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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
[X] Annual report pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the fiscal year ended December 31, 1999
--------------------
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
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(Exact name of registrant as specified in its charter)
CALIFORNIA 1-1402 95-1240705
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(State of incorporation (Commission (I.R.S. Employer
or organization) File Number) Identification No.
555 WEST FIFTH STREET, LOS ANGELES, CALIFORNIA 90013
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(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:
Series Y, due 2021; Series Z, due 2002;
Series BB, due 2023; Series DD, due 2023; New York
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 56. Glossary on page 58.
Aggregate market value of the voting preferred stock held by non-
affiliates of the registrant as of February 29, 2000 was
$13.8 million.
Registrant's common stock outstanding as of February 29, 2000 was
wholly owned by Pacific Enterprises.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Information Statement prepared for the May 2000
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 . . . . . . . . . . . . . . . . 11
Item 6. Selected Financial Data. . . . . . . . . . . . . . . . 12
Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations . . . . . . . . 12
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk . . . . . . . . . . . . . . . . . 25
Item 8. Financial Statements and Supplementary Data. . . . . . 26
Item 9. Changes In and Disagreements with Accountants on
Accounting and Financial Disclosure . . . . . . . . 53
PART III
Item 10. Directors and Executive Officers of the Registrant . . 53
Item 11. Executive Compensation . . . . . . . . . . . . . . . . 53
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . 54
Item 13. Certain Relationships and Related Transactions . . . . 54
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . 54
Signatures. . . . . . . . . . . . . . . . . . . . . . . . . . . 55
Exhibit Index . . . . . . . . . . . . . . . . . . . . . . . . . 56
Glossary. . . . . . . . . . . . . . . . . . . . . . . . . . . . 58
This 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" and "should" or similar expressions, or discussions of strategy
or of plans are intended to identify forward-looking statements that
involve risks, uncertainties and assumptions. Future results may
differ materially from those expressed in these forward-looking
statements.
These 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 and regulatory conditions and
developments; technological developments; capital market conditions;
inflation rates; interest rates; exchange rates; energy markets,
including the timing and extent of changes in commodity prices;
weather conditions; business and regulatory or legal decisions; the
pace of deregulation of retail natural gas and electricity delivery;
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 236 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 2041.
State Regulation
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 throughout this report.
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 18.1 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, through its two business units.
One business unit focuses on core distribution customers (primarily
residential customers) and the other on large volume gas
transportation customers. Natural gas service is also provided on a
wholesale basis to the distribution systems of the City of Long
Beach, affiliated company SDG&E and Southwest Gas Corporation.
Supplies of Natural Gas
The Company buys natural gas under several short-term and long-term
contracts. Short-term purchases are based on monthly-spot-market
prices. The Company has firm pipeline capacity contracts with
pipeline companies that expire at various dates through 2006.
Most of the natural gas purchased and delivered by the Company is
produced outside of California. These supplies are delivered to the
Company's intrastate transmission system by interstate pipeline
companies, primarily El Paso Natural Gas Company and Transwestern
Natural Gas Company. These interstate companies provide
transportation services for supplies purchased from other sources by
the Company or its transportation customers. The rates that
interstate pipeline companies may charge for natural gas and
transportation services are regulated by the FERC. Existing pipeline
capacity into California exceeds current demand by over 1 billion
cubic feet (bcf) per day. The implications of this excess are
described in "Management's Discussion and Analysis of Financial
Condition and Results of Operations" herein.
The following table shows the sources of natural gas deliveries from
1995 through 1999.
Year Ended December 31
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1999 1998 1997 1996 1995
- -------------------------------------------------------------------------------------------------------------
Gas Purchases (billions of cubic feet)
Spot market 315 270 229 226 206
Long-term 74 101 95 96 99
California producers 2 3 5 12 29
------- ------- ------- ------- -------
Total Purchases 391 374 329 334 334
Customer-Owned and Exchange Receipts 637 637 614 518 620
Storage Withdrawal
(Injection) - net (6) (28) (3) 42 (13)
Company Use and
Unaccounted For (16) (21) (10) (10) (4)
------- ------- ------- ------- -------
Net Deliveries 1,006 962 930 884 937
======= ======= ======= ======= =======
Cost of Gas Purchased (millions of dollars)
Commodity costs $ 916 $ 774 $ 849 $ 627 $ 478
Fixed charges* 147 174 250 276 264
------- ------- ------- ------- -------
Total Purchases $1,063 $ 948 $1,099 $ 903 $ 742
======= ======= ======= ======= =======
Average Cost of Purchases
(dollars per thousand cubic feet)** $2.34 $2.07 $ 2.58 $1.88 $1.42
======= ======= ======= ======= =======
* 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 81
percent of total natural gas volumes purchased by the Company
during 1999, as compared with 72 percent and 70 percent during 1998
and 1997, respectively. These supplies were generally purchased at
prices significantly below those of long-term fixed-price sources
of supply.
During 1999, the Company delivered 1,006 bcf of natural gas through
its system. Approximately 63 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 5.0 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 aggregate transportation customers are permitted to aggregate
their natural gas requirement and, up to a CPUC-imposed limit of 10
percent of the Company's core market, to purchase natural gas
directly from brokers or producers. The Company continues to be
obligated to purchase reliable supplies of natural gas to serve the
requirements of its core customers.
Noncore customers have the option of purchasing natural gas
either from the Company or from other sources, such as brokers
or producers, for delivery through the Company's transmission
and distribution system. The only natural gas supplies that the
Company may offer for sale to noncore customers are the same
supplies that it purchases for its core customers. Most noncore
customers procure their own natural gas supply.
In 1999, 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, 1999, the Company was storing
approximately 22 bcf of customer-owned gas.
Demand for Natural Gas
Natural gas is a principal energy source for residential,
commercial, industrial and UEG customers. Natural gas competes with
electricity for residential and commercial cooking, water heating,
space heating and clothes drying, and with other fuels for large
industrial, commercial and UEG uses. Growth in the natural gas
markets is largely dependent upon the health and expansion of the
southern California economy. The Company added approximately 74,000
and 46,000 new customer meters in 1999 and 1998, respectively,
representing growth rates of approximately 1.5 percent and 0.9
percent, respectively. The Company expects its growth for 2000 will
continue at about the 1999 level.
During 1999, 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 1999 was only 1,500, it accounted for 13 percent of
the authorized natural gas revenues and 57 percent of total natural
gas volumes. External factors such as weather, electric
deregulation, the use of hydro-electric power, competing pipeline
bypass and general economic conditions can result in significant
shifts in this market. 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 and purchased by the
Company's UEG customers. 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. UEG customer
demand decreased in 1998 as a result of decreased demand for
electricity.
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
the 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 from the
Company's service area.
Other
Additional information concerning customer demand and other aspects
of natural gas operations is provided under "Management's
Discussion and Analysis of Financial Condition and Results of
Operations" and in Notes 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 SoCalGas' profitability. The natural gas
industry is currently undergoing a transition to increased
competition.
Natural Gas Industry Restructuring
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. In January 1998, the CPUC released a staff
report initiating a project to assess the current market and
regulatory framework for California's natural gas industry.
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 by 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)
To promote efficient operations and improved productivity and to
move away from reasonableness reviews and disallowances, the CPUC
has been directing utilities to use PBR. PBR has replaced the
general rate case and certain other regulatory proceedings for
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.
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 subject to the limitations of the Gas Cost
Incentive Mechanism (GCIM) discussed 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.
Affiliate Transactions
In December 1997, the CPUC adopted rules establishing uniform
standards of conduct governing the manner in which California
investor-owned utilities (IOUs) conduct business with their
affiliates. Information on affiliate transactions 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
utilities' 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,
including hazardous substances, 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
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 potential responsible party (PRP) for
two landfill sites and three industrial waste disposal sites, from
which releases have occurred as described below.
In December 1999, SoCalGas was notified that it is a PRP at the
Gibson Oil 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 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, 1999, 13 of these
sites have been remediated, of which 10 have received certification
from the California Environmental Protection Agency. Preliminary
investigations, at a minimum, have been completed on 39 of the gas
plant sites.
