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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934 [Fee Required]
For the fiscal year ended December 31, 1993
Commission file number 1-1402
SOUTHERN CALIFORNIA GAS COMPANY
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(Exact name of Registrant as specified in its charter)
California 95-1240705
- ------------------------ ---------------------------------
(State of incorporation) (IRS Employer Identification No.)
555 West Fifth Street, Los Angeles, California 90013-1011
- ---------------------------------------------- -------------
(Address of principal executive offices) (Zip Code)
(213) 244-1200
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(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
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Preferred stock Pacific Stock Exchange
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6% Cumulative
Preferred - Series A
7-3/4% Series Preferred Stock
First Mortgage Bonds New York Stock Exchange
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Series X, due 2020 (9-3/4%)
Series Y, due 2021 (8-3/4%)
Series Z, due 2002 (6-7/8%)
Series AA, due 1997 (6-1/2%)
Series BB, due 2023 (7-3/8%)
Series CC, due 1998 (5-1/4%)
Series DD, due 2023 (7-1/2%)
Series EE, due 2025 (6-7/8%)
Series FF, due 2003 (5-3/4%)
Securities registered pursuant to Section 12(g) of the Act: None
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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
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]
The aggregate market value of Registrant's voting stock (Preferred Stock) held
by non-affiliates at March 1, 1994, was approximately $196 million. This amount
excludes the market value of 49,369 shares of Preferred Stock held by
Registrant's parent, Pacific Enterprises. All of the Registrant's Common Stock
is owned by Pacific Enterprises.
DOCUMENTS INCORPORATED BY REFERENCE
Certain information in this Annual Report is incorporated by reference to
information contained or to be contained in other documents filed or to be filed
by Registrant with the Securities and Exchange Commission. The following table
identifies the information so incorporated in each Part of this Annual Report on
Form 10-K and the document in which it is or will be contained.
Information Incorporated
by Reference and Document
Annual Report in Which Information is or
On Form 10-K will be Contained
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Part III - Information contained under the captions
"Election of Directors", "Share Ownership of
Directors and "Executive Officers" and "Executive
Compensation" in Registrant's Information
Statement for its Annual Meeting of Shareholders
scheduled to be held on April 25, 1994.
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TABLE OF CONTENTS
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PART I
Item 1. Business ................................................... 5
Recent Developments ...................................... 6
Regulatory Activity ................................... 6
Restructuring of Gas
Supply Contracts ...................................... 6
Comprehensive Settlement of
Regulatory Issues ..................................... 7
Operating Statistics ..................................... 7
Service Area ............................................. 9
Utility Services ......................................... 10
Demand for Gas ........................................... 11
Supplies of Gas .......................................... 12
Rates and Regulation ..................................... 14
Environmental Matters .................................... 15
Employees .................................................. 16
Management ................................................. 17
Item 2. Properties ................................................. 18
Item 3. Legal Proceedings .......................................... 18
Item 4. Submission of Matters to a
Vote of Security Holders ................................... 18
PART II
Item 5. Market for Registrant's Common
Equity and Related Stockholder Matters ..................... 19
Item 6. Selected Financial Data .................................... 20
Item 7. Management's Discussion and Analysis
of Financial Condition and Results of
Operations ................................................. 20
Item 8. Financial Statements and
Supplementary Data ......................................... 31
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Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure ....................................... 57
PART III
Item 10. Directors and Executive Officers
of the Registrant .......................................... 57
Item 11. Executive Compensation ..................................... 57
Item 12. Security Ownership of Certain
Beneficial Owners and Management ........................... 57
Item 13. Certain Relationships and Related
Transactions ............................................... 57
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K .................................... 58
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PART I
ITEM 1. BUSINESS
Southern California Gas Company (The Gas Company or the Company) is a
public utility owning and operating a natural gas transmission, storage and
distribution system that supplies natural gas in 535 cities and communities
throughout a 23,000-square mile service territory comprising most of Southern
California and parts of Central California. The Gas Company is the principal
subsidiary of Pacific Enterprises (the "Parent").
The Gas Company is the nation's largest natural gas distribution utility.
It serves approximately 16 million residential, commercial, industrial, utility
electric generation and wholesale customers through approximately 4.7 million
meters in its service territory. Most of those meters represent "core"
customers, which are primarily residential and small commercial and industrial
accounts. The Gas Company's "noncore" customers are served by over 1,000
meters. Noncore customers consist of large-volume gas users such as electric
utilities, wholesale and large commercial and industrial customers capable of
switching from natural gas to alternate fuels or suppliers.
The Company is subject to regulation by the California Public Utilities
Commission (CPUC) which, among other things, establishes rates the Company may
charge for gas service, including an authorized rate of return on investment.
The Company's future earnings and cash flow will be determined primarily by the
allowed rate of return on common equity, growth in rate base, noncore pricing
and the variance in gas volumes delivered to these customers versus CPUC-adopted
forecast deliveries, the recovery of gas and contract restructuring costs if
the Comprehensive Settlement (see "Recent Developments - Comprehensive
Settlement of Regulatory Issues") is not approved and the ability of
management to control expenses and investment in line with the amounts
authorized by the CPUC to be collected in rates. Also, the Company's ability
to earn revenues in excess of its authorized return from noncore customers due
to volume increases will be substantially eliminated for the five years of the
Comprehensive Settlement referenced above. This is because forecasted
deliveries in excess of the 1991 throughput levels used to establish rates
were contemplated in estimating the costs of the Comprehensive Settlement, and
are reflected in current year liabilities. In addition, the impact of any
future regulatory restructuring and increased competitiveness in the industry,
including the continuing threat of customers bypassing the Company's system
and obtaining service directly from interstate pipelines, can affect the
Company's performance.
For 1994, the CPUC has authorized the Company to earn a rate of return on
rate base of 9.22 percent and a 11.00 percent rate of return on common equity
compared to 9.99 percent and 11.90 percent, respectively, in 1993. Growth in
rate base for 1993 was approximately 1.8 percent and rate base is expected to
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increase by approximately 4 percent to 5 percent in 1994. The Company has
achieved or exceeded its authorized return on rate base for the last eleven
consecutive years and its authorized rate of return on equity for the last nine
consecutive years.
The Gas Company was incorporated in California in 1910. Its principal
executive offices are located at 555 West Fifth Street, Los Angeles, California
90013 and its telephone number is (213) 244-1200.
RECENT DEVELOPMENTS
REGULATORY ACTIVITY
On December 17, 1993, the CPUC issued its decision in the Company's 1994
general rate case which authorized a net $97 million rate reduction. The
Company plans to adjust its operations with the intention of operating within
the amounts authorized in rates. Approximately $21 million of the rate
reduction represents productivity improvements. Other items include
non-operational issues, primarily reductions in marketing programs and income
tax effects of the rate reduction. The decision also includes the effects
of the reduction of the Company's rate of return authorized in its 1994
cost of capital proceeding, which increased the total reduction in rates to
$132 million. New rates emanating from the CPUC decision became effective
January 1, 1994.
RESTRUCTURING OF GAS SUPPLY CONTRACTS
The Company and its gas supply affiliates have reached agreements with
suppliers of California offshore and Canadian gas for a restructuring of
long-term gas supply contracts. The cost of these supplies to the Company has
been substantially in excess of its average delivered cost of gas. During 1993,
these excess costs totaled approximately $125 million.
The new agreements substantially reduce the ongoing delivered costs of
these gas supplies and provide lump sum settlement payments of $375 million to
the suppliers. The expiration date for the Canadian gas supply contract has
been shortened from 2012 to 2003, and the supplier of California offshore gas
continues to have an option to purchase related gas treatment and pipeline
facilities owned by the Company's gas supply affiliate. The agreement with the
suppliers of Canadian gas is subject to certain Canadian regulatory and other
approvals.
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COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES
The Gas Company and a number of interested parties, including the Division
of Ratepayer Advocates ("DRA") of the CPUC, large noncore customers and
ratepayer groups, have filed for CPUC approval a comprehensive settlement (the
"Comprehensive Settlement") of a number of pending regulatory issues including
partial rate recovery of restructuring costs associated with the gas supply
contracts discussed above. The Comprehensive Settlement, if approved by the
CPUC, would permit the Company to recover in utility rates approximately 80
percent of the contract restructuring costs of $375 million and accelerated
depreciation of related pipeline assets of its gas supply affiliates of
approximately $130 million, together with interest, over a period of
approximately five years. The Gas Company has filed a financing application
with the CPUC primarily for the borrowing of $425 million to provide for funds
needed under the Comprehensive Settlement. See "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations - Comprehensive
Settlement of Regulatory Issues" for a discussion of the regulatory issues, in
addition to the gas supply issues, addressed in the Comprehensive Settlement.
OPERATING STATISTICS
The following table sets forth certain operating statistics of the Company
from 1989 through 1993.
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OPERATING STATISTICS
Year Ended December 31,
------------------------------------------------------------------------------
1993 1992 1991 1990 1989
---- ---- ---- ---- ----
Gas Sales, Transportation & Exchange
Revenues (thousands of dollars):
Residential $1,652,562 $1,483,654 $1,673,837 $1,547,492 $1,484,099
Commercial/Industrial 853,579 836,672 977,065 1,057,030 1,016,267
Utility Electric Generation 147,208 194,639 148,573 235,102 482,747
Wholesale 116,737 128,881 144,779 164,716 191,817
Exchange 3,745 5,863 7,482 8,496 8,371
--------- --------- --------- --------- ---------
Total $2,773,831 $2,649,709 $2,951,736 $3,012,836 $3,183,301
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Volumes (millions of cubic feet):
Residential 247,507 243,920 249,522 261,887 255,414
Commercial/Industrial 339,706 363,124 460,368 436,330 400,554
Utility Electric Generation 212,720 220,642 170,043 158,985 201,845
Wholesale 147,978 149,232 141,931 139,034 145,923
Exchange 16,969 23,888 25,604 30,246 29,725
--------- --------- --------- --------- ---------
Total 964,880 1,000,806 1,047,468 1,026,482 1,033,461
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Sales 352,052 355,177 411,414 515,757 594,327
Transportation 595,859 621,741 610,450 480,479 409,409
Exchange 16,969 23,888 25,604 30,246 29,725
--------- --------- --------- --------- ---------
Total 964,880 1,000,806 1,047,468 1,026,482 1,033,461
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Revenues (per thousand cubic feet):
Residential $6.68 $6.08 $6.71 $5.91 $5.81
Commercial/Industrial $2.51 $2.30 $2.12 $2.42 $2.54
Utility Electric Generation $0.69 $0.88 $0.87 $1.48 $2.39
Wholesale $0.79 $0.86 $1.02 $1.18 $1.31
Exchange $0.22 $0.25 $0.29 $0.28 $0.28
Customers
Active Meters (at end of period):
Residential 4,459,250 4,445,500 4,429,896 4,381,563 4,295,838
Commercial 187,602 189,364 193,051 193,409 192,269
Industrial 23,924 24,419 25,642 26,530 26,957
Utility Electric Generation 8 8 8 8 7
Wholesale 3 2 2 2 2
--------- --------- --------- --------- ---------
Total 4,670,787 4,659,293 4,648,599 4,601,512 4,515,073
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Residential Meter Usage
(annual average):
Revenues $371 $334 $380 $356 $349
Volumes (thousands of cubic feet) 55.6 55.0 56.6 60.3 60.1
System Usage (millions of
cubic feet):
Average Daily Sendout 2,611 2,717 2,881 2,824 2,852
Peak Day Sendout 4,578 4,547 4,356 5,267 5,295
Sendout Capability
(at end of period) 7,371 7,419 7,073 7,073 7,027
Degree Days (1):
Number 1,255 (2) 1,258 1,409 1,432 1,344
Average (20 years) 1,433 1,458 1,474 1,506 1,509
Percent of Average 87.6% 86.3% 95.6% 95.1% 89.1%
Population of Service Area
(estimated at year end) 15,600,000 15,600,000 15,600,000 15,100,000 14,800,000
(1) The number of degree days for any period of time indicates whether the
temperature is relatively hot or cold. A degree day is recorded for each
degree the average temperature for any day falls below 65 degrees
Fahrenheit.
(2) Estimated calendar degree days.
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SERVICE AREA
The Gas Company distributes natural gas throughout a 23,000-square mile
service territory with a population of approximately 16 million people. As
indicated by the following map, its service territory includes most of Southern
California and portions of Central California.
[MAP]
Natural gas service is also provided on a wholesale basis to the distribution
systems of the City of Long Beach, San Diego Gas & Electric Company and
Southwest Gas Company.
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UTILITY SERVICES
The Gas Company's customers are divided, for regulatory purposes, into core
and noncore customers. Core customers are primarily residential and small
commercial and industrial customers, without alternative fuel capability.
Noncore customers are primarily electric utilities, wholesale and large
commercial and industrial customers, with alternative fuel capability.
The Gas Company offers two basic utility services, sale of gas and
transmission of gas. Residential customers and most other core customers
purchase gas directly from The Gas Company. Noncore customers and large core
customers have the option of purchasing gas either from The Gas Company or from
other sources (such as brokers or producers) for delivery through the Company's
transmission and distribution system. Smaller customers are permitted to
aggregate their gas requirements and also to purchase gas directly from brokers
or producers, up to a limit of 10 percent of the Company's core market. The Gas
Company generally earns the same contribution to earnings whether a particular
customer purchases gas from the Company or utilizes the Company's system for
transportation of gas purchased from others. (See "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of
Operations-Ratemaking Procedures.")
