination).
In connection with the PE/Enova business combination, the holders of
common stock of PE and Enova became the holders of Sempra Energy's
common stock. The preferred stock of SDG&E remained outstanding. The
combination was a tax-free transaction.
Expenses incurred by SDG&E in connection with the business
combination were $35 million, after tax, in 1998. No significant
expenses were incurred subsequently. These costs consist primarily of
employee-related costs, and investment banking, legal, regulatory and
consulting fees. See Note 1 of the notes to the Consolidated Financial
Statements for additional information.
19
Capital Resources and Liquidity
The Company's operations have historically been a major source of
liquidity. However, higher electric-commodity prices and the inability
of SDG&E to bill its small-usage customers on a current basis for the
full purchase cost of electricity due to legislative actions, have
resulted in a significant decrease in cash flows available from
SDG&E's operating activities in 2000. SDG&E had incurred costs in
excess of amounts which it can bill its customers on a current basis,
or "undercollected costs," of $447 million at December 31, 2000, and
$605 million at January 31, 2001. California recently enacted
legislation authorizing the California Department of Water Resources
(DWR) to purchase electricity for resale to all California
investor-owned utility retail end-use customers (including customers
of SDG&E), that is intended to halt or substantially slow the growth
of cost undercollections by SDG&E and other California Investor-Owned
Utilities (IOUs). Consequently, SDG&E believes that its continued
accumulation of undercollected costs will depend primarily upon the
effects of this legislation and other legislative and regulatory
developments. For additional discussion, see "Results of Operations"
herein and Note 12 of the notes to Consolidated Financial Statements.
Additional working capital and other requirements are met
primarily through the issuance of long-term debt. Cash requirements
primarily consist of capital expenditures for utility plant. Due to
the factors described herein and in Note 12 of the notes to
Consolidated Financial Statements regarding high electricity costs,
and the Company's inability to bill its small-usage customers on a
current basis for the full cost of electricity purchases, management
is unable to determine whether the sources of funding described above
are sufficient to provide for all of the capital expenditures it would
otherwise intend to make after funding its basic liquidity needs. The
Company's ability to fund its capital expenditure program and
liquidity requirements is significantly affected by the Company's
credit ratings and related ability to obtain financing on commercially
reasonable terms.
Continued purchases by the DWR for resale to SDG&E's customers of
substantially all of the electricity that would otherwise be purchased
by SDG&E (as further discussed under "Results of Operations" herein)
or dramatic decreases in wholesale electricity prices, favorable
action by the CPUC on SDG&E's electric rate surcharge application
discussed below and SDG&E's access to the capital markets are required
to manage and finance SDG&E's cost undercollections and provide
adequate liquidity.
Cash Flows From Operating Activities
The decrease in cash flows from operating activities in 2000 was
primarily due to SDG&E's refunds to customers for surplus rate-
reduction-bond proceeds, and SDG&E's cost undercollections related to
high electric commodity prices and energy charges in excess of the 6.5
cents/kWh ceiling in accordance with AB 265 (see "Results of
Operations" below and Note 12 of the notes to Consolidated Financial
Statements). This decrease was partially offset by higher deferred
incomes taxes and accounts payable. The increase in accounts payable
is primarily due to higher sales volumes and higher prices for natural
gas and purchased power. The increase in deferred income taxes
primarily relates to the timing of deductions for undercollections
related to higher electricity costs referred to above.
The decrease in cash flows from operating activities in 1999 was
primarily due to the completion of the recovery of SDG&E's stranded
costs in 1999 and to reduced revenues, both the result of the sale of
SDG&E's fossil power plants and combustion turbines in the second
20
quarter of 1999. This decrease was partially offset by the absence of
business-combination expenses in 1999. See additional discussion on
the sale of the power plants in Note 12 of notes to Consolidated
Financial Statements.
Cash Flows From Investing Activities
Net cash provided by investing activities increased in 2000 primarily
due to loan repayments from Sempra Energy, partially offset by higher
capital expenditures for utility plant.
Cash flows from investing activities in 1999 included the
proceeds from the sale of SDG&E's two fossil power plants and
combustion turbines, offset by loans to Sempra Energy and capital
expenditures. The South Bay Power Plant was sold to the San Diego
Unified Port District for $110 million. The Encina Power Plant and 17
combustion-turbine generators were sold to Dynegy, Inc. and NRG
Energy, Inc. for $356 million. See additional discussion in Note 12 of
the notes to Consolidated Financial Statements.
Capital Expenditures
Capital expenditures were $79 million higher in 2000 compared to 1999
primarily due to additions and improvements to the natural gas and
electric distribution systems.
Capital expenditures were $18 million higher in 1999 compared to
1998 primarily due to improvements to the electric distribution system
as a result of higher demand and an expansion of the natural gas
system.
Capital expenditures in 2001 are expected to be comparable to
those of 2000. They will include improvements and additions to the
Company's gas and electric distribution systems and are intended to be
financed primarily by operations and debt issuances. These capital
expenditures are dependent on SDG&E's ability to recover its
electricity costs, including the balancing account undercollections
referred to above.
Cash Flows From Financing Activities
Net cash used in financing activities increased in 2000 primarily due
to higher dividends paid to the Parent.
Net cash used in financing activities decreased in 1999 compared
to 1998 primarily due to lower dividends paid to the Parent and lower
long-term debt repayments in 1999.
Long-Term Debt
In 2000, repayments on long-term debt included $65 million of rate-
reduction bonds and $10 million of first-mortgage bonds. In addition,
during December 2000, $60 million of variable-rate industrial
development bonds were put back by the holders and subsequently
remarketed in February 2001 at a 7.0 percent fixed interest rate.
Between January 24 and February 5, 2001, the Company drew down $250
million from its $285 million available credit facilities.
In 1999, repayments on long-term debt included $28 million of
first-mortgage bonds and $66 million of rate-reduction bonds.
In 1998, repayments included $147 million of first-mortgage bonds
and $66 million of rate-reduction bonds.
Dividends
Dividends paid to the Parent amounted to $400 million in 2000,
compared to $100 million in 1999 and $263 million in 1998.
21
The payment of future dividends and the amount thereof are within
the discretion of the Company's board of directors. CPUC regulation of
SDG&E's capital structure limits to $154 million the portion of the
Company's December 31, 2000, retained earnings that is available for
dividends.
Capitalization
Total capitalization including the current portion of long-term debt
was $2.5 billion at December 31, 2000. The debt-to-capitalization
ratio was 54 percent at December 31, 2000. Significant changes in
capitalization during 2000 included higher dividends declared to the
Parent, partially offset by lower outstanding debt.
Cash and Cash Equivalents
Cash and cash equivalents were $256 million at December 31, 2000.
This cash is available for investment in projects consistent with the
Company's strategic direction, the retirement of debt, the payment of
dividends and other corporate purposes. However, as discussed above,
funds available for these purposes may be limited by SDG&E's ability
to recover from its customers on a current basis the full amount of
the high electricity prices.
If the impacts of the high electricity costs and the Company's
inability to bill customers for these costs on a current basis are
favorably resolved, the Company anticipates that operating cash
required in 2001 for common stock dividends and debt payments will be
provided by cash generated from operating activities and existing cash
balances. Cash required for capital expenditures will be provided by
cash generated both from operating activities and from long-term and
short-term debt issuances.
In addition to cash generated from ongoing operations, SDG&E has
credit agreements that permit short-term borrowings of up to $285
million, and/or support its commercial paper. These agreements expire
at various dates in 2001. Because of the ramifications of the high
electric costs (as discussed in Notes 3 and 12 of the notes to
Consolidated Financial Statements), between January 24 and February 5,
2001, SDG&E drew down $250 million from its available credit
facilities.
In December 2000, SDG&E filed a shelf registration for the public
offering of up to $800 million of debt. As yet, no debt securities
have been issued under these registration statements. For additional
information see Notes 4 and 12 of the notes to Consolidated Financial
Statements.
For additional discussion see "Factors Influencing Future
Performance" below and Note 12 of the notes to Consolidated Financial
Statements
Results of Operations
To understand the operations and financial results of SDG&E, it is
important to understand the ratemaking procedures that SDG&E follows.
SDG&E is regulated by the CPUC. It is the responsibility of the
CPUC to determine that utilities operate in the best interests of
their customers and have the opportunity to earn a reasonable return
on investment. In 1996, California enacted legislation restructuring
California's investor-owned electric utility industry. The legislation
and related decisions of the CPUC were intended to stimulate
competition and reduce electric rates. The California Power Exchange
(PX) served as a wholesale power pool and the Independent System
Operator (ISO) scheduled power transactions and access to the
transmission system.
22
A flawed electric-industry restructuring plan, electricity
supply/demand imbalances, and legislative and regulatory
responses, including the rate ceiling as described in "Factors
Influencing Future Performance" below, have materially and adversely
affected the timing of revenue collections by the Company and related
cash flows. Additional legislation passed in early 2001, as well as
future legislation and regulatory actions concerning California's
energy crisis, could have a significant impact on SDG&E's future
operations, liquidity and financial results.
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. The CPUC currently is studying the issue of
restructuring for sales to core customers and, as mentioned above,
supply/demand imbalances are affecting the price of natural gas in
California more than in the rest of the country because of
California's dependence on natural gas fired electric generation due
to air-quality considerations.
In connection with restructuring of the electric and natural gas
industries, SDG&E received approval from the CPUC for Performance-
Based Ratemaking (PBR). Under PBR, income potential is tied to
achieving or exceeding specific performance and productivity measures,
rather than to expanding utility plant in a market where a utility
already has a highly developed infrastructure
See additional discussion of these situations under "Factors
Influencing Future Performance" and in Note 12 of the notes to
Consolidated Financial Statements.
The table below summarizes the components of utility electric and
natural gas volumes and revenues by customer class for 2000, 1999 and
1998.
SDG&E
ELECTRIC DISTRIBUTION
(Dollars in millions, volumes in million kWhs)
2000 1999 1998
-----------------------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
-----------------------------------------------------------------------
Residential 6,304 $730 6,327 $663 6,282 $637
Commercial 6,123 747 6,284 592 6,821 643
Industrial 2,614 310 2,034 154 3,097 233
Direct access 3,308 99 3,212 118 964 44
Street and highway lighting 74 7 73 7 85 8
Off-system sales 899 59 383 10 706 15
-----------------------------------------------------------------------
19,322 1,952 18,313 1,544 17,955 1,580
Balancing and other 232 274 285
-----------------------------------------------------------------------
Total 19,322 $2,184 18,313 $1,818 17,955 $1,865
-----------------------------------------------------------------------
23
SDG&E
GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
Gas Sales Transportation & Exchange Total
----------------------------------------------------------------------
Throughput Revenue Throughput Revenue Throughput Revenue
----------------------------------------------------------------------
2000:
Residential 33 $ 279 - $ 1 33 $ 280
Commercial and Industrial 21 139 22 16 43 155
Utility Electric Generation - - 63 24 63 24
-----------------------------------------------------------------------
54 $ 418 85 $41 139 459
Balancing accounts and other 28
---------
Total $ 487
- ---------------------------------------------------------------------------------------------
1999:
Residential 38 $ 270 - - 38 $ 270
Commercial and Industrial 22 111 18 $15 40 126
Utility Electric Generation 18 7* 30 6 48 13
-----------------------------------------------------------------------
78 $ 388 48 $21 126 409
Balancing accounts and other (20)
---------
Total $ 389
- ---------------------------------------------------------------------------------------------
1998:
Residential 35 $ 258 - - 35 $ 258
Commercial and Industrial 21 105 19 $16 40 121
Utility Electric Generation 57 9* - - 57 9
----------------------------------------------------------------------
113 $ 372 19 $16 132 388
Balancing accounts and other (4)
---------
Total $ 384
- ---------------------------------------------------------------------------------------------
* This consists of the interdepartmental margin on SDG&E's sales to its power plants prior to
their sale in 1999.
2000 Compared to 1999
Net income decreased from $199 million in 1999 to $151 million in
2000. The decrease is primarily due to an after-tax charge of $30
million for a potential regulatory disallowance related to the
acquisition of wholesale power in the deregulated California market.
Net income increased to $39 million for the three months ended
December 31, 2000, compared to net income of $36 million for the
corresponding period in 1999. This increase was primarily due to
higher gas sales.
Electric revenues increased from $1.8 billion in 1999 to $2.2
billion in 2000. The increase was primarily due to higher sales to
industrial customers and the effect of higher electric commodity
costs, partially offset by the $50 million pretax charge referred to
above and the decrease in base electric rates (the noncommodity
portion) from the completion of stranded cost recovery. For 2000,
SDG&E's electric revenues included an undercollection of $447 million
as a result of a 6.5-cent rate cap. In January 2001, SDG&E filed with
the CPUC for a temporary electric surcharge to reduce the growing
undercollection of electric commodity costs. SDG&E is unable to
predict the amount, if any, of the request that the CPUC would grant,
or when it would issue a decision. The CPUC has deferred this
proceeding pending resolution of the broader issues related to the
state-wide high costs. Additional information concerning electric
rates is described in "Factors Influencing Future Performance" below
and in Note 12 of the notes to Consolidated Financial Statements.
24
Natural gas revenues increased from $389 million in 1999 to $487
million in 2000, primarily due to higher prices for natural gas in
2000 (see discussion of balancing accounts in Note 2 of the notes to
Consolidated Financial Statements) and higher utility electric
generation (UEG) revenues. The increase in UEG revenues was due to
higher demand for electricity in 2000 and the sale of SDG&E's fossil
fuel generating plants in the second quarter of 1999. Prior to the
plant sale, SDG&E's natural gas revenues from these plants consisted
of the margin from the sales. Subsequent to the plant sale, SDG&E gas
revenues consist of the price of the natural gas transportation
service since the sales now are to unrelated parties. In addition, the
generating plants receiving gas transportation from SDG&E are
operating at higher capacities than previously, as discussed below.
