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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, 1998
--------------------
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 68. Glossary on page 76.
Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of March 26, 1999 was
$22.9 million.
Registrant's common stock outstanding as of March 26, 1999 was
wholly owned by Enova Corporation.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 1999
annual meeting of shareholders are incorporated by reference into
Part III.
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 18
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 18
Item 4. Submission of Matters to a Vote of Security Holders. . 19
Executive Officers of the Registrant . . . . . . . . . 19
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 19
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 20
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 20
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 34
Item 8. Financial Statements and Supplementary Data. . . . . . 35
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 64
PART III
Item 10. Directors and Executive Officers of the Registrant . . 64
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 64
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . 65
Item 13. Certain Relationships and Related Transactions . . . . 65
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 65
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 67
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 68
Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 76
This report includes forward-looking statements within the definition
of Section 27A of the Securities Act of 1933 and Section 21E of the
Securities Exchange Act of 1934. The words "estimates," "believes,"
"expects," "anticipates," "plans" and "intends," variations of such
words, and similar expressions, are intended to identify forward-
looking statements that involve risks and uncertainties which could
cause actual results to differ materially from those anticipated.
These statements are necessarily based upon various assumptions
involving judgments with respect to the future including, among
others, local, regional, national and international economic,
competitive, political and regulatory conditions and developments,
technological developments, capital market conditions, inflation
rates, interest rates, energy markets, weather conditions, business
and regulatory or legal decisions, the pace of deregulation of retail
natural gas and electricity industries, 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. Accordingly, while the Company believes that the
assumptions are reasonable, there can be no assurance that they will
approximate actual experience, or that the expectations will be
realized. Readers are urged to carefully review and consider 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
San Diego Gas & Electric Company (SDG&E or the Company) is an
operating public utility which provides electric and natural gas
service to San Diego County and southern Orange County. SDG&E is the
principal subsidiary of Enova Corporation (Enova). Effective June 26,
1998, Enova and Pacific Enterprises (PE) combined to form Sempra
Energy, a California-based Fortune 500 energy-services company
(PE/Enova Business Combination). Southern California Gas Company
(SoCalGas), the nation's largest natural gas distribution utility, is
the principal subsidiary of PE. Further discussion of SDG&E and the
PE/Enova Business Combination is included in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and in
Note 1 of the "Notes to Consolidated Financial Statements," herein.
GOVERNMENT REGULATION
Local Regulation
SDG&E has separate electric and gas franchises with the 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 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).
State Regulation
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
transmission access, the uniform systems of accounts, rates of
depreciation and electric rates involving sales for resale. The FERC
also regulates the interstate sale and transportation of natural gas.
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 construction and operation of its generating
plants. Discharge permits, San Diego Air Pollution Control District
permits and NRC licenses are the most significant examples. The
licenses and permits may be revoked or modified by the granting
agency if facts develop or events occur that differ significantly
from the facts and projections assumed in granting the approval.
Furthermore, discharge permits and other approvals are granted for a
term less than the expected life of the facility. They require
periodic renewal, which results in continuing regulation by the
granting agency.
Other regulatory matters are described throughout this report.
SOURCES OF REVENUE
(In Millions of Dollars) 1998 1997 1996
- -------------------------------------------------------------------
Revenue by type of customer:
Electric:
Residential $ 637 $ 684 $ 647
Commercial/Industrial 876 948 886
Other 352 137 58
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Total Electric Revenues 1,865 1,769 1,591
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Gas:
Residential 258 241 210
Commercial/Industrial 105 120 101
Utility Electric Generation 21 37 37
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Total Gas Revenues 384 398 348
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PX/ISO Power 500 -- --
--------- --------- ---------
Total Utility Revenues $ 2,749 $ 2,167 $ 1,939
========= ========= =========
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.
NATURAL GAS OPERATIONS
SDG&E distributes natural gas to 721,000 customers in San Diego and
southern Orange counties throughout a 4,100-square-mile service
territory. The Company purchases natural gas for resale to its
customers and for fuel in its generating plants.
Supplies of Natural Gas
The Company buys natural gas primarily from various spot-market
suppliers. It also has natural gas transportation contracts with
pipeline companies, which expire at various dates through 2023.
Most of the natural gas purchased and delivered by the Company is
produced outside of California. These supplies originate in New
Mexico, Oklahoma and Texas and are transported to the SoCalGas
pipeline at the California border by El Paso Natural Gas Company and
by Transwestern Pipeline Company. 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 has four long-term natural gas supply contracts with four
Canadian suppliers. The Company has been in negotiations and
litigation with the suppliers concerning the contracts' terms and
prices. Of the four contracts, three have been settled. Additional
information regarding natural gas contracts is provided in Note 11 of
the "Notes to Consolidated Financial Statements" herein.
During 1998, SDG&E received natural gas from one Canadian supplier
based on terms of the settlement agreement. Natural gas from Canada
is transported to SDG&E's system over Alberta Natural Gas, Pacific
Gas Transmission and Pacific Gas & Electric (PG&E) pipelines.
The following table shows the sources of natural gas deliveries from
1994 through 1998.
Year Ended December 31
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1998 1997 1996 1995 1994
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Gas Purchases (billions of cubic feet) 118 101 97 90 95
Customer-Owned and
Exchange Receipts 19 18 17 17 15
Storage Withdrawal
(Injection) - Net (3) 1 2 (1)
Company Use and
Unaccounted For (2) (1) (1) (1) (2)
------- ------- ------- ------- -------
Net Deliveries 132 119 113 108 107
======= ======= ======= ======= =======
Cost of Gas Purchased
(millions of dollars) $ 318 $ 311 $ 252 $ 188 $ 246
------- ------- ------- ------- -------
Average Cost of Gas Purchased
(Dollars per Thousand Cubic Feet) $2.69 $3.08 $2.59 $2.08 $2.60
======= ======= ======= ======= =======
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. These
supplies were generally purchased at prices significantly below
those of long-term sources of supply.
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 721,000 core customers (694,000 million
residential and 27,000 small commercial and industrial). Noncore
customers consist primarily of utility electric generation (UEG),
wholesale, and large commercial and industrial customers, and total
113.
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.
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.
For 1998, approximately 90 percent of the CPUC-authorized natural
gas margin was allocated to the core customers, with 10 percent
allocated to the noncore customers.
Although revenue from transportation services 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 12,000
new natural gas customers in 1998. This represents a growth rate of
approximately 1.6 percent. The Company expects its growth for 1999
will continue at about the 1998 level.
Demand for natural gas by noncore customers is very sensitive to
the price of alternative competitive fuels. Although the number of
noncore customers in 1998 was only 113, they accounted for
approximately 32 percent of the authorized natural gas revenues and
64 percent of total natural gas volumes. External factors such as
weather, electric deregulation, the increased use of hydro-electric
power, competing pipeline bypass and general economic conditions
can result in significant shifts in this market. Natural gas demand
for the Company's generation plants is also greatly affected by the
price and availability of electricity.
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 Note 11 of the "Notes to Consolidated Financial
Statements" herein.
ELECTRIC OPERATIONS
Resource Planning
In September 1996, California enacted a law restructuring
California's electric-utility industry. The legislation adopted the
December 1995 CPUC policy decision restructuring the industry 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
independent Power Exchange (PX) that serves as a wholesale power
pool allowing all energy producers to participate competitively.
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 electric-industry restructuring, beginning March
31, 1998, the California investor-owned utilities (IOUs) are
obligated to bid their power supply, including owned generation and
purchased-power contracts, into the PX. The IOUs are also obligated
to purchase from the PX the power that they distribute. Based on
generating plants in service and purchased-power contracts
currently in place, at February 28, 1999 the net megawatts (mw) of
electric power available to SDG&E to bid into the PX are as
follows:
Source Net mw
--------------------------------------------------
Gas/oil generating plants 1,641
Combustion turbines 332
Nuclear generating plants 430
Long-term contracts with other utilities 275
Contracts with others 593
-----
Total 3,271
=====
SDG&E reported an all-time record for electricity usage of 3,960 mw
on August 31, 1998. The previous record of 3,668 mw was reached on
September 4, 1997.