The Gas Company continues to be obligated to purchase reliable supplies of
natural gas to serve the requirements of its core customers. However, the only
gas supplies that the Company may offer for sale to noncore customers are the
same supplies that it purchases to serve its core customers. Noncore customers
that elect to purchase gas supplies from the Company must for a two-year period
agree to take-or-pay for 75 percent of the gas that they contract to purchase.
The Gas Company also provides a gas storage service for noncore customers
on a bid basis. The storage service program provides opportunities for
customers to store gas on an "as available" basis during the summer to reduce
winter purchases when gas costs are generally higher, or to reduce their level
of winter curtailment in the event temperatures are unusually cold. During
1993, The Gas Company stored approximately 24 billion cubic feet of
customer-owned gas.
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DEMAND FOR GAS
Natural gas is a principal energy source in the Company's service area for
residential, commercial and industrial uses as well as utility electric
generation (UEG) requirements. Gas competes with electricity for residential
and commercial cooking, water heating and space heating uses, and with other
fuels for large industrial, commercial and UEG uses. Demand for natural gas in
Southern California is expected to continue to increase but at a slower rate due
primarily to a slowdown in housing starts, new energy efficient building
construction and appliance standards and general recessionary business
conditions.
During 1993, 97 percent of residential energy customers in the Company's
service territory used natural gas for water heating and 94 percent for space
heating. Approximately 78 percent of those customers used natural gas for
cooking and over 72 percent for clothes drying.
Demand for natural gas by large industrial and UEG customers is very
sensitive to the price of alternative competitive fuels. These customers number
only approximately 1,000; however, during 1993, accounted for approximately 19
percent of total revenues, 65 percent of total gas volumes delivered and 15
percent of the authorized gas margin. Changes in the cost of gas or alternative
fuels, primarily fuel oil, can result in significant shifts in this market,
subject to air quality regulations. Demand for gas for UEG use is also affected
by the price and availability of electric power generated in other areas and
purchased by the Company's UEG customers.
Since the completion of the Kern River/Mojave Interstate Pipeline (Mojave)
in February 1992, the Company's throughput to customers in the Kern County area
who use natural gas to produce steam for enhanced oil recovery projects has
decreased significantly because of the bypass of the Company's system. Mojave
now delivers to customers formerly served by the Company 350 to 400 million
cubic feet of gas per day. The decrease in revenues from enhanced oil recovery
customers is subject to full balancing account treatment, except for a five
percent incentive to the Company for attaining certain throughput levels, and
therefore, does not have a material impact on earnings. However, bypass of
other Company markets also may occur as a result of plans by Mojave to extend
its pipeline north to Sacramento through portions of the Company's service
territory. The effect of bypass is to increase the Company's rates to other
customers and thus make its natural gas service less competitive with that of
competing pipelines and available alternate fuels.
In response to bypass, the Company has received authorization from the CPUC
for expedited review of price discounts proposed for long-term gas
transportation contracts
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with some noncore customers. In addition, in December 1992, the CPUC approved
changes in the methodology for allocating the Company's costs between core and
noncore customers to reduce the subsidization of core customer rates by noncore
customers. Effective in June 1993, these new rate changes implemented the
CPUC's policy known as "long-run marginal cost." The revised methodologies have
resulted in a reduction of noncore rates and a corresponding increase in core
rates that better reflect the cost of serving each customer class and, together
with price discounting authority, has enabled the Company to better compete with
interstate pipelines for noncore customers. In addition, in August 1993 a
capacity brokering program was implemented. Under the program, for a fee, the
Company provides to noncore customers, or others, a portion of its control of
interstate pipeline capacity to allow more direct access to producers. Also,
the Comprehensive Settlement (see "Recent Developments - Comprehensive
Settlement of Regulatory Issues") will help the Company's competitiveness
by reducing the cost of transportation service to noncore customers.
SUPPLIES OF GAS
In 1993, The Gas Company delivered slightly less than 1 trillion cubic feet
of natural gas through its system. Approximately 64 percent of these deliveries
were customer-owned gas for which The Gas Company provided transportation
services, compared to 65 percent in 1992. The balance of gas deliveries was gas
purchased by The Gas Company and resold to customers.
Most of the natural gas delivered by The Gas Company is produced outside of
California. These supplies are delivered to the California border by interstate
pipeline companies (primarily El Paso Natural Gas Company and Transwestern
Natural Gas Company) that produce or purchase the supplies or provide
transportation services for supplies purchased from other sources by The Gas
Company or its transportation customers. These supplies enter The Gas
Company's intrastate transmission system at the California border for delivery
to customers.
The Gas Company currently has paramount rights to daily deliveries of up to
2,200 million cubic feet of natural gas over the interstate pipeline systems of
El Paso Natural Gas Company (up to 1,450 million cubic feet) and Transwestern
Pipeline Company (up to 750 million cubic feet). The rates that interstate
pipeline companies may charge for gas and transportation services and other
terms of service are regulated by the Federal Energy Regulatory Commission
(FERC).
The following table sets forth the sources of gas deliveries by The Gas
Company from 1989 through 1993.
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SOURCES OF GAS
Year Ended December 31,
-------------------------------------------------------------------------
1993 1992 1991 1990 1989
------ ------ ------ ------ ------
Gas Purchases: (millions of cubic feet)
Market Gas:
30-Day 84,696 20,695 139,649 148,849 202,316
Other 159,197 198,049 168,486 225,710 161,078
--------- --------- --------- --------- ---------
Total Market Gas 243,893 218,744 308,135 374,559 363,394
El Paso Natural
Gas Company 7,288
Transwestern
Pipeline Company 87,475
Affiliates 96,559 99,226 98,566 103,406 104,097
California Producers &
Federal Offshore 28,107 42,262 39,613 52,633 54,145
--------- --------- --------- --------- ---------
Total Gas Purchased 368,559 360,232 446,314 530,598 616,399
Customer-Owned Gas
and Exchange Receipts 622,307 641,080 629,038 531,263 436,239
Storage Withdrawal
(Injection) - Net (9,498) 14,379 (8,451) (13,288) 1,010
Company Use and
Unaccounted For (16,488) (14,885) (19,432) (22,091) (20,185)
--------- --------- --------- --------- ---------
Net Gas Deliveries 964,880 1,000,806 1,047,469 1,026,482 1,033,463
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Gas Purchases: (thousands of dollars)
Commodity Costs $ 815,145 $ 805,550 $1,071,445 $1,371,854 $1,514,494
Fixed Charges * 397,714 397,579 358,294 405,233 430,242
Total Gas Purchases $1,212,859 $1,203,129 $1,429,739 $1,777,087 $1,944,736
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Average Cost of Gas Purchased
per thousand cubic feet** $2.21 $2.24 $2.40 $2.59 $2.46
* 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 the Company.
** The average commodity cost of gas purchased excludes fixed charges.
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Market sensitive 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 approximately 66 percent of total gas volumes
purchased by the Company during 1993, as compared with 61 percent and 69
percent, respectively, during 1992 and 1991. These supplies were generally
purchased at prices significantly below those for other long-term sources of
supply.
See "Item 7. "Management's Discussion and Analysis of Financial Condition
and Results of Operations - Comprehensive Settlement of Regulatory Issues" for a
discussion of the contemplated gas cost incentive mechanism.
The Gas Company estimates that sufficient natural gas supplies will be
available to meet the requirements of its customers into the next century.
Because of the many variables upon which estimates of future service are based,
however, actual levels of service may vary significantly from estimated levels.
RATES AND REGULATION
The Gas Company is regulated by the CPUC. The CPUC 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
in the best interest of the ratepayer with a reasonable profit. The regulatory
structure is complex and has a very substantial impact on the profitability of
the Company.
The return that the Company is authorized to earn is the product of the
authorized rate of return on rate base and the amount of rate base. Rate base
consists primarily of net investment in utility plant. Thus, the Company's
earnings are affected by changes in the authorized rate of return on rate base
and the growth in rate base and by the Company's ability to control expenses and
investment in rate base within the amounts authorized by the CPUC in setting
rates. In addition, the Company's ability to achieve its authorized rate of
return is affected by other regulatory and operating factors. See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Ratemaking Procedures."
The Gas Company's operating and fixed costs, including return on rate base,
are allocated between core and noncore customers under a methodology that is
based upon the costs incurred in serving these customer classes. For 1994,
approximately 87 percent of the CPUC-authorized gas margin has been allocated to
core customers and 13 percent to noncore customers, including wholesale
customers. Under the current regulatory framework, costs may be reallocated
between the core and the noncore markets once every other year in a biennial
cost allocation proceeding (BCAP).
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ENVIRONMENTAL MATTERS
The Gas Company has identified and reported to California environmental
authorities 42 former gas manufacturing sites for which it (together with other
utilities as to 21 of the sites) may have remedial obligations under
environmental laws. In addition, the Company is one of a large number of major
corporations that have been named by federal authorities as potentially
responsible parties for environmental remediation of two other industrial sites
and a landfill site. These 45 sites are in various stages of investigation or
remediation. It is anticipated that the investigation, and if necessary,
remediation of these sites will be completed over a period of from ten years to
twenty years.
The CPUC approved approximately $9 million in the Company's base rates for
expenditures beginning in 1990 through 1993 associated with investigating these
sites. In addition, the CPUC previously has approved a special ratemaking
procedure with respect to environmental remediation costs under which, upon
approval by the CPUC on a site-by-site basis, these costs are accumulated for
recovery in future rates subject to a reasonableness review. However, in a
decision issued in late 1992 in connection with its initial reasonableness
review of these costs, the CPUC concluded that the Company had failed to
demonstrate by clear and convincing evidence, the reasonableness for rate
recovery of the applied for remediation costs under the existing ratemaking
procedure. The decision concluded that a reasonableness review procedure may
not be appropriate for rate recovery of environmental remediation costs. In
addition, the CPUC ordered the Company, along with other California energy
utilities and the DRA, to work toward the development of an alternate ratemaking
procedure including cost sharing between shareholder and ratepayers.
In November 1993, a collaborative settlement agreement between the above
parties was submitted to the CPUC for approval that recommends a ratemaking
mechanism that would provide recovery of 90 percent of environmental
investigation and remediation costs without reasonableness review. In addition,
the utilities would have the opportunity to retain a percentage of any insurance
recoveries to offset the 10 percent of costs not recovered in rates. On March
10, 1994, an administrative law judge's proposed decision was issued which
adopted the sharing mechanism discussed above. A final CPUC decision is
expected in mid-1994.
Through the end of 1993, preliminary investigations at 33 sites have been
completed by the Company and remediation liabilities are estimated to be $82
million for all 45 sites. The liability estimated for these sites is subject to
future
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adjustment pending further investigation. (See Note 5 of Notes to Consolidated
Financial Statements set forth in Item 8 of this Annual Report.)
EMPLOYEES
The Company employs approximately 9,000 persons. Most field, clerical and
technical employees of the Company are represented by the Utility Workers' Union
of America, or the International Chemical Workers' Union. Collective bargaining
agreements covering these approximately 6,400 employees expired on June 30,
1993, principally as a consequence of failure to reach agreement with respect to
The Gas Company's proposal to permit the use of outside contractors for certain
services now being provided by union represented employees, if costs were not
lowered to an amount that would be incurred through the use of outside
contractors. In August 1993, after reaching an impasse, the Company
unilaterally implemented the majority of its proposals and after two failed
strike votes and further negotiations, the Union membership voted in February
1994 on a contract with terms consistent with that implemented by the Company.
On February 28, 1994, the Union notified the Company that the contract had been
ratified by the membership and a contract was signed on March 9, 1994. The
collective bargaining agreement with respect to wages and working conditions
will extend through March 31, 1996. The medical plan agreement will expire on
December 31, 1995.
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MANAGEMENT
The executive officers of Southern California Gas Company are as follows:
Became an
Executive
Name Age Position Officer
- ---- --- -------- ---------
Willis B. Wood 59 Presiding Director 8/93
Richard D. Farman 58 Chief Executive Officer 2/87
Warren I. Mitchell 56 President 8/81
Lloyd A. Levitin 61 Executive Vice President 6/93
and Chief Financial Officer
Lee K. Harrington 47 Senior Vice President 5/83
Frederick E. John 48 Senior Vice President 5/83
Nancy I. Day 49 Vice President 3/90
Leslie E. LoBaugh 48 Vice President and 4/93
General Counsel
Wilton E. Miller 57 Vice President 3/90
Mark C. Pocino 49 Vice President 3/90
Roy M. Rawlings 49 Vice President 1/87
Debra L. Reed 37 Vice President 8/88
Albert E. Russell 53 Vice President 6/89
Thomas S. Sayles 42 Vice President 1/94
Anne S. Smith 40 Vice President 11/91
Lee M. Stewart 48 Vice President 11/90
George E. Strang 54 Vice President 7/84
Ralph Todaro 43 Vice President -
Finance and Controller 11/88
All of the Company's executive officers have been employed by the Company, the
Parent, or its affiliates in management positions for more than the past five
years, except Mr. Sayles. From 1982 until joining the Company in January 1994,
Mr. Sayles was Senior Legal Counsel for TRW, Inc. (1982-1990); Commissioner of
Corporations (1991-1992) and Secretary of the California Business,
Transportation and Housing Agency (1993) for the State of California.
