SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 2000
--------------------
OR
[ ] Transition report pursuant to Section 13 or 15(d) of the
Securities Exchange Act of 1934 for the transition period from
______ to_______
SOUTHERN CALIFORNIA GAS COMPANY
- -------------------------------------------------------------------
(Exact name of registrant as specified in its charter)
CALIFORNIA 1-1402 95-1240705
- -------------------------------------------------------------------
(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.
555 WEST FIFTH STREET, LOS ANGELES, CALIFORNIA 90013
- -------------------------------------------------------------------
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (213)244-1200
--------------
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of each exchange
Title of each class on which registered
- ------------------- ---------------------
Preferred Stock Pacific
First Mortgage Bonds: New York
Series Y, due 2021; Series Z, due 2002;
Series BB, due 2023; Series DD, due 2023;
Series EE, due 2025; Series FF, due 2003
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 53. Glossary on page 55.
Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of February 28, 2001 was
$12.6 million.
Registrant's common stock outstanding as of February 28, 2001 was
wholly owned by Pacific Enterprises.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 2001
annual meeting of shareholders are incorporated by reference into
Part III.
TABLE OF CONTENTS
PART I
Item 1. Business . . . . . . . . . . . . . . . . . . . . . . . 3
Item 2. Properties . . . . . . . . . . . . . . . . . . . . . . 11
Item 3. Legal Proceedings. . . . . . . . . . . . . . . . . . . 11
Item 4. Submission of Matters to a Vote of Security Holders. . 11
PART II
Item 5. Market for Registrant's Common Equity and Related
Stockholder Matters . . . . . . . . . . . . . . . . 12
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 12
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 13
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 24
Item 8. Financial Statements and Supplementary Data. . . . . . 25
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 49
PART III
Item 10. Directors and Executive Officers of the Registrant . . 49
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 49
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . 49
Item 13. Certain Relationships and Related Transactions . . . . 50
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 50
Independent Auditors' Consent . . . . . . . . . . . . . . . . . 51
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 52
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 53
Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 55
2
This Annual Report contains statements that are not historical fact
and constitute forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. The words
"estimates," "believes," "expects," "anticipates," "plans,"
"intends," "may," "would" and "should" or similar expressions, or
discussions of strategy or of plans are intended to identify forward-
looking statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions.
Future results may differ materially from those expressed in these
forward-looking statements.
Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions; actions by the California Public Utilities
Commission, the California Legislature and the Federal Energy
Regulatory Commission; the financial condition of other investor-
owned utilities; inflation rates and interest rates; energy markets,
including the timing and extent of changes in commodity prices;
weather conditions; business, regulatory and legal decisions; the
pace of deregulation of retail natural gas and electricity delivery;
the timing and success of business-development efforts; and other
uncertainties, all of which are difficult to predict and many of
which are beyond the control of the Company. Readers are cautioned
not to rely unduly on any forward-looking statements and are urged to
review and consider carefully the risks, uncertainties and other
factors which affect the Company's business described in this Annual
Report and other reports filed by the Company from time to time with
the Securities and Exchange Commission.
PART I
ITEM 1. BUSINESS
DESCRIPTION OF BUSINESS
A description of Southern California Gas Company (SoCalGas or the
Company) is given in "Management's Discussion and Analysis of
Financial Condition and Results of Operations" herein.
GOVERNMENT REGULATION
Local Regulation
SoCalGas has gas franchises with the 238 legal jurisdictions in its
service territory. These franchises allow SoCalGas to locate
facilities for the transmission and distribution of natural gas in
the streets and other public places. Some franchises have fixed
terms, such as that for the city of Los Angeles, which expires in
2012. Most of the franchises do not have fixed terms and continue
indefinitely. The range of expiration dates for the franchises with
definite terms is 2003 to 2048.
3
State Regulation
The State of California Legislature, from time to time, passes laws
that regulate SoCalGas' operations. For example, in 1999, the
legislature enacted a law addressing natural gas industry
restructuring.
The California Public Utilities Commission (CPUC) regulates SoCalGas'
rates and conditions of service, sales of securities, rate of return,
rates of depreciation, uniform systems of accounts, examination of
records, and long-term resource procurement. The CPUC 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.
Federal Regulation
The Federal Energy Regulatory Commission (FERC) regulates the
interstate sale and transportation of natural gas, the uniform
systems of accounts and rates of depreciation.
Licenses and Permits
SoCalGas obtains a number of permits, authorizations and licenses in
connection with the transmission and distribution of natural gas.
They require periodic renewal, which results in continuing regulation
by the granting agency.
Other regulatory matters are described in Note 11 of the notes to
Consolidated Financial Statements, herein.
SOURCES OF REVENUE
Industry segment information is contained in "Management's Discussion
and Analysis of Financial Condition and Results of Operations," and
in Note 12 of the notes to Consolidated Financial Statements, herein.
NATURAL GAS OPERATIONS
Utility Services
SoCalGas distributes natural gas throughout a 23,000-square-mile
service territory with a population of approximately 18.4 million
people. Its service territory includes most of southern California
and part of central California.
The Company offers two basic utility services: sale of natural gas
and transportation of natural gas. Natural gas service is also
provided on a wholesale basis to the distribution systems of the City
of Long Beach, Southwest Gas Corporation and SDG&E, an affiliated
company.
Supplies of Natural Gas
SoCalGas buys natural gas under short-term and long-term contracts.
Short-term purchases under these contracts are primarily from various
Southwest U.S. and Canadian gas suppliers, and are primarily based on
monthly spot-market prices. SoCalGas transports gas under long-term firm
pipeline capacity agreements that provide for annual reservation charges.
SoCalGas recovers such fixed charges in rates. SoCalGas has firm pipeline
capacity contracts with pipeline companies that expire at various dates
through 2006.
4
Most of the natural gas purchased and delivered by the Company is
produced outside of California. These supplies are delivered to the
Company's intrastate transmission system by interstate pipeline
companies, primarily El Paso Natural Gas Company and Transwestern
Natural Gas Company. These interstate companies provide
transportation services for supplies purchased from other sources by
the Company or its transportation customers. The rates that
interstate pipeline companies may charge for transportation services
are regulated by the FERC.
The following table shows the sources of natural gas deliveries from
1996 through 2000.
Year Ended December 31
-------------------------------------------------------------------
2000 1999 1998 1997 1996
- -------------------------------------------------------------------------------------------------------------
Purchases in billions of cubic feet
Spot market 343 315 270 229 226
Long-term 16 74 101 95 96
California producers 1 2 3 5 12
------- ------- ------- ------- -------
Total Purchases 360 391 374 329 334
Customer-Owned and Exchange Receipts 755 637 637 614 518
Storage Withdrawal
(Injection) - net 39 (6) (28) (3) 42
Company Use and
Unaccounted For (21) (16) (21) (10) (10)
------- ------- ------- ------- -------
Net Deliveries 1,133 1,006 962 930 884
======= ======= ======= ======= =======
Purchases in millions of dollars
Commodity costs $1,243 $ 916 $ 774 $ 849 $ 627
Fixed charges* 128 147 174 250 276
------- ------- ------- ------- -------
Total Purchases $1,371 $1,063 $ 948 $1,099 $ 903
======= ======= ======= ======= =======
Average Cost of Purchases
(dollars per thousand cubic feet)** $3.45 $2.34 $ 2.07 $2.58 $1.88
======= ======= ======= ======= =======
* Fixed charges primarily include pipeline demand charges, take or pay settlement costs and other
direct-billed amounts allocated over the quantities delivered by the interstate pipelines
serving SoCalGas.
** The average commodity cost of natural gas purchased excludes fixed charges.
Market-sensitive natural gas supplies (supplies purchased on
the spot market as well as under longer-term contracts,
ranging from one month to ten years, based on spot prices)
accounted for 95 percent of total natural gas volumes
purchased by the Company during 2000, as compared with 81
percent and 72 percent during 1999 and 1998, respectively.
Supply/demand imbalances are affecting the price of natural
gas in California more than in the rest of the country because
of California's dependence on natural gas fired electric
generation due to air-quality considerations. The average
price of natural gas at the California/Arizona (CA/AZ) border
was $6.25/mmbtu in 2000, compared with $2.33/mmbtu in 1999. On
December 11, 2000, the average spot cash gas price at the
CA/AZ border reached a record high of $56.91/mmbtu.
5
During 2000, the Company delivered 1,133 bcf of natural gas through
its system. Approximately 70 percent of these deliveries were
customer-owned natural gas for which the Company provided
transportation services. The balance of natural gas deliveries was
gas purchased by the Company and resold to customers. 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 approximately 5 million core
customers (4.8 million residential and 0.2 million small
commercial and industrial). Noncore customers consist primarily
of utility electric generation (UEG), wholesale, large
commercial, industrial and off-system (outside the Company's
normal service territory) customers, and total approximately
1,500.
Most core customers purchase natural gas directly from the Company.
Core customers are permitted to aggregate their natural gas
requirement and, up to a limit of 10 percent of the Company's core
market, to purchase natural gas directly from brokers or producers.
The Company continues to be obligated to purchase reliable supplies
of natural gas to serve the requirements of its core customers.
SoCalGas and SDG&E recently filed an application with the CPUC to
combine the two companies' core procurement portfolios.
Noncore customers have the option of purchasing natural gas
either from the Company or from other sources, such as brokers
or producers, for delivery through the Company's transmission
and distribution system. The only natural gas supplies that the
Company may offer for sale to noncore customers are the same
supplies that it purchases for its core customers. Most noncore
customers procure their own natural gas supply.
In 2000, approximately 87 percent of the CPUC-authorized
natural gas margin was allocated to the core customers, with 13
percent allocated to the noncore customers.
Although revenue from transportation throughput is less than for
natural gas sales, the Company generally earns the same margin
whether the Company buys the gas and sells it to the customer or
transports natural gas already owned by the customer.
The Company also provides natural gas storage services for noncore
and off-system customers on a bid and negotiated contract basis.
The storage service program provides opportunities for customers to
store natural gas on an "as available" basis, usually during the
summer to reduce winter purchases when natural gas costs are
generally higher. As of December 31, 2000, the Company was storing
approximately 2 bcf of customer-owned gas.
6
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 these natural gas
markets depends largely on the health and expansion of the southern
California economy. The Company added approximately 69,000 new
customer meters in 2000 and 74,000 in 1999, representing growth
rates of approximately 1.4 percent and 1.5 percent, respectively.
SoCalGas expects its growth rate for 2001 to be at the 2000 level.
During 2000, 99 percent of residential energy customers in the
Company's service area used natural gas for water heating, 96
percent for space heating, 76 percent for cooking and 55 percent
for clothes drying.
Demand for natural gas by noncore customers is very sensitive to
the price of competing fuels. Although the number of noncore
customers in 2000 was only 1,500, it accounted for 12 percent of
the authorized natural gas revenues and 69 percent of total natural
gas volumes. External factors such as weather, the price of
electricity, electric deregulation, the use of hydroelectric power,
competing pipeline bypass and general economic conditions can
result in significant shifts in demand and market price. The demand
for natural gas by large UEG customers is also greatly affected by
the price and availability of electric power generated in other
areas. The increase in UEG demand in 2000 was due to higher demand
for electricity and increased use of natural gas for electric
generation, a colder 2000 - 2001 winter and population growth in
California. Natural gas demand in 1999 for UEG customer use
increased primarily due to higher electric energy usage in the
summer, as a result of warmer weather.
Effective March 31, 1998, electric industry restructuring gave
California consumers the option of selecting their electric
energy provider from a variety of local and out-of-state
producers. As a result, natural gas demand for electric
generation within southern California competes with electric
power generated throughout the western United States. Although
electric industry restructuring has no direct impact on the
Company's natural gas operations, future volumes of natural gas
transported for UEG customers may be adversely affected to the
extent that regulatory changes divert electricity production
from the Company's service area and as noted in the following
paragraph.
On January 18, 2001, Pacific Gas & Electric Company (PG&E) filed an
emergency application with the CPUC requesting that SoCalGas be
ordered to purchase natural gas or supply available natural gas to
meet PG&E's core procurement needs. Some of PG&E's suppliers are
declining to sell natural gas to PG&E due to its poor credit
rating. Although SoCalGas has agreed to supply a limited amount of
natural gas to PG&E through March 31, 2001 (secured by PG&E
customer receivables), it is still urging rejection of the request
which, if approved, could severely jeopardize SoCalGas' ability to
serve its own customers because of cash flow considerations.
7
Other
Additional information concerning customer demand and other aspects
of natural gas operations is provided under "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Notes 10 and 11 of the notes to Consolidated
Financial Statements herein.
RATES AND REGULATION
SoCalGas is regulated by the CPUC, which consists of five
commissioners appointed by the Governor of California for staggered
six-year terms. It is the responsibility of the CPUC to determine
that utilities operate within the best interests of their
customers. The regulatory structure is complex and has a
substantial impact on the profitability of the Company. Both the
electric and natural gas industries are currently undergoing
transitions to competition and are being impacted by abnormally
high commodity prices resulting from supply/demand imbalances.