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. The sales are subject to regulatory approval and are
expected to close during the first half of 1999.
San Onofre Nuclear Generating Station (SONGS): SDG&E owns 20
percent of the three nuclear units at SONGS (south of San Clemente,
California). The cities of Riverside and Anaheim own a total of 5
percent of SONGS Units 2 and 3. Southern California Edison (Edison)
owns the remaining interests and operates the units.
SONGS 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. SDG&E and Edison filed
a decommissioning plan in November 1994, although final
decommissioning is not scheduled to occur until 2013 when Units 2
and 3 are also decommissioned. However, SDG&E and the other owners
have requested that the CPUC grant authority to begin
decommissioning Unit 1 on January 1, 2000. The unit's spent nuclear
fuel has been removed from the reactor and 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.
SONGS 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 1998 SDG&E spent $14 million on capital modifications and
additions and expects to spend $11 million in 1999. SDG&E deposits
funds in an external trust to provide for the future dismantling
and decontamination of the units.
Additional Information: Additional information concerning SDG&E's
power plants, the SONGS units, nuclear decommissioning and industry
restructuring (including SDG&E's divestiture of its electric
generation assets) is provided immediately below and in
"Environmental Matters" and "Electric Properties," herein, as well
as 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.
Purchased Power: The following table lists contracts with the
various suppliers:
Megawatt
Supplier Period Commitment Source
- -------------------------------------------------------------------
Long-Term Contracts with Other Utilities:
Portland General
Electric (PGE) Through December 2013 75 Coal
Public Service
Company of
New Mexico (PNM) Through April 2001 100 System supply
PacifiCorp Through December 2001 100 System Supply
-----
Total 275
=====
Contracts with Others:
Illinova Power
Marketing Through December 1999 200 System Supply
LG&E Power Marketing Through December 2001 150 System Supply
Applied Energy Through December 2019 102 Cogeneration
Yuma Cogeneration Through June 2024 50 Cogeneration
Goal Line Limited Through December 2025 50 Cogeneration
Partnership
Other (89) Various 41 Cogeneration
------
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. Charges under contracts from PacifiCorp, LG&E and Illinova
are for firm energy only and are based on the amount of energy
received. The prices under these contracts are at market value at
the time the contracts were negotiated. Costs under the remaining
contracts (all with Qualifying Facilities) are based on SDG&E's
avoided cost.
Additional information concerning SDG&E's purchased-power contracts
is described immediately below, and in "Management's Discussion and
Analysis of Financial Condition and Results of Operations" and in
Note 11 of the "Notes to Consolidated Financial Statements" herein.
Power Pools
In 1964 SDG&E, PG&E, and Edison entered into the California Power
Pool Agreement. It provided for the transfer of electrical capacity
and energy by purchase, sale or exchange during emergencies and at
other mutually determined times. Due to electric-industry
restructuring (discussed below) the California Power Pool was
terminated by the FERC in May 1997. However, SDG&E, Edison, PG&E
and the Los Angeles Department of Water and Power will continue to
abide by the provisions of the existing California Statewide
Emergency Plan for sharing capacity and energy in the event of a
severe resource emergency.
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 150 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 target and coordinate delivery of cost-effective
sources of power from outside their service territories through a
centralized exchange of information. Although the extent has not
yet been determined, the status of the WSPP is likely to change due
to industry restructuring and the initiation of the PX and the
Independent System Operator (ISO).
Transmission Arrangements
In addition to interconnections with other California utilities,
SDG&E has firm transmission capabilities for purchased power from
the Northwest, the Southwest and Mexico.
Pacific Intertie: The Pacific Intertie, consisting of AC and DC
transmission lines, enables SDG&E to purchase and receive surplus
coal and hydroelectric power from the Northwest. SDG&E, PG&E,
Edison and others share transmission capacity on the Pacific
Intertie under an agreement that expires in July 2007. SDG&E's
share of the intertie was 266 MW. Due to electric industry
restructuring (see "Transmission Access" below), the operating
rights of SDG&E, Edison and PG&E on the Pacific Intertie have been
transferred to the ISO.
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 and enables SDG&E to import power from the
Southwest. SDG&E's share of the line is 931 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. SDG&E uses these interconnections
for transactions with Comision Federal de Electricidad (CFE),
Mexico's government-owned electric utility.
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 transfer of control by the
California IOUs of their transmission facilities to the ISO.
Beginning on March 31, 1998 the ISO is responsible for the
operation and control of the transmission lines. Additional
information regarding the ISO and transmission access is discussed
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 Kwhr Cents per Kwhr
- -------------------------------------------------------------------
1998 1997 1996 1998 1997 1996
----- ----- ----- ---- ---- ----
Natural gas 17.3% 19.8% 22.8% 3.0 3.3 2.8
Nuclear fuel 11.5 11.8 19.6 0.6 0.6 0.5
Fuel oil 0.1 1.1 2.4 2.2
----- ----- -----
Total generation 28.8 31.7 43.5
Purchased
power - net 26.3 68.3 56.5 3.6 2.8 3.1
ISO/PX 44.9 3.4
----- ----- -----
Total 100.0% 100.0% 100.0%
====== ====== ======
The cost of purchased power includes capacity costs as well as the
costs of fuel. The cost of natural gas includes transportation
costs. The costs of natural gas, nuclear fuel and fuel oil 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. These services and the dates through which they are under
contract are as follows:
Mining and milling of uranium concentrate 2003
Conversion of uranium concentrate to uranium hexafluoride 2003
Enrichment of uranium hexafluoride(1) 2003
Fabrication of fuel assemblies 2003
Storage and disposal of spent fuel(2) --
(1) SDG&E has a contract with Urenco, a British consortium, for
enrichment services through 2003.
(2) Spent fuel is being stored at SONGS, where storage capacity
will be adequate at least through 2006. If necessary,
modifications in fuel-storage technology can be implemented to
provide on-site storage capacity for operation through 2013,
the expiration date of the NRC operating license. The plan of
the U.S. Department of Energy (DOE) is to provide a permanent
storage site for the spent nuclear fuel by 2010.
Pursuant to the Nuclear Waste Policy Act of 1982, SDG&E entered
into a contract with the DOE for spent-fuel disposal. Under the
agreement, the DOE is responsible for the ultimate disposal of
spent fuel. SDG&E is paying a disposal fee of $0.90 per megawatt-
hour of net nuclear generation. Disposal fees average $3 million
per year.
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 discussed
in Note 11 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. Two of the five commissioner positions are
currently vacant. 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 (see below).
Electric Industry Restructuring
In September 1996, California enacted a law restructuring its
electric-utility industry. The legislation adopts the December 1995
CPUC policy decision restructuring the industry to stimulate
competition and reduce rates. Additional information on electric
industry restructuring is discussed 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
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 natural gas customers. Additional information
on natural gas industry restructuring is discussed 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
Previously, earnings fluctuations from changes in the costs of
electric fuel, purchased energy and natural gas, and consumption
levels for electricity and the majority of natural gas were
eliminated by balancing accounts authorized by the CPUC. This is
still the case for most natural gas operations. However, 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 costs and consumption
levels can affect earnings from electric operations. Additional
information on balancing accounts is discussed 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)
To promote efficient operations and improved productivity and to
move away from reasonableness reviews and disallowances, the CPUC
has been directing utilities to use PBR. PBR has replaced the
general rate case and certain other regulatory proceedings for
SDG&E. Under PBR, regulators require future income potential to be
tied to achieving or exceeding specific performance and
productivity measures, as well as cost reductions, rather than
relying solely on expanding utility rate base in a market where a
utility already has a highly developed infrastructure. Additional
information on PBR is discussed 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 natural gas fuel costs and changes
in the cost of natural gas transportation services are determined
in the BCAP. The BCAP adjusts rates to reflect variances in core
customer demand from estimates previously used in establishing core
customer rates. The mechanism substantially eliminates the effect
on core income of variances in core market demand and natural gas
costs. Additional information on the BCAP is discussed 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.
Affiliate Transactions
In December 1997, the CPUC adopted rules establishing uniform
standards of conduct governing the manner in which California
investor-owned utilities conduct business with their affiliates.