The cost of electric fuel and purchased power increased from $536
million in 1999 to $1.3 billion in 2000. The increase was primarily
due to the higher cost of electricity from the PX that has resulted
from higher demand for electricity, and the shortage of power plants
in California, higher prices for natural gas used to generate
electricity (as described above), the sale of SDG&E's fossil fuel
power plants and warmer weather in California. Additional information
concerning the recent supply/demand conditions is provided in Note 12
of the notes to Consolidated Financial Statements. Under the current
regulatory framework, changes in on-system prices normally do not
affect net income. See the discussions of balancing accounts and
electric revenues in Note 2 of the notes to Consolidated Financial
Statements.
PX/ISO power revenues have been netted against purchased-power
expenses. In September 2000, as a result of high electricity costs the
CPUC authorized SDG&E to purchase up to 1,900 megawatts of power
directly from third-party suppliers under both short-term contracts
and long-term contracts. Subsequent to December 31, 2000, the state of
California authorized the DWR to purchase all of SDG&E's power
requirements not covered by its own generation or by existing
contracts. These and related events are discussed more fully in Note
12 of the notes to Consolidated Financial Statements.
The cost of natural gas distributed increased from $168 million
in 1999 to $273 million in 2000. The increase was largely due to
higher prices for natural gas. Prices for natural gas have increased
due to the increased use of natural gas to fuel electric generation,
colder winter weather and population growth in California. Under the
current regulatory framework, changes in core-market natural gas
prices do not affect net income, since the actual commodity cost of
natural gas for core customers is included in customer rates on a
substantially current basis.
Depreciation and decommissioning expense decreased from $561
million in 1999 to $210 million in 2000. The decrease was primarily
due to the mid-1999 completion of the accelerated recovery of SDG&E's
generation assets.
Operating expenses decreased from $479 million in 1999 to $412
million in 2000. The decrease was primarily due to the 1999 sale of
SDG&E's fossil fuel generating plants.
1999 Compared to 1998
Net income for 1999 increased to $199 million, compared to net income
of $191 million in 1998. The increase is primarily due to $35 million,
after-tax, of PE/Enova business combination expense in 1998 (none in
1999) partially offset by lower income from electric operations. Net
income decreased to $36 million for the three months ended December
31, 1999, compared to net income of $50 million for the corresponding
25
period in 1998. The decrease is due to lower income from electric
operations in 1999 and higher interest on the portion of the rate-
reduction bond liability which was refundable to customers.
Electric revenues decreased from $1.9 billion in 1998 to $1.8
billion in 1999. The decrease was primarily due to a temporary
decrease in base electric rates following the completion of SDG&E's
stranded cost recovery as noted above and as more fully described in
Note 12 of the notes to Consolidated Financial Statements.
Natural gas revenues increased from $384 million in 1998 to $389
million in 1999. The increase was primarily due to higher residential
and UEG revenues. The increased residential revenues are due to
slightly higher volumes sold in 1999 compared to 1998. The increase in
UEG revenues was primarily due to the sale of SDG&E's fossil fuel
generating plants in the second quarter of 1999, as explained above.
The Company's cost of natural gas distributed increased from $166
million in 1998 to $168 million in 1999. The increase was largely due
to an increase in the average price of natural gas purchased.
Depreciation and decommissioning expense decreased from $603
million in 1998 to $561 million in 1999. The decrease was primarily
due to the mid-1999 completion of the accelerated recovery of
generation assets.
Operating expenses decreased from $541 million in 1998 to $479
million in 1999. The decrease was primarily due to the lower
business-combination costs, as previously discussed
Other Income and Deductions, Interest Expense, and Income Taxes
Other Income and Deductions
Other income and deductions were $34 million, $38 million and $11
million in 2000, 1999, and 1998 respectively. The increase from 1998
to 1999 is primarily due to higher interest earned on a loan to
Sempra Energy.
Interest Expense
Interest expense for 2000 decreased to $118 million from $120 million
in 1999 primarily due to lower interest on long-term debt as a result
of a lower average balance on the rate reduction bonds during 2000.
Interest expense for 1999 increased to $120 million from $106 million
in 1998 primarily due to interest of $28 million on the portion of
the rate-reduction bond liability which was refundable to customers,
partially offset by lower interest expense on long-term debt as a
result of lower long-term debt balances during 1999. See additional
discussion of rate reduction bonds in Note 4 of the notes to
Consolidated Financial Statements.
Income Taxes
Income tax expense was $144 million, $126 million and $142 million
for the years ended December 31, 2000, 1999 and 1998, respectively.
The effective income tax rates were 48.8 percent, 38.8 percent and
42.6 percent for the same years. The increase in income tax expense
for 2000 compared to 1999 was primarily due to lower charitable
contributions (during 1999 SDG&E made a charitable contribution to
the San Diego Unified Port District in connection with the sale of
the South Bay generating plant), partially offset by lower income
before income taxes. The decrease in income taxes for 1999 compared
to 1998 was primarily due to the charitable contribution to the San
Diego Unified Port District.
26
Factors Influencing Future Performance
Factors influencing future performance are summarized below.
Electric Industry Restructuring and Electric Rates
In 1996, California enacted legislation restructuring California's
investor-owned electric utility industry. The legislation and related
decisions of the CPUC were intended to stimulate competition and
reduce electric rates. During the transition period, utilities were
allowed to charge frozen rates that were designed to be above current
costs by amounts assumed to provide a reasonable opportunity to
recover the above-market "stranded" costs of investments in electric-
generating assets. The rate freeze was to end for each utility when
it completed recovery of its stranded costs, but no later than March
31, 2002. SDG&E completed recovery of its stranded costs in June 1999
and, with its rates no longer frozen, SDG&E's overall rates were
initially lower, but became subject to fluctuation with the actual
cost of electricity purchases.
A number of factors, including supply/demand imbalances,
resulted in abnormally high electric-commodity costs beginning in
mid-2000 and continuing into 2001. During the second half of 2000,
the average electric-commodity cost was 15.51 cents/kWh (compared to
4.15 cents/kWh in the second half of 1999). This caused SDG&E's
monthly customer bills to be substantially higher than normal. In
response, legislation enacted in September 2000 imposed a ceiling of
6.5 cents/kWh on the cost of electricity that SDG&E may pass on to
its small-usage customers on a current basis. Customers covered under
the commodity rate ceiling generally include residential, small-
commercial and lighting customers. The ceiling, which was retroactive
to June 1, 2000, extends through December 31, 2002 (December 31, 2003
if deemed by the CPUC to be in the public interest). As a result of
the ceiling, SDG&E is not able to pass through to its small-usage
customers on a current basis the full purchase cost of electricity
that it provides. The legislation provides for the future recovery of
undercollections in a manner (not specified in the decision) intended
to make SDG&E whole for the reasonable and prudent costs of procuring
electricity. In the meantime, the amount paid for electricity in
excess of the ceiling (the undercollected costs) is accumulated in an
interest-bearing balancing account. The undercollection, included in
Regulatory Assets on the Consolidated Balance Sheets, was $447
million at December 31, 2000 and $605 million at January 31, 2001,
and is expected to increase to $700 million in March 2001, and remain
constant thereafter, except for interest, if the DWR continues to
purchase SDG&E's power requirements, as more fully described in
"Results of Operations" herein. The rate ceiling has materially and
adversely affected SDG&E's revenue collections and its related cash
flows and liquidity. SDG&E has fully drawn upon substantially all of
its short-term credit facilities. Its ability to access the capital
markets and obtain additional financing has been substantially
impaired by the financial distress being experienced by other
California investor-owned utilities (IOUs) as well as by lender
uncertainties concerning California utility regulation generally and
the rapid growth of utility cost undercollections. Continued
purchases by the DWR for resale to SDG&E's customers of substantially
all of the electricity that would otherwise be purchased by SDG&E or
dramatic decreases in wholesale electricity prices, favorable action
by the CPUC on SDG&E's electric rate surcharge application and SDG&E
access to the capital markets are required to manage and finance
SDG&E's cost undercollections and provide adequate liquidity.
Consequently, in January 2001, SDG&E filed an application with
27
the CPUC requesting a temporary electric-rate surcharge of 2.3
cents/kWh, subject to refund, beginning March 1, 2001. The surcharge
is intended to provide SDG&E with continued access to financing on
commercially reasonable terms by managing the growth of SDG&E's
undercollected power costs. The CPUC has deferred this proceeding,
pending resolution of the broader issues related to the state-wide
high costs. In response to the situation facing the California IOUs,
the state of California passed legislation to permit its governor to
negotiate with the IOUs to acquire their transmission assets. There
is no assurance that these negotiations will result in a sale of the
transmission assets. SDG&E has been having discussions with
representatives of the governor concerning the possibility of such a
transaction and what the terms might be. There is no assurance that
these discussions will result in a sale of the transmission assets.
SDG&E would consider entering into such a transaction only if the
sales price and the conditions of the sale and of future operating
arrangements are reasonable.
See additional discussion in Note 12 of the notes to
Consolidated Financial Statements.
Natural Gas Restructuring and Gas Rates
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. In January 1998, the CPUC released a staff report
initiating a proceeding to assess the current market and regulatory
framework for California's natural gas industry. The general goals of
the plan are to consider reforms to the current regulatory framework,
emphasizing market-oriented policies benefiting California's natural
gas consumers. A CPUC decision is expected in 2001.
In October 1999, the state of California enacted a law that
requires natural gas utilities to provide "bundled basic gas service"
(including transmission, storage, distribution, purchasing, revenue-
cycle services and after-meter services) to all core customers,
unless the customer chooses to purchase gas from a nonutility
provider. The law prohibits the CPUC from unbundling distribution-
related gas services (including meter reading and billing) and after-
meter services (including leak investigation, inspecting customer
piping and appliances, pilot relighting and carbon monoxide
investigation) for most customers. The objective is to preserve both
customer safety and customer choice.
Supply/demand imbalances have increased the price of natural gas
in California more than in the rest of the country because of
California's dependence on natural gas fired electric generation due
to air-quality considerations. The average price of natural gas at
the California/Arizona (CA/AZ) border was $6.25/mmbtu in 2000,
compared with $2.33/mmbtu in 1999. On December 11, 2000, the average
spot-market price at the CA/AZ border reached a record high of
$56.91/mmbtu. Underlying the high natural gas prices are several
factors, including the increase in natural gas usage for electric
generation, colder winter weather and reduced natural gas supply
resulting from historically low storage levels, lower gas production
and a major pipeline rupture. In December 2000, SDG&E filed with the
Federal Energy Regulatory Commission (FERC) for a reinstitution of
price caps on short-term interstate capacity to the CA/AZ border and
between the interstate pipelines and California's local distribution
companies, effective until March 31, 2001. The FERC responded by
issuing extensive data requests, but has not otherwise acted on the
SDG&E request.
A recent lawsuit, which seeks class-action certification,
28
alleges that SDG&E, Sempra Energy, SoCalGas and El Paso Energy Corp.
acted to drive up the price of natural gas for Californians by
agreeing to stop a pipeline project that would have brought new and
cheaper natural gas supplies into California. SDG&E believes the
allegations are without merit.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and potential disallowances, the
CPUC has been directing utilities to use PBR. PBR has replaced the
general rate case and certain other regulatory proceedings for the
Company. Under PBR, regulators require future income potential to be
tied to achieving or exceeding specific performance and productivity
goals, as well as cost reductions, rather than by relying solely on
expanding utility plant in a market where a utility already has a
highly developed infrastructure. See additional discussion of PBR in
"Results of Operations" above and in Note 12 of the notes to
Consolidated Financial Statements.
Allowed Rate of Return
For 2001, the Company is authorized to earn a rate of return on rate
base of 8.75 percent and a rate of return on common equity of 10.6
percent, compared to 9.35 percent and 11.6 percent, respectively,
prior to July 1, 1999. 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 incentive mechanisms. In
addition, earnings are affected by changes in sales volumes.
Management Control of Expenses and Capital Expenditures
In the past, management has been able to control operating expenses
and investment within the amounts authorized to be collected in
rates. However, that effort is now increasing. Due to the ever-
increasing financial pressures experienced by SDG&E in the current
electric industry environment, in January 2001 the Company launched a
cash-conservation plan, which includes sales of nonessential
property, containment of new hiring, reduction of outside
contractors, and deferral of information system and construction
projects that do not affect the core reliability of service to
customers. While the Company is not planning employee layoffs at this
time, all expenses and activities not directly tied to the
maintenance of essential services and safety will continue to be
scrutinized and deferred if possible.
Environmental Matters
The Company's operations are subject to federal, state and local
environmental laws and regulations governing such things as hazardous
wastes, air and water quality, land use, solid waste disposal and the
protection of wildlife.
The Company's capital costs to comply with environmental
requirements are generally recovered through the depreciation
components of customer rates. The Company's customers generally are
responsible for 90 percent of the non-capital costs associated with
hazardous substances and the normal operating costs associated with
safeguarding air and water quality, disposing properly of solid
waste, and protecting endangered species and other wildlife.
Therefore, the likelihood of the Company's financial position or
29
results of operations being adversely affected in a significant
manner is remote.
The environmental issues currently facing the Company or
resolved during the latest three-year period include investigation
and remediation of its manufactured-gas sites (all three sites
completed as of December 31, 2000 and site-closure letters received
for two), asbestos and other cleanup at its former fossil fuel power
plants (all sold in 1999 and actual or estimated cleanup costs
included in the transactions), cleanup of third-party waste disposal
sites used by the Company, which has been identified as a Potentially
Responsible Party (investigation and remediations are continuing),
and mitigation of damage to the marine environment caused by the
cooling-water discharge from the San Onofre Nuclear Generating
Station (the requirements for enhanced fish protection, a 150-acre
artificial reef and restorations on 150 acres of coastal wetlands are
in process).
Market Risk
The Company's policy is to use derivative financial instruments to
reduce its exposure to fluctuations in interest rates, foreign-
currency exchange rates and energy prices. Transactions involving
these financial instruments are with credit-worthy firms and major
exchanges. The use of these instruments exposes the Company to market
and credit risks which, at times, may be concentrated with certain
counterparties.
