<PAGE>
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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D. C. 20549
--------------------------
/X/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 [FEE REQUIRED]
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1997
COMMISSION FILE NUMBER 1-1402
--------------------------
SOUTHERN CALIFORNIA GAS COMPANY
(Exact name of Registrant as specified in its charter)
CALIFORNIA 95-1240705
(State of incorporation) (IRS Employer Identification No.)
555 WEST FIFTH STREET, LOS ANGELES, 90013-1011
CALIFORNIA (Zip Code)
(Address of principal executive offices)
(213) 244-1200
(Registrant's telephone number, including area code)
--------------------------
Securities registered pursuant to Section 12(b) of the Act:
<TABLE>
<CAPTION>
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
- ------------------------------- ---------------------------
<S> <C>
Preferred Stock Pacific Stock Exchange
6% Cumulative
Preferred--Series A
7 3/4% Series Preferred Stock
First Mortgage Bonds New York Stock Exchange
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%)
</TABLE>
Securities registered pursuant to Section 12(g) of the Act: None
--------------------------
Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days. Yes /X/ No / /
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /X/
The aggregate market value of Registrant's voting stock (Preferred Stock)
held by non-affiliates at March 16, 1998, was approximately $22 million. This
amount excludes the market value of 50,477 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.
<TABLE>
<CAPTION>
ANNUAL REPORT INFORMATION INCORPORATED BY REFERENCE AND DOCUMENT
ON FORM 10-K IN WHICH INFORMATION IS OR WILL BE CONTAINED
- ------------------------------ ------------------------------------------------------------------
<S> <C>
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 5,
1998.
</TABLE>
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TABLE OF CONTENTS
<TABLE>
<S> <C>
PART I
Item 1. Business....................................................................... 3
Operating Statistics......................................................... 4
Service Area................................................................. 5
Utility Services............................................................. 6
Demand for Gas............................................................... 6
Competition.................................................................. 7
Supplies of Gas.............................................................. 7
Rates and Regulation......................................................... 9
Environmental Matters........................................................ 11
Employees.................................................................... 12
Management................................................................... 12
Item 2. Properties..................................................................... 12
Item 3. Legal Proceedings.............................................................. 13
Item 4. Submission of Matters to a Vote of Security Holders............................ 13
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder Matters.......... 14
Item 6. Selected Financial Data........................................................ 14
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................................... 14
Item 7a. Quantitative and Qualitative Disclosures About Market Risk.................... 26
Item 8. Financial Statements and Supplementary Data.................................... 27
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure........................................................... 48
PART III
Item 10. Directors and Executive Officers of the Registrant............................ 48
Item 11. Executive Compensation........................................................ 48
Item 12. Security Ownership of Certain Beneficial Owners and Management................ 48
Item 13. Certain Relationships and Related Transactions................................ 48
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.............. 49
</TABLE>
2
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THIS REPORT CONTAINS FORWARD-LOOKING STATEMENTS WITH RESPECT TO MATTERS
INHERENTLY INVOLVING NUMEROUS RISKS AND UNCERTAINTIES. THESE STATEMENTS ARE
IDENTIFIED BY THE WORDS "ESTIMATES," "EXPECTS," "ANTICIPATES," "PLANS,"
"BELIEVES," AND SIMILAR EXPRESSIONS.
THESE STATEMENTS ARE NECESSARILY BASED UPON VARIOUS ASSUMPTIONS INVOLVING
JUDGMENTS WITH RESPECT TO THE FUTURE INCLUDING, AMONG OTHER FACTORS, NATIONAL,
REGIONAL, AND LOCAL ECONOMIC, COMPETITIVE AND REGULATORY CONDITIONS,
TECHNOLOGICAL DEVELOPMENTS, INFLATION RATES, INTEREST RATES, ENERGY MARKETS,
WEATHER CONDITIONS, BUSINESS AND REGULATORY DECISIONS, AND OTHER UNCERTAINTIES,
ALL OF WHICH ARE DIFFICULT TO PREDICT, AND MANY OF WHICH ARE BEYOND THE CONTROL
OF SOUTHERN CALIFORNIA GAS COMPANY. ACCORDINGLY, WHILE SOUTHERN CALIFORNIA GAS
COMPANY BELIEVES THESE ASSUMPTIONS ARE REASONABLE, THERE CAN BE NO ASSURANCE
THAT THEY WILL APPROXIMATE ACTUAL EXPERIENCE, OR THAT THE EXPECTATIONS WILL BE
REALIZED.