Executive officers are elected annually and serve at the pleasure of the
Board of Directors.
There are no family relationships among any of the Company's executive
officers.
-18-
ITEM 2. PROPERTIES
At December 31, 1993, The Gas Company owned approximately 3,280 miles of
transmission and storage pipeline, 42,250 miles of distribution pipeline and
42,406 miles of service piping. It also owned thirteen transmission compressor
stations and six underground storage reservoirs (with a combined working storage
capacity of approximately 116 billion cubic feet) and general office buildings,
shops, service facilities, and certain other equipment necessary in the conduct
of its business.
Southern California Gas Tower, a wholly-owned subsidiary of The Gas
Company, has a 15 percent limited partnership interest in a 52-story office
building in downtown Los Angeles. The Gas Company occupies about half of the
building.
ITEM 3. LEGAL PROCEEDINGS
Except for the matters referred to in the financial statements filed with
or incorporated by reference in Item 8 or referred to elsewhere in this Annual
Report, neither the Company nor any of its subsidiaries is a 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
No matters were submitted during the fourth quarter of 1993 to a vote of
the Company's security holders.
-19-
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON
EQUITY AND RELATED STOCKHOLDER MATTERS
The Parent owns all of the Company's Common Stock. The information
required by this item concerning dividends declared is included in the Statement
of Consolidated Shareholders' Equity set forth in Item 8 of this Annual Report.
Such information is incorporated herein by reference.
RANGE OF MARKET PRICES OF PREFERRED STOCK
Three Months Ended 1993 1992
- -----------------------------------------------------------------------------------------
Preferred Stock: 7 3/4% 6%-Series A 7 3/4% 6%-Series A
----- ----------- ----- ---------
March 31 27-24 5/8 21 5/8-19 1/2 - 20 1/4-16 1/8
June 30 27-25 1/8 22 3/4-20 - 19 5/8-17 1/2
Sept. 30 27-26 23 1/4-22 1/4 - 20 7/8-19 1/2
Dec. 31 26 7/8-25 1/2 22 3/4-20 1/4 - 20 5/8-19 1/8
Market prices for the preferred stock were obtained from the Pacific Stock
Exchange. (The 7 3/4% preferred stock began trading in April 1993 therefore,
estimates for the first quarter were obtained from the underwriter). The 6%
Preferred Stock and the Flexible Auction Series Preferred Stock, Series A and
Series C are not listed on any exchange.
-20-
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth certain selected financial data of the Company
for 1989 through 1993.
SELECTED FINANCIAL DATA
Year Ended December 31,
-----------------------------------------------------------------------
(Thousands of Dollars) 1993 1992 1991 1990 1989
- -----------------------------------------------------------------------------------------------------
Operating revenues $2,811,074 $2,839,925 $2,930,306 $3,212,625 $3,275,350
Net income $ 193,676 $ 194,716 $ 211,792* $ 177,744 $ 180,903
Total assets $4,950,220 $4,155,399 $4,059,186 $4,013,497 $3,770,686
Long-term debt $1,235,622 $1,147,198 $1,147,132 $1,016,493 $ 893,842
Preferred stock-with
mandatory redemption $ 60,000
*Net income for 1991 includes a net after-tax gain of $15 million relating to
the sale of The Gas Company's headquarters office property.
The Gas Company's parent, Pacific Enterprises, owns 96 percent of the
voting stock, including all of the issued and outstanding common stock;
therefore, per share data have been omitted.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern California Gas Company is a subsidiary of Pacific Enterprises
(Parent). This section includes management's analysis of operating results from
1991 through 1993, and is intended to provide additional information about the
Company's financial performance. This section also focuses on many of the
factors that influence future operating results and discusses future investment
and financing plans. This section should be read in conjunction with the
Consolidated Financial Statements.
FINANCIAL AND OPERATING PERFORMANCE. The Gas Company provides natural gas
distribution, transmission and storage in a 23,000-square-mile service area in
southern California and parts of central California.
The Company's markets are separated into core customers and noncore
customers. Core customers include approximately 4.7 million customers (4.5
million residential and 0.2 million smaller commercial and industrial
customers). The noncore market consists of over 1,000 customers which primarily
includes utility electric
-21-
generation, wholesale, and large commercial and industrial customers. The
noncore customers are sensitive to the price relationship between natural gas
and alternate fuels, and are capable of readily switching from one fuel to
another, subject to air quality regulations.
Key financial and operating data for the Company are highlighted in the
table below.
(Dollars in Millions) 1993 1992 1991
- ----------------------------------------------------------------------------
Net income (after preferred dividends) $184 $188 $204
Authorized return on rate base 9.99% 10.49% 10.79%
Authorized return on common equity 11.90% 12.65% 13.00%
Weighted average rate base $2,769 $2,720 $2,663
Growth in weighted average rate base over
prior period 1.8% 2.1% 4.5%
- ----------------------------------------------------------------------------
The Company has achieved or exceeded the rate of return on rate base
authorized by the California Public Utilities Commission (CPUC) for 11
consecutive years. In 1994, the Company is authorized to earn 9.22 percent on
rate base and 11.00 percent on common equity. This compares to authorized
returns of 9.99 percent on rate base and 11.90 percent on common equity in 1993.
Rate base is expected to increase approximately 4 percent to 5 percent in 1994.
Net income decreased $4 million in 1993 due primarily to a reduction in the
Company's authorized rate of return on common equity and lower earnings from the
noncore market, partially offset by continued reductions in the Company's cost
of service, including operating and financing costs, and growth in rate base.
During 1992, net income decreased $16 million due primarily to the recognition
in 1991 of a $15 million gain on the 1987 sale of the Company's former
headquarters property. In addition, 1992 results reflect a reduction in the
Company's authorized rate of return on common equity and disallowances related
to its new headquarters, partially offset by growth in rate base and higher
earnings from the noncore market.
The table below summarizes the components of gas revenues.
Sales Transportation and Exchange Total
--------------------- --------------------------- ----------------------------
Volume Revenue Volume Revenue Throughput Gas Revenue
(bcf) ($ Millions) (bcf) ($ Millions) (bcf) ($ Millions)
- -------------------------------------------------------------------------------------------------
1993 352 2,282 613 492 965 2,774
1992 355 2,116 646 534 1,001 2,650
1991 411 2,607 636 345 1,047 2,952
- -------------------------------------------------------------------------------------------------
The table shows the composition of the Company's throughput and gas revenue
for the past three years. Although the revenues associated with transportation
volumes are less than for gas sales, the Company generally earns the same margin
whether it buys the gas and sells it to the
-22-
customer or transports gas already owned by the customer. Throughput, the total
gas sales and transportation volumes moved through the Company's system, is
affected by weather and general economic conditions. In addition, throughput
has declined over the last two years as a result of bypass of The Gas Company's
system, primarily by enhanced oil recovery customers. (See Factors Influencing
Future Performance.) The average commodity cost of gas purchased by the
Company, excluding fixed charges, for 1993 was $2.21 per thousand cubic feet,
compared to $2.24 per thousand cubic feet in 1992 and $2.40 per thousand cubic
feet in 1991.
RATEMAKING PROCEDURES. The Company is regulated by the CPUC. It is the
responsibility of the CPUC to determine that utilities operate in the best
interest of the ratepayer with a reasonable profit. The current ratemaking
procedures are summarized below. Some of these procedures would be modified by
the Comprehensive Settlement discussed later in this section.
The return that the Company is authorized to earn is the product of the
authorized rate of return on rate base and the amount of rate base. Rate base
consists primarily of net investment in utility plant. Thus, the Company's
earnings are affected by changes in the authorized rate of return on rate base
and the growth in rate base and by the Company's ability to control expenses and
investment in rate base within the amounts authorized by the CPUC in setting
rates. In addition, achievement of the authorized rate of return is affected by
other regulatory and operating factors.
General rate applications are filed every three years. New rates emanating
from the Company's most recent rate case went into effect on January 1, 1994.
In a general rate case, the CPUC establishes a margin, which is the amount of
revenue authorized to be collected from customers to recover authorized
operating expenses (other than the cost of gas), depreciation, interest, taxes
and return on rate base.
In a process referred to as the annual attrition allowance, the CPUC
annually adjusts rates for years between general rate cases to cover the effects
of inflation and changes in rate base. Separate proceedings are held annually to
review The Gas Company's cost of capital, including return on common equity,
interest costs and changes in capital structure.
The CPUC separately reviews and issues decisions on the reasonableness of
various aspects of the Company's operations. The CPUC has disallowed costs it
determined to
-23-
be imprudent, and further disallowances are possible in the future.
In the biennial cost allocation proceeding (BCAP), the CPUC specifies for
each two-year period the allocation of total margin to be collected from the
Company's core and noncore customer classes and the expected volumes of gas each
customer class will consume annually. The Company maintains regulatory accounts
to accumulate undercollections and overcollections from customers and makes
periodic filings with the CPUC to adjust future gas rates to account for
variances between forecasted and actual gas costs and deliveries. In August
1993, the Company filed a $134 million rate increase with the CPUC. Included in
this BCAP filing is a rate structure designed to further reduce subsidies by
nonresidential core customers to residential customers by better aligning
residential rates with the cost of providing residential service. The CPUC, in
an interim decision, granted the Company a $121 million revenue increase
effective January 1, 1994. A final CPUC decision is expected in late 1994.
For the core market, the regulatory procedures provide for recording margin
ratably each month. The BCAP balancing account procedure, which substantially
eliminates the effect on income of variances in gas costs and volumes sold,
allows the Company to increase rates for increased gas acquisition costs or for
revenue shortfalls due to reductions in demand by core customers. Conversely,
the Company reduces rates for decreased gas acquisition costs or for higher than
projected revenues from increases in demand by core customers.
For the noncore market the CPUC has created a risk-and-reward mechanism.
Earnings may be enhanced by delivering higher than forecast gas volumes to
noncore customers. Conversely, the Company is at risk for unfavorable variances
in noncore volumes or pricing. This upside and downside earnings potential in
the noncore market was limited by the CPUC's procurement rulemaking decision in
August 1991. This decision significantly reduced the Company's gas procurement
activities on behalf of noncore customers and adopted new service level options
and rate structures. It also included a provision for balancing account
treatment for 75 percent of any undercollection or overcollection in the
recovery of noncore margin and other costs, as compared to what was designated
by the CPUC, to be recovered or returned in rates at a later date. The CPUC's
revised noncore rate design generally provides for single, rolled-in, volumetric
rates, which include use-or-pay provisions in lieu of rates with demand charges.
The collection of up-front demand charges had provided compensation to The
Gas Company for standing ready
-24-
to provide a contracted level of service and buffered the potential earnings
loss from lower than forecast volumes in the noncore market. Under certain
conditions, noncore rates, including demand charges, and terms of service are
negotiable.
REGULATORY ACTIVITY. On December 17, 1993, the CPUC issued its decision in
the Company's 1994 general rate case which authorized a net $97 million rate
reduction. The Company plans to attempt to adjust its operations with the
intention of operating within the amounts authorized in rates. Approximately
$21 million of the rate reduction represents productivity improvements. Other
items include non-operational issues, primarily reductions in marketing programs
and income tax effects of the rate reduction. The decision also includes the
effects of the reduction of the Company's rate of return authorized in its 1994
cost of capital proceeding, which increased the total reduction in rates to $132
million. New rates emanating from the decision became effective on January 1,
1994.
RESTRUCTURING OF GAS SUPPLY CONTRACTS. The Company and its gas supply
affiliates have reached agreements with suppliers of California offshore and
Canadian gas for a restructuring of long-term gas supply contracts. The cost of
these supplies to the Company has been substantially in excess of the Company's
average delivered cost of gas. During 1993, these excess costs totaled
approximately $125 million.
The new agreements substantially reduce the ongoing delivered costs of
these gas supplies and provide lump sum settlement payments of $375 million to
the suppliers. The expiration date for the Canadian gas supply contract has
been shortened from 2012 to 2003, and the supplier of California offshore gas
continues to have an option to purchase related gas treatment and pipeline
facilities owned by the Company's gas supply affiliate. The agreement with the
suppliers of Canadian gas is subject to certain Canadian regulatory and other
approvals.
COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES. The Company and a number of
interested parties (including the Division of Ratepayer Advocates of the CPUC,
large noncore customers and ratepayer groups) have proposed for CPUC approval a
comprehensive settlement (Comprehensive Settlement) of a number of pending
regulatory issues including partial rate recovery of restructuring costs
associated with the gas supply contracts discussed above. The Comprehensive
Settlement, if approved by the CPUC, would permit the Company to recover in
utility rates approximately 80 percent of the contract restructuring costs of
$375 million and accelerated depreciation of related pipeline assets of its gas
supply affiliates of approximately $130
-25-
million, together with interest, over a period of approximately five years. The
Company has filed a financing application with the CPUC primarily for the
borrowing of $425 million to provide for funds needed under the Comprehensive
Settlement. In addition to the gas supply issues, the Comprehensive Settlement
addresses the following other regulatory issues:
NONCORE CUSTOMER RATES. The Comprehensive Settlement also contemplates
changes in the CPUC ratemaking procedures for determining rates to be
charged by the Company to its customers for the five-year period commencing
with the approval of the Comprehensive Settlement by the CPUC. Rates
charged to the customers would be established based upon the Company's
recorded throughput to these customers for 1991. The existing limited
regulatory balancing account treatment for variances in noncore volumes
from those estimated in establishing rates would be eliminated subject to a
crediting mechanism for noncore revenues in excess of certain limits.