The Company periodically enters into interest-rate swap and cap
agreements to moderate exposure to interest-rate changes and to lower
the overall cost of borrowing. These swap and cap agreements
generally remain off the balance sheet as they involve the exchange
of fixed-rate and variable-rate interest payments without the
exchange of the underlying principal amounts. The related gains or
losses are reflected in the income statement as part of interest
expense. The Company would be exposed to interest-rate fluctuations
on the underlying debt should other parties to the agreement not
perform. Such nonperformance is not anticipated. See the "Interest-
Rate Risk" section below for additional information regarding the
Company's use of interest-rate swap and cap agreements.
The Company uses energy derivatives to manage natural gas price
risk associated with servicing its load requirements. These
instruments can include forward contracts, futures, swaps, options
and other contracts, with maturities ranging from 30 days to 12
months. In the case of price-risk management, the use of derivative
financial instruments by the Company is subject to certain
limitations imposed by Sempra Energy's risk management policies and
regulatory requirements. The counterparties with whom the Company
enters into derivative transactions must also meet corporate credit
standards. See Note 9 of the notes to Consolidated Financial
Statements and the "Market Risk Management Activities" section below
for further information regarding the use of energy derivatives by
the Company.
Market-Risk Management Activities
Market risk is the risk of erosion of the Company's cash flows, net
income and asset values due to adverse changes in interest and
foreign-currency rates, and in prices for equity and energy. Sempra
Energy has adopted corporate-wide policies governing its market-risk
management activities. An Energy Risk Management Oversight Committee,
consisting of senior officers, oversees company-wide energy-price
risk-management and trading activities to ensure compliance with
30
Sempra Energy's stated energy risk management and trading policies.
In addition, all affiliates have groups that monitor and control
energy-price risk management and trading activities independently
from the groups responsible for creating or actively managing these
risks.
Along with other tools, the Company uses Value at Risk (VaR) to
measure its exposure to market risk. VaR is an estimate of the
potential loss on a position or portfolio of positions over a
specified holding period, based on normal market conditions and
within a given statistical confidence level. The Company has adopted
the variance/covariance methodology in its calculation of VaR, and
uses a 95 percent confidence level. Holding periods are specific to
the types of positions being measured, and are determined based on
the size of the position or portfolios, market liquidity, purpose and
other factors. Historical volatilities and correlations between
instruments and positions are used in the calculation.
The following discussion of the Company's primary market-risk
exposures as of December 31, 2000, includes a discussion of how these
exposures are managed.
Interest-Rate Risk
The Company is exposed to fluctuations in interest rates primarily as
a result of its fixed-rate long-term debt. The Company has
historically funded operations through long-term bond issues with
fixed interest rates. With the restructuring of the regulatory
process, greater flexibility has been permitted within the debt-
management process. As a result, recent debt offerings have been
selected with short-term maturities to take advantage of yield curves
or used a combination of fixed-rate and floating-rate debt. Subject
to regulatory constraints, interest-rate swaps may be used to adjust
interest-rate exposures when appropriate, based upon market
conditions.
At December 31, 2000, the notional amount of interest-rate swap
transactions totaled $45 million. See Note 9 of the notes to
Consolidated Financial Statements for further information regarding
this swap transaction.
The VaR on the Company's fixed-rate long-term debt is estimated
at approximately $114 million as of December 31, 2000, assuming a
one-year holding period.
Energy-Price Risk
Market risk related to physical commodities is based upon potential
fluctuations in natural gas and electricity prices and basis. The
Company's market risk is impacted by changes in volatility and
liquidity in the markets in which these instruments are traded. The
Company is exposed, in varying degrees, to price risk in the natural
gas and electricity markets. The Company's policy is to manage this
risk within a framework that considers the unique markets, operating
and regulatory environment.
Market Risk
SDG&E may, at times, be exposed to limited market risk in its natural
gas purchase, sale and storage activities as a result of activities
under its gas PBR. SDG&E manages this risk within the parameters of
the Company's market-risk management and trading framework. As of
December 31, 2000, the total VaR of SDG&E's natural gas positions was
not material.
31
Credit Risk
Credit risk relates to the risk of loss that would be incurred as a
result of nonperformance by counterparties pursuant to the terms of
their contractual obligations. The Company avoids concentration of
counterparties and maintains credit policies with regard to
counterparties that management believes significantly minimize
overall credit risk. These policies include an evaluation of
prospective counterparties' financial condition (including credit
ratings), collateral requirements under certain circumstances, and
the use of standardized agreements that allow for the netting of
positive and negative exposures associated with a single
counterparty.
The Company monitors credit risk through a credit-approval
process and the assignment and monitoring of credit limits. These
credit limits are established based on risk and return considerations
under terms customarily available in the industry.
Almost all of the Company's accounts receivable are with
customers located in California and, therefore, potentially affected
by the high costs of electricity and natural gas in California, as
described in "Factors Influencing Future Performance" and in Note 12
of the notes to Consolidated Financial Statements.
New Accounting Standards
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 133 "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging
Activities." As amended, SFAS 133, requires that an entity recognize
all derivatives as either assets or liabilities in the statement of
financial position, measure those instruments at fair value and
recognize changes in the fair value of derivatives in earnings in the
period of change unless the derivative qualifies as an effective
hedge that offsets certain exposures.
The adoption of this new standard on January 1, 2001, did not
have a material impact on the Company's earnings. However, $93
million in current assets, $5 million in noncurrent assets, $2
million in current liabilities, and $238 million in noncurrent
liabilities were recorded as of January 1, 2001, in the Consolidated
Balance Sheet as fixed-priced contracts and other derivatives. Due to
the regulatory environment in which SDG&E operates, regulatory assets
and liabilities were established to the extent that derivative gains
and losses are recoverable or payable through future rates. As such,
$93 million in current regulatory liabilities, $5 million in
noncurrent regulatory liabilities, $2 million in current regulatory
assets, and $238 million in noncurrent regulatory assets were
recorded as of January 1, 2001, in the Consolidated Balance Sheet.
The ongoing effects will depend on future market conditions and the
Company's hedging activities.
In December 1999, the Securities and Exchange Commission (SEC)
issued Staff Accounting Bulletin (SAB) 101 - Revenue Recognition.
SABs are not rules issued by the SEC. Rather, they represent
interpretations and practices followed by the SEC's staff in
administering the disclosure requirements of the federal securities
laws. SAB 101 provides guidance on the recognition, presentation and
disclosure of revenue in financial statements; it does not change the
existing rules on revenue recognition. SAB 101 sets forth the basic
criteria that must be met before revenue should be recorded.
Implementation of SAB 101 was required by the fourth quarter of 2000
and had no effect on the Company's consolidated financial statements.
32
Information Regarding Forward-Looking Statements
This Annual Report contains statements that are not historical fact
and constitute forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995, including
statements regarding SDG&E's ability to finance undercollected costs
on reasonable terms and retain its financial strength, estimates of
future accumulated undercollected costs, and its plans to obtain
future financing. The words "estimates," "believes," "expects,"
"anticipates," "plans," "intends," "may," "would" and "should" or
similar expressions, or discussions of strategy or of plans are
intended to identify forward-looking statements. Forward-looking
statements are not guarantees of performance. They involve risks,
uncertainties and assumptions. Future results may differ materially
from those expressed in these forward-looking statements.
Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions; actions by the CPUC, the California
Legislature, the DWR and the FERC; the financial condition of other
investor-owned utilities; inflation rates and interest rates; energy
markets, including the timing and extent of changes in commodity
prices; weather conditions; business, regulatory and legal decisions;
the pace of deregulation of retail natural gas and electricity
delivery; the timing and success of business-development efforts; and
other uncertainties, all of which are difficult to predict and many
of which are beyond the control of the Company. Readers are cautioned
not to rely unduly on any forward-looking statements and are urged to
review and consider carefully the risks, uncertainties and other
factors which affect the Company's business described in this Annual
Report and other reports filed by the Company from time to time with
the SEC.
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 Management Activities."
33
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 as of December
31, 2000 and 1999, and the related statements of consolidated
income, cash flows and changes in shareholders' equity for each of
the three years in the period ended December 31, 2000. These
financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of San
Diego Gas & Electric Company and subsidiary as of December 31, 2000
and 1999, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 2000
in conformity with accounting principles generally accepted in the
United States of America.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
January 26, 2001(February 27,2001 as to Notes 3,4 and 12)
34
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions
For the years ended December 31 2000 1999 1998
------- ------- -------
Operating Revenues
Electric $2,184 $1,818 $1,865
Natural gas 487 389 384
------- ------- -------
Total operating revenues 2,671 2,207 2,249
------- ------- -------
Operating Expenses
Electric fuel and net purchased power 1,326 536 437
Cost of natural gas distributed 273 168 166
Operation and maintenance 412 479 541
Depreciation and decommissioning 210 561 603
Other taxes and franchise payments 81 80 83
Income taxes 134 102 133
------- ------- -------
Total operating expenses 2,436 1,926 1,963
------- ------- -------
Operating Income 235 281 286
------- ------- -------
Other Income and (Deductions)
Allowance for equity funds used
during construction 6 5 5
Interest income 51 40 31
Regulatory interest (8) (6) (2)
Taxes on non-operating income (10) (24) (9)
Other - net (5) 23 (14)
------- ------- -------
Total 34 38 11
------- ------- -------
Income Before Interest Charges 269 319 297
------- ------- -------
Interest Charges
Long-term debt 81 84 96
Other 39 38 12
Allowance for borrowed funds
used during construction (2) (2) (2)
------- ------- -------
Total 118 120 106
------- ------- -------
Net Income 151 199 191
Preferred Dividend Requirements 6 6 6
------- ------- -------
Earnings Applicable to Common Shares $ 145 $ 193 $ 185
======= ======= =======
See notes to Consolidated Financial Statements.
35
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
Dollars in millions
Balance at December 31 2000 1999
------- -------
ASSETS
Utility plant - at original cost $4,778 $4,483
Accumulated depreciation and decommissioning (2,502) (2,326)
------ ------
Utility plant - net 2,276 2,157
------ ------
Nuclear decommissioning trusts 543 551
------ ------
Current assets
Cash and cash equivalents 256 337
Accounts receivable - trade 233 174
Accounts receivable - other 20 18
Due from affiliates -- 152
Income taxes receivable 236 87
Inventories 50 61
Other 8 5
------ ------
Total current assets 803 834
------ ------
Other assets
Loan to parent -- 422
Deferred taxes recoverable in rates 140 114
Regulatory assets 925 233
Deferred charges and other assets 47 55
------ ------
Total other assets 1,112 824
------ ------
Total $4,734 $4,366
====== ======
See notes to Consolidated Financial Statements.
36
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
Dollars in millions
Balance at December 31 2000 1999
------- -------
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock $ 857 $ 857
Retained earnings 205 460
Accumulated other comprehensive income (loss) (3) (3)
------ ------
Total common equity 1,059 1,314
Preferred stock not subject to mandatory redemption 79 79
Preferred stock subject to mandatory redemption 25 25
Long-term debt 1,281 1,418
------ ------
Total capitalization 2,444 2,836
------- ------
Current liabilities
Accounts payable 407 155
Deferred income taxes 252 106
Regulatory balancing accounts - net 367 192
Current portion of long-term debt 66 66
Other 196 161
------ ------
Total current liabilities 1,288 680
------ ------
Deferred credits and other liabilities
Customer advances for construction 40 44
Deferred income taxes 502 327
Deferred investment tax credits 48 51
Deferred credits and other liabilities 412 428
------ ------
Total deferred credits and other liabilities 1,002 850
------ ------
Contingencies and commitments (Note 11)
Total $4,734 $4,366
====== ======
See notes to Consolidated Financial Statements.
37
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions
For the years ended December 31 2000 1999 1998
-------- -------- --------
Cash Flows from Operating Activities
Net income $ 151 $ 199 $ 191
Adjustments to reconcile net income
to net cash provided by operating activities
Depreciation and decommissioning 210 561 603
Customer refunds paid (628) -- --
Portion of depreciation arising from sales of
generating plants -- (303) --
Application of balancing accounts to stranded costs -- (66) (86)
Deferred income taxes and investment tax credits 300 (3) (49)
Non-cash rate reduction bond expense (revenue) 32 (42) --
Other - net (170) 53 (115)
Changes in working capital components
Accounts receivable (55) 7 30
Inventories -- -- (12)
Income taxes (149) (87) 4
Other current assets (17) (45) 51
Accounts payable 252 (6) 4
Regulatory balancing accounts 213 267 (14)
Other current liabilities 35 (15) (72)
------- ------- -------
Net cash provided by operating activities 174 520 535
------- ------- -------
Cash Flows from Investing Activities
Capital expenditures (324) (245) (227)
Loan repaid by (paid to) affiliate 593 (422) --
Proceeds from sales of generating plants - net -- 466 --
Contributions to decommissioning funds (5) (16) (22)
Other - net 24 (8) (28)
------- ------- -------
Net cash provided by (used in) investing
activities 288 (225) (277)
------- ------- -------
Cash Flows from Financing Activities
Dividends paid (406) (106) (269)
Issuance of long-term debt 12 -- --
Repayment of long-term debt (149) (136) (241)
------- ------- -------
Net cash used in financing activities (543) (242) (510)
------- ------- -------
Increase (decrease) in cash and cash equivalents (81) 53 (252)
Cash and cash equivalents, January 1 337 284 536
------- ------- -------
Cash and cash equivalents, December 31 $ 256 $ 337 $ 284
======= ======= =======
See notes to Consolidated Financial Statements.
38
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS (continued)
Dollars in millions
For the years ended December 31 2000 1999 1998
------- ------- -------
Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Income tax payments (refunds) - net $ (8) $ 266 $ 207
======= ======= =======
Interest payments, net of amounts capitalized $ 119 $ 134 $ 118
======= ======= =======
Supplemental Schedule of Non-Cash Transactions
Dividend to parent of intercompany receivable $ -- $ -- $ 100
======= ======= =======
Property dividend to parent $ -- $ -- $ 29
======= ======= =======
See notes to Consolidated Financial Statements.
