<PAGE>
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, 1994
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
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(State of incorporation) (IRS Employer Identification No.)
555 West Fifth Street, Los Angeles, California 90013-1011
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(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
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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 14, 1995, was approximately $87 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 May 2, 1995.
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TABLE OF CONTENTS
PART I
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Operating Statistics. . . . . . . . . . . . . . . . 5
Service Area. . . . . . . . . . . . . . . . . . . . 7
Utility Services. . . . . . . . . . . . . . . . . . 8
Demand for Gas. . . . . . . . . . . . . . . . . . . 8
Competition . . . . . . . . . . . . . . . . . . . . 9
Supplies of Gas . . . . . . . . . . . . . . . . . . 9
Rates and Regulation. . . . . . . . . . . . . . . . 12
Environmental Matters . . . . . . . . . . . . . . . 13
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . 13
Management. . . . . . . . . . . . . . . . . . . . . . . . . . 14
Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . 15
Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . 15
Item 4. Submission of Matters to a Vote of Security Holders . . . . . 15
PART II
Item 5. Market for Registrant's Common
Equity and Related Stockholder Matters. . . . . . . . . . . . 16
Item 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . 16
Item 7. Management's Discussion and Analysis
of Financial Condition and Results of
Operations. . . . . . . . . . . . . . . . . . . . . . . . . . 17
Item 8. Financial Statements and
Supplementary Data. . . . . . . . . . . . . . . . . . . . . . 25
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure. . . . . . . . . . . . . . . . . . . . . 45
PART III
Item 10. Directors and Executive Officers
of the Registrant . . . . . . . . . . . . . . . . . . . . . . 46
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Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . 46
Item 12. Security Ownership of Certain
Beneficial Owners and Management. . . . . . . . . . . . . . . 46
Item 13. Certain Relationships and Related
Transactions. . . . . . . . . . . . . . . . . . . . . . . . . 46
PART IV
Item 14. Exhibits, Financial Statement Schedules,
and Reports on Form 8-K . . . . . . . . . . . . . . . . . . . 47
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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 distribution,
transmission and storage 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 17 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 1,200 meters. Noncore customers consist of large-volume gas users such as
electric utilities, wholesale and large commercial and industrial customers.
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. Under current ratemaking policies, the Company's future earnings
and cash flow will be determined primarily by the allowed rate of return on
common equity, the growth in rate base, noncore market pricing and the variance
in gas volumes delivered to noncore customers versus CPUC-adopted forecast
deliveries and the ability of management to control expenses and investment in
line with the amounts authorized by the CPUC to be collected in rates. The
impact of any future regulatory restructuring, such as performance based
ratemaking ("PBR") (See "Rates and Regulation"), and increased competitiveness
in the industry, including the continuing threat of customers bypassing the
Company's system and obtaining service directly from interstate pipelines, and
electric industry restructuring, may also affect the Company's performance.
For 1995, the CPUC has authorized the Company to earn a rate of
return on rate base of 9.67 percent and a 12.00 percent rate of return on common
equity compared to 9.22 percent and 11.00 percent, respectively, in 1994.
Growth in rate base for 1994 was approximately 3 percent. Rate base is expected
to remain at the same level in 1995. The Company has achieved or exceeded its
authorized rate of return on rate base for the last twelve 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.
OPERATING STATISTICS
The following table sets forth certain operating statistics of
the Company from 1990 through 1994.
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OPERATING STATISTICS
<TABLE>
<CAPTION>
Year Ended December 31
----------------------------------------------------------------------
1994 1993 1992 1991 1990
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<S> <C> <C> <C> <C> <C>
Gas Sales, Transportation & Exchange
Revenues (thousands of dollars):
Residential $1,712,899 $1,652,562 $1,483,654 $1,673,837 $1,547,492
Commercial/Industrial 798,180 853,579 836,672 977,065 1,057,030
Utility Electric Generation 118,353 147,208 194,639 148,573 235,102
Wholesale 98,354 116,737 128,881 144,779 164,716
Exchange 690 3,745 5,863 7,482 8,496
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Total in rates 2,728,476(1) 2,773,831 2,649,709 2,951,736 3,012,836
Regulatory balancing accounts
and other (141,952) 37,243 190,216 (21,430) 199,789
---------- ---------- ---------- ---------- ----------
Operating Revenue $2,586,524 $2,811,074 $2,839,925 $2,930,306 $3,212,625
---------- ---------- ---------- ---------- ----------
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Volumes (millions of cubic feet):
Residential 256,400 247,507 243,920 249,522 261,887
Commercial/Industrial 347,419 339,706 363,124 460,368 436,330
Utility Electric Generation 260,290 212,720 220,642 170,043 158,985
Wholesale 146,279 147,978 149,232 141,931 139,034
Exchange 10,002 16,969 23,888 25,604 30,246
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Total 1,020,390 964,880 1,000,806 1,047,468 1,026,482
--------- ------- --------- --------- ---------
--------- ------- --------- --------- ---------
Core 341,469 338,795 334,630 351,432 372,677
Noncore 678,921 626,085 666,176 696,036 653,805
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Total 1,020,390 964,880 1,000,806 1,047,468 1,026,482
--------- ------- --------- --------- ---------
--------- ------- --------- --------- ---------
Sales 362,624 352,052 355,177 411,414 515,757
Transportation 647,764 595,859 621,741 610,450 480,479
Exchange 10,002 16,969 23,888 25,604 30,246
--------- ------- --------- --------- ---------
Total 1,020,390 964,880 1,000,806 1,047,468 1,026,482
--------- ------- --------- --------- ---------
--------- ------- --------- --------- ---------
Revenues (per thousand cubic feet):
Residential $6.68 $6.68 $6.08 $6.71 $5.91
Commercial/Industrial $2.30 $2.51 $2.30 $2.12 $2.42
Utility Electric Generation $0.45 $0.69 $0.88 $0.87 $1.48
Wholesale $0.67 $0.79 $0.86 $1.02 $1.18
Exchange $0.07 $0.22 $0.25 $0.29 $0.28
Customers
Active Meters (at end of period):
Residential 4,483,324 4,459,250 4,445,500 4,429,896 4,381,563
Commercial 187,518 187,602 189,364 193,051 193,409
Industrial 23,505 23,924 24,419 25,642 26,530
Utility Electric Generation 8 8 8 8 8
Wholesale 3 3 2 2 2
--------- --------- --------- --------- ---------
Total 4,694,358 4,670,787 4,659,293 4,648,599 4,601,512
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Residential Meter Usage (annual average):
Revenues $383 $371 $334 $380 $356
Volumes (thousands of cubic feet) 57.4 55.6 55.0 56.6 60.3
System Usage (millions of cubic feet):
Average Daily Sendout 2,795 2,611 2,717 2,881 2,824
Peak Day Sendout 4,350 4,578 4,547 4,356 5,267
Sendout Capability (at end of period) 7,570 7,351 7,419 7,073 7,073
Degree Days(2):
Number 1,438(3) 1,203 1,258 1,409 1,432
Average (20 Year) 1,418 1,430 1,458 1,474 1,506
Percent of Average 101.4% 84.1% 86.3% 95.6% 95.1%
Population of Service Area
(estimated at year end) 17,070,000 15,600,000 15,600,000 15,600,000 15,100,000
<FN>
(1) Beginning January 1, 1994, rates included the ratepayer's portion of the
Comprehensive Settlement (the amount included in rates for 1994 was $119
million).
(2) 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.
(3) Estimated calendar degree days.
</TABLE>
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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 17
million people. As indicated by the following map, its service territory
includes most of southern California and parts of central California.
[MAP OF THE GAS COMPANY'S SERVICE TERRITORY]
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 separated, 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 primarily include utility electric
generation, wholesale and large commercial and industrial customers. 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.
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 margin whether the Company buys the gas and
sells it to the customer or transports gas already owned by the customer. (See
"Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations-Operating Results.")
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.
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 1994, The Gas Company stored approximately 24 billion cubic feet of
customer-owned gas.
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 1994, 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 72 percent for clothes drying.
Demand for natural gas by noncore customers such as large volume
commercial, industrial and electric generating customers is very sensitive to
the price of alternative competitive fuels. These customers number only
approximately 1,200; however, during 1994, they accounted for approximately 17
percent of total gas revenues, 67 percent of total gas volumes delivered and 14
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
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<PAGE>
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.
COMPETITION
Since interstate pipelines began operations in The Gas Company's
service territories, 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. 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.
The Company is fully at risk for lost noncore volumes due to competition, and
would not receive balancing account treatment except in the enhanced oil
recovery market.
In order to respond to certain bypass threats, 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.
The CPUC has also 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. These decisions 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 new
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 "Item 7. Management's Discussion and Analysis
of Financial Condition and Result of Operations - Ratemaking Procedures -
Comprehensive Settlement of Regulatory Issues.") will help improve the Company's
competitiveness by reducing the cost of transportation service to noncore
customers.
Historically, environmental laws have favorably impacted the use
of natural gas in the Company's service territory, particularly by utility
electric generation customers. However, increasingly complex administrative
requirements may discourage natural gas use by large commercial and industrial
customers.
In April 1994, the CPUC announced it would review the structure
of California's electric utility service, a review that could lead to
significant changes in the way investor-owned utilities conduct business,
including the amount of electricity purchased from out-of-state suppliers. The
CPUC's proposed deregulation of electricity sales by the year 2002 may affect
the future volumes of natural gas the Company transports for electric utilities.
Utility electric generation customers currently account for 26 percent of the
Company's annual throughput. See "Item 7. Management's Discussion and Analysis
of Financial Condition and Results of Operation - Factors Influencing Future
Performance - Electric Industry Restructuring."
SUPPLIES OF GAS
In 1994, The Gas Company delivered approximately 1 trillion cubic
feet of natural gas through its system. Approximately 65 percent of these
deliveries were customer-owned gas for which The Gas Company provided
transportation services, compared to 64 percent in 1993. 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
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(primarily El Paso Natural Gas Company and Transwestern Natural Gas Company)
that 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).
Existing interstate pipeline capacity into California exceeds
current demand by over 1 billion cubic feet per day. Up to 2 billion cubic feet
per day of capacity on the El Paso and Transwestern interstate pipeline systems,
representing over $175 million and $55 million, respectively, of reservation
charges annually, may be relinquished within the next few years based on
existing contract reduction options and contract expirations. Some of this
capacity may not be resubscribed. Current FERC regulation could permit costs of
unsubscribed capacity to be allocated to remaining firm service customers,
including The Gas Company. Under existing regulation in California, the Company
would have the opportunity to include its portion of any such reallocated costs
in its rates. If competitive conditions did not support higher rates resulting
from these reallocated costs, then the Company would be at risk for lost
revenues in the noncore market.
The Company, as a part of a coalition of customers who hold 90
percent of the firm transportation capacity rights on the El Paso and
Transwestern systems, has offered a proposal for market based rates with
balanced incentives to El Paso and Transwestern to resolve the issue of
unsubscribed capacity. See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations - Factors Influencing Future
Performance - Excess Interstate Pipeline Capacity."
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The following table sets forth the sources of gas deliveries by
The Gas Company from 1990 through 1994.