Consequently, the Company would bear the full risk of any declines in
noncore deliveries from 1991 levels. Any revenue enhancement from
deliveries in excess of 1991 levels will be limited by a crediting account
mechanism that will require a credit to customers of 87.5 percent of
revenues in excess of certain limits. These annual limits above which the
credit is applicable increase from $11 million to $19 million over the
five-year period to which the Comprehensive Settlement is applicable.
REASONABLENESS REVIEWS. The Comprehensive Settlement contemplates the
settlement of all pending CPUC reasonableness reviews with respect to the
Company's gas purchases from 1989 through 1992 as well as certain other
future reasonableness review issues. The Comprehensive Settlement also
allows recovery of future excess interstate pipeline capacity costs in the
Company's rates.
GAS COST INCENTIVE MECHANISM. The Comprehensive Settlement contemplates
that a gas cost incentive mechanism (GCIM) would be implemented with an
initial term of three years. Gas costs in excess of a tolerance band over
average market price would be shared equally between ratepayers and the
Company. Savings from gas purchased below the average market price would
be also shared equally between the ratepayers and the Company. The GCIM
would provide a 4 1/2 percent tolerance band in 1994 and a 4 percent
tolerance band in 1995 and
-26-
1996. The GCIM is intended to replace the current gas procurement
reasonableness review process. On March 16, 1994, the CPUC issued its
decision approving the GCIM for implementation for a three year trial
period beginning April 1, 1994.
ATTRITION ALLOWANCES. The Comprehensive Settlement contemplates that the
Company may receive annual allowances for operational attrition for 1995
and 1996 only to the extent that the annual inflation rate for those years
exceeds 2 percent or 3 percent, respectively. This is a departure from
past regulatory practice of allowing recovery of the full effect of
inflation in rates. The Company intends to continue to attempt to control
operating expenses and investment in those years to amounts authorized in
rates to offset the effect of this regulatory change.
The Company believes the Comprehensive Settlement will be approved by the
CPUC; therefore, it has been reflected in the Company's financial statements.
Approximately $465 million is included in Regulatory Accounts Receivable and
Regulatory Assets for the recovery of costs as provided in the Comprehensive
Settlement. Upon giving effect to liabilities previously recognized at the
Company and amounts absorbed by its gas supply affiliates, the costs of the
Comprehensive Settlement, including the restructuring of gas supply contracts,
did not result in any additional charge to The Gas Company's consolidated
earnings. In the event the Comprehensive Settlement is not approved by the
CPUC, the Company will seek other regulatory approvals for the recovery of these
costs.
FACTORS INFLUENCING FUTURE PERFORMANCE. Based on existing ratemaking
policies, future Company earnings and cash flow will be determined primarily by
the allowed rate of return on common equity, the growth in rate base, noncore
pricing and the variance in gas volumes delivered to these customers versus
CPUC-adopted forecast deliveries, the recovery of gas and contract restructuring
costs if the Comprehensive Settlement is not approved and the ability of
management to control expenses and investment in line with the amounts
authorized by the CPUC to be collected in rates. Also, the Company's ability to
earn revenues in excess of its authorized return from noncore customers due to
volume increases will be substantially eliminated for the five years of the
Comprehensive Settlement described above. This is because forecasted deliveries
in excess of the 1991 throughput levels used to establish rates were
contemplated in estimating the costs of the Comprehensive Settlement, and are
reflected in current year liabilities. The impact of any future regulatory
restructuring and increased competitiveness in the industry, including the
continuing threat of customers bypassing the Company's system and obtaining
service
-27-
directly from interstate pipelines, can also affect the Company's performance.
The Gas Company's earnings for 1994 will be affected by the reduction in
the authorized rate of return on common equity, reflecting the overall decline
in cost of capital offset by higher rate base than in 1993. For 1994, the
Company is authorized to earn a rate of return on rate base of 9.22 percent and
an 11.00 percent rate of return on common equity compared to 9.99 percent and
11.90 percent, respectively, in 1993. Rate base is expected to increase by
approximately 4 percent to 5 percent in 1994.
Since the completion of the Kern River/Mojave Interstate Pipeline (Mojave)
in February 1992, the Company's throughput to customers in the Kern County area
who use natural gas to produce steam for enhanced oil recovery projects has
decreased significantly because of the bypass of the Company's system. Mojave
now delivers to customers formerly served by the Company 350 million to 400
million cubic feet per day. The decrease in revenues from enhanced oil recovery
customers is subject to full balancing account treatment, except for a 5 percent
incentive to the Company for attaining certain throughput levels, and therefore,
does not have a material impact on the Company's earnings. However, bypass of
other markets may also occur as a result of plans by Mojave to extend its
pipeline north to Sacramento through portions of the Company's service
territory. The effect of bypass is to increase the Company's rates to other
customers and thus make its natural gas service less competitive with that of
competing pipelines and available alternate fuels.
In response to bypass, the Company has received authorization from the CPUC
for expedited review of price discounts proposed for long-term gas
transportation contracts with some noncore customers. In addition, in December
1992, the CPUC approved changes in the methodology for allocating the Company's
cost between core and noncore customers to reduce subsidization of core customer
rates by noncore customers. Effective in June 1993, these new rate changes
implemented the CPUC's policy known as "long-run marginal cost." The revised
methodologies have resulted in a reduction of noncore rates and a corresponding
increase in core rates that better reflects the cost of serving each customer
class and, together with price discounting authority, has enabled the Company to
better compete with interstate pipelines for noncore customers. In addition, in
August 1993 a capacity brokering program was implemented. Under the program,
for a fee, the Company provides to noncore customers, or others, a portion of
its control of interstate pipeline capacity to allow more direct access to
producers. Also, the Comprehensive Settlement will help the Company's
competitiveness by reducing the cost of transportation service to noncore
customers.
-28-
Over the past 11 years, management has been able to control operating
expenses and investment within the amounts authorized to be collected in rates
and intends to continue to do so. However, it may not be able to accomplish
this goal. It also bears the risk of nonrecovery of margin or other costs
authorized by the CPUC for the noncore market subject to the Comprehensive
Settlement as discussed above. Unanticipated sharp increases in the inflation
rate could also reduce earnings and cash flow. This possibility is increased
with the limits on attrition allowance in 1995 and 1996 under the proposed
Comprehensive Settlement.
The Company's earnings are subject to variability depending on gas
throughput for its noncore customers. There is a continuing risk that an
unfavorable variance in noncore volumes can result from external factors such as
weather, the use of increased hydroelectric power, the price relationship
between alternative fuels and natural gas and the operational capacity and/or
competing pipeline bypass of the Company's system. In these cases the Company is
at risk for the lost revenue. In addition, although an economic downturn or
recession does not affect the Company as significantly as nonregulated
businesses, there is a risk that an unfavorable variance in the noncore volumes
can result.
The Gas Company's operations are affected by a growing number of
environmental laws and regulations. These laws and regulations affect current
operations as well as future expansion and also require cleanup of facilities no
longer in use. Because of expected regulatory treatment, the Company believes
that compliance with these laws will not have a significant impact on its
financial statements. For further discussion of regulatory and environmental
matters, see Note 5 of Notes to Consolidated Financial Statements.
The Company employs approximately 9,000 persons. Most field, clerical and
technical employees of the Company are represented by the Utility Workers' Union
of America, or the International Chemical Workers' Union. Collective bargaining
agreements covering these approximately 6,400 employees expired on June 30,
1993, principally as a consequence of failure to reach agreement with respect to
the Company's proposal to permit the use of outside contractors for certain
services now being provided by union represented employees, if costs were not
lowered to an amount that would be incurred through the use of outside
contractors. In August 1993, after reaching an impasse, the Company
unilaterally implemented the majority of its proposals and after two failed
strike votes and further negotiations, the Union membership voted in February
1994 on a contract with terms consistent with that implemented by the Company.
On February 28, 1994, the Union notified the Company that the contract had been
ratified by the membership and a contract was signed on March 9, 1994. The
collective bargaining agreement with respect to wages and working conditions
will
-29-
extend through March 31, 1996. The medical plan agreement will expire on
December 31, 1995.
On January 17, 1994, the Company's service area was struck by a major
earthquake. The result was a temporary disruption to approximately 150,000
customers and damage to some facilities. The financial impact of the damages
related to the earthquake not recovered by insurance is expected to be recovered
in rates under an existing balancing account mechanism, and should have no
impact on the Company's financial statements.
CAPITAL EXPENDITURES. Capital expenditures were $318 million, $326 million
and $316 million in 1993, 1992 and 1991, respectively. Capital expenditures for
utility plant are expected to be $345 million in 1994 and will be financed by
internally-generated funds and by issuance of long-term debt.
LIQUIDITY. In 1993, as a result of the Comprehensive Settlement, Accounts
Payable-Affiliates includes the liability for lump sum settlement payments of
$375 million to restructure long-term gas supply contracts and the liability for
accelerated amortization of related pipeline assets of gas supply affiliates of
$130 million; and Regulatory Assets include the long-term portion of the accrual
of amounts to be recovered in rates. Regulatory Accounts Receivable increased
in 1993 and 1992 reflecting higher undercollections under the BCAP balancing
account procedures due primarily to throughput falling below CPUC-adopted
forecast levels. The 1993 balance also includes the current portion of the
accrual for the Comprehensive Settlement and undercollections for the transition
costs in connection with the capacity brokering program.
Regulatory interest income for 1993 and 1992 increased and decreased $3
million respectively, primarily due to the interest earned on the related
interest-bearing regulatory accounts. Other-net (deductions) for 1993 and 1992
reflect the disallowances related to the new headquarters property. The loss on
the in-substance defeasance of debt transactions recorded in 1992 is also
reflected in Other-net.
Interest on long-term debt for 1993 decreased $11 million and increased $10
million in 1992 due to the refinancing of debt at lower interest rates and the
timing of new and replacement of previously retired debt issues. Other interest
charges (credits) in 1993 increased $10 million reflecting higher accruals for
regulatory related issues. The $10 million decrease in 1992 reflected lower
interest associated with supplier refunds received and reversals of the interest
associated with prior income tax exposures.
The Company expects to incur additional borrowings of $425 million to
finance the Comprehensive Settlement. Borrowings are expected to include
primarily commercial paper and medium-term notes. The Company has no plans to
issue additional debt
-30-
beyond that required by the Comprehensive Settlement and up to $100 million to
finance ongoing operations.