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. The CPUC is currently assessing the current
market and regulatory framework for California's natural gas
industry. As a result of California's dependence on natural gas
fired electric generation due to air-quality considerations,
supply/demand imbalances are affecting the price of natural gas in
California more than in the rest of the country. Additional
information on natural gas industry restructuring is provided in
"Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 11 of the notes to Consolidated
Financial Statements herein.
Balancing Accounts
In general, earnings fluctuations from changes in the costs of
natural gas and consumption levels for the majority of natural
gas are eliminated through balancing accounts authorized by the
CPUC. Additional information on balancing accounts is provided
in "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and in Note 2 of the notes to
Consolidated Financial Statements herein.
Performance-Based Regulation (PBR)
In recent years, the CPUC has directed utilities to use PBR. To
promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, PBR has
replaced the general rate case and certain other regulatory
proceedings for SoCalGas. Additional information on PBR is provided
in "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 11 of the notes to Consolidated
Financial Statements herein.
8
Biennial Cost Allocation Proceeding (BCAP)
Rates to recover the changes in the cost of natural gas
transportation services are determined in the BCAP. The BCAP
adjusts rates to reflect variances in customer demand from
estimates previously used in establishing customer natural gas
transportation rates. The mechanism substantially eliminates the
effect on income of variances in market demand and natural gas
transportation costs and is subject to the limitations of the Gas
Cost Incentive Mechanism (GCIM) described below. The BCAP will
continue under PBR. Additional information on the BCAP is provided
in "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and in Note 11 of the notes to Consolidated
Financial Statements herein.
Gas Cost Incentive Mechanism (GCIM)
The GCIM is a process SoCalGas uses to evaluate its natural gas
purchases, substantially replacing the previous process of
reasonableness reviews. Additional information on the GCIM is
provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" and in Note 11 of the notes to
Consolidated Financial Statements herein.
Cost of Capital
Under PBR, annual Cost of Capital proceedings have been replaced by
an automatic adjustment mechanism if changes in certain indices
exceed established tolerances. Additional information on the
Company's cost of capital is provided in "Management's Discussion
and Analysis of Financial Condition and Results of Operations" and
in Note 11 of the notes to Consolidated Financial Statements
herein.
ENVIRONMENTAL MATTERS
Discussions about environmental issues affecting SoCalGas are
included in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" herein. The following
additional information should be read in conjunction with those
discussions.
Hazardous Substances
In 1994, the CPUC approved the Hazardous Waste Collaborative
Memorandum account, a mechanism that allows SoCalGas to recover in
rates the costs associated with the cleanup of sites contaminated
with hazardous waste.
SoCalGas lawfully disposed of wastes at permitted facilities owned
and operated by other entities. Operations at these facilities may
result in actual or threatened risks to the environment or public
health. Under California law, businesses that arrange for legal
disposal of wastes at a permitted facility from which wastes are
later released, or threaten to be released, can be held financially
responsible for corrective actions at the facility.
SoCalGas has been named as a potentially responsible party (PRP)
for two landfill sites and five industrial waste disposal sites,
from which releases have occurred as described below.
Remedial actions and negotiations with other PRPs and the United
States Environmental Protection Agency (EPA) have been in progress
since 1986 and 1993 for the two landfill sites. The Company's share
of costs to remediate these sites is estimated to be $3.7 million,
of which $410,000 was incurred during 2000.
9
In the early 1990s, the Company was notified of hazards at two
industrial waste treatment facilities in the California communities
of Fresno and Carson, where the Company had disposed of wastes.
During 2000, the Company settled with the other PRPs at these sites
for $425,000 and has no additional liability.
In December 1999, SoCalGas was notified that it is a PRP at a waste
treatment facility in Bakersfield, California. SoCalGas is working
with other PRPs in order to remove from the site certain liquid
wastes that threaten to be released. It is too early to determine
the existence or extent of any prior releases or SoCalGas'
potential total liability.
In March 2000, SoCalGas was notified it is a PRP at a former
mercury recycling facility in Brisbane, California. Total potential
liability is estimated at less than $10,000. Also in March 2000,
SoCalGas was sued in Federal District Court as a PRP in a waste oil
disposal site in Los Angeles. Plaintiffs alleged that SoCalGas had
transported various petroleum wastes to the site in the 1950s for
recycling. SoCalGas settled with plaintiffs in December 2000 for
$200,000.
In addition, the Company has identified and reported to California
environmental authorities 42 former manufactured-gas plant sites
for which it (together with other users as to 21 of these sites)
may have cleanup obligations. As of December 31, 2000, 18 of these
sites have been remediated, of which 14 have received certification
from the California Environmental Protection Agency. Preliminary
investigations, at a minimum, have been completed on 40 of the gas
plant sites.
At December 31, 2000, SoCalGas' estimated remaining investigation
and remediation liability related to hazardous waste sites,
including the manufactured-gas plant sites detailed above, was
$57.6 million, of which 90 percent is authorized to be recovered
through the Hazardous Waste Collaborative mechanism. SoCalGas
believes that any costs not ultimately recovered through rates,
insurance or other means, will not have a material adverse effect
on SoCalGas' results of operations or financial position.
Estimated liabilities for environmental remediation are recorded
when amounts are probable and estimable. Amounts authorized to be
recovered in rates under the Hazardous Waste Collaborative
mechanism are recorded as a regulatory asset.
Air and Water Quality
California's air quality standards are more restrictive than
federal standards. 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.
10
OTHER MATTERS
Research, Development and Demonstration (RD&D)
The SoCalGas RD&D portfolio is focused in five major areas:
operations, utilization systems, power generation, public interest
and transportation. Each of these activities provides benefits to
customers and society by providing more cost-effective, efficient
natural gas equipment with lower emissions, increased safety and
reduced environmental mitigation and other utility operating costs.
The CPUC has authorized SoCalGas to recover its operating costs
associated with RD&D. An annual average of $7.9 million has been
spent for the last three years.
Employees of Registrant
As of December 31, 2000, SoCalGas had 5,853 employees, compared to
6,079 at December 31, 1999.
Wages
Field, technical and most clerical employees of SoCalGas are
represented by the Utility Workers' Union of America or the
International Chemical Workers' Council. The collective bargaining
agreement on wages, hours and working conditions remains in effect
through March 31, 2002.
ITEM 2. PROPERTIES
Natural Gas Properties
At December 31, 2000, SoCalGas owned 2,846 miles of transmission
and storage pipeline, 45,150 miles of distribution pipeline and
44,547 miles of service piping. It also owned 10 transmission
compressor stations and 6 underground storage reservoirs (with a
combined working capacity of 117.8 Bcf).
Other Properties
SoCalGas has a 15-percent limited partnership interest in a 52-
story office building in downtown Los Angeles. SoCalGas leases
approximately half of the building through the year 2011. The lease
has six separate five-year renewal options.
The Company owns or leases other offices, operating and maintenance
centers, shops, service facilities and equipment necessary in the
conduct of business.
ITEM 3. LEGAL PROCEEDINGS
Except for the matters described in Note 10 of the notes to
Consolidated Financial Statements or referred to elsewhere in this
Annual Report, neither the Company nor its subsidiaries are party to,
nor is their property the subject of, any material pending legal
proceedings other than routine litigation incidental to their
businesses.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
11
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS
All of the issued and outstanding common stock of SoCalGas is owned
by PE, a wholly owned subsidiary of Sempra Energy. The information
required by Item 5 concerning dividends declared is included in the
"Statements of Consolidated Changes in Shareholders' Equity" set
forth in Item 8 of this Annual Report herein.
Dividend Restrictions
CPUC regulation of SoCalGas' capital structure limits to $266
million the portion of the Company's December 31, 2000 retained
earnings that is available for dividends. Additional information
is provided in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" herein.
ITEM 6. SELECTED FINANCIAL DATA
At December 31, or for the years then ended
------------------------------------------------
(Dollars in millions) 2000 1999 1998 1997 1996
-------- ------- ------- ------- -------
Income Statement Data:
Operating revenues $2,854 $2,569 $2,427 $2,641 $2,422
Operating income $ 266 $ 268 $ 238 $ 318 $ 286
Dividends on preferred Stock $ 1 $ 1 $ 1 $ 7 $ 8
Earnings applicable to
common shares $ 206 $ 200 $ 158 $ 231 $ 193
Balance Sheet Data:
Total assets $4,116 $3,452 $3,834 $4,205 $4,354
Long-term debt $ 821 $ 939 $ 967 $ 968 $1,090
Short-term debt (a) $ 120 $ 30 $ 75 $ 498 $ 409
Shareholders' equity $1,309 $1,310 $1,382 $1,467 $1,487
(a) Includes long-term debt due within one year.
Since SoCalGas is a wholly owned subsidiary of Pacific Enterprises, per
share data has been omitted.
This data should be read in conjunction with the Consolidated Financial
Statements and the notes to Consolidated Financial Statements contained
herein.
12
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
Introduction
This section includes management's discussion and analysis of
operating results from 1998 through 2000, and provides information
about the capital resources, liquidity and financial performance of
SoCalGas. 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.
SoCalGas is the nation's largest natural gas distribution
utility. It owns and operates a natural gas distribution, transmission
and storage system supplying natural gas throughout a 23,000-square
mile service territory comprising most of southern California and part
of central California. The Company is the principal subsidiary of
Pacific Enterprises (PE or the Parent), which is wholly-owned by
Sempra Energy. The Company provides natural gas service to
residential, commercial, industrial, utility electric generation and
wholesale customers through 5.0 million meters in a service area with
a population of 18.4 million.
Supply/demand imbalances are affecting the price of
natural gas in California more than in the rest of the country
because of California's dependence on natural gas fired
electric generation due to air-quality considerations.
The uncertainties shaping California's electric industry
and business environment also affect the Company's operations.
These recent developments are continuing to change. Information
as of March 7, 2001, the date this report was prepared, is found
herein, primarily under "Results of Operations" and "Factors
Influencing Future Performance" and in Note 11 of the notes to
Consolidated Financial Statements
Business Combinations
Sempra Energy was formed to serve as a holding company for PE and
Enova Corporation (Enova), the parent corporation of San Diego Gas &
Electric Company, in connection with a business combination that
became effective on June 26, 1998 (the PE/Enova business combination).
In connection with the PE/Enova business combination, the holders of
common stock of PE and Enova became the holders of Sempra Energy's
common stock. The preferred stock of SoCalGas remained outstanding.
The combination was a tax-free transaction.
Expenses incurred by SoCalGas in connection with this event were
$35 million, aftertax, for the year ended December 31, 1998. No
significant expenses were incurred subsequently. These costs consist
primarily of employee-related costs, and investment banking, legal,
regulatory and consulting fees. See Note 1 of the notes to the
Consolidated Financial Statements for additional information.
Capital Resources and Liquidity
The Company's operations have historically been a major source of
liquidity. In addition, working capital requirements are met primarily
through the issuance of short-term and long-term debt. Cash
requirements primarily consist of capital expenditures for utility
plant.
13
Cash Flows From Operating Activities
The increase in cash flows from operating activities in 2000 was
primarily due to higher accounts payable and overcollected regulatory
balancing accounts, partially offset by increased accounts receivable.
The increases in accounts payable and accounts receivable were
primarily due to higher prices for natural gas. The regulatory
balancing account overcollections resulted from higher sales volumes
and the actual cost of gas being lower than amounts being collected in
rates.
The decrease in cash flows from operating activities in
1999 was primarily due to the return to ratepayers of the
previously overcollected regulatory balancing accounts. This
decrease was partially offset by the absence of business
combination expenses and lower income tax payments in 1999. See
Note 1 of the notes to the Consolidated Financial Statements for
additional information.
Cash Flows From Investing Activities
Cash flows from investing activities primarily represent capital
expenditures for utility plant.
Capital expenditures were $198 million in 2000, compared to $146
million and $128 million spent in 1999 and in 1998, respectively. The
increase in capital expenditures in 2000 is primarily due to
improvements to the gas distribution system and expansion of pipeline
capacity to meet increased demand by electric generators and
commercial and industrial customers. Capital expenditures increased
in 1999 primarily due to internal software development projects during
1999.
Capital expenditures in 2001 are expected to be comparable to
those of 2000. They will be financed primarily by operations and debt
issuances.
Cash Flows From Financing Activities
Net cash used in financing activities decreased in 2000 compared to
1999 primarily due to lower long-term debt repayments and lower
dividends to the Parent compared to 1999.
Net cash used in financing activities decreased in 1999 primarily
due to lower short-term debt repayments and the repurchase of
preferred stock in 1998, partially offset by greater dividends to the
Parent in 1999.
Long-Term and Short-Term Debt
Cash was used for the repayment of $30 million and $75 million of
unsecured notes in 2000 and 1999, respectively.
In 1998, cash was used for the repayment of $100 million of
first-mortgage bonds and $47 million of Swiss Franc bonds, partially
offset by the issuance of $75 million of medium-term notes. Short-term
debt repayments included $94 million of debt issued to finance the
Comprehensive Settlement as discussed in Note 11 of the notes to
Consolidated Financial Statements.
14
Stock Redemption
On February 2, 1998, SoCalGas redeemed all outstanding shares of its
7.75% Series Preferred Stock at a cost of $25.09 per share, or $75
million including accrued dividends.
