<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, 1995
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
TITLE OF EACH CLASS ON WHICH REGISTERED
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Preferred Stock Pacific Stock Exchange
6% Cumulative
Preferred - Series A
7-3/4% Series Preferred Stock
FIRST MORTGAGE BONDS New York Stock Exchange
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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 15, 1996, was approximately $195 million.
This amount excludes the market value of 49,504 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, 1996.
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TABLE OF CONTENTS
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PART I
<TABLE>
<S> <C> <C>
Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Operating Statistics . . . . . . . . . . . . . . . . . . . . . . 5
Service Area . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Utility Services . . . . . . . . . . . . . . . . . . . . . . . . 8
Demand for Gas . . . . . . . . . . . . . . . . . . . . . . . . . 8
Competition. . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Supplies of Gas. . . . . . . . . . . . . . . . . . . . . . . . . 10
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. . . . . . . . . 45
Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . 46
Item 12. Security Ownership of Certain Beneficial Owners
and Management. . . . . . . . . . . . . . . . . . . . . . . . . . . 46
</TABLE>
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<TABLE>
<S> <C> <C>
Item 13. Certain Relationships and Related Transactions. . . . . . . . . . . 46
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . 47
</TABLE>
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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 part 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. The Company's
markets are separated into core and noncore customers. Core customers
consist of approximately 4.7 million customers (4.5 million residential and
200,000 small commercial and industrial customers). The noncore market
consists of approximately 1,600 customers which include utility electric
generation, wholesale and large commercial and industrial customers. Most
noncore customers procure their own gas rather than purchase gas through the
Company.
The Company is subject to regulation by the California Public Utilities
Commission ("CPUC") which, among other things, establishes the 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, changes to authorized 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
(including the performance based regulation ("PBR") proposal (See "Rates and
Regulation")), 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 future performance.
For 1996, the CPUC has authorized the Company to earn a rate of return
on rate base of 9.42 percent and 11.6 percent rate of return on common equity
compared to 9.67 percent and 12 percent, respectively, in 1995. Rate base
declined 3.4 percent in 1995. In 1996, rate base is expected to decline
slightly from the 1995 level. The Company has achieved or exceeded its
authorized rate of return on rate base for the last thirteen 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 1991 through 1995.
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<TABLE>
<CAPTION>
OPERATING STATISTICS
YEAR ENDED DECEMBER 31
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1995 1994 1993 1992 1991
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<S> <C> <C> <C> <C> <C>
Gas Sales, Transportation & Exchange Revenues
(thousands of dollars):
Residential $ 1,553,491 $ 1,712,899 $1,652,562 $1,483,654 $1,673,837
Commercial/Industrial 751,409 798,180 853,579 836,672 977,065
Utility Electric Generation 104,486 118,353 147,208 194,639 148,573
Wholesale 62,256 98,354 116,737 128,881 144,779
Exchange 777 690 3,745 5,863 7,482
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Total in rates 2,472,419(1) 2,728,476(1) 2,773,831 2,649,709 2,951,736
Regulatory balancing accounts and other (193,111) (141,952) 37,243 190,216 (21,430)
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Operating Revenue $ 2,279,308 $ 2,586,524 $2,811,074 $2,839,925 $2,930,306
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Volumes (millions of cubic feet):
Residential 239,417 256,400 247,507 243,920 249,522
Commercial/Industrial 351,649 347,419 339,706 363,124 460,368
Utility Electric Generation 204,582 260,290 212,720 220,642 170,043
Wholesale 128,730 146,279 147,978 149,232 141,931
Exchange 12,735 10,002 16,969 23,888 25,604
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Total 937,113 1,020,390 964,880 1,000,806 1,047,468
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Core 324,758 341,469 338,795 334,630 351,432
Noncore 612,355 678,921 626,085 666,176 696,036
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Total 937,113 1,020,390 964,880 1,000,806 1,047,468
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Sales 337,952 362,624 352,052 355,177 411,414
Transportation 586,426 647,764 595,859 621,741 610,450
Exchange 12,735 10,002 16,969 23,888 25,604
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Total 937,113 1,020,390 964,880 1,000,806 1,047,468
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Revenues (per thousand cubic feet):
Residential $ 6.49 $ 6.68 $ 6.68 $ 6.08 $ 6.71
Commercial/Industrial $ 2.14 $ 2.30 $ 2.51 $ 2.30 $ 2.12
Utility Electric Generation $ 0.51 $ 0.45 $ 0.69 $ 0.88 $ 0.87
Wholesale $ 0.48 $ 0.67 $ 0.79 $ 0.86 $ 1.02
Exchange $ 0.06 $ 0.07 $ 0.22 $ 0.25 $ 0.29
Customers
Active Meters (at end of period):
Residential 4,526,150 4,483,324 4,459,250 4,445,500 4,429,896
Commercial 184,470 187,518 187,602 189,364 193,051
Industrial 22,976 23,505 23,924 24,419 25,642
Utility Electric Generation 8 8 8 8 8
Wholesale 3 3 3 2 2
----------- ----------- ---------- ---------- ----------
Total 4,733,607 4,694,358 4,670,787 4,659,293 4,648,599
----------- ----------- ---------- ---------- ----------
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Residential Meter Usage (annual average):
Revenues (dollars) $ 345 $ 383 $ 371 $ 334 $ 380
Volumes (thousands of cubic feet) 53.2 57.4 55.6 55.0 56.6
System Usage (millions of cubic feet):
Average Daily Sendout 2,579 2,795 2,611 2,717 2,881
Peak Day Sendout 4,120 4,350 4,578 4,547 4,356
Sendout Capability (at end of period) 8,059 7,570 7,351 7,419 7,073
Degree Days (2):
Number 1,215(3) 1,459 1,203 1,258 1,409
Average (20 Year) 1,380 1,418 1,430 1,458 1,474
Percent of Average 88.0% 102.9% 84.1% 86.3% 95.6%
Population of Service Area (estimated at year
end) 17,260,000 17,070,000 15,600,000 15,600,000 15,600,000
</TABLE>
(1) Beginning January 1, 1994, rates included the ratepayer's portion of the
Comprehensive Settlement (the amount included in rates for 1995 and 1994
was $84 million and $119 million, respectively).
(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.
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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 part of central California.
[MAP OF SOUTHERN CALIFORNIA GAS COMPANY 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 Corporation.
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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
("UEG"), wholesale and large commercial and industrial customers. Noncore
customers are especially sensitive to the price relationship between natural
gas and alternate fuels, and many 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
transportation of gas. There are two business units at The Gas Company, one
focusing on core distribution customers and the other on large volume gas
transportation customers. 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. As of December 31, 1995, The Gas Company stored approximately 42
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 UEG requirements.
Gas competes with electricity for residential and commercial cooking, water
heating, space heating uses and clothes drying, 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 1995, approximately 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 UEG customers is very sensitive to the price of
alternative competitive fuels. These customers number only approximately
1,600; however,
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during 1995, they accounted for approximately 16 percent of total gas
revenues, 65 percent of total gas volumes delivered and 11 percent of the
authorized gas margin. Changes in the cost of gas or alternative fuels,
primarily fuel oil, can result in significant shifts in this market, subject
to air quality regulations. Demand for gas for UEG use is also affected by
the price and availability of electric power generated in other areas and
purchased by the Company's UEG customers. (See "Competition" below.)
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, and therefore, does not have a material impact on earnings. Bypass
of other Company markets also may occur and the Company is fully at risk for
lost noncore volumes due to bypass. The Company is continuing to reduce its
costs to maintain low cost competitiveness to retain transportation
customers. Also, significant additional bypass would require construction of
additional facilities by competing pipelines.
To respond to bypass, the Company has received authorization from the
CPUC for expedited review of long-term gas transportation contracts with some
noncore customers at lower than tariff rates. The CPUC has also approved
changes in the methodology for allocating the Company's costs that eliminates
subsidization of core customer rates by noncore customers. This allocation
flexibility, together with negotiating authority, has enabled the Company to
better compete with new interstate pipelines for noncore customers. In
addition, under a capacity brokering 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 - Company Operations -
Ratemaking Procedures.") improves the Company's competitiveness by reducing
the cost of transportation service to noncore customers.
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 have favorably impacted the use of natural
gas in the Company's service territory, particularly by UEG customers and
large industrial customers. However, increasingly complex administrative and
reporting requirements of environmental agencies applicable to commercial and
industrial customers utilizing gas are not generally applicable to those
using electricity.