39
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
For the years ended December 31, 2000, 1999, 1998
(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, 1997 | $ 79 $ 857 $ 530 $1,466
Net income/comprehensive income $ 191 | 191 191
Special dividends to Sempra Energy | (129) (129)
Preferred dividends declared | (6) (6)
Common stock dividends declared | (319) (319)
- -------------------------------------------------------------------------------------------------------
Balance at December 31, 1998 | 79 857 267 1,203
Net income 199 | 199 199
Other comprehensive income(loss): |
Pension (3)| $ (3) (3)
-----|
Comprehensive income $ 196 |
Preferred dividends declared | (6) (6)
- ------------------------------------------------------------------------------------------------------
Balance at December 31, 1999 | 79 857 460 (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
====================================================================================================
See notes to Consolidated Financial Statements.
40
NOTE 1: BUSINESS COMBINATION
On June 26, 1998, Enova Corporation (Enova or Parent), the parent
company of San Diego Gas & Electric (SDG&E or the Company), and
Pacific Enterprises (PE), parent company of Southern California Gas
Company (SoCalGas), combined into a new company named Sempra Energy.
As a result of the combination, (i) each outstanding share of common
stock of Enova was converted into one share of common stock of Sempra
Energy, (ii) each outstanding share of common stock of PE was
converted into 1.5038 shares of common stock of Sempra Energy and
(iii) the preferred stock and preference stock of the combining
companies and their subsidiaries remained outstanding.
NOTE 2: SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The Consolidated Financial Statements include the accounts of SDG&E
and its sole subsidiary, SDG&E Funding LLC. The Company's policy is to
consolidate subsidiaries that are more than 50 percent owned and
controlled. All material intercompany accounts and transactions have
been eliminated.
As a subsidiary of Sempra Energy, the Company receives certain
services therefrom. Although it is charged its allocable share of the
cost of such services, that cost is less than if the Company had to
provide those services itself.
Effects of Regulation
The accounting policies of SDG&E 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 prepares its financial statements in accordance with the
provisions of Statement of Financial Accounting Standards (SFAS) No.
71, "Accounting for the Effects of Certain Types of Regulation," under
which a regulated utility records a regulatory asset if it is probable
that, through the ratemaking process, the utility will recover that
asset from customers. Regulatory liabilities represent future
reductions in rates for amounts due to customers. To the extent that
portions of the utility operations were to be no longer subject to
SFAS No. 71, or recovery was to be no longer probable as a result of
changes in regulation or the utility's competitive position, the
related regulatory assets and liabilities would be written off. In
addition, SFAS No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of," affects utility
plant and regulatory assets such that a loss must be recognized
whenever a regulator excludes all or part of an asset's cost from rate
base. The application of SFAS No. 121 continues to be evaluated in
connection with industry restructuring. Information concerning
regulatory assets and liabilities is described below in "Revenues and
Regulatory Balancing Accounts" and industry restructuring is described
in Note 12.
Revenues and Regulatory Balancing Accounts
Revenues from utility customers consist of deliveries to customers and
the changes in regulatory balancing accounts.
Prior to 1998, earnings fluctuations from changes in the costs of
fuel oil, purchased energy and natural gas, and consumption levels for
41
electricity and the majority of natural gas were eliminated by
balancing accounts authorized by the CPUC. However, as a result of
California's electric-restructuring law, previous overcollections
recorded in SDG&E's applicable balancing accounts were applied to
recovery of prior generation costs (as described in Note 12), and
fluctuations in certain costs and consumption levels can now affect
earnings from electric operations. In addition, fluctuations in
certain costs and consumption levels can affect earnings from the
Company's gas operations. Additional information on regulatory matters
is included in Note 12.
Regulatory Assets
Regulatory assets include undercollected electric-commodity costs
accumulated due to the temporary rate ceiling imposed in mid-2000.
Regulatory assets also include unrecovered premiums on early
retirement of debt, postretirement benefit costs, deferred income
taxes recoverable in rates and other expenditures that the utilities
expect to recover in future rates. See Note 12 for additional
information on the rate ceiling, industry restructuring and other
regulatory matters.
Inventories
Included in inventories at December 31, 2000, were $38 million of
materials and supplies ($50 million in 1999), and $12 million of
natural gas and fuel oil ($11 million in 1999). Materials and supplies
are generally valued at the lower of average cost or market; fuel oil
and natural gas are valued by the last-in first-out method.
Loan to Affiliate
SDG&E has a promissory note receivable from Sempra Energy. The note
bears interest based on short-term commercial paper rates, and is due
on demand. The note receivable was $19 million and $612 million at
December 31, 2000 and 1999, respectively.
Utility Plant
This primarily represents the buildings, equipment and other
facilities used by SDG&E to provide natural gas and electric utility
service.
The cost of utility plant includes labor, materials, contract
services and related items, and an allowance for funds used during
construction. The cost of retired depreciable utility plant, plus
removal costs minus salvage value, is charged to accumulated
depreciation. Information regarding electric industry restructuring
and its effect on utility plant is included in Note 12. Utility plant
balances by major functional categories at December 31, 2000, were:
natural gas operations $0.9 billion, electric distribution $2.7
billion, electric transmission $0.8 billion, and other electric $0.4
billion. The corresponding amounts at December 31, 1999, were: natural
gas operations $0.9 billion, electric distribution $2.5 billion,
electric transmission $0.7 billion, and other electric $0.4 billion.
Accumulated depreciation and decommissioning of natural gas and
electric utility plant in service at December 31, 2000, were $0.5
billion and $2.0 billion, respectively, and at December 31, 1999, were
$0.5 billion and $1.8 billion, respectively. Depreciation expense is
based on the straight-line method over the useful lives of the assets
or a shorter period prescribed by the CPUC. The provisions for
42
depreciation as a percentage of average depreciable utility plant (by
major functional categories) in 2000, 1999 and 1998, respectively
were: natural gas operations 3.79, 3.83, 4.01, electric distribution
4.67, 4.69, 4.49, electric transmission 3.21, 3.50, 3.31, and other
electric 8.33, 8.21, 6.29. See Note 12 for discussion of the sale of
generation facilities and industry restructuring.
Allowance for Funds Used During Construction (AFUDC)
The allowance represents the cost of funds used to finance the
construction of utility plant and is added to the cost of utility
plant. AFUDC also increases income, partly as an offset to interest
charges shown in the Statements of Consolidated Income, although it is
not a current source of cash.
Nuclear-Decommissioning Liability
Deferred credits and other liabilities at December 31, 2000, and 1999,
include $162 million and $165 million, respectively, of accumulated
decommissioning costs associated with SDG&E's interest in San Onofre
Nuclear Generating Station (SONGS) Unit 1, which was permanently shut
down in 1992. Additional information on SONGS Unit 1 decommissioning
costs is included in Note 5. The corresponding liability for Units 2
and 3 is included in accumulated depreciation and amortization.
Comprehensive Income
Comprehensive income includes all changes, except those resulting from
investments by owners and distributions to owners, in the equity of a
business enterprise from transactions and other events including, as
applicable, minimum pension liability adjustments.
Use of Estimates in the Preparation of the Financial Statements
The preparation of the consolidated financial statements in conformity
with generally accepted accounting principles requires management to
make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Actual
results could differ from those estimates.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with original
maturities of three months or less at the date of purchase.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the
current year's presentation.
New Accounting Standards
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 133 "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging
Activities." As amended, SFAS 133 requires that an entity recognize
all derivatives as either assets or liabilities in the statement of
43
financial position, measure those instruments at fair value and
recognize changes in the fair value of derivatives in earnings in the
period of change unless the derivative qualifies as an effective hedge
that offsets certain exposures.
The adoption of this new standard on January 1, 2001, did not
have a material impact on the Company's earnings. However, $93
million in current assets, $5 million in noncurrent assets, $2
million in current liabilities, and $238 million in noncurrent
liabilities were recorded as of January 1, 2001, in the Consolidated
Balance Sheet as fixed-priced contracts and other derivatives. Due to
the regulatory environment in which SDG&E operates, regulatory assets
and liabilities were established to the extent that derivative gains
and losses are recoverable or payable through future rates. As such,
$93 million in current regulatory liabilities, $5 million in
noncurrent regulatory liabilities, $2 million in current regulatory
assets, and $238 million in noncurrent regulatory assets were
recorded as of January 1, 2001, in the Consolidated Balance Sheet.
The ongoing effects will depend on future market conditions and the
Company's hedging activities.
In December 1999, the Securities and Exchange Commission (SEC)
issued Staff Accounting Bulletin (SAB) 101 - Revenue Recognition. SABs
are not rules issued by the SEC. Rather, they represent
interpretations and practices followed by the SEC's staff in
administering the disclosure requirements of the federal securities
laws. SAB 101 provides guidance on the recognition, presentation and
disclosure of revenue in financial statements; it does not change the
existing rules on revenue recognition. SAB 101 sets forth the basic
criteria that must be met before revenue should be recorded.
Implementation of SAB 101 was required by the fourth quarter of 2000
and had no effect on the Company's consolidated financial statements.
NOTE 3: SHORT-TERM BORROWINGS
At December 31, 2000, SDG&E had $285 million of bank lines available
to support commercial paper and variable-rate long-term debt. The
credit agreements expire at varying dates in mid-2001, but $200
million of the then outstanding borrowings may be extended, at SDG&E's
option, to a term maturity of an additional year. Any debt under the
lines would bear interest at various rates based on market rates and
SDG&E's credit rating. SDG&E's bank lines of credit were unused at
both December 31, 2000, and 1999.
Between January 24 and February 5, 2001, SDG&E drew down $250
million on these credit facilities.
44
NOTE 4: LONG-TERM DEBT
- -------------------------------------------------------------------
December 31,
(Dollars in millions) 2000 1999
- -------------------------------------------------------------------
First-mortgage Bonds
7.625% June 15, 2002 $ 28 $ 28
6.800% June 1, 2015 14 14
5.900% June 1, 2018 68 68
5.900% September 1, 2018 93 93
6.100% September 1, 2018 40 40
6.400% September 1, 2018 43 43
6.100% September 1, 2019 35 35
Variable rates September 1, 2020 58 58
5.850% June 1, 2021 60 60
8.500% April 1, 2022 10 10
5.420% December 1, 2027 45 45
6.400% December 1, 2027 75 75
Variable rates December 1, 2027 45 105
9.625% April 15, 2020 - 10
------------------------
614 684
------------------------
Unsecured Bonds
5.900% June 1, 2014 130 130
Variable rates July 1, 2021 39 39
Variable rates December 1, 2021 60 60
Variable rates March 1, 2023 25 25
------------------------
254 254
------------------------
Rate-reduction bonds, various rates
(payable annually through 2007) 461 526
Capital leases 19 21
------------------------
Total 1,348 1,485
Less:
Current portion of long-term debt 66 66
Unamortized debt discount - net 1 1
------------------------
Total $1,281 $1,418
- -------------------------------------------------------------------
Excluding capital leases, which are described in Note 11, maturities
of long-term debt, including rate-reduction bonds, are $66 million in
2001, $94 million in 2002, $66 million in 2003, $66 million in 2004,
$66 million in 2005 and $971 million thereafter. Although holders of
variable-rate bonds may elect to redeem them prior to scheduled
maturity, for purposes of determining the maturities listed above,
since redeemed bonds are remarketed and are backed by long-term lines
of credit, it is assumed the bonds will be held to maturity.
SDG&E has CPUC authorization to issue an additional $938 million
in short-term or long-term debt (see discussion under "Recent Shelf
Registration" below).
First-Mortgage Bonds
First-mortgage bonds are secured by a lien on substantially all of
SDG&E's utility plant. SDG&E may issue additional first-mortgage bonds
45
upon compliance with the provisions of their bond indentures, which
permit, among other things, the issuance of an additional $1.6 billion
of first-mortgage bonds as of December 31, 2000, subject to CPUC
authorization (see discussion under "Recent Shelf Registration" below.
During May 2000, by the Company called $10 million of first-
mortgage bonds prior to scheduled maturity. During December 2000, $60
million of variable-rate first-mortgage bonds were put back by the
holders and subsequently remarketed on February 1, 2001 at 7.0 percent
fixed interest rate.
Callable Bonds
At SDG&E's option, certain first-mortgage bonds may be called at a
premium. SDG&E has $227 million of variable-rate bonds that are
callable at various dates in 2001. Of the Company's remaining callable
bonds, $45 are callable in year 2001, $204 million are callable in
2002 and $221 million in 2003.
Rate-Reduction Bonds
In December 1997, $658 million of rate-reduction bonds were issued on
behalf of SDG&E at an average interest rate of 6.26 percent. These
bonds were issued to facilitate the 10-percent rate reduction mandated
by California's electric-restructuring law. See Note 12 for additional
information. These bonds are being repaid over 10 years by SDG&E's
residential and small commercial customers via a charge on their
electricity bills. These bonds are secured by the revenue streams
collected from customers and are not secured by, or payable from,
utility assets.
The sizes of the rate-reduction bond issuances were set so as to
make the IOUs neutral as to the 10-percent rate reduction, and were
based on a four-year period to recover stranded costs. Because SDG&E
recovered its stranded costs in only 18 months (due to the greater-
than-anticipated plant-sale proceeds), the bond sale proceeds were
greater than needed. Accordingly, during the third quarter of 2000,
SDG&E returned to its customers, via a combination of cash refunds and
billing credits, $388 million of surplus bond proceeds in accordance
with a June 8, 2000 CPUC decision. The bonds and their repayment
schedule are not affected by this refund.
Unsecured Debt
Various long-term obligations totaling $254 million are unsecured.
Unsecured bonds totaling $124 million have variable-interest-rate
provisions.
Recent Shelf Registration
In December 2000, SDG&E filed a shelf registration for the public
offering of up to $800 million of debt securities and requested CPUC
authorization to incur additional indebtedness. On February 8, 2001,
the CPUC approved SDG&E's financing application, but denied SDG&E
authority to issue first-mortgage bonds beyond the $138 million
previously authorized. SDG&E has requested a rehearing of this denial.
Any securities under this shelf registration are offered on a delayed
or continuous basis pursuant to Rule 415 under the Securities Act of
1933. At December 31, 2000, no debt securities were issued under this
registration statement.