Dividends
Dividends paid to the Parent amounted to $200 million in 2000,
compared to $278 million in 1999 and $165 million in 1998.
The payment of future dividends and the amount thereof are within
the discretion of the Company's board of directors. CPUC regulation of
SoCalGas' capital structure limits to $266 million the portion of the
Company's December 31, 2000, retained earnings that is available for
dividends.
Capitalization
Total capitalization including the current portion of long-term debt
was $2.3 billion at December 31, 2000. The debt to capitalization
ratio was 42 percent at December 31, 2000. The change in
capitalization during 2000 was primarily due to the repayment of long-
term debt.
Cash and Cash Equivalents
Cash and cash equivalents were $205 million at December 31, 2000. This
cash is available for investment in projects consistent with the
Company's strategic direction, the retirement of debt, the repurchase
of common stock, the payment of dividends and other corporate
purposes. The Company anticipates that operating cash required in 2001
for capital expenditures, dividends and debt payments will be provided
by cash generated from operating activities and from long-term and
short-term debt issuances.
In addition to cash generated from ongoing operations, the
Company has a credit agreement that permits short-term borrowings of
up to $170 million. This agreement expires in 2002. For additional
information see Note 3 of the notes to Consolidated Financial
Statements.
Management believes that the sources of funding described above
are sufficient to meet short-term and long-term liquidity needs.
Results of Operations
To understand the operations and financial results of SoCalGas, it is
important to understand the ratemaking procedures that SoCalGas
follows.
SoCalGas is regulated by the CPUC. It is the responsibility of
the CPUC to determine that utilities operate in the best interests of
their customers and have the opportunity to earn a reasonable return
on investment.
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. The CPUC currently is studying the issue of
restructuring for sales to core customers and, as mentioned above,
supply/demand imbalances are affecting the price of natural gas in
California more than in the rest of the country because of
California's dependence on natural gas fired electric generation due
to air-quality considerations.
15
See additional discussions of natural gas-industry restructuring
below under "Factors Influencing Future Performance" and in Note 11 of
the notes to Consolidated Financial Statements.
In connection with restructuring of the natural gas industry,
SoCalGas received approval from the CPUC for Performance-Based
Ratemaking (PBR). Under PBR, income potential is tied to achieving or
exceeding specific performance and productivity measures, rather than
to expanding utility plant in a market where a utility already has a
highly developed infrastructure (see Note 11 of the notes to
Consolidated Financial Statements).
The table below summarizes the components of natural gas volumes and
revenues by customer class for 2000, 1999 and 1998.
SoCalGas
GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
Gas Sales Transportation & Exchange Total
----------------------------------------------------------------------
Throughput Revenue Throughput Revenue Throughput Revenue
----------------------------------------------------------------------
2000:
Residential 251 $2,167 3 $ 12 254 $2,179
Commercial and Industrial 86 621 317 209 403 830
Utility Electric Generation - - 310 106 310 106
Wholesale - - 166 54 166 54
-----------------------------------------------------------------------
337 $2,788 796 $381 1,133 3,169
Balancing accounts and other (315)
---------
Total $2,854
- ---------------------------------------------------------------------------------------------
1999:
Residential 275 $1,821 3 $ 10 278 $1,831
Commercial and Industrial 84 452 306 229 390 681
Utility Electric Generation - - 188 77 188 77
Wholesale - - 150 57 150 57
-----------------------------------------------------------------------
359 $2,273 647 $373 1,006 2,646
Balancing accounts and other (77)
---------
Total $2,569
- ---------------------------------------------------------------------------------------------
1998:
Residential 269 $1,976 3 $ 11 272 $1,987
Commercial and Industrial 81 466 315 261 396 727
Utility Electric Generation - - 139 66 139 66
Wholesale - - 155 66 155 66
-----------------------------------------------------------------------
350 $2,442 612 $404 962 2,846
Balancing accounts and other (419)
---------
Total $2,427
- ---------------------------------------------------------------------------------------------
2000 Compared to 1999
Net income for 2000 increased to $207 million compared to net income
of $201 million in 1999. The increase is primarily due to higher non-
core gas throughput, the sale of the Company's investment in Plug
Power, and lower operating and maintenance expenses. For the fourth
quarter of 2000, net income decreased to $56 million from $59 million
for the fourth quarter of 1999. The decrease is primarily due to the
favorable resolution of tax related issues in 1999, partially offset
by higher non-core gas throughput and the sale of the Company's
investment in Plug Power in 2000.
16
Natural gas revenues increased from $2.6 billion in 1999 to $2.9
billion in 2000, primarily due to higher prices for natural gas in
2000 (see discussion of balancing accounts and gas revenues in Note 2
of the notes to Consolidated Financial Statements) and higher UEG
revenues. The increase in UEG revenues was due to higher demand for
electricity in 2000. In addition, the generating plants receiving gas
transportation from the Company are operating at higher capacities
than previously, as discussed below.
The cost of natural gas distributed increased from $1.0 billion
in 1999 to $1.4 billion in 2000. The increase was largely due to
higher prices for natural gas. Prices for natural gas have increased
due to the increased use of natural gas to fuel electric generation,
colder winter weather, and population growth in California. Under the
current regulatory framework, changes in core-market natural gas
prices do not affect net income, since the actual commodity cost of
natural gas for core customers is included in customer rates on a
substantially current basis.
Operating expenses decreased from $738 million in 1999 to $695
million in 2000. The decrease was primarily due to lower pension
expense in 2000.
1999 Compared to 1998
Net income for 1999 increased to $201 million compared to net income
of $159 million in 1998. The increase is primarily due to $35 million,
after-tax, of PE/Enova business combination expenses in 1998. For the
fourth quarter of 1999, net income increased to $59 million from $38
million for the fourth quarter of 1998. The increase is primarily due
to lower business-combination and operating expenses in 1999 and the
favorable resolution of tax related issues.
Natural gas revenues increased from $2.4 billion in 1998 to $2.6
billion in 1999. The increase was primarily due to higher UEG
revenues, partially offset by a decrease in residential, commercial
and industrial revenues. The increase in UEG revenues was primarily
due to higher electric energy usage in the summer, as a result of
warmer weather. The decrease in residential and commercial and
industrial revenues is due to lower gas prices.
The Company's cost of natural gas distributed increased from $0.9
billion in 1998 to $1.0 billion in 1999. The increase was largely due
to an increase in the average price of natural gas purchased.
Operating expenses decreased from $798 million in 1998 to $738
million in 1999. The decrease was primarily due to the $60 million of
business-combination costs in 1998.
Other Income and Deductions, Interest Expense and Income Taxes
Other Income and Deductions
Other income and deductions, which primarily consists of interest
income and/or expense from short-term investments and regulatory
balancing accounts, increased to income of $15 million in 2000
compared to an expense of $7 million in 1999. The increase is
primarily due to higher interest earned on a loan to Sempra Energy,
and a gain recognized on the sale of its investment in Plug Power.
Other income was $1 million in 1998. The decrease from 1998 to 1999
is primarily due to an increase in interest expense on regulatory
balancing accounts, partially offset by an increase in interest
income on short-term investments.
17
Interest Expense
Interest expense for 2000 increased to $74 million from $60 million
in 1999, primarily due to a reversal of interest expense related to
income-tax issues in 1999 as a result of favorable income-tax
rulings, partially offset by lower interest expense on long-term debt
due to lower average long-term debt balances during 2000. Interest
expense was $80 million for 1998. The decrease of $20 million in 1999
was primarily due to the reversal of interest expense noted above.
Income Taxes
Income tax expense was $183 million, $182 million and $128 million
for the years ended December 31, 2000, 1999 and 1998, respectively.
The increase in income tax expense for 1999 compared to 1998 is due
to the increase in income before taxes. The effective income tax
rates were 46.9 percent, 47.5 percent and 44.6 percent for the same
years. See Note 5 of the notes to the Consolidated Financial
Statements for additional information.
Factors Influencing Future Performance
The factors influencing financial performance are summarized below.
Natural Gas Restructuring and Gas Rates
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. In January 1998, the CPUC released a staff report
initiating a proceeding to assess the current market and regulatory
framework for California's natural gas industry. The general goals of
the plan are to consider reforms to the current regulatory framework,
emphasizing market-oriented policies benefiting California's natural
gas consumers. A CPUC decision is expected in 2001.
In October 1999, the state of California enacted a law that
requires natural gas utilities to provide "bundled basic gas service"
(including transmission, storage, distribution, purchasing, revenue-
cycle services and after-meter services) to all core customers,
unless the customer chooses to purchase gas from a nonutility
provider. The law prohibits the CPUC from unbundling distribution-
related gas services (including meter reading and billing) and after-
meter services (including leak investigation, inspecting customer
piping and appliances, pilot relighting and carbon monoxide
investigation) for most customers. The objective is to preserve both
customer safety and customer choice.
18
Supply/demand imbalances are affecting the price of
natural gas in California more than in the rest of the country
because of California's dependence on natural gas fired
electric generation due to air-quality considerations. The
average price of natural gas at the California/Arizona (CA/AZ)
border was $6.25/mmbtu in 2000, compared with $2.33/mmbtu in
1999. On December 11, 2000, the average spot-market price at
the CA/AZ border reached a record high of $56.91/mmbtu.
Underlying the high natural gas prices are several factors,
including the increase in natural gas usage for electric
generation, colder winter weather and reduced natural gas
supply resulting from historically low storage levels, lower
gas production and a major pipeline rupture. In December 2000,
SoCalGas filed with the Federal Energy Regulatory Commission
(FERC) for a reinstitution of price caps on short-term
interstate capacity to the CA/AZ border and between the
interstate pipelines and California's local distribution
companies, effective until March 31, 2001. The FERC responded
by issuing extensive data requests, but has not otherwise acted
on the Company's request.
A recent lawsuit, which seeks class-action certification,
alleges that SoCalGas, Sempra Energy, SDG&E and El Paso Energy Corp.
acted to drive up the price of natural gas for Californians by
agreeing to stop a pipeline project that would have brought new and
cheaper natural gas supplies into California. SoCalGas believes the
allegations are without merit.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to move
away from reasonableness reviews and potential disallowances, the
CPUC has been directing utilities to use PBR. PBR has replaced the
general rate case and certain other regulatory proceedings for the
Company. Under PBR, regulators require future income potential to be
tied to achieving or exceeding specific performance and productivity
goals, as well as cost reductions, rather than by relying solely on
expanding utility plant in a market where a utility already has a
highly developed infrastructure. See additional discussion of PBR
"Results of Operations" above and in Note 11 of the notes to
Consolidated Financial Statements.
Allowed Rate of Return
For 2001, SoCalGas is authorized to earn a rate of return on rate
base of 9.49 percent and a rate of return on common equity of 11.6
percent, the same as in 2000 and 1999. The Company can earn more than
the authorized rate by controlling costs below approved levels or by
achieving favorable results in certain areas, such as incentive
mechanisms. In addition, earnings are affected by changes in sales
volumes, except for the majority of SoCalGas' core sales.
Management Control of Expenses and Investment
In the past, management has been able to control operating expenses
and investment within the amounts authorized to be collected in
rates. It is the intent of management to control operating expenses
and 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 at least its authorized rates of
return. However, in view of the earnings-sharing mechanism and other
elements of the PBR, it is more difficult to exceed authorized
returns to the degree experienced prior to the inception of PBR. See
additional discussion of PBR above and in Note 11 of the notes to
Consolidated Financial Statements.
19
Noncore Bypass
SoCalGas is at risk for 25-percent of the revenue related reductions
in noncore volumes due to bypass. However, significant bypass would
require construction of additional facilities by competing pipelines.
SoCalGas has not had a material reduction in earnings from bypass and
it is continuing to reduce its costs to remain competitive and to
retain its transportation customers.
Noncore Pricing
To respond to bypass, SoCalGas received authorization from the CPUC
for expedited review of long-term natural gas transportation service
contracts with some noncore customers at fixed transportation rates,
some of which are at lower than the otherwise-applicable tariff
rates. In addition, the CPUC approved changes in the methodology that
reduced the subsidization of core customer rates by noncore
customers. This allocation modification, together with negotiating
authority, has enabled SoCalGas to better compete with new interstate
pipelines for noncore customers.
Noncore Throughput
SoCalGas' earnings will be adversely impacted if natural gas
throughput to its noncore customers varies from estimates adopted by
the CPUC in establishing rates. There is a continuing risk that an
unfavorable variance in noncore volumes may result from external
factors such as weather, electric deregulation, the increased use of
hydroelectric power, competing pipeline bypass of SoCalGas' system
and a downturn in general economic conditions. In addition, many
noncore customers are especially sensitive to the price relationship
between natural gas and alternate fuels, as they are capable of
readily switching from one fuel to another, subject to air-quality
regulations. SoCalGas is at risk for 25-percent of the lost revenue.
Through July 31, 1999, some of the favorable earnings effect of
higher revenues resulting from higher throughput to noncore customers
was limited as a result of the Comprehensive Settlement. The
settlement addressed a number of regulatory issues and was approved
by the CPUC in July 1994. This treatment has been replaced by the PBR
mechanism as adopted in the 1999 BCAP whereby revenue fluctuations
will impact earnings (positively or negatively). See Note 11 of the
notes to Consolidated Financial Statements for further discussion.