The objective of these rules is to ensure that the utilities'
energy affiliates do not gain an unfair advantage over other
competitors in the marketplace and that utility customers do not
subsidize affiliate activities. Additional information on affiliate
transactions is discussed 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. SDG&E is seeking CPUC approval to
establish new, separate rates of return for SDG&E's electric-
distribution and natural gas businesses. A CPUC decision is
expected during the second quarter of 1999. In 1998, SDG&E's
natural gas and electric-distribution operations were authorized to
earn a rate of return on common equity of 11.6 percent and a rate
of return on rate base of 9.35 percent. Additional information on
the utility's cost of capital is discussed 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, including
hazardous substances and air and water quality, are included in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" herein. The following should be read in
conjunction with those discussions.
Hazardous Substances
The utility lawfully disposed of wastes at 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, redevelopment agencies are authorized
to require landowners to cleanup property within their jurisdiction
or, where the landowner or operator of such a facility fails to
complete any corrective action required, applicable environmental
laws may impose an obligation to undertake corrective actions on
the utility and others who disposed of hazardous wastes at the
facility.
The Redevelopment Agency for the City of San Diego has exerted this
authority affecting the Company's Station A facility and adjacent
properties to accommodate a major league ballpark and ancillary
development proposed by the City. During the early 1900s, SDG&E and
its predecessors manufactured gas from coal and oil at the Station
A facility and at two small facilities in Escondido and Oceanside.
Environmental assessments have identified residual by-products from
the gas-manufacturing process and subsurface hydrocarbon
contamination on portions of the Station A site. A risk assessment
has been completed for Station A and demolition was performed
during 1997 at a cost of $1 million. Initial cleanup actions
commenced in 1998, and are expected to be completed in 1999, at an
estimated cost of $5 million. SDG&E is negotiating with the agency
to create a cooperative agreement as a result of which the Station
A cleanup will be performed under the oversight of the San Diego
County Department of Environmental Health, though the agency will
retain its rights to enforce the cleanup in the event SDG&E does
not complete it. Contaminants resulting from the gas-manufacturing
process by-products were assessed at the Escondido and Oceanside
sites. Remediation at the Escondido site has been completed and a
site-closure letter received. Remediation at the Oceanside facility
is in process and the cost is not expected to be significant.
Station B is located in downtown San Diego and was operated as a
steam and electric-generating facility between 1911 and June 1993
when it was closed. Pursuant to a cleanup and abatement order,
SDG&E remediated hydrocarbon contamination discovered as a result
of the removal of three 100,000-gallon underground diesel-fuel
storage tanks from an adjacent substation. Asbestos was used in the
construction of the power plant. Activities to dismantle and
decommission the facility required the removal of the asbestos in a
manner complying with all applicable environmental, health and
safety laws. This work also included the removal or cleanup of
certain loose and flaking lead-based paints, small amounts of PCBs,
fuel oil and other substances. These activities were completed in
1998 at a cost of $6 million.
SDG&E is in the process of selling its electric-generating assets.
As a part of its environmental due diligence, the utility conducted
a thorough environmental assessment of the South Bay and Encina
power plants and 17 combustion turbine sites to determine the
environmental condition of each. Pursuant to the sale agreements
for such facilities, the utility 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 instances of contamination, principally hydrocarbon
releases, some of which were determined to be significant and to
require cleanup in accordance with the agreement. Estimated costs
to perform the necessary remediation are $7 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 will be
offset against the sales price for the facilities, together with
other appropriate costs, and the remaining net proceeds will be
offset against SDG&E's other transition costs.
SDG&E has been named as a potential responsible party (PRP) for an
industrial waste disposal site as described below.
SDG&E and 10 other entities have been named 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 the
utility and others sold used electrical transformers to the site's
owner. The DTSC considers SDG&E to be responsible for 7.4 percent
of the transformer-related contamination at the site. The estimate
for the development of the cleanup plan is $1 million. The estimate
for the actual cleanup is in the $2 million to $8 million range.
At December 31, 1998, the utility's estimated remaining
investigation and remediation liability related to hazardous waste
sites (non-PRP sites) was $15 million, of which 90 percent is
authorized to be recovered through the Hazardous Waste
Collaborative mechanism. SDG&E believes that any costs not
ultimately recovered through rates, insurance or other means, upon
giving effect to previously established liabilities, will not have
a material adverse effect on the Company's consolidated results of
operations or the 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. Possible recoveries
of environmental remediation liabilities from third parties are not
deducted from the liability.
Electric and Magnetic Fields (EMFs)
Although scientists continue to research the possibility that
exposure to EMFs causes adverse health effects, science, to date,
has not demonstrated a cause-and-effect relationship between
adverse health effects and exposure to the type of EMFs emitted by
utilities' 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
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
As mentioned above, SDG&E has entered into agreements for the sale
of its fossil-fueled generating facilities. The completion of these
sales will, for the most part, eliminate the potential impact of
the following issues.
During 1996 and 1997, SDG&E installed equipment on South Bay Unit 1
in order to comply with the nitrogen-oxide-emission limits that the
APCD imposed on electric-generating boilers through its Rule 69.
The estimated capital costs for compliance with the rule have
decreased to an immaterial amount due to the sale of the electric-
generating power plants. The California Air Resources Board has
expressed concern that Rule 69 does not meet the requirements of
the California Clean Air Act and may advocate or propose more
restrictive emissions limitations which will likely cause Rule 69
compliance costs to increase.
Wastewater discharge permits issued by the Regional Water Quality
Control Board (RWQCB) for the utility's Encina and South Bay power
plants are required to enable the utility to discharge its cooling
water and certain other wastewaters into the Pacific Ocean and into
San Diego Bay. Wastewater discharge permits are prerequisite to the
continuation of cooling-water and other wastewater discharges and,
therefore, the continued operation of the power plants as they are
currently configured. Increasingly stringent cooling-water and
wastewater discharge limitations may be imposed in the future and
the utility may be required to build additional facilities or
modify existing facilities to comply with these requirements. Such
facilities could include wastewater treatment facilities, cooling
towers, intake structures or offshore-discharge pipelines. Any
required construction could involve substantial expenditures, and
certain plants or units may be unavailable for electric generation
during construction.
In 1981, SDG&E submitted a demonstration study in support of its
request for two exceptions to certain thermal discharge
requirements imposed by the California Thermal Plan for Encina
power plant Unit 5. In November 1994, the RWQCB issued a new
discharge permit, subject to the results of certain additional
thermal discharge and cooling-water-related studies, to be used to
evaluate the exception requests. The results of these additional
studies were submitted to the RWQCB and the United States
Environmental Protection Agency in 1997. If the utility's exception
requests are denied, the utility could be required to construct
offshore discharge facilities, or other structures at an estimated
cost of $75 million to $100 million or to perform mitigation, the
costs of which may be significant.
In November 1996, the RWQCB issued a new discharge permit to the
utility for the South Bay power plant. SDG&E filed an appeal to the
State Water Resources Control Board (SWRCB) of various provisions,
which the utility considered unduly stringent. Certain of these
matters were resolved in negotiations among the RWQCB, the SWRCB
and certain environmental groups. The SWRCB dismissed the remaining
matters, which SDG&E thereafter appealed to the San Diego County
Superior Court. These latter issues were subsequently settled
through negotiations between SDG&E and the RWQCB. All of the
settled issues have been incorporated into the November 1996
National Pollutant Discharge Elimination System permit by permit
addendums adopted by the RWQCB. The Superior Court case will be
dismissed after the expiration of the RWQCB appeal and EPA review
periods.
California has enacted legislation to protect ground water from
contamination by hazardous substances. Underground storage
containers require permits, inspections and periodic reports, as
well as specific requirements for new tanks, closure of old tanks
and monitoring systems for all tanks. It is expected that cleanup
of sites previously contaminated by underground tanks will occur
for an unknown number of years. SDG&E cannot predict the cost of
such cleanup.
In May 1987 the RWQCB issued SDG&E a cleanup and abatement order
for gasoline contamination originating from an underground storage
tank located at the utility's Mountain Empire Operation and
Maintenance facility. SDG&E assessed the extent of the
contamination, removed all contaminated soil and completed
remediation of the site. Monitoring of the site confirms its
remediation. SDG&E has applied for and is awaiting a site-closure
letter from the RWQCB.