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
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
provides gas service to residential, commercial, industrial, utility electric
generation and wholesale customers through approximately 4.8 million meters in a
service area with a population of approximately 17.6 million.
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.
3
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OPERATING STATISTICS
The following table sets forth certain operating statistics of SoCalGas from
1993 through 1997.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
---------------------------------------------------------------------
1997 1996 1995 1994 1993
----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
Gas Sales, Transportation & Exchange
Revenues (millions of dollars):
Residential..................................... $ 1,736 $ 1,613 $ 1,554 $ 1,713 $ 1,652
Commercial/Industrial........................... 756 708 751 798 854
Utility Electric Generation..................... 76 70 104 118 147
Wholesale....................................... 67 70 62 98 117
Exchange........................................ 1 1 1 1 4
----------- ----------- ----------- ----------- -----------
Total in rates (1).............................. 2,636 2,462 2,472 2,728 2,774
Regulatory balancing accounts and other........... 5 (40) (193) (142) 37
----------- ----------- ----------- ----------- -----------
Operating Revenue............................. $ 2,641 $ 2,422 $ 2,279 $ 2,586 $ 2,811
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Volumes (billions of cubic feet):
Residential..................................... 240 236 239 256 247
Commercial/Industrial........................... 388 374 352 348 340
Utility Electric Generation..................... 158 139 204 260 213
Wholesale....................................... 138 130 129 146 148
Exchange........................................ 6 5 13 10 17
----------- ----------- ----------- ----------- -----------
Total......................................... 930 884 937 1,020 965
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Core............................................ 323 314 325 341 339
Noncore......................................... 607 570 612 679 626
----------- ----------- ----------- ----------- -----------
Total......................................... 930 884 937 1,020 965
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Sales........................................... 317 315 338 362 352
Transportation.................................. 607 564 586 648 596
Exchange........................................ 6 5 13 10 17
----------- ----------- ----------- ----------- -----------
Total......................................... 930 884 937 1,020 965
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Revenues (per thousand cubic feet):
Residential..................................... $ 7.23 $ 6.86 $ 6.49 $ 6.68 $ 6.68
Commercial/Industrial........................... $ 1.95 $ 1.89 $ 2.14 $ 2.30 $ 2.51
Utility Electric Generation..................... $ 0.48 $ 0.50 $ 0.51 $ 0.45 $ 0.69
Wholesale....................................... $ 0.49 $ 0.54 $ 0.48 $ 0.67 $ 0.79
Exchange........................................ $ 0.17 $ 0.10 $ 0.06 $ 0.07 $ 0.22
Customers
Active Meters (at end of period):
Residential..................................... 4,624,279 4,582,553 4,526,150 4,483,324 4,459,250
Commercial...................................... 183,146 184,425 184,470 187,518 187,602
Industrial...................................... 22,642 22,952 22,976 23,505 23,924
Utility Electric Generation..................... 8 9 8 8 8
Wholesale....................................... 4 3 3 3 3
----------- ----------- ----------- ----------- -----------
Total......................................... 4,830,079 4,789,942 4,733,607 4,694,358 4,670,787
----------- ----------- ----------- ----------- -----------
----------- ----------- ----------- ----------- -----------
Residential Meter Usage (annual average):
Revenues (dollars).............................. $ 375 $ 352 $ 345 $ 383 $ 371
Volumes (thousands of cubic feet)............... 51.9 50.5 53.2 57.4 55.6
System Usage (millions of cubic feet):
Average Daily Sendout........................... 2,515 2,452 2,579 2,795 2,611
Peak Day Sendout................................ 3,887 4,000 4,120 4,350 4,578
Degree Days (2):
Number.......................................... 1,126(3) 1,195 1,241 1,459 1,203
Average (20 Year)............................... 1,358 1,369 1,381 1,418 1,430
Percent of Average.............................. 82.9% 87.3% 89.9% 102.9% 84.1%
Population of Service Area (estimated at year
end)............................................ 17,630,000 17,424,000 17,260,000 17,070,000 15,600,000
</TABLE>
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(1) Beginning January 1, 1994, rates included the ratepayer's portion of the
Comprehensive Settlement (the amount included in rates for 1997, 1996, 1995,
and 1994 was $98 million, $90 million, $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.