-31-
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
STATEMENT OF CONSOLIDATED INCOME
Year Ended December 31,
----------------------------------------------------
(Thousands of Dollars) 1993 1992 1991
- ---------------------------------------------------------------------------------------------------------
OPERATING REVENUES: $2,811,074 $2,839,925 $2,930,306
------------ ------------ ------------
OPERATING EXPENSES:
Cost of gas distributed 1,187,072 1,207,275 1,380,609
Operation 768,677 730,638 681,313
Maintenance 99,795 101,680 110,111
Depreciation 228,244 219,011 208,184
Income taxes 134,491 164,487 146,442
Local franchise payments 46,217 50,743 47,485
Ad valorem taxes 32,592 37,677 36,238
Payroll and other taxes 29,488 29,030 28,591
------------ ------------ ------------
Total 2,526,576 2,540,541 2,638,973
------------ ------------ ------------
NET OPERATING REVENUE: 284,498 299,384 291,333
------------ ------------ ------------
OTHER INCOME AND (DEDUCTIONS):
Interest income 1,668 3,948 4,656
Regulatory interest 4,924 1,731 4,253
Allowance for equity funds used during
construction 4,406 3,608 2,995
Gain on sale of headquarters property 27,756
Income taxes on non-operating income 5,670 572 (12,841)
Other - net (5,245) (11,314) (2,950)
------------ ------------ ------------
Total 11,423 (1,455) 23,869
------------ ------------ ------------
INTEREST CHARGES AND (CREDITS):
Interest on long-term debt 95,806 106,641 96,684
Other interest 9,180 (1,132) 8,428
Allowance for borrowed funds used
during construction (2,741) (2,296) (1,702)
------------ ------------ ------------
Total 102,245 103,213 103,410
------------ ------------ ------------
NET INCOME 193,676 194,716 211,792
DIVIDENDS ON PREFERRED STOCK 9,882 6,992 7,357
------------ ------------ ------------
NET INCOME APPLICABLE TO COMMON STOCK $ 183,794 $ 187,724 $ 204,435
------------ ------------ ------------
------------ ------------ ------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
- 32 -
CONSOLIDATED BALANCE SHEET
December 31,
-----------------------------------
(Thousands of Dollars) 1993 1992
- ---------------------------------------------------------------------------------------------------------
ASSETS
Utility Plant - at original cost $5,422,549 $5,137,001
Less Accumulated Depreciation 2,205,043 2,015,303
---------- ----------
Utility plant - net 3,217,506 3,121,698
---------- ----------
CURRENT ASSETS:
Cash and cash equivalents 14,533 1,318
Accounts receivable - trade (less
allowance for doubtful
receivables of $16,754 in
1993 and $15,335 in 1992) 494,884 491,621
Accounts and notes receivable - other 8,424 8,452
Regulatory accounts receivable 443,718 281,398
Gas in storage 53,114 39,835
Materials and supplies 20,618 18,798
Prepaid expenses 22,971 44,579
---------- ----------
Total current assets 1,058,262 886,001
---------- ----------
REGULATORY ASSETS 674,452 147,700
---------- ----------
Total $4,950,220 $4,155,399
---------- ----------
---------- ----------
CAPITALIZATION AND LIABILITIES
CAPITALIZATION:
Common equity:
Common stock $ 834,889 $ 834,889
Retained earnings 607,250 559,492
---------- ----------
Total common equity 1,442,139 1,394,381
Preferred stock 196,551 196,551
Long-term debt 1,235,622 1,147,198
---------- ----------
Total capitalization 2,874,312 2,738,130
---------- ----------
CURRENT LIABILITIES:
Short-term debt 267,000 215,000
Accounts payable - trade 188,484 192,575
Accounts payable - affiliates 513,306 29,171
Accounts payable - other 228,517 156,677
Accrued taxes and franchise payments 21,907 96,373
Deferred income taxes 39,542 25,246
Long-term debt due within one year 26,667
Accrued interest 35,007 29,732
Other accrued liabilities 129,372 98,772
---------- ----------
Total current liabilities 1,423,135 870,213
---------- ----------
CUSTOMER ADVANCES FOR CONSTRUCTION 45,493 45,015
DEFERRED INCOME TAXES 399,535 353,013
DEFERRED INVESTMENT TAX CREDITS 72,993 76,804
OTHER DEFERRED CREDITS 134,752 72,224
COMMITMENTS AND CONTINGENT LIABILITIES
---------- ----------
Total $4,950,220 $4,155,399
---------- ----------
---------- ----------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
- 33 -
STATEMENT OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
-------------------------------------------------------
(Thousands of Dollars) 1993 1992 1991
- -----------------------------------------------------------------------------------------------------------------------------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $ 193,676 $ 194,716 $ 211,792
Items not requiring cash:
Depreciation 228,244 219,011 208,184
Deferred income taxes 33,093 16,381 (5,720)
Deferred investment tax credits (3,811) (3,616) (3,941)
Allowance for funds used during construction (7,147) (5,904) (4,697)
Other 22,442 24,258 (2,741)
Net change in other working capital components:
Accounts receivable (3,235) 40,794 380
Regulatory accounts receivable (107,320) (107,203) 28,165
Gas in storage (13,279) 17,764 (28,181)
Other current assets 19,787 37,432 5,055
Accounts payable 77,672 (139,000) (63,993)
Accrued taxes and franchise payments (74,466) 25,965 (47,616)
Deferred income taxes - current 23,501 13,719 21,778
Other current liabilities 26,245 (7,693) (43,758)
------------ ------------ ------------
Net cash provided by operating activities 415,402 326,624 274,707
------------ ------------ ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for utility plant (318,429) (326,085) (316,526)
Increase in other assets - net (52,929) (7,856) (8,272)
------------ ------------ ------------
Net cash used in investing activities (371,358) (333,941) (324,798)
------------ ------------ ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends (144,590) (133,861) (142,799)
Issuance of long-term debt 631,000 282,000 150,000
Payments of long-term debt (569,239) (272,626) (24,136)
Sale of preferred stock 75,000 50,000
Redemption of preferred stock (75,000)
Increase in short-term debt 52,000 92,000 23,000
------------ ------------ ------------
Net cash provided by (used in) financing activities (30,829) (32,487) 56,065
------------ ------------ ------------
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS 13,215 (39,804) 5,974
CASH AND CASH EQUIVALENTS - JANUARY 1 1,318 41,122 35,148
CASH AND CASH EQUIVALENTS - DECEMBER 31 $ 14,533 $ 1,318 $ 41,122
------------ ------------ ------------
------------ ------------ ------------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
CASH PAID DURING THE YEAR FOR -
Interest (net of amount capitalized) $ 97,514 $ 111,574 $ 141,915
------------ ------------ ------------
------------ ------------ ------------
Income taxes $ 142,346 $ 105,241 $ 206,539
------------ ------------ ------------
------------ ------------ ------------
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
- 34 -
STATEMENT OF CONSOLIDATED LONG-TERM DEBT
December 31,
----------------------------------------------
(Thousands of Dollars) 1993 1992
- ---------------------------------------------------------------------------------------------------------
First Mortgage Bonds:
8 3/4 % May 1, 1996 $ $ 16,668
8 1/2 % October 1, 1997 20,001
6 1/2 % December 15, 1997 125,000 125,000
5 1/4% March 1, 1998 100,000
6 7/8 % August 15, 2002 100,000 100,000
5 3/4% November 15, 2003 100,000
9 3/8 % March 1, 2016 100,000
9 % December 1, 2016 100,000
9 5/8 % November 1, 2018 125,000
9 3/4 % December 1, 2020 18,435 120,000
8 3/4 % October 1, 2021 150,000 150,000
7 3/8 % March 1, 2023 100,000
7 1/2 % June 15, 2023 125,000
6 7/8 % November 1, 2025 175,000
9 3/8 % June 15, 1998 100,000
BONDS:
SFr. 100,000,000 5 1/8 % Bonds, February 6, 1998 (a) 47,250 47,250
SFr. 150,000,000 7 1/2 % Foreign Interest Payment Securities
May 14, 1996 (b) 75,282 75,282
NOTES:
4.69% - 8 3/4% 1995-2000 138,000 107,000
LONG-TERM DEBT HELD IN TREASURY
------------ ------------
Total outstanding 1,253,967 1,186,201
------------ ------------
Less:
Payments due within one year 26,667
Unamortized debt discount less premium 18,345 12,336
------------ ------------
18,345 39,003
------------ ------------
LONG-TERM DEBT $1,235,622 $1,147,198
------------ ------------
------------ ------------
(a) The Gas Company has entered into a swap transaction with a major
international bank to hedge the currency exposure of the bonds.
The terms of the swap result in a U.S. dollar liability of $47
million at an interest rate of 9.725 percent. The Gas Company is
exposed to credit losses in the event of nonperformance by the
other parties to the swap agreement. However, the Company does
not anticipate nonperformance by the counterparties.
(b) The Foreign Interest Payment Securities are renewable at ten-year intervals
at reset interest rates. Interest is payable in U.S. dollars. The principal
was exchanged into $75 million at an exchange rate of 1.9925, which is also
the minimum rate of exchange for determining the amount of principal
repayable in Swiss Francs.
The annual principal payment requirements including sinking fund payments,
on the noncurrent portion
- 35 -
of long-term debt for the years 1995 through 1998 are $86, $95, $147 and $147 in
millions, respectively. Substantially all utility plant is pledged as collateral
for the first mortgage bonds.
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- 36 -
STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY
(Thousands of Dollars)
- ------------------------------------------------------------------------------------------------------------------------
Preferred Common Retained
Stock Stock Earnings
----- ----- --------
BALANCE, DECEMBER 31, 1990 $146,551 $834,889 $429,427
Net income 211,792
Cash dividends declared
Preferred stock (7,357)
Common stock (135,293)
Preferred stock sold (500 shares) 50,000
------------ ------------ ------------
BALANCE, DECEMBER 31, 1991 196,551 834,889 498,569
Net income 194,716
Cash dividends declared:
Preferred stock (6,992)
Common stock (126,801)
------------ ------------ ------------
BALANCE, DECEMBER 31, 1992 196,551 834,889 559,492
Net income 193,676
Cash dividends declared:
Preferred stock (9,882)
Common stock (136,036)
Preferred stock sold (3,000,000 shares) 75,000
Preferred stock redeemed (750 shares) (75,000)
------------ ------------ ------------
BALANCE, DECEMBER 31, 1993 $196,551 $834,889 $607,250
------------ ------------ ------------
------------ ------------ ------------
The number of shares of preferred stock and common stock authorized and
outstanding at December 31, 1993 and 1992, is set forth in Note 10 of Notes to
Consolidated Financial Statements.
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- 37 -
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
The Gas Company is a subsidiary of Pacific Enterprises (Parent) which
owns approximately 96 percent of The Gas Company's voting stock, including all
of its issued and outstanding common stock; therefore, per share data have been
omitted.
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements
include the accounts of the Company and its subsidiary, Southern California Gas
Tower, a wholly-owned subsidiary that has a 15 percent limited partnership
interest in a 52-story office building in which the Company occupies
approximately one-half of the leasable space. Investments of less than 20
percent are accounted for using the cost method.
RESTATEMENTS AND RECLASSIFICATION. Certain changes in account
classification have been made in the prior years' consolidated financial
statements to conform to the 1993 financial statement presentation.
REGULATION. The Gas Company is a public utility and follows
accounting policies prescribed or authorized by the California Public Utilities
Commission (CPUC).
INVENTORIES. Gas in storage inventory is stated at last-in, first-out
(LIFO) cost. As a result of the regulatory accounting procedure, the pricing of
gas in storage does not have an effect on net income. If the first-in, first-out
(FIFO) method of accounting for gas inventory had been used by the Company,
inventory would have been higher than reported at December 31, 1993 and 1992 by
$58 million and $66 million, respectively. Materials and supplies are stated at
average unit cost.
UTILITY PLANT. The cost of additions, renewals and improvements to
utility plant are charged to the appropriate plant accounts. These costs include
labor, material, other direct costs, indirect charges and an allowance for funds
used during construction. The cost of utility plant retired or otherwise
disposed of, plus removal costs and less salvage, is charged to accumulated
depreciation. Depreciation is recorded on the straight-line remaining life
basis.
REVENUES. Operating revenues are recognized in the same period in
which the related gas is delivered to customers.
OTHER. Cash equivalents include short-term investments purchased with
maturities of less than 90 days. Interest of $7 million in 1993, $6 million in
1992 and $5
- 38 -
million in 1991 was capitalized. Other major accounting policies are included
in the following notes.
- 39 -
2. Gain On Sale Of Headquarters and Relocation
In 1987, The Gas Company completed an agreement under which the
headquarters office property of the Company was sold. In late 1990, the CPUC
ruled that the entire after-tax gain of approximately $24 million be returned to
ratepayers over a period of 11 years and 11 months without interest. The Gas
Company was permitted to retain the investment income it has earned on the net
proceeds from the sale to date and will continue to be entitled to this income
through the refund period. As a result, the Company recorded a net after-tax
gain of $15 million in 1991, which reflects the $24 million gain reduced by the
liability due to ratepayers discounted to the date of sale. At December 31,
1993, the discounted refund obligation remaining for the unamortized pre-tax
gain (net proceeds of $62 million less book value of the property) was $21
million and is included in Accounts Payable -Other and Other Deferred Credits in
the Consolidated Balance Sheet.
In late 1991, the Company moved its corporate headquarters to a new
location in downtown Los Angeles. The Company leases about one-half of the space
in The Gas Company Tower, and is also a limited partner in the ownership of the
building. In connection with the Company's move to The Gas Company Tower, the
CPUC performed a review of the costs associated with this new leased office
space. In July 1992, the CPUC decided that certain lease expenses and
approximately $8 million of related capital expenditures should not be
recoverable in future gas rates. The CPUC decision also required that the
Company compensate ratepayers over the 20-year life of the lease for the
estimated sale value of its 15 percent ownership interest in The Gas Company
Tower.
3. Income Taxes
In 1992, the Company adopted Statement of Financial Accounting
Standards No. 109, "Accounting for Income Taxes", the effect of which was not
material.
A reconciliation of the difference between computed statutory federal
income tax expense and actual income tax expense is as follows:
- 40 -
Year Ended December 31,
--------------------------------------------------------
(Thousands of Dollars) 1993 1992 1991
- -----------------------------------------------------------------------------------------------------------------------------
Computed statutory federal income tax expense $112,874 $121,935 $126,165
Increases (reductions) resulting from:
Excess book over tax depreciation 17,847 17,121 16,006
Federal income tax rate change 1,698
State income taxes - net of federal income tax benefit 16,993 23,543 23,752
Research and development credit (4,000)
Amortization of deferred investment tax credits (3,811) (3,867) (3,691)
Resolution of proposed tax deficiency (10,193)
Other - net (2,587) 5,183 (2,949)
------------ ------------ -------------
Total income tax expense $128,821 $163,915 $159,283
------------ ------------ -------------
------------ ------------ -------------
- 41 -
The components of income tax expense are as follows:
Year Ended December 31,
------------------------------------------------------------
(Thousands of Dollars) 1993 1992 1991
- -----------------------------------------------------------------------------------------------------------------------------
Federal
Current $ 53,831 $ 103,908 $ 110,824
Deferred 46,044 25,254 11,958
------------ ------------ ------------
99,875 129,162 122,782
------------ ------------ ------------
State
Current 22,206 34,331 36,215
Deferred 6,740 422 286
------------ ------------ ------------
28,946 34,753 36,501
------------ ------------ ------------
Total
Current 76,037 138,239 147,039
Deferred 52,784 25,676 12,244
------------ ------------ ------------
$ 128,821 $ 163,915 $ 159,283
------------ ------------ ------------
------------ ------------ ------------
The principal components of net deferred tax liabilities are as follows:
December 31,
----------------------------------------------------------------------------------
1993 1992
---------------------------------------------- ----------------------------------
(Thousands of Dollars) Assets Liabilities Total Assets Liabilities Total
- -----------------------------------------------------------------------------------------------------------------------------------
Depreciation $ $382,983 $382,983 $ $364,710 $364,710
Regulatory accounts receivable 162,339 162,339 110,666 110,666
Deferred investment tax credits (32,336) (32,336) (33,256) (33,256)
Customer advances for construction (21,774) (21,774) (28,225) (28,225)
Regulatory asset 44,873 44,873 28,210 28,210
Other regulatory (153,634) 56,626 (97,008) (98,057) 34,211 (63,846)
---------- ---------- ---------- ---------- ---------- ----------
Total deferred income tax
(assets) liabilities $(207,744) $646,821 $439,077 $(159,538) $537,797 $378,259
---------- ---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ---------- ----------
The Parent files a consolidated federal income tax return and combined
California franchise tax reports which include the Company and the Parent's
other subsidiaries. The Gas Company pays the amount of taxes applicable to the
Company had it filed on a separate return basis.