At December 31, 1999, SoCalGas' estimated remaining investigation
and remediation liability related to hazardous waste sites,
including the manufactured-gas plant sites detailed above, was $64
million, of which 90 percent is authorized to be recovered through
the Hazardous Cost Substance Recovery Account. 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.
OTHER MATTERS
Year 2000
Sempra Energy established an overall company-wide Year 2000
readiness effort that included SoCalGas. There were only a few,
very minor year 2000 interruptions to the Company's automated
systems and applications with suppliers and customers. Sempra
Energy incurred expenses of $48 million (including $7.6 million in
1999) for its Year 2000 readiness effort and expects to incur no
additional costs.
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 cost
associated with RD&D. An annual average of $9 million has been
spent for the last three years.
Employees of Registrant
As of December 31, 1999 SoCalGas had 6,079 employees, compared to
6,148 at December 31, 1998.
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, 2000. Negotiations for a new agreement are
ongoing.
ITEM 2. PROPERTIES
Natural Gas Properties
At December 31, 1999, SoCalGas owned 2,854 miles of transmission
and storage pipeline, 44,595 miles of distribution pipeline and
44,211 miles of service piping. It also owned 10 transmission
compressor stations and 6 underground storage reservoirs (with a
combined working capacity of approximately 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
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.
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
The CPUC regulates SoCalGas' capital structure, limiting the
dividends it may pay. At December 31, 1999, $267 million of
SoCalGas' retained earnings was available for future dividends.
ITEM 6. SELECTED FINANCIAL DATA
(Dollars in millions)
At December 31, or for the years then ended
------------------------------------------------
1999 1998 1997 1996 1995
-------- ------- ------- ------- -------
Income Statement Data:
Operating Revenues $2,569 $2,427 $2,641 $2,422 $2,279
Operating Income $ 268 $ 238 $ 318 $ 286 $ 300
Dividends on Preferred Stock $ 1 $ 1 $ 7 $ 8 $ 12
Earnings Applicable to
Common Shares $ 200 $ 158 $ 231 $ 193 $ 203
Balance Sheet Data:
Total Assets $3,532 $3,834 $4,205 $4,354 $4,462
Long-Term Debt $ 939 $ 967 $ 968 $1,090 $1,220
Short-Term Debt (a) $ 30 $ 75 $ 498 $ 409 $ 329
Shareholders' Equity $1,310 $1,382 $1,467 $1,487 $1,645
(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.
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 1997 through 1999, and provides information
about the capital resources, liquidity and financial performance of
Southern California Gas Company (SoCalGas or the Company). This
section also focuses on the major factors expected to influence
future operating results and discusses investment and financing
plans. It should be read in conjunction with the consolidated
financial statements included in this Annual Report.
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 17.6 million.
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.
There were no business-combination costs in 1999. 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 continue to be 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 include capital investments in plant.
Additional information on sources and uses of cash during the
last three years is summarized in the following condensed statement
of consolidated cash flows:
- ------------------------------------------------------------
SOURCES AND (USES) OF CASH
Year Ended December 31
(Dollars in millions) 1999 1998 1997
- ------------------------------------------------------------
Operating Activities $ 483 $ 782 $ 396
-------------------------
Investing Activities:
Capital expenditures (146) (128) (159)
Other 17 22 40
-------------------------
Total Investing Activities (129) (106) (119)
-------------------------
Financing Activities:
Dividends paid (279) (166) (258)
Redemption of preferred stock -- (75) --
Long-term debt - net (75) (73) (122)
Short-term debt - net -- (351) 89
-------------------------
Total Financing Activities (354) (665) (291)
-------------------------
Increase (decrease) in cash
and cash equivalents $ -- $ 11 $ (14)
- ------------------------------------------------------------
Cash Flows From Operating Activities
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 lower expenses incurred in connection with the
PE/Enova business combination and lower income tax payments in
1999.
The increase in cash flows from operating activities in 1998
was primarily due to higher throughput compared to 1997, combined
with natural gas costs that were lower than amounts being collected
in rates, which resulted in overcollected regulatory balancing
accounts at year-end 1998. This increase was partially offset by
expenses incurred in connection with the PE/Enova business
combination.
Cash Flows From Investing Activities
Cash flows from investing activities primarily represent capital
investment in plant.
Capital expenditures increased in 1999 primarily due to
internal software development projects during 1999.
Capital expenditures were $31 million lower in 1998 primarily
due to the shifting of certain functions to Sempra Energy following
the PE/Enova business combination.
Capital expenditures are estimated to be $220 million in 2000.
They will be financed primarily by internally generated funds.
Cash Flows From Financing Activities
Net cash used in financing activities decreased in 1999 primarily
due to lower short-term debt repayments compared to the same period
in 1998 and the repurchase of preferred stock in 1998, partially
offset by greater dividends to the parent in 1999.
Net cash used in financing activities increased in 1998 due to
greater short-term debt repayments and the redemption of preferred
stock in 1998, partially offset by lower long-term debt issuances.
Long-Term and Short-Term Debt
In 1999, cash was used for the repayment of $75 million of
unsecured notes.
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 repayment of $94 million
of debt issued to finance the Comprehensive Settlement (see Note 11
of the notes to Consolidated Financial Statements
Stock Redemption
On February 2, 1998, SoCalGas redeemed all of its 7 3/4% Series
Preferred Stock at a cost of $25.09 per share, or $75.3 million
including accrued dividends.
Dividends
Dividends paid to parent amounted to $278 million in 1999, compared
to $165 million in 1998 and $251 million in 1997.
The payment of future dividends and the amount thereof are
within the discretion of the board of directors.
Capitalization
Total capitalization at December 31, 1999 was $2.3 billion. The
debt to capitalization ratio was 43 percent at December 31, 1999
and 1998 and 50 percent in December 31, 1997. The decrease in 1998
compared to 1997 was primarily due to the repayment of short-term
debt.
Cash and Cash Equivalents
Cash and cash equivalents were $11 million at December 31, 1999.
The Company anticipates that operating cash required in 2000 for
capital expenditures, common stock dividends and debt payments will
be provided by cash generated from operating activities.
In addition to cash from ongoing operations, the Company has
multi-year credit agreements that permit term borrowings of up to
$400 million. At December 31, 1999 all bank lines of credit were
unused. For further discussion, 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.
Ratemaking Procedures
To understand the operations and financial results of the Company
it is important to understand the ratemaking procedures that the
Company follows.
The Company is regulated by the California Public Utility
Commission (CPUC). It is the responsibility of the CPUC to
determine that utilities operate in the best interests of their
customers and have the opportunity to earn a reasonable return on
investment. In response to utility-industry restructuring, the
Company has received approval from the CPUC for Performance-Based
Regulation (PBR).
Under PBR, regulators allow income potential to be tied to
achieving or exceeding specific performance and productivity
measures, rather than relying solely on expanding utility plant in
a market where a utility already has a highly developed
infrastructure. See additional discussion of PBR in Note 11 of the
notes to Consolidated Financial Statements.
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. In August 1998, California enacted a law
prohibiting the CPUC from enacting any natural gas industry
restructuring decision for core (residential and small commercial)
customers prior to January 2000. During the implementation
moratorium, the CPUC held hearings throughout the state and intends
to give the legislature a draft ruling before adopting a final
market-structure policy.
See additional discussion of natural gas-industry
restructuring below in "Industry Restructuring" and in Note 11 of
the notes to Consolidated Financial Statements.
Results of Operations
1999 Compared to 1998
Net income for 1999 increased to $201 million compared to net
income of $159 in 1998. The increase is primarily due to $35
million, after-tax, of PE/Enova business combination expenses in
1998.
Utility natural gas revenues increased 6 percent in 1999
primarily due to lower overcollections in 1999 and higher utility
electric generation (UEG) revenues, partially offset by a decrease
in residential and 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 13
percent in 1999, largely due to an increase in UEG volumes
transported.
Operating expenses decreased 8 percent in 1999, primarily due
to the lower business combination costs (none in 1999 compared to
$60 million pretax 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.