Excess Interstate Pipeline Capacity
SoCalGas has exercised its step-down option on both the El Paso and
Transwestern systems, thereby reducing its firm interstate capacity
obligation from 2.25 Bcf per day to 1.45 Bcf per day.
FERC-approved settlements have resulted in a reduction in the
costs that SoCalGas possibly may have been required to pay for the
capacity released back to El Paso and Transwestern. Of the remaining
1.45 Bcf per day of capacity, SoCalGas' core customers use 1.05 Bcf
per day at the full FERC tariff rate. The remaining 0.40 Bcf per day
of capacity is sold in the secondary market. Under existing
California regulation, unsubscribed capacity costs associated with
the remaining 0.40 Bcf per day are recoverable in customer rates.
While including the unsubscribed pipeline cost in rates may impact
SoCalGas' ability to compete in competitive markets, SoCalGas does
not believe its inclusion will have a significant impact on volumes
transported or sold.
20
Environmental Matters
The Company's operations are subject to federal, state and local
environmental laws and regulations governing such things as hazardous
wastes, air and water quality, land use, solid waste disposal and the
protection of wildlife.
The Company's capital costs to comply with environmental
requirements are generally recovered through the depreciation
components of customer rates. The Company's customers generally are
responsible for 90 percent of the non-capital costs associated with
hazardous substances and the normal operating costs associated with
safeguarding air and water quality, disposing properly of solid
waste, and protecting endangered species and other wildlife.
Therefore, the likelihood of the Company's financial position or
results of operations being adversely affected in a significant
manner is remote.
The environmental issues currently facing the Company or
resolved during the latest three-year period include investigation
and remediation of its manufactured-gas sites (18 completed as of
December 31, 2000 and 24 to be completed) and cleanup of third-party
waste-disposal sites used by the Company, which has been identified
as a Potentially Responsible Party (investigations and remediations
are continuing).
Market Risk
The Company's policy is to use derivative financial instruments to
reduce its exposure to fluctuations in interest rates, foreign-
currency exchange rates and energy prices. Transactions involving
these financial instruments are with credit-worthy firms and major
exchanges. The use of these instruments exposes the Company to market
and credit risks which, at times, may be concentrated with certain
counterparties.
The Company uses energy derivatives to manage natural gas price
risk associated with servicing its load requirements. In addition,
the Company makes limited use of natural gas derivatives for trading
purposes. These instruments can include forward contracts, futures,
swaps, options and other contracts, with maturities ranging from 30
days to 12 months. In the case of both price-risk management and
trading activities, the use of derivative financial instruments by
the Company is subject to certain limitations imposed by Company
policy and regulatory requirements. See Note 8 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.
21
Market-Risk Management Activities
Market risk is the risk of erosion of the Company's cash flows, net
income and asset values due to adverse changes in interest and
foreign-currency rates, and in prices for equity and energy. Sempra
Energy has adopted corporate-wide policies governing its market-risk
management and trading activities. An Energy Risk Management
Oversight Committee, consisting of senior officers, oversees company-
wide energy-price risk-management and trading activities to ensure
compliance with Sempra Energy's stated energy risk management and
trading policies. In addition, the Company has groups that monitor
and control energy-price risk management and trading activities
independently from the groups responsible for creating or actively
managing these risks.
Along with other tools, the Company uses Value at Risk (VaR) to
measure its exposure to market risk. VaR is an estimate of the
potential loss on a position or portfolio of positions over a
specified holding period, based on normal market conditions and
within a given statistical confidence level. The Company has adopted
the variance/covariance methodology in its calculation of
VaR, and uses a 95-percent confidence level. Holding periods are
specific to the types of positions being measured, and are determined
based on the size of the position or portfolios, market liquidity,
purpose and other factors. Historical volatilities and correlations
between instruments and positions are used in the calculation.
The following discussion of the Company's primary market-risk
exposures as of December 31, 2000, includes a discussion of how these
exposures are managed.
Interest-Rate Risk
The Company is exposed to fluctuations in interest rates primarily as
a result of its fixed-rate long-term debt. The Company has
historically funded operations through long-term bond issues with
fixed interest rates. With the restructuring of the regulatory
process, greater flexibility has been permitted within the debt-
management process. As a result, recent debt offerings have been
selected with short-term maturities to take advantage of yield curves
or have used a combination of fixed-rate and floating-rate debt.
Subject to regulatory constraints, interest-rate swaps may be used to
adjust interest-rate exposures when appropriate, based upon market
conditions.
The VaR on the Company's fixed-rate long-term debt is estimated
at approximately $107 million as of December 31, 2000, assuming a
one-year holding period.
Energy-Price Risk
Market risk related to physical commodities is based upon potential
fluctuations in natural gas 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 market.
The Company's policy is to manage this risk within a framework that
considers the unique markets, operating and regulatory environment.
Market Risk
SoCalGas may, at times, be exposed to limited market risk in its
natural gas purchase, sale and storage activities as a result of
activities under the Gas Cost Incentive Mechanism (GCIM). SoCalGas
manages this risk within the parameters of the Company's market-risk
management and trading framework. As of December 31, 2000, the total
VaR of SoCalGas's natural gas positions was not material.
22
Credit Risk
Credit risk relates to the risk of loss that would be incurred as a
result of nonperformance by counterparties pursuant to the terms of
their contractual obligations. The Company avoids concentration of
counterparties and maintains credit policies with regard to
counterparties that management believes significantly minimize
overall credit risk. These policies include an evaluation of
prospective counterparties' financial condition (including credit
ratings), collateral requirements under certain circumstances, and
the use of standardized agreements that allow for the netting of
positive and negative exposures associated with a single
counterparty.
The Company monitors credit risk through a credit-approval
process and the assignment and monitoring of credit limits. These
credit limits are established based on risk and return considerations
under terms customarily available in the industry.
Almost all of SoCalGas's accounts receivable are with customers
located in California and, therefore, potentially affected by the
high costs of electricity and natural gas in California, as described
in "Factors Influencing Future Performance" and in Note 11 of the
notes to Consolidated Financial Statements.
New Accounting Standards
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 133 "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging
Activities." As amended, SFAS 133, requires that an entity recognize
all derivatives as either assets or liabilities in the statement of
financial position, measure those instruments at fair value and
recognize changes in the fair value of derivatives in earnings in the
period of change unless the derivative qualifies as an effective
hedge that offsets certain exposures.
The adoption of this new standard on January 1, 2001, did not
impact the Company's earnings. However, $982 million in current
assets, $1.1 billion in noncurrent assets, and $4 million in current
liabilities were recorded as of January 1, 2001, in the Consolidated
Balance Sheet as fixed-priced contracts and other derivatives. Due to
the regulatory environment in which SoCalGas operates, regulatory
assets and liabilities were established to the extent that derivative
gains and losses are recoverable or payable through future rates. As
such, $982 million in current regulatory liabilities, $1.1 billion in
noncurrent regulatory liabilities, and $4 million in current
regulatory assets were recorded as of January 1, 2001, in the
Consolidated Balance Sheet. The ongoing effects will depend on future
market conditions and the Company's hedging activities.
In December 1999, the Securities and Exchange Commission (SEC)
issued Staff Accounting Bulletin (SAB) 101 - Revenue Recognition.
SABs are not rules issued by the SEC. Rather, they represent
interpretations and practices followed by the SEC's staff in
administering the disclosure requirements of the federal securities
laws. SAB 101 provides guidance on the recognition, presentation and
disclosure of revenue in financial statements; it does not change the
existing rules on revenue recognition. SAB 101 sets forth the basic
criteria that must be met before revenue should be recorded.
Implementation of SAB 101 was required by the fourth quarter of 2000
and had no effect on the Company's consolidated financial statements.
23
Information Regarding Forward-Looking Statements
This Annual Report contains statements that are not historical fact
and constitute forward-looking statements within the meaning of the
Private Securities Litigation Reform Act of 1995. The words
"estimates," "believes," "expects," "anticipates," "plans,"
"intends," "may," "would" and "should" or similar expressions, or
discussions of strategy or of plans are intended to identify forward-
looking statements. Forward-looking statements are not guarantees of
performance. They involve risks, uncertainties and assumptions.
Future results may differ materially from those expressed in these
forward-looking statements.
Forward-looking statements are necessarily based upon various
assumptions involving judgments with respect to the future and other
risks, including, among others, local, regional, national and
international economic, competitive, political, legislative and
regulatory conditions; actions by the CPUC, the California
Legislature and the FERC; the financial condition of other investor-
owned utilities; inflation rates and interest rates; energy markets,
including the timing and extent of changes in commodity prices;
weather conditions; business, regulatory and legal decisions; the
pace of deregulation of retail natural gas and electricity delivery;
the timing and success of business-development efforts; and other
uncertainties, all of which are difficult to predict and many of
which are beyond the control of the Company. Readers are cautioned
not to rely unduly on any forward-looking statements and are urged to
review and consider carefully the risks, uncertainties and other
factors which affect the Company's business described in this Annual
Report and other reports filed by the Company from time to time with
the SEC.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A is set forth under "Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Market Risk Management Activities."
24
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of Southern California
Gas Company:
We have audited the accompanying consolidated balance sheets
of Southern California Gas Company and subsidiaries as of December
31, 2000 and 1999, and the related statements of consolidated
income, cash flows and changes in shareholders' equity for each of
the three years in the period ended December 31, 2000. These
financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with auditing standards
generally accepted in the United States of America. Those standards
require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test
basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the
accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
Southern California Gas Company and subsidiaries as of December 31,
2000 and 1999, and the results of their operations and their cash
flows for each of the three years in the period ended December 31,
2000 in conformity with accounting principles generally accepted in
the United States of America.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
January 26, 2001 (February 27, 2001 as to Note 3)
25
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions
For the years ended December 31 2000 1999 1998
------ ------- -------
Operating Revenues $2,854 $2,569 $2,427
------ ------ ------
Operating Expenses
Cost of natural gas distributed 1,361 1,032 913
Operation and maintenance 695 738 798
Depreciation 263 260 254
Income taxes 173 179 126
Other taxes and franchise payments 96 92 98
------ ------ ------
Total operating expenses 2,588 2,301 2,189
------ ------ ------
Operating Income 266 268 238
------ ------ ------
Other Income and (Deductions)
Interest income 27 16 4
Regulatory interest (12) (14) --
Allowance for equity funds used during construction 3 -- 3
Taxes on non-operating income (10) (3) (2)
Other - net 7 (6) (4)
------ ------ ------
Total 15 (7) 1
------ ------ ------
Income Before Interest Charges 281 261 239
------ ------ ------
Interest Charges
Long-term debt 68 74 75
Other 8 (12) 6
Allowance for borrowed funds used during construction (2) (2) (1)
------ ------ ------
Total 74 60 80
------ ------ ------
Net Income 207 201 159
Preferred Dividend Requirements 1 1 1
------ ------ ------
Earnings Applicable to Common Shares $ 206 $ 200 $ 158
====== ====== ======
See notes to Consolidated Financial Statements.
26
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions
Balance at December 31 2000 1999
---------- ----------
ASSETS
Utility plant - at original cost $6,314 $6,160
Accumulated depreciation (3,557) (3,339)
------ ------
Utility plant - net 2,757 2,821
------ ------
Current assets
Cash and cash equivalents 205 11
Accounts receivable - trade (less allowance for doubtful
receivables of $19 in 2000 and $16 in 1999) 589 280
Accounts and notes receivable - other 83 14
Due from affiliates 214 73
Deferred income taxes 74 25
Inventories 67 78
Other 80 5
------ ------
Total current assets 1,312 486
------ ------
Regulatory assets 12 91
Investments and other assets 35 54
------ ------
Total $4,116 $3,452
====== ======
See notes to Consolidated Financial Statements.
27
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions
Balance at December 31 2000 1999
----------- -----------
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock $ 835 $ 835
Retained earnings 453 447
Accumulated other comprehensive income (loss) (1) 6
------ ------
Total common equity 1,287 1,288
Preferred stock 22 22
Long-term debt 821 939
------ ------
Total capitalization 2,130 2,249
------ ------
Current liabilities
Accounts payable - trade 368 159
Accounts payable - other 44 50
Regulatory balancing accounts - net 463 154
Income taxes payable 90 4
Interest payable 26 29
Current portion of long-term debt 120 30
Other 300 205
------ ------
Total current liabilities 1,411 631
------ ------
Deferred credits and other liabilities
Customer advances for construction 16 27
Deferred income taxes 314 319
Deferred investment tax credits 53 56
Deferred credits and other liabilities 192 170
------ ------
Total deferred credits and other liabilities 575 572
------ ------
Contingencies and commitments (Note 10)
Total $4,116 $3,452
====== ======
See notes to Consolidated Financial Statements.