On December 20, 1995, the CPUC issued a final decision to restructure
California electric utility regulation. Implementation of portions of the
plan is expected to need state legislative or federal administrative
approval. The CPUC's proposal has no immediate effect on the Company's
operations. However, The Gas Company is continuing to evaluate the decision
because future volumes of natural gas it transports for electric utilities
may be adversely affected by increased use of electricity generated by
out-of-state producers. UEG customers currently account for 22 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 Financial Performance.") The restructuring may also
result in a reduction of electric rates to core customers, but it is unlikely
to overcome the entire cost advantage of natural gas for existing residential
uses.
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SUPPLIES OF GAS
---------------
In 1995, The Gas Company delivered approximately 937 billion cubic feet
of natural gas through its system. Approximately 64 percent of these
deliveries were customer-owned gas for which The Gas Company provided
transportation services, compared to 65 percent in 1994. 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 Company's
intrastate transmission system by interstate pipeline companies (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.
The Gas Company currently has paramount rights to daily deliveries of
up to 1.9 billion cubic feet of natural gas over the interstate pipeline
systems of El Paso Natural Gas Company (up to 1,150 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. 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.
The FERC has approved a settlement with Transwestern which calls for
firm customers, including The Gas Company, to subsidize unsubscribed pipeline
costs for a five-year period with Transwestern assuming full responsibility
after that time. On March 15, 1996, El Paso filed a proposed settlement
agreement with the FERC that is similar to the Transwestern settlement.
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The following table sets forth the sources of gas deliveries by The Gas
Company from 1991 through 1995.
SOURCES OF GAS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
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1995 1994 1993 1992 1991
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<S> <C> <C> <C> <C> <C>
Gas Purchases (Millions of Cubic Feet):
Market Gas:
30-Day 133,298 98,071 84,696 20,695 139,649
Other 72,792 148,371 159,197 198,049 168,486
--------- ---------- ---------- ---------- ----------
Total Market Gas 206,090 246,442 243,893 218,744 308,135
Affiliates 98,460 101,276 96,559 99,226 98,566
California Producers & Federal Offshore 29,181 36,158 28,107 42,262 39,613
--------- ---------- ---------- ---------- ----------
Total Gas Purchases 333,731 383,876 368,559 360,232 446,314
Customer-Owned Gas and Exchange Receipts 619,721 658,293 622,307 641,080 629,038
Storage Withdrawal (Injection) - Net (12,278) (9,299) (9,498) 14,379 (8,451)
Company Use and Unaccounted For (4,061) (12,480) (16,488) (14,885) (19,433)
--------- ---------- ---------- ---------- ----------
Net Gas Deliveries 937,113 1,020,390 964,880 1,000,806 1,047,468
--------- ---------- ---------- ---------- ----------
--------- ---------- ---------- ---------- ----------
Gas Purchases: (Thousands of dollars)
Commodity Costs $ 477,595 $ 643,865 $ 815,145 $ 805,550 $1,071,445
Fixed Charges* 264,269 368,516 397,714 397,579 358,294
--------- ---------- ---------- ---------- ----------
Total Gas Purchases $ 741,864 $1,012,381 $1,212,859 $1,203,129 $1,429,739
--------- ---------- ---------- ---------- ----------
--------- ---------- ---------- ---------- ----------
Average Cost of Gas Purchased
(Dollars per Thousand Cubic Feet)** $ 1.42 $ 1.68 $ 2.21 $ 2.24 $ 2.40
--------- ---------- ---------- ---------- ----------
--------- ---------- ---------- ---------- ----------
</TABLE>
* Fixed charges primarily include pipeline demand charges, take or pay
settlement costs and other direct billed amounts allocated over the
quantities delivered by the interstate pipelines serving the Company.
** The average commodity cost of gas purchased excludes fixed charges.
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Market sensitive gas supplies (supplies purchased on the spot market as
well as under longer-term contracts ranging from one month to ten years based
on spot prices) accounted for approximately 62 percent of total gas volumes
purchased by the Company during 1995, as compared with 64 percent and 66
percent, respectively, during 1994 and 1993. These supplies were generally
purchased at prices significantly below those for other long-term sources of
supply.
The Gas Company estimates that sufficient natural gas supplies will be
available to meet the requirements of its customers into the next century.
In 1994, the CPUC approved a "Gas Cost Incentive Mechanism" ("GCIM") for
evaluating the Company's gas purchases. The new GCIM three-year pilot
program that began in April 1994 substantially replaces the prior process of
CPUC reasonableness reviews of gas purchases. The GCIM compares the
Company's cost of gas with the average market price of 30-day firm spot
supplies delivered to The Gas Company's service area and permits full
recovery of all costs within a tolerance band above that average. Cost of
gas purchased above the tolerance band or savings from gas purchased below
the average market price are shared equally between customers and
shareholders. (See "Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations -Ratemaking Procedures.")
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 within the best interests of the ratepayer with an opportunity to
earn a reasonable return on investment. 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 the authorized rate of return on rate
base and the amount of rate base. Rate base consists primarily of net
investment in utility plant. Thus, the Company's earnings are affected by
changes in the authorized rate of return on rate base and the growth in rate
base and by the Company's ability to control expenses and investment in rate
base within the amounts authorized by the CPUC in setting rates. In
addition, the Company's ability to achieve its authorized rate of return is
affected by other regulatory and operating factors. (See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations - Ratemaking Procedures.")
The Gas Company's operating and fixed costs, including return on rate
base, are allocated between core and noncore customers under a methodology
that is based upon the costs incurred in serving these customer classes. For
1996, 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").
The Company has filed a PBR application with the CPUC to replace the
general rate case and certain other traditional regulatory proceedings. PBR,
if approved, would allow the Company to be more responsive to consumer
interests and compete more effectively in contestable markets. Key elements
of this proposal include a permanent reduction in base rates of $42 million,
an indexing measure that would limit future base rate increases to the
inflation rate less a
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productivity factor and rate refunds to customers if service quality were to
deteriorate. This new approach would maintain cost based rates, but would
link financial performance with changes in productivity. 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 the PBR proposal, the Company would be at risk for certain changes
in interest rates and cost of capital, changes in core volumes not caused by
weather, and achievement of productivity improvements. The CPUC's process
for approval of PBR has been delayed pending determination of additional
information various parties desire to establish the starting base cost of
service. An agreement with several interested parties has been reached under
which the Company will provide a substantial portion of the supporting
documentation that would be required for a general rate case proceeding. This
additional step will delay implementation beyond the proposed January 1, 1997
starting date.
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, 1995, nine 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 39 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 two landfill sites. These 47 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 thirty years.
A settlement between The Gas Company and other California utilities and
the Division of Ratepayer Advocates 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
portion of any insurance recovery to offset the 10 percent of costs not
recovered in rates.
At December 31, 1995, the Company's estimated remaining liability for
investigation and remediation was approximately $76 million, of which 90
percent is authorized to be recovered 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 Financial Performance - Environmental Matters.") Because
of 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 7,200 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. Agreements
covering these approximately 5,200 employees related to benefits expired in
1995 and an agreement covering wages, hours and working conditions will
expire on March 31, 1996. Negotiations related to new contracts are ongoing.
-13-
<PAGE>
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 58 President August 1981
Larry J. Dagley 47 Senior Vice President August 1995
and Chief Financial Officer
Debra L. Reed 39 Senior Vice President August 1988
Lee M. Stewart 50 Senior Vice President November 1990
Paul J. Cardenas 49 Vice President January 1995
Pamela J. Fair 37 Vice President January 1995
Leslie E. LoBaugh, Jr. 50 Vice President and General Counsel January 1995
Richard M. Morrow 46 Vice President January 1995
Eric B. Nelson 46 Vice President January 1995
Roy M. Rawlings 51 Vice President January 1987
Anne S. Smith 42 Vice President November 1991
George E. Strang 56 Vice President July 1984
Ralph Todaro 45 Vice President and Controller November 1988
Dennis V. Arriola 35 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. Dagley and Mr. Arriola. From 1985 until
joining Pacific Enterprises in August 1995, Mr. Dagley was Senior Vice
President and Controller (1985-1993) and Senior Vice President and Chief
Financial Officer (1993-1995) of Transco Energy Company. 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).
-14-
<PAGE>
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.