The Company generally provides for income taxes on the basis of amounts expected
to be paid currently except for the provision for deferred income taxes on
regulatory accounts, customer advances for construction and accelerated
depreciation of property placed in service after 1980. In addition, the Company
recognizes certain other deferred tax liabilities (primarily accelerated
depreciation of property placed in service prior to 1981 and deferred investment
tax credits) which are expected to be recovered through future rates. At
December 31, 1993 and 1992, $109 million and $105 million, respectively, of
deferred income taxes have been offset by an equivalent amount in Regulatory
Assets.
- 42 -
4. Restructuring of Gas Supply Contracts and Comprehensive Settlement of
Regulatory Issues
RESTRUCTURING OF GAS SUPPLY CONTRACTS. The Company and its gas supply
affiliates have reached agreements with suppliers of California offshore and
Canadian gas for a restructuring of long-term gas supply contracts. The cost of
these supplies to the Company has been substantially in excess of the Company's
average delivered cost of gas. During 1993, these excess costs totaled
approximately $125 million.
The agreements substantially reduce the ongoing delivered costs of these gas
supplies and provide lump sum settlement payments of $375 million to the
suppliers. The expiration date for the Canadian gas supply contract has been
shortened from 2012 to 2003, and the supplier of California offshore gas
continues to have an option to purchase related gas treatment and pipeline
facilities owned by the Company's gas supply affiliate. The agreement with the
suppliers of Canadian gas is subject to certain Canadian regulatory and other
approvals.
COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES. The Company and a number of
interested parties (including the Division of Ratepayer Advocates (DRA) of the
CPUC, large noncore customers and ratepayer groups) have proposed for CPUC
approval a comprehensive settlement (Comprehensive Settlement) of a number of
pending regulatory issues including partial rate recovery of restructuring costs
associated with the gas supply contracts discussed above. The Comprehensive
Settlement, if approved by the CPUC, would permit the Company to recover in
utility rates approximately 80 percent of the contract restructuring costs of
$375 million and accelerated amortization of related pipeline assets of its gas
supply affiliates of approximately $130 million, together with interest, over a
period of approximately five years. The Company has filed a financing
application with the CPUC primarily for the borrowing of $425 million to provide
for funds needed under the Comprehensive Settlement. In addition to the gas
supply issues, the Comprehensive Settlement addresses the following other
regulatory issues:
NONCORE CUSTOMER RATES. The Comprehensive Settlement also
contemplates changes in the CPUC ratemaking procedures for determining
rates to be charged by the Company to its customers for the five-year
period commencing with the approval of the Comprehensive Settlement by
the CPUC. Rates charged to the customers would be established based
upon the Company's recorded throughput to these customers for 1991.
The existing limited regulatory balancing account treatment for
variances in noncore volumes from those estimated in establishing
rates would be eliminated subject to a crediting mechanism for noncore
revenues in excess of certain limits. Consequently, the Company would
bear the full risk of any declines
- 43 -
in noncore deliveries from 1991 levels. Any revenue enhancement from
deliveries in excess of 1991 levels will be limited by a crediting
account mechanism that will require a credit to customers of 87.5
percent of revenues in excess of certain limits. These annual limits
above which the credit is applicable increase from $11 million to $19
million over the five-year period to which the Comprehensive
Settlement is applicable.
REASONABLENESS REVIEWS. The Comprehensive Settlement contemplates the
settlement of all pending CPUC reasonableness reviews with respect to
the Company's gas purchases from 1989 through 1992 as well as certain
other future reasonableness review issues. The Comprehensive
Settlement also allows recovery of future excess interstate pipeline
capacity costs in the Company's rates.
GAS COST INCENTIVE MECHANISM. The Comprehensive Settlement
contemplates that a gas cost incentive mechanism (GCIM) would be
implemented with an initial term of three years. Gas costs in excess
of a tolerance band over average market price would be shared equally
between ratepayers and the Company. Savings from gas purchased below
the average market price would be also shared equally between the
ratepayers and the Company. The GCIM would provide a 4 1/2 percent
tolerance band in 1994 and a 4 percent tolerance band in 1995 and
1996. The GCIM is intended to replace the current gas procurement
reasonableness review process. On March 16, 1994, the CPUC issued its
decision approving the GCIM for implementation for a three year trial
period beginning April 1, 1994.
ATTRITION ALLOWANCES. The Comprehensive Settlement contemplates that
the Company may receive annual allowances for operational attrition
for 1995 and 1996 only to the extent that the annual inflation rate
for those years exceeds 2 percent and 3 percent, respectively. This
is a departure from past regulatory practice of allowing recovery of
the full effect of inflation in rates. The Company intends to
continue to attempt to control operating expenses and investment in
those years to amounts authorized in rates to offset the effect of
this regulatory change.
The Company believes the Comprehensive Settlement will be approved by
the CPUC; therefore, it has been reflected in the Company's financial
statements. Approximately $465 million is included in Regulatory
- 44 -
Accounts Receivable and Regulatory Assets for the recovery of costs as provided
in the Comprehensive Settlement. Accounts Payable-Affiliates include the
liability for lump sum settlement payments of $375 million to restructure
long-term gas supply contracts. Upon giving effect to liabilities previously
recognized at the Company, the costs of the Comprehensive Settlement, including
the restructuring of gas supply contracts, did not result in any additional
charge to The Gas Company's consolidated earnings. In the event the
Comprehensive Settlement is not approved by the CPUC, the Company will seek
other regulatory approvals for the recovery of these costs.
5. Commitments and Contingent Liabilities
ENVIRONMENTAL OBLIGATIONS. The Gas Company has identified and
reported to California environmental authorities 42 former gas manufacturing
sites for which it (together with other utilities as to 21 of the sites) may
have remedial obligations under environmental laws. In addition, the Company is
one of a large number of major corporations that have been named by federal
authorities as potentially responsible parties for environmental remediation of
two other industrial sites and a landfill site. These 45 sites are in various
stages of investigation or remediation. It is anticipated that the
investigation, and if necessary, remediation of these sites will be completed
over a period of from 10 years to 20 years.
The CPUC approved approximately $9 million in the Company's base rates
for expenditures beginning in 1990 through 1993, associated with investigating
these sites. In addition, the CPUC previously has approved a special ratemaking
procedure with respect to environmental remediation costs under which, upon
approval by the CPUC on a site-by-site basis, these costs are accumulated for
recovery in future rates subject to a reasonableness review. However, in a
decision issued in late 1992 in connection with its initial reasonableness
review of these costs, the CPUC concluded that the Company had failed to
demonstrate, by clear and convincing evidence, the reasonableness for rate
recovery of the applied for remediation costs under the existing ratemaking
procedure. The decision concluded that a reasonableness review procedure may not
be appropriate for rate recovery of environmental remediation costs. In
addition, the CPUC ordered the Company along with other California energy
utilities and the DRA to work toward the development of an alternate ratemaking
procedure including cost sharing between shareholder and ratepayers.
In November 1993, a collaborative settlement agreement between the
above parties was submitted to the CPUC for approval that recommends a
ratemaking mechanism that would provide recovery of 90 percent of environmental
investigation and remediation costs without reasonableness
- 45 -
review. In addition, the utilities would have the opportunity to retain a
percentage of any insurance recoveries to offset the 10 percent of costs not
recovered in rates. On March 10, 1994, an administrative law judge's proposed
decision was issued which adopted the sharing mechanism discussed above. A
final CPUC decision is expected in mid-1994.
Through the end of 1993, preliminary investigations at 33 sites have
been completed by the Company and investigation and remediation liabilities are
estimated to be $82 million for all 45 sites. The liability estimated for these
sites is subject to future adjustment pending further investigation. In 1993
and 1992, the Company charged $7 million and $5 million, respectively, to income
and the remaining amount is included in Regulatory Assets. The Company believes
that any costs not ultimately recovered through rates, insurance or other means,
upon giving effect to previously established liabilities, will not have a
material adverse effect on the Company's financial statements.
OTHER COMMITMENTS AND CONTINGENCIES. On January 17, 1994, the
Company's service area was struck by a major earthquake. The result was a
disruption in service to less than 3 percent of its customers at any given time
and damage to some facilities. The financial impact of the damages related to
the earthquake not recovered by insurance is expected to be recovered in rates
under an existing regulatory mechanism, and should have no impact on the
Company's financial statements.
At December 31, 1993, the Company had commitments for capital
expenditures of approximately $30 million.
6. Leases
The Gas Company has leases on real and personal property expiring at
various dates from 1994 to 2011. The rentals payable under these leases are
determined on both fixed and percentage bases and most leases contain options to
extend which are excercisable by the Company.
Rental expense under operating leases was $39 million, $37 million and
$24 million, in 1993, 1992 and 1991, respectively.
- 46 -
The following is a schedule of future minimum operating lease
commitments as of December 31, 1993:
Future Minimum
(Thousands of Dollars) Lease Payments
- --------------------------------------------------------------
Year Ending December 31
1994 $ 27,516
1995 26,384
1996 25,050
1997 24,416
1998 23,912
Later years 235,902
----------
Total $363,180
----------
----------
7. Compensating Balances and Short-term Borrowing Arrangements
The Company has $825 million of unsecured revolving lines of credit,
of which $325 million is a multi-year credit agreement requiring annual fees of
.125 percent and $500 million is a 364 day credit agreement requiring annual
fees of .10 percent. At December 31, 1993, all bank lines of credit were
unused. The unused bank lines of credit support the Company's commercial paper
program and provide liquidity for the Company.
At December 31, 1993 and 1992, The Gas Company had commercial paper
obligations of $267 million and $215 million, respectively, with weighted
average annual interest rates of 3.25 percent and 3.81 percent, respectively.
8. In-Substance Defeasance of Debt
During 1992, the Company established irrevocable trusts to satisfy
future principal and interest payments related to $200 million of its Series S
and U First Mortgage Bonds. The first mortgage bonds, accrued interest thereon
and related unamortized debt discount were removed from the 1992 Consolidated
Balance Sheet in an in-substance defeasance transaction. The loss resulting
from these transactions did not have a material impact on earnings.
9. Fair Value of Financial Instruments
The carrying amount of cash and cash equivalents approximates fair
value because of the short maturity of those instruments. The Company's Flexible
Auction Series preferred stocks approximate fair value since they are remarketed
periodically.
The fair value of the Company's long-term debt and 6 percent
preferred, 6 percent Series A preferred and 7 3/4 percent preferred stock is
estimated based on the quoted market prices for the same or similar issues or on
the current rates offered to the Company for debt of similar remaining
maturities. The fair value of these financial
- 47 -
instruments is different from the carrying amount. The fair value of the swap
transaction is the estimated amount that the bank would receive or pay to
terminate the swap agreement at the reporting date, taking into account current
exchange rates and the current credit worthiness of the swap counterparty.
The following financial instruments have a fair value which is different from
the carrying amount as of December 31.
1993 1992
---- ----
Carrying Fair Carrying Fair
Amount Value Amount Value
- --------------------------------------------------------------------------------------------------------------
(Dollars in Millions)
Long-Term Debt $1,253 $1,272 $1,186 $1,228
Preferred Stocks $ 97 $ 95 22 $ 17
- --------------------------------------------------------------------------------------------------------------
- 48 -
10. Capital Stock
The amount of capital stock outstanding is as follows:
December 31, 1993 December 31, 1992
--------------------------- ----------------------------
Number Thousands Number Thousands
of Shares of Dollars of Shares of Dollars
- --------------------------------------------------------------------------------------------------------------
PREFERRED STOCK:
cumulative, voting (a) (b) (c):
6%, $25 par value 79,011 $ 1,975 79,011 $ 1,975
6%, Series A, $25 par value 783,032 19,576 783,032 19,576
Series Preferred, no par value:
Flexible Auction, Series A 500 50,000 500 50,000
Flexible Auction, Series B 750 75,000
Flexible Auction, Series C 500 50,000 500 50,000
7 3/4%, $25 Stated Value 3,000,000 75,000
---------- ----------
Total $196,551 $196,551
---------- ----------
---------- ----------
PREFERENCE STOCK - cumulative, voting,
no par value (a) (c)
COMMON STOCK -
no par value (a) (c) 91,300,000 $834,889 19,300,000 $834,889
---------- ----------
---------- ----------
(a) The Gas Company's Articles of Incorporation authorize the following stocks:
100 million shares of Common Stock; 160,000 shares of 6% Preferred Stock;
840,000 shares of 6% Preferred Stock, Series A; 5 million shares of Series
Preferred Stock and 5 million shares of Preference Stock.