4
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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 17.6 million people. As
indicated by the following map, its service territory includes most of southern
California and part of central California.
[GRAPHIC-MAP OF SERVICE AREA]
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.
5
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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. There
are approximately 4.8 million core customers (4.6 million residential and
200,000 small commercial and industrial). Noncore customers consist primarily of
utility electric generation ("UEG"), wholesale and large commercial and
industrial customers, and total approximately 1,600. Gas volumes delivered to
UEG customers are greatly affected by the price and availability of electric
power generated outside of The Gas Company's service area. UEG and other noncore
customers are also 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 through two business units, one focusing on core
distribution customers and the other on large volume gas transportation
customers. Most residential customers and most other core customers purchase gas
directly from The Gas Company. Noncore 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. Core customers are permitted to aggregate their gas requirements and
also to purchase gas directly from brokers or producers, up to a limit of 10 %
of the Company's core market. Most noncore customers procure their own gas
supply rather than purchase from The Gas Company. Although the revenues from
transportation throughput are less than for gas sales, 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. For 1998,
approximately 88% of the total margin authorized is contributed by the core
market, with 12% contributed by the noncore market. (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 gas storage services for noncore and
off-system customers on a bid and negotiated contract basis. The storage service
program provides opportunities for customers to store gas on an "as available"
basis, usually during the summer to reduce winter purchases when gas costs are
generally higher. As of December 31, 1997, The Gas Company stored approximately
15 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 and clothes drying uses, and with other fuels for large
industrial, commercial and UEG uses. Growth in The Gas Company's markets is
largely dependent upon the health and expansion of the southern California
economy. The Gas Company added approximately 43,700 new meters in 1997. This
represents a growth rate of approximately 0.9%. The Gas Company anticipates that
customer growth for 1998 will continue at about 1997 levels.
During 1997, approximately 97% of residential energy customers in The Gas
Company service area used natural gas for water heating and 94% for space
heating. Approximately 78% of those customers used natural gas for cooking and
72% 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,
during 1997, accounted for approximately 15% of total gas revenues, 65% of total
gas volumes delivered and 12% of the authorized gas margin. External factors
such as weather,
6
<PAGE>
electric deregulation, the increased use of hydro-electric power, competing
pipeline bypass and general economic conditions can result in significant shifts
in this market. Demand for gas for UEG customer use is also greatly affected by
the price and availability of electric power generated in other areas and
purchased by the Company's UEG customers. (See "Competition" below.) Demand for
gas for UEG customer use in 1997 increased as a result of higher demands for
electricity and less availability of hydro-electricity. UEG customer demand
decreased in 1996 as a result of abundant hydro-electricity.
As a result of electric industry restructuring, natural gas demand for
electric generation within the Company's service area competes with electric
power generated throughout the western United States. Effective March 31, 1998,
California consumers are scheduled to be given the option of selecting their
electric energy provider from a variety of local and out-of-state producers. The
implementation of electric industry restructuring has no direct impact on the
Company's operations. However, future volumes of natural gas transported for
utility electric generation customers may be adversely affected to the extent
that regulatory changes divert electricity generation from the Company's service
area. In addition, the electric industry restructuring has mandated a 10%
reduction of electric rates to core customers as of January 1, 1998; however,
electricity is unlikely to overcome the entire cost advantage of natural gas for
existing uses. (See "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operation--Factors Influencing Future Performance.")
COMPETITION
The Gas Company's throughput to enhanced oil recovery ("EOR") customers has
decreased significantly since 1992 because of the bypass of the Company's
system. 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 earnings.
Bypass of other Company markets may also occur and the Company is fully at
risk for reduction in such noncore volumes due to bypass. However, significant
additional bypass would require construction of additional facilities by
competing pipelines. The Gas Company is continuing to reduce its costs to
maintain cost competitiveness to retain transportation customers.