ITEM 2. PROPERTIES
-------------------
At December 31, 1995, The Gas Company owned approximately 2,965 miles of
transmission and storage pipeline, 43,163 miles of distribution pipeline and
42,699 miles of service piping. It also owned 13 transmission compressor
stations and 6 underground storage reservoirs (with a combined working
storage capacity of approximately 115 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 leases, and currently
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 1995 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>
1995 1994
------------------------------------------------------------------------------
7 3/4% 6%-Series A 7 3/4% 6%-Series A
<S> <C> <C> <C> <C>
- -----------------------------------------------------------------------------------------------------
Three months ended:
March 31 $24 3/8 - 21 $18 3/4 - 17 3/8 $26 1/4 - 24 5/8 $21 1/2 - 20
June 30 $25 1/2 - 24 $19 7/8 - 18 $25 1/4 - 23 1/4 $20 3/4 - 18 3/4
Sept. 30 $26 1/4 - 25 1/8 $21 - 19 $24 1/4 - 22 3/8 $19 1/2 - 17 3/4
Dec. 31 $25 3/4 - 25 $21 3/4 - 19 7/8 $23 3/8 - 21 $18 - 16 1/4
</TABLE>
Market prices for the preferred stock were obtained from the Pacific Stock
Exchange. 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 1991 through 1995.
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
Year Ended December 31
------------------------------------------------------------------
(Thousands of Dollars) 1995 1994 1993 1992 1991
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $2,279,308 $2,586,524 $2,811,074 $2,839,925 $2,930,306
Net income $ 214,833 $ 190,513 $ 193,676 $ 194,716 $ 211,792*
Total assets $4,462,279 $4,775,763 $4,950,220 $4,155,399 $4,059,186
Long-term debt $1,220,136 $1,396,931 $1,235,622 $1,147,198 $1,147,132
</TABLE>
*Net income for 1991 includes a net after-tax gain of $15 million relating to
the sale of The Gas Company's headquarters office property.
The Gas Company's parent, Pacific Enterprises, owns 96 percent of the voting
stock, including all of the issued and outstanding common stock; therefore, per
share data have been omitted.
- 16 -
<PAGE>
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
---------------------------------------------
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
------------------------------------------------
INTRODUCTION
This section includes management's analysis of operating results from 1993
through 1995, and is intended to provide additional information about the
Southern California Gas Company's capital resources, liquidity and financial
performance. This section also focuses on the major factors expected to
influence future operating results and discusses future investment and
financing plans. Management's Discussion and Analysis should be read in
conjunction with the Consolidated Financial Statements.
The Company, a subsidiary of Pacific Enterprises (the Parent), is a
Los Angeles-based utility engaged in supplying natural gas throughout most of
southern and part of central California. The Company is the nation's
largest natural gas distribution utility, serving 4.7 million meters and 535
cities and communities throughout a 23,000 square mile service territory with a
population of approximately 17 million.
The Company markets are separated into core customers and noncore customers.
Core customers consist of approximately 4.7 million customers (4.5 million
residential and 200,000 small commercial and industrial customers). The
noncore market consists of approximately 1,600 large customers which includes
8 utility electric generation, 3 wholesale, and the remainder large commercial
and industrial customers. Most noncore customers procure their own gas supply
rather than purchase gas through the utility.
In 1995, the Parent completed a realignment into business units which
established a more flexible design to allow a more rapid response to
competitive forces. There are two business units at the Company, one focusing
on core distribution customers and the other on large volume gas transportation
customers.
CAPITAL RESOURCES AND LIQUIDITY
The Company's primary sources and uses of cash during the last three years are
summarized in the following condensed statement of cash flows:
<TABLE>
<CAPTION>
SOURCES AND (USES) OF CASH Year Ended December 31
--------------------------
(Dollars in millions) 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating Activities $ 663 $ 150 $ 415
Capital Expenditures (231) (245) (318)
Financing Activities:
Long-Term Debt (168) 246 62
Short-Term Debt (44) 11 52
Dividends (242) (155) (145)
------ ------ ------
Total Financing Activities (454) 102 (31)
Other (23) 36 (53)
--------------------------
Increase (Decrease) in Cash and Cash Equivalents $ (45) $ 43 $ 13
--------------------------
--------------------------
</TABLE>
- 17 -
<PAGE>
CASH FLOWS FROM OPERATING ACTIVITIES
The increase in cash flow from operating activities to $663 million in 1995
from $150 million in 1994 is primarily due to a payment of $391 million for the
settlement of gas contract issues made in 1994. The decrease in cash flow from
operating activities of $265 million in 1994 from 1993 is primarily due to a
payment for the settlement of gas contract issues partially offset by an
increase in collections of regulatory accounts receivable.
There are a number of factors that impact the Company's cash flow from
operations. These include changes in operating expenses and the authorized
return on common equity.
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures primarily represent rate base investment at the Company.
The table below summarizes capital expenditures by utility plant classification:
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES Year Ended December 31
--------------------------
- (Dollars in millions) 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
- Distribution $126 $129 $159
- Transmission 19 24 54
- Storage 19 22 33
- Other 67 70 72
--------------------------
- Total $231 $245 $318
--------------------------
--------------------------
</TABLE>
Capital expenditures for 1995 are $14 million lower than 1994, primarily the
result of reduced investing requirements for connecting new customers. The
decrease in expenditures in 1994 compared to 1993 was primarily due to a $30
million decrease in distribution main pipeline extensions as a result of fewer
new customer connections and a $30 million decrease in non-recurring
transmission projects such as the expansion of a compressor station and
pipeline upgrades.
Capital expenditures are estimated to be approximately $224 million in 1996 and
will be financed primarily by internally generated funds.
CASH FLOWS FROM FINANCING ACTIVITIES
In 1995, $454 million was used for financing activities. This was the result of
repayment of short and long-term debt and payment of common dividends.
Cash flow provided by financing activities of $102 million in 1994 was due to
the issuance of long-term debt for financing a comprehensive settlement of gas
supply contracts and other regulatory issues (see Note 2 of Notes to
Consolidated Financial Statements - Comprehensive Settlement of Regulatory
Issues). The cash flow used for financing activities in 1993 of $31 million
was primarily due to dividend payments partially offset by the issuance of short
and long-term debt.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents are $13 million and $58 million at December 31, 1995
and 1994, respectively. The Company anticipates that cash required in 1996 for
capital expenditures, dividends and debt payments will be provided by cash
generated from operating activities and existing cash balances.
- 18 -
<PAGE>
In addition to cash from ongoing operations, the Company has available a $650
million multi-year credit agreement requiring annual fees of .075%. The
interest rate on this line varies and is derived from formulas based on market
rates and the Company's credit ratings. This multi-year credit agreement
expires in February, 2001. At December 31, 1995, the bank line of credit was
unused. This line of credit provides backing for the Company's commercial paper
program. The Company has $415 million of commercial paper outstanding at
December 31, 1995, including $265 million to finance the Comprehensive
Settlement of gas supply contracts and other regulatory issues, with the
remainder financing seasonal cash needs at the Company.
PREFERRED STOCK REDEMPTION
The Company plans to redeem up to $100 million of variable rate preferred stock
during 1996.
COMPANY OPERATIONS
To fully understand the operations and financial results of the Company it is
important to understand the ratemaking procedures that the Company employs.
RATEMAKING PROCEDURES
The Company is regulated by the California Public Utilities Commission (CPUC).
It is the responsibility of the CPUC to determine that utilities operate in the
best interests of the ratepayer with the opportunity to earn a reasonable
return on investment. Current ratemaking procedures are summarized below.
In a general rate case, the CPUC establishes a margin, which is the amount of
revenue authorized to be collected from customers to recover authorized
operating expenses (other than the cost of gas), depreciation, interest, taxes
and return on rate base. General rate cases are typically filed every three
years. On June 1, 1995, the Company filed a "Performance Based Regulation"
(PBR) application with the CPUC which would replace the general rate case. For a
further discussion of PBR, see Factors Influencing Future Financial Performance
- - Performance Based Regulation.
The CPUC annually adjusts rates for years between general rate cases to reflect
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 1996 for increases in operating and maintenance expenses to the
extent that the projected annual inflation rate exceeds 3%. In 1995, the CPUC
authorized allowances to the extent inflation exceeded 2%. For further
discussion of annual attrition allowances, see Note 2 of Notes to Consolidated
Financial Statements.
Biennial cost allocation proceedings (BCAP) adjust rates to reflect variances
in the cost of gas and customer demand from estimates adopted in a general rate
case. This mechanism substantially eliminates the effect on income of variances
in core market demand and gas costs subject to limitations of the Gas Cost
Incentive Mechanism and Comprehensive Settlement. For further discussion see
Note 2 of Notes to Consolidated Financial Statements.
The CPUC approved a Gas Cost Incentive Mechanism (GCIM) for evaluating the
Company's gas purchases. This mechanism compares the Company's cost of gas
with the average market price of 30-day firm spot supplies delivered to the
Company's service area and permits full recovery of all costs within a
tolerance band above that average. The costs of purchases above the
tolerance band or savings from purchases below the average market price are
shared equally between ratepayers and shareholders. For further discussion of
GCIM, see Note 2 of Notes to Consolidated Financial Statements.