SOURCES OF GAS
--------------
<TABLE>
<CAPTION>
Year Ended December 31
----------------------------------------------------------------------
1994 1993 1992 1991 1990
---- ---- ---- ---- ----
<S> <C> <C> <C> <C> <C>
Gas Purchases: (Millions of Cubic Feet)
Market Gas:
30-Day 98,071 84,696 20,695 139,649 148,849
Other 148,371 159,197 198,049 168,486 225,710
--------- ------- --------- --------- ---------
Total Market Gas 246,442 243,893 218,744 308,135 374,559
Affiliates 101,276 96,559 99,226 98,566 103,406
California Producers &
Federal Offshore 36,158 28,107 42,262 39,613 52,633
--------- ------- --------- --------- ---------
Total Gas Purchases 383,876 368,559 360,232 446,314 530,598
Customer-Owned Gas and
Exchange Receipts 658,293 622,307 641,080 629,038 531,263
Storage Withdrawal
(Injection) - Net (9,299) (9,498) 14,379 (8,451) (13,288)
Company Use and
Unaccounted For (12,480) (16,488) (14,885) (19,432) (22,091)
--------- ------- --------- --------- ---------
Net Gas Deliveries 1,020,390 964,880 1,000,806 1,047,469 1,026,482
--------- ------- --------- --------- ---------
--------- ------- --------- --------- ---------
Gas Purchases: (Thousands of dollars)
Commodity Costs $ 643,865 $ 815,145 $ 805,550 $1,071,445 $1,371,854
Fixed Charges* 368,516 397,714 397,579 358,294 405,233
---------- ---------- ---------- ---------- ----------
Total Gas Purchases $1,012,381 $1,212,859 $1,203,129 $1,429,739 $1,777,087
---------- ---------- ---------- ---------- ----------
---------- ---------- ---------- ---------- ----------
Average Cost of Gas Purchased
(Dollars per Thousand Cubic Feet)** $1.68 $2.21 $2.24 $2.40 $2.59
----- ----- ----- ----- -----
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<FN>
* 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.
</TABLE>
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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 64 percent of total gas
volumes purchased by the Company during 1994, as compared with 66 percent and 61
percent, respectively, during 1993 and 1992. These supplies were generally
purchased at prices significantly below those for other long-term sources of
supply.
On March 16, 1994, the CPUC approved a new process for evaluating
the Company's gas purchases substantially replacing the previous process of
reasonableness reviews. The new "Gas Cost Incentive Mechanism" ("GCIM") is a
three-year pilot program that began in April 1994. The GCIM essentially
compares the Company's cost of gas with a benchmark level. See "Item 7.
"Management's Discussion and Analysis of Financial Condition and Results of
Operations - Ratemaking Procedures - GCIM."
The Gas Company estimates that sufficient natural gas supplies
will be available to meet the requirements of its customers into the next
century.
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 an opportunity to
earn a reasonable profit. The regulatory structure is complex and has a very
substantial impact on the profitability of the Company.
Under current ratemaking procedures, the return that the Company
is authorized to earn is the product of an 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
1995, approximately 89 percent of the CPUC-authorized gas margin has been
allocated to core customers and 11 percent to noncore customers, including
wholesale customers. Under the current regulatory framework, costs may be
reallocated between the core and the noncore customer classes once every other
year in a biennial cost allocation proceeding (BCAP).
During 1994, the Company began exploring a new approach for
setting rates to its customers known as "Performance Based Ratemaking." This
new approach, PBR, would maintain cost based rates but would link financial
performance with increases and decreases in productivity and generally would
allow for rates to increase by the rate of inflation, less an agreed upon
adjustment for productivity improvements. The Gas Company proposes to file a
PBR application with the CPUC in 1995, and if approved, the change would not
take effect until January 1, 1997, at the earliest. Although PBR could result
in increased earnings volatility, the Company would have the opportunity to
improve financial performance to the extent it was able to reduce expenses,
increase energy deliveries and generate profits from new products and
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services. See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations--Factors Influencing Future Performance."
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. As of December 31, 1994, eight of the
sites have been remediated, of which five have received certification from the
California Environmental Protection Agency. Preliminary investigations, at a
minimum, have been completed on thirty-three of the sites, including those sites
at which the remediations described above have been completed. In addition, the
Company is one of a large number of major corporations that have been identified
as a potentially responsible party for environmental remediation of three
industrial waste disposal sites and a landfill site. These 46 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.
In May 1994, the CPUC approved a collaborative settlement between
the Company and other California utilities and the Division of Ratepayer
Advocates which provides for rate recovery of 90 percent of environmental
investigation and remediation costs without reasonableness review. In addition,
the utilities have the opportunity to retain a percentage of any insurance
recovery to offset the 10 percent of costs not recovered in rates.
At December 31, 1994, the Company's estimated remaining
liability for investigation and remediation for the 46 sites was approximately
$65 million, which it is authorized to recover through the rate recovery
mechanism described above. The estimated liability is subject to future
adjustment pending further investigation. See "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operation - Factors
Influencing Future Performance - Environmental Matters." Because of the
current and expected rate recovery, the Company believes that compliance with
environmental laws and regulations will not have a material adverse effect on
its financial statements.
EMPLOYEES
The Company employs approximately 8,200 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 5,560
employees expire with respect to wages and working conditions on March 31, 1996
and with respect to medical benefits on December 31, 1995. The agreement with
respect to all benefits except medical expires on March 31, 1995, and the
Company is currently in the process of negotiating a new agreement.
In order to enhance its overall competitiveness, the Company has
also continued to downsize. In 1994, approximately 800 positions were
eliminated and the Company expects to eliminate another 300-500 positions in
1995 as a result of efficiency and productivity improvements, and more
reductions will result from organizational realignment. In addition, the
Company has a competitive benchmarking program that compares the costs of
retaining certain support functions versus outsourcing them. Functions which
cannot be performed at competitive rates may be contracted to outside providers.
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MANAGEMENT
The executive officers of Southern California Gas Company are as
follows:
<TABLE>
<CAPTION>
Became an
Executive
Name Age Position Officer
- ---- --- -------- -------
<S> <C> <C> <C>
Warren I. Mitchell 57 President August 1981
Lloyd A. Levitin 62 Executive Vice President and June 1993
Chief Financial Officer
Debra L. Reed 38 Senior Vice President August 1988
Lee M. Stewart 49 Senior Vice President November 1990
Paul J. Cardenas 48 Vice President January 1995
Pamela J. Fair 36 Vice President January 1995
Eric B. Nelson 45 Vice President January 1995
Richard M. Morrow 45 Vice President January 1995
Roy M. Rawlings 50 Vice President January 1987
Anne S. Smith 41 Vice President November 1991
George E. Strang 55 Vice President July 1984
Ralph Todaro 44 Vice President and Controller November 1988
Dennis V. Arriola 34 Treasurer August 1994
</TABLE>
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 for Mr. Arriola. From 1987 until joining the Company in August
1994, Mr. Arriola was a Vice President of Bank of America NT&SA (1992-1994) and
a Vice President of Security Pacific National Bank (1987-1992).
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.
- 14 -
<PAGE>
ITEM 2. PROPERTIES
At December 31, 1994, The Gas Company owned approximately 3,040
miles of transmission and storage pipeline, 42,683 miles of distribution
pipeline and 42,647 miles of service piping. It also owned 13 transmission
compressor stations and 6 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 1994 to a
vote of the Company's security holders.
- 15 -
<PAGE>
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
<TABLE>
<CAPTION>
Three Months Ended 1994 1993
- --------------------------------------------------------------------------------------------
Preferred Stock: 7 3/4% 6%-Series A 7 3/4% 6%-Series A
------ ----------- ------ -----------
<S> <C> <C> <C> <C>
March 31 $26 1/4 - 24 5/8 $21 1/2 - 20 $27 - 24 5/8 $21 5/8 - 19 1/2
June 30 $25 1/4 - 23 1/4 $20 3/4 - 18 3/4 $27 - 25 1/8 $22 3/4 - 20
Sept. 30 $24 1/4 - 22 3/8 $19 1/2 - 17 3/4 $27 - 26 $23 1/4 - 22 1/4
Dec. 31 $23 3/8 - 21 $18 - 16 1/4 $26 7/8 - 25 1/2 $22 3/4 - 20 1/4
</TABLE>
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.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth certain selected financial data of the Company
for 1990 through 1994.
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
---------------------------------------------------------------------------
Year Ended December 31
- ---------------------------------------------------------------------------------------------
(Thousands of 1994 1993 1992 1991 1990
Dollars) ---- ---- ---- ---- ----
- --------
<S> <C> <C> <C> <C> <C>
Operating revenues $2,586,524 $2,811,074 $2,839,925 $2,930,306 $3,212,625
Net income $ 190,513 $ 193,676 $ 194,716 $ 211,792* $ 177,744
Total assets $4,775,763 $4,950,220 $4,155,399 $4,059,186 $4,013,497
Long-term debt $1,396,931 $1,235,622 $1,147,198 $1,147,132 $1,016,493
<FN>
*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.
</TABLE>
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.
- 16 -
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Southern California Gas Company (the "Company") is a subsidiary of Pacific
Enterprises (the "Parent"). The Company, a public utility, provides natural
gas distribution, transmission and storage in a 23,000-square mile service area
in southern California and parts of central California. This section includes
management's analysis of operating results from 1992 through 1994, and is
intended to provide additional information about the Company's financial
performance. This section also focuses on major factors expected to influence
future operating results and discusses future investment and financing plans.
This section should be read in conjunction with the Consolidated Financial
Statements set forth in Item 8.
OPERATIONS
The Company's markets are separated into core customers and noncore customers.
Core customers consist of approximately 4.7 million customers (4.5 million
residential and 0.2 million smaller commercial and industrial customers). The
noncore market consists of approximately 1,200 customers which primarily include
utility electric generation, wholesale, and large commercial and industrial
customers. Many 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.
FINANCIAL RESULTS
Under current utility ratemaking policies, the return that the Company is
authorized to earn is the product of an 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 California Public Utilities Commission ("CPUC") in
setting rates. In addition, achievement of the authorized rate of return is
affected by other regulatory and operating factors. The Company is exploring a
new approach for setting rates to its customers as discussed in Factors
Influencing Future Performance.
Key financial and operating data for the Company are highlighted in the table
below.
<TABLE>
<CAPTION>
(Dollars in Millions) 1994 1993 1992
- ----------------------------------------------------------------------------------------
<S> <C> <C> <C>
Net income (after preferred dividends) $180 $184 $188
Authorized return on rate base 9.22% 9.99% 10.49%
Authorized return on common equity 11.00% 11.90% 12.65%
Weighted average rate base $2,862 $2,769 $2,720
Growth in weighted average rate base over prior period 3.4% 1.8% 2.1%
- ----------------------------------------------------------------------------------------
</TABLE>
Net income decreased $4 million in 1994 due primarily to a reduction in the
Company's authorized rate of return on common equity from 11.90 percent in 1993
to 11.00 percent in 1994 partially offset by reductions in operating expenses,
higher earnings from the noncore market and the growth in rate base. During
1993, net income decreased $4 million 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 reductions in the Company's cost of service,
including operating and financing costs, and growth in rate base.
- 17 -
<PAGE>
The Company has achieved or exceeded the rate of return on rate base authorized
by the CPUC for 12 consecutive years. In 1994, the Company achieved a 9.74
percent return on rate base compared to a 9.22 percent authorized return and a
12.33 percent return on equity compared to an 11.00 percent authorized return.
The improved returns were primarily due to more efficient operations through
aggressive reductions in operating expenses, noncore earnings and a conservation
award. The Company plans to continue efforts to reduce costs in 1995. In 1995,
the Company is authorized to earn 9.67 percent on rate base and 12.00 percent on
common equity. Rate base is expected to remain at the same level as 1994.
The Company's operating revenues decreased $224 million in 1994. The decrease
reflects a reduction in authorized gas margin and the average unit cost of gas
partially offset by the growth in rate base and an increase in noncore volumes
transported. The Company's cost of gas distributed decreased $195 million in
1994. The decrease reflects a lower average unit cost of gas in 1994 partially
offset by a slight increase in core volumes delivered. Core volumes increased
as a result of colder weather in 1994 compared to 1993. The Company's operating
revenues decreased $29 million from 1992 to 1993. The decrease reflects a
reduction in authorized gas margin, the average unit cost of gas and noncore
volumes transported partially offset by the growth in rate base. The Company's
cost of gas distributed decreased $20 million in 1993. The decrease reflects a
lower average unit cost of gas in 1993 partially offset by an increase in core
volumes delivered. The average unit cost of gas has declined as a result of
lower market prices. The average commodity cost of gas purchased by the
Company, excluding fixed charges, for 1994 was $1.68 per thousand cubic feet,
compared to $2.21 per thousand cubic feet in 1993 and $2.24 per thousand cubic
feet in 1992.