46
Interest Rate Swaps
SDG&E periodically enters into interest-rate swap and cap agreements
to moderate its exposure to interest-rate changes and to lower its
overall cost of borrowing. At December 31, 2000, SDG&E had such an
agreement, maturing in 2002, with underlying debt of $45 million.
NOTE 5: FACILITIES UNDER JOINT OWNERSHIP
SONGS and the Southwest Powerlink transmission line are owned jointly
with other utilities. The Company's interests at December 31, 2000,
are:
- -------------------------------------------------------------------
(Dollars in millions) Southwest
Project SONGS Powerlink
- -------------------------------------------------------------------
Percentage ownership 20 88
Utility plant in service $ 63 $217
Accumulated depreciation and amortization $ 32 $119
Construction work in progress $ 5 $ 2
- -------------------------------------------------------------------
The Company's share of operating expenses is included in the
Statements of Consolidated Income. Participants in each project must
provide their own financing. The amounts specified above for SONGS
include nuclear production, transmission and other facilities. Certain
substation equipment at SONGS is wholly owned by the Company.
SONGS Decommissioning
Objectives, work scope and procedures for the future dismantling and
decontamination of the SONGS units must meet the requirements of the
Nuclear Regulatory Commission, the Environmental Protection Agency,
the CPUC and other regulatory bodies.
The Company's share of decommissioning costs for the SONGS units
is estimated to be $449 million in current dollars, based on a cost
study completed in 1998. Cost studies are updated every three years
and approved by the CPUC. Rate recovery of decommissioning costs is
allowed until the time that the costs are fully recovered. The amount
accrued each year, which is currently being collected in rates, is
based on the amount allowed by regulators. This amount is considered
sufficient to cover the Company's share of future decommissioning
costs. Payments to the nuclear decommissioning trusts are expected to
continue until SONGS is fully decommissioned, which is not expected to
occur before 2022, or until sufficient funds have been collected.
Unit 1 was permanently shut down in 1992, and physical
decommissioning began in January 2000. Several structures have been
dismantled, and preparations have been made for major work to be
performed in 2001 and beyond. That work will include dismantling,
removal and disposal of all Unit 1 equipment and facilities, (both
nuclear and non-nuclear components), decontamination of the site and
construction of an on-site storage facility for Unit 1 spent fuel.
These activities are expected to be completed by 2008.
The amounts collected in rates are invested in externally managed
trust funds. The securities held by the trust are considered available
for sale and the trust is shown on the Consolidated Balance Sheets at
market value. These values reflect unrealized gains of $158 million
and $164 million at December 31, 2000, and 1999, respectively.
The Financial Accounting Standards Board (FASB) is reviewing the
accounting for liabilities related to closure and removal of long-
47
lived assets, such as nuclear power plants, including the recognition,
measurement and classification of such costs. The FASB could require,
among other things, that the Company's future balance sheets include a
liability for the estimated decommissioning costs, and a related
increase in the carrying value of the asset.
Additional information regarding SONGS is included in Notes 11
and 12.
NOTE 6: INCOME TAXES
The reconciliation of the statutory federal income tax rate to the
effective income tax rate is as follows:
- -------------------------------------------------------------
2000 1999 1998
- -------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 6.6 5.2 1.3
State income taxes - net of
federal income tax benefit 8.5 5.9 5.6
Tax credits (1.5) (2.1) (1.7)
Charitable contribution of plant - (7.9) -
Other - net 0.2 2.7 2.4
---------------------------
Effective income tax rate 48.8% 38.8% 42.6%
- -------------------------------------------------------------
The components of income tax expense are as follows:
- -------------------------------------------------------------
(Dollars in millions) 2000 1999 1998
- -------------------------------------------------------------
Current
Federal $ (115) $ 90 $ 150
State (41) 39 41
---------------------------
Total current taxes (156) 129 191
---------------------------
Deferred
Federal 244 11 (30)
State 59 (9) (16)
---------------------------
Total deferred taxes 303 2 (46)
---------------------------
Deferred investment
tax credits - net (3) (5) (3)
---------------------------
Total income tax expense $ 144 $ 126 $ 142
- -------------------------------------------------------------
Federal and state income taxes are allocated between operating income
and other income.
48
Accumulated deferred income taxes at December 31 result from the
following:
- -------------------------------------------------------------
(Dollars in millions) 2000 1999
- -------------------------------------------------------------
Deferred tax liabilities:
Differences in financial and
tax bases of utility plant $ 341 $ 356
Regulatory balancing accounts 470 150
Loss on reacquired debt 24 30
Other 83 70
---------------------------
Total deferred tax liabilities 918 606
---------------------------
Deferred tax assets:
Investment tax credits 33 35
Other 131 138
---------------------------
Total deferred tax assets 164 173
---------------------------
Net deferred income tax liability $ 754 $ 433
- -------------------------------------------------------------
The net liability is recorded on the Consolidated Balance
Sheets at December 31, 2000 as follows:
- -------------------------------------------------------------
(Dollars in millions) 2000 1999
- -------------------------------------------------------------
Current liability $ 252 $ 106
Noncurrent liability 502 327
- -------------------------------------------------------------
Total $ 754 $ 433
- -------------------------------------------------------------
NOTE 7: EMPLOYEE BENEFIT PLANS
The information presented below describes the plans of the Company. In
connection with the PE/Enova business combination described in Note 1,
numerous participants have been transferred from the Company's plans
to plans of related entities.
In connection with voluntary separations related to the business
combination, the Company recorded a $9 million special termination
benefit in 1998. During 2000, the Company participated in another
voluntary separation program. As a result, the Company recorded a $5
million special termination benefit in 2000.
Pension and Other Postretirement Benefits
The Company sponsors qualified and nonqualified pension plans and
other postretirement benefit plans for its employees. The following
tables provide a reconciliation of the changes in the plans' benefit
obligations and fair value of assets over the two years, and a
statement of the funded status as of each year end:
49
- -------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
(Dollars in millions) 2000 1999 2000 1999
- -------------------------------------------------------------------------------
Weighted-Average Assumptions
as of December 31:
Discount rate 7.25%(1) 7.75% 7.75% 7.75%
Expected return on plan assets 8.00% 8.00% 4.00% 4.00%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered
health care charges - - 7.50%(2) 7.75%(2)
Change in Benefit Obligation:
Net benefit obligation at
January 1 $ 476 $ 494 $ 45 $ 48
Service cost 10 11 1 1
Interest cost 36 34 3 3
Plan participants' contributions - - - 2
Actuarial (gain) loss 9 4 3 (4)
Transfer of liability(3) - (15) - -
Curtailments (1) - - -
Special termination benefits 5 - - -
Gross benefits paid (58) (52) (3) (5)
----------------------------------------------
Net benefit obligation at
December 31 477 476 49 45
----------------------------------------------
Change in Plan Assets:
Fair value of plan assets
at January 1 713 587 18 17
Actual return on plan assets (51) 178 3 -
Employer contributions - - 4 4
Plan participants' contributions - - - 2
Gross benefits paid (58) (52) (3) (5)
----------------------------------------------
Fair value of plan assets
at December 31 604 713 22 18
----------------------------------------------
Funded status at December 31 127 237 (27) (27)
Unrecognized net actuarial gain (182) (317) - (2)
Unrecognized prior service cost 16 20 - -
----------------------------------------------
Net recorded liability
at December 31 $ (39) $ (60) $ (27) $ (29)
- --------------------------------------------------------------------------------
(1) Discount rate decreased from 7.75% to 7.25%, effective March 1, 2000.
(2) Decreasing to ultimate trend of 6.50% in 2004.
(3) To reflect transfer of plan liability to Sempra Energy.
The following table provides the amounts recognized on the
Consolidated Balance Sheets at December 31:
- -------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
--------------------------------------------
(Dollars in millions) 2000 1999 2000 1999
- -------------------------------------------------------------------------------
Accrued benefit cost $(36) $(57) $(27) $(29)
Accumulated other
comprehensive income, pretax (3) (3) - -
- -------------------------------------------------------------------------------
Net recorded liability $(39) $(60) $(27) $(29)
- -------------------------------------------------------------------------------
50
The following table provides the components of net periodic benefit
cost (income) for the plans:
- ------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
For the years ended December 31 2000 1999 1998 2000 1999 1998
(Dollars in millions)
-----------------------------------------------
Service cost $ 10 $ 11 $ 19 $ 1 $ 1 $ 1
Interest cost 36 34 43 3 3 3
Expected return on assets (57) (47) (60) (1) - (1)
Amortization of:
Transition obligation - - - 2 2 2
Prior service cost 3 3 3 - - -
Actuarial gain (17) (9) (11) - - -
Special termination benefits 5 - 9 1 - -
Regulatory adjustment - - - (2) - -
-----------------------------------------------
Total net periodic benefit cost
(income) $(20) $ (8) $ 3 $ 4 $ 6 $ 5
- ------------------------------------------------------------------------------
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 $ 2 $ (2)
obligation
- ------------------------------------------------------------------------
Other postretirement benefits include retiree life insurance and
medical benefits for retirees and their spouses.
Savings Plan
The Company offers a savings plan, administered by plan trustees, to
all eligible employees. Eligibility to participate in the plan begins
after one month of service. Employees may contribute, subject to plan
provisions, from 1 percent to 15 percent of their regular earnings.
Employer contributions, after one year of service, are used to
purchase shares of Sempra Energy common stock. Employer contributions
are equal to 50 percent of the first 6 percent of eligible base salary
contributed by employees. The employees' contributions, at the
direction of the employees, are primarily invested in Sempra Energy
common stock, mutual funds or institutional trusts. During 2000,
SDG&E's plan contribution was age-based for represented employees.
Company contributions to the savings plan were $5 million in 2000, $4
million in 1999 and $5 million in 1998.
NOTE 8: STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans that align employee
and shareholder objectives related to Sempra Energy's long-term
growth. The long-term incentive stock compensation plan provides for
aggregate awards of Sempra Energy non-qualified stock options,
incentive stock options, restricted stock, stock appreciation rights,
51
performance awards, stock payments or dividend equivalents.
In 1995, SFAS No. 123, "Accounting for Stock-Based Compensation,"
was issued. It encourages a fair-value-based method of accounting for
stock-based compensation. As permitted by SFAS No. 123, Sempra Energy
and its subsidiaries adopted only its disclosure requirements and
continues to account for stock-based compensation in accordance with
the provisions of Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees."
The subsidiaries record an expense for the plans to the extent
that subsidiary 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 $1 million and $2 million in 2000
and 1998, respectively. There were no expenses recorded in 1999.
NOTE 9: FINANCIAL INSTRUMENTS
Fair Value
The fair values of the Company's financial instruments (cash,
temporary investments, notes receivable, dividends payable, short-term
and long-term debt, customer deposits, and preferred stock) are not
materially different from the carrying amounts, except for long-term
debt and preferred stock. The carrying amounts and fair values of
long-term debt were $1.3 billion and $1.4 billion, respectively, at
December 31, 2000. The carrying amounts and fair values of long-term
debt were both $1.5 billion at December 31, 1999. Included in long-
term debt are SDG&E's rate-reduction bonds. The carrying amounts and
fair values of the bonds were $461 million and $462 million,
respectively, at December 31, 2000, and $526 million and $511 million,
respectively, at December 31, 1999. The carrying amounts and fair
values of preferred stock were $104 million and $89 million,
respectively, at December 31, 2000, and $104 million and $97 million,
respectively, at December 31, 1999. The fair values of the long-term
debt and preferred stock were estimated based on quoted market prices
for them or for similar issues.
Off-Balance-Sheet Financial Instruments
The Company's policy is to use derivative financial instruments to
manage its exposure to fluctuations in interest rates, foreign-
currency exchange rates and energy prices. Transactions involving
these financial instruments expose the Company to market and credit
risks which may at times be concentrated with certain counterparties,
although counterparty nonperformance is not anticipated.
Swap Agreements
The Company periodically enters into interest-rate-swap and cap
agreements to moderate exposure to interest-rate changes and to lower
the overall cost of borrowing. These agreements generally remain off
the balance sheet as they involve the exchange of fixed-rate and
variable-rate interest payments without the exchange of the underlying
principal amounts. The related gains or losses are reflected in the
Statements of Consolidated Income as part of interest expense.
At December 31, 2000, and 1999, the Company had one interest-
rate-swap agreement: a floating-to-fixed-rate swap associated with $45
million of variable-rate bonds maturing in 2002. SDG&E expects to hold
this financial instrument to its maturity. This swap agreement has
effectively fixed the interest rate on the underlying variable-rate
debt at 5.4 percent. SDG&E would be exposed to interest-rate
52
fluctuations on the underlying debt should the counterparty to the
agreement not perform. Such nonperformance is not anticipated. This
agreement, if terminated, would result in an obligation of $1.3
million at both December 31, 2000, and December 31, 1999. Additional
information on this topic is included in Note 4.
Energy Derivatives
The Company uses energy derivatives for price-risk management purposes
within certain limitations imposed by Company policies and regulatory
requirements. Energy derivatives are used to mitigate risk and better
manage costs. These instruments include forward contracts, swaps,
options and other contracts which have maturities ranging from 30 days
to 12 months.
At December 31, 2000, and 1999, gains and/or losses from these
activities were not material to SDG&E's financial statements.