- 19 -
<PAGE>
1993 - 1995 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 change in the
authorized 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. The Company refunds or collects in the future the amounts by which
certain defined costs vary from the amounts authorized by the CPUC in the
rate case or other regulatory proceedings. Also, variations in core revenues
from estimates adopted by the CPUC in established rates are refunded or
collected through the balancing account mechanism. Thus, full balancing
account treatment allows the Company to fully recover amounts recorded as
deferred costs or core revenue shortfalls currently or in the future.
Key financial and operating data for the Company are highlighted in the table
below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
--------------------------------
(DOLLARS IN MILLIONS) 1995 1994 1993
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues $2,279 $2,587 $2,811
Cost of gas $ 737 $ 992 $1,187
Operating expenses $ 760 $ 827 $ 868
Net income (after preferred dividends) $ 203 $ 180 $ 184
Authorized return on rate base 9.67% 9.22% 9.99%
Authorized return on common equity 12.00% 11.00% 11.90%
Weighted average rate base $2,766 $2,862 $2,769
(Decline) growth in weighted average rate base over prior period (3.4)% 3.4% 1.8%
--------------------------------
</TABLE>
The Company's operating revenues decreased $308 million in 1995. The
decrease is primarily due to a reduction in the average unit cost of gas and
a decrease in noncore transportation volumes. The Company's cost of gas
distributed decreased $255 million in 1995 due to lower volumes of gas
purchased for customers and a decrease in the average unit cost of gas. The
decrease in transportation volumes was primarily in the utility electric
generation market. This was due to an abundance of less expensive
hydroelectricity resulting from high levels of precipitation last winter. The
decrease in operating revenue of $224 million in 1994 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
average commodity cost of gas purchased by the Company, excluding fixed
charges, for 1995 was $1.42 per thousand cubic feet, compared to $1.68 per
thousand cubic feet in 1994 and $2.21 per thousand cubic feet in 1993.
The Company's operating expenses decreased $67 million in 1995. The decrease
primarily reflects savings from cost reduction efforts in 1995 and
nonrecurring expenses in 1994. Operating costs for 1994 included expenses
resulting from the January 1994 earthquake and expenses related to a
discontinued capital project. The decrease of $41 million in 1994 was
primarily due to aggressive reductions in operating expenses partially offset
by the nonrecurring expenses discussed above.
The Company has achieved or exceeded the rate of return on rate base
authorized by the CPUC for 13 consecutive years. In 1995, the Company
achieved a 10.84% return on rate base compared to a 9.67% authorized return
and a 13.89% return on equity compared to a 12% authorized return. The
improved returns were primarily due to lower operating costs as a result of
reduced staffing levels and other cost reduction efforts.
- 20 -
<PAGE>
In 1994, the Company achieved a 9.74% return on rate base compared to a 9.22%
authorized return and a 12.33% return on equity compared to an 11% authorized
return. The improved returns were primarily due to more efficient operations
through reductions in operating expenses, higher noncore earnings and a
conservation award.
The Company plans to continue efforts to control costs in 1996. In 1996, the
Company is authorized to earn 9.42% return on rate base and 11.6% on common
equity. Rate base is expected to decline slightly from the level in 1995.
OPERATING RESULTS
The table below summarizes the components of the Company's throughput and
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 of Notes to Consolidated Financial Statements). The amount
included in rates for 1995 was $84 million and in 1994 was $119 million.
<TABLE>
<CAPTION>
GAS SALES TRANSPORTATION AND EXCHANGE TOTAL
--------- --------------------------- -----
(DOLLARS IN MILLIONS, VOLUME
IN BILLION CUBIC FEET) THROUGHPUT REVENUE THROUGHPUT REVENUE THROUGHPUT REVENUE
- -------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
1995:
Residential 237 $1,547 2 $ 7 239 $1,554
Commercial/Industrial 97 546 267 206 364 752
Utility Electric Generation 205 104 205 104
Wholesale 4 7 125 55 129 62
------------------------------------------------------------------------------
Total in Rates 338 $2,100 599 $372 937 2,472
Balancing and Other (193)
----------
Total Operating Revenues $2,279
- ------------------------------------------------------------------------------------------------------------
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
- ------------------------------------------------------------------------------------------------------------
- ------------------------------------------------------------------------------------------------------------
</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 1996, approximately 89% of total margin authorized is contributed by the
core market (residential and smaller commercial and industrial customers),
with 11% contributed by the noncore market. Throughput, the total gas sales
and transportation volumes moved through the Company's system, decreased in
1995 as a result of lower demands, primarily by utility electric generators.
This was as a result of an abundance of inexpensive hydroelectricity. The
increase in throughput in 1994 from 1993 levels was the result of greater
weather-related demand in noncore volumes, primarily utility electric
generation.
- 21 -
<PAGE>
FACTORS INFLUENCING FUTURE FINANCIAL PERFORMANCE
Because of the ratemaking and regulatory process as well as the changing
energy marketplace there are several factors that will influence future
financial performance. These factors are summarized below.
Under current ratemaking policies, Company net income and cash flow will be
determined primarily by the allowed rate of return on common equity, changes
in authorized rate base, noncore market pricing, the variance in gas volumes
delivered to noncore customers from 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.
Future regulatory restructurings (including the PBR proposal from the
Company), 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 following detailed discussion addresses each of the major factors
expected to influence future financial performance:
ALLOWED RATE OF RETURN. The Company's earnings for 1996 will be affected by
a decrease in the authorized rate of return on common equity. For 1996, the
Company is authorized to earn a rate of return on rate base of 9.42% and a
rate of return on common equity of 11.6%, compared to 9.67% and 12%,
respectively, in 1995. A change in return on equity of one percentage point
impacts net income by approximately $13 million. The CPUC has also
authorized an increase in the equity component of the Company's capital to
47.4% in 1996 from 47.0% in 1995. The 40 basis point increase in the equity
component should add between $1 million to $2 million to earnings. Rate base
is expected to decline slightly from the level in 1995.
NONCORE BYPASS. The Company's throughput to enhanced oil recovery (EOR)
customers in the Kern County area has decreased significantly because of the
bypass of the Company's system by competing interstate pipelines. The
decrease in revenues from EOR customers is subject to full balancing account
treatment except for a 5% incentive to the Company, and therefore, does not
have a material impact on the Company's earnings.
Bypass of other markets may also occur, and the Company is fully at risk for
lost non-EOR noncore volumes due to bypass. The Company is continuing to
reduce its costs to maintain low cost competitiveness to retain
transportation customers. Also, significant additional bypass would require
construction of additional facilities by competing pipelines.
NONCORE PRICING. To respond to bypass, the Company has received
authorization from the CPUC for expedited review of long-term gas
transportation service contracts with some noncore customers at lower than
tariff rates. In addition, the CPUC has approved changes in methodology that
eliminates subsidization of core customer rates by noncore customers. This
allocation flexibility, together with negotiating authority, has enabled the
Company to better compete with interstate pipelines for noncore customers.
NONCORE THROUGHPUT. The Company's earnings may be adversely impacted 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,
electric deregulation, the increased use of hydroelectric power, competing
pipeline bypass of the Company's system and a downturn in general economic
conditions. Many noncore customers are especially sensitive to the price
relationship between natural gas and
- 22 -
<PAGE>
alternative fuels and they are capable of readily switching from one fuel to
another, subject to air quality regulations. The Company is at risk for the
lost revenue.
Through July 31, 1999 any favorable earnings effect of higher revenues
resulting from higher throughput to noncore customers has been eliminated as
a result of the Comprehensive Settlement described in Note 2 of Notes to
Consolidated Financial Statements.
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 annual reservation charges to pipeline
customers may be relinquished within the next few years. Some of this
capacity may not be resubscribed. Current Federal Energy Regulatory
Commission (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.
The FERC has approved a settlement with Transwestern which calls for firm
customers, including the Company, to subsidize unsubscribed pipeline costs
for a five-year period with Transwestern assuming full responsibility after
that time. Negotiations are continuing with El Paso and a settlement is
expected to be filed with the FERC in the first quarter of 1996.
MANAGEMENT CONTROL OF EXPENSES AND INVESTMENT. Over the past 13 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.
PERFORMANCE BASED REGULATION. The Company has filed a PBR application with
the CPUC to replace the general rate cases and other traditional regulatory
proceedings. PBR, if approved, would allow the Company to be more responsive
to consumer interests and compete more effectively in contestable markets.