- 18 -
<PAGE>
OPERATING RESULTS
The table below summarizes the components of throughput and revenue in rates
charged to customers for the past three years. Beginning January 1, 1994, rates
included the ratepayer portion of the Comprehensive Settlement (See Note 2 in
Notes to Consolidated Financial Statements). The amount included in rates for
1994 was $119 million.
<TABLE>
<CAPTION>
Transportation
Gas Sales and Exchange Total
--------- ------------ -----
(Dollars in millions,
volume in billion cubic Throughput Revenue Throughput Revenue Throughput Revenue
feet)
- ---------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1994:
Residential 254 $1,704 2 $ 9 256 $1,713
Commercial/Industrial 100 592 258 207 358 799
Utility Electric
Generation 260 118 260 118
Wholesale 8 21 138 77 146 98
-------------------------------------------------------------------------------------------
Total in Rates 362 $2,317 658 $411 1,020 2,728
Balancing and Other (141)
----------
Total Operating
Revenues $2,587
-------------------------------------------------------------------------------------------
1993:
Residential 244 $1,641 4 $ 12 248 $1,653
Commercial/Industrial 97 610 259 247 356 857
Utility Electric
Generation 4 213 143 213 147
Wholesale 11 27 137 90 148 117
-------------------------------------------------------------------------------------------
Total in Rates 352 $2,282 613 $492 965 2,774
Balancing and Other 37
----------
Total Operating
Revenues $2,811
-------------------------------------------------------------------------------------------
1992:
Residential 241 $1,475 3 $ 9 244 $1,484
Commercial/Industrial 100 586 287 256 387 842
Utility Electric
Generation 21 221 174 221 195
Wholesale 14 34 135 95 149 129
--------------------------------------------------------------------------------------------
Total in Rates 355 $2,116 646 $534 1,001 2,650
Balancing and Other 190
-----------
Total Operating
Revenues $2,840
- ---------------------------------------------------------------------------------------------------------------------
- ---------------------------------------------------------------------------------------------------------------------
</TABLE>
Although the revenues from transportation throughput are less than for gas
sales, the Company generally earns the same margin whether it buys the gas and
sells it to the customer or transports gas already owned by the customer. For
1995, approximately 89 percent of total margin authorized is contributed by the
core market (residential and smaller commercial and industrial customers), with
11 percent contributed by the noncore market. Throughput, the total gas sales
and transportation volumes moved through the Company's system, has increased
during 1994 as a result of greater weather-related demand in noncore volumes,
primarily utility electric generation and large commercial and industrial
customers. During 1993, throughput declined from 1992 levels as a result of
bypass of the Company's system, primarily by enhanced oil recovery customers
(See Factors Influencing Future Performance).
- 19 -
<PAGE>
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 the
opportunity to earn a reasonable return on investment. Current ratemaking
procedures are summarized below.
GENERAL RATE CASES. General rate applications are filed every three years. 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 as discussed below, see BCAP),
depreciation, interest, taxes and return on rate base. Rate adjustments from
the Company's next general rate case proceeding would normally be scheduled to
go into effect in 1997, however, the Company has filed a petition for
modification with the CPUC to delay the proceeding and is exploring a new
approach for setting rates to its customers. Known as "Performance Based
Ratemaking" (PBR), this new method would link financial performance with
productivity improvements and generally would allow for rates to increase by the
rate of inflation, less an agreed-upon percentage for productivity improvements.
The Company proposes to file a PBR application with the CPUC in 1995 and if
approved, to implement it in 1997 at the earliest. For a further discussion of
PBR, see Factors Influencing Future Performance-Performance Based Ratemaking.
ATTRITION. In a process referred to as the annual attrition allowance, the CPUC
annually adjusts rates for years between general rate cases to cover the changes
in rate base and the effects of inflation as adjusted by a productivity
improvement factor. Separate proceedings are held annually to review the
Company's cost of capital, including return on common equity, interest costs and
changes in capital structure. The CPUC has authorized annual allowances for
operational attrition for 1995 and 1996 to the extent that the annual inflation
rate for those years exceeds 2 percent and 3 percent, respectively, for
operating and maintenance expenses. This compares to a 3 percent productivity
adjustment authorized for 1994. The rate base attrition will continue based
upon a three year rolling average of recorded net utility plant additions. For
further discussion of annual attrition allowances, see Note 2 of Notes to
Consolidated Financial Statements.
GCIM. On March 16, 1994, the CPUC approved a new process for evaluating the
Company's gas purchases substantially replacing the previous process of
reasonableness reviews. The new Gas Cost Incentive Mechanism (GCIM) is a
three-year pilot program that began April 1, 1994. The GCIM essentially
compares the Company's cost of gas with a benchmark level, which represents the
average market price of 30-day firm spot supplies delivered to the Company's
service area.
All savings from gas purchased below the benchmark are shared equally between
ratepayers and shareholders. The Company can recover all costs in excess of the
benchmark, but within a tolerance band. If the Company's cost of gas exceeds
the tolerance band, then the excess costs are shared equally between ratepayers
and shareholders. For the first year of the program, the GCIM provides a 4.5
percent tolerance band above the benchmark. For the second and third years of
the program, the tolerance band decreases to 4 percent. In 1994, since the
inception of the GCIM, the Company's gas purchases were within the tolerance
band.
The Company enters into a certain amount of gas futures contracts in the open
market to help reduce gas costs within the GCIM tolerance band. The Company's
policy is to use gas futures contracts to mitigate risk and better manage gas
costs. The CPUC has approved the use of gas futures for managing risk
associated with the GCIM. For the year ended December 31, 1994, gains or losses
from gas futures contracts are not material to the Company's financial
statements.
BCAP. In a biennial cost allocation proceeding (BCAP), the CPUC specifies for
each two-year period the allocation of total authorized revenue requirements
(including cost of gas) to be
- 20 -
<PAGE>
collected from the Company's core and noncore customer classes. The Company
maintains regulatory accounts to accumulate undercollections and overcollections
from customers and makes periodic filings with the CPUC to adjust future rates
to amortize outstanding balances in those accounts. In the most recent BCAP
decision issued by the CPUC in December 1994, the Company has been authorized to
collect a $130 million revenue increase effective January 1, 1995. Of this
amount, $45 million has been authorized for the 1995 attrition allowance, $27
million as a result of the increase in the 1995 authorized rate of return on
common equity and rate base, and $58 million for the BCAP. Included in the BCAP
decision was a partial reallocation of costs to further reduce subsidies by
nonresidential core customers to residential customers in order to better align
residential rates with the cost of providing residential service.
For the core market, the Company records 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, subject to the terms and conditions of the GCIM
mechanism and the Comprehensive Settlement (as discussed below). Conversely,
the Company reduces rates for decreased gas acquisition costs or higher than
projected revenues from increases in demand by core customers.
RESTRUCTURING OF GAS SUPPLY CONTRACTS.
The Company and its gas supply affiliates restructured long-term gas supply
contracts with suppliers of California offshore and Canadian gas. The Company's
cost of these supplies had been substantially in excess of its average delivered
cost of gas for all supplies. The new contracts substantially reduced the
ongoing delivered costs of these gas supplies and provided for lump sum payments
of $391 million to the suppliers. The expiration date for the Canadian gas
supply contract was also shortened from 2012 to 2003.
COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES.
On July 20, 1994, the CPUC approved a comprehensive settlement (Comprehensive
Settlement) of a number of pending regulatory issues including partial rate
recovery of restructuring costs associated with the long-term gas supply
contracts discussed above. The Comprehensive Settlement permits the Company to
recover in utility rates approximately 80 percent of the contract restructuring
costs of $391 million and accelerated amortization of related pipeline assets of
approximately $140 million, together with interest, over a period of
approximately five years (See Note 2 of Notes to Consolidated Financial
Statements).
FACTORS INFLUENCING FUTURE PERFORMANCE
Under current 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 market pricing and the variance in gas volumes delivered
to noncore customers versus CPUC-adopted forecast deliveries and the ability of
management to control expenses and investment in line with the amounts
authorized by the CPUC to be collected in rates.
The impact of any future regulatory restructuring, such as Performance Based
Ratemaking, increased competitiveness in the industry, including the continuing
threat of customers bypassing the Company's system and obtaining service
directly from interstate pipelines, and electric industry restructuring could
also affect the Company's future performance. The Company's ability to report
as earnings the results from revenues in excess of its authorized return from
noncore customers due to volume increases has been substantially eliminated for
the five years beginning August 1, 1994 as a consequence of the Comprehensive
Settlement described above. This is because certain forecasted levels of gas
deliveries in excess of the 1991 throughput levels used to
- 21 -
<PAGE>
establish noncore rates were contemplated in estimating the costs of the
Comprehensive Settlement at December 31, 1993.
The following discussion addresses each of the major factors expected to
influence future performance:
ALLOWED RATE OF RETURN AND GROWTH IN RATE BASE. The Company's earnings for 1995
will be affected by the increase in the authorized rate of return on common
equity, reflecting the overall increase in cost of capital. For 1995, the
Company is authorized to earn a rate of return on rate base of 9.67 percent and
a rate of return on common equity of 12.00 percent compared to 9.22 percent and
11.00 percent, respectively, in 1994. Rate base is expected to remain at the
same level as 1994.
NONCORE BYPASS. Since the completion of the Kern River and Mojave Interstate
Pipelines 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. The Kern River and Mojave Interstate Pipelines now deliver natural gas
to customers formerly served by the Company amounting to 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, and therefore, does not have a material impact on the
Company's earnings. However, bypass of other markets may also occur, and the
Company is fully at risk for lost noncore volumes due to competition, and would
not receive balancing account treatment except in the enhanced oil recovery
market.
NONCORE PRICING. In order to respond to certain bypass threats, the Company has
received authorization from the CPUC for expedited review of price discounts
proposed through 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 costs between core and noncore
customers to reduce subsidization of core customer rates by noncore customers.
Effective in June 1993, the CPUC implemented the new cost allocation 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 new
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 improve the Company's competitiveness by
reducing the cost of transportation service to noncore customers.
NONCORE THROUGHPUT. The Company's earnings are subject to variability if gas
throughput to its noncore customers varies from estimates adopted by the CPUC in
establishing rates. There is a continuing risk that an unfavorable variance in
noncore volumes can result from external factors such as weather, the use of
increased hydroelectric power, the price relationship between alternative fuels
and natural gas, competing pipeline bypass of the Company's system and general
economic conditions. 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 exists the
risk that an unfavorable variance in the noncore volumes can result.
MANAGEMENT CONTROL OF EXPENSES AND INVESTMENT. Over the past 12 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 to
remain competitive and reduce the risk of bypass. Future cost reductions are
expected, including employee reductions and productivity gains as a result of
moving to a realigned business unit organization. In connection with the
Comprehensive Settlement, the Company has agreed to absorb a 2 percent and 3
percent
- 22 -
<PAGE>
productivity adjustment to its authorized level of operating and maintenance
expenses in 1995 and 1996, respectively, before it can seek any rate recovery
due to the effects of inflation.
The Company also bears the risk of nonrecovery of margin or other costs
authorized by the CPUC for the noncore market under the terms of the
Comprehensive Settlement. Unanticipated significant increases in the inflation
rate could also reduce earnings and cash flow.
PERFORMANCE BASED RATEMAKING. During 1994, the Company began exploring a new
approach for setting rates to its customers. Known as PBR, the new method would
maintain cost based rates but would link financial performance with increases
and decreases in productivity and generally would allow for rates to increase by
the rate of inflation, less an agreed-upon adjustment for productivity
improvements. Although PBR could result in increased earnings volatility, the
Company would have the opportunity to improve financial performance to the
extent it was able to reduce expenses, increase energy deliveries and generate
profits from new products and services. Under PBR, the Company would be at risk
for changes in interest rates and cost of capital, changes in core volumes not
related to weather, and achieving the productivity improvements. The Company
proposes to file a PBR application with the CPUC in 1995 and if approved, to
implement it in 1997 at the earliest.