To respond to bypass, the Company may seek expedited review of long-term gas
transportation contracts with some noncore customers at lower than tariff rates.
In addition, the Company allocates costs in a manner 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, a comprehensive settlement of
certain regulatory issues (the "Comprehensive Settlement") has improved the
Company's competitiveness by reducing the cost of transportation service to
noncore customers. (See "Item 7. Management's Discussion and Analysis of
Financial Condition and Result of Operations--1995-1997 Financial Results.")
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 agencies applicable
to commercial and industrial customers utilizing gas are not generally
applicable to those using electricity. However, anticipated advancements in
natural gas technologies should enable gas equipment to remain competitive with
alternate energy sources.
SUPPLIES OF GAS
In 1997, The Gas Company delivered approximately 930 billion cubic feet
("Bcf") of natural gas through its system. Approximately 65% of these deliveries
were customer-owned gas for which The Gas
7
<PAGE>
Company provided transportation services. 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 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 Bcf per day. This excess has reduced the market value of pipeline
capacity well below FERC tariff rates. The Gas Company has exercised its
step-down option on both the El Paso and Transwestern interstate pipeline
systems, thereby reducing its firm interstate capacity obligations to 1.45 Bcf
per day from 2.25 Bcf per day.
FERC-approved settlements have resulted in a reduction in the costs that The
Gas Company may possibly have to pay for the capacity released back to El Paso
and Transwestern that cannot be remarketed. Of the remaining 1.45 Bcf per day of
capacity, the Company's core customers use 1.05 Bcf per day at the full FERC
tariff rate. The remaining 0.4 Bcf per day of capacity is marketed at
significant discounts. Under existing regulation in California, unsubscribed
capacity costs associated with the remaining 0.4 Bcf per day are recoverable in
customer rates. While including the unsubscribed pipeline cost in rates may
impact the Company's ability to compete in highly contested markets, The Gas
Company does not believe its inclusion will have a significant impact on volumes
transported or sold.
8
<PAGE>
The following table sets forth the sources of gas deliveries by The Gas
Company from 1993 through 1997.
SOURCES OF GAS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
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1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C>
Gas Purchases (Billions of Cubic Feet):
Market Gas..................................................... 229 226 206 247 244
Affiliates..................................................... 95 96 99 101 97
California Producers & Federal Offshore........................ 5 12 29 36 28
--------- --------- --------- --------- ---------
Total Gas Purchases.......................................... 329 334 334 384 369
Customer-Owned Gas and Exchange Receipts......................... 614 518 620 658 622
Storage Withdrawal (Injection)--Net.............................. (3) 42 (13) (9) (10)
Company Use and Unaccounted For.................................. (10) (10) (4) (13) (16)
--------- --------- --------- --------- ---------
Net Gas Deliveries........................................... 930 884 937 1,020 965
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Gas Purchases: (Thousands of dollars)
Commodity Costs................................................ $ 849 $ 627 $ 478 $ 644 $ 815
Fixed Charges*................................................. 250 276 264 368 398
--------- --------- --------- --------- ---------
Total Gas Purchases.......................................... $ 1,099 $ 903 $ 742 $ 1,012 $ 1,213
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
Average Cost of Gas Purchased
(Dollars per Thousand Cubic Feet)**............................ $ 2.58 $ 1.88 $ 1.42 $ 1.68 $ 2.21
--------- --------- --------- --------- ---------
--------- --------- --------- --------- ---------
</TABLE>
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* 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.
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 70% of total gas volumes purchased by the
Company during 1997, as compared with 68% and 62%, respectively, during 1996 and
1995. 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 well into the next century.
RATES AND REGULATION
The Gas Company is regulated by the California Public Utilities Commission
("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 their customers
and have the 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.
PERFORMANCE BASED REGULATION
On July 16, 1997, the CPUC issued its final decision on The Gas Company's
application for performance based regulation ("PBR"), which was filed with the
CPUC in 1995.
9
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For the five-year period that commenced January 1, 1998, PBR replaces the
general rate case procedure and certain other regulatory proceedings. Under
ratemaking procedures in effect prior to the PBR decision, The Gas Company
typically filed a general rate case with the CPUC every three years. In a
general rate case, the CPUC established a base margin, which is the amount of
revenue to be collected from customers to recover authorized operating expenses
(other than the cost of gas), depreciation, taxes and return on rate base.