Key elements of this proposal include a permanent reduction in base rates of
$42 million, an indexing measure that would limit future base rate increases
to the inflation rate less a productivity factor, and rate refunds to customers
if service quality were to deteriorate. This new approach would maintain cost-
based rates but would link financial performance with changes in
productivity. 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 the PBR proposal, the Company would be at risk for certain changes in
interest rates and cost of capital, changes in core volumes not caused by
weather, and achievement of productivity improvements. The CPUC's process
for approval of PBR has been delayed pending determination of additional
information various parties desire to establish the starting base cost of
service. An agreement with several interested parties has been reached under
which the Company will provide a substantial portion of the supporting
documentation that would be required for a general rate case proceeding. This
additional step will delay implementation beyond the proposed January 1, 1997
starting date.
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. On December 20, 1995, the CPUC issued a final decision to
restructure California electric utility regulation. Implementation of
portions of the plan is expected to require state legislative or federal
administrative approval. The CPUC's decision has no immediate effect on the
Company's operations. However, the Company is continuing to evaluate the
decision because future volumes of natural gas it transports for electric
utilities may
- 23 -
<PAGE>
be adversely affected by increased use of electricity generated by
out-of-state producers. The electric industry restructuring may also result
in a reduction of electric rates to core customers, but it is unlikely to
overcome the entire cost advantage of natural gas for existing uses.
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. Increasingly complex administrative and reporting requirements of
environmental organizations applicable to commercial and industrial customers
utilizing natural gas are not generally required by those using electricity.
However, anticipated advancement in natural gas technologies will enable gas
equipment to remain competitive with alternate energy sources. 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 environmental and regulatory matters, see Note 4 of
Notes to Consolidated Financial Statements.
UNION CONTRACT. Most field, clerical and technical employees of the Company
are represented by the Utility Workers' Union of America or the International
Chemical Workers' Union. A contract with these unions relating to employee
benefits expired in 1995 and a contract covering wages, hours and working
conditions will expire March 31, 1996. Negotiations related to new contracts
are ongoing.
CALIFORNIA ECONOMY. Growth in the Company markets is largely dependent on
the health and expansion of the California economy. While California has
undergone a recession in recent years, current economic forecasts indicate the
state will experience a higher growth in jobs than the rest of the country.
OTHER INCOME AND INTEREST EXPENSE
OTHER INCOME AND DEDUCTIONS. Other income was $6 million, $17 million and
$11 million in 1995, 1994 and 1993, respectively. The decrease from 1994 is
primarily due to a $13 million reduction in regulatory interest which is
recognized on balances in the regulatory balancing accounts. Other - Net
expense consists primarily of contributions and amortization of loss on
reacquired debt.
INTEREST EXPENSE. Interest expense was $91 million, $105 million and $102
million in 1995, 1994 and 1993, respectively. Interest expense in 1995 was
reduced from the 1994 level as a result of repayment of debt and refinancing
of Company debt at lower interest rates.
- 24 -
<PAGE>
Item 8. Financial Statements and Supplementary Data
----------------------------------------------------
STATEMENT OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
Year Ended December 31
------------------------------------------
(Thousands of Dollars) 1995 1994 1993
- -----------------------------------------------------------------------------------------
<S> <C> <C> <C>
OPERATING REVENUES $2,279,308 $2,586,524 $2,811,074
---------- ---------- ----------
OPERATING EXPENSES
Cost of Gas Distributed 736,605 991,625 1,187,072
Operation 672,864 745,961 768,677
Maintenance 86,255 80,980 99,795
Depreciation 237,026 233,580 228,244
Income Taxes 151,274 145,603 134,491
Local Franchise Payments 34,048 41,966 46,217
Ad Valorem Taxes 34,974 36,901 32,592
Payroll and Other Taxes 26,431 31,281 29,488
---------- ---------- ----------
Total 1,979,477 2,307,897 2,526,576
---------- ---------- ----------
Net operating revenue 299,831 278,627 284,498
---------- ---------- ----------
OTHER INCOME AND (DEDUCTIONS)
Interest Income 7,566 6,623 1,668
Regulatory Interest 1,442 14,046 4,924
Allowance for Equity Funds Used During
Construction 5,495 2,394 4,406
Income Taxes on Non-Operating Income (277) 941 5,670
Other - Net (8,606) (7,033) (5,245)
---------- ---------- ----------
Total 5,620 16,971 11,423
---------- ---------- ----------
INTEREST CHARGES AND (CREDITS)
Interest on Long-Term Debt 86,864 89,023 95,806
Other Interest 6,938 17,425 9,180
Allowance for Borrowed Funds Used
During Construction (3,184) (1,363) (2,741)
---------- ---------- ----------
Total 90,618 105,085 102,245
---------- ---------- ----------
Net Income 214,833 190,513 193,676
Dividends on Preferred Stock 11,613 10,468 9,882
---------- ---------- ----------
Net Income Applicable to Common Stock $ 203,220 $ 180,045 $ 183,794
---------- ---------- ----------
---------- ---------- ----------
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
-25-
<PAGE>
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
December 31
--------------------------
(Thousands of Dollars) 1995 1994
- -----------------------------------------------------------------------------------------
<S> <C> <C>
---------- ----------
ASSETS
Utility Plant - at original cost $5,807,940 $5,613,013
Less: Accumulated Depreciation 2,594,713 2,400,601
---------- ----------
Utility plant - net 3,213,227 3,212,412
---------- ----------
Current Assets:
Cash and cash equivalents 12,611 57,531
Accounts receivable - trade (less allowance for doubtful
receivables of $13,456 in 1995 and $10,830 in 1994) 398,515 523,975
Regulatory accounts receivable - net 260,573 360,479
Deferred income taxes 25,953
Gas in storage 54,782 63,470
Materials and supplies 14,504 25,792
Prepaid expenses 32,593 34,129
---------- ----------
Total current assets 799,531 1,065,376
---------- ----------
Regulatory Assets 449,521 497,975
---------- ----------
Total $4,462,279 $4,775,763
---------- ----------
---------- ----------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common equity:
Common stock $ 834,889 $ 834,889
Retained earnings 613,445 643,040
---------- ----------
Total common equity 1,448,334 1,477,929
Preferred stock 196,551 196,551
Long-term debt 1,220,136 1,396,931
---------- ----------
Total capitalization 2,865,021 3,071,411
---------- ----------
Current Liabilities:
Short-term debt 233,817 278,201
Accounts payable - trade 162,670 212,888
Accounts payable - affiliates 9,734 35,013
Accounts payable - other 255,900 143,235
Accrued taxes and franchise payments 45,933 117,576
Deferred income taxes 40,792
Long-term debt due within one year 95,283 86,000
Accrued interest 43,480 40,057
Other accrued liabilities 50,678 162,489
---------- ----------
Total current liabilities 897,495 1,116,251
---------- ----------
Customer Advances for Construction 47,029 44,269
Deferred Income Taxes 404,308 341,149
Deferred Investment Tax Credits 66,983 69,969
Other Deferred Credits 181,443 132,714
Commitments and Contingent Liabilities (Note 4)
---------- ----------
Total $4,462,279 $4,775,763
---------- ----------
---------- ----------
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
-26-
<PAGE>
STATEMENT OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
(THOUSANDS OF DOLLARS) 1995 1994 1993
- --------------------------------------------------------------------------------------------
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income $214,833 $190,513 $193,676
Items Not Requiring Cash:
Depreciation 237,026 233,580 228,244
Deferred income taxes 59,544 (49,432) 33,093
Deferred investment tax credits (2,986) (3,024) (3,811)
Allowance for funds used during construction (8,679) (3,757) (7,147)
Other 53,296 (18,983) 22,442
Net Change in Other Working Capital Components:
Accounts receivable 125,460 (20,667) (3,235)
Regulatory accounts receivable 183,723 231,006 (107,320)
Gas in storage 8,688 (10,356) (13,279)
Other current assets 12,824 (16,332) 19,787
Accounts payable (16,171) (521,172) 77,672
Accrued taxes and franchise payments (71,643) 30,386 (74,466)
Deferred income taxes (76,001) 4,914 23,501
Other current liabilities (57,144) 103,451 26,245
--------- --------- ---------
Net cash provided by operating activities 662,770 150,127 415,402
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital Expenditures for Utility Plant (230,969) (244,721) (318,429)
(Increase) Decrease in Other Assets - Net (22,492) 35,267 (52,929)
--------- --------- ---------
Net cash used in investing activities (253,461) (209,454) (371,358)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends (242,333) (154,723) (144,590)
Issuance of Long-Term Debt 245,847 631,000
Payments of Long-Term Debt (167,512) (569,239)
Sale of Preferred Stock 75,000
Redemption of Preferred Stock (75,000)
Increase (Decrease) in Short-Term Debt (44,384) 11,201 52,000
--------- --------- ---------
Net cash provided by (used in) financing activities (454,229) 102,325 (30,829)
--------- --------- ---------
Increase (Decrease) in Cash and Cash Equivalents (44,920) 42,998 13,215
Cash and Cash Equivalents - January 1 57,531 14,533 1,318
--------- --------- ---------
Cash and Cash Equivalents - December 31 $ 12,611 $ 57,531 $ 14,533
--------- --------- ---------
--------- --------- ---------
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Paid During the Year for:
Interest (net of amount capitalized) $ 81,932 $107,088 $ 97,514
--------- --------- ---------
--------- --------- ---------
Income taxes $231,987 $ 89,135 $142,346
--------- --------- ---------
--------- --------- ---------
</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, 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
Net Income 214,833
Cash Dividends Declared:
Preferred stock (11,613)
Common stock (232,815)
-------- -------- ---------
BALANCE AT DECEMBER 31, 1995 $196,551 $834,889 $613,445
-------- -------- ---------
-------- -------- ---------
</TABLE>
The number of shares of preferred stock and common stock authorized and
outstanding at December 31, 1995 and 1994, 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% 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 subsidiaries. One subsidiary has a 15% limited partnership
interest in a 52-story office building in which the Company occupies
approximately one-half of the leasable space. Investments in 50% 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 1995 financial statement
presentation.