OTHER
Year 2000
A discussion of the Company's plans to prepare its computer systems
and applications for the year 2000 and beyond is included in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" herein.
Research, Development and Demonstration (RD&D)
As a result of electric-industry restructuring, SDG&E has
significantly reduced its electric RD&D program. Effective January
1, 1998, the CEC began administering the electric public purpose
RD&D programs to which SDG&E contributes $3.9 million annually. In
December 1998, the CPUC approved SDG&E's $1.2 million request to
fund natural gas RD&D programs. SDG&E will use these revenues to
fund gas projects that add value to the utility and its customers.
Annual RD&D costs have averaged $5.2 million over the past three
years.
Employees of Registrant
As of December 31, 1998, SDG&E had 2,982 employees, compared to
3,576 at December 31, 1997. This decrease is related to synergies
resulting from the PE/Enova Business Combination and the shifting
of certain functions to Sempra Energy.
Certain employees at SDG&E are represented by the International
Brotherhood of Electrical Workers, Local 465, with two labor
agreements. The generation contract runs through February 28, 2001
and negotiations for the utility contract (transmission and
distribution) are ongoing.
ITEM 2. PROPERTIES
Electric Properties
The utility's generating capacity is described in "Electric
Resources" herein.
SDG&E's electric transmission and distribution facilities include
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, 167 miles of high pressure transmission pipelines, 6,858
miles of high and low pressure distribution mains, and 5,695 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 certain equipment necessary
in the conduct of business.
ITEM 3. LEGAL PROCEEDINGS
Except for the matters referred to in the financial statements in
Item 8 or referred to elsewhere in this Annual Report, neither the
Company nor any of its affiliates is a party to, nor is its
property the subject of, any material pending legal proceedings
other than routine litigation incidental to its businesses.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 4. EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* Positions
- -------------------------------------------------------------------
Warren I. Mitchell 61 Chairman
Edwin A. Guiles 49 President and Chief Financial
Officer
Gary D. Cotton 58 Senior Vice President - Fuels &
Power Operations
Steven D. Davis 42 Vice President and Corporate
Secretary
Pamela J. Fair 40 Vice President - Marketing &
Customer Services
* As of December 31, 1998.
Each Executive Officer has been an officer of Sempra Energy or one
of its subsidiaries for more than five years.
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, 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
The CPUC regulates SDG&E's capital structure, limiting the
dividends it may pay. At December 31, 1998, $183 million of
retained earnings was available for future dividends.
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in millions)
At December 31, or for the years then ended
------------------------------------------------
1998 1997 1996 1995 1994
-------- ------- ------- ------- -------
Income Statement Data:
Operating Revenues $2,749 $2,167 $1,939 $1,814 $1,857
Operating Income $ 286 $ 317 $ 309 $ 315 $ 303
Dividends on Preferred Stock $ 6 $ 6 $ 6 $ 8 $ 8
Earnings Applicable to
Common Shares $ 185 $ 232 $ 216 $ 226 $ 136
Balance Sheet Data:
Total Assets $4,257 $4,654 $4,161 $4,473 $4,353
Long-Term Debt $1,548 $1,788 $1,285 $1,217 $1,214
Short-Term Debt (a) $ 72 $ 73 $ 34 $ 124 $ 182
Shareholders' Equity $1,227 $1,490 $1,508 $1,639 $1,593
(a) Includes bank and other notes payable, commercial paper borrowings and 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 notes to consolidated financial statements contained herein.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Introduction
This section includes management's analysis of operating results
from 1996 through 1998, and is intended to provide additional
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 Orange County, California.
It also purchases and distributes natural gas to 721,000 customers
in San Diego County and transports electricity and gas for others.
SDG&E's only subsidiary is described below under "Electric Rates."
Business Combinations
Sempra Energy (Sempra) was formed to serve as a holding company for
SDG&E's parent, Enova Corporation (Enova), and Pacific Enterprises
(PE), the parent company of Southern California Gas Company
(SoCalGas) in connection with a business combination that became
effective on June 26, 1998 (the PE/Enova Business Combination).
Expenses incurred by SDG&E in connection with the business
combination are $35 million, aftertax, and $11 million, aftertax,
for the years ended December 31, 1998 and 1997, respectively. These
costs consist primarily of employee-related costs, and investment
banking, legal, regulatory and consulting fees.
In connection with the PE/Enova Business Combination, the
holders of common stock of Enova and PE each became holders of
Sempra Energy common stock. PE's common shareholders received
1.5038 shares of Sempra Energy's common stock for each share of PE
common stock, and Enova's common shareholders received one share of
Sempra Energy's common stock for each share of Enova common stock.
The combination was approved by the shareholders of both companies
on March 11, 1997 and was a tax-free transaction.
Capital Resources and Liquidity
The Company's working capital requirements are met through cash
from operations and the issuance of short-term and long-term debt.
Additional information on sources and uses of cash during the
last three years is summarized in the following condensed statement
of cash flows:
Sources and (Uses) of Cash
Year Ended December 31,
(Dollars in millions) 1998 1997 1996
- -------------------------------------------------------------------
Operating activities $ 535 $ 381 $ 529
----------------------------------
Investing activities:
Capital expenditures (227) (197) (209)
Other - net (50) (17) (25)
----------------------------------
Total investing activities (277) (214) (234)
----------------------------------
Financing activities:
Dividends paid (269) (256) (189)
Long-term debt - net (241) 544 (31)
Redemption of preferred stock -- -- (15)
----------------------------------
Total financing activities (510) 288 (235)
----------------------------------
Increase (decrease) in cash
and cash equivalents $(252) $ 455 $ 60
- -------------------------------------------------------------------
Cash Flows from Operating Activities
The increase in cash flows from operating activities in 1998 was
primarily due to the acceleration of depreciation of electric-
generating assets, partially offset by recovery of stranded costs
via the competition transition charge and the 10-percent rate
reduction reflected in customers' bills. The increase was also
partially offset by expenses incurred in connection with the
PE/Enova Business Combination.
The decrease in cash flows from operating activities in 1997
was primarily due to increased working capital requirements.
Cash Flows from Investing Activities
Capital expenditures were $30 million higher in 1998 than in 1997
due to increased spending for system integrity and reliability
projects, restoration of service and mandated programs.
Capital expenditures were $12 million lower in 1997 than in
1996 due to changes in scope and timing of several major capital
projects.
Payments to the nuclear-decommissioning trusts are expected to
continue until San Onofre Nuclear Generating Station (SONGS) is
decommissioned, which is not expected to occur before 2013. Unit
1, although permanently shut down in 1992, was scheduled to be
decommissioned concurrently with Units 2 and 3. However, the
Company and the other SONGS owners have requested the CPUC for
authority to begin decommissioning Unit 1 on January 1, 2000. See
Note 5 of the notes to Consolidated Financial Statements for
additional information.
The decision of the CPUC approving the PE/Enova Business
Combination required, among other things, that SDG&E divest itself
of all its fossil-fueled generating facilities. In December 1998,
SDG&E entered into agreements to accomplish that. Completion is
pending regulatory approval and is expected during the first half
of 1999. See "Electric-Generation Assets" below for further
discussion. Anticipated proceeds from these plant assets, net of
the assets' book value, the costs of sales and certain
environmental cleanup costs, will be applied for accounting
purposes directly to the recovery of the Company's other transition
costs. On a cash basis, the proceeds will be available for general
corporate purposes. However, the divestiture of the facilities
will eventually lead to reduced cash flow from operations.
Capital expenditures are estimated to be $240 million in 1999.
They will be financed primarily by internally generated funds and
will largely represent investment in rate base. The level of
capital expenditures in the next few years will depend heavily on
the impacts of electric-industry restructuring and the timing and
extent of expenditures to comply with environmental requirements.
Cash Flows from Financing Activities
Net cash used in financing activities increased in 1998 due to the
issuance of Rate Reduction Bonds in 1997 (see "Long-Term Debt"
below) and greater long-term debt repayments in 1998.