1998 Compared to 1997
Net income for 1998 decreased to $159 million, compared to net
income of $238 million in 1997. The decrease in net income is
primarily due to the costs associated with the PE/Enova business
combination and lower base margin established at SoCalGas in its
PBR decision which became effective on August 1, 1997 (see Note 11
of the notes to Consolidated Financial Statements). The expense
related to the business combination was $35 million, aftertax, for
1998. There were no business combination costs in 1997.
Utility natural gas revenues decreased 8 percent in 1998
primarily due to the lower natural gas margin established in the
SoCalGas' PBR decision, a decrease in the average cost of natural
gas and a decrease in sales to utility electric-generation
customers. This was partially offset by increased sales to
residential customers due to colder weather in 1998.
The Company's cost of natural gas distributed decreased 16
percent in 1998, largely due to a decrease in the average price of
natural gas purchased, partially offset by increases in sales
volume.
Operating expenses increased 12 percent in 1998, primarily due
to the higher business-combination costs ($60 million pretax in
1998, compared to none in 1997).
For the fourth quarter of 1998, net income decreased to $38
million from $51 million for the fourth quarter of 1997. The
decrease is primarily due to an increase in business-combination
and operating expenses in 1998.
Operating Results
The table below summarizes the components of utility natural gas
and electric volumes and revenues by customer class for 1999, 1998
and 1997.
GAS SALES, TRANSPORTATION & EXCHANGE
(Dollars in millions, volumes in billion cubic feet)
Gas Sales Transportation & Exchange Total
----------------------------------------------------------------------
Throughput Revenue Throughput Revenue Throughput Revenue
----------------------------------------------------------------------
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
- ---------------------------------------------------------------------------------------------
1997:
Residential 237 $1,726 3 $ 10 240 $1,736
Commercial and Industrial 80 502 314 255 394 757
Utility Electric Generation - - 158 76 158 76
Wholesale 138 67 138 67
-----------------------------------------------------------------------
317 $2,228 613 $408 930 2,636
Balancing accounts and other 5
---------
Total $2,641
- ---------------------------------------------------------------------------------------------
Other Income, Interest Expense and Income Taxes
Other Income
Other income, which primarily consists of interest income from
short-term investments and regulatory-balancing accounts, decreased
to an expense of $7 million in 1999 compared to income of $1
million in 1998. The change 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. Other
income was $7 million in 1997. The change of $6 million in 1998 was
primarily due to higher regulatory interest expense in 1997.
Interest Expense
Interest expense for 1999 decreased to $60 million in 1999 from $80
million in 1998. The decrease is primarily due to the reversal of
interest expense in 1999 as a result of favorable tax rulings.
Interest expense was $87 million for 1997. The decrease of $7
million in 1998 is primarily due the repayment of short-term debt
in 1998.
Income Taxes
Income tax expense was $182 million, $128 million and $178 million
for the years ended December 31, 1999, 1998 and 1997, respectively.
The effective income tax rates were 48 percent, 45 percent and 43
percent for the same periods. The increase is due to the increase
in income before taxes. See Note 5 of the notes to the Consolidated
Financial Statements for additional information.
Factors Influencing Future Performance
Performance of the Company in the near future will depend primarily
on ratemaking and regulatory process, electric and natural gas
industry restructuring, and the changing energy marketplace. These
and other factors are summarized below.
Industry Restructuring
The natural gas industry experienced an initial phase of
restructuring during the 1980s by deregulating natural gas sales to
noncore customers. On January 21, 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.
In August 1998, California enacted a law prohibiting the CPUC
from enacting any natural gas-industry restructuring decision for
core customers prior to January 1, 2000. During the implementation
moratorium, the CPUC held hearings throughout the state and intends
to give the legislature a draft ruling before adopting a final
market-structure policy. The Company has been actively
participating in this effort and has argued in support of
competition intended to maximize benefits to customers rather than
to protect competitors.
In October 1999, the State of California enacted a law (AB
1421) which requires that 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 gas from a
non-utility 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.
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. Effective March 31, 1998, California consumers
were given the option of selecting their electric energy
provider from a variety of local and out-of-state producers.
Although the 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 from the Company's service area.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to
move away from reasonableness reviews and disallowances, the CPUC
has been directing utilities to use PBR. PBR has replaced the
general rate case and certain other regulatory proceedings for the
Company. Under PBR, regulators require future income potential to
be tied to achieving or exceeding specific performance and
productivity goals, as well as cost reductions, rather than by
relying solely on expanding utility plant in a market where a
utility already has a highly developed infrastructure. See
additional discussion of PBR in Note 11 of the notes to
Consolidated Financial Statements.
Accounting Standards
SoCalGas accounts for the economic effects of regulation on all of
its utility operations in accordance with Statement of Financial
Accounting Standards (SFAS) No. 71, "Accounting for the Effects of
Certain Types of Regulation." Under SFAS No. 71, a regulated entity
records a regulatory asset if it is probable that, through the
ratemaking process, the utility will recover the asset from
customers. Regulatory liabilities represent future reductions in
revenues for amounts due to customers. See Notes 2 and 11 of the
notes to Consolidated Financial Statements for additional
information.
Affiliate Transactions
On December 16, 1997, the CPUC adopted rules establishing uniform
standards of conduct governing the manner in which California IOUs
conduct business with their affiliates. The objective of these
rules, which became effective January 1, 1998, is to ensure that
the utilities' energy affiliates do not gain an unfair advantage
over other competitors in the marketplace and that utility
customers do not subsidize affiliate activities.
The CPUC excluded utility-to-utility transactions between
SoCalGas and SDG&E from the affiliate-transaction rules in its
March 1998 decision approving the PE/Enova business combination.
See Notes 1 and 11 of the notes to Consolidated Financial
Statements for additional information.
Allowed Rate of Return
For 2000, 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, which are unchanged from 1999. The Company can earn more
than the authorized rate by controlling costs below approved
levels, by experiencing increased volumes of sales not subject to
balancing accounts (both of which are subject to revenue sharing,
as described in Note 11 of the notes to Consolidated Financial
Statements) or by achieving favorable results in certain areas,
such as incentive mechanisms that are not subject to revenue
sharing. See additional discussion in Note 11 of the notes to
Consolidated Financial Statements.
Management Control of Expenses and Investment
In the past, management has been able to control operating expenses
and 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.
Noncore Bypass
SoCalGas is fully at risk for 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 has received authorization from the
CPUC for expedited review of long-term natural gas transportation
service contracts with some noncore customers at lower-than-tariff
rates. In addition, the CPUC approved changes in the methodology
that eliminates subsidization of core customer rates by noncore
customers. This allocation flexibility, 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 the lost revenue.
Through July 31, 1999, any 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 will be 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
Existing interstate pipeline capacity into California exceeds
current demand by over one billion cubic feet (Bcf) per day. This
situation has reduced the market value of the capacity well below
the Federal Energy Regulatory Commission's (FERC) tariffs. 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 that cannot be
remarketed. 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 marketed
at significant discounts. 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.
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.
Because the potential situations in which the Company is faced
with environmental issues are in connection with utility
operations, capital costs to comply with environmental requirements
are generally recovered through the depreciation components of
customer rates. California utilities' customers also 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
wastes, 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
amount 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 (13 completed as of
December 31, 1999 and 29 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).
Derivative Financial Instruments
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 reputable firms and major
exchanges. The use of these instruments exposes the Company to
market and credit risks. At times, credit risk may be concentrated
with certain counterparties, although counterparty nonperformance
is not anticipated.
The Company 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 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.
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 is a discussion of the Company's primary market-
risk exposures as of December 31, 1999, including a discussion of
how these exposures are managed.
Interest-Rate Risk
The Company is exposed to fluctuations in interest rates primarily
as a result of its fixed-rate long-term debt. The Company has
historically funded 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.
A portion of the Company's borrowings are denominated in
foreign currencies, which expose the Company to market risk
associated with exchange-rate movements. The Company has hedged
this foreign-currency cash exposure through a swap transaction
entered into with a major international bank.