(b) Each issue of the Flexible Auction Series Preferred Stock is auctioned on
specified dividend dates. The term of each subsequent dividend period is, at The
Gas Company's option, 49 days or longer, not to exceed ten years. The weighted
average dividend rates for the Flexible Auction Series Preferred Stock for 1993,
1992 and 1991 were: Series A, 2.67 percent, 3.21 percent and 4.77 percent,
respectively; Series B 3.28 percent, 3.24 percent and 4.89 percent,
respectively; Series C, 2.75 percent, 3.28 percent and 4.1 percent,
respectively. Subsequent dividend rates may be affected by general market
conditions and the credit rating assigned to the Flexible Auction Series
Preferred Stock. The Gas Company has the option of redeeming the shares, in
whole or in part, at $100,000 per share plus accumulated dividends, on any
scheduled dividend payment date.
(c) In the event of any liquidation, dissolution or winding up of The Gas
Company, the holders of shares of each series of Preferred Stock and of each
series of Series Preferred Stock would be entitled to receive the stated value
or the liquidation preference for their shares, plus accrued dividends before
any amount shall be paid to the holders of Preference Stock or Common Stock. If
the amounts payable with respect to the shares of each series of Preferred Stock
or Series Preferred Stock are not paid in full, the holders
- 49 -
of such shares will share ratably in any such distribution. After payment in
full to the holders of each series of Preferred Stock, Series Preferred Stock
and Preference Stock of the liquidating distributions to which they are
entitled, the remaining assets and funds of The Gas Company would be divided pro
rata among the holders of the 6% Preferred Stock and the holders of Common
Stock.
In January 1993, the Company issued 3 million shares of 7 3/4 percent
Series Preferred Stock. The proceeds of $75 million which were used to redeem
the Flexible Auction Series Preferred Stock, Series B. In addition, the Company
also issued 72 million shares of common stock to the Parent.
11. Transactions with Affiliates
Pacific Interstate Transmission Company, Pacific Interstate Offshore
Company and Pacific Offshore Pipeline Company, subsidiaries of the Parent and
gas supply affiliates of The Gas Company, sell and transport gas to the Company
under tariffs approved by the Federal Energy Regulatory Commission. During
1993, 1992 and 1991, billings for such gas purchases totaled $344 million, $356
million, and $381 million, respectively. The Gas Company has long-term gas
purchase and transportation agreements with the affiliates extending through the
year 2012 requiring certain minimum payments which allow the affiliates to
recover the construction cost of their facilities. The Gas Company is obligated
to make minimum annual payments to cover the affiliates' operation and
maintenance expenses, demand charges paid to their suppliers, current taxes
other than income taxes, and debt service costs, including interest expense and
scheduled retirement of debt. These long-term agreements have recently been
restructured in conjunction with the Comprehensive Settlement, previously
discussed (see Note 4).
12. Pension, Postretirement and Other Employee Benefit Plans
PENSION PLANS. The Gas Company has a noncontributory defined benefit
pension plan covering substantially all of its employees. Benefits are based on
employees' years of service and compensation during his or her last years of
employment. The Gas Company's policy is to fund the plan annually at a level
which is fully deductible for federal income tax purposes and as necessary on an
actuarial basis to provide assets sufficient to meet the benefits to be paid to
plan members.
In conformity with generally accepted accounting principles for a rate
regulated enterprise, The Gas Company has recorded regulatory adjustments to
reflect, in net income, pension costs calculated under the actuarial method
allowed for ratemaking. The cumulative difference between
- 50 -
the net periodic pension cost calculated for financial reporting and ratemaking
purposes has been included as a deferred charge (credit) in the Consolidated
Balance Sheet.
Pension expense is as follows:
Year Ended December 31,
----------------------------------------
(Thousands of Dollars) 1993 1992 1991
- --------------------------------------------------------------------------------------------
Service cost - benefits earned during the period $ 31,828 $ 30,327 $ 28,580
Interest cost on projected benefit obligation 78,727 75,578 69,621
Actual return on plan assets (153,293) (68,730) (220,042)
Net amortization and deferral 54,816 (13,041) 147,682
---------- ---------- ----------
Net periodic pension cost 12,078 24,134 25,841
Special early retirement program 17,546 12,227
Postretirement health care and life insurance
benefits 22,088 15,545
Regulatory adjustment 919 (8,891) 1,400
---------- ---------- ----------
Total pension expense $ 30,543 $ 49,558 $ 42,786
---------- ---------- ----------
---------- ---------- ----------
- 51 -
A reconciliation of the pension plans' funded status to the pension
liability recognized in the Consolidated Balance Sheet is as follows:
December 31,
--------------------------
(Thousands of Dollars) 1993 1992
- -----------------------------------------------------------------------------------------------------------------------
Actuarial present value of pension benefit obligations:
Accumulated benefit obligation, including $792,800 and $659,700
in vested benefits at December 31, 1993 and 1992, respectively $ 907,890 $ 758,104
Effect of future salary increases 267,061 266,902
------------ ------------
Projected benefit obligation 1,174,951 1,025,006
Plan assets at fair value, primarily publicly traded common
stocks and equity pooled funds 1,282,921 1,147,898
------------ ------------
Plan assets greater than projected benefit obligation 107,970 122,892
Unrecognized net gain (157,215) (176,117)
Unrecognized prior service cost 39,480 43,212
Unrecognized transition obligation 5,658 8,456
------------ ------------
Accrued pension liability included in the Consolidated Balance Sheet $ (4,107) $ (1,557)
------------ ------------
Deferred pension charge (credit) included in the Consolidated Balance Sheet $ (390) $ 529
------------ ------------
------------ ------------
The plans' major actuarial assumptions include:
Weighted average discount rate 7% 8%
Rate of increase in future compensation levels 5% 6%
Expected long-term rate of return on plan assets 8 1/2% 8 1/2%
POSTRETIREMENT BENEFIT PLANS. In 1993, the Company adopted Statement
of Financial Accounting Standards No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions" (SFAS 106). SFAS 106 requires the
accrual of the cost of certain postretirement benefits other than pensions over
the active service period of the employee. The Company previously recorded
these costs when paid or funded. In accordance with SFAS 106, the Company
elected to amortize the unfunded transition obligation of $256 million over 20
years. The CPUC in late 1992 authorized SFAS 106 amounts to be recovered in
rates; therefore, a regulatory asset has been recorded to reflect the portion of
the liability which will be recovered in future rates.
The Company's postretirement benefit plan currently provides medical
and life insurance benefits to qualified retirees. In the past, employee
cost-sharing provisions have been implemented to control the increasing costs of
these benefits. Other changes could occur in the future. The Company's policy
is to fund these benefits at a level which is fully tax deductible for federal
income tax purposes, not to exceed amounts recoverable in rates, and as
- 52 -
necessary on an actuarial basis to provide assets sufficient to be paid to plan
participants. The net periodic postretirement benefit cost was as follows:
Year Ended December 31,
------------------------
(Thousands of Dollars) 1993
- ------------------------------------------------------------------------------------------------------
Service cost - benefits earned during the period $11,917
Interest cost on projected benefit obligation 26,848
Actual return on plan assets (10,076)
Net amortization and deferral 15,205
-------
Net periodic postretirement benefit cost $43,894
- ------------------------------------------------------------------------------------------------------
Prior to 1993, the Company commenced funding its future liability for
postretirement benefits through the pension plan . Amounts funded were subject
to the respective income tax limitations and amounts provided through rates. In
1992 and 1991, the amounts funded totaled $22 million and $16 million,
respectively.
A reconciliation of the plan's funded status to the postretirement
benefit liability recognized in the Consolidated Balance Sheet is as follows:
(Thousands of Dollars) December 31, 1993
- -----------------------------------------------------------------------------------------------
Accumulated postretirement benefit obligation:
Retirees $147,666
Fully eligible active plan participants 178,777
Other active plan participants 30,799
----------
357,242
Plan assets at fair value, primarily publicly traded common stocks
and equity pooled funds (116,803)
----------
Unfunded accumulated postretirement benefit obligation 240,439
Unrecognized net transition obligation (242,827)
Unrecognized net gain 1,365
----------
Net postretirement benefit liability included in the Consolidated Balance Sheet (1,023)
----------
----------
The plan's major actuarial assumptions include:
Health care cost trend rate 8%
Weighted average discount rate 7%
Rate of increase in future compensation levels 5%
Expected long-term rate of return on plan assets 8 1/2%
- -----------------------------------------------------------------------------------------------
The assumed health care cost trend rate is 8 percent for 1994. The
trend rate is expected to decrease from 1995 to 1998 with a 6 percent ultimate
trend rate thereafter. The effect of a one-percentage-point increase in the
assumed health care cost trend rate for each future year is $8 million on the
aggregate of the service and interest cost components of net periodic
postretirement cost for 1993 and $61 million on the accumulated postretirement
benefit obligation at December 31, 1993. The estimated income tax rate used in
the return on plan assets is zero since the plan assets are invested in tax
exempt funds.
- 53 -
OTHER EMPLOYEE BENEFITS PLANS. Upon completion of one year of
service, all employees of the Company are also eligible to participate in the
Company's retirement savings plan administered by bank trustees. Employees may
contribute from 1 to 14 percent of their regular earnings. The Gas Company
generally contributes an amount of cash or a number of shares of the Parent's
common stock of equivalent fair market value which, when added to prior
forfeitures, will equal 50 percent of the first 6 percent of eligible base
salary contributed by employees. The employees' contributions, at the direction
of the employees, are primarily invested in the Parent's common stock, mutual
funds or guaranteed interest accounts. The Gas Company's contributions, which
were invested in the Parent's common stock, were $9 million each in 1993 and
1992 and $8 million in 1991.
In November 1992, the Financial Accounting Standards Board issued
Statement of Financial Accounting Standards No. 112, "Employers' Accounting for
Postemployment Benefits" (SFAS 112). SFAS 112 requires the accrual of the
obligation to provide benefits to former or inactive employees after employment
but before retirement. The new standard will be adopted by the Company in 1994
and is not expected to have a material impact on earnings since these costs,
primarily disability benefits, are currently recovered in rates as paid.
In 1993, the Company offered a special early retirement program for a
limited period to certain eligible employees. The cost of this program is
included in the total pension expense for 1993.
- 54 -
STATEMENT OF MANAGEMENT RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS
The consolidated financial statements have been prepared by
management. The integrity and objectivity of these financial statements and the
other financial information in the Annual Report, including the estimates and
judgments on which they are based, are the responsibility of management. The
financial statements have been audited by Deloitte & Touche, independent
auditors, appointed by the Board of Directors. Their report is shown on the
following page. Management has made available to Deloitte & Touche all of the
Company's financial records and related data, as well as the minutes of
shareholders' and directors' meetings.
Management maintains a system of internal accounting control which it
believes is adequate to provide reasonable, but not absolute, assurance that
assets are properly safeguarded and accounted for, that transactions are
executed in accordance with management's authorization and are properly recorded
and reported, and for the prevention and detection of fraudulent financial
reporting. Management monitors the system of internal control for compliance
through its own review and a strong internal auditing program which also
independently assesses the effectiveness of the internal controls. In
establishing and maintaining internal controls, the Company exercises judgment
in determining that the costs of such controls do not exceed the benefits to be
derived.
Management acknowledges its responsibility to provide financial
information (both audited and unaudited) that is representative of the Company's
operations, reliable on a consistent basis, and relevant for a meaningful
financial assessment of the Company. Management believes that the control
process enables them to meet this responsibility.
Management also recognizes its responsibility for fostering a strong
ethical climate so that the Company's affairs are conducted according to the
highest standards of personal and corporate conduct. This responsibility is
characterized and reflected in the Parent's code of corporate conduct, which is
publicized throughout the Company. The Parent maintains a systematic program to
assess compliance with this policy.
The Board of Directors has an Audit Committee composed solely of
directors who are not officers or employees of the Company. The Committee
recommends for approval by the full Board the appointment of the independent
auditors. The Committee meets periodically with management, with the Company's
internal auditors and with the independent auditors. The independent auditors
and the internal auditors also meet alone with the Audit Committee and have free
access to the Audit Committee at any time.
Richard D. Farman
Chief Executive Officer
Ralph Todaro
Vice President, Finance and Controller
January 31, 1994
- 55 -
INDEPENDENT AUDITORS' REPORT
Southern California Gas Company:
We have audited the consolidated financial statements of Southern California Gas
Company and its subsidiary (pages 31 to 53) as of December 31, 1993 and 1992,
and for each of the three years in the period ended December 31, 1993. Our
audits also included the consolidated financial statement schedules listed in
the Index at Item 14(a)2. These financial statements and financial statement
schedules 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, the consolidated financial statements present fairly, in all
material respects, the financial position of Southern California Gas Company and
its subsidiary as of December 31, 1993 and 1992, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting principles.
Also, in our opinion, such consolidated financial statement schedules, when
considered in relation to the basic consolidated financial statements taken as a
whole, present fairly in all material respects the information set forth
therein.