Under PBR, regulators allow future income potential to be tied to achieving
or exceeding specific performance and productivity measures, rather than relying
solely on expanding utility rate base in a market where The Gas Company already
has a highly developed infrastructure. Key elements of the PBR include a
reduction in base rates, an indexing mechanism that limits future rate increases
to the inflation rate less a productivity factor, a sharing mechanism with
customers if earnings exceed the authorized rate of return on rate base, and
rate refunds to customers if service quality deteriorates. The change in
regulatory oversight changes the way earnings are affected by various factors.
For example, under PBR earnings are more reliant on operational efficiencies and
less on investment in property, plant and equipment.
PBR retains the balancing account mechanism by which The Gas Company refunds
or collects in the future the difference between actual core revenue and the
amounts authorized by the CPUC to be received in regulatory proceedings. 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.
The Commission's PBR decision established the following rules for The Gas
Company:
- The decision ordered a rate reduction to an initial base margin of $1.3
billion. This represents a rate reduction of $191 million effective August
1, 1997, partially offset by a $27 million rate increase to reflect
inflation and customer growth effective on January 1, 1998.
- Earnings up to 25 basis points above the authorized rate of return are
retained 100% by shareholders. Earnings that exceed the authorized rate of
return on rate base by greater than 25 basis points are shared between
customers and shareholders on a sliding scale that begins with 75% of
earnings being given back to customers and declining to 0% as earned
returns approach 300 basis points above authorized amounts. However, the
decision rejected sharing of any amount by which actual earnings may fall
below the authorized rate of return. In 1998, The Gas Company is
authorized to earn a 9.49% return on rate base.
- Margin per customer is indexed based on inflation less an estimated
productivity factor of 2.1% in the first year, increasing 0.1% per year to
2.5% in the fifth year. This factor includes 1% to approximate the
projected impact of declining rate base.
- The CPUC decision allows for pricing flexibility for residential and small
commercial customers, with any shortfalls being borne by shareholders and
with gains shared between shareholders and customers.
The Gas Company implemented the base margin reduction on August 1, 1997, and
implemented the remaining PBR elements on January 1, 1998. The CPUC intends for
its PBR decision to be in effect for five years. The CPUC decision also provides
the possibility that changes to the PBR mechanism could be adopted in a decision
to be issued in the Company's 1998 Biennial Cost Allocation Proceeding ("BCAP")
application anticipated to become effective on August 1, 1999.
The BCAP adjusts rates to reflect variances in core customer demand from
estimates previously used in establishing core customer rates. The mechanism
substantially eliminates the effect on core income of variances in core market
demand and gas costs subject to the limitations of the Gas Cost Incentive
Mechanism ("GCIM") and the Comprehensive Settlement. The BCAP will continue
under PBR.
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<PAGE>
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 service area. The
mechanism permits full recovery of all costs within a "tolerance band" above the
benchmark price and refunds all savings within a "tolerance band" below the
benchmark price. The costs of purchases or savings outside the "tolerance band"
are shared equally between customers and shareholders. The GCIM is authorized by
the CPUC to be in effect through March 31, 1999.
In June 1997, the CPUC approved a $3.2 million pre-tax shareholder award for
the GCIM year-ended March 31, 1996 which was recognized as income in 1997.
In June 1997, The Gas Company filed a GCIM application with the CPUC
requesting a shareholder award for the annual period ending March 31, 1997. The
CPUC is expected to issue a final decision on this matter by mid-1998, and
income associated with this award will be recognized at that time.
AFFILIATE TRANSACTIONS
On December 16, 1997, the CPUC adopted rules establishing uniform standards
of conduct governing the manner in which California investor-owned utilities
conduct business with their affiliates providing energy or energy-related
services within California. The objective of these rules, which are effective
beginning January 1, 1998, is to ensure that the utilities' energy affiliates do
not gain an unfair advantage over other competitors in the marketplace and that
utility customers do not subsidize affiliate activities. (See "Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations-- Factors Influencing Future Performance.")