NOTE 10: SHAREHOLDERS' EQUITY AND PREFERRED STOCK SUBJECT TO
MANDATORY REDEMPTION
- --------------------------------------------------------------------
Call December 31,
(Dollars in millions,
except call price) Price 2000 1999
- ---------------------------------------------------------------------
COMMON EQUITY
Common stock, without par value,
authorized 255,000,000 shares, all outstanding
shares are owned by Enova Corporation $ 857 $ 857
Retained earnings 205 460
Accumulated other comprehensive income (3) (3)
---------------------
Total $1,059 $1,314
---------------------
PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION
$20 par value, authorized 1,375,000 shares:
5% Series, 375,000
shares outstanding $ 24.00 $ 8 $ 8
4.50% Series, 300,000
shares outstanding $ 21.20 6 6
4.40% Series, 325,000
shares outstanding $ 21.00 7 7
4.60% Series, 373,770
shares outstanding $ 20.25 7 7
Without par value:
$1.70 Series, 1,400,000
shares outstanding $ 25.85 35 35
$1.82 Series, 640,000
shares outstanding $ 26.00 16 16
---------------------
Total $79 $79
----------------------
Total Shareholders' Equity $1,138 $1,393
----------------------
- -----------------------------------------------------------------
Call December 31,
(Dollars in millions
except call price) Price 2000 1999
- --------------------------------------------------------------------
PREFERRED STOCK SUBJECT TO MANDATORY REDEMPTION
Without par value, $1.7625 Series,
1,000,000 shares outstanding $ 25.00 $25 $25
- --------------------------------------------------------------------
Dividend Restrictions
CPUC regulation of SDG&E's capital structure limits to $154 million
the portion of the Company's December 31, 2000 retained earnings that
is available for dividends.
53
All series of SDG&E's preferred stock have cumulative preferences
as to dividends. The $20 par value preferred stock has two votes per
share on matters being voted upon by shareholders of SDG&E and a
liquidation value at par, whereas the no par value preferred stock is
nonvoting and has a liquidation value of $25 per share. SDG&E is
authorized to issue 10,000,000 shares of no par value preferred stock
(both subject to and not subject to mandatory redemption). All series
are currently callable except for the $1.70 and $1.7625 series
(callable in 2003). The $1.7625 series has a sinking fund requirement
to redeem 50,000 shares per year from 2003 to 2007; the remaining
750,000 shares must be redeemed in 2008.
NOTE 11: COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts
SDG&E buys natural gas under several short-term and long-term
contracts. Short-term purchases are from various Southwest U.S.
and Canadian suppliers and are primarily based on monthly spot-
market prices. SDG&E transports gas under long-term firm
pipeline capacity agreements that provide for annual
reservation charges. SDG&E recovers such fixed charges in
rates. These contracts expire at various dates between 2007 and
2023.
SDG&E had been involved in negotiations and litigation with four
Canadian suppliers concerning contract terms and prices related to
long-term natural gas supply contracts. In 1999, SDG&E settled with
the last of the four suppliers, terminating the contract. SDG&E
continues to purchase natural gas from one of the suppliers under
terms of the settlement agreement. SDG&E purchases natural gas on a
spot basis to fill its additional long-term pipeline capacity. SDG&E
continues to use the long-term pipeline capacity in other ways as
well, including the transport of replacement natural gas and the
release of a portion of this capacity to third parties. All of SDG&E's
gas is delivered through SoCalGas pipelines under a short-term
transportation agreement. In addition, SoCalGas provides SDG&E six
billion cubic feet of natural gas storage capacity under an agreement
expiring March 2002.
At December 31, 2000, the future minimum payments under natural
gas contracts were:
- -----------------------------------------------------------------
Storage and
(Dollars in millions) Transportation Natural Gas
- -----------------------------------------------------------------
2001 $ 14 $ 108
2002 11 34
2003 10 17
2004 12 -
2005 12 -
Thereafter 150 -
----------------------------------
Total minimum payments $ 209 $ 159
- -----------------------------------------------------------------
Total payments under the contracts were $273 million in 2000, $220
million in 1999 and $324 million in 1998.
Purchased-Power Contracts
SDG&E buys electric power under several long-term contracts. The
contracts expire on various dates between 2001 and 2025. Prior to the
54
electric rate ceiling described in Note 14, the above-market cost of
contracts was recovered from virtually all of SDG&E's customers. In
general, the market value of these contracts was recovered by bidding
them into the California Power Exchange (PX) and receiving revenue
from the PX for bids accepted. As of January 1, 2001, SDG&E no longer
bid those contracts into the PX in compliance with a FERC order
prohibiting sales to the PX. Since then those contracts have been used
to serve customers. In late 2000, SDG&E entered into additional
contracts to serve customers instead of buying all of its power from
the PX. On January 17, 2001, The California Assembly passed a bill
(AB1) to allow the California Department of Water Resources (DWR) to
purchase power under long-term contracts for the benefit of California
consumers. For additional discussion of this matter see Note 12.
At December 31, 2000, the estimated future minimum payments under
the long-term contracts were:
- -----------------------------------------------------------------
(Dollars in millions)
- -----------------------------------------------------------------
2001 $ 320
2002 223
2003 211
2004 162
2005 164
Thereafter 2,295
----------
Total minimum payments $3,375
- -----------------------------------------------------------------
The payments represent capacity charges and minimum energy purchases.
SDG&E is required to pay additional amounts for actual purchases of
energy that exceed the minimum energy commitments. Total payments
under the contracts were $257 million in 2000, $251 million in 1999
and $293 million in 1998.
Leases
SDG&E has capital and operating leases on real and personal property
expiring at various dates from 2001 to 2032. Certain leases on office
facilities contain escalation clauses requiring annual increases in
rent ranging from 2 percent to 5 percent. The rentals payable under
these leases are determined on both fixed and percentage bases, and
most leases contain options to extend, which are exercisable by SDG&E.
SDG&E also has nuclear fuel and real property that are financed by
long-term capital leases. Property, plant and equipment included $58
million at December 31, 2000, and $46 million at December 31, 1999
related to these leases. The associated accumulated amortization is
$38 million and $24 million, respectively.
55
At December 31, 2000, the minimum rental commitments payable in
future years under all noncancellable leases were:
- -----------------------------------------------------------------
Operating Capitalized
(Dollars in millions) Leases Leases
- -----------------------------------------------------------------
2001 $ 14 $20
2002 13 -
2003 11 -
2004 9 -
2005 8 -
Thereafter 23 -
------------------------------
Total future rental commitment $ 78 20
Imputed interest (6%) (1)
-----------
Net commitment $19
- -----------------------------------------------------------------
Rent expense totaled $32 million in 2000, $39 million in 1999 and $50
million in 1998.
Other Commitments and Contingencies
At December 31, 2000, commitments for capital expenditures were
approximately $12 million.
Environmental Issues
The Company's operations are subject to federal, state and local
environmental laws and regulations governing hazardous wastes, air and
water quality, land use, solid waste disposal and the protection of
wildlife. The Company incurs significant costs to operate its
facilities in compliance with these laws and regulations and these
costs generally have been recovered in customer rates.
In 1994, the CPUC approved the Hazardous Waste Collaborative
Memorandum account allowing utilities to recover their hazardous waste
costs, including those related to Superfund sites or similar sites
requiring cleanup. Recovery of 90 percent of cleanup costs and related
third-party litigation costs and 70 percent of the related insurance-
litigation expenses is permitted. In addition, the Company has the
opportunity to retain a percentage of any insurance recoveries to
offset the 10 percent of costs not recovered in rates. Environmental
liabilities that may arise are recorded when remedial efforts are
probable and the costs can be estimated.
The Company's capital expenditures to comply with environmental
laws and regulations were $2 million in 2000, $160,000 in 1999 and $1
million in 1998. The increase in 2000 is due to the installation of
emission-control equipment on the Company's Rainbow compressor
facility. Compliance with these regulations over the next five years
is not expected to be significant. The Company has been associated
with various sites, which may require remediation under federal, state
or local environmental laws. The Company is unable to determine fully
the extent of its responsibility for remediation of these sites until
assessments are completed. Furthermore, the number of others that also
may be responsible, and their ability to share in the cost of the
cleanup, is not known.
The environmental issues currently facing the Company or resolved
56
during the latest three-year period include investigation and
remediation of its manufactured-gas sites (all three sites completed
as of December 31, 2000 and site-closure letters received for two),
asbestos and other cleanup at its former fossil-fuel power plants (all
sold in 1999 and actual or estimated cleanup costs included in the
transactions), cleanup of third-party waste disposal sites used by the
Company, which has been identified as a Potentially Responsible Party
(investigation 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 restorations on 150 acres of coastal wetlands are
in process).
As discussed in Note 12, restructuring of the California electric
utility industry has changed the way utility rates are set and costs
are recovered. In 1998, the CPUC modified the Hazardous Waste
Collaborative mechanism by providing that electric-generation-related
cleanup costs be included in transition-cost recovery. The effect of
this decision is that the Company's costs of compliance with
environmental regulations may not be fully recoverable.
Nuclear Insurance
SDG&E and the co-owners of SONGS have purchased primary insurance of
$200 million, the maximum amount available, for public-liability
claims. An additional $9.3 billion of coverage is provided by
secondary financial protection required by the Nuclear Regulatory
Commission and provides for loss sharing among utilities owning
nuclear reactors if a costly accident occurs. SDG&E could be assessed
retrospective premium adjustments of up to $36 million in the event of
a nuclear incident involving any of the licensed, commercial reactors
in the United States, if the amount of the loss exceeds $200 million.
In the event the public-liability limit stated above is insufficient,
the Price-Anderson Act provides for Congress to enact further revenue-
raising measures to pay claims, which could include an additional
assessment on all licensed reactor operators.
Insurance coverage is provided for up to $2.8 billion of property
damage and decontamination liability. Coverage is also provided for
the cost of replacement power, which includes indemnity payments for
up to three years, after a waiting period of 12 weeks. Coverage is
provided primarily through mutual insurance companies owned by
utilities with nuclear facilities. If losses at any of the nuclear
facilities covered by the risk-sharing arrangements were to exceed the
accumulated funds available from these insurance programs, SDG&E could
be assessed retrospective premium adjustments of up to $4 million.
Department of Energy Decommissioning
The Energy Policy Act of 1992 established a fund for the
decontamination and decommissioning of the Department of Energy (DOE)
nuclear fuel enrichment facilities. Utilities which have used DOE
enrichment services are being assessed a total of $2.3 billion,
subject to adjustment for inflation, over a 15-year period ending in
2006. Each utility's share is based on its share of enrichment
services purchased from the DOE through 1992. SDG&E's annual
assessment is approximately $1 million. This assessment is recovered
through SONGS revenue.
Department of Energy Nuclear Fuel Disposal
The Nuclear Waste Policy Act of 1982 made the DOE responsible for the
57
disposal of spent nuclear fuel. However, it is uncertain when the DOE
will begin accepting spent nuclear fuel from SONGS. Continued delays
by the DOE can lead to increased cost of disposal, which could be
significant. If this occurs and the Company is unable to recover the
increased costs from the federal government or from its customers, the
Company's profitability from SONGS would be adversely affected.
Litigation
A recent lawsuit, which seeks class-action certification, alleges that
Sempra Energy, SoCalGas, SDG&E and El Paso Energy Corp. acted to drive
up the price of natural gas for Californians by agreeing to stop a
pipeline project that would have brought new and cheaper natural gas
supplies into California. The Company believes the allegations are
without merit.
Except for the matters referred to above, the Company is not
party to, nor is its property the subject of, any material pending
legal proceedings other than routine litigation incidental to their
businesses. Management believes that these matters will not have a
material adverse effect on the Company's results of operations,
financial condition or liquidity.
Electric Distribution System Conversion
Under a CPUC-mandated program and through franchise agreements with
various cities, SDG&E is committed, in varying amounts, to converting
overhead distribution facilities to underground. As of December 31,
2000, the aggregate unexpended amount of this commitment was
approximately $100 million. Capital expenditures for underground
conversions were $26 million in 2000, $20 million in 1999 and $17
million in 1998.
Concentration of Credit Risk
SDG&E maintains credit policies and systems to minimize overall credit
risk. These policies include, when applicable, the use of an
evaluation of potential counterparties' financial condition and an
assignment of credit limits. These credit limits are established based
on risk and return considerations under terms customarily available in
the industry.
SDG&E grants credit to its utility customers, substantially all
of whom are located in SDG&E's service territory, which covers all of
San Diego County and an adjacent portion of Orange County.
Supply/demand imbalances have caused a significant increase in
the price of electricity and, although there is currently a temporary
ceiling on the cost of electricity that SDG&E may pass on to its
customers, once SDG&E is able to pass on these costs, the Company may
experience an increase in customer credit risk. Additional information
on this issue is discussed in Note 12.
NOTE 12: REGULATORY MATTERS
Electric Industry Restructuring
In 1996, California enacted legislation (AB 1890) restructuring
California's investor-owned electric utility industry. The legislation
and related decisions of the CPUC were intended to stimulate
competition and reduce electric rates.
As part of the framework for a competitive electric generation
58
market, the legislation established the California Power Exchange
(PX). The PX served as a wholesale power pool to which the California
investor-owned utilities (IOUs) were required to sell all of their
power supply (including owned generation and purchased-power
contracts) and, except to the extent otherwise authorized by the CPUC,
from which they were required to buy all of the electricity needed to
serve their retail consumers. The PX also purchased power from
nonutility generators through an auction process intended to establish
competitive market prices for the power that it sells to the IOUs.
The restructuring legislation also established a rate freeze on
amounts that the IOUs could charge their customers. The rate freeze
was designed to generate revenue levels assumed to be sufficient to
provide the IOUs with a reasonable opportunity to recover, by December
31, 2001, their costs of generation and purchased power that are fixed
and unavoidable and included in customer rates. Certain costs such as
those related to purchased-power contracts (including those with
qualifying facilities) may be recovered beyond December 31, 2001. The
rate freeze was to end as to each utility when it completed recovery
of the costs, but in no event later than March 31, 2002.
In June 1999, SDG&E completed the recovery of its stranded costs,
other than the future above-market portion of its purchased-power
contracts that were in effect at December 31, 1995, and SONGS costs,
both of which will continue to be collected in rates. Recovery of the
other costs was effected by, among other things, the sale of SDG&E's
fossil power plants and combustion turbines during the quarter ended
June 30, 1999. Therefore, SDG&E is no longer subject to the rate
freeze imposed by the AB 1890.
With the rate freeze no longer applicable, SDG&E lowered its base
rates (the portion of its rates not attributable to electric-commodity
costs) and began to pass through to its customers, without markup, the
cost of electricity purchased from the PX. SDG&E's overall rates were
lower than during the rate freeze, but they also became subject to
fluctuation with the actual cost of electricity purchases.