Net cash provided by financing activities increased in 1997
primarily due to issuance of the Rate Reduction Bonds partially
offset by higher dividends paid.
Long-Term Debt
In December 1997, $658 million of Rate Reduction Bonds were issued
on the Company's behalf at an average interest rate of 6.26
percent. A portion of the bond proceeds was used to retire
variable-rate, taxable IDBs. Additional information concerning the
Rate Reduction Bonds is provided below under "Electric Industry
Restructuring." In 1998, cash was used for the repayment of $147
million of first mortgage bonds and $66 million of rate reduction
bonds.
In 1997, cash was used for the repayment of $127 million of
first mortgage bonds. This was more than offset by the issuance of
$25 million in Medium-Term Notes and $658 million of Rate Reduction
Bonds.
SDG&E has $83 million of temporary investments that will be
maintained into the future to offset, for regulatory purposes, a
like amount of long-term debt. The specific debt series being
offset consist of variable-rate IDBs. The CPUC has approved
specific ratemaking treatment, which allows SDG&E to offset IDBs as
long as there is at least a like amount of temporary investments.
If and when SDG&E requires all or a portion of the $83 million of
IDBs to meet future needs for long-term debt, such as to finance
new construction, the amount of investments which are being
maintained will be reduced below $83 million and the level of IDBs
being offset will be reduced by the same amount.
Dividends
Common stock dividends amounted to $269 million, $256 million and
$189 million in 1998, 1997 and 1996, respectively.
The payment of future dividends and the amount thereof are
within the discretion of the board of directors.
Capitalization
The debt-to-capitalization ratio was 57 percent at year-end 1998,
above the 56 percent ratio in 1997. The increase was primarily due
to the declaration of dividends to Enova. The debt-to-
capitalization ratio increase to 56 percent in 1997 from 48 percent
in 1996 was primarily due to the issuance of Rate Reduction Bonds.
Cash and Temporary Investments
Cash and temporary investments were $284 million at December 31,
1998. The Company anticipates that cash required in 1999 for
capital expenditures, dividends and debt payments will be provided
by cash generated from operating activities and existing cash
balances.
In addition to cash from ongoing operations, the Company has
multi-year credit agreements that permit term borrowing of up to
$295 million. At December 31, 1998 all bank lines of credit were
unused. For further discussion, see Note 3 of the notes to
Consolidated Financial statements.
Ratemaking Procedures
To understand the operations and financial results of the Company
it is important to understand the ratemaking procedures that the
Company follows.
The Company is regulated by the CPUC. It is the responsibility
of the CPUC to determine that utilities operate in the best
interest of their customers and have the opportunity to earn a
reasonable return on investment. In response to utility-industry
restructuring, SDG&E received approval from the CPUC for
performance-based regulation (PBR).
PBR replaced the general rate case (GRC) procedure and certain
other regulatory proceedings. Under ratemaking procedures in
effect prior to PBR, the Company typically filed a GRC with the
CPUC every three years. In a GRC, the CPUC establishes a base
margin, which is the amount of revenue to be collected from
customers to recover authorized operating expenses (other than the
cost of fuel, natural gas and purchased power), depreciation, taxes
and return on rate base.
Under PBR, regulators allow income potential to be tied to
achieving or exceeding specific performance and productivity
measures, rather than relying solely on expanding utility rate base
in a market where a utility already has a highly developed
infrastructure. See additional discussion of PBR and electric-
industry restructuring in Note 12 of the notes to Consolidated
Financial Statements.
Results of Operations
1998 Compared to 1997
Net income for 1998 decreased 20 percent to $191 million in 1998,
compared to net income of $238 million in 1997. The decrease in net
income was primarily due to higher PE/Enova Business Combination
costs, lower incentive awards for performance-based ratemaking, and
changes in regulatory mechanisms for recording revenues due to
electric industry restructuring. Included in the calculation of
pretax income are PE/Enova Business Combination costs of $35
million, aftertax, in 1998 and $11 million, aftertax, in 1997.
These nonrecurring expenses consist primarily of employee-related
costs, and investment banking, legal, regulatory and consulting
fees.
Electric revenues increased 5 percent in 1998 compared to 1997
primarily due to the recovery of stranded costs via the competition
transition charge (CTC), and to alternate costs incurred (including
fuel and purchased power) due to the delay from January 1 to March
31, 1998, in the startup of operations of the Power Exchange (PX)
and the Independent System Operator (ISO). These factors were
partially offset by a decrease in retail revenues as a result of
the 10-percent small-customer rate reduction, which became
effective in January 1998, and by a decrease in sales to other
utilities, due to the startup of the PX. The 10-percent rate
reduction and the PX are described under "Factors Influencing
Future Performance" and in Note 12 of the notes to Consolidated
Financial Statements.
Revenues from the ISO/PX reflect sales from the Company's power
plants and from long-term purchased-power contracts to the ISO/PX
commencing April 1, 1998.
Purchased power decreased 34 percent in 1998 primarily as a
result of ISO/PX purchases' replacing short-term energy sources
commencing April 1, 1998.
Depreciation and amortization expense increased 86 percent in
1998 due to the recovery of stranded costs via the CTC. The
financial impact of the increase is offset by CTC revenue (see
above).
Operating expenses increased 32 percent in 1998 primarily due
to the higher PE/Enova Business Combination costs and higher
electric-distribution maintenance costs primarily related to the
Company's tree-trimming program.
1997 Compared to 1996
Net income for 1997 increased 7 percent to $238 million compared to
net income of $222 million in 1996. The increase in earnings was
primarily due to higher incentive awards for performance-based
ratemaking and demand-side management, partially offset by the
PE/Enova Business Combination costs.
Electric revenues increased 11 percent in 1997, primarily due
to an increase in sales for resale to other utilities and increased
retail sales volume due to weather.
Purchased power increased 42 percent in 1997, primarily due to
increased volume, which resulted from lower nuclear-generation
availability due to refuelings at SONGS and increased use of
purchased power due to decreased purchased-power prices.
The table below summarizes the components of electric
volumes and revenues by customer class for 1998, 1997 and 1996.
Electric Distribution
(Dollars in millions, volumes in millions of Kwhrs)
1998 1997 1996
----------------------------------------------------------
Volumes Revenue Volumes Revenue Volumes Revenue
----------------------------------------------------------
Residential 6,282 $ 637 6,125 $ 684 5,936 $ 647
Commercial 6,821 643 6,940 680 6,467 625
Industrial 3,097 233 3,607 268 3,567 261
Direct access 964 44 - - - -
Street and highway lighting 85 8 76 7 75 7
Off-system sales 706 15 4,919 116 650 13
----------------------------------------------------------
17,955 1,580 21,667 1,755 16,695 1,553
Balancing and other 285 14 38
----------------------------------------------------------
Total 17,955 $1,865 21,667 $1,769 16,695 $1,591
----------------------------------------------------------
Factors Influencing Future Performance
Performance of the Company in the near future will depend primarily
on the ratemaking and regulatory process, electric- and natural
gas-industry restructuring, and the changing energy marketplace.
These factors are summarized below.
KN Energy Acquisition. On February 22, 1999, Sempra Energy
announced a definitive agreement to acquire KN Energy, Inc.,
subject to approval by the shareholders of both companies and by
various regulatory agencies. See Note 14 of the notes to
Consolidated Financial Statements for additional information.
Electric Industry Restructuring. As discussed above, in September
1996, California enacted a law restructuring California's electric-
utility industry (AB 1890). Consumers now have 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 PX that serves as a wholesale power pool allowing all energy
producers to participate competitively. The local utility continues
to provide distribution service regardless of which source the
consumer chooses. See Note 12 of the notes to Consolidated
Financial Statements for additional information.
Transition Costs. AB 1890 allows utilities, within certain limits,
the opportunity to recover their stranded costs incurred for
certain above-market CPUC-approved facilities, contracts and
obligations through the establishment of the CTC.
Utilities are allowed a reasonable opportunity to recover their
stranded costs through December 31, 2001. Stranded costs include
sunk costs, as well as ongoing costs the CPUC finds reasonable and
necessary to maintain generation facilities through December 31,
2001. These costs also include other items SDG&E has accrued under
cost-of-service regulation.