ALLOWED RATE OF RETURN
For 1998, The Gas Company is authorized to earn a rate of return on rate
base of 9.49% and a rate of return on common equity of 11.6%, which is unchanged
from 1997.
GAS INDUSTRY RESTRUCTURING
The gas industry experienced an initial phase of restructuring during the
1980's by deregulating gas sales to noncore customers. On January 21, 1998, the
CPUC released a staff report initiating a project to assess the current market
and regulatory framework for California's natural gas industry. The general
goals of the plan are to consider reforms to the current regulatory framework
emphasizing market-oriented policies to benefit California natural gas
consumers.
ENVIRONMENTAL MATTERS
The CPUC has approved a collaborative settlement which provides for rate
recovery of 90% of environmental investigation and remediation costs without
reasonableness review. In addition, The Gas Company has the opportunity to
retain a portion of any insurance recovery to offset the 10% of costs not
recovered in rates.
At December 31, 1997, the Company's estimated remaining liability for
investigation and remediation was approximately $72 million, of which 90% 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 Performance.")
Because of expected insurance and rate recovery, the Company believes that
compliance with environmental laws and regulations will not have a material
adverse effect on its consolidated results of operations or financial position.
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, 1997, ten of the sites have been
remediated, of
11
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which seven have received certification from the California Environmental
Protection Agency. Two sites are in the process of being remediated. 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 Gas Company and its subsidiaries are one of a large
number of major corporations that have been identified as potentially
responsible parties for environmental remediation of two industrial waste
disposal sites and two landfill sites.
EMPLOYEES
The Company employs approximately 6,615 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. A contract on wages and
working conditions is effective through March 31, 1999. Terms of the contract
allow an extension through March 31, 2000.
MANAGEMENT
The executive officers of Southern California Gas Company are as follows:
<TABLE>
<CAPTION>
BECAME AN
NAME AGE POSITION EXECUTIVE OFFICER
- ------------------------- --- --------------------------------------- ------------------
<S> <C> <C> <C>
Warren I. Mitchell 60 President August 1981
Neal E. Schmale 51 Executive Vice President and Chief December 1997
Financial Officer
Debra L. Reed 41 Senior Vice President August 1988
Lee M. Stewart 52 Senior Vice President November 1990
Paul J. Cardenas 51 Vice President January 1995
Pamela J. Fair 39 Vice President January 1995
Leslie E. LoBaugh, Jr. 52 Vice President and General Counsel January 1995
Richard M. Morrow 48 Vice President January 1995
Roy M. Rawlings 53 Vice President January 1987
Anne S. Smith 44 Vice President November 1991
George E. Strang 58 Vice President July 1984
Ralph Todaro 47 Vice President and Controller November 1988
Dennis V. Arriola 37 Vice President and 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. Schmale and Mr. Arriola. From 1992 until joining
Pacific Enterprises in December 1997, Mr. Schmale was President of the Petroleum
Products and Chemical Divisions of Unocal Corporation (1992-1994) and Chief
Financial Officer of Unocal Corporation (1994-1997). From 1987 until joining the
Company in August 1994, Mr. Arriola was a Vice President of Bank of America
NT&SA (1992-1994) and a Vice President of Security Pacific National Bank
(1987-1992).
Executive officers are elected annually and serve at the pleasure of the
Board of Directors. There are no family relationships among any of the Company's
executive officers.
ITEM 2. PROPERTIES
At December 31, 1997, The Gas Company owned approximately 2,843 miles of
transmission and storage pipeline, 43,769 miles of distribution pipeline and
43,499 miles of service piping. It also owned 10
12
<PAGE>
transmission compressor stations and 6 underground storage reservoirs (with a
combined working storage capacity of approximately 116 Bcf 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% 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 1997 to a vote of the
Company's security holders.