ELECTRIC INDUSTRY RESTRUCTURING. Demand for natural gas by electric generation
customers is sensitive to the price and availability of electric power generated
in other areas and purchased by these electric generation customers. In April
1994, the CPUC announced it will review the structure of California's electric
utility service, a review that could lead to significant changes in the way
California's investor-owned electric utilities and cogenerators conduct
business. The CPUC's proposal has no immediate effect on the Company's
operations. However, the Company is closely monitoring the process and has
taken an active role in the proceedings because of its considerable experience
with natural gas deregulation and because future volumes of natural gas it
transports for electric utilities could be adversely affected. In addition, as
a result of restructuring, electric rates could become more competitive in the
future.
The following table indicates the comparative energy cost of gas versus the
energy cost of electricity in 1995 for an average residential customer in the
Company's service territory:
<TABLE>
<CAPTION>
Fuel Price Price/MMBTU
---- ----- -----------
<S> <C> <C>
Natural Gas $.716/Therm $ 7.16
Electricity $.132/KWH $38.58
</TABLE>
The electric industry restructuring may result in a reduction of electric rates
to core customers, but it is unlikely to overcome the entire cost advantage of
natural gas for residential heating.
EXCESS INTERSTATE PIPELINE CAPACITY. Existing interstate pipeline capacity into
California exceeds current demand by over 1 billion cubic feet per day. Up to 2
billion cubic feet per day of capacity on the El Paso and Transwestern
interstate pipeline systems, representing over $175 million and $55 million,
respectively, of reservation charges annually, may be relinquished within the
next few years based on existing contract reduction options and contract
expirations. Some of this capacity may not be resubscribed. Current FERC
regulation could permit the cost of unsubscribed capacity to be allocated to
remaining firm service customers, including the Company. Under existing
regulation in California, the Company would have the opportunity to include its
portion of any such reallocated costs in its rates. If competitive conditions
did not support higher rates resulting from these reallocated costs, then the
Company would be at risk for lost revenues in the noncore market.
- 23 -
<PAGE>
The Company, as a part of a coalition of customers who hold 90 percent of the
firm transportation capacity rights on the El Paso and Transwestern systems, has
offered a proposal for market based rates with balanced incentives to El Paso
and Transwestern to resolve the issue of stranded or unsubscribed capacity.
Negotiations on a settlement of the issue, consistent with the coalition's
proposal, are progressing with Transwestern. Discussions of the proposal with
El Paso are continuing.
ENVIRONMENTAL MATTERS. The Company's operations and those of its customers are
affected by a growing number of environmental laws and regulations. These laws
and regulations affect current operations as well as future expansion.
Historically, environmental laws favorably impacted the use of natural gas in
the Company's service territory, particularly by utility electric generation and
large industrial customers. However, increasingly complex administrative
requirements may discourage natural gas use by commercial and large industrial
customers. Environmental laws also require clean up of facilities no longer in
use. Because of current and expected rate recovery, 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 4 of Notes to Consolidated Financial Statements.
CAPITAL EXPENDITURES
Capital expenditures were $245 million, $318 million and $326 million in 1994,
1993 and 1992, respectively. Capital expenditures primarily represent ratebase
investment. The decline in capital expenditures is due primarily to the
continued sluggishness in the southern California economy, lower amounts
required to replace aging pipeline and fewer large projects. Capital
expenditures are estimated to be $250 million in 1995 and will be financed
primarily by internally-generated funds.
LIQUIDITY
Cash and cash equivalents at December 31, 1994 was $58 million. Regulatory
Accounts Receivable decreased in 1994 primarily due to overcollections under the
BCAP balancing account procedures due primarily to lower gas prices than
forecasted. Regulatory Accounts Receivable increased in 1993 and 1992
reflecting higher undercollections due primarily to core market throughput
falling below CPUC-adopted forecast levels. Regulatory Assets decreased in 1994
primarily due to the recovery of $119 million related to the Comprehensive
Settlement. In 1993, Accounts Payable-Other included the liability for lump sum
settlement payments of $375 million to restructure long-term gas supply
contracts which were paid in 1994.
INTEREST EXPENSE. Interest expense on long-term debt was $89 million, $96
million and $107 million for 1994, 1993 and 1992, respectively. Interest
expense in 1994 and 1993 was reduced from 1992 levels as a result of refinancing
debt at lower interest rates.
FUTURE BORROWINGS. At December 31, 1994, all financing for the Comprehensive
Settlement has been completed. The Company has $330 million of commercial paper
outstanding to finance the Comprehensive Settlement. This amount is expected to
decline over the five year period of the Comprehensive Settlement as amounts are
recovered in rates. The Company anticipates that cash requirements in 1995 for
capital expenditures, dividends and debt requirements will come from cash
generated from operating activities, existing cash balances and any future
refinancing of existing debt. Future refinancings are expected to include a
combination of commercial paper and medium-term notes.
- 24 -
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
STATEMENT OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
Year Ended December 31
--------------------------------------
(Thousands of Dollars) 1994 1993 1992
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES $2,586,524 $2,811,074 $2,839,925
---------- ---------- ----------
OPERATING EXPENSES
Cost of gas distributed 991,625 1,187,072 1,207,275
Operation 745,961 768,677 730,638
Maintenance 80,980 99,795 101,680
Depreciation 233,580 228,244 219,011
Income taxes 145,603 134,491 164,487
Local franchise payments 41,966 46,217 50,743
Ad valorem taxes 36,901 32,592 37,677
Payroll and other taxes 31,281 29,488 29,030
---------- ---------- ----------
Total 2,307,897 2,526,576 2,540,541
---------- ---------- ----------
Net Operating Revenue 278,627 284,498 299,384
---------- ---------- ----------
OTHER INCOME AND (DEDUCTIONS)
Interest income 6,623 1,668 3,948
Regulatory interest 14,046 4,924 1,731
Allowance for equity funds used during
construction 2,394 4,406 3,608
Income taxes on non-operating income 941 5,670 572
Other - net (7,033) (5,245) (11,314)
---------- ---------- ----------
Total 16,971 11,423 (1,455)
---------- ---------- ----------
INTEREST CHARGES AND (CREDITS)
Interest on long-term debt 89,023 95,806 106,641
Other interest 17,425 9,180 (1,132)
Allowance for borrowed funds used
during construction (1,363) (2,741) (2,296)
---------- ---------- ----------
Total 105,085 102,245 103,213
---------- ---------- ----------
Net Income 190,513 193,676 194,716
Dividends On Preferred Stock 10,468 9,882 6,992
---------- ---------- ----------
Net Income Applicable To Common Stock $ 180,045 $ 183,794 $ 187,724
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
- 25 -
<PAGE>
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
December 31
----------------------
(Thousands of Dollars) 1994 1993
- ------------------------------------------------------------------------------------------
<S> <C> <C>
ASSETS
Utility Plant - at original cost $5,613,013 $5,422,549
Less Accumulated Depreciation 2,400,601 2,205,043
Utility plant - net 3,212,412 3,217,506
Current Assets:
Cash and cash equivalents 57,531 14,533
Accounts receivable - trade (less allowance for doubtful
receivables of $10,830 in 1994 and $16,745 in 1993) 523,975 503,308
Regulatory accounts receivable - net 360,479 443,718
Gas in storage 63,470 53,114
Materials and supplies 25,792 20,618
Prepaid expense 34,129 22,971
---------- ----------
Total current assets 1,065,376 1,058,262
---------- ----------
Regulatory Assets 497,975 674,452
---------- ----------
Total $4,775,763 $4,950,220
---------- ----------
---------- ----------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common equity:
Common stock $ 834,889 $ 834,889
Retained earnings 643,040 607,250
Total common equity 1,477,929 1,442,139
Preferred stock 196,551 196,551
Long-term debt 1,396,931 1,235,622
---------- ----------
Total capitalization 3,071,411 2,874,312
---------- ----------
Current Liabilities:
Short-term debt 278,201 267,000
Accounts payable - trade 212,888 188,484
Accounts payable - affiliates 35,013 513,306
Accounts payable - other 143,235 228,517
Accrued taxes and franchise payments 117,576 21,907
Deferred income taxes 40,792 39,542
Long-term debt due within one year 86,000
Accrued interest 40,057 35,007
Other accrued liabilities 162,489 129,372
---------- ----------
Total current liabilities 1,116,251 1,423,135
---------- ----------
Customer Advances For Construction 44,269 45,493
Deferred Income Taxes 341,149 399,535
Deferred Investment Tax Credits 69,969 72,993
Other Deferred Credits 132,714 134,752
Commitments And Contingent Liabilities
---------- ----------
Total $4,775,763 $4,950,220
---------- ----------
---------- ----------
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- 26 -
<PAGE>
STATEMENT OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31
----------------------------------
(Thousands of Dollars) 1994 1993 1992
- ---------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $190,513 $193,676 $194,716
Items not requiring cash:
Depreciation 233,580 228,244 219,011
Deferred income taxes (49,432) 33,093 16,381
Deferred investment tax credits (3,024) (3,811) (3,616)
Allowance for funds used during construction (3,757) (7,147) (5,904)
Other (18,983) 22,442 24,258
Net change in other working capital components:
Accounts receivable (20,667) (3,235) 40,794
Regulatory accounts receivable 231,006 (107,320) (107,203)
Gas in storage (10,356) (13,279) 17,764
Other current assets (16,332) 19,787 37,432
Accounts payable (521,172) 77,672 (139,000)
Accrued taxes and franchise payments 30,386 (74,466) 25,965
Deferred income taxes - current 4,914 23,501 13,719
Other current liabilities 103,451 26,245 (7,693)
-------- -------- --------
Net cash provided by operating activities 150,127 415,402 326,624
-------- -------- --------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures for utility plant (244,721) (318,429) (326,085)
(Increase) Decrease in other assets - net 35,267 (52,929) (7,856)
-------- -------- --------
Net cash used in investing activities (209,454) (371,358) (333,941)
-------- -------- --------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends (154,723) (144,590) (133,861)
Issuance of long-term debt 245,847 631,000 282,000
Payments of long-term debt (569,239) (272,626)
Sale of preferred stock 75,000
Redemption of preferred stock (75,000)
Increase in short-term debt 11,201 52,000 92,000
-------- -------- --------
Net cash provided by (used in)
financing activities 102,325 (30,829) (32,487)
-------- -------- --------
Increase (Decrease) In
Cash And Cash Equivalents 42,998 13,215 (39,804)
Cash And Cash Equivalents - January 1 14,533 1,318 41,122
-------- -------- --------
Cash And Cash Equivalents - December 31 $ 57,531 $ 14,533 $ 1,318
-------- -------- --------
-------- -------- --------
SUPPLEMENTAL DISCLOSURE OF
CASH FLOW INFORMATION:
Cash Paid During The Year For:
Interest (net of amount capitalized) $107,088 $ 97,514 $ 11,574
-------- -------- --------
-------- -------- --------
Income taxes $ 89,135 $142,346 $105,241
-------- -------- --------
-------- -------- --------
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
- 27 -
<PAGE>
STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
Preferred Common Retained
(Thousands of Dollars) Stock Stock Earnings
- -----------------------------------------------------------------------------
<S> <C> <C> <C>
BALANCE AT 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 AT 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 AT DECEMBER 31, 1993 196,551 834,889 607,250
Net income 190,513
Cash dividends declared:
Preferred stock (10,468)
Common stock (144,255)
-------- -------- --------
BALANCE AT DECEMBER 31, 1994 $196,551 $834,889 $643,040
-------- -------- --------
-------- -------- --------
</TABLE>
The number of shares of preferred stock and common stock authorized and
outstanding at December 31, 1994 and 1993, is set forth in Note 9 of Notes to
Consolidated Financial Statements.