The VaR on the Company's fixed-rate long-term debt is
estimated at approximately $99 million as of December 31, 1999,
assuming a one-year holding period.
Energy-Price Risk
Market risk related to physical commodities is based upon potential
fluctuations in natural gas and electricity prices and basis. The
Company's market risk is impacted by changes in volatility and
liquidity in the markets in which these instruments are traded. The
Company is exposed, in varying degrees, to price risk in the
natural gas 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, 1999, the
total VaR of SoCalGas's natural gas positions was not material.
Credit Risk
Credit risk relates to the risk of loss that would be incurred as a
result of nonperformance by counterparties pursuant to the terms of
their contractual obligations. The Company avoids concentration of
counterparties and maintains credit policies with regard to
counterparties that management believes significantly minimize
overall credit risk. These policies include an evaluation of
potential counterparties' financial condition (including credit
rating), collateral requirements under certain circumstances, and
the use of standardized agreements that allow for the netting of
positive and negative exposures associated with a single
counterparty.
The Company monitors credit risk through a credit-approval
process and the assignment and monitoring of credit limits. These
credit limits are established based on risk and return
considerations under terms customarily available in the industry.
Year 2000 Issues
Sempra Energy established an overall company-wide Year 2000
readiness effort that included SoCalGas. There were only a few,
very minor year 2000 interruptions to the Company's automated
systems and applications with suppliers and customers. Sempra
Energy incurred expenses of $48 million (including $7.6 million in
1999) for its Year 2000 readiness effort and expects to incur no
additional costs.
New Accounting Standards
In June 1998, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards (SFAS) No. 133
"Accounting for Derivative Instruments and Hedging Activities." In
June 1999, the effective date of this statement was deferred for
one year. As amended, SFAS 133, which is effective for the Company
on January 1, 2001, requires that an entity recognize all
derivatives as either assets or liabilities in the statement of
financial position, measure those instruments at fair value and
recognize changes in the fair value of derivatives in earnings in
the period of change unless the derivative qualifies as an
effective hedge that offsets certain exposures. The effect of this
standard on the Company's Consolidated Financial Statements has not
yet been determined.
Information Regarding Forward-Looking Statements
This 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" and "should" or similar expressions or discussions
of strategy or of plans are intended to identify forward-looking
statements that involve risks and uncertainties and assumptions.
Future results may differ materially from those expressed in these
forward-looking statements.
These 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 and regulatory
conditions and developments; technological developments; capital
market conditions; inflation rates; interest rates; exchange rates;
energy markets, including the timing and extent of changes in
commodity prices; weather conditions; business, regulatory or legal
decisions; the pace of deregulation of retail natural gas and
electricity delivery; 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.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required by Item 7A is set forth under "Item 7.
Management's Discussion and Analysis of Financial Condition and
Results of Operations - Market Risk Management Activities."
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Shareholders of Southern California
Gas Company:
We have audited the accompanying consolidated balance sheets
of Southern California Gas Company and subsidiaries as of December
31, 1999 and 1998, and the related statements of consolidated
income, changes in shareholders' equity, and cash flows for each of
the three years in the period ended December 31, 1999. These
financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted
auditing standards. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the
amounts and disclosures in the financial statements. An audit also
includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits
provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present
fairly, in all material respects, the financial position of
Southern California Gas Company and subsidiaries as of December 31,
1999 and 1998, and the results of their operations and their cash
flows for each of the three years in the period ended December 31,
1999 in conformity with generally accepted accounting principles.
/s/ DELOITTE & TOUCHE LLP
San Diego, California
February 4, 2000
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Dollars in millions
For the years ended December 31 1999 1998 1997
------ ------- -------
Operating Revenues $2,569 $2,427 $2,641
------ ------ ------
Expenses
Cost of natural gas distributed 1,032 913 1,088
Operation and maintenance 738 798 712
Depreciation 260 254 251
Income taxes 179 126 174
Other taxes and franchise payments 92 98 98
------ ------ ------
Total 2,301 2,189 2,323
------ ------ ------
Operating Income 268 238 318
------ ------ ------
Other Income and (Deductions)
Interest income 16 4 1
Regulatory interest (14) -- 15
Allowance for equity funds used during construction -- 3 2
Taxes on nonoperating income (3) (2) (4)
Other - net (6) (4) (7)
------ ------ ------
Total (7) 1 7
------ ------ ------
Income Before Interest Charges 261 239 325
------ ------ ------
Interest Charges
Long-term debt 74 75 82
Other interest (12) 6 6
Allowance for borrowed funds used during construction (2) (1) (1)
------ ------ ------
Total 60 80 87
------ ------ ------
Net income 201 159 238
Preferred Dividend Requirements 1 1 7
------ ------ ------
Earnings Applicable to Common Shares $ 200 $ 158 $ 231
====== ====== ======
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions
December 31,
1999 1998
---------- ----------
ASSETS
Utility plant - at original cost $6,177 $6,063
Accumulated depreciation (3,342) (3,111)
------ ------
Utility plant - net 2,835 2,952
------ ------
Current assets
Cash and cash equivalents 11 11
Accounts receivable - trade (less allowance for doubtful
receivables of $16 in 1999 and $17 in 1998) 285 440
Accounts and notes receivable - other 14 13
Due from affiliates 73 --
Deferred income taxes 25 157
Natural gas in storage 67 49
Materials and supplies 12 14
Prepaid expenses 15 14
------ ------
Total current assets 502 698
------ ------
Regulatory assets 155 173
Investments and other assets 40 11
------ ------
Total $3,532 $3,834
====== ======
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
Dollars in millions
December 31,
1999 1998
----------- -----------
CAPITALIZATION AND LIABILITIES
Capitalization
Common stock $ 835 $ 835
Retained earnings 447 525
Accumulated other comprehensive income 6 --
------ ------
Total common equity 1,288 1,360
Preferred stock 22 22
Long-term debt 939 967
------ ------
Total capitalization 2,249 2,349
------ ------
Current liabilities
Accounts payable - trade 159 153
Accounts payable - other 227 221
Accounts payable - affiliates -- 111
Regulatory balancing accounts overcollected - net 165 129
Other taxes payable 28 31
Accrued income taxes 4 30
Interest accrued 29 46
Current portion of long-term debt 30 75
Other 84 75
------ ------
Total current liabilities 726 871
------ ------
Customer advances for construction 27 31
Deferred income taxes - net 319 323
Deferred investment tax credits 56 58
Deferred credits and other liabilities 155 202
------ ------
Total deferred credits 557 614
------ ------
Contingencies and commitments (Note 10)
Total $3,532 $3,834
====== ======
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Dollars in millions
For the years ended December 31 1999 1998 1997
------ ------ ------
Cash Flows From Operating Activities
Net income $ 201 $ 159 $ 238
Adjustments to reconcile net income to net
cash provided by operating activities
Depreciation 260 254 251
Deferred income taxes (13) (50) (15)
Deferred investment tax credits (2) (3) (3)
Allowance for funds used during construction -- (4) (4)
Other (46) 1 (21)
Changes in working capital components
Accounts receivable 154 46 (86)
Regulatory balancing accounts 36 484 36
Gas in storage (18) (24) 3
Other current assets 1 (1) (1)
Accounts payable (18) (13) (87)
Accrued income taxes (26) (9) 50
Other taxes payable (3) 1 2
Deferred income taxes 132 (146) 21
Due to (from) affiliates (184) 81 (14)
Other current liabilities 9 6 26
------ ------ ------
Net cash provided by operating activities 483 782 396
------ ------ ------
Cash Flows from Investing Activities
Capital expenditures (146) (128) (159)
Other - net 17 22 40
------ ------ ------
Net cash used in investing activities (129) (106) (119)
------ ------ ------
Cash Flows from Financing Activities
Dividends paid (279) (166) (258)
Redemption of preferred stock -- (75) --
Issuance of long-term debt -- 75 120
Payment of long-term debt (75) (148) (242)
Increase (decrease) in short-term debt -- (351) 89
------ ------ ------
Net cash used in financing activities (354) (665) (291)
------ ------ ------
Net increase (decrease) -- 11 (14)
Cash and Cash Equivalents, January 1 11 -- 14
------ ------ ------
Cash and Cash Equivalents, December 31 $ 11 $ 11 $ --
====== ====== ======
Supplemental Disclosure of Cash Flow Information:
Income tax payments, net of refunds $ 100 $ 302 $ 132
====== ====== ======
Interest payments, net of amount capitalized $ 77 $ 86 $ 75
====== ====== ======
See notes to Consolidated Financial Statements.