28
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions
For the years ended December 31 2000 1999 1998
------ ------ ------
Cash Flows From Operating Activities
Net Income $ 207 $ 201 $ 159
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation 263 260 254
Deferred income taxes and investment tax credits (4) 133 (169)
Other - net 23 (62) (33)
Changes in working capital components
Accounts receivable (378) 154 46
Inventories 11 (18) (24)
Other current assets (75) 1 (1)
Accounts payable 203 (18) (13)
Income taxes payable 86 (26) (9)
Due to/from affiliates (3) (83) 81
Regulatory balancing accounts 309 36 484
Other current liabilities 92 6 7
------ ------ ------
Net cash provided by operating activities 734 584 782
------ ------ ------
Cash Flows from Investing Activities
Capital expenditures (198) (146) (128)
Loan to affiliate (132) (101) --
Other - net 21 17 22
------ ------ ------
Net cash used in investing activities (309) (230) (106)
------ ------ ------
Cash Flows from Financing Activities
Dividends paid (201) (279) (166)
Redemption of preferred stock -- -- (75)
Issuance of long-term debt -- -- 75
Payment of long-term debt (30) (75) (148)
Increase (decrease) in short-term debt -- -- (351)
------ ------ ------
Net cash used in financing activities (231) (354) (665)
------ ------ ------
Increase in cash and cash equivalents 194 -- 11
Cash and cash equivalents, January 1 11 11 --
------ ------ ------
Cash and cash equivalents, December 31 $ 205 $ 11 $ 11
====== ====== ======
Supplemental Disclosure of Cash Flow Information:
Income tax payments, net of refunds $ 101 $ 100 $ 302
====== ====== ======
Interest payments, net of amount capitalized $ 77 $ 77 $ 86
====== ====== ======
See notes to Consolidated Financial Statements.
29
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
For the years ended December 31, 2000, 1999, 1998
Dollars in millions
| Accumulated
| Other Total
Comprehensive| Preferred Common Retained Comprehensive Shareholders'
Income | Stock Stock Earnings Income (Loss) Equity
- --------------------------------------------------------------------------------------------------
|
Balance at December 31, 1997 | $ 97 $ 835 $ 535 $1,467
Net income/comprehensive income $ 159 | 159 159
Preferred stock dividends declared | (1) (1)
Common stock dividends declared | (168) (168)
Redemption of preferred stock | (75) (75)
- --------------------------------------------------------------------------------------------------
Balance at December 31, 1998 | 22 835 525 1,382
Net income 201 | 201 201
Other comprehensive income (loss): |
Available-for-sale securities 10 | $ 10 10
Pension (4) | (4) (4)
----- |
Comprehensive income $ 207 |
Preferred stock dividends declared | (1) (1)
Common stock dividends declared | (278) (278)
- --------------------------------------------------------------------------------------------------
Balance at December 31, 1999 | 22 835 447 6 1,310
Net income 207 | 207 207
Other comprehensive income (loss): |
Available-for-sale securities (10) | (10) (10)
Pension 3 | 3 3
----- |
Comprehensive income $ 200 |
Preferred stock dividends declared | (1) (1)
Common stock dividends declared | (200) (200)
- --------------------------------------------------------------------------------------------------
Balance at December 31, 2000 $ 22 $ 835 $ 453 $ (1) $1,309
==================================================================================================
See notes to Consolidated Financial Statements.
30
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1: BUSINESS COMBINATION
On June 26, 1998, Enova Corporation (Enova), the parent company of
San Diego Gas & Electric (SDG&E), and Pacific Enterprises (PE),
parent company of Southern California Gas Company (SoCalGas or the
Company), combined into a new company named Sempra Energy. As a
result of the combination, (i) each outstanding share of common stock
of Enova was converted into one share of common stock of Sempra
Energy, (ii) each outstanding share of common stock of PE was
converted into 1.5038 shares of common stock of Sempra Energy and
(iii) the preferred stock and preference stock of the combining
companies and their subsidiaries remained outstanding.
NOTE 2: SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation
The Consolidated Financial Statements include the accounts of
SoCalGas and its subsidiaries. The Company's policy is to consolidate
all subsidiaries that are more than 50 percent owned and controlled.
All material intercompany accounts and transactions have been
eliminated. As a subsidiary of Sempra Energy, the Company receives
certain services therefrom. Although it is charged its allocable
share of the cost of such services, that cost is less than if the
Company had to provide those services itself.
Effects of Regulation
The accounting policies of SoCalGas conform with generally accepted
accounting principles for regulated enterprises and reflect the
policies of the California Public Utilities Commission (CPUC) and the
Federal Energy Regulatory Commission (FERC).
SoCalGas prepares its financial statements in accordance with
the provisions of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation,"
under which a regulated utility records a regulatory asset if it is
probable that, through the ratemaking process, the utility will
recover that asset from customers. Regulatory liabilities represent
future reductions in rates for amounts due to customers. To the
extent that portions of the utility operations were to be no longer
subject to SFAS No. 71, or recovery was to be no longer probable as a
result of changes in regulation or the utility's competitive
position, the related regulatory assets and liabilities would be
written off. In addition, SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to Be
Disposed Of," affects utility plant and regulatory assets such that a
loss must be recognized whenever a regulator excludes all or part of
an asset's cost from rate base. Additional information on the effects
of regulation on the Company is provided in Note 11.
Revenues and Regulatory Balancing Accounts
Revenues from utility customers consist of deliveries to customers
and the changes in regulatory balancing accounts. Balancing accounts
eliminate from earnings most of the fluctuations in prices and
volumes of natural gas by adjusting future rates to recover
shortfalls from customers or to return excess collections to
customers.
31
Regulatory Assets
Regulatory assets include unrecovered premiums on early retirement of
debt and other expenditures that the Company expects to recover in
future rates. See Note 11 for additional information.
Inventories
Included in inventories at December 31, 2000, were $11 million of
materials and supplies ($11 million in 1999), and $56 million of
natural gas ($67 million in 1999). Materials and supplies are
generally valued at the lower of average cost or market; natural gas
is valued by the last-in first-out method.
Loan to Affiliate
SoCalGas has a promissory note receivable from Sempra Energy. The
note bears interest based on short-term commercial paper rates, and
is due on demand. The note receivable was $233 million and $101
million at December 31, 2000 and 1999, respectively.
Utility Plant
This primarily represents the buildings, equipment and other
facilities used by SoCalGas to provide natural gas utility service.
The cost of utility plant includes labor, materials, contract
services and related items, and an allowance for funds used during
construction. The cost of retired depreciable utility plant, plus
removal costs minus salvage value, is charged to accumulated
depreciation. Depreciation expense is based on the straight-line
method over the useful lives of the assets or a shorter period
prescribed by the CPUC. The provisions for depreciation as a
percentage of average depreciable utility plant was 4.36, 4.39, 4.36
in 2000, 1999 and 1998, respectively.
Allowance for Funds Used During Construction (AFUDC)
The allowance represents the cost of funds used to finance the
construction of utility plant and is added to the cost of utility
plant. AFUDC also increases income, partly as an offset to interest
charges shown in the Statements of Consolidated Income, although it
is not a current source of cash.
Comprehensive Income
Comprehensive income includes all changes, except those resulting
from investments by owners and distributions to owners, in the equity
of a business enterprise from transactions and other events
including, as applicable, minimum pension liability adjustments and
unrealized gains and losses on marketable securities that are
classified as available-for-sale. At December 31, 1999, the Company
had one such investment, which increased in value during 1999. In
October 2000, this investment was sold. These changes are reflected
in the Statement of Consolidated Changes in Shareholders' Equity.
32
Use of Estimates in the Preparation of the Financial Statements
The preparation of the consolidated financial statements in
conformity with generally accepted accounting principles requires
management to make estimates and assumptions that affect the reported
amounts of assets and liabilities and disclosure of contingent assets
and liabilities at the date of the financial statements and the
reported amounts of revenues and expenses during the reporting
period. Actual results could differ from those estimates.
Cash and Cash Equivalents
Cash equivalents are highly liquid investments with original
maturities of three months or less at the date of purchase.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the
current year's presentation.
New Accounting Standards
Effective January 1, 2001, the Company adopted Statement of Financial
Accounting Standards (SFAS) No. 133 "Accounting for Derivative
Instruments and Hedging Activities," as amended by SFAS No. 138,
"Accounting for Certain Derivative Instruments and Certain Hedging
Activities." As amended, SFAS 133 requires that an entity recognize
all derivatives as either assets or liabilities in the statement of
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 exposure.
The adoption of this new standard on January 1, 2001, did not
impact the Company's earnings. However, $982 million in current
assets, $1.1 billion in noncurrent assets, and $4 million in current
liabilities were recorded as of January 1, 2001, in the Consolidated
Balance Sheet as fixed-priced contracts and other derivatives. Due to
the regulatory environment in which SoCalGas operates, regulatory
assets and liabilities were established to the extent that derivative
gains and losses are recoverable or payable through future rates. As
such, $982 million in current regulatory liabilities, $1.1 billion in
noncurrent regulatory liabilities, and $4 million in current
regulatory assets were recorded as of January 1, 2001, in the
consolidated balance sheet. The ongoing effects will depend on future
market conditions and the Company's hedging activities.
In December 1999, the Securities and Exchange Commission (SEC)
issued Staff Accounting Bulletin (SAB) 101 - Revenue Recognition.
SABs are not rules issued by the SEC. Rather, they represent
interpretations and practices followed by the SEC's staff in
administering the disclosure requirements of the federal securities
laws. SAB 101 provides guidance on the recognition, presentation and
disclosure of revenue in financial statements; it does not change the
existing rules on revenue recognition. SAB 101 sets forth the basic
criteria that must be met before revenue should be recorded.
Implementation of SAB 101 was required by the fourth quarter of 2000
and had no effect on the Company's consolidated financial statements.
33
NOTE 3: SHORT-TERM BORROWINGS
At December 31, 2000, SoCalGas had a $200 million credit agreement,
which was available to support commercial paper. At December 31,
2000, and 1999, SoCalGas' lines of credit were unused. On February 9,
2001, the agreement expired and was replaced on February 27, 2001,
with a $170 million one-year agreement. This agreement bears
interest at various rates based on market rates and SoCalGas' credit
rating.
NOTE 4: LONG-TERM DEBT
- -------------------------------------------------------------------
December 31,
(Dollars in millions) 2000 1999
- -------------------------------------------------------------------
First-Mortgage Bonds
6.875% August 15, 2002 $ 100 $ 100
5.750% November 15, 2003 100 100
8.750% October 1, 2021 150 150
7.375% March 1, 2023 100 100
7.500% June 15, 2023 125 125
6.875% November 1, 2025 175 175
----------------------------
750 750
----------------------------
Unsecured Long-Term Debt
6.375% Notes, October 29, 2001 120 120
5.670% Notes, January 15, 2028 75 75
SFr. 15,695,000 6.375% Foreign
Interest Payment Securities 8 8
8.750% Notes, July 6, 2000 -- 30
----------------------------
203 233
----------------------------
Total 953 983
Less:
Current portion of long-term debt 120 30
Unamortized debt discount on
long-term debt 12 14
----------------------------
Total $ 821 $ 939
- -------------------------------------------------------------------
Maturities of long-term debt are $120 million in 2001, $100 million
in 2002, $175 million in 2003 and $558 million after 2005. SoCalGas
has CPUC authorization to issue an additional $455 million in long-
term debt.
First-Mortgage Bonds
First-mortgage bonds are secured by a lien on substantially all of
SoCalGas' utility plant. SoCalGas may issue additional first-mortgage
bonds upon compliance with the provisions of their bond indentures,
which permit, among other things, the issuance of an additional $585
million of first-mortgage bonds as of December 31, 2000, subject to
CPUC authorization.
34
Unsecured Long-Term Debt
In July 2000, SoCalGas repaid $30 million of 8.75 percent medium-term
notes upon maturity.
In May 1996, SoCalGas issued SFr. 15,695,000 ($8 million) of
6.375% Foreign Interest Payment Securities. The securities are
renewable at ten-year intervals at reset interest rates. The next put
date for the securities is May 14, 2006.
Callable Bonds
At the Company's option, certain bonds may be called at a premium.
$150 million of the bonds are callable in 2001 and $400 million in
2003.
NOTE 5: INCOME TAXES
The reconciliation of the statutory federal income tax rate to the
effective income tax rate is as follows:
- ------------------------------------------------------------------
2000 1999 1998
- ------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 5.6 6.8 9.4
State income taxes - net of
federal income tax benefit 6.8 7.3 4.7
Tax credits (0.7) (0.6) (0.9)
Other - net 0.2 (1.0) (3.6)
------------------------------
Effective income tax rate 46.9% 47.5% 44.6%
- ------------------------------------------------------------------
The components of income tax expense are as follows:
- ------------------------------------------------------------------
(Dollars in millions) 2000 1999 1998
- ------------------------------------------------------------------
Current:
Federal $144 $ 36 $233
State 42 13 64
------------------------------
Total current taxes 186 49 297
------------------------------
Deferred:
Federal - 112 (128)
State (1) 24 (38)
------------------------------
Total deferred taxes (1) 136 (166)
------------------------------
Deferred investment tax credits-net (2) (3) (3)
------------------------------
Total income tax expense $183 $182 $128
- ------------------------------------------------------------------
35
Federal and state income taxes are allocated between operating income
and other income.