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
- 28 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Southern California Gas Company (the "Company") is a subsidiary of Pacific
Enterprises ("Parent"). The Parent owns approximately 96 percent of the
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 wholly-owned subsidiary, Southern California Gas Tower. The subsidiary 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
in 50 percent or less joint ventures and partnerships are accounted for by the
equity or cost method, as appropriate.
RECLASSIFICATIONS
Certain changes in account classification have been made in the prior years'
consolidated financial statements to conform to the 1994 financial statement
presentation.
REGULATION
The Company is a public utility and follows accounting policies prescribed or
authorized by the California Public Utilities Commission (CPUC). The Company
applies the provisions of Statement of Financial Accounting Standards No. 71,
"Accounting for the Effects of Certain Types of Regulation." This statement
requires cost-based rate regulated entities that meet certain criteria to
reflect the authorized recovery of costs due to regulatory decisions in their
financial statements.
GAS IN STORAGE
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 any effect on net income. If the first-in, first-out (FIFO) method
of accounting for gas in storage inventory had been used by the Company,
inventory would have been higher than reported at December 31, 1994 and 1993 by
$34 million and $58 million, respectively. Materials and supplies are generally
stated at the lower of cost, determined on an average cost basis, or market.
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.
REGULATORY ACCOUNTS RECEIVABLE - NET
Authorized regulatory balancing accounts are maintained to accumulate
undercollections and overcollections from the revenue and cost estimates adopted
by the CPUC in setting rates. The Company makes periodic filings with the CPUC
to adjust future gas rates to account for such variances.
- 29 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION (AFUDC)
AFUDC represents the cost of funds used to finance the construction of utility
plant and is added to the cost of utility plant. Interest expense of $4 million
in 1994, $7 million in 1993 and $6 million in 1992 was capitalized.
OTHER
Cash equivalents include short-term investments purchased with maturities of
less than 90 days. Other major accounting policies are included in the following
notes.
2. REGULATORY MATTERS
RESTRUCTURING OF GAS SUPPLY CONTRACTS
In 1993, the Company and its gas supply affiliates restructured long-term gas
supply contracts with suppliers of California offshore and Canadian gas. In the
past, the Company's cost of these supplies had been substantially in excess of
its average delivered cost of gas for all gas supplies.
The restructured contracts substantially reduced the ongoing delivered costs of
these gas supplies and provided lump sum payments totaling $391 million to the
suppliers. The expiration date for the Canadian gas supply contract was also
shortened from 2012 to 2003.
COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES
On July 20, 1994, the CPUC approved a comprehensive settlement (Comprehensive
Settlement) of a number of pending regulatory issues including rate recovery of
a significant portion of the restructuring costs associated with long-term gas
supply contracts discussed above. The Comprehensive Settlement permits the
Company to recover in utility rates approximately 80 percent of the contract
restructuring costs of $391 million and accelerated amortization of related
pipeline assets of approximately $140 million, together with interest, over a
period of approximately five years. In addition to the gas supply issues, the
Comprehensive Settlement addresses the following other regulatory issues:
NONCORE CUSTOMER RATES. The Comprehensive Settlement changed the
procedures for determining noncore rates to be charged by the Company to
its customers for the five-year period commencing August 1, 1994. Rates
charged to the customers are established based upon the Company's recorded
throughput to these customers for 1991. The Company will 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 from August 1, 1994 through July 31, 1999. The
Company's ability to report as earnings the results from revenues in excess
of its authorized return from noncore customers due to volume increases has
been substantially eliminated for the five years beginning August 1, 1994
as a consequence of the Comprehensive Settlement described above. This is
because forecasted deliveries in excess of the 1991 throughput levels used
to establish noncore rates were contemplated in estimating the costs of the
Comprehensive Settlement at December 31, 1993.
- 30 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
REASONABLENESS REVIEWS. The Comprehensive Settlement includes settlement
of all pending reasonableness reviews with respect to the Company's gas
purchases from April, 1989 through March, 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. On March 16, 1994, the CPUC approved a new
process for evaluating the Company's gas purchases, substantially replacing
the previous process of reasonableness reviews. The new Gas Cost Incentive
Mechanism (GCIM) is a three-year pilot program beginning April 1, 1994.
The GCIM essentially compares the Company's cost of gas with a benchmark
level, which is the average market price of 30-day firm spot supplies
delivered to the Company's service area.
All savings from gas purchased below the benchmark are shared equally
between ratepayers and shareholders. The Company can recover all costs in
excess of the benchmark but within a tolerance band. If the Company's cost
of gas exceeds the tolerance band, then the excess costs will be shared
equally between ratepayers and shareholders. For the first year of the
program, the GCIM provides a 4.5 percent tolerance band above the
benchmark. For the second and third years of the program, the tolerance
band decreases to 4.0 percent. In 1994, since the inception of the GCIM,
the Company's gas purchases were within the tolerance band (See Note 8).
ATTRITION ALLOWANCES. The Comprehensive Settlement authorizes the Company
annual allowances for operational attrition for 1995 and 1996 to the extent
that the annual inflation rate for those years exceeds 2 percent and 3
percent, respectively, for operating and maintenance expenses. This
compares to a 3 percent productivity adjustment authorized for 1994. The
rate base attrition will continue based upon a three year rolling average
of recorded net utility plant additions. This is a departure from past
regulatory practice of allowing recovery of the full effect of inflation on
operating and maintenance expenses 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 recorded the impact of the Comprehensive Settlement in 1993 and,
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 Company's
consolidated earnings.
Regulatory Accounts Receivable-Net and Regulatory Assets include a total of
approximately $327 million and $465 million in 1994 and 1993 respectively, for
the recovery of costs as provided in the Comprehensive Settlement. At December
31, 1993, Accounts Payable-Other included the remaining liability for
settlement payments of $375 million, which were paid in 1994, to restructure
the long-term gas supply contracts. The CPUC authorized the borrowing of up to
$425 million primarily to provide for funds needed under the Comprehensive
Settlement. As of December 31, 1994, the Company has $524 million in
commercial paper outstanding, of which $330 million relates to the
Comprehensive Settlement (See Note 6).
- 31 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 to the
financial statements.
A reconciliation of the difference between computed statutory federal income tax
expense and actual income tax expense is as follows:
<TABLE>
<CAPTION>
Year Ended December 31
-------------------------------
(Thousands of Dollars) 1994 1993 1992
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Computed statutory federal income tax
expense $117,311 $112,874 $121,935
Increase (reductions) resulting from:
Excess book over tax depreciation 17,473 17,847 17,121
State income taxes - net of federal
income tax benefit 19,119 16,993 23,543
Capitalized expenses not deferred (6,589)
Federal income tax rate change 1,698
Research and development credit (4,000)
Amortization of deferred investment tax
credits (3,024) (3,811) (3,867)
Resolution of proposed tax deficiency 3,850 (10,193)
Other - net (3,478) (2,587) 5,183
------------------------------
Total income tax expense $144,662 $128,821 $163,915
------------------------------
------------------------------
</TABLE>
The components of income tax expense are as follows:
<TABLE>
<CAPTION>
Year Ended December 31
-------------------------------
(Thousands of Dollars) 1994 1993 1992
- -------------------------------------------------------------------------------
<S> <C> <C> <C>
Federal
Current $147,647 $ 53,831 $103,908
Deferred (32,500) 46,044 25,254
-------------------------------
115,147 99,875 129,162
-------------------------------
-------------------------------
State
Current 44,289 22,206 34,331
Deferred (14,774) 6,740 422
-------------------------------
29,515 28,946 34,753
-------------------------------
-------------------------------
Total
Current 191,936 76,037 138,239
Deferred (47,274) 52,784 25,676
-------------------------------
$144,662 $128,821 $163,915
-------------------------------
-------------------------------
</TABLE>
- 32 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The principal components of net deferred tax liabilities are as follows:
<TABLE>
<CAPTION>
December 31
- ----------------------------------------------------------------------------------------------------------------------
1994 1993
- ----------------------------------------------------------------------------------------------------------------------
(Thousands of Dollars) Assets Liabilities Total Assets Liabilities Total
- ----------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Depreciation $(399,381) $(399,381) $(382,983) $(382,983)
Comprehensive Settlement $211,996 211,996
Regulatory accounts receivable (150,767) (150,767) (162,339) (162,339)
Deferred investment tax credits 30,996 30,996 $32,336 32,336
Customer advances for
construction 25,527 25,527 21,774 21,774
Regulatory asset (39,604) (39,604) (44,873) (44,873)
Other regulatory 109,084 (169,792) (60,708) 153,634 (56,626) 97,008
-------------------------------------------------------------------------------
Total deferred income tax
assets (liabilities) $377,603 $(759,544) $(381,941) $207,744 $(646,821) $(439,077)
-------------------------------------------------------------------------------
-------------------------------------------------------------------------------
</TABLE>
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 Company pays the amount of taxes applicable to itself
had it filed a separate return.
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, 1994 and 1993, $97 million and $109 million, respectively, of
deferred income taxes have been offset by an equivalent amount in regulatory
assets.
4. COMMITMENTS AND CONTINGENT LIABILITIES
ENVIRONMENTAL OBLIGATIONS
The Company has identified and reported to California environmental authorities
42 former manufactured gas plant sites for which it (together with other
utilities as to 21 of the sites) may have environmental obligations under
environmental laws. As of December 31, 1994, eight of these sites have been
remediated, of which five have received certification from the California
Environmental Protection Agency. Preliminary investigations, at a minimum, have
been completed on 33 of the gas plant sites including those sites at which the
remediations described above have been completed. In addition, the Company has
been named as a potentially responsible party of one landfill site and three
industrial waste disposal sites.
On May 4, 1994, the CPUC approved a collaborative settlement between the Company
and other California energy utilities and the Division of Ratepayer Advocates
which provides for rate recovery of 90 percent of environmental investigation
and remediation costs without reasonableness review. In addition, the utilities
have the opportunity to retain a percentage of any insurance recoveries to
offset the 10 percent of costs not recovered in rates.
- 33 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
At December 31, 1994, the Company's estimated remaining investigation and
remediation liability was approximately $65 million which it is authorized to
recover through the mechanism discussed above. The estimated liability 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. There were no related
charges to income in 1994. 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.
LITIGATION
The Company is a defendant in various lawsuits arising in the normal course of
business. Management believes that the resolution of these pending claims and
legal proceedings will not have a material effect on the Company's financial
statements.
OTHER COMMITMENTS AND CONTINGENCIES
At December 31, 1994, commitments for capital expenditures were approximately
$33 million.
On January 17, 1994, the Company's service area was struck by a major
earthquake. The result was a disruption in service to 150,000, or less than 3
percent, of its 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 material effect on the Company's financial statements.
5. LEASES
The Company has leases on real and personal property expiring at various dates
from 1995 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 exercisable by the Company. Rental expense under operating leases was $42
million, $39 million and $37 million, in 1994, 1993 and 1992, respectively.
The following is a schedule of future minimum operating lease commitments as of
December 31, 1994:
<TABLE>
<CAPTION>
Future Minimum
(Thousands of Dollars) Lease Payments
- -----------------------------------------------------------------------------
<S> <C>
Year Ending December 31:
1995 $ 30,345
1996 28,164
1997 29,427
1998 27,322
1999 27,161
Later years 314,341
--------
Total $456,760
--------
--------
</TABLE>
- 34 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
6. COMPENSATING BALANCES AND SHORT-TERM BORROWING ARRANGEMENTS
The Company has $750 million of unsecured revolving lines of credit, of which
$350 million is a multi-year credit agreement requiring annual fees of .10
percent and $400 million is a 364 day credit agreement requiring annual fees of
.07 percent. The interest rates on these lines vary and are derived from
formulas based on market rates and the Company's credit rating. The multi-year
credit agreement expires on February 8, 2000. At December 31, 1994, 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, 1994 and 1993, the Company had $524 million and $267 million,
respectively, of commercial paper obligations outstanding. The weighted average
annual interest rate of commercial paper obligations outstanding was 5.96
percent and 3.25 percent at December 31, 1994 and 1993, respectively. At
December 31, 1994, the Company has classified $246 million of the commercial
paper as long-term debt since it is the Company's intent (supported by the $350
million multi-year credit agreement above) to continue to refinance that portion
of the debt on a long-term basis.