A number of factors, including supply/demand imbalances, resulted
in abnormally high electric-commodity prices beginning in mid-2000,
which caused SDG&E's monthly customer bills to be substantially higher
than normal. These conditions and the resultant abnormally high
electric-commodity prices continued into 2001. During the second half
of 2000, the average electric-commodity cost was 15.51 cents/kWh
(compared to 4.15 cents/kWh in the second half of 1999). In December
2000, the average was 17.91 cents/kWh (compared to 3.73 cents/kWh in
December 1999).
These higher prices were initially passed through to SDG&E's
customers and resulted in customer bills that in most cases were
double or triple those from the prior year. This resulted in
legislative and regulatory responses.
California Assembly Bill 265 (AB 265), enacted in September 2000,
imposes a ceiling of 6.5 cents/kWh on the cost of the electric-
commodity that SDG&E may pass on to its small-usage customers on a
current basis. Customers covered under the commodity rate ceiling
generally include residential, small-commercial and lighting
customers. This is a "floating cap" that can float downward as prices
decrease, but cannot exceed actual commodity costs without the
permission of the CPUC. The ceiling, retroactive to June 1, 2000,
extends through December 31, 2002, and may be extended through
December 31, 2003, if the CPUC determines that it is in the public
interest to do so. The legislation also provides for the future
recovery of undercollections (the cost of electricity purchased by
SDG&E that cannot be passed on to customers on a current basis)
resulting from the reasonable and prudent costs of procuring the
59
commodity. In accordance with AB 265, the CPUC is examining the
prudence and reasonableness of SDG&E's procurement of wholesale energy
on behalf of its customers for the period July 1999 through August
2000. A decision is expected in the third quarter of 2001. Based upon
historical experience with the CPUC, SDG&E recorded a $50 million
pretax charge during the third quarter of 2000 related to the recent
legislative and regulatory actions associated with power acquisition
costs.
SDG&E accumulates the amount that it pays for electricity in
excess of the rate ceiling (the undercollected costs) in an interest-
bearing balancing account. SDG&E expects to amortize these amounts,
together with interest, in rates charged to customers following the
end of the ceiling period. Due to their long-term nature, these
undercollected costs are classified as a noncurrent regulatory asset
on the Company's Consolidated Balance Sheets. The undercollection was
$447 million at December 31, 2000 and $605 million at January 31,
2001. The rate ceiling materially and adversely affects the timing of
SDG&E's revenue collections and related cash flows. The rate at which
the undercollected costs accumulate will depend primarily upon the
effects of the recently enacted AB 1 discussed under "Purchased-Power
Contracts" in Note 11 and below under "Recent State of California
Actions," and other legislative and regulatory developments, wholesale
prices for electric power and, to a lesser extent, variations in the
volume of electricity used by SDG&E's customers (which is
significantly affected by seasonal and other temperature variations)
and the availability, price and use of longer-term fixed-price
purchase contracts. Because of these and many other factors, the
amount of undercollected costs that will accumulate in future periods
cannot be estimated with any reasonable certainty. However, as
discussed below under "Recent State of California Actions," AB 1 could
end material growth in SDG&E's cost undercollections.
The rate ceiling has materially and adversely affected SDG&E's
revenue collections and its related cash flows and liquidity. SDG&E
has fully drawn upon substantially all of its short-term credit
facilities. Its ability to access the capital markets and obtain
additional financing has been substantially impaired by the financial
distress being experienced by other California IOUs as well as by
lender uncertainties concerning California utility regulation
generally and the rapid growth of utility cost undercollections.
On January 24, 2001, SDG&E filed an application with the CPUC
requesting a temporary 2.3 cents/kWh electric rate surcharge, subject
to refund, beginning March 1, 2001. The surcharge is intended to
provide SDG&E with continued access to financing on commercially
reasonable terms by managing the growth of SDG&E's undercollected
power costs and to provide for the amortization of the
undercollections in customer rates. SDG&E's application also renews a
previous request that the CPUC freeze the commodity rate SDG&E can
charge its customers at 6.5 cents/kWh instead of using that rate as a
ceiling. SDG&E is unable to predict the amount, if any, of the request
that the CPUC would grant, or when it would issue a decision. The CPUC
has deferred this proceeding pending resolution of the broader issues
related to the state-wide high costs.
FERC Actions
On November 1, 2000, the FERC reported its findings from its formal
investigation of the electric rates and structure of the ISO/PX, as
well as of market-based sellers in the California market. The
investigation found no specific abuse of market power by individual
generators and determined that constraints within the market
structure, such as hedging restrictions imposed by the CPUC, and a
60
long-term shortage of power in the state, resulted in the high
electric commodity prices. Federal regulators proposed several
remedies to fix California's flawed market, but stated that past
profits from generators and traders could not be ordered refunded to
customers. The FERC did state that the high short-term energy rates
during the summer of 2000 were "unjust and unreasonable" and left the
door open to future customer refunds should specific instances of
market abuses be uncovered. The report proposed various remedies and
on December 15, 2000, the FERC issued an order adopting these
remedies. Among other things, the order allows the California IOUs to
buy and sell power outside the PX to afford the IOUs more favorable
pricing, to replace the ISO/PX stakeholder governing boards with
independent boards, and to require market buyers to schedule 95
percent of their transactions in the day-ahead markets to reduce the
over-reliance on the real-time market to meet supply.
The order fails to require sellers to enter into forward
contracts at reasonable prices, fails to provide an effective price
cap and does not address issues associated with retroactive refund and
retroactive remedial authority issues. The IOUs have requested a
rehearing, which is pending, of the FERC's decision based on
insufficiency of remedies for the wholesale electric market situation.
In connection with reaction to the FERC order, the PX suspended
its trading operations on January 31, 2001.
PX/ISO Billings
Although it has experienced substantial undercollections of its
costs of purchasing electricity for its customers, SDG&E has
nonetheless remained current in paying for its electricity
purchases as well as its other payment obligations. However, on
February 9, 2001, SDG&E received a "charge-back" billing of $29
million relating to a default by another California utility in
paying for power purchased by the other utility from the ISO.
SDG&E believes the charge-back is improper under applicable
tariffs. SDG&E and other recipients of the charge-back billings have
obtained an order preventing their collection pending the outcome of
litigation contesting the charges.
SDG&E may receive additional charge-back billings in respect to
defaults in electricity purchase payments by other California IOUs in
paying for electricity purchased from the ISO and the PX. It also
expects that it may receive billings for its own purchases of
electricity from the PX that do not reflect proper compliance by the
PX with wholesale price caps ordered by the FERC. These billings are
expected to cease in March 2001, since SDG&E is no longer selling
electricity to the PX. SDG&E will contest all such billings to the
extent that it believes they are inconsistent with applicable tariffs
and orders.
Recent State of California Actions
Federal and California officials met with power generators, marketers
and utility representatives several times in January 2001 to try to
end California's power crisis. The parties conceptually agreed that,
among other things, the state of California would buy electricity
through long-term contracts at reduced rates, which it would resell to
consumers. In order to implement these plans, the California
Legislature passed AB 1, signed by the governor on February 1, 2001,
to allow the DWR to purchase power via long-term contracts for resale
to consumers. The bill authorizes the DWR to enter into long-term
contracts of up to 10 years to purchase power and to sell it to
consumers at not more than the acquisition costs. This authority ends
on December 31, 2002. Repayment will come from utility customers'
61
monthly bills. The bill also authorizes funds from the state's
general fund for immediate power purchases and authorizes the DWR to
issue up to $10 billion in revenue bonds to purchase power. Ratepayers
will pay off these advances and bonds over time. The law also
encourages energy conservation by prohibiting higher rates for
customers that do not exceed 130 percent of a baseline allotment for
energy consumption and setting penalties for businesses that don't
reduce their outside lighting. The first state power auction was held
in January 2001. In early February 2001, the DWR announced agreements
on contracts totaling about 5,000 megawatts and ranging from three
years to 10 years. The state is expected to purchase about one-third
of the electricity used by the IOUs' customers. Also in early February
2001, the CPUC approved emergency regulations for delivery and payment
mechanisms for the sale of electricity procured by the DWR. In an
interim agreement between the DWR and SDG&E, effective February 7,
2001, the DWR is purchasing the entire portion of the power used by
SDG&E customers that is not provided by SONGS or SDG&E's existing
contracts.
SDG&E believes that the DWR's purchase of all of SDG&E's power
needs would end material growth in SDG&E's cost undercollections. To
the extent that the DWR does not purchase all of SDG&E's power needs,
SDG&E may be required to begin again making purchases and to purchase
any shortfall at market prices for resale to its customers at SDG&E's
rate ceiling (which remains unchanged by the legislation) with any
related undercollections continuing to increase SDG&E's total
undercollected costs.
The California Legislature continues to remain in emergency
session to address the California energy crisis. Various legislative
and other proposals that would significantly affect the structure of
California's electric industry, the rates that SDG&E and other IOUs
may charge their customers and the ability of the utilities to
purchase electricity for their customers, and to finance and recover
undercollected costs have been advanced. Among these proposals is that
of the governor that would, among other things, have the state of
California purchase the IOUs' transmission systems for amounts at
least equal to their net book value to provide the IOUs with funds to
mitigate the situation. SDG&E has been having discussions with
representatives of the governor concerning the possibility of such a
transaction and what the terms might be. There is no assurance that
these discussions will result in a sale of the transmission assets.
SDG&E would consider entering into such a transaction only if the
sales price and conditions of the sale and of future operating
arrangements are reasonable.
Credit Ratings
Although the credit ratings of the Company have not changed,
California regulatory uncertainties have led the major credit-rating
agencies to change their rating outlooks on most of the Company's
securities to negative.
Liquidity and Capital Resources
The rate ceiling has materially and adversely affected SDG&E's revenue
collections and its related cash flows and liquidity. SDG&E has fully
drawn upon substantially all of its short-term credit facilities. Its
ability to access the capital markets and obtain additional financing
has been substantially impaired by the financial distress being
experienced by other California IOUs as well as by lender
uncertainties concerning California utility regulation generally and
the rapid growth of utility cost undercollections.
Continued purchases by the DWR for resale to SDG&E's customers of
62
substantially all of the electricity that would otherwise be purchased
by SDG&E or dramatic decreases in wholesale electricity prices,
favorable action by the CPUC on SDG&E's electric-rate-surcharge
application and SDG&E access to the capital markets are required to
manage and finance SDG&E's cost undercollections and provide adequate
liquidity.
Natural Gas
Supply/demand imbalances are affecting the price of natural gas in
California more than in the rest of the country because of
California's dependence on natural gas fired electric generation due
to air-quality considerations. The average price of natural gas at the
California/Arizona (CA/AZ) border was $6.25/mmbtu in 2000, compared
with $2.33/mmbtu in 1999. On December 11, 2000, the average spot cash
gas price at the CA/AZ border reached a record high of $56.91/mmbtu.
Underlying the high natural gas prices are several factors, including
the increase in natural gas throughput for electric generation (a 40-
percent increase in Southern California compared to 1999), colder
winter weather and reduced natural gas supply resulting from
historically low storage levels, lower natural gas production and a
major pipeline rupture. In December 2000, SDG&E filed with the FERC
for a reinstitution of price caps on short-term interstate capacity to
the CA/AZ border and between the interstate pipelines and California's
local distribution companies, effective until March 31, 2001. SDG&E
requested that, if the price of natural gas sold into California
exceeds 150 percent of the national average, the price should be
capped at that level, plus FERC-imposed transportation costs. The FERC
responded by issuing extensive data requests, but has not otherwise
acted on the SDG&E request.
Restructuring of Electric Distribution
Thus far, the CPUC's electric industry restructuring has been confined
to generation. Transmission and distribution have remained subject to
traditional cost-of-service regulation. However, the CPUC is exploring
the possibility of opening up electric distribution to competition. A
CPUC staff report on this issue was submitted to the CPUC in July
2000, with dissenting opinions recommending against changing electric
distribution regulation at this time due to the current state of
electric industry restructuring. A proposed decision is expected in
mid-2001.
Gas Industry Restructuring
The natural gas industry experienced an initial phase of restructuring
during the 1980s by deregulating natural gas sales to noncore
customers. In January 1998, the CPUC released a staff report
initiating a project to assess the current market and regulatory
framework for California's natural gas industry. The general goals of
the plan are to consider reforms to the current regulatory framework
emphasizing market-oriented policies benefiting California's natural
gas consumers.
In July 1999, after hearings, the CPUC issued a decision stating
which natural gas regulatory changes it found most promising,
encouraging parties to submit settlements addressing those changes,
and providing for further hearings if necessary.
In October 1999, the state of California enacted a law (AB 1421)
which requires that natural gas utilities provide "bundled basic gas
service" (including transmission, storage, distribution, purchasing,
revenue-cycle services and after-meter services) to all core
customers, unless the customer chooses to purchase natural gas from a
63
nonutility provider. The law prohibits the CPUC from unbundling most
distribution-related natural gas services (including meter reading)
and after-meter services (including leak investigation, inspecting
customer piping and appliances, pilot relighting and carbon monoxide
investigation) for core customers. The objective is to preserve both
customer safety and customer choice.
Between late 1999 and April 2000, several conflicting settlement
proposals were filed by various groups of parties that addressed the
changes the CPUC found promising in July 1999. The issues in dispute
included, among other things, recovery of the utilities' costs to
implement whatever regulatory changes are adopted. Additional
proposals included improving the access of energy service providers to
sell natural gas supply to core customers of SDG&E.
Hearings were held in mid-2000 and a Proposed Decision (PD) was
released in November 2000. The PD recommends some, but not all, of the
changes proposed by SDG&E. If adopted, the PD is not expected to have
a negative earnings impact on the SDG&E. A CPUC decision is expected
in 2001.
Performance-Based Regulation (PBR)
In recent years, the CPUC has directed utilities to use PBR. To
promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, PBR has replaced
the general rate case and certain other regulatory proceedings for
SDG&E. Under PBR, regulators generally require future income potential
to be tied to achieving or exceeding specific performance and
productivity measures, as well as cost reductions, rather than relying
solely on expanding utility plant in a market where a utility already
has a highly developed infrastructure.