Through December 31, 1998, SDG&E has recovered transition
costs of $500 million for nuclear generation and $200 million for
non-nuclear generation. Excluding the costs of purchased power and
other costs whose recovery is not limited to the pre-2002 period,
the balance of the Company's stranded assets at December 31, 1998
is $600 million, consisting of $400 million for the power plants
and $200 million of related deferred taxes and undercollections.
During the 1998 - 2001 period, recovery of transition costs is
limited by a rate cap. See Note 12 of the notes to Consolidated
Financial Statements for additional information.
Electric Generation Assets. In November 1997, the Company adopted a
plan to auction its power plants and other electric-generating
assets so that it could continue to concentrate its business on the
transmission and distribution of electricity and natural gas as
California opens its electric-utility industry to competition. The
plan included the divestiture of the Company's fossil power plants
and combustion turbines, its 20-percent interest in SONGS and its
portfolio of long-term purchased-power contracts. The power plants,
including the interest in SONGS, have a net book value as of
December 31, 1998, of $400 million ($100 million for fossil and
$300 million for SONGS).
In March 1998, the CPUC's decision approving the PE/Enova
Business Combination required, among other things, the divestiture
by the Company of its fossil-fueled generation units. On December
11, 1998, the Company entered into agreements for the sale of the
Company's South Bay and Encina Power Plants and 17 combustion-
turbine generators. The sales are subject to regulatory approval
and are expected to close during the first half of 1999. See Note
12 of the notes to Consolidated Financial Statements for additional
information.
Electric Rates. AB 1890 provides for a 10-percent reduction of
residential and small commercial customers effective January 1998,
and provided for the issuance of rate-reduction bonds by an agency
of the State of California to enable the investor-owned utilities
(IOUs) to achieve this rate reduction. 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 are being
repaid over 10 years by the Company's residential and small-
commercial customers via a nonbypassable charge on their
electricity bills. In September 1997, SDG&E and the other
California IOUs received a favorable ruling by the Internal Revenue
Service on the tax treatment of the bond transaction. The ruling
states, among other things, that the receipt of the bond proceeds
does not result in gross income to the Company at the time of
issuance, but rather the proceeds are taxable over the life of the
bonds. The Securities and Exchange Commission determined that these
bonds should be reflected on the utilities' balance sheets as debt,
even though the bonds are not secured by, or payable from, utility
assets, but rather by the revenue streams collected from customers.
SDG&E formed a subsidiary, SDG&E Funding LLC, to facilitate the
issuance of the rate-reduction bonds. In exchange for the bond
proceeds, the Company sold to SDG&E Funding LLC all of its rights
to the revenue streams. Consequently, the revenue streams are not
the property of the Company and are not available to creditors of
the Company.
AB 1890 also included a rate freeze for all customers. Until
the earlier of March 31, 2002, or when transition cost recovery is
complete, the Company's average system rate will be frozen at 9.64
cents per kilowatt-hour (kwh), except for the impacts of fuel-cost
changes and the 10-percent rate reduction described above.
Beginning in 1998, system-average rates were fixed at 9.43 cents
per kwh, which includes the maximum permitted increase related to
fuel-cost increases and the mandatory rate reduction. The Company's
ability to recover its transition costs is dependent on its total
revenues under the rate freeze exceeding traditional cost-of-
service revenues during the transition period by at least the
amount of the CTC less the net proceeds from the sale of electric-
generating assets. During the transition period, SDG&E will not
earn awards from special programs, such as Demand-Side Management,
unless total revenues are also adequate to cover the awards. Fuel-
price volatility is one of the more significant uncertainties in
the ability of SDG&E to recover its transition costs and program
awards.
In early 1999, the Company filed with the CPUC for an interim
mechanism to deal with electric rates after the rate freeze ends,
noting the possibility that the SDG&E rate freeze could end in
1999.
Performance-Based Regulation. As discussed above under PBR,
regulators allow future income potential to be tied to achieving or
exceeding specific performance and productivity measures, as well
as cost reductions, rather than by relying solely on expanding
utility rate base. See additional discussion of PBR in Note 12 of
the notes to Consolidated Financial Statements.
Regulatory Accounting Standards. The Company is accounting for the
economic effects of regulation on its utility operations, except
for electric generation, in accordance with Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation." Under SFAS No. 71, a regulated entity
records a regulatory asset if it is probable that, through the
ratemaking process, the utility will recover the asset from
customers. Regulatory liabilities represent future reductions in
revenues for amounts due to customers. See Notes 2 and 12 of the
notes to Consolidated Financial Statements for additional
information.
Affiliate Transactions. On December 16, 1997, the CPUC adopted
rules establishing uniform standards of conduct governing the
manner in which California IOUs conduct business with their
affiliates. The objective of these rules, effective January 1,
1998, is to ensure that the Company's energy affiliates do not gain
an unfair advantage over other competitors in the marketplace and
that utility customers do not subsidize affiliate activities.
The CPUC excluded utility-to-utility transactions between the
Company and SoCalGas from the affiliate-transaction rules in its
March 1998 decision approving the PE/Enova Business Combination. As
a result, the affiliate-transaction rules will not substantially
impact the Company's ability to achieve anticipated synergy
savings. See Notes 1 and 12 of the notes to Consolidated Financial
Statements for additional information.
Allowed Rate of Return. For 1998, SDG&E was authorized to earn a
rate of return on rate base of 9.35 percent and a rate of return on
common equity of 11.6 percent, unchanged from 1997. See additional
discussion in Note 12 of the notes to Consolidated Financial
statements.
Management Control of Expenses and Investment. In the past,
management has been able to control operating expenses and capital
investment within the amounts authorized to be collected in rates.
It is the intent of management to control operating expenses and
capital investments within the amounts authorized to be collected
in rates in the PBR decision. The Company intends to make the
efficiency improvements, changes in operations and cost reductions
necessary to achieve this objective and earn its authorized rate of
return. However, in view of the earnings-sharing mechanism and
other elements of the PBR, it is more difficult to achieve returns
at least at or in excess of authorized returns at levels
experienced in past years. See additional discussion of PBR in Note
12 of the notes to Consolidated Financial Statements.
Environmental Matters
The Company's operations are conducted in accordance with
applicable federal, state and local environmental laws and
regulations governing such things as hazardous wastes, air and
water quality, and the protection of wildlife.
These costs of compliance are normally recovered in customer
rates. Whereas it is anticipated that the environmental costs
associated with natural gas operations and with electric
transmission and generation operations will continue to be
recoverable in rates, the restructuring of the California electric-
utility industry, described above under "Electric Industry
Restructuring," will change the way utility rates are set and costs
associated with electric generation are recovered. Capital costs
related to environmental regulatory compliance for electric
generation are intended to be included in transition costs for
recovery through 2001. However, depending on the final outcome of
industry restructuring and the impact of competition, the costs of
future compliance with environmental regulations may not be fully
recoverable.
Capital expenditures to comply with environmental laws and
regulations were $1 million in 1998, $4 million in 1997 and $6
million in 1996, and are not expected to be significant during the
next five years. These projected expenditures primarily consist of
the estimated cost of reducing air emissions by retrofitting power
plants. This estimate anticipates that SDG&E completes the planned
sale of its fossil-fueled power plants during the first half of
1999. Additional information on the Company's divestiture of its
electric generating assets is discussed above under "Electric
Generation Assets" and in Note 12 of the notes to Consolidated
Financial Statements.
Hazardous Substances. In 1994, the CPUC approved the Hazardous
Waste Collaborative, a mechanism which allows the Company and other
utilities to recover, through rates, 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 through rates. 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 CTC recovery process described above.
During the early 1900s, the Company and its predecessors
manufactured gas from coal or oil, the sites of which have often
become contaminated with the hazardous residual by-products of the
process. The Company has identified three former manufactured gas
plant sites. One of these sites has been remediated and a site-
closure letter has been received from the San Diego County
Department of Environmental Health. An environmental site
assessment has been conducted and the estimated cost to remediate
the other two sites is $6 million. Ninety percent of the Company's
costs to clean up the gas plants and to meet their PRP obligations,
a total estimated to be $15 million, is recoverable through the
Hazardous Waste Collaborative mechanism.