SOUTHERN CALIFORNIA GAS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CHANGES IN SHAREHOLDERS' EQUITY
For the years ended December 31, 1999, 1998, 1997
(Dollars in millions)
| Accumulated
| Other Total
Comprehensive| Preferred Common Comprehensive Retained Shareholders'
Income | Stock Stock Income Earnings Equity
- --------------------------------------------------------------------------------------------------
|
Balance at December 31, 1996 | $ 97 $ 835 $ 555 $1,487
Net income/comprehensive income $ 238 | 238 238
Preferred stock dividends declared | (7) (7)
Common stock dividends declared | (251) (251)
- --------------------------------------------------------------------------------------------------
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 |
Available-for-sale securities 12 | $ 12 12
Pension (6) | (6) (6)
----- |
Comprehensive income $ 207 |
Preferred stock dividends declared | (1) (1)
Common stock dividends declared | (278) (278)
- --------------------------------------------------------------------------------------------------
Balance at December 31, 1999 $ 22 $ 835 $ 6 $ 447 $1,310
==================================================================================================
See notes to Consolidated Financial Statements.
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 (Parent).
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.
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 has been preparing 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 may record 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 their 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.
Regulatory Assets
Regulatory assets include unrecovered premium on early retirement
of debt, post-retirement benefit costs, deferred income taxes
recoverable in rates and other regulatory-related expenditures that
the Company expects to recover in future rates. See Note 11 for
additional information.
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 4.39, 4.36 and
4.35 in 1999, 1998 and 1997, respectively.
Inventories
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.
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
SFAS No. 130, "Reporting Comprehensive Income" requires reporting
of comprehensive income and its components (revenues, expenses,
gains and losses) in any complete presentation of general-purpose
financial statements. Comprehensive income describes 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. Securities
are so classified if the company uses the securities in its
cash/asset management program whereby the securities may be sold in
connection with interest rate changes and cash requirements. At
December 31, 1999, the company had one such investment, which
increased in value during 1999. That increase is recognized in the
"Statement of Consolidated Changes in Shareholders' Equity."
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, or
investments that are readily convertible to cash.
Basis of Presentation
Certain prior-year amounts have been reclassified to conform to the
current year's presentation.
New Accounting Standard
In June 1998, the Financial Accounting Standards Board issued SFAS
No. 133 "Accounting for Derivative Instruments and Hedging
Activities," which is effective for the Company on January 1, 2001.
The statement requires that an entity recognize all derivatives as
either assets or liabilities in the statement of financial
position, measure those instruments at fair value and recognize
changes in the fair value of derivatives in earnings in the period
of change unless the derivative qualifies as an effective hedge
that offsets certain exposures. The effect of this standard on the
Company's Consolidated Financial Statements has not yet been
determined.
NOTE 3: SHORT-TERM BORROWINGS
SoCalGas has a $400 million multi-year credit agreement. This
agreement expires in 2001 and bears interest at various rates based
on market rates and the Company's credit ratings. SoCalGas' lines
of credit are available to support commercial paper. At December
31, 1999 and 1998, SoCalGas' bank line of credit was unused.
NOTE 4: LONG-TERM DEBT
- -------------------------------------------------------------------
December 31,
(Dollars in millions) 1999 1998
- -------------------------------------------------------------------
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
6.210% Notes, November 7, 1999 -- 75
6.375% Notes, October 29, 2001 120 120
8.750% Notes, July 6, 2000 30 30
5.670% Notes, January 15, 2003 75 75
SFr. 15,695,000 6.375% Foreign Interest
Payment Securities, May 14, 2006 8 8
----------------------------
233 308
----------------------------
Total 983 1,058
Less:
Current portion of long-term debt 30 75
Unamortized debt discount on
long-term debt 14 16
----------------------------
Total $ 939 $ 967
- -------------------------------------------------------------------
Maturities of long-term debt are $30 million in 2000, $120 million
in 2001, $100 million in 2002, $175 million in 2003, $0 in 2004 and
$558 million thereafter. SoCalGas has CPUC authorization to issue
an additional $600 million in long-term debt.
First-Mortgage Bonds
First-mortgage bonds are secured by a lien on substantially all
utility plant. SoCalGas may issue additional first-mortgage bonds
upon compliance with the provisions of its bond indenture, which
permit, among other things, the issuance of an additional $750
million of first-mortgage bonds as of December 31, 1999.
Callable Bonds
At the Company's option, certain bonds may be called at a premium.
$150 million of the bonds are callable in 2001, $400 million in
2003 and $8 million in 2006.
Other Long-Term Debt
During 1998, SoCalGas issued $75 million of unsecured debt in
medium-term notes used to finance working capital requirements.
There were no new issues during 1999.
Currency Rate Swaps
In May 1996, SoCalGas issued SFr. 15,695,000 of 6.375% Foreign
Interest Payment Securities maturing on May 14, 2006. SoCalGas
hedged the currency exposure by entering into a swap transaction
with a major international bank. As a result, the bond issue,
interest payments and other ongoing costs were swapped for fixed
annual payments. The securities are renewable at ten-year intervals
at reset interest rates. The next put date for the securities is in
the year 2006.
NOTE 5: INCOME TAXES
The reconciliation of the statutory federal income tax rate to the
effective income tax rate is as follows:
- ------------------------------------------------------------------
1999 1998 1997
- ------------------------------------------------------------------
Statutory federal income tax rate 35.0% 35.0% 35.0%
Depreciation 6.8 9.4 5.5
State income taxes - net of
federal income tax benefit 7.3 4.7 6.3
Tax credits (0.6) (0.9) (0.7)
Other - net (1.0) (3.6) (3.3)
------------------------------
Effective income tax rate 47.5% 44.6% 42.8%
- ------------------------------------------------------------------
The components of income tax expense are as follows:
- ------------------------------------------------------------------
(Dollars in millions) 1999 1998 1997
- ------------------------------------------------------------------
Current:
Federal $36 $233 $138
State 13 64 38
------------------------------
Total current taxes 49 297 176
------------------------------
Deferred:
Federal 112 (128) 6
State 24 (38) (1)
------------------------------
Total deferred taxes 136 (166) 5
------------------------------
Deferred investment tax credits-net (3) (3) (3)
------------------------------
Total income tax expense $182 $128 $178
- ------------------------------------------------------------------
Accumulated deferred income taxes at December 31 result from the
following:
- ------------------------------------------------------------------
(Dollars in millions) 1999 1998
- ------------------------------------------------------------------
Deferred Tax Liabilities:
Differences in financial and
tax bases of utility plant $423 $449
Regulatory balancing accounts 16 -
Other 18 51
------------------------------
Total deferred tax liabilities 457 500
------------------------------
Deferred Tax Assets:
Investment tax credits 23 25
Regulatory balancing accounts - 51
Comprehensive settlement (see Note 11) 42 95
Other deferred liabilities 98 153
Other - 10
------------------------------
Total deferred tax assets 163 334
------------------------------
Net deferred income tax liability 294 166
- ------------------------------------------------------------------
The net liability is recorded on the consolidated balance sheet as
follows:
- ------------------------------------------------------------------
(Dollars in millions) 1999 1998
- ------------------------------------------------------------------
Current asset $ (25) $(157)
Non-current liability 319 323
- ------------------------------------------------------------------
Total $ 294 $ 166
- -------------------------------------------------------------------
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 were transferred from the Company's
plans to plans of related entities. In connection therewith, the
Company recorded a $51 million special termination benefit in 1998.