REGULATION
In conformity with generally accepted accounting principles (GAAP), the
Company's accounting policies reflect the financial effects of rate
regulation 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. The Company records
Regulatory Assets which represent assets which are being recovered through
customer rates or are probable of being recovered through customer rates. As
of December 31, 1995, the Company had $450 million of regulatory assets which
included the following: costs of reacquiring debt - $52 million;
Comprehensive Settlement costs (see Note 2) - $175 million; deferred income
taxes - $109 million (see Note 3); environmental remediation - $64 million
(see Note 4); and other costs - $50 million. Maintenance of the regulatory
accounts and regulatory accounts receivable represents the only difference in
the application of GAAP for the Company versus non-regulated entities.
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.
GAS IN STORAGE
Gas in storage inventory is stated at last-in, first-out (LIFO) cost. As a
result of a 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, 1995
and 1994 by $21 million and $34 million, respectively. Materials and
supplies are generally stated at the lower of cost, determined on an average
cost basis, or market.
- 29 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
UTILITY PLANT
The costs 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. The depreciation methods are consistent with those used by
non-regulated entities.
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
$9 million in 1995, $4 million in 1994 and $7 million in 1993 was capitalized.
OTHER
Cash equivalents include short-term investments purchased with maturities of
less than 90 days.
The preparation of financial statements in conformity with GAAP requires
management to make estimates and assumptions that affect the reported amounts
of assets and liabilities and disclosure of contingent assets and liabilities
at the date of the financial statements and the reported amounts of revenues
and expenses during the reporting period. Actual results could differ from
those estimates.
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
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% 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
- 30 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
deliveries in excess of 1991 levels will be limited by a crediting account
mechanism that will require a credit to customers of 87.5% 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 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.
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.
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 Gas Cost Incentive
Mechanism (GCIM) is a three-year pilot program which began April 1, 1994.
The GCIM essentially compares the Company's cost of gas with a benchmark
level, which is the average price of 30-day firm spot supplies delivered to
the Company's market area.
The Company can recover costs in excess of the benchmark to the extent they
fall within a tolerance band which extends to 4% above the benchmark. If the
Company's cost of gas exceeds the tolerance level, then the excess cost will
be shared equally between ratepayers and shareholders. All savings from gas
purchased below the average market price are shared equally between
ratepayers and shareholders. For the first year of the program, ended March
31, 1995, gas purchases were within the established 4.5% tolerance band.
ATTRITION ALLOWANCES. The Comprehensive Settlement authorizes the Company an
annual allowance for increases in operating and maintenance expenses for 1996
to the extent that the projected annual inflation rate exceeds 3%. In 1995
attrition was calculated on the inflation rate in excess of 2%. The rate
base attrition will continue to be based upon a three year rolling average of
recorded net utility plant additions. This is a departure from past
regulatory practice of allowing recovery in rates of the full effect of
inflation on operating and maintenance expenses. The Company intends to
continue to attempt to control operating expenses and investment to amounts
authorized in rates to offset the effect of this regulatory change. The most
recent decision issued by the CPUC in December 1995 authorized the Company to
collect $12 million in rates for the 1996 attrition allowance.
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.
- 31 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
In the most recent decision issued by the CPUC in December 1995, the Company
has been authorized to reduce rates by $50 million effective January 1, 1996.
The reduction is comprised of the following:
(Millions of Dollars) Increase (Decrease)
---------------------------------------------------------------
1996 Cost of Capital $(12)
BCAP: Core (94)
Noncore 20
1996 Attrition Allowances 12
1994 Earthquake Costs 22
Other 2
-----
Total $(50)
-----
-----
Regulatory Accounts Receivable and Regulatory Assets include a total of
approximately $259 million and $327 million in 1995 and 1994, respectively,
for the recovery of costs as provided in the Comprehensive Settlement. The
CPUC authorized the borrowing of $425 million primarily to provide for funds
needed under the Comprehensive Settlement. As of December 31, 1995, the
Company has $265 million in commercial paper remaining outstanding related to
the Comprehensive Settlement (See Note 6).
3. INCOME TAXES
A reconciliation of the difference between computed statutory federal income
tax expense and actual income tax expense for operations is as follows:
<TABLE>
<CAPTION>
Year Ended December 31
-----------------------------------
(Thousands of Dollars) 1995 1994 1993
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Computed statutory federal income tax expense $128,235 $117,311 $112,874
Increase (reductions) resulting from:
Excess book over tax depreciation 19,638 17,473 17,847
State income taxes - net of federal income tax benefit 21,287 19,119 16,993
Capitalized expenses not deferred (10,058) (6,589)
Federal income tax rate change 1,698
Research and development credit (4,000)
Amortization of deferred investment tax credits (2,986) (3,024) (3,811)
Resolution of proposed tax deficiency (2,452) 3,850 (10,193)
Other - net (2,113) (3,478) (2,587)
-----------------------------------
Total income tax expense $151,551 $144,662 $128,821
-----------------------------------
-----------------------------------
</TABLE>
- 32 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The components of income tax expense are as follows:
<TABLE>
<CAPTION>
Year Ended December 31
--------------------------------
(Thousands of Dollars) 1995 1994 1993
- --------------------------------------------------------------------------------
<S> <C> <C> <C>
Federal
Current $119,489 $147,647 $ 53,831
Deferred 310 (32,500) 46,044
--------------------------------
119,799 115,147 99,875
--------------------------------
State
Current 37,116 44,289 22,206
Deferred (5,364) (14,774) 6,740
--------------------------------
31,752 29,515 28,946
--------------------------------
Total
Current 156,605 191,936 76,037
Deferred (5,054) (47,274) 52,784
--------------------------------
$151,551 $144,662 $128,821
--------------------------------
--------------------------------
</TABLE>
The principal components of net deferred tax liabilities are as follows:
<TABLE>
<CAPTION>
December 31
--------------------------------------------------------------------------------------
1995 1994
--------------------------------------------------------------------------------------
(Thousands of Dollars) Assets Liabilities Total Assets Liabilities Total
- ------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
Depreciation $(449,571) $(449,571) $(399,381) $(399,381)
Comprehensive Settlement $ 159,294 (77,504) 81,790 $ 211,996 (107,597) 104,399
Regulatory accounts receivable (103,889) (103,889) (150,767) (150,767)
Deferred investment tax credits 29,673 29,673 30,996 30,996
Customer advances for
construction 20,787 20,787 25,527 25,527
Regulatory asset (30,144) (30,144) (39,604) (39,604)
Other regulatory 118,623 (45,624) 72,999 109,084 (62,195) 46,889
--------------------------------------------------------------------------------------
Total deferred income tax
assets (liabilities) $328,377 $(706,732) $(378,355) $377,603 $(759,544) $(381,941)
--------------------------------------------------------------------------------------
--------------------------------------------------------------------------------------
</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 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, 1995 and 1994, $109 million and $97 million, respectively, of
deferred income taxes have been offset by an equivalent amount in regulatory
assets.