Accumulated deferred income taxes at December 31 result from the
following:
- ------------------------------------------------------------------
(Dollars in millions) 2000 1999
- ------------------------------------------------------------------
Deferred Tax Liabilities:
Differences in financial and
tax bases of utility plant $416 $439
Regulatory balancing accounts 11 16
Other 19 18
------------------------------
Total deferred tax liabilities 446 473
------------------------------
Deferred Tax Assets:
Investment tax credits 38 39
Comprehensive Settlement (see Note 11) 26 42
Other deferred liabilities 142 98
-----------------------------
Total deferred tax assets 206 179
------------------------------
Net deferred income tax liability $ 240 $ 294
- ------------------------------------------------------------------
The net liability is recorded on the Consolidated Balance Sheets at
December 31 as follows:
- ------------------------------------------------------------------
(Dollars in millions) 2000 1999
- ------------------------------------------------------------------
Current asset $ (74) $ (25)
Noncurrent liability 314 319
- ------------------------------------------------------------------
Total $ 240 $ 294
- -------------------------------------------------------------------
NOTE 6: EMPLOYEE BENEFIT PLANS
The information presented below describes the plans of the Company.
In connection with the PE/Enova business combination described in
Note 1, numerous participants have been transferred from the
Company's plans to plans of related entities. In connection with
voluntary separations related to the business combination, the
Company recorded a $51 million special termination benefit and a
settlement gain of $30 million in 1998.
During 2000, the Company participated in another voluntary
separation program. As a result, the Company recorded a $40 million
special termination benefit in 2000.
36
Pension and Other Postretirement Benefits
The Company sponsors qualified and nonqualified pension plans and
other postretirement benefit plans for its employees. The following
tables provide a reconciliation of the changes in the plans' benefit
obligations and fair value of assets over the two years, and a
statement of the funded status as of each year end:
- ---------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
(Dollars in millions) 2000 1999 2000 1999
- ---------------------------------------------------------------------------------
Weighted-Average Assumptions
as of December 31:
Discount rate 7.25%(1) 7.75% 7.75% 7.75%
Expected return on plan assets 8.00% 8.00% 8.00% 8.00%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered
health care charges - - 7.50%(2) 7.75%(2)
Change in Benefit Obligation:
Net benefit obligation at
January 1 $1,057 $1,156 $ 408 $ 446
Service cost 23 28 8 11
Interest cost 84 77 28 30
Plan participants' contributions - - - 1
Actuarial (gain)/loss 79 (120) (17) (62)
Curtailments (4) - 4 -
Transfer of liability (3) - (6) - -
Special termination benefits 34 - 2 -
Gross benefits paid (148) (78) (18) (18)
-----------------------------------------------
Net benefit obligation at
December 31 1,125 1,057 415 408
-----------------------------------------------
Change in Plan Assets:
Fair value of plan assets
at January 1 1,971 1,595 463 379
Actual return on plan assets (141) 453 (23) 77
Employer contributions - 1 10 24
Plan participants' contributions - - - 1
Transfer of assets (3) - - 2 -
Gross benefits paid (148) (78) (18) (18)
-----------------------------------------------
Fair value of plan assets
at December 31 1,682 1,971 434 463
-----------------------------------------------
Funded status at December 31 557 914 19 55
Unrecognized net actuarial gain (591) (969) (116) (156)
Unrecognized prior service cost 38 45 - -
Unrecognized net transition
obligation 2 3 96 110
-----------------------------------------------
Net recorded asset (liability)
at December 31 $ 6 $ (7) $ (1) $ 9
- ---------------------------------------------------------------------------------
(1) Discount rate decreased from 7.75% to 7.25%, effective March 1, 2000.
(2) Decreasing to ultimate trend of 6.50% in 2004.
(3) To reflect transfer of plan assets and liability to Sempra Energy.
37
The following table provides the amounts recognized on the
Consolidated Balance Sheets at December 31:
- ------------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
---------------------------------------------
(Dollars in millions) 2000 1999 2000 1999
- ------------------------------------------------------------------------------------
Prepaid benefit cost $ 15 - - $ 9
Accrued benefit cost (9) $ (7) $ (1) -
Additional minimum liability (4) (2) - -
Intangible asset 1 2 - -
Accumulated other
comprehensive income, pretax 3 - - -
- ------------------------------------------------------------------------------------
Net recorded asset(liability) $ 6 $ (7) $ (1) $ 9
- ------------------------------------------------------------------------------------
The following table provides the components of net periodic benefit
cost for the plans:
- ---------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
For the years ended December 31 2000 1999 1998 2000 1999 1998
(Dollars in millions)
- ---------------------------------------------------------------------------------
Service cost $ 23 $ 28 $ 33 $ 8 $ 11 $ 12
Interest cost 84 77 95 28 30 31
Expected return on assets (131) (112) (128) (32) (27) (24)
Amortization of:
Transition obligation 1 1 1 9 9 9
Prior service cost 4 4 3 - - -
Actuarial gain (29) (14) (12) (8) - -
Special termination benefits 33 - 48 7 - 3
Settlement credit - - (30) - - -
Regulatory adjustment 18 17 - 28 24 9
-----------------------------------------------
Total net periodic benefit cost $ 3 $ 1 $ 10 $ 40 $ 47 $ 40
- ---------------------------------------------------------------------------------
Assumed health care cost trend rates have a significant effect on the
amounts reported for the health care plans. A one-percent change in
assumed health care cost trend rates would have the following
effects:
- ----------------------------------------------------------------------
(Dollars in millions) 1% Increase 1% Decrease
- ----------------------------------------------------------------------
Effect on total of service and interest cost
components of net periodic postretirement
health care benefit cost $ 6 $ (6)
Effect on the health care component of the
accumulated other postretirement benefit $61 $(58)
obligation
- ----------------------------------------------------------------------
38
Except for one nonqualified retirement plan, all pension plans had
plan assets in excess of accumulated benefit obligations. For that
one plan the projected benefit obligation and accumulated benefit
obligation were $16 million and $12 million, respectively, as of
December 31, 2000, and $12 million and $9 million, respectively, as
of December 31, 1999.
Other postretirement benefits include retiree life insurance,
medical benefits for retirees and their spouses, and Medicare Part B
reimbursement for certain retirees.
Savings Plan
The Company offers a savings plan, administered by plan trustees, to
all eligible employees. Eligibility to participate in the plan is
immediate for salary deferrals. Employees may contribute, subject to
plan provisions, from one percent to 15 percent of their regular
earnings. Employer contributions, after one year of completed
service, are used to purchase shares of Sempra Energy common stock.
Employer contributions are equal to 50 percent of the first 6 percent
of eligible base salary contributed by employees. The employee's
contributions, at the direction of the employees, are primarily
invested in Sempra Energy stock, mutual funds, or institutional
trusts. Employer contributions for the SoCalGas plan are partially
funded by the Sempra Energy Employee Stock Ownership Plan and Trust
(formerly the Pacific Enterprises Employee Stock Ownership Plan and
Trust). Company contributions to the savings plan were $5 million in
2000, $6 million in 1999 and $7 million in 1998.
NOTE 7: STOCK-BASED COMPENSATION
Sempra Energy has stock-based compensation plans that align employee
and shareholder objectives related to Sempra Energy's long-term
growth. The long-term incentive stock compensation plan provides for
aggregate awards of Sempra Energy non-qualified stock options,
incentive stock options, restricted stock, stock appreciation rights,
performance awards, stock payments or dividend equivalents.
In 1995, SFAS No. 123, "Accounting for Stock-Based
Compensation," was issued. It encourages a fair-value-based method of
accounting for stock-based compensation. As permitted by SFAS No.
123, Sempra Energy and its subsidiaries adopted only its disclosure
requirements and continues to account for stock-based compensation in
accordance with the provisions of Accounting Principles Board Opinion
No. 25, "Accounting for Stock Issued to Employees."
The subsidiaries record an expense for the plans to the extent
that subsidiary employees participate in the plans, or that
subsidiaries are allocated a portion of Sempra Energy's costs of the
plans. SoCalGas recorded expenses (credits) of $2 million, ($4)
million and $4 million in 2000, 1999 and 1998, respectively.
NOTE 8: FINANCIAL INSTRUMENTS
Fair Value
The fair values of the Company's financial instruments (cash
temporary investments, notes receivable, dividends payable, short-
term and long-term debt, and preferred stock) are not materially
different from the carrying amounts, except for long-term debt and
preferred stock. The carrying amounts and fair values of long-term
debt were $1.0 billion and $0.9 billion, respectively, at both
December 31, 2000, and December 31, 1999. The carrying amounts and
fair values of preferred stock were $22 million and $15 million,
respectively, at December 31, 2000, and $22 million and $17 million,
respectively, at December 31, 1999. The fair values of the long-term
debt and preferred stock were estimated based on quoted market prices
for them or for similar issues.
39
Off-Balance-Sheet Financial Instruments
The Company's policy is to use derivative financial instruments to
manage its exposure to fluctuations in interest rates, foreign-
currency exchange rates and energy prices. Transactions involving
these financial instruments expose the Company to market and credit
risks which may at times be concentrated with certain counterparties,
although counterparty nonperformance is not anticipated.
Energy Derivatives
The Company uses energy derivatives for price-risk management
purposes within certain limitations imposed by Company policies and
regulatory requirements.
The Company is subject to price risk on its natural gas
purchases if its cost exceeds a 2 percent tolerance band above the
benchmark price. This is discussed further in Note 11. SoCalGas
becomes subject to price risk when positions are incurred during the
buying, selling and storing of natural gas. As a result of the Gas
Cost Incentive Mechanism (GCIM), the Company enters into a certain
amount of natural gas futures contracts in the open market with the
intent of reducing natural gas costs within the GCIM tolerance band.
The Company's policy is to use natural gas futures contracts to
mitigate risk and better manage natural gas costs. The CPUC has
approved the use of natural gas futures for managing risk associated
with the GCIM. At December 31, 2000, unrealized gains associated with
these activities totaled $72 million. These savings will be passed on
to customers during the first quarter of 2001. At December 31 1999,
unrealized gains and/or losses from natural gas futures contracts
were not material to the Company's financial statements.
NOTE 9: SHAREHOLDERS' EQUITY
COMMON EQUITY
- -----------------------------------------------------------------
December 31,
(Dollars in millions) 2000 1999
- -----------------------------------------------------------------
Common stock $ 835 $ 835
Retained earnings 453 447
Accumulated other comprehensive income (1) 6
--------------------------
Total common equity $ 1,287 $ 1,288
- -----------------------------------------------------------------
The Company is authorized to issue 100 million shares of common
stock. All shares of outstanding SoCalGas common stock are owned by
Pacific Enterprises.
40
PREFERRED STOCK
- -----------------------------------------------------------------
December 31,
(Dollars in millions) 2000 1999
- -----------------------------------------------------------------
Not subject to mandatory redemption:
$25 par value, authorized 1,000,000 shares
6% Series, 79,011 shares outstanding $ 3 $ 3
6% Series A, 783,032 shares outstanding 19 19
Without par value, authorized 10,000,000 shares - -
---------------
Total preferred stock $22 $22
- -----------------------------------------------------------------
None of SoCalGas' series of preferred stock are callable. All series
have one vote per share and cumulative preferences as to dividends.
On February 2, 1998, SoCalGas redeemed all outstanding shares of
7.75% Series Preferred Stock at a price per share of $25 plus accrued
dividends. The total cost to SoCalGas was $75 million.
Dividend Restrictions
CPUC regulation of SoCalGas' capital structure limits to $266 million
the portion of the Company's December 31, 2000 retained earnings that
is available for dividends.
NOTE 10: COMMITMENTS AND CONTINGENCIES
Natural Gas Contracts
SoCalGas buys natural gas under short-term and long-term contracts.
Short-term purchases under these contracts are primarily from various
Southwest U.S. and Canadian gas suppliers, and are primarily based on
monthly spot-market prices. SoCalGas transports gas under long-term firm
pipeline capacity agreements that provide for annual reservation charges.
SoCalGas recovers such fixed charges in rates. SoCalGas has commitments
for firm pipeline capacity under contracts with pipeline companies that
expire at various dates through 2006. In 1998, SoCalGas restructured its
long-term commodity contracts with suppliers of California offshore and
Canadian Gas. These contracts expire at the end of 2003.
At December 31, 2000, the future minimum payments under natural
gas contracts were:
- -----------------------------------------------------------------
Storage and
(Dollars in millions) Transportation Natural Gas
- -----------------------------------------------------------------
2001 $ 182 $ 1,268
2002 178 360
2003 180 262
2004 182 -
2005 177 -
Thereafter 92 -
----------------------------------
Total minimum payments $ 991 $ 1,890
- -----------------------------------------------------------------
41
Total payments under the contracts were $1.4 billion in 2000, $1.1
billion in 1999, and $0.9 billion in 1998.
Leases
SoCalGas has operating leases on real and personal property expiring
at various dates from 2001 to 2030. Certain leases contain escalation
clauses requiring annual increases in rent ranging from 4 percent to
5 percent. The rentals payable under these leases are determined on
both fixed and percentage bases, and most leases contain extension
options which are exercisable by SoCalGas.