- 35 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
7. LONG-TERM DEBT
<TABLE>
<CAPTION>
December 31
---------------------
(Thousands of Dollars) 1994 1993
- -----------------------------------------------------------------------------------------------------
<S> <C> <C>
FIRST MORTGAGE BONDS:
6 1/2 % December 15, 1997 $ 125,000 $ 125,000
5 1/4% March 1, 1998 100,000 100,000
6 7/8 % August 15, 2002 100,000 100,000
5 3/4% November 15, 2003 100,000 100,000
9 3/4 % December 1, 2020 18,435 18,435
8 3/4 % October 1, 2021 150,000 150,000
7 3/8 % March 1, 2023 100,000 100,000
7 1/2 % June 15, 2023 125,000 125,000
6 7/8 % November 1, 2025 175,000 175,000
OTHER LONG-TERM DEBT:
4.69% Notes, June 16, 1995 31,000 31,000
8 3/4% Notes, August 4, 1995 20,000 20,000
5.03% - 5.05% Notes, August 28 - September 1, 1995 28,000 28,000
5.81% - 5.85% Notes, December 1, 1995 7,000 7,000
8 3/4% Notes, July 8, 1996 20,000 20,000
5.98% Notes, August 28, 1997 22,000 22,000
8 3/4% Notes, July 6, 2000 10,000 10,000
SFr. 100,000,000 5 1/8 % Bonds, February 6, 1998 (foreign currency
exposure hedged through currency swap at an interest rate of 9.725%) 47,250 47,250
SFr. 150,000,000 7 1/2 % Foreign Interest Payment Securities
May 14, 1996 75,282 75,282
5.96% Commercial Paper, February 8, 2000 245,847
-----------------------
Total outstanding 1,499,814 1,253,967
-----------------------
Less:
Payments due within one year 86,000
Unamortized debt discount less premium 16,883 18,345
-----------------------
102,883 18,345
-----------------------
Long-Term Debt $1,396,931 $1,235,622
-----------------------
-----------------------
</TABLE>
The annual principal payment requirements of long-term debt for the years 1995
through 1998 are $86 million, $95 million, $147 million, and $497 million,
respectively. No amounts are due in 1999. Substantially all utility plant is
pledged as collateral for the first mortgage bonds.
CURRENCY RATE SWAPS
In February 1986, the Company issued SFr. 100 million of 5 1/8 percent bonds
which will mature on February 6, 1998. The Company has entered into a swap
transaction with a major international bank to hedge the currency exposure. The
terms of the swap result in a U.S. dollar liability of $47 million at an
interest rate of 9.725 percent with the principal payable on February 6, 1998.
In May 1986, the Company issued SFr. 150 million of 7 1/2 percent Foreign
Interest Payment Securities which are renewable at 10-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.
- 36 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
8. 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, 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 the currency rate swap 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 fair value of these financial instruments is different from
the carrying amount.
The following financial instruments have a fair value which is different from
the carrying amount as of December 31.
<TABLE>
<CAPTION>
1994 1993
-------------------------------------
(Dollars Carrying Fair Carrying Fair
in Millions) Amount Value Amount Value
- ------------------------------------------------------------------
<S> <C> <C> <C> <C>
Long-Term Debt $1,499 $1,377 $1,253 $1,272
Preferred Stocks $ 97 $ 78 $ 97 $ 95
</TABLE>
In October, 1994, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards No. 119 (SFAS 119), "Disclosure
about Derivative Financial Instruments and Fair Value of Financial Instruments."
SFAS 119 is effective for financial statements issued for fiscal years ending
after December 15, 1994 and requires certain disclosures about financial
instruments not covered by SFAS 105, "Disclosure of Information about Financial
Instruments with Off-Balance Sheet Risk and Financial Instruments with
Concentrations of Credit Risk." As a result of the Gas Cost Incentive Mechanism
(GCIM) (See Note 2), the Company enters into a certain amount of gas futures
contracts in the open market to help reduce gas costs within the GCIM tolerance
band. The Company's policy is to use gas futures contracts to mitigate risk and
better manage gas costs. The CPUC has approved the use of gas futures for
managing risk associated with the GCIM. For the year ended December 31, 1994,
gains or losses from gas futures contracts are not material to the Company's
financial statements.
- 37 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
9. CAPITAL STOCK
The amount of capital stock outstanding is as follows:
<TABLE>
<CAPTION>
December 31, 1994 December 31, 1993
----------------------------------------------
Number Thousands Number Thousands
of Shares of Dollars of Shares of Dollars
----------------------------------------------
<S> <C> <C> <C> <C>
PREFERRED STOCK:
cumulative, voting (a) (b) (c) (d):
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 C 500 50,000 500 50,000
7 3/4%, $25 Stated Value 3,000,000 75,000 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 91,300,000 $834,889
-------- --------
-------- --------
</TABLE>
(a) The 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
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 1994,
1993 and 1992 were: Series A, 3.40 percent, 2.67 percent and 3.21 percent,
respectively; and Series C, 3.33 percent, 2.75 percent and 3.28 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 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 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 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 Company would be divided pro rata among the holders of the 6%
Preferred Stock and the holders of Common Stock.
- 38 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
10. 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 Company, sell and transport gas to the Company under tariffs
approved by the Federal Energy Regulatory Commission. During 1994, 1993 and
1992, billings for such gas purchases totaled $215 million, $344 million, and
$356 million, respectively. The Company has long-term gas purchase and
transportation agreements with the affiliates extending through the year 2003
requiring certain minimum payments which allow the affiliates to recover the
construction cost of their facilities. The 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 were restructured in conjunction with the
Comprehensive Settlement previously discussed (see Note 2).
11. PENSION, POSTRETIREMENT AND OTHER EMPLOYEE BENEFIT PLANS
PENSION PLAN
The 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 their last years of employment. The 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 Company has recorded regulatory adjustments to reflect, in net
income, pension costs calculated under the actuarial method allowed for
ratemaking. The cumulative difference between the net periodic pension cost
calculated for financial reporting and ratemaking purposes has been included as
a deferred charge or credit in the Consolidated Balance Sheet.
Pension expense is as follows:
<TABLE>
<CAPTION>
Year Ended December 31
---------------------------------------
(Thousands of Dollars) 1994 1993 1992
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost - benefits earned during the period $33,627 $31,828 $30,327
Interest cost on projected benefit obligation 80,741 78,727 75,578
Actual return on plan assets (2,631) (153,293) (68,730)
Net amortization and deferral (94,173) 54,816 (13,041)
-------------------------------------
Net periodic pension cost 17,564 12,078 24,134
Special early retirement program 11,790 17,546 12,227
Postretirement health care and life insurance benefits 22,088
Regulatory adjustment (1,878) 919 (8,891)
-------------------------------------
Total pension expense $27,476 $30,543 $49,558
-------------------------------------
-------------------------------------
</TABLE>
-39 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of the pension plan's funded status to the pension liability
recognized in the Consolidated Balance Sheet is as follows:
<TABLE>
<CAPTION>
December 31
--------------------------
(Thousands of Dollars) 1994 1993
- -------------------------------------------------------------------------------------------------------
<S> <C> <C>
Actuarial present value of pension benefit obligations
Accumulated benefit obligation, including $751,852 and $792,800
in vested benefits at December 31, 1994 and 1993, respectively $ 844,762 $ 907,890
Effect of future salary increases 203,995 267,061
- -------------------------------------------------------------------------------------------------------
Projected benefit obligation 1,048,757 1,174,951
Less: plan assets at fair value, primarily publicly traded common
stocks and equity pooled funds (1,237,747) (1,282,921)
Unrecognized net gain 234,372 157,215
Unrecognized prior service cost (35,761) (39,480)
Unrecognized transition obligation (5,143) (5,658)
- -------------------------------------------------------------------------------------------------------
Accrued pension liability included in the Consolidated Balance Sheet $ 4,478 $ 4,107
- -------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
Deferred pension credit (charge) included in the Consolidated Balance Sheet $ (1,489) $ 390
- -------------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------------
The plan's major actuarial assumptions include:
Weighted average discount rate 8% 7%
Rate of increase in future compensation levels 5% 5%
Expected long-term rate of return on plan assets 8% 8 1/2%
</TABLE>
POSTRETIREMENT BENEFIT PLAN
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.
As with pensions, the Company has recorded regulatory adjustments to reflect, in
net income, postretirement benefit costs calculated under the actuarial method
allowed for ratemaking. The cumulative difference between the net periodic
postretirement benefit cost calculated for financial reporting and ratemaking
purposes has been included as a deferred charge or credit in the Consolidated
Balance Sheet.
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 necessary on an
actuarial basis to provide assets sufficient to be paid to plan participants.
The net postretirement benefit expense was as follows:
- 40 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
Year Ended December 31
----------------------
(Thousands of Dollars) 1994 1993
- --------------------------------------------------------------------------
<S> <C> <C>
Service cost - benefits earned during the period $13,122 $11,917
Interest cost on projected benefit obligation 26,464 26,848
Actual return on plan assets (1,487) (10,076)
Net amortization and deferral 2,561 15,205
-------------------
Net periodic postretirement benefit cost 40,660 43,894
Regulatory adjustment (2,887)
-------------------
Net postretirement benefit expense $37,773 $43,894
-------------------
-------------------
</TABLE>
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, the amounts funded totaled $22 million.
A reconciliation of the plan's funded status to the postretirement benefit
liability recognized in the Consolidated Balance Sheet is as follows:
<TABLE>
<CAPTION>
December 31
------------------
(Thousands of Dollars) 1994 1993
- ------------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees $160,066 $147,666
Fully eligible active plan participants 174,440 178,777
Other active plan participants 17,012 30,799
------------------
351,518 357,242
Less: plan assets at fair value, primarily
publicly traded common stocks
and equity pooled funds (144,304) (116,803)
Unrecognized net transition obligation (230,047) (242,827)
Unrecognized net gain 19,954 1,365
------------------
Prepaid postretirement benefit asset
included in the Consolidated Balance Sheet $ (2,879) $ (1,023)
------------------
------------------
Deferred postretirement benefit charge
included in the Consolidated Balance Sheet $ (2,887) $ 0
------------------
------------------
The plan's major actuarial assumptions include:
Health care cost trend rate 8% 8%
Weighted average discount rate 8% 7%
Rate of increase in future compensation levels 5% 5%
Expected long-term rate of return on plan assets 8% 8 1/2%
</TABLE>
The assumed health care cost trend rate is 7.5 percent for 1995. 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 $7.1 million on the aggregate of
the service and interest cost components of net periodic postretirement cost for
1994 and $54.4 million on the accumulated postretirement benefit obligation at
December 31, 1994. The estimated income tax rate used in the return on plan
assets is zero since the plan is tax exempt.
- 41 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
POSTEMPLOYMENT BENEFITS
Effective January 1, 1994, the Company adopted SFAS 112, "Employers' Accounting
for Postemployment Benefits". SFAS 112 requires the accrual of the obligation
to provide benefits to former or inactive employees after employment but before
retirement. The adoption of SFAS 112 had no impact on earnings since these
costs are currently recovered in rates as paid, and as such, have been
reflected as a regulatory asset. At December 31, 1994 and 1993, the total
postemployment benefit liability was $49 million and $39 million, respectively,
and represents primarily workers' compensation and disability benefits.