- 33 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 these sites) may have remedial obligations under
environmental laws. As of December 31, 1995, nine 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 39 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 for two landfill sites 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% 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% of costs not recovered in rates.
At December 31, 1995, the Company's estimated remaining investigation and
remediation liability was $76 million of which it is authorized to recover 90%
through the mechanism discussed above. The estimated liability is subject to
future adjustment pending further investigation. 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 adverse effect on the Company's
financial statements.
OBLIGATIONS UNDER FIRM COMMITMENTS
The Company has commitments for firm pipeline capacity under contracts with
pipeline companies that expire at various dates through the year 2006. These
agreements provide for payments of an annual demand or reservation charge. The
Company recovers such fixed charges in rates. Estimated minimum commitments as
of December 31, 1995 are as follows: 1996 - $258 million, 1997 - $222 million,
1998 - $244 million, 1999 - $244 million, 2000 - $244 million, after 2000 -
$1,327 million.
OTHER COMMITMENTS AND CONTINGENCIES
At December 31, 1995, commitments for capital expenditures were approximately
$27 million.
- 34 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
5. LEASES
The Company has leases on real and personal property expiring at various dates
from 1996 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 $45 million, $42 million and $39
million in 1995, 1994 and 1993, respectively.
The following is a schedule of future minimum operating lease commitments as of
December 31, 1995:
<TABLE>
<CAPTION>
Future Minimum
(Thousands of Dollars) Lease Payments
---------------------------------------------------------------------
<S> <C>
Year Ending December 31:
1996 $ 31,739
1997 32,708
1998 29,584
1999 29,909
2000 30,511
Later years 271,833
--------
Total $426,284
--------
--------
</TABLE>
6. COMPENSATING BALANCES AND SHORT-TERM BORROWING ARRANGEMENTS
The Company has a $650 million multi-year credit agreement requiring annual fees
of .075%. The interest rate on this line varies and is derived from formulas
based on market rates and the Company's credit ratings. The multi-year credit
agreement expires on February 8, 2001. At December 31, 1995, the bank line of
credit was unused. The unused bank line of credit provides backing for the
Company's commercial paper program.
At December 31, 1995 and 1994, the Company had $415 million and $524 million,
respectively, of commercial paper obligations outstanding. The weighted
average annual interest rate of commercial paper obligations outstanding was
5.66% and 5.96% at December 31, 1995 and 1994, respectively. At December 31,
1995, the Company has classified $181 million of the commercial paper as
long-term debt since it is the Company's intent (supported by the $650 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) 1995 1994
- --------------------------------------------------------------------------------------------------
<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
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
8 3/4% Notes, August 4, 1995 20,000
5.03% - 5.05% Notes, August 28 - September 1, 1995 28,000
5.81% - 5.85% Notes, December 1, 1995 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. 150,000,000 7 1/2% Foreign Interest Payment Securities,
May 14, 1996 75,282 75,282
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
5.66% Commercial Paper, February 8, 2001 181,304 245,847
---------- ----------
Total outstanding 1,330,836 1,499,814
---------- ----------
Less:
Payments due within one year 95,283 86,000
Unamortized debt discount less premium 15,417 16,883
---------- ----------
110,700 102,883
---------- ----------
Long-Term Debt $1,220,136 $1,396,931
---------- ----------
---------- ----------
</TABLE>
The annual principal payment requirements of long-term debt for the years 1996,
1997, 1998 and 2000 are $95 million, $147 million, $147 million, and
$10 million, respectively. No amounts are due in 1999. Substantially all of
utility plant serves as collateral for the First Mortgage Bonds.
- 36 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
CURRENCY RATE SWAPS
In February 1986, the Company issued SFr. 100 million of 5 1/8% 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% with the principal payable on February 6, 1998.
In May 1986, the Company issued SFr. 150 million of 7 1/2% 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.
8. FINANCIAL INSTRUMENTS
The carrying amount of cash and cash equivalents approximates fair value
because of the short maturity of those instruments. The Flexible Auction
preferred stocks of the Company approximate fair value since they are
remarketed periodically. The carrying amount of the currency swaps
approximates fair value.
The fair value of the Company's long-term debt, 6% preferred, 6% Series A
preferred and 7 3/4% preferred stock is estimated based on the quoted market
prices for the same or similar issues or on the current rates offered to the
Company for debt of similar remaining maturities. The fair value of these
financial 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>
1995 1994
-------------------------------------------
Carrying Fair Carrying Fair
(Dollars in Millions) Amount Value Amount Value
--------------------------------------------------------------------
<S> <C> <C> <C> <C>
Long-Term Debt $1,315 $1,278 $1,483 $1,377
Preferred Stocks $ 97 $ 93 $ 97 $ 78
</TABLE>
As a result of the GCIM (See Note 2), the Company enters into a certain
amount of gas futures contracts in the open market with the intent of
reducing gas costs within the GCIM tolerance band. The Company 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, 1995, 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 at December 31 is as follows:
<TABLE>
<CAPTION>
December 31, 1995 December 31, 1994
----------------------------------------------------
Number Thousands Number Thousands
of Shares of Dollars of Shares of Dollars
------------------------------------------------------
<S> <C> <C> <C> <C>
PREFERRED STOCK:
cumulative, voting (a)(b)(c):
6%, $25 par value 79,011 $ 1,975 79,011 $ 1,975
6%, Series A, $25 par value 783,032 19,576 783,032 19,576
Series Preferred, no par value
Flexible Auction, Series A 500 50,000 500 50,000
Flexible Auction, Series 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 Preferred Stock for
1995, 1994 and 1993 were: Series A, 4.80%, 3.40% and 2.67%, respectively;
and for Series C, 4.18%, 3.33% and 2.75%, 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 1995,
1994 and 1993, billings for such gas purchases totaled $141 million, $215
million, and $344 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 an employee's
years of service and compensation during his or her 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 was as follows:
<TABLE>
<CAPTION>
Year Ended December 31
-------------------------------------
(Thousands of Dollars) 1995 1994 1993
- ------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost - benefits earned during the period $ 26,038 $ 33,627 $ 31,828
Interest cost on projected benefit obligation 84,392 80,741 78,727
Actual return on plan assets (315,420) (2,631) (153,293)
Net amortization and deferral 210,594 (94,173) 54,816
-------------------------------------
Net periodic pension cost 5,604 17,564 12,078
Special early retirement program 18,011 11,790 17,546
Regulatory adjustment 4,582 (1,878) 919
-------------------------------------
Total pension expense $ 28,197 $ 27,476 $ 30,543
-------------------------------------
-------------------------------------
</TABLE>
- 39 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
A reconciliation of the plan's funded status to the pension liability
recognized in the Consolidated Balance Sheet is as follows:
<TABLE>
<CAPTION>
December 31
--------------------------
(Thousands of Dollars) 1995 1994
- ---------------------------------------------------------------------------------------------------------
<S> <C> <C>
Actuarial present value of pension benefit obligations
Accumulated benefit obligation, including $956,990 and $751,852
in vested benefits at December 31, 1995 and 1994, respectively $ 1,083,052 $ 844,762
Effect of future salary increases 270,530 203,995
--------------------------
Projected benefit obligation 1,353,582 1,048,757
Less: plan assets at fair value, primarily publicly traded common
stocks and equity pooled funds (1,492,891) (1,237,747)
Unrecognized net gain 185,932 234,372
Unrecognized prior service cost (40,608) (35,761)
Unrecognized transition obligation (4,635) (5,143)
--------------------------
Accrued pension liability included in the Consolidated Balance Sheet $ 1,380 $ 4,478
--------------------------
--------------------------
Deferred pension charge included in the Consolidated Balance Sheet $ (1,813) $ (1,489)
--------------------------
--------------------------
The plans' major actuarial assumptions include:
Weighted average discount rate 6.85% 8.00%
Rate of increase in future compensation levels 5.00% 5.00%
Expected long-term rate of return on plan assets 8.00% 8.00%
</TABLE>
POSTRETIREMENT BENEFIT PLANS
In 1993, the Company adopted Statement of Financial Accounting Standards No.
106, "Employers' Accounting for Postretirement Benefits Other Than Pensions"
(SFAS 106). SFAS 106 requires the accrual of the cost of certain
postretirement benefits other than pensions over the active service period of
the employee. The Company previously recorded these costs when paid or
funded. In accordance with SFAS 106, the Company elected to allow
amortization 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 plans currently provide medical and life
insurance benefits to qualified retirees. 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 for regulated
companies, and as necessary on an actuarial basis to provide assets
sufficient to be paid to plan participants.