The Company's PBR mechanism is in effect through December 31,
2002, at which time the mechanism will be updated. That update will
include, among other things, a reexamination of the Company's
reasonable costs of operation in 2003 to be allowed in rates. Key
elements of the current mechanism include an annual indexing mechanism
that adjusts customer rates by the inflation rate less a productivity
factor and other adjustments to accommodate major unanticipated
events, a sharing mechanism with customers that applies to earnings
that exceed the authorized rate of return on rate base, rate refunds
to customers if service quality deteriorates or awards if service
quality exceeds set standards, and a change in authorized rate of
return and customer rates if interest rates change by more than a
specified amount. A rate change is triggered by a six-month trailing
average and a 100-basis-point change in interest rates. If this
occurs, there would be an automatic adjustment of rates for the change
in the cost of capital according to a formula which applies a
percentage of the change to various capital components.
Biennial Cost Allocation Proceeding
On April 20, 2000, the CPUC issued a decision on the Company's 1999
BCAP, adopting an overall decrease in natural gas revenues of $37
million for transportation rates effective June 1, 2000. Since the
decrease reflects anticipated changes in corresponding costs, it has
no effect on net income.
Cost of Capital
Electric industry restructuring has changed the method of calculating
the Company's annual cost of capital. In June 1999, the CPUC adopted a
64
10.6 percent return on common equity (ROE) and an 8.75 percent return
on rate base (ROR) for SDG&E's electric distribution and natural gas
businesses. These rates remain in effect for 2000 and 2001. The
electric-transmission cost of capital is determined under a separate
FERC proceeding. SDG&E is required by its last cost of capital
proceeding to file an application on or before May 8, 2001, proposing
revisions to its authorized ROE, ROR and capital structure, to be in
effect for 2002. The application will, among other things, consider
the recent and ongoing financial impacts on SDG&E of electric industry
restructuring.
Integration of Core Gas Purchase Functions
On January 11, 2001, SoCalGas and SDG&E filed an application with the
CPUC to integrate their natural gas purchasing departments. The filing
calls for a single natural gas acquisition group to purchase natural
gas for the two utilities' core gas customers by using their pooled
gas portfolio assets. These assets include storage, interstate
capacity and natural gas supply contracts. The two utilities would
charge their core customers the same natural gas commodity rate from
the diversified portfolio. The change would bring increased efficiency
to the utilities' core gas purchase functions. The filing requests
that this change be effective November 1, 2001. A CPUC decision is not
expected until October 2001.
NOTE 13: SEGMENT INFORMATION
The Company previously had three separately managed reportable
segments: electric transmission and distribution, electric generation,
and natural gas service. Effective with the sale of its fossil fuel
generation facilities in 1999 and other organizational changes, the
Company no longer operates in multiple business segments.
NOTE 14: QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarter ended
-----------------------------------------------------
Dollars in millions March 31 June 30 September 30 December 31
- -------------------------------------------------------------------------------
2000
Operating revenues $ 471 $ 574 $ 731 $ 895
Operating expenses 389 505 698 844
---------------------------------------------------
Operating income $ 82 $ 69 $ 33 $ 51
---------------------------------------------------
Net income $ 54 $ 41 $ 17 $ 39
Dividends on preferred stock 2 1 2 1
---------------------------------------------------
Earnings applicable
to common shares $ 52 $ 40 $ 15 $ 38
===================================================
1999
Operating revenues $ 461 $ 740 $ 520 $ 486
Operating expenses 390 673 438 425
---------------------------------------------------
Operating income $ 71 $ 67 $ 82 $ 61
---------------------------------------------------
Net income $ 55 $ 47 $ 61 $ 36
Dividends on preferred stock 2 1 2 1
---------------------------------------------------
Earnings applicable
to common shares $ 53 $ 46 $ 59 $ 35
===================================================
The sum of the quarterly amounts does not necessarily equal the annual total due
to rounding. Reclassifications have been made to certain of the amounts
since they were presented in the Quarterly Reports on Form 10-Q.
65
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
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 2001 annual meeting of shareholders. The
information required on the Company's executive officers is provided
below.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* Positions
- -------------------------------------------------------------------
Edwin A. Guiles 51 Chairman
Debra L. Reed 44 President and Chief Financial
Officer
Gary D. Cotton 60 Senior Vice President
Steven D. Davis 44 Vice President and Corporate
Secretary
Pamela J. Fair 42 Vice President
* As of December 31, 2000.
Except for Mr. Davis, each Executive Officer has been an officer of
SDG&E or one of its affiliates for more than five years.
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 2001 annual meeting of
shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The information required by Item 12 is incorporated by reference from
"Election of Directors" in the Information Statement prepared for the
May 2001 annual meeting of shareholders.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
66
PART IV
ITEM 14. 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 . . . . . . . . . . . . . . 34
Statements of Consolidated Income for the years
ended December 31, 2000, 1999 and 1998 . . . . . . . . 35
Consolidated Balance Sheets at December 31,
2000 and 1999. . . . . . . . . . . . . . . . . . . . . 36
Statements of Consolidated Cash Flows for the
years ended December 31, 2000, 1999 and 1998 . . . . . 38
Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2000, 1999 and 1998 . . . . . . . . . . . 40
Notes to Consolidated Financial Statements . . . . . . . 41
2. Financial statement schedules
The following documents may be found in this report at the
indicated page numbers:
Independent Auditors' Consent. . . . . . . . . . . . . . 68
Other schedules for which provision is made in Regulation S-X
are not required under the instructions contained therein or
are inapplicable.
3. Exhibits
See Exhibit Index on page 70 of this report.
(b) Reports on Form 8-K
The following reports on Form 8-K were filed after September 30,
2000:
Current Report on Form 8-K filed December 5, 2000, announcing
distribution of a Preliminary Prospectus Supplement related to the
offering of $300 million of notes by Sempra Energy and including an
exhibit entitled "Recent Developments," excerpted from the preliminary
prospectus, related to California electric industry restructuring.
Current Report on Form 8-K filed January 24, 2001, announcing SDG&E's
application to the CPUC for authority to implement an electric rate
surcharge, which would increase the rates it may charge its electric
customers.
Current Report on Form 8-K filed February 16, 2001, reporting a
discussion of recent developments affecting SDG&E contained in
supplemental information distributed in connection with the
remarketing from short term to long term of certain unsecured,
variable-rate SDG&E bonds.
67
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement Numbers 33-45599, 33-52834, 333-52150 and 33-49837 of
San Diego Gas and Electric Company on Forms S-3 of our report
dated January 26, 2001 (February 9, 2001 as to Notes 3 and 12) for
the year ended December 31, 2000.
/S/ DELOITTE & TOUCHE LLP
San Diego, California
March 9, 2001
68
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/ Debra L. Reed
---------------------------------.
Debra L. Reed
President and Chief Financial 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:
Debra L. Reed
President,
Chief Financial Officer /s/ Debra L. Reed March 6, 2001
---------------------
Principal Financial Officer:
Debra L. Reed
President,
Chief Financial Officer /s/ Debra L. Reed March 6,2001
---------------------
Principal Accounting Officer:
Debra L. Reed
President,
Chief Financial Officer /s/ Debra L. Reed March 6,2001
---------------------
Directors:
Edwin A. Guiles
Chairman /s/ Edwin A. Guiles March 6,2001
----------------------
Hyla H. Bertea, Director /s/ Hyla H. Bertea March 6,2001
----------------------
Ann L. Burr, Director /s/ Ann L. Burr March 6,2001
----------------------
Herbert L. Carter, Director /s/ Herbert L. Carter March 6,2001
----------------------
Richard A. Collato, Director /s/ Richard A. Collator March 6,2001
-----------------------
Daniel W. Derbes, Director /s/ Daniel W. Derbes March 6,2001
----------------------
Wilford D. Godbold, Jr., Director /s/ Wilford D. Godbold, Jr. March 6,2001
----------------------
William D. Jones, Director /s/ William D. Jones March 6,2001
----------------------
Ralph R. Ocampo, Director /s/ Ralph R. Ocampo March 6,2001
----------------------
William G. Ouchi, Director /s/ William G. Ouchi March 6,2001
----------------------
Richard J. Stegemeier, Director /s/ Richard J. Stegemeier March 6,2001
----------------------
Thomas C. Stickel, Director /s/ Thomas C. Stickel March 6,2001
----------------------
Diana L. Walker, Director /s/ Diana L. Walker March 6,2001
----------------------
69
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 1-11439
(Enova 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 September 1,
1998. (SDG&E 1998 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.)
Exhibit 10 -- Material Contracts
10.01 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.)
10.02 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.)
70
Compensation
10.03 Sempra Energy Deferred Compensation and Excess Savings Plan
effective January 1, 2000 (2000 Sempra Energy Form 10-K
Exhibit 10.07).
10.04 Sempra Energy Supplemental Executive Retirement Plan as amended
and restated effective July 1, 1998 (1998 Sempra Energy Form
10-K Exhibit 10.09).
10.05 Sempra Energy Executive Incentive Plan effective June 1, 1998
(1998 Sempra Energy Form 10-K Exhibit 10.11).
10.06 Sempra Energy Executive Deferred Compensation Agreement
Effective June 1, 1998(1998 Sempra Energy Form 10-K Exhibit
10.12).
10.07 Sempra Energy 1998 Long Term Incentive Plan (Incorporated by
reference from the Registration Statement on Form S-8 Sempra
Energy Registration No. 333-56161 dated June 5, 1998(Exhibit 4.1)).
10.08 Supplemental Executive Retirement Plan restated as of
July 1, 1994 (1994 SDG&E Form 10-K Exhibit 10.14).
Financing
10.09 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).
10.10 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).
10.11 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).
10.12 Loan agreement with City of San Diego in connection with
the issuance of $57.7 million of Industrial Development
Bonds, dated as of June 1, 1995 (June 30, 1995 SDG&E
Form 10-Q Exhibit 10.3).
10.13 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).
10.14 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).
10.15 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).
71
10.16 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).
10.17 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).
10.18 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).
10.19 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).
Nuclear
10.20 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).
10.21 Fuel Lease dated as of September 8, 1983 between SONGS Fuel
Company, as Lessor and San Diego Gas & Electric Company, as
Lessee, and Amendment No. 1 to Fuel Lease, dated September
14, 1984 and Amendment No. 2 to Fuel Lease, dated March 2,
1987 (1992 SDG&E Form 10-K Exhibit 10.11).
10.22 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).
10.23 Amendment No. 1 to the Qualified CPUC Decommissioning Master
Trust Agreement dated September 22, 1994 (see Exhibit 10.21
herein)(1994 SDG&E Form 10-K Exhibit 10.56).
10.24 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 10.22 herein)(1994 SDG&E Form 10-K Exhibit 10.57).
10.25 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 10.22 herein)(1996 Form 10-K Exhibit 10.59).
10.26 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 10.22 herein)(1996 Form 10-K Exhibit 10.60).
72
10.27 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 10.22 herein)(1999 Form 10-K Exhibit 10.26).
10.28 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 10.22 herein)(1999 Form 10-K Exhibit 10.27).
10.29 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).
10.30 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 10.29 herein)(1996 Form 10-K Exhibit 10.62).
10.31 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 10.29 herein)(1996 Form 10-K Exhibit 10.63).
10.32 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 10.29 herein)(1999 Form 10-K Exhibit 10.31).
10.33 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 10.29 herein)(1999 Form 10-K Exhibit 10.32).
10.34 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).
10.35 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).
Natural Gas Transportation and Storage
10.36 Master Services Contract, Schedule J, Transaction Based Storage
Service Agreement dated April 1, 2000 and expiring March 31,
2001 between San Diego Gas & Electric Company and Southern
California Gas Company. (1999 10-K Exhibit 10.35)
10.37 Master Services Contract, Schedule J, Transaction Based Storage
Service Agreement dated April 1, 1999 and expiring March 31,
2000 between San Diego Gas & Electric Company and Southern
California Gas Company. (1998 10-K Exhibit 10.61)
10. 38 Master Services Contract (Intrastate Transmission Service ),
dated July 1, 1998 and expiring July 1, 2000 between San Diego
Gas & Electric Company and Southern California Gas Company.
(1998 10-K Exhibit 10.64)
73
10.39 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).
10.40 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).
10.41 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
10.42 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).
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, 2000, 1999, 1998, 1997 and 1996.
Exhibit 21 - Subsidiaries
21.01 Schedule of Subsidiaries at December 31, 2000.
Exhibit 23 - Independent Auditors' Consent, page 68.
74
GLOSSARY
AB 1 A California Assembly bill authorizing
the California Department of Water Resources
to purchase energy for California consumers.
AB 265 California Assembly Bill imposing a 6.5
cent/kWh electric commodity rate ceiling.
AB 1890 California Assembly Bill - California's
electric restructuring law.
AB 1421 A California Assembly bill requiring that
natural gas utilities provide bundled basic
gas service to certain customers.
AFUDC Allowance for Funds Used During
Construction
BCAP Biennial Cost Allocation Proceeding
Bcf Billion Cubic Feet (of natural gas)
CA/AZ California/Arizona
CEC California Energy Commission
CPUC California Public Utilities Commission
DOE Department of Energy
DTSC Department of Toxic Substances Control
DWR California Department of Water Resources
Edison Southern California Edison Company
EMF Electric and Magnetic Fields
Enova Enova Corporation, the Company's parent
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
Intertie Pacific Intertie
IOUs Investor-Owned Utilities
ISO California Independent System Operator
kWh Kilowatt Hour
75
mmbtu Million British Thermal Units (of natural gas)
mW Megawatt
NRC Nuclear Regulatory Commission
Parent Enova Corporation
PBR Performance-Based Regulation/Ratemaking
PD Proposed Decision
PE Pacific Enterprises, an affiliate of the
Company
PG&E Pacific Gas and Electric Company
PGE Portland General Electric Company
PNM Public Service Company of New Mexico
PRP Potentially Responsible Party
PX California Power Exchange
SAB Staff Accounting Bulletin(SEC)
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
UEG Utility Electric Generation
VaR Value at Risk
WSPP Western Systems Power Pool
76