EARLY RETIREMENT PROGRAM
In 1994 and 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 1994 and 1993, respectively.
RETIREMENT SAVINGS PLAN
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 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 investment contracts. The
Company's contributions, which were invested in the Parent's common stock, were
$8 million in 1994 and $9 million each in 1993 and 1992.
- 42 -
<PAGE>
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 LLP, independent
certified public accountants, appointed by the Board of Directors. Their report
is shown on the following page. Management has made available to Deloitte &
Touche LLP 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 regularly with management, with the Company's
internal auditors and with the independent auditors. The independent auditors
and the internal auditors periodically meet alone with the Audit Committee and
have free access to the Audit Committee at any time.
Warren I. Mitchell,
President
Ralph Todaro,
Vice President and Controller
January 31, 1995
- 43 -
<PAGE>
INDEPENDENT AUDITORS' REPORT
Southern California Gas Company:
We have audited the consolidated financial statements of Southern California Gas
Company and its subsidiaries (pages 25 to 42) as of December 31, 1994 and
1993, and for each of the three years in the period ended December 31, 1994.
These financial statements are the responsibility of the Company's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Southern California
Gas Company and its subsidiaries as of December 31, 1994 and 1993, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1994 in conformity with generally accepted
accounting principles.
DELOITTE & TOUCHE LLP
Los Angeles, California
January 31, 1995
- 44 -
<PAGE>
OTHER INFORMATION
QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
1994
--------------------------------------
Three Months Ended March 31 June 30 Sept. 30 Dec. 31
- -------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
Operating revenues $689,154 $630,298 $567,929 $699,143
Net operating revenue $ 67,598 $ 68,094 $ 67,575 $ 75,360
Net income $ 43,949 $ 45,788 $ 45,197 $ 55,579
Net income applicable to
Common stock $ 41,509 $ 43,223 $ 42,532 $ 52,781
<CAPTION>
1993
--------------------------------------
Three Months Ended March 31 June 30 Sept. 30 Dec. 31
- -------------------------------------------------------------------------
(Thousands of Dollars)
<S> <C> <C> <C> <C>
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
</TABLE>
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
- 45 -
<PAGE>
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 May 2, 1995. 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" and "Executive Compensation" in the Company's Information
Statement for its Annual Meeting of Shareholders scheduled to be held on May 2,
1995. 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 May 2, 1995. Such information
is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS
Not applicable.
- 46 -
<PAGE>
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 LLP,
Independent Certified Public Accountants.
1.02 Statement of Consolidated
Income for the years ended
December 31, 1994, 1993 and 1992.
1.03 Consolidated Balance Sheet at December 31,
1994 and 1993.
1.04 Statement of Consolidated Cash Flows
for the years ended December 31, 1994,
1993 and 1992.
1.05 Statement of Consolidated Shareholders'
Equity for the years ended December 31, 1994,
1993, 1992 and 1991.
1.06 Notes to Consolidated Financial
Statements.
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).
- 47 -
<PAGE>
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).
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).
- 48 -
<PAGE>
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).
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).
10.10 Pacific Enterprises Employee Stock Option Plan (Note 27; Exhibit
4.01).
21. SUBSIDIARIES OF THE REGISTRANT
21.01 List of subsidiaries of Southern
California Gas Company.
- 49 -
<PAGE>
23. CONSENTS OF EXPERTS AND COUNSEL
23.01 Consent of Deloitte & Touche LLP,
Independent Certified Public Accountants.
24. POWER OF ATTORNEY
24.01 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).
27. Financial Data Schedule
27.01 Financial Data Schedule
(b) REPORTS ON FORM 8-K:
The following report on Form 8-K was filed during the last
quarter of 1994.
REPORT DATE ITEM REPORTED
Nov. 23, 1994 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.
-50-
<PAGE>
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.
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.
- 51 -
<PAGE>
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.
26 Annual Report on Form 10-K for the year ended December 31, 1993, filed
by Southern California Gas Company.
27 Registration Statement No. 33-54055 filed by Pacific Enterprises on
June 9, 1994.
- 52 -
<PAGE>
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: /s/ Warren I. Mitchell
--------------------------
Name: Warren I. Mitchell
Title: President
Dated: March 17, 1995
- 53 -
<PAGE>
Each person whose signature appears below hereby authorizes Warren I.
Mitchell, Lloyd A. Levitin, Ralph Todaro, 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
/s/ Warren I. Mitchell
- ----------------------- President March 17, 1995
(Warren I. Mitchell) (Principal Executive Officer)
/s/ Lloyd A. Levitin
- ----------------------- Executive Vice President and
(Lloyd A. Levitin) Chief Financial Officer
(Principal Financial Officer) March 17, 1995
/s/ Ralph Todaro
- ----------------------- Vice President and Controller March 17, 1995
(Ralph Todaro)
/s/ Hyla H. Bertea
- ----------------------- Director March 17, 1995
(Hyla H. Bertea)
/s/ Herbert L. Carter
- ----------------------- Director March 17, 1995
(Herbert L. Carter)
/s/ Richard D. Farman
- ----------------------- Director March 17, 1995
(Richard D. Farman)
/s/ Wilford D. Godbold, Jr.
- ----------------------- Director March 17, 1995
(Wilford D. Godbold, Jr.)
/s/ Ignacio E. Lozano, Jr.
- ----------------------- Director March 17, 1995
(Ignacio E. Lozano, Jr.)
/s/ Harold M. Messmer, Jr.
- ----------------------- Director March 17, 1995
(Harold M. Messmer, Jr.)
/s/ Paul A. Miller
- ----------------------- Director March 17, 1995
(Paul A. Miller)
/s/ Joseph R. Rensch
- ----------------------- Director March 17, 1995
(Joseph R. Rensch)
/s/ Diana L. Walker
- ----------------------- Director March 17, 1995
(Diana L. Walker)
/s/ Willis B. Wood, Jr.
- ----------------------- Director March 17, 1995
(Willis B. Wood, Jr.)
- 54 -
<PAGE>
Exhibit 3.02
BYLAWS
OF
SOUTHERN CALIFORNIA GAS COMPANY
MARCH 1, 1995
<PAGE>
BYLAWS
OF
SOUTHERN CALIFORNIA GAS COMPANY
____________
ARTICLE I
PRINCIPAL OFFICE
SECTION 1. The principal executive office of the Company is located at
555 West Fifth Street, City of Los Angeles, County of Los Angeles, California.
ARTICLE II
MEETINGS OF SHAREHOLDERS
SECTION 1. All Meetings of Shareholders shall be held either at the
principal executive office of the Company or at any other place within or
without the state as may be designated by resolution of the Board of Directors.
SECTION 2. An Annual Meeting of Shareholders shall be held each year on
such date and at such time as may be designated by resolution of the Board of
Directors.
SECTION 3. At an Annual Meeting of Shareholders, only such business shall
be conducted as shall have been properly brought before the Annual Meeting. To
be properly brought before an Annual Meeting, business must be (a) specified in
the notice of the Annual Meeting (or any supplement thereto) given by or at the
direction of the Board of Directors, (b) otherwise properly brought before the
Annual Meeting by a Shareholder. For business to be properly brought before an
Annual Meeting by a Shareholder, including the nomination of any person (other
than a person nominated by or at the direction of the Board of Directors) for
election to the Board of Directors, the Shareholder must have given timely and
proper written notice to the Secretary of the Company. To be timely, the
Shareholder's written notice must be received at the principal executive office
of the Company not less than sixty nor more than one hundred twenty days in
advance of the date corresponding to the date of the last Annual Meeting;
provided, however, that in the event the Annual Meeting to which the
Shareholder's written notice relates is to be held on a date which differs by
more than sixty days from the date corresponding to the date of the last Annual
Meeting, the Shareholder's written notice to be timely must be so received not
later than the close of business on the tenth day following the date on which
public disclosure of the date of the Annual Meeting is made or given to
Shareholders. To be proper, the Shareholder's written notice must set forth as
to each matter the Shareholder proposes to bring before the Annual Meeting (a) a
brief description of the business desired to be brought before the Annual
Meeting, (b)
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the name and address of the Shareholder as they appear on the Company's books,
(c) the class and number of shares of the Company which are beneficially owned
by the Shareholder, and (d) any material interest of the Shareholder in such
business. In addition, if the Shareholder's written notice relates to the
nomination at the Annual Meeting of any person for election to the Board of
Directors, such notice to be proper must also set forth (a) the name, age,
business address and residence address of each person to be nominated, (b) the
principal occupation or employment of each such person, (c) the number of shares
of capital stock beneficially owned by each such person, and (d) such other
information concerning each such person as would be required under the rules of
the Securities and Exchange Commission in a proxy statement soliciting proxies
for the election of such person as a Director, and must be accompanied by a
consent, signed by each such person, to serve as a Director of the Company if
elected. Notwithstanding anything in the Bylaws to the contrary, no business
shall be conducted at an Annual Meeting except in accordance with the procedures
set forth in this Section 3.
SECTION 4. Each Shareholder of the Company shall be entitled to elect
voting confidentiality as provided in this Section 4 on all matters submitted to
Shareholders by the Board of Directors and each form of proxy, consent, ballot
or other written voting instruction distributed by the Company to Shareholders
shall include a check box or other appropriate mechanism by which Shareholders
who desire to do so may so elect voting confidentiality.
All inspectors of election, vote tabulators and other persons
appointed or engaged by or on behalf of the Company to process voting
instructions (none of whom shall be a Director or Officer of the Company or any
of its affiliates) shall be advised of and instructed to comply with this
Section 4 and, except as required or permitted hereby, not at any time to
disclose to any person (except to other persons engaged in processing voting
instructions), the identity and individual vote of any Shareholder electing
voting confidentiality; provided, however, that voting confidentiality shall not
apply and the name and individual vote of any shareholder may be disclosed to
the Company or to any person (i) to the extent that such disclosure is required
by applicable law or is appropriate to assert or defend any claim relating to
voting or (ii) with respect to any matter for which votes of Shareholders are
solicited in opposition to any of the nominees or the recommendations of the
Board of Directors unless the persons engaged in such opposition solicitation
provide Shareholders of the Company with voting confidentiality (which, if not
otherwise provided, will be requested by the Company) comparable in the opinion
of the Company to the voting confidentiality provided by this Section 4.
ARTICLE III
BOARD OF DIRECTORS
SECTION 1. The Board of Directors shall have power to:
a. Conduct, manage and control the business of the Company, and make
rules consistent with law, the Articles of Incorporation and the Bylaws;
b. Elect, and remove at their discretion, Officers of the Company,
prescribe their duties, and fix their compensation;
c. Authorize the issue of shares of stock of the Company upon lawful
terms: (i) in consideration of money paid, labor done, services actually
rendered to the Company or for its benefit or in its reorganization, debts
or securities cancelled, and tangible or intangible property actually
received either by this Company or by a wholly-owned subsidiary; but
neither promissory notes of the purchaser (unless adequately secured by
collateral other than the shares acquired or unless permitted by Section
408 of the California Corporations Code) nor future services shall
constitute payment or part payment for shares of this Company; or (ii) as
a share dividend or upon a stock split, reverse stock split,
reclassifications of outstanding shares
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into shares of another class, conversion of outstanding shares into shares
of another class, exchange of outstanding shares for shares of another
class or other change affecting outstanding shares;
d. Borrow money and incur indebtedness for the purposes of the Company,
and cause to be executed and delivered, in the Company name, promissory
notes, bonds, debentures, deeds of trust, mortgages, pledges,
hypothecations or other evidences of debt;
e. Elect an Executive Committee and other committees.
SECTION 2. The Board of Directors shall consist of not less than nine
nor more than seventeen members. The authorized number of Directors shall be
fixed from time to time, within the limits specified, by a resolution duly
adopted by the Board of Directors. A majority of the authorized number of
Directors shall constitute a quorum of the Board.