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) 1999 1998 1999 1998
- ---------------------------------------------------------------------------------
Weighted-Average Assumptions
as of December 31:
Discount rate 7.75% 6.75% 7.75% 6.75%
Expected return on plan assets 8.00% 8.50% 8.00% 8.50%
Rate of compensation increase 5.00% 5.00% 5.00% 5.00%
Cost trend of covered
health-care charges - - 7.75%(1) 8.00%(1)
Change in Benefit Obligation:
Net benefit obligation at
January 1 $1,156 $1,378 $ 446 $ 463
Service cost 28 33 11 12
Interest cost 77 95 30 31
Plan participants' contributions - - 1 1
Plan amendments - 16 - -
Actuarial gain (120) (10) (62) (5)
Transfer of liability (2) (6) (204) - (43)
Special termination benefits - 48 - 3
Gross benefits paid (78) (200) (18) (16)
-----------------------------------------------
Net benefit obligation at
December 31 1,057 1,156 408 446
-----------------------------------------------
Change in Plan Assets:
Fair value of plan assets
at January 1 1,595 1,834 379 343
Actual return on plan assets 453 286 77 61
Employer contributions 1 1 24 30
Plan participants' contributions - - 1 1
Transfer of assets (2) - (326) - (40)
Gross benefits paid (78) (200) (18) (16)
-----------------------------------------------
Fair value of plan assets
at December 31 1,971 1,595 463 379
-----------------------------------------------
Funded status at December 31 914 439 55 (67)
Unrecognized net actuarial gain (969) (518) (156) (53)
Unrecognized prior service cost 45 50 - (1)
Unrecognized net transition
obligation 3 3 110 119
-----------------------------------------------
Net asset (liability)
at December 31 $ (7) $ (26) $ 9 $ (2)
- ---------------------------------------------------------------------------------
(1) Decreasing to ultimate trend of 6.50% in 2004.
(2) To reflect transfer of plan assets and liability to Sempra Energy
plan for Company employees transferred to Sempra Energy.
The following table provides the components of net periodic benefit
cost (income) for the plans:
- ---------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
-----------------------------------------------
(Dollars in millions) 1999 1998 1997 1999 1998 1997
- ---------------------------------------------------------------------------------
Service cost $ 28 $ 33 $ 32 $ 11 $ 12 $ 13
Interest cost 77 95 95 30 31 30
Expected return on assets (112) (128) (120) (27) (24) (20)
Amortization of:
Transition obligation 1 1 1 9 9 9
Prior service cost 4 3 3 - - -
Actuarial gain (14) (12) (10) - - -
Special termination benefit - 48 13 - 3 2
Settlement credit - (30) - - - -
Regulatory adjustment 17 - - 24 9 -
-----------------------------------------------
Total net periodic benefit cost $ 1 $ 10 $ 14 $ 47 $ 40 $ 34
- ---------------------------------------------------------------------------------
The following table provides the amounts recognized on the
SoCalGas balance sheet at December 31.
- -------------------------------------------------------------------------------------
Other
Pension Benefits Postretirement Benefits
----------------------------------------------
(Dollars in millions) 1999 1998 1999 1998
- -------------------------------------------------------------------------------------
Prepaid benefit cost - - $ 9 -
Accrued benefit cost $ (1) $(20) - $(2)
Additional minimum liability (2) (6) - -
Intangible asset 2 - - -
Accumulated other
comprehensive income (6) - - -
- -------------------------------------------------------------------------------------
Net liability (7) (26) 9 (2)
- -------------------------------------------------------------------------------------
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 $8 $ (7)
Effect on the health care component of the
accumulated postretirement benefit obligation $61 $(55)
- ------------------------------------------------------------------------
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 $12 million and $9 million, respectively, as of
December 31, 1999, and $15 million and $12 million, respectively,
as of December 31, 1998.
Other postretirement benefits include medical benefits for
retirees and their spouses (and Medicare Part B reimbursement for
certain retirees), and retiree life insurance.
Savings Plans
SoCalGas 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. The employee's contributions, at the direction of the
employees, are primarily invested in Sempra Energy stock, mutual
funds or guaranteed investment contracts. Employer contributions,
after one year of completed service, are made in 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. Employer contributions for the SoCalGas plan are
partially funded by the Sempra Energy Employee Stock Ownership Plan
and Trust (formerly Pacific Enterprises Employee Stock Ownership
Plan and Trust). Annual expense for the savings plans was $6
million in 1999, $7 million in 1998 and $7 million in 1997.
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, Statement of Financial Accounting Standards (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 its disclosure-only requirements and continue
to account for stock-based compensation in accordance with the
provisions of accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees."
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, the subsidiaries record an expense for
the plans. SoCalGas recorded expenses of $4 million in each of 1998
and 1997. In 1999 SoCalGas' share of the plans' income was $4 million.
NOTE 8: FINANCIAL INSTRUMENTS
Fair Value
The fair values of the Company's financial instruments 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 are $1.0 billion and $0.9 billion, respectively,
at December 31, 1999, and $1.1 billion each at December 31, 1998.
The carrying amounts and fair values of preferred stock are $22
million and $17 million, respectively, at December 31, 1999, and
$22 million and $8 million, respectively, at December 31, 1998. The
fair values of the first-mortgage and other bonds and preferred
stock are estimated based on quoted market prices. The fair values
of long-term notes payable are based on the present value of the
future cash flows, discounted at rates available for similar notes
with comparable maturities.
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's regulated operations use energy derivatives for price
risk management purposes within certain limitations imposed by
Company policies and regulatory requirements.
SoCalGas 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. For the years ended December 31, 1999,
1998 and 1997, gains and losses from natural gas futures contracts
are not material to SoCalGas' financial statements.
NOTE 9: SHAREHOLDERS' EQUITY
- -----------------------------------------------------------------
December 31,
(Dollars in millions) 1999 1998
- -----------------------------------------------------------------
COMMON EQUITY:
Common stock, without par value,
authorized 100,000,000 shares,
91,300,000 shares outstanding $ 835 $ 835
Retained earnings 447 525
Accumulated other comprehensive income 6 --
--------------------------
Total common equity $ 1,288 $ 1,360
- -----------------------------------------------------------------
All shares of SoCalGas common stock are wholly owned by Pacific
Enterprises.
- -----------------------------------------------------------------
December 31,
(Dollars in millions) 1999 1998
- -----------------------------------------------------------------
PREFERRED STOCK:
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
---------------
$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 $0.09 of dividends accruing to the date of redemption. The
total cost to SoCalGas was approximately $75.3 million.
Dividend Restrictions
The CPUC regulates SoCalGas' capital structure, limiting the
dividends it may pay. At December 31, 1999, $267 million of
SoCalGas' retained earnings was available for future dividends.
NOTE 10: CONTINGENCIES AND COMMITMENTS
Natural Gas Contracts
SoCalGas buys natural gas under several short-term and long-term
contracts. Short-term purchases are primarily from various U.S.
Southwest and Canadian gas suppliers, and are based on monthly
spot-market prices. In 1998, SoCalGas restructured its long-term
commodity purchase contracts with suppliers of California offshore
and Canadian gas. These new purchase contracts expire at the end of
2003. SoCalGas has commitments for firm pipeline capacity under
contracts with pipeline companies that expire at various dates
through the year 2006. These agreements provide for payments of an
annual reservation charge. SoCalGas recovers such fixed charges in
rates.
At December 31, 1999, the future minimum payments under
natural gas contracts were:
- -----------------------------------------------------------------
Storage and
(Dollars in millions) Transportation Natural Gas
- -----------------------------------------------------------------
2000 $ 182 $ 399
2001 184 165
2002 186 170
2003 186 158
2004 183 -
Thereafter 315 -
----------------------------------
Total minimum payments $1,236 $ 892
- -----------------------------------------------------------------
Total payments under the contracts were $1.1 billion in 1999,
$0.9 billion in 1998, and $1.1 billion in 1997.
Leases
SoCalGas has operating leases on real and personal property
expiring at various dates from 2000 to 2029. The rentals payable
under these leases are determined on both fixed and percentage
bases, and most leases contain options to extend, which are
exercisable by SoCalGas.