As a part of its sale of the South Bay and Encina power plants
and 17 combustion turbines (described above), the Company retained
limited remediation obligations for contamination existing on these
sites upon the closing of the sales. The Company's costs to perform
its remediation obligations as a part of such sales is estimated to
be $10 million. These costs are eligible for inclusion in the CTC
recovery process.
Air and Water Quality. California's air quality standards are more
restrictive than federal standards. However, due to the sale of the
electric-generating power plants, the Company's primary air-quality
issue, compliance with these standards will be less significant in
the future.
In connection with the issuance of operating permits, the
Company 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 marine fish hatchery programs and pay for monitoring and
oversight of the mitigation projects. The Company's share of the
cost is estimated to be $23 million. The pricing structure
contained in the CPUC's decision regarding accelerated recovery of
SONGS Units 2 and 3 costs is expected to accommodate most of these
added mitigation costs.
The environmental laws and regulations regarding natural gas
affect the operations of customers as well as the Company's
regulated natural gas operations. Increasingly complex
administrative and reporting requirements of environmental agencies
applicable to commercial and industrial customers utilizing natural
gas are not generally required of those using electricity. However,
anticipated advancements in natural gas technologies are expected
to enable natural gas equipment to remain competitive with
alternate energy sources.
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.
Other Income, Interest Expense and Income Taxes
Other Income
Other income, which primarily consists of interest income from
short-term investments and regulatory accounts receivable balances,
increased in 1998 to $21 million from $7 million in 1997. The
increase was primarily due to interest earned on temporary
investment balances, which were higher in 1998 than in 1997 due to
cash received from the issuance of the rate-reduction bonds in
December 1997. Other income increased slightly in 1997 to $7
million from $4 million in 1996.
Interest Expense
Interest expense for 1998 increased to $116 million from $86
million in 1997 primarily due to the issuance of rate-reduction
bonds in December 1997. Interest expense for 1997 decreased to $86
million from $91 million in 1996 as a result of lower long-term
debt balances throughout most of 1997.
Income Taxes
Income tax expense was $142 million, $219 million and $198 million
in 1998, 1997 and 1996, respectively. These represent effective
tax rates of 43 percent, 48 percent and 47 percent for the same
periods. The decrease in the effective tax rate in 1998 is
primarily due to tax issues related to the recovery of CTC.
Derivative Financial Instruments
The Company's policy is to use derivative financial instruments to
manage exposure to fluctuations in interest rates, foreign currency
exchange rates and energy prices. Transactions involving these
financial instruments are with reputable firms and major exchanges.
The use of these instruments may expose the Company to market and
credit risks. At times, credit risk may be concentrated with
certain counterparties, although counterparty nonperformance is not
anticipated.
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. At December 31,
1998 and 1997, the notional amount of swap transactions totaled $45
million. See Note 9 of the notes to Consolidated Financial
Statements for further information regarding these swap
transactions.
The Company uses energy derivatives to manage natural gas price
risk associated with servicing its load requirements. These
instruments 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 activities, the use of
derivative financial instruments by the Company is subject to
certain limitations imposed by established Company policy and
regulatory requirements. 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 energy. The Company has
adopted corporate-wide policies governing its market-risk
management activities. An Energy Risk Management Oversight
Committee, consisting of senior corporate officers, oversees
Company-wide energy-price risk-management activities to ensure
compliance with the Company's stated energy risk-management
policies.
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, tenor and other factors. Historical volatilities and
correlations between instruments and positions are used in the
calculation.
The following is a discussion of the Company's primary market-
risk exposures as of December 31, 1998, including 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 its 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- and floating-rate debt.
Interest rate swaps, subject to regulatory constraints, may be used
to adjust interest-rate exposures when appropriate, based upon
market conditions.
The VaR on the Company's fixed rate long-term debt is estimated
at approximately $129 million as of December 31, 1998, assuming a
one-year holding period.
Energy Price Risk
Market risk related to physical commodities is based upon potential
fluctuations in natural gas, petroleum and electricity commodity
exchange 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, petroleum 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
The Company is exposed to market risk in its natural gas purchase,
sale and storage activities whenever natural gas prices fall
outside the PBR tolerance band. SDG&E manages this risk within the
parameters of the Company's market-risk management framework. As of
December 31, 1998 the total VaR of the Company's natural gas
positions was not material.
SDG&E is exposed to market risk on its electricity purchases
and sales under the electricity rate cap. See Note 12 of the notes
to Consolidated Financial Statements and the discussion under the
"Factors Influencing Future Performance" section for further
information regarding the electricity rate cap.
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
potential counterparties' financial condition (including credit
rating), 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.
Year 2000 Issues
Most companies are affected by the inability of many automated
systems and applications to process the year 2000 and beyond. The
Year 2000 issues are the result of computer programs and other
automated processes using two digits to identify a year, rather
than four digits. Any of the Company's computer programs that
include date-sensitive software may recognize a date using "00" as
representing the year 1900, instead of the year 2000, or "01" as
1901, etc., which could lead to system malfunctions. The Year 2000
issue impacts both Information Technology (IT) systems and also
non-IT systems, including systems incorporating "embedded
processors." To address this problem, in 1996, both Pacific
Enterprises and Enova Corporation established company-wide Year
2000 programs. These programs have now been consolidated into the
Sempra Energy's overall Year 2000 readiness effort. Sempra Energy
has established a central Year 2000 Program Office which reports to
the its Chief Information Technology Officer and reports
periodically to the audit committee of the Board of Directors.
The Company's State of Readiness
Sempra Energy is identifying all IT and non-IT systems that might
not be Year 2000 ready and categorizing them in the following
areas: IT applications, computer hardware and software
infrastructure, telecommunications, embedded systems and third
parties. Sempra Energy is currently evaluating its exposure in all
of these areas. These systems and applications are being tracked
and measured through four key phases: inventory, assessment,
remediation/testing and Year 2000 readiness. Those applications and
systems, which, if not appropriately remediated, may have a
significant impact on energy delivery, revenue collection or the
safety of personnel, customers or facilities, are being assessed
and modified/replaced first. The testing effort includes functional
testing of Year 2000 dates and validating that changes have not
altered existing functionality. Sempra Energy uses an independent,
internal-review process to verify that the appropriate testing has
occurred.
Inventory and assessment for all company systems were completed
by January 1999 and ongoing inventory and assessment will be
performed, as necessary, on any new applications. The project is on
schedule and the Company estimates that by June 30, 1999, all
critical systems will be suitable for continued use into the year
2000 with no significant operational problems.
Sempra Energy's current schedule for Year 2000 testing,
readiness and development of contingency plans is subject to change
depending upon the remediation and testing phases of its compliance
effort and upon developments that may arise as the Company
continues to assess its computer-based systems and operations. In
addition, this schedule is dependent upon the efforts of third
parties, such as suppliers (including energy producers) and
customers. Accordingly, delays by third parties may cause Sempra
Energy's schedule to change.
Costs to Address Sempra Energy's Year 2000 Issues
Sempra Energy's budget for the Year 2000 program is $48 million, of
which $38 million has been spent. As Sempra Energy continues to
assess its systems and as the remediation and testing efforts
progress, cost estimates may change. Sempra Energy's Year 2000
readiness effort is being funded entirely by operating cash flows.
The Risks of Sempra Energy's Year 2000 Issues
Based upon its current assessment and testing of the Year 2000
issue, Sempra Energy believes the reasonably likely worst case Year
2000 scenarios to have the following impacts upon its operations.
With respect to Sempra Energy's ability to provide energy to its
domestic utility customers, it believes that the reasonably likely
worst case scenario is for small, localized interruptions of
natural gas or electrical service which are restored in a time-
frame that is within normal service levels. With respect to
services that are essential to Sempra Energy's operations, such as
customer service, business operations, supplies and emergency
response capabilities, the scenario is for minor disruptions of
essential services with rapid recovery and all essential
information and processes ultimately recovered.