Separate trusts for each of the plans have been established exclusively for
the benefit payments of each plan. Some of the plans' funds are commingled
with the pension funds by the trustee for investment purposes but are
accounted for separately per plan.
- 40 -
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The net periodic postretirement benefit expense was as follows:
<TABLE>
<CAPTION>
Year Ended December 31
-------------------------------------
(Thousands of Dollars) 1995 1994 1993
- -----------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Service cost - benefits earned during the period $12,363 $13,122 $11,917
Interest cost on projected benefit obligation 29,089 26,464 26,848
Actual return on plan assets (36,172) (1,487) (10,076)
Net amortization and deferral 35,006 2,561 15,205
-------------------------------------
Net periodic postretirement benefit cost 40,286 40,660 43,894
Regulatory adjustment (1,378) (2,887)
-------------------------------------
Total postretirement benefit expense $38,908 $37,773 $43,894
-------------------------------------
-------------------------------------
</TABLE>
A reconciliation of the plan's funded status to the postretirement liability
recognized in the Consolidated Balance Sheet is as follows:
<TABLE>
<CAPTION>
December 31
-----------------------------
(Thousands of Dollars) 1995 1994
- ------------------------------------------------------------------------------------------------------------------------
<S> <S> <S>
Accumulated postretirement benefit obligation:
Retirees $ 176,278 $ 160,066
Fully eligible active plan participants 228,456 174,440
Other active plan participants 21,301 17,012
-----------------------------
426,035 351,518
Less: plan assets at fair value, primarily publicly traded common stocks (209,990) (144,304)
Unrecognized net transition obligation and equity pooled funds (217,266) (230,047)
Unrecognized net pension service cost 15,050 16,342
Unrecognized net gain (loss) (15,207) 3,612
-----------------------------
Prepaid postretirement benefit asset included in the Consolidated Balance Sheet $ (1,378) $ (2,879)
-----------------------------
-----------------------------
Deferred postretirement benefit charge included in the Consolidated Balance Sheet $ (1,378) $ (2,887)
-----------------------------
-----------------------------
The plan's major actuarial assumptions include:
Health care cost trend rate 7.50% 8.00%
Weighted average discount rate 6.85% 8.00%
Rate of increase in future compensation levels 5.00% 5.00%
Expected long-term rate of return on plan assets 8.00% 8.00%
</TABLE>
The assumed health care cost trend rate is 7.5% for 1996. The trend rate is
expected to decrease from 1996 to 1998 with a 6.5% ultimate trend rate
thereafter. The effect of a one-percentage-point increase in the assumed health
care cost trend rate for each future year is $8.1 million on the aggregate of
the service and interest cost components of net periodic postretirement cost for
1995 and $60.1 million on the accumulated postretirement benefit obligation at
December 31, 1995. The estimated income tax rate used in the return on plan
assets is zero since the assets are invested in tax exempt funds.
-41-
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
POSTEMPLOYMENT BENEFITS
At December 31, 1992, the Company adopted Statement of Financial Accounting
Standards No. 112, "Employers' Accounting for Postemployment Benefits" (SFAS
112). SFAS 112 requires the accrual of the obligation to provide benefits to
former or inactive employees after employment but before retirement. There was
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,
1995 and 1994 the liability was $45 million and $49 million, respectively, and
represents primarily workers compensation and disability benefits.
RETIREMENT SAVINGS PLAN
Upon completion of one year of service, all employees of the Company and certain
subsidiaries are eligible to participate in the Company's retirement savings
plan administered by bank trustees. Employees may contribute from 1% to 14% of
their regular earnings. The Company generally contributes an amount of cash or
a number of shares of the Company's common stock of equivalent fair market value
which, when added to prior forfeitures, will equal 50% of the first 6% of
eligible base salary contributed by employees. The employees' contributions, at
the direction of the employees, are primarily invested in the Company's common
stock, mutual funds or guaranteed investment contracts. In 1993, 1994 and 1995
the Company's contributions were partially funded by the Pacific Enterprises
Employee Stock Ownership Plan and Trust. The Company's compensation expense was
$7 million in 1995, $8 million in 1994 and $9 million in 1993.
-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
page 44. 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 whether the benefits to be derived justify the costs of such
controls.
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 Company's code of corporate conduct, which is
publicized throughout the Company. The Company 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. 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
Larry J. Dagley,
Senior Vice President and Chief Financial Officer
January 31, 1996
-43-
<PAGE>
INDEPENDENT AUDITORS, REPORT
Southern California Gas Company:
We have audited the consolidated financial statements of Southern California Gas
Company and subsidiaries (pages 25 to 42) as of December 31, 1995 and 1994, and
for each of the three years in the period ended December 31, 1995. 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, 1995 and 1994, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 1995 in conformity with generally accepted
accounting principles.
DELOITTE & TOUCHE LLP
Los Angeles, California
January 31, 1996
-44-
<PAGE>
QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
1995
------------------------------------------------
THREE MONTHS ENDED MARCH 31 JUNE 30 SEPT. 30 DEC. 31
- ------------------------------------------------------------------------------------
(THOUSANDS OF DOLLARS)
<S> <C> <C> <C> <C>
OPERATING REVENUES $604,690 $579,559 $505,292 $589,767
NET OPERATING REVENUE $ 73,272 $ 73,880 $ 71,499 $ 81,180
NET INCOME $ 51,049 $ 53,025 $ 50,650 $ 60,109
NET INCOME APPLICABLE TO COMMON STOCK $ 48,121 $ 50,107 $ 47,762 $ 57,230
<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
</TABLE>
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by this Item with respect to the Company's directors
is set forth under the caption "Election of Directors" in the Company's
Information Statement for its Annual Meeting of Shareholders scheduled to be
held on May 2, 1996. 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.
-45-
<PAGE>
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, 1996. 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, 1996. Such information
is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS
None.
-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, 1995, 1994 and 1993.
1.03 Consolidated Balance Sheet at December 31,
1995 and 1994.
1.04 Statement of Consolidated Cash Flows
for the years ended December 31, 1995,
1994 and 1993.
1.05 Statement of Consolidated Shareholders'
Equity for the years ended December 31, 1995,
1994, 1993 and 1992.
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 1995.
REPORT DATE ITEM REPORTED
----------- -------------
October 31, 1995 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: WARREN I. MITCHELL /s/
-----------------------------
Name: Warren I. Mitchell
Title: President
Dated: March 20, 1996
-53-
<PAGE>
Each person whose signature appears below hereby authorizes Warren I.
Mitchell, Larry J. Dagley, 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
- --------- ----- -----
WARREN I. MITCHELL /s/ President March 20, 1996
- ------------------------ (Principal Executive
(Warren I. Mitchell) Officer)
LARRY J. DAGLEY /s/ Senior Vice President and March 20, 1996
- ------------------------ Chief Financial Officer
(Larry J. Dagley) (Principal Financial
Officer)
RALPH TODARO /s/ Vice President and March 20, 1996
- ------------------------ Controller
(Ralph Todaro) (Principal Accounting
Officer)
HYLA H. BERTEA /s/ Director March 20, 1996
- ------------------------
(Hyla H. Bertea)
HERBERT L. CARTER /s/ Director March 20, 1996
- ------------------------
(Herbert L. Carter)
RICHARD D. FARMAN /s/ Director March 20, 1996
- ------------------------
(Richard D. Farman)
WILFORD D. GODBOLD, JR. /s/ Director March 20, 1996
- ------------------------
(Wilford D. Godbold, Jr.)
IGNACIO E. LOZANO, JR. /s/ Director March 20, 1996
- ------------------------
(Ignacio E. Lozano, Jr.)
HAROLD M. MESSMER, JR. /s/ Director March 20, 1996
- ------------------------
(Harold M. Messmer, Jr.)
PAUL A. MILLER /s/ Director March 20, 1996
- ------------------------
(Paul A. Miller)
RICHARD J. STEGEMEIER /s/ Director March 20, 1996
- ------------------------
(Richard J. Stegemeier)
DIANA L. WALKER /s/ Director March 20, 1996
- ------------------------
(Diana L. Walker)
WILLIS B. WOOD, JR. /s/ Director March 20, 1996
- ------------------------
(Willis B. Wood, Jr.)
-54-
<PAGE>
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)
<PAGE>
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 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 Corporation 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 into shares of another
class, conversion of outstanding shares
2
<PAGE>
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 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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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 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, 1996, appearing in this
Annual Report on Form 10-K of Southern California Gas Company for the year
ended December 31, 1995.
DELOITTE & TOUCHE LLP
Los Angeles, California
March 21, 1996
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