ARTICLE IV
MEETING OF DIRECTORS
SECTION 1. Meetings of the Board of Directors shall be held at any
place which has been designated by resolution of the Board of Directors, or by
written consent of all members of the Board. In the absence of such
designation, regular meetings shall be held in the principal executive office.
SECTION 2. Immediately following each Annual Meeting of Shareholders
there shall be a regular meeting of the Board of Directors for the purpose of
organization, election of Officers and the transaction of other business. In
all months other the month in which the Annual Meeting of Shareholders is held
there shall be a regular meeting of the Board of Directors on the first Tuesday
of each month at such hour as shall be designated by resolution of the Board of
Directors. Notice of regular meetings of the Directors shall be given in the
manner described in these Bylaws for giving notice of special meetings. No
notice of the regular meeting of Board of Directors which follows the Annual
Meeting of Shareholders need be given.
SECTION 3. Special meetings of the Board of Directors for any purpose
may be called at any time by the President, or by any a majority of the
authorized number of Directors. Notice of the time and place of special
meetings shall be given to each Director. In case notice is mailed or
telegraphed, it shall be deposited in the United States mail or delivered to the
telegraph company in the city in which the principal executive office is located
at least twenty hours prior to the time of the meeting. In case notice is given
personally or by telephone, it shall be delivered at least six hours prior to
the time of the meeting.
SECTION 4. The transactions of any meeting of the Board of Directors,
however called or noticed, shall be as valid as though in a meeting duly held
after regular call and notice if a quorum be present and each of the Directors,
either before or after the meeting, signs a written waiver of notice, a consent
to holding such meeting, or an approval of the minutes thereof or attends the
meeting without protesting, prior thereto or at its commencement, the lack of
notice to such Director. All such waivers, consents or approvals shall be made
a part of the minutes of the meeting.
SECTION 5. If any regular meeting of Shareholders or of the Board of
Directors falls on a legal holiday, then such meeting shall be held on the next
succeeding business day at the same hour. But a special meeting of Shareholders
or Directors may be held upon a holiday with the same force and effect as if
held upon a business day.
3
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ARTICLE V
OFFICERS
SECTION 1. The Officers of the Company shall be a President, Vice
Presidents, one or more of whom, in the discretion of the Board of Directors,
may be appointed Executive or Senior Vice President, a Secretary and a
Treasurer. The Company may have, at the discretion of the Board of Directors,
any other Officers and may also have, at the discretion of and upon appointment
by the President, one or more Assistant Secretaries and Assistant Treasurers.
One person may hold two or more offices.
ARTICLE VI
THE PRESIDENT
SECTION 1. The President shall be the principal executive officer of
the Company, shall have general charge of all of the Company's business and
affairs and all of its Officers and shall have all of the powers and perform all
of the duties inherent in that office and such additional powers and duties as
may be prescribed by the Board of Directors.
ARTICLE VII
VICE PRESIDENTS
SECTION 1. In the President's absence or disability, the Vice
Presidents in order of their rank shall perform all of the duties of the
President and when so acting shall have all of the powers and be subject to all
of the restrictions of the President. The Vice Presidents shall have such other
powers and perform such additional duties as may be prescribed by the Board of
Directors or the President.
ARTICLE VIII
SECRETARY
SECTION 1. The Secretary shall keep at the principal executive office,
a book of minutes of all meetings of Directors and Shareholders, which shall
contain a statement of the time and place of the meeting, whether it was regular
or special, and if special, how authorized and the notice given, the names of
those present at Directors' meetings, the number of shares present or
represented by written proxy at Shareholders' meetings and the proceedings.
SECTION 2. The Secretary shall give notice of all meetings of
Shareholders and the Board of Directors required by the Bylaws or by law to be
given, and shall keep the seal of the Company in safe custody. The Secretary
shall have such other powers and perform such additional duties as may be
prescribed by the Board of Directors or the President.
SECTION 3. It shall be the duty of the Assistant Secretaries to help
the Secretary in the performance of the Secretary's duties. In the absence or
disability of the Secretary, the Secretary's duties may be performed by an
Assistant Secretary.
4
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ARTICLE IX
TREASURER
SECTION 1. The Treasurer shall have custody and account for all funds
or moneys of the Company which may be deposited with the Treasurer, or in banks,
or other places of deposit. The Treasurer shall disburse funds or moneys which
have been duly approved for disbursement. The Treasurer shall sign notes, bonds
or other evidences of indebtedness for the Company as the Board of Directors may
authorize. The Treasurer shall have such other powers and perform such
additional duties as may be prescribed by the Board of Directors or the
President.
SECTION 2. It shall be the duty of the Assistant Treasurers to help the
Treasurer in the performance of the Treasurer's duties. In the Treasurer's
absence or disability, the Treasurer's duties may be performed by an Assistant
Treasurer.
ARTICLE X
RECORD DATE
SECTION 1. The Board of Directors may fix a time in the future as a
record date for ascertaining the Shareholders entitled to notice and to vote at
any meeting of Shareholders, to give consent to corporate action in writing
without a meeting, to receive any dividend, distribution, or allotment of rights
or to exercise rights related to any change, conversion, or exchange of shares.
The selected record date shall not be more than sixty nor less than 10 days
prior to the date of the Meeting nor more than sixty days prior to any other
action or event for the purposes for which it is fixed. When a record date is
fixed, only Shareholders of Record on that date are entitled to notice and to
vote at the Meeting, to give consent to corporate action, to receive a dividend,
distribution, or allotment of rights, or to exercise any rights in respect of
any other lawful action, notwithstanding any transfer of shares on the books of
the Company after the record date.
5
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ARTICLE XI
INDEMNIFICATION OF AGENTS OF THE COMPANY;
PURCHASE OF LIABILITY INSURANCE
SECTION 1. For the purposes of this Article, "agent" means any person
who is or was a Director, Officer, employee or other agent of the Company, or is
or was serving at the request of the Company as a director, officer, employee or
agent of another foreign or domestic corporation, partnership, joint venture,
trust or other enterprise, or was a director, officer, employee or agent of a
foreign or domestic corporation which was a predecessor corporation of the
Company or of another enterprise at the request of such predecessor corporation;
"proceeding" means any threatened, pending or completed action or proceeding,
whether civil, criminal, administrative, or investigative; and "expenses"
includes, without limitation, attorneys' fees and any expenses of establishing a
right to indemnification under Section 4 or paragraph (d) of Section 5 of this
Article.
SECTION 2. The Company shall indemnify any person who was or is a
party, or is threatened to be made a party, to any proceeding (other than an
action by or in the right of the Company to procure a judgment in its favor) by
reason of the fact that such person is or was an agent of the Company, against
expenses, judgments, fines, settlements and other amounts actually and
reasonably incurred in connection with such proceeding if such person acted in
good faith and in a manner such person reasonably believed to be in the best
interests of the Company, and, in the case of a criminal proceeding, had no
reasonable cause to believe the conduct of such person was unlawful. The
termination of any proceeding by judgment, order, settlement, conviction or upon
a plea of nolo contendere or its equivalent shall not, of itself, create a
presumption that the person did not act in good faith and in a manner which the
person reasonably believed to be in the best interests of the Company or that
the person had reasonable cause to believe that the person's conduct was
unlawful.
SECTION 3. The Company shall indemnify any person who was or is a party
or is threatened to be made a party to any threatened, pending or completed
action by or in the right of the Company to procure a judgment in its favor by
reason of the fact that such person is or was an agent of the Company, against
expenses actually and reasonably incurred by such person in connection with the
defense or settlement of such action if such person acted in good faith and in a
manner such person believed to be in the best interests of the Company and its
Shareholders.
No indemnification shall be made under this Section 3 for any of the
following:
a. In respect of any claim, issue or matter as to which such person shall
have been adjudged to be liable to the Company in the performance of such
person's duty to the Company and its Shareholders, unless and only to the
extent that the court in which such proceeding is or was pending shall
determine upon application that, in view of all the circumstances of the
case, such person is fairly and reasonably entitled to indemnity for
expenses and then only to the extent that the court shall determine;
b. Of amounts paid in settling or otherwise disposing of a pending action
without court approval;
c. Of expenses incurred in defending a pending action which is settled or
otherwise disposed of without court approval.
SECTION 4. To the extent that an agent of the Company has been
successful on the merits in defense of any proceeding referred to in Section 2
or 3 or in defense of any claim, issue or matter therein, the agent shall be
indemnified against expenses actually and reasonably incurred by the agent in
connection therewith.
SECTION 5. Except as provided in Section 4, any indemnification under
this Article shall be made by the Company only if authorized in the specific
case, upon a determination that indemnification of the agent is proper in the
circumstances because the agent has met the applicable standard of conduct set
forth in Section 2 or 3, by any of the following:
6
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a. A majority vote of a quorum consisting of Directors who are not
parties to such proceeding;
b. If such a quorum of Directors is not obtainable, by independent legal
counsel in a written opinion;
c. Approval of the Shareholders, with the shares owned by the person to
be indemnified not being entitled to vote thereon;
d. The court in which such proceeding is or was pending upon application
made by the Company or the agent or the attorney or other person rendering
services in connection with the defense, whether or not such application by
the agent, attorney or other person is opposed by the Company.
SECTION 6. Expenses incurred in defending any proceeding may be
advanced by the Company prior to the final disposition of such proceeding upon
receipt of an undertaking by or on behalf of the agent to repay such amount if
it shall be determined ultimately that the agent is not entitled to be
indemnified as authorized in this Article.
SECTION 7. The indemnification provided by this Article shall not be
deemed exclusive of any other rights to which those seeking indemnification may
be entitled under any agreement, vote of Shareholders or disinterested Directors
or otherwise, to the extent such additional rights to indemnification are
authorized in the Articles of Incorporation of the Company. The rights to
indemnity under this Article shall continue as to a person who has ceased to be
a Director, Officer, employee, or agent and shall inure to the benefit of the
heirs, executors and administrators of the person.
SECTION 8. No indemnification or advance shall be made under this
Article, except as provided in Section 4 or paragraph (d) of Section 5, in any
circumstance where it appears:
a. That it would be inconsistent with a provision of the Articles of
Incorporation, these Bylaws, a resolution of the Shareholders or an
agreement in effect at the time of the accrual of the alleged cause of
action asserted in the proceeding in which the expenses were incurred or
other amounts were paid, which prohibits or otherwise limits
indemnification;
b. That it would be inconsistent with any condition expressly imposed by
a court in approving a settlement.
SECTION 9. The Company shall have the power to purchase and maintain
insurance on behalf of any agent of the Company against any liability asserted
against or incurred by the agent in such capacity or arising out of the agent's
status as such whether or not the Company would have the power to indemnify the
agent against such liability under the provisions of this Article.
SECTION 10. This Article does not apply to any proceeding against any
trustee, investment manager or other fiduciary of an employee benefit plan in
such person's capacity as such, even though such person may also be an agent of
the Company as defined in Section 1. Nothing contained in this Article shall
limit any right to indemnification to which such a trustee, investment manager
or other fiduciary may be entitled by contract or otherwise, which shall be
enforceable to the extent permitted by applicable law.
7
<PAGE>
Exhibit 21.01
Subsidiaries of Southern California Gas Company
EcoTrans Aftermarket Corporation
EcoTrans OEM Corporation
Southern California Gas Tower
<PAGE>
Exhibit 23.01
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
33-51322, 33-53258, 33-59404 and 33-52663 of Southern California Gas
Company on Forms S-3 of our report dated January 31, 1995, appearing in this
Annual Report on Form 10-K of Southern California Gas Company for the year ended
December 31, 1994.
DELOITTE & TOUCHE LLP
Los Angeles, California
March 17, 1995
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
The schedule contains summary financial information extracted from the
Consolidated Statement of Income, Balance Sheet and Cash Flows and is qualified
in its entirety in reference to such financial statements.
</LEGEND>
<CIK> 0000092108
<NAME> SOUTHERN CALIFORNIA GAS COMPANY
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