DELOITTE & TOUCHE
Los Angeles, California
January 31, 1994
- 56 -
OTHER INFORMATION
QUARTERLY FINANCIAL DATA (UNAUDITED)
1993
-------------------------------------------------------
Three Months Ended March 31 June 30 Sept. 30 Dec. 31
- ---------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating revenues $758,721 $633,440 $625,172 $793,741
Net operating revenue $ 70,602 $ 68,847 $ 75,270 $ 69,779
Net income $ 46,167 $ 47,462 $ 50,064 $ 49,983
Net income applicable to common stock $ 43,634 $ 45,025 $ 47,622 $ 47,513
1992
-------------------------------------------------------
Three Months Ended March 31 June 30 Sept. 30 Dec. 31
- -----------------------------------------------------------------------------------------------------------
(Thousands of Dollars)
Operating revenues $735,635 $633,028 $610,736 $860,526
Net operating revenue $ 72,693 $ 71,301 $ 74,751 $ 80,639
Net income $ 45,513 $ 46,438 $ 49,036 $ 53,729
Net income applicable to common stock $ 43,585 $ 44,626 $ 47,418 $ 52,095
- 57 -
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
Information required by this Item with respect to the Company's
directors is set forth under the caption "Election of Directors" in the
Company's Information Statement for its Annual Meeting of Shareholders scheduled
to be held on April 25, 1994. Such information is incorporated herein by
reference.
Information required by this Item with respect to the Company's
executive officers is set forth in Item 1 of this Annual Report.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this Item is set forth under the caption
"Election of Directors", "Executive Compensation" and "Employee Benefit Plans"
in the Company's Information Statement for its Annual Meeting of Shareholders
scheduled to be held on April 25, 1994. Such information is incorporated herein
by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN
BENEFICIAL OWNERS AND MANAGEMENT
Information required by this Item is set forth under the caption
"Election of Directors" in the Company's Information Statement for its Annual
Meeting of Shareholders scheduled to be held on April 25, 1994. Such
information is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS
Not applicable.
- 58 -
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT
SCHEDULES, AND REPORTS ON FORM 8-K
(a) Documents filed as part of this report:
1. CONSOLIDATED FINANCIAL STATEMENTS (SET FORTH IN
ITEM 8 OF THIS ANNUAL REPORT ON FORM 10-K):
1.01 Report of Deloitte & Touche
Independent Auditors.
1.02 Statement of Consolidated
Income for the years ended
December 31, 1993, 1992 and 1991.
1.03 Statement of Consolidated Cash Flows
for the years ended December 31, 1993,
1992 and 1991.
1.04 Consolidated Balance Sheet at December 31,
1993 and 1992.
1.05 Statement of Consolidated Long-Term Debt
at December 31, 1993 and 1992.
1.06 Statement of Consolidated Shareholders'
Equity for the years ended December 31, 1993,
1992 and 1991.
1.07 Notes to Consolidated Financial
Statements.
2. SUPPLEMENTAL FINANCIAL STATEMENT SCHEDULES:
2.01 Report of Deloitte & Touche,
Independent Auditors (contained in Item 1.01)
2.02 Utility Plant for the years ended
December 31, 1993, 1992 and 1991 -
Schedule V. . . . . . . . . . . . . . . . . . . . .
2.03 Accumulated Depreciation and Amortization
of Utility Plant for the years ended
December 31, 1993, 1992 and 1991 -
Schedule VI . . . . . . . . . . . . . . . . . . . .
2.04 Short-Term Borrowings, December 31, 1993,
1992 and 1991 - Schedule IX . . . . . . . . . . . .
- 59 -
3. ARTICLES OF INCORPORATION AND BY-LAWS:
3.01 Restated Articles of Incorporation of
Southern California Gas Company
(Note 25; Exhibit 3.01)
3.02 Bylaws of Southern California Gas Company. . . . . .
4. INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS:
(Note: As permitted by Item 601(b)(4)(iii) of Regulation S-K, certain
instruments defining the rights of holders of long-term debt for which the
total amount of securities authorized thereunder does not exceed ten
percent of the total assets of Southern California Gas Company and its
subsidiaries on a consolidated basis are not filed as exhibits to this
Annual Report. 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
(Note 13; Exhibit 4.01).
4.02 First Mortgage Indenture of Southern California
Gas Company to American Trust Company dated as of
October 1, 1940 (Note 1; Exhibit B-4).
4.03 Supplemental Indenture of Southern California Gas
Company to American Trust Company dated as of
July 1, 1947 (Note 2; Exhibit B-5).
4.04 Supplemental Indenture of Southern California
Gas Company to American Trust Company dated as
of August 1, 1955 (Note 3; Exhibit 4.07).
4.05 Supplemental Indenture of Southern California
Gas Company to American Trust Company dated as
of June 1, 1956 (Note 4; Exhibit 2.08).
4.06 Supplemental Indenture of Southern California
Gas Company to Wells Fargo Bank, National
Association dated as of August 1, 1972 (Note 7;
Exhibit 2.19).
4.07 Supplemental Indenture of Southern California
Gas Company to Wells Fargo Bank, National
Association dated as of May 1, 1976 (Note 6;
Exhibit 2.20).
4.08 Supplemental Indenture of Southern California
Gas Company to Wells Fargo Bank, National
Association dated as of September 15, 1981
(Note 12; Exhibit 4.25).
- 60 -
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 (Note 16; 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 (Note 18; 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 (Note 24; Exhibit 4.37).
4.12 Specimen Flexible Auction Series A Preferred
Stock Certificate (Note 21; Exhibit 4.11).
4.13 Specimen Flexible Auction Series B Preferred
Stock Certificate (Note 22; Exhibit 4.12).
4.14 Specimen Flexible Auction Series C Preferred
Stock Certificate (Note 23; Exhibit 4.13).
4.15 Specimen 7 3/4% Series Preferred Stock
Certificate (Note 25; Exhibit 4.15).
10. MATERIAL CONTRACTS
10.01 Restatement and Amendment of Pacific
Enterprises 1979 Stock Option Plan
(Note 10; Exhibit 1.1).
10.02 Pacific Enterprises Supplemental Medical
Reimbursement Plan for Senior Officers
(Note 11; Exhibit 10.24).
10.03 Pacific Enterprises Financial Services
Program for Senior Officers (Note 11;
Exhibit 10.25).
10.04 Southern California Gas Company Retirement
Savings Plan, as amended and restated as of
August 30, 1988 (Note 15; Exhibit 28.02).
10.05 Southern California Gas Company Statement of
Life Insurance, Disability Benefit and Pension
Plans, as amended and restated as of
January 1, 1985 (Note 16; Exhibit 10.27).
- 61 -
10.06 Southern California Gas Company Pension
Restoration Plan For Certain Management
Employees (Note 11; Exhibit 10.29).
10.07 Pacific Enterprises Executive Incentive
Plan (Note 18; Exhibit 10.13)
10.08 Pacific Enterprises Deferred Compensation
Plan for Key Management Employees (Note 15;
Exhibit 10.41).
10.09 Pacific Enterprises Stock Incentive Plan
(Note 19; Exhibit 4.01).
22. SUBSIDIARIES OF THE REGISTRANT
22.01 List of subsidiaries of Southern
California Gas Company. . . . . . . . . . . . . . . . . .
24. CONSENTS OF EXPERTS AND COUNSEL
24.01 Consent of Deloitte & Touche,
Independent Auditors. . . . . . . . . . . . . . . . . . .
25. POWER OF ATTORNEY
25.01 Power of Attorney of Certain Officers
and Directors of Southern California Gas
Company (contained on the signature pages
of this Annual Report on Form 10-K).
(b) REPORTS ON FORM 8-K:
The following reports on Form 8-K were filed during the last
quarter of 1993.
Report Date Item Reported
----------- -------------
Oct. 29, 1993 Item 5
Nov. 3, 1993 Item 5
Dec. 3, 1993 Item 5
Dec. 17, 1993 Item 5
_________________________
NOTE: Exhibits referenced to the following notes were filed with the
documents cited below under the exhibit or annex number following
such reference. Such exhibits are incorporated herein by
reference.
- 62 -
Note
Reference Document
1 Registration Statement No. 2-4504 filed by Southern California Gas
Company on September 16, 1940.
2 Registration Statement No. 2-7072 filed by Southern California Gas
Company on March 15, 1947.
3 Registration Statement No. 2-11997 filed by Pacific Lighting
Corporation on October 26, 1955.
4 Registration Statement No. 2-12456 filed by Southern California Gas
Company on April 23, 1956.
5 Registration Statement No. 2-45361 filed by Southern California Gas
Company on August 16, 1972.
6 Registration Statement No. 2-56034 filed by Southern California Gas
Company on April 14, 1976.
7 Registration Statement No. 2-59832 filed by Southern California Gas
Company on September 6, 1977.
8 Registration Statement No. 2-42239 filed by Pacific Lighting Gas
Supply Company (under its former name of Pacific Lighting Service
Company) on October 29, 1971.
9 Registration Statement No. 2-43834 filed by Pacific Lighting
Corporation on April 17, 1972.
10 Registration Statement No. 2-66833 filed by Pacific Lighting
Corporation on March 5, 1980.
11 Annual Report on Form 10-K for the year ended December 31, 1980, filed
by Pacific Lighting Corporation.
12 Annual Report on Form 10-K for the year ended December 31, 1981, filed
by Pacific Lighting Corporation.
13 Annual Report on Form 10-K for the year ended December 31, 1980 filed
by Southern California Gas Company.
14 Quarterly Report on Form 10-Q for the quarter ended September 30,
1983, filed by Southern California Gas Company.
15 Registration Statement No. 33-6357 filed by Pacific Enterprises on
December 30, 1988.
- 63 -
16 Annual Report on Form 10-K for the year ended December 31, 1984, filed
by Southern California Gas Company.
17 Current Report on Form 8-K for the month of March 1986, filed by
Southern California Gas Company.
18 Annual Report on Form 10-K for the year ended December 31, 1987 filed
by Pacific Lighting Corporation.
19 Registration Statement No. 33-21908 filed by Pacific Enterprises on
May 17, 1988.
20 Annual Report on Form 10-K for the year ended December 31, 1988, filed
by Southern California Gas Company.
21 Annual Report on Form 10-K for the year ended December 31, 1989, filed
by Southern California Gas Company.
22 Annual Report on Form 10-K for the year ended December 31, 1990, filed
by Southern California Gas Company.
23 Annual Report on Form 10-K for the year ended December 31, 1991, filed
by Southern California Gas Company.
24 Registration Statement No. 33-50826 filed by Southern California Gas
Company on August 13, 1992.
25 Annual Report on Form 10-K for the year ended December 31, 1992, filed
by Southern California Gas Company.
- 64 -
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, thereunto duly authorized.
SOUTHERN CALIFORNIA GAS COMPANY
By: WILLIS B. WOOD
---------------------------------------
Name: WILLIS B. WOOD, JR.
Title: Presiding Director
Dated: March 28, 1994
- 65 -
Each person whose signature appears below hereby authorizes Lloyd A.
Levitin, Ralph Todaro and Warren I. Mitchell, and each of them, severally, as
attorney-in-fact, to sign on his or her behalf, individually and in each
capacity stated below, and file all amendments to this Annual Report.
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
Signature Title Date
WILLIS B. WOOD, JR. Presiding March 28, 1994
- ------------------------------- Director and Director
(Willis B. Wood, Jr.) (Principal Executive Officer)
LLOYD A. LEVITIN Executive Vice - March 28, 1994
- ------------------------------ President and Chief
(Lloyd A. Levitin) Financial Officer
(Principal
Financial Officer)
HYLA H. BERTEA Director March 28, 1994
- ------------------------------
(Hyla H. Bertea)
HERBERT L. CARTER Director March 28, 1994
- ------------------------------
(Herbert L. Carter)
JAMES F. DICKASON Director March 28, 1994
- ------------------------------
(James F. Dickason)
RICHARD D. FARMAN Director March 28, 1994
- ------------------------------
(Richard D. Farman)
WILFORD D. GODBOLD, JR. Director March 28, 1994
- ------------------------------
(Wilford D. Godbold, Jr.)
IGNACIO E. LOZANO, JR. Director March 28, 1994
- ------------------------------
(Ignacio E. Lozano, Jr.)
HAROLD M. MESSMER, JR. Director March 28, 1994
- ------------------------------
(Harold M. Messmer, Jr.)
- 66 -
PAUL A. MILLER Director March 28, 1994
- ------------------------------
(Paul A. Miller)
JOSEPH N. MITCHELL Director March 28, 1994
- ------------------------------
(Joseph N. Mitchell)
JOSEPH R. RENSCH Director March 28, 1994
- ------------------------------
(Joseph R. Rensch)
ROCCO C. SICILIANO Director March 28, 1994
- ------------------------------
(Rocco C. Siciliano)
LEONARD H. STRAUS Director March 28, 1994
- ------------------------------
(Leonard H. Straus)
DIANA L. WALKER Director March 28, 1994
- ------------------------------
(Diana L. Walker)
APPENDIX TO FORM 10-K
DESCRIPTION OF MAP
This is a map of the State of California. The shaded portions of the map,
most of southern and parts of central California, indicate the area served by
Southern California Gas Company.