The minimum rental commitments payable in future years under
all noncancellable leases are:
- -----------------------------------------------------------------
Operating
(Dollars in millions) Leases
- -----------------------------------------------------------------
2000 $ 28
2001 27
2002 29
2003 27
2004 28
Thereafter 219
- -----------------------------------------------------------------
Total future rental commitment $ 358
- -----------------------------------------------------------------
Rent expense totaled $39 million in 1999, $43 million in
1998 and $44 million in 1997.
Other Commitments and Contingencies
December 31, 1999, commitments for capital expenditures were
approximately $8 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. SoCalGas 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.
SoCalGas' capital expenditures to comply with environmental laws
and regulations were $1 million in each of 1999, 1998 and 1997, and
are not expected to be significant over the next five years.
SoCalGas has been associated with various sites which may
require remediation under federal, state or local environmental laws.
SoCalGas 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.
Litigation
The Company is involved in various legal matters, including those
arising out of the ordinary course of business. 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
The Company 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 gas sales to noncore
customers. On January 21, 1998, the CPUC issued 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.
In August 1998, California enacted a law prohibiting the CPUC
from enacting any natural gas industry restructuring decision for
core (residential and small commercial) customers prior to January
1, 2000. During the implementation moratorium, the CPUC held
hearings throughout the state and intends to give the legislature a
draft ruling before adopting a final market-structure policy.
SoCalGas has been actively participating in this effort and has
argued in support of competition intended to maximize benefits to
customers rather than to protect competitors.
In October 1999, the State of California enacted a law (AB
1421) which requires that 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 gas from a
non-utility provider. The law prohibits the CPUC from further
unbundling of 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.
Performance-Based Regulation (PBR)
To promote efficient operations and improved productivity and to
move away from reasonableness reviews and disallowances, the CPUC
has been directing utilities to use PBR. PBR has replaced the
general rate case and certain other regulatory proceedings for
SoCalGas. Under PBR, regulators require future income potential to
be tied to achieving or exceeding specific performance and
productivity measures, as well as cost reductions, rather than
relying solely on expanding utility plant in a market where a
utility already has a highly developed infrastructure.
SoCalGas' PBR mechanism is in effect through December 31,
2002; however, the CPUC decision allows for the possibility that
changes to its mechanism could be adopted in its 1999 Biennial Cost
Allocation Proceeding decision, which is anticipated during the
second quarter of 2000. SoCalGas' PBR mechanism is scheduled to be
updated at December 31, 2002, at which time it will be updated for,
among other things, changes in costs and volumes. Key elements of
the mechanism include an initial reduction in base rates, an
indexing mechanism that limits future rate increases to the
inflation rate less a productivity factor, a sharing mechanism with
customers if earnings exceed the authorized rate of return on rate
base, and rate refunds to customers if service quality
deteriorates. Specifically, the key elements of the mechanism
include the following:
- -- Earnings up to 25 basis points in excess of the authorized rate
of return on rate base are retained 100 percent by shareholders.
Earnings that exceed the authorized rate of return on rate base by
greater than 25 basis points are shared between customers and
shareholders on a sliding scale that begins with 75 percent of the
additional earnings being given back to customers and declining to
0 percent as earned returns approach 300 basis points above
authorized amounts. There is no sharing if actual earnings fall
below the authorized rate of return. In 1999, SoCalGas was
authorized to earn a 9.49 percent return on its rate base. The same
rate of return is authorized for 2000.
- -- Base rates are indexed based on inflation less an estimated
productivity factor.
- -- Performance indicators, including employee safety, customer
satisfaction, and call-center responsiveness, affect the Company's
future income potential. The SoCalGas mechanism authorizes
penalties up to $4 million annually, or more in certain, limited
situations.
- -- The SoCalGas mechanism allows for pricing flexibility for
residential and small commercial customers, with any shortfalls in
revenue being borne by shareholders and with any increase in
revenue shared between shareholders and customers.
- -- Annual cost of capital proceedings are replaced by an automatic
adjustment mechanism if changes in certain indices exceed
established tolerances. The SoCalGas mechanism 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.
Comprehensive Settlement Of Natural Gas Regulatory Issues
In July 1994, the CPUC approved a comprehensive settlement for
SoCalGas (Comprehensive Settlement) of a number of regulatory
issues, including rate recovery of a significant portion of the
restructuring costs associated with certain long-term contracts
with suppliers of California-offshore and Canadian natural gas. In
the past, the cost of these supplies had been substantially in
excess of SoCalGas' average delivered cost for all natural gas
supplies. The restructured contracts substantially reduced the
ongoing delivered costs of these supplies. The Comprehensive
Settlement permitted SoCalGas to recover in utility rates
approximately 80 percent of the contract-restructuring costs of
$391 million and accelerated amortization of related pipeline
assets of approximately $140 million, together with interest,
incurred prior to January 1, 1999. 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 is being replaced by the PBR
mechanism as adopted in the 1999 Biennial Cost Allocation
Proceeding (BCAP). The CPUC's proposed decision on the 1999 BCAP
would allow balancing account treatment for 75 percent of noncore
revenues.
- --The Gas Cost Incentive Mechanism (GCIM) for evaluating SoCalGas'
natural gas purchases substantially replaced the previous process
of reasonableness reviews. In December 1998 the CPUC extended the
GCIM program indefinitely.
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
SoCalGas totaling $13 million. In June 1999, SoCalGas filed its
annual GCIM application with the CPUC requesting an award of $8
million for the annual period ended March 31, 1999. A CPUC decision
is expected during the second quarter of 2000.
Biennial Cost Allocation Proceeding (BCAP)
In the second quarter of 1997, the CPUC issued a decision on
SoCalGas' 1996 BCAP filing. In this decision, the CPUC considered
SoCalGas' relinquishments of interstate pipeline capacity on the El
Paso and Transwestern pipelines. This resulted in a reduction in
the pipeline demand charges allocated to SoCalGas' customers and
surcharges allocated to firm capacity holders through pipeline
rate-case settlements adopted at the FERC. However FERC is
reviewing the decision.
On November 4, 1999, the CPUC issued a decision on the 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 will be reflected in the rates adopted in
the final 1999 BCAP decision.
In October 1998, SoCalGas filed its 1999 BCAP application
requesting that new rates become effective August 1, 1999 and
remain in effect through December 31, 2002. The proposed beginning
date follows the conclusion of SoCalGas' Comprehensive Settlement
(discussed above), and the proposed end date aligns with the
expiration of its current PBR. On January 11, 2000, the CPUC issued
a proposed decision adopting an overall decrease in natural gas
revenues of $208 million for SoCalGas. A final CPUC decision is
expected in the second quarter of 2000.
Cost Of Capital
For 2000, SoCalGas 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 1999, unless interest-rate changes are large enough to
trigger an automatic adjustment as discussed above under
"Performance-Based Regulation."
Transactions Between Utilities and Affiliated Companies
On December 16, 1997, the CPUC adopted rules, effective January 1,
1998, establishing uniform standards of conduct governing the
manner in which California's investor-owned utilities (IOUs)
conduct business with their energy-related affiliates. The
objective of the affiliate-transaction rules is to ensure that
these affiliates do not gain an unfair advantage over other
competitors in the marketplace and that utility customers do not
subsidize affiliate activities. The rules establish standards
relating to non-discrimination, disclosure and information
exchange, and separation of activities. The CPUC excluded utility-
to-utility transactions between SDG&E and SoCalGas from the
affiliate-transaction rules in its March 1998 decision approving
the business combination of Enova and PE, which is described in
Note 1.
Other affiliates sold and transported natural gas to the
Company under tariffs approved by the FERC. Billings for the
purchases totaled $0 in 1999 and $252 million in each of the years
1998 and 1997. The decrease in 1999 is due to the sale of the
related facilities and contracts in late 1998.
During 1999, 1998 and 1997, the Company sold natural gas
transportation and storage services to SDG&E in the amount of $50
million to $60 million per year. These sales were at rates
established by the CPUC.
NOTE 12: SEGMENT INFORMATION
The Company has two separately managed reportable segments:
natural gas distribution, and natural gas transmission/storage.