At December 31, 2000, the minimum rental commitments payable in
future years under all noncancellable leases were:
- -----------------------------------------------------------------
(Dollars in millions)
- -----------------------------------------------------------------
2001 $ 27
2002 29
2003 29
2004 28
2005 28
Thereafter 191
- -----------------------------------------------------------------
Total future rental commitment $ 332
- -----------------------------------------------------------------
Rent expense totaled $41 million in 2000, $39 million in 1999 and $43
million in 1998.
Other Commitments and Contingencies
At December 31, 2000, commitments for capital expenditures were
approximately $12 million.
Environmental Issues
The Company's operations are subject to federal, state and local
environmental laws and regulations governing hazardous wastes, air
and water quality, land use, solid waste disposal and the protection
of wildlife. The Company incurs significant costs to operate its
facilities in compliance with these laws and regulations and these
costs generally have been recovered in customer rates.
In 1994, the CPUC approved the Hazardous Waste Collaborative
Memorandum account allowing utilities to recover their hazardous
waste costs, including those related to Superfund sites or similar
sites requiring cleanup. Recovery of 90 percent of cleanup costs and
related third-party litigation costs and 70 percent of the related
insurance-litigation expenses is permitted. In addition, the Company
has the opportunity to retain a percentage of any insurance
recoveries to offset the 10 percent of costs not recovered in rates.
Environmental liabilities that may arise are recorded when remedial
efforts are probable and the costs can be estimated.
42
The Company's capital expenditures to comply with environmental
laws and regulations were $1 million in each of 2000, 1999 and 1998,
and are not expected to be significant over the next five years. The
Company has been associated with various sites which may require
remediation under federal, state or local environmental laws. The
Company is unable to determine fully the extent of its responsibility
for remediation of these sites until assessments are completed.
Furthermore, the number of others that also may be responsible, and
their ability to share in the cost of the cleanup, is not known.
The environmental issues currently facing the Company or
resolved during the latest three-year period include investigation
and remediation of its manufactured-gas sites (18 completed as of
December 31, 2000 and 24 to be completed) and cleanup of third-party
waste disposal sites used by the Company, which has been identified
as a Potentially Responsible Party (investigation and remediations
are continuing).
Litigation
A recent lawsuit, which seeks class-action certification, alleges
that Sempra Energy, SoCalGas, SDG&E and El Paso Energy Corp. acted to
drive up the price of natural gas for Californians by agreeing to
stop a pipeline project that would have brought new and cheaper
natural gas supplies into California. The Company believes the
allegations are without merit.
Except for the matter referred to above, neither the Company nor
its subsidiaries are party to, nor is their property the subject of,
any material pending legal proceedings other than routine litigation
incidental to their businesses. Management believes that these
matters will not have a material adverse effect on the Company's
results of operations, financial condition or liquidity.
Concentration of Credit Risk
SoCalGas maintains credit policies and systems to minimize overall
credit risk. These policies include, when applicable, the use of an
evaluation of potential counterparties' financial condition and an
assignment of credit limits. These credit limits are established
based on risk and return considerations under terms customarily
available in the industry. SoCalGas grants credit to its utility
customers, substantially all of whom are located in its service
territory, which covers most of Southern California and a portion of
central California.
NOTE 11: REGULATORY MATTERS
Gas Industry Restructuring
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. In January 1998, the CPUC released a staff report
initiating a project to assess the current market and regulatory
framework for California's natural gas industry. The general goals of
the plan are to consider reforms to the current regulatory framework
emphasizing market-oriented policies benefiting California's natural
gas consumers.
In July 1999, after hearings, the CPUC issued a decision stating
which natural gas regulatory changes it found most promising,
encouraging parties to submit settlements addressing those changes,
and providing for further hearings if necessary.
43
In October 1999, the state of California enacted a law (AB 1421)
which requires that natural gas utilities provide "bundled basic gas
service" (including transmission, storage, distribution, purchasing,
revenue-cycle services and after-meter services) to all core
customers, unless the customer chooses to purchase natural gas from a
nonutility provider. The law prohibits the CPUC from unbundling most
distribution-related natural gas services (including meter reading)
and after-meter services (including leak investigation, inspecting
customer piping and appliances, pilot relighting and carbon monoxide
investigation) for core customers. The objective is to preserve both
customer safety and customer choice.
Between late 1999 and April 2000, several conflicting settlement
proposals were filed by various groups of parties that addressed the
changes the CPUC found promising in July 1999. The principal issues
in dispute included: whether firm, tradable rights to capacity on
SoCalGas' major gas transmission lines should be created, with
SoCalGas at risk for market demand for the recovery of the cost of
these facilities; the extent to which SoCalGas' storage services
should be further unbundled and SoCalGas be put at greater risk for
recovery of storage costs; the manner in which interstate pipeline
capacity held by SoCalGas to serve core markets should be allocated
to core customers who purchase gas from energy service providers
other than SoCalGas; and the recovery of the utilities' costs to
implement whatever regulatory changes are adopted. Additional
proposals included improving the access of energy service providers
to sell natural gas supply to core customers of SoCalGas.
Certain parties contend that the restructuring process is an
appropriate venue for addressing whether SoCalGas should refund
retroactively to September 1999 the cost in rates of ownership and
operation of one of SoCalGas' storage fields. SoCalGas actively
opposes this proposal and the propriety of this venue for its
resolution. In November 2000, these parties entered into a settlement
with SoCalGas in a related CPUC proceeding that provides for no
retroactive refund of the cost in rates of this field. This
settlement is pending CPUC approval.
Hearings in the restructuring case were held in mid-2000 and a
Proposed Decision (PD) was released in November 2000. The PD does not
recommend adoption of shareholder absorption of stranded interstate
pipeline costs or retroactive refund of any amount related to the
storage field. The PD recommends some, but not all, of the changes
proposed by SoCalGas. If adopted, the PD is not expected to have a
negative earnings impact on SoCalGas. A CPUC decision is expected in
2001.
Supply/demand imbalances are affecting the price of natural gas
in California more than in the rest of the country because of
California's dependence on natural gas fired electric generation due
to air-quality considerations. The average price of natural gas at
the California/Arizona (CA/AZ) border was $6.25/mmbtu in 2000,
compared with $2.33/mmbtu in 1999. On December 11, 2000, the average
spot-market price at the CA/AZ border reached a record high of
$56.91/mmbtu. Underlying the high natural gas prices are several
factors, including the increase in natural gas usage for electric
generation, cold winter weather and reduced natural gas supply
resulting from historically low storage levels, lower gas production
and a major pipeline rupture. In December 2000, SoCalGas filed with
the FERC for a reinstitution of price caps on short-term interstate
capacity to the CA/AZ border and between the interstate pipelines and
California's local distribution companies, effective until March 31,
2001. SoCalGas requested that if the price of natural gas sold into
California exceeds 150 percent of the national average, the price
should be capped at that level, plus FERC-imposed transportation
costs. The FERC responded by issuing extensive data requests, but has
not otherwise acted on the Company's request.
44
Electric Industry Restructuring
As a result of electric industry restructuring, natural gas demand
for electric generation within southern California competes with
electric power generated throughout the western United States.
Although electric industry restructuring has no significant direct
impact on the Company's natural gas operations, future volumes of
natural gas transported for UEG customers may be adversely affected
to the extent that regulatory changes divert electricity generation
from the Company's service area and as noted in the following
paragraph.
On January 18, 2001, Pacific Gas and Electric Company (PG&E)
filed an emergency application with the CPUC requesting that SoCalGas
be ordered to purchase natural gas or supply available natural gas to
meet PG&E's core procurement needs. Some of PG&E's suppliers are
declining to sell natural gas to PG&E due to its poor credit rating.
Although SoCalGas has agreed to supply a limited amount of natural
gas to PG&E through March 31, 2001 (secured by PG&E customer
receivables), it is still urging rejection of the request which, if
approved, could severely jeopardize SoCalGas' ability to serve its
own customers because of cash flow considerations.
Performance-Based Regulation (PBR)
In recent years, the CPUC has directed utilities to use PBR. To
promote efficient operations and improved productivity and to move
away from reasonableness reviews and disallowances, PBR has replaced
the general rate case and certain other regulatory proceedings for
SoCalGas. Under PBR, regulators generally require future income
potential to be tied to achieving or exceeding specific performance
and productivity measures, as well as cost reductions, rather than
relying solely on expanding utility plant in a market where a utility
already has a highly developed infrastructure.
The Company's PBR mechanism is in effect through December 31,
2002, at which time the mechanism will be updated. That update will
include, among other things, a reexamination of the Company's
reasonable costs of operation in 2003 to be allowed in rates. Key
elements of the current mechanism include an annual indexing
mechanism that adjusts rates by the inflation rate less a
productivity factor and other adjustments to accommodate major
unanticipated events, a sharing mechanism with customers that applies
to earnings that exceed the authorized rate of return on rate base,
rate refunds to customers if service quality deteriorates or awards
if service quality exceeds set standards, and a change in authorized
rate of return and customer rates if interest rates change by more
than a specified amount. A rate change is triggered if the 12-month
trailing average of actual market interest rates increases or
decreases by more than 150 basis points and is forecasted to continue
to vary by at least 150 basis points for the next year. If this
occurs, there would be an automatic adjustment of rates for the
change in the cost of capital according to a formula which applies a
percentage of the change to various capital components.
45
Comprehensive Settlement of Natural Gas Regulatory Issues
In July 1994, the CPUC approved a comprehensive settlement for the
Company (Comprehensive Settlement) of a number of regulatory issues,
including rate recovery of a significant portion of the restructuring
costs associated with certain long-term gas-supply contracts. In
addition to the supply issues, the Comprehensive Settlement addressed
the following other regulatory issues:
**Noncore revenues were governed by the Comprehensive Settlement
through July 31, 1999. This treatment was replaced by the 1999
Biennial Cost Allocation Proceeding (BCAP), which went into
effect on June 1, 2000. The CPUC's decision on the 1999 BCAP
allows balancing account treatment for 75 percent of noncore
revenues.
**The Gas Cost Incentive Mechanism (GCIM) for evaluating the
Company's natural gas purchases substantially replaced the
previous process of reasonableness reviews. GCIM compares
SoCalGas' cost of natural gas with a benchmark level, which is
the average price of 30-day firm spot supplies in the basins in
which SoCalGas purchases natural gas. The mechanism permits
full recovery of all costs within a tolerance band above the
benchmark price and refunds all savings within a tolerance band
below the benchmark price. The costs or savings outside the
tolerance band are shared equally between customers and
shareholders. The CPUC approved the use of natural gas futures
for managing risk associated with the GCIM. SoCalGas enters
into natural gas futures contracts in the open market on a
limited basis to mitigate risk and better manage natural gas
costs.
In 1998 the CPUC approved GCIM-related shareholder awards to the
Company totaling $13 million. On June 8, 2000, the CPUC approved an
$8 million award for the year ended March 31, 1999, and deferred its
decision regarding extending the GCIM beyond March 31, 2000 until an
evaluation is performed by its staff. On January 4, 2001, the CPUC's
Energy Division issued its evaluation report recommending the
continuation of the GCIM with modifications. A CPUC decision is
expected by September 2001.
In June 2000, the Company filed its annual GCIM application with
the CPUC, requesting an award of $10 million for the year ended March
31, 2000. On October 30, 2000, the CPUC's Office of Ratepayer
Advocates recommended approval of the award and the extension of the
GCIM beyond March 31, 2000, with certain modifications to the
tolerance band and benchmark price. A CPUC decision is expected by
September 2001.
Biennial Cost Allocation Proceeding
On November 4, 1999, the CPUC revised its previous decision on the
Company's 1996 BCAP, shifting $88 million of pipeline surcharges from
the pipeline capacity relinquishments to noncore customers. The
noncore customer rate impact of the decision is mitigated by
overcollections in the regulatory accounts and is reflected in the
rates adopted in the final 1999 BCAP decision.
46
On April 20, 2000, the CPUC issued a decision on the Company's
1999 BCAP, adopting an overall decrease in natural gas revenues of
$210 million for transportation rates effective June 1, 2000. There
is a return to 75/25 (customer/shareholder) balancing account
treatment for noncore transportation revenues, excluding certain
transactions. In addition, unbundled noncore storage revenues are
balanced 50/50 between customers and shareholders. Since the decrease
reflects anticipated changes in corresponding costs, it has no effect
on net income.
Cost of Capital
For 2001, the Company is authorized to earn a rate of return on
common equity of 11.6 percent and a 9.49 percent return on rate base,
the same as in 2000 and 1999, unless interest-rate changes are large
enough to trigger an automatic adjustment as discussed above under
"Performance-Based Regulation."
Integration of Core Gas Purchase Functions
On January 11, 2001, SoCalGas and SDG&E filed an application with the
CPUC to integrate their natural gas purchasing departments. The
filing calls for a single natural gas acquisition group to purchase
natural gas for the two utilities' core gas customers by using their
pooled gas portfolio assets. These assets include storage, interstate
capacity and natural gas supply contracts. The two utilities would
charge their core customers the same natural gas commodity rate from
the diversified portfolio. The change would bring increased
efficiency to the utilities' core gas purchase functions. The filing
requests that this change be effective November 1, 2001. A CPUC
decision is not expected until October 2001.