13
<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>
1997 1996
------------------------------------------ ------------------------------------------
7 3/4% 6%-SERIES A 7 3/4% 6%-SERIES A
-------------------- -------------------- -------------------- --------------------
<S> <C> <C> <C> <C>
Three months ended:
March 31...................... $25 3/4 - 25 1/4 $21 7/8 - 20 3/8 $26 1/8 - 25 $22 5/8 - 20 1/2
June 30....................... $25 3/4 - 25 1/4 $21 7/8 - 20 1/4 $25 3/4 - 25 $21 1/2 - 19 5/8
Sept. 30...................... $25 5/8 - 25 1/4 $23 - 21 $25 5/8 - 25 1/8 $21 1/4 - 20 1/8
Dec. 31....................... $25 3/4 - 24 7/8 $24 1/4 - 22 1/4 $25 3/4 - 25 1/4 $21 3/8 - 20
</TABLE>
Market prices for the preferred stock were obtained from the Pacific Stock
Exchange.
ITEM 6. SELECTED FINANCIAL DATA
The following table sets forth certain selected financial data of the
Company for 1993 through 1997.
SELECTED FINANCIAL DATA
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-----------------------------------------------------
1997 1996 1995 1994 1993
--------- --------- --------- --------- ---------
(MILLIONS OF DOLLARS)
<S> <C> <C> <C> <C> <C>
Operating revenues............................................... $ 2,641 $ 2,422 $ 2,279 $ 2,587 $ 2,811
Net income....................................................... $ 238 $ 201 $ 215 $ 191 $ 194
Total assets..................................................... $ 4,205 $ 4,354 $ 4,462 $ 4,776 $ 4,950
Long-term debt................................................... $ 968 $ 1,090 $ 1,220 $ 1,397 $ 1,236
</TABLE>
The Gas Company's parent, Pacific Enterprises, owns, as of the date hereof,
approximately 99% of the voting stock, including all of the issued and
outstanding common stock; therefore, per share data have been omitted.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
INTRODUCTION
This section includes management's analysis of operating results from 1995
through 1997, and is intended to provide additional information about the
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 Parent and Enova Corporation ("Enova"), the parent company of San Diego
Gas & Electric Company, have agreed to a business combination in which they will
each become a subsidiary of a new holding company to be named Sempra Energy. The
holders of the common stock of each company will become holders of the common
stock of Sempra Energy. This strategic merger of equals will be a tax free
transaction accounted for as a pooling of interests.
14
<PAGE>
The combination was approved by the shareholders of both the Parent and
Enova on March 11, 1997, but remains subject to approval by the California
Public Utilities Commission ("CPUC") and the Securities and Exchange Commission
("SEC") under the Public Utility Holding Company Act of 1935. It also remains
subject to final approval by the Federal Energy Regulatory Commission ("FERC"),
which has conditionally approved the combination subject to the imposition of
certain CPUC conditions that are expected to be imposed and are acceptable to
the Parent and Enova.
A CPUC administrative law judge has issued a proposed decision recommending
CPUC approval of the combination. The proposed decision also proposes that net
savings from synergies and cost avoidances from the combination be shared
between customers and shareholders over a five-year period, resulting in
approximately $175 million for customers and $165 million for shareholders. A
CPUC Commissioner has issued an alternate decision which proposes that the net
savings (approximately $1 billion) be shared over a ten-year period
approximately equally between customers and shareholders in essentially the same
manner as originally proposed by the Parent and Enova. The Commissioner's
alternate decision does not preclude other commissioners from proposing other
alternate decisions. The CPUC final decision may be the proposed decision by the
administrative law judge, the alternate decision proposed by the Commissioner,
or another decision.
SEC and final FERC regulatory approvals for the combination are expected to
be obtained following CPUC approval and the commencement of combined operations
is expected during the summer of 1998.
In connection with the completion of the Department of Justice's review and
clearance of the combination, Enova committed to follow through on its
previously announced plans to auction off two fossil-fuel power plants. In
addition, Sempra Energy agreed to obtain prior approval from the Department of
Justice before acquiring or otherwise controlling any existing California
generation facilities in excess of 500 megawatts.
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>
YEAR ENDED DECEMBER 31
-------------------------------
SOURCES AND (USES) OF CASH 1997 1996 1995
- ------------------------------------------------------------------------------ --------- --------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Operating Activities.......................................................... $ 396 $ 638 $ 663
Capital Expenditures.......................................................... (159) (197) (231)
Financing Activities:
Issuance of Long-Term Debt.................................................. 120 75
Payments of Long-Term Debt.................................................. (242) (153) (168)