To assist in preparing for and mitigating these possible
scenarios, Sempra Energy is a member of several industry-wide
efforts established to deal with Year 2000 problems affecting
embedded systems and equipment used by the nation's natural gas and
electric power companies. Under these efforts, participating
utilities are working together to assess specific vendors' system
problems and to test plans. These assessments will be shared by the
industry as a whole to facilitate Year 2000 problem solving.
A portion of this risk is due to the various Year 2000
schedules of critical third-party suppliers and customers. Sempra
Energy is in the process of contacting its critical suppliers and
customers to survey their Year 2000 remediation programs. While
risks related to the lack of Year 2000 readiness by third parties
could materially and adversely affect the Company's business,
results of operations and financial condition, the Company expects
its Year 2000 readiness efforts to reduce significantly the
Company's level of uncertainty about the impact of third party Year
2000 issues on both its IT systems and non-IT systems.
Company's Contingency Plans
Sempra Energy's contingency plans for Year-2000-related
interruptions are being incorporated in its existing overall
emergency preparedness plans. To the extent appropriate, such plans
will include emergency backup and recovery procedures, remediation
of existing systems parallel with installation of new systems,
replacing electronic applications with manual processes,
identification of alternate suppliers and increasing inventory
levels. Sempra Energy expects these contingency plans to be
completed by June 30, 1999. Due to the speculative and uncertain
nature of contingency planning, there can be no assurances that
such plans actually will be sufficient to reduce the risk of
material impacts on Sempra Energy's operations due to Year 2000
issues.
New Accounting Standards
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 133
"Accounting for Derivative Instruments and Hedging Activities."
This statement, which is effective January 1, 2000, 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 effect of this standard on the Company's
Consolidated Financial Statements has not yet been determined.
Information Regarding Forward-Looking Statements
This report includes forward-looking statements within the
definition of Section 27A of the Securities Act of 1933 and Section
21E of the Securities Exchange Act of 1934. The words "estimates,"
"believes," "expects," "anticipates," "plans" and "intends,"
variations of such words, and similar expressions are intended to
identify forward-looking statements that involve risks and
uncertainties which could cause actual results to differ materially
from those anticipated. These statements are necessarily based upon
various assumptions involving judgments with respect to the future
including, among others, local, regional, national, and
international economic, competitive, political and regulatory
conditions and developments, technological developments, capital
market conditions, inflation rates, interest rates, energy markets,
weather conditions, business and regulatory or legal decisions, the
pace of deregulation of retail natural gas and electricity
industries, 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. Accordingly,
while the Company believes that the assumptions are reasonable,
there can be no assurance that they will approximate actual
experience, or that the expectations will be realized. Readers are
urged to carefully review and consider 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.
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."
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, 1998 and 1997, and the related statements of consolidated
income, changes in shareholders' equity, and cash flows for each of
the three years in the period ended December 31, 1998. 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 generally accepted
auditing standards. 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, 1998
and 1997, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 1998
in conformity with generally accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
January 27, 1999, except for Note 14 as to which the date is
February 22, 1999
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions
For the years ended December 31 1998 1997 1996
------- ------- -------
Operating Revenues
Electric $1,865 $1,769 $1,591
PX / ISO power 500 -- --
Gas 384 398 348
------- ------- -------
Total 2,749 2,167 1,939
------- ------- -------
Expenses
Electric fuel 177 164 134
Purchased power 292 441 311
PX / ISO power 468 -- --
Gas purchased for resale 166 183 152
Maintenance 106 87 58
Depreciation and decommissioning 603 324 314
Property and other taxes 42 43 45
General and administrative 290 213 248
Other 186 178 166
Income taxes 133 217 202
------- ------- -------
Total 2,463 1,850 1,630
------- ------- -------
Operating Income 286 317 309
------- ------- -------
Other Income and (Deductions)
Allowance for equity funds used
during construction 5 5 5
Taxes on nonoperating income (9) (2) 4
Other - net 25 4 (5)
------- ------- -------
Total 21 7 4
------- ------- -------
Income Before Interest Charges 307 324 313
------- ------- -------
Interest Charges
Long-term debt 96 69 76
Short-term debt and other 14 14 13
Amortization of debt discount and
expense, less premium 8 5 5
Allowance for borrowed funds
used during construction (2) (2) (3)
------- ------- -------
Total 116 86 91
------- ------- -------
Net Income 191 238 222
Preferred Dividend Requirements 6 6 6
------- ------- -------
Earnings Applicable to Common Shares $ 185 $ 232 $ 216
======= ======= =======
See notes to Consolidated Financial Statements.
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
CONSOLIDATED BALANCE SHEETS
Dollars in millions
Balance at December 31 1998 1997
------- -------
ASSETS
Utility plant - at original cost $4,903 $4,750
Accumulated depreciation and decommissioning (2,603) (2,391)
------ ------
Utility plant - net 2,300 2,359
------ ------
Nuclear decommissioning trust 494 399
------ ------
Current assets
Cash and temporary investments 284 536
Accounts receivable 199 229
Due from affiliates 110 126
Inventories 77 65
Regulatory balancing accounts undercollected - net 9 --
Other 17 52
------ ------
Total current assets 696 1,008
------ ------
Deferred taxes recoverable in rates 194 185
Regulatory assets 435 608
Deferred charges and other assets 138 95
------ ------
Total $4,257 $4,654
====== ======
CAPITALIZATION AND LIABILITIES
Capitalization
Common equity $1,124 $1,387
Preferred stock not subject to mandatory redemption 78 78
Preferred stock subject to mandatory redemption 25 25
Long-term debt 1,548 1,788
------ ------
Total capitalization 2,775 3,278
------- ------
Current liabilities
Current portion of long-term debt 72 73
Accounts payable 165 161
Dividends payable 102 46
Interest accrued 9 11
Regulatory balancing accounts overcollected - net -- 58
Other 185 114
------ ------
Total current liabilities 533 463
------ ------
Customer advances for construction 41 38
Deferred income taxes - net 397 440
Deferred investment tax credits 89 94
Deferred credits and other liabilities 422 341
Contingencies and commitments (Note 11) -- --
------ ------
Total $4,257 $4,654
====== ======
See notes to Consolidated Financial Statements.
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions
For the years ended December 31 1998 1997 1996
-------- -------- --------
Cash Flows from Operating Activities
Net income $ 191 $ 238 $ 222
Adjustments to reconcile net income
to net cash provided by operating activities
Depreciation and decommissioning 603 324 314
Allowance for equity funds used during construction (5) (5) (5)
Deferred income taxes and investment tax credits (132) 10 (16)
Application of balancing accounts to stranded costs (86) -- --
Other - net (64) 21 28
Changes in working capital components
Accounts receivable 30 (41) 18
Inventories (12) (2) 5
Other current assets 51 (4) (14)
Interest and taxes accrued 39 (40) (25)
Accounts payable and other current liabilities (66) (143) 50
Regulatory balancing accounts (14) 23 (37)
Cash used by discontinued operations -- -- (11)
------- ------- -------
Net cash provided by operating activities 535 381 529
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Cash Flows from Investing Activities
Utility construction expenditures (227) (197) (209)
Contributions to decommissioning funds (22) (22) (22)
Other - net (28) 5 (3)
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Net cash used by investing activities (277) (214) (234)
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Cash Flows from Financing Activities
Dividends paid (269) (256) (189)
Issuances of long-term debt -- 677 227
Repayment of long-term debt (241) (133) (258)
Redemption of preferred stock -- -- (15)
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Net cash provided (used) by financing activities (510) 288 (235)
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Net increase (decrease) (252) 455 60
Cash and temporary investments, January 1 536 81 21
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Cash and temporary investments, December 31 $ 284 $ 536 $ 81
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See notes to Consolidated Financial Statements.
SAN DIEGO GAS & ELECTRIC COMPANY AND SUBSIDIARY
STATEMENTS OF CONSOLIDATED CASH FLOWS (continued)
Dollars in millions
For the years ended December 31 1998 1997 1996
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Supplemental Disclosure of Cash Flow Information
Cash paid during the year for:
Income tax payments, net of refunds $ 207 $ 217 $ 245
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Interest payments, net of amounts capitalized $ 118 $ 89 $ 94