NOTE 12: SEGMENT INFORMATION
The Company previously had two separately managed reportable
segments: natural gas distribution and natural gas
transmission/storage. During 2000, the Company simplified how
management evaluates performance. As a result, the Company no longer
operates in multiple business segments.
47
NOTE 13: QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarter ended
----------------------------------------------------
Dollars in millions March 31 June 30 September 30 December 31
- ------------------------------------------------------------------------------------
2000
Operating revenues $ 698 $ 630 $ 722 $ 804
Operating expenses 632 563 653 740
--------------------------------------------------
Operating income $ 66 $ 67 $ 69 $ 64
--------------------------------------------------
Net income $ 50 $ 48 $ 53 $ 56
Dividends on preferred stock - 1 - -
--------------------------------------------------
Earnings applicable
to common shares $ 50 $ 47 $ 53 $ 56
==================================================
1999
Operating revenues $ 607 $ 624 $ 562 $ 776
Operating expenses 538 559 494 710
--------------------------------------------------
Operating income $ 69 $ 65 $ 68 $ 66
--------------------------------------------------
Net income $ 47 $ 47 $ 48 $ 59
Dividends on preferred stock - 1 - -
--------------------------------------------------
Earnings applicable
to common shares $ 47 $ 46 $ 48 $ 59
==================================================
Reclassifications have been made to certain of the amounts since they were presented in the
Quarterly Reports on Form 10-Q.
48
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information required on Identification of Directors is
incorporated by reference from "Election of Directors" in the
Information Statement prepared for the May 2001 annual meeting of
shareholders. The information required on the Company's executive
officers is set forth below.
EXECUTIVE OFFICERS OF THE REGISTRANT
Name Age* Positions
- -------------------------------------------------------------------
Edwin A. Guiles 51 Chairman, President and Chief
Financial Officer of Southern
California Gas Company, and
President - Energy Distribution
Services
Lee M. Stewart 55 President - Energy Transportation
Services and Corporate Secretary
Richard M. Morrow 51 Vice President
Roy M. Rawlings 56 Vice President
Anne S. Smith 47 Vice President
* As of December 31, 2000
Each Executive Officer has been an officer of SoCalGas or one of its
affiliates for more than five years.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 11 is incorporated by reference from
"Election of Directors" and "Executive Compensation" in the
Information Statement prepared for the May 2001 annual meeting of
shareholders.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT
The information required by Item 12 is incorporated by reference from
"Election of Directors" in the Information Statement prepared for the
May 2001 annual meeting of shareholders.
49
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
None.
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K
(a) The following documents are filed as part of this report:
1. Financial statements
Page in
This Report
Independent Auditors' Report . . . . . . . . . . . . . . 25
Statements of Consolidated Income for the years
ended December 31, 2000, 1999 and 1998 . . . . . . . . 26
Consolidated Balance Sheets at December 31,
2000 and 1999. . . . . . . . . . . . . . . . . . . . . 27
Statements of Consolidated Cash Flows for the
years ended December 31, 2000, 1999 and 1998 . . . . . 29
Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 2000, 1999 and 1998 . . . . . . . . . . . 30
Notes to Consolidated Financial Statements . . . . . . . 31
2. Financial statement schedules
The following documents may be found in this report at the
indicated page numbers.
Independent Auditors' Consent . . . . . . . . . . . . . 51
Any other schedules for which provision is made in Regulation S-X
are not required under the instructions contained therein or are
inapplicable.
3. Exhibits
See Exhibit Index on page 53 of this report.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed after September 30, 2000.
50
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration
Statement Nos. 333-45537, 33-51322, 33-53258, 33-59404, and 33-
52663 of Southern California Gas Company on Forms S-3 of our report
dated January 26, 2001 (February 27, 2001, as to Note 3), appearing
in this Annual Report on Form 10-K of Southern California Gas
Company for the year ended December 31, 2000.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
March 9, 2001
51
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be
signed on its behalf by the undersigned, hereunto duly authorized.
SOUTHERN CALIFORNIA GAS COMPANY
By: /s/ Edwin A. Guiles
Edwin A. Guiles
Chairman, Chief Financial Officer
and President
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report is signed below by the following persons on behalf of the
Registrant in the capacities and on the dates indicated.
Name/Title Signature Date
Principal Executive Officer:
Edwin A. Guiles
Chairman, President /s/ Edwin A. Guiles March 6, 2001
Principal Financial Officer:
Edwin A. Guiles
Chief Financial Officer /s/ Edwin A. Guiles March 6, 2001
Principal Accounting Officer:
Edwin A. Guiles
Chief Financial Officer /s/ Edwin A. Guiles March 6, 2001
Directors:
Edwin A. Guiles
Chairman /s/ Edwin A. Guiles March 6, 2001
Hyla H. Bertea, Director /s/ Hyla H. Bertea March 6, 2001
Ann L. Burr, Director /s/ Ann L. Burr March 6, 2001
Herbert L. Carter, Director /s/ Herbert L. Carter March 6, 2001
Richard A. Collato, Director /s/ Richard A. Collato March 6, 2001
Daniel W. Derbes, Director /s/ Daniel W. Derbes March 6, 2001
Wilford D. Godbold, Jr., Director /s/ Wilford D. Godbold, Jr. March 6, 2001
William D. Jones, Director /s/ William D. Jones March 6, 2001
Ralph R. Ocampo, Director /s/ Ralph R. Ocampo March 6, 2001
William G. Ouchi, Director /s/ William G. Ouchi March 6, 2001
Richard J. Stegemeier, Director /s/ Richard J. Stegemeier March 6, 2001
Thomas C. Stickel, Director /s/ Thomas C. Stickel March 6, 2001
Diana L. Walker, Director /s/ Diana L. Walker March 6, 2001
52
EXHIBIT INDEX
The Forms 8-K, 10-K and 10-Q referred to herein were filed under
Commission File Number 1-14201 (Sempra Energy), Commission File Number
1-40 (Pacific Enterprises) and/or Commission File Number 1-1402
(Southern California Gas Company).
Exhibit 3 -- By-Laws and Articles Of Incorporation
3.01 Restated Articles of Incorporation of Southern California Gas Company
(Southern California Gas Company 1996 Form 10-K; Exhibit 3.01).
3.02 Bylaws of Southern California Gas Company dated September 1, 1998
(Southern California Gas Company 1998 Form 10-K; Exhibit 3.02).
Exhibit 4 -- Instruments Defining The Rights Of Security Holders
The Company agrees to furnish a copy of each such instrument to the
Commission upon request.
4.01 Specimen Preferred Stock Certificates of Southern California Gas
Company (Southern California Gas Company 1980 Form 10-K; Exhibit 4.01).
4.02 First Mortgage Indenture of Southern California Gas Company to American
Trust Company dated as of October 1, 1940 (Registration Statement No.
2-4504 filed by Southern California Gas Company on September 16, 1940;
Exhibit B-4).
4.03 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of July 1, 1947 (Registration Statement No. 2-7072
filed by Southern California Gas Company on March 15, 1947; Exhibit B-5).
4.04 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of August 1, 1955 (Registration Statement No.
2-11997 filed by Pacific Lighting Corporation on October 26, 1955;
Exhibit 4.07).
4.05 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of June 1, 1956 (Registration Statement No.
2-12456 filed by Southern California Gas Company on April 23, 1956;
Exhibit 2.08).
4.06 Supplemental Indenture of Southern California Gas Company to Wells Fargo
Bank, National Association dated as of August 1, 1972 (Registration
Statement No. 2-59832 filed by Southern California Gas Company on
September 6, 1977; Exhibit 2.19).
4.07 Supplemental Indenture of Southern California Gas Company to Wells Fargo
Bank, National Association dated as of May 1, 1976 (Registration
Statement No. 2-56034 filed by Southern California Gas Company on April
14, 1976; Exhibit 2.20).
4.08 Supplemental Indenture of Southern California Gas Company to Wells Fargo
Bank, National Association dated as of September 15, 1981 (Pacific
Lighting Corporation 1981 Form 10-K; Exhibit 4.25).
53
4.09 Supplemental Indenture of Southern California Gas Company to
Manufacturers Hanover Trust Company of California, successor to Wells
Fargo Bank, National Association, and Crocker National Bank as
Successor Trustee dated as of May 18, 1984 (Southern California Gas
Company 1984 Form 10-K; Exhibit 4.29).
4.10 Supplemental Indenture of Southern California Gas Company to Bankers
Trust Company of California, N.A., successor to Wells Fargo Bank,
National Association dated as of January 15, 1988 (Pacific Lighting
Corporation 1987 Form 10-K; Exhibit 4.11).
4.11 Supplemental Indenture of Southern California Gas Company to First
Trust of California, National Association, successor to Bankers Trust
Company of California, N.A. dated as of August 15, 1992 (Registration
Statement No. 33-50826 filed by Southern California Gas Company on August
13, 1992; Exhibit 4.37).
4.12 Specimen 7 3/4% Series Preferred Stock Certificate (Southern California
Gas Company 1992 Form 10-K; Exhibit 4.15).
Exhibit 10 -- Material Contracts
Compensation
10.01 Sempra Energy Deferred Compensation and Excess Savings Plan
effective January 1, 2000 (2000 Sempra Energy Form 10-K
Exhibit 10.07).
10.02 Sempra Energy Supplemental Executive Retirement Plan as amended
and restated effective July 1, 1998. (1998 Sempra Energy Form 10-K
Exhibit 10.09).
10.03 Sempra Energy Executive Incentive Plan effective June 1, 1998.
(1998 Sempra Energy Form 10-K Exhibit 10.11).
10.04 Sempra Energy Executive Deferred Compensation Agreement
effective June 1, 1998. (1998 Sempra Energy Form 10-K Exhibit 10.12).
10.05 Sempra Energy 1998 Long Term Incentive Plan (Incorporated by reference
from the Registration Statement on Form S-8 Sempra Energy Registration
No. 333-56161 dated June 5, 1998 (Exhibit 4.1)).
10.06 Amended and Restated Pacific Enterprises Employee Stock Option Plan
(Southern California Gas Company 1996 Form 10-K; Exhibit 10.10).
Exhibit 12 -- Statement Re: Computation of Ratios
12.01 Computation of Ratio of Earnings to Fixed Charges for the years
ended December 31, 2000, 1999, 1998, 1997 and 1996.
Exhibit 21 -- Subsidiaries
21.01 Schedule of Subsidiaries at December 31, 2000.
Exhibit 23 -- Independent Auditors' Consent, page 51.
54
GLOSSARY
AFUDC Allowance for Funds Used During
Construction
BCAP Biennial Cost Allocation Proceeding
Bcf Billion Cubic Feet (of natural gas)
CA/AZ California/Arizona
CPUC California Public Utilities Commission
Enova Enova Corporation
EPA Environmental Protection Agency
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GCIM Gas Cost Incentive Mechanism
IDBs Industrial Development Bonds
IOUs Investor-Owned Utilities
mmbtu Million British Thermal Units (of natural gas)
PBR Performance-Based Ratemaking/Regulation
PD Proposed Decision
PE Pacific Enterprises, the Company's parent
PG&E Pacific Gas and Electric Company
PRP Potential Responsible Party
SAB Staff Accounting Bulletin
SDG&E San Diego Gas & Electric Company
SEC Securities and Exchange Commission
SFAS Statement of Financial Accounting Standards
SoCalGas Southern California Gas Company
UEG Utility Electric Generation
VaR Value at Risk
55
EXHIBIT 12.1
SOUTHERN CALIFORNIA GAS
COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES
(Dollars in millions)
|
1996 |
1997 |
1998 |
1999 |
2000 |
|
|
Fixed Charges: |
|||||
|
Interest |
$88 |
$88 |
$81 |
$62 |
$72 |
|
Interest Portion of Annual Rentals |
5 ------ |
5 ------ |
4 ------ |
3 ------ |
4 ------ |
|
Total Fixed Charges For Purpose of Ratio |
$93 |
$93 |
$85 |
$65 |
$76 |
|
Earnings: |
|||||
|
Pretax income from continuing operations |
$349 |
$416 |
$287 |
$383 |
$390 |
|
Add: |
|||||
|
Fixed charges (from above) |
93 |
93 |
85 |
65 |
76 |
|
Less: Fixed charges capitalized |
2 |
1 |
1 |
2 |
2 |
|
Fixed charges net of |
91 |
92 |
84 |
63 |
74 |
|
Total Earnings for Purpose of |
$440 |
$508 |
$371 |
$446 |
$464 |
|
Ratio of Earnings to Fixed Charges |
4.73 |
5.46 |
4.36 |
6.86 |
6.11 |
EXHIBIT 21.01
SOUTHERN CALIFORNIA GAS COMPANY
Schedule of Subsidiaries at December 31, 2000
Subsidiary State of Incorporation
- ---------- ----------------------
Ecotrans OEM Corporation California
Southern California Gas Tower California