The accounting policies of the segments are the same as those
described in Note 2, and segment performance is evaluated by
management based on reported operating income. Intersegment
transactions generally are recorded the same as sales or
transactions with third parties. Interest expense and income tax
expense are not allocated to the reportable segments. Interest
revenue is included in other income on the Statements of
Consolidated Income. It is not allocated to the reportable
segments and, therefore, is not presented in the tables below.
- --------------------------------------------------------------------
For the year ended December 31,
(Dollars in millions) 1999 1998 1997
- --------------------------------------------------------------------
Revenues:
Distribution $ 2,259 $ 2,159 $ 2,283
Transmission & storage 297 266 337
All other 13 2 21
------------------------------------
Total $ 2,569 $ 2,427 $ 2,641
------------------------------------
Depreciation and amortization:
Distribution $ 205 $ 200 $ 197
Transmission & storage 55 54 54
------------------------------------
Total $ 260 $ 254 $ 251
------------------------------------
Segment Income:
Distribution $ 355 $ 300 $ 383
Transmission & storage 76 64 87
All other 16 -- 22
------------------------------------
Total segment income 447 364 492
------------------------------------
Interest expense (60) (80) (87)
Income tax expense (182) (128) (178)
Nonoperating income (4) 3 11
------------------------------------
Net income $ 201 $ 159 $ 238
------------------------------------
- --------------------------------------------------------------------
At December 31, or for
the year then ended
1999 1998 1997
- --------------------------------------------------------------------
Assets:
Distribution $ 1,163 $ 2,373 $ 2,946
Transmission & storage 1,746 1,184 1,207
All other 623 277 52
------------------------------------
Total $ 3,532 $ 3,834 $ 4,205
------------------------------------
Capital Expenditures:
Distribution $ 100 $ 92 $ 110
Transmission & storage 17 15 24
All other 29 21 25
------------------------------------
Total $ 146 $ 128 $ 159
------------------------------------
Geographic Information:
Long-lived assets
United States $ 2,868 $ 2,955 $ 3,077
- --------------------------------------------------------------------
NOTE 13: QUARTERLY FINANCIAL DATA (UNAUDITED)
Quarter ended
-------------------------------------------------------
Dollars in millions March 31 June 30 September 30 December 31
- ---------------------------------------------------------------------------------------
1999
Operating revenues $ 607 $ 624 $ 562 $ 776
Operating expenses 537 560 494 710
-----------------------------------------------------
Operating income $ 70 $ 64 $ 68 $ 66
-----------------------------------------------------
Net income $ 47 $ 47 $ 48 $ 59
Dividends on preferred stock - 1 - -
-----------------------------------------------------
Net income applicable
to common shares $ 47 $ 46 $ 48 $ 59
=====================================================
1998
Operating revenues $ 664 $ 578 $ 520 $ 665
Operating expenses 594 537 449 609
-----------------------------------------------------
Operating income $ 70 $ 41 $ 71 $ 56
-----------------------------------------------------
Net income $ 48 $ 19 $ 54 $ 38
Dividends on preferred stock 1 - - -
-----------------------------------------------------
Net income applicable
to common shares $ 47 $ 19 $ 54 $ 38
=====================================================
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 2000 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
- -------------------------------------------------------------------
Warren I. Mitchell 62 Chairman and President
Lee M. Stewart 54 Senior Vice President and
Corporate Secretary;
President-Energy Transportation
Services
Debra L. Reed 43 Senior Vice President and
Chief Financial Officer;
President-Energy Distribution
Services
Richard M. Morrow 50 Vice President
Roy M. Rawlings 55 Vice President
Anne S. Smith 46 Vice President
George E. Strang 60 Vice President
* As of December 31, 1999
Each Executive Officer has been an officer of SoCalGas 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 2000 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 2000 annual meeting of shareholders.
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 . . . . . . . . . . . . . . 26
Statements of Consolidated Income for the years
ended December 31, 1999, 1998 and 1997 . . . . . . . . 27
Consolidated Balance Sheets at December 31,
1999 and 1998. . . . . . . . . . . . . . . . . . . . . 28
Statements of Consolidated Cash Flows for the
years ended December 31, 1999, 1998 and 1997 . . . . . 30
Statements of Consolidated Changes in
Shareholders' Equity for the years ended
December 31, 1999, 1998 and 1997 . . . . . . . . . . . 31
Notes to Consolidated Financial Statements . . . . . . . 32
2. Financial statement schedules
None.
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 56 of this report.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed after September 30, 1999.
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/ Warren I. Mitchell
.
Warren I. Mitchell
Chairman 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 Officers:
Warren I. Mitchell
Chairman, President /s/ Warren I. Mitchell March 7, 2000
Principal Financial Officer:
Debra L. Reed
Senior Vice President,
Chief Financial Officer /s/ Debra L. Reed March 7, 2000
Principal Accounting Officer:
Debra L. Reed
Senior Vice President,
Chief Financial Officer /s/ Debra L. Reed March 7, 2000
Directors:
Warren I. Mitchell
Chairman /s/ Warren I. Mitchell March 7, 2000
Hyla H. Bertea, Director /s/ Hyla H. Bertea March 7, 2000
Ann L. Burr, Director /s/ Ann L. Burr March 7, 2000
Herbert L. Carter, Director /s/ Herbert L. Carter March 7, 2000
Richard A. Collato, Director /s/ Richard A. Collato March 7, 2000
Daniel W. Derbes, Director /s/ Daniel W. Derbes March 7, 2000
Wilford D. Godbold, Jr., Director /s/ Wilford D. Godbold, Jr. March 7, 2000
Robert H. Goldsmith, Director /s/ Robert H. Goldsmith March 7, 2000
William D. Jones, Director /s/ William D. Jones March 7, 2000
Ignacio E. Lozano, Jr., Director /s/ Ignacio E. Lozano, Jr. March 7, 2000
Ralph R. Ocampo, Director /s/ Ralph R. Ocampo March 7, 2000
William G. Ouchi, Director /s/ William G. Ouchi March 7, 2000
Richard J. Stegemeier, Director /s/ Richard J. Stegemeier March 7, 2000
Thomas C. Stickel, Director /s/ Thomas C. Stickel March 7, 2000
Diana L. Walker, Director /s/ Diana L. Walker March 7, 2000
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).
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 Supplemental Executive Retirement Plan as amended
and restated effective July 1, 1998. (1998 Sempra Energy Form 10-K
Exhibit 10.09).
10.02 Sempra Energy Executive Incentive Plan effective June 1, 1998.
(1998 Sempra Energy Form 10-K Exhibit 10.11).
10.03 Sempra Energy Executive Deferred Compensation Agreement
effective June 1, 1998. (1998 Sempra Energy Form 10-K Exhibit 10.12).
10.04 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)).
10.05 Amended and Restated Pacific Enterprises Employee Stock Option Plan
(Southern California Gas Company 1996 Form 10-K; Exhibit 10.10).
Exhibit 21 -- Subsidiaries
21.01 Schedule of Subsidiaries at December 31, 1999.
Exhibit 23 -- Consents Of Experts And Counsel
23.01 Independent Auditors' Consent
Exhibit 27 -- Financial Data Schedule
27.01 Financial Data Schedule for the year ended December 31, 1999.
GLOSSARY
AFUDC Allowance for Funds Used During
Construction
BCAP Biennial Cost Allocation Proceeding
Bcf Billion Cubic Feet (of natural gas)
CPUC California Public Utilities Commission
Enova Enova Corporation
FASB Financial Accounting Standards Board
FERC Federal Energy Regulatory Commission
GCIM Gas Cost Incentive Mechanism
IDBs Industrial Development Bonds
IOUs Investor-Owned Utilities
ORA Office of Ratepayer Advocates
PBR Performance-Based Ratemaking/Regulation
PE Pacific Enterprises, the Company's parent
PRP Potential Responsible Party
SDG&E San Diego Gas & Electric Company
SFAS Statement of Financial Accounting Standards
SoCalGas Southern California Gas Company
UEG Utility Electric Generation
VaR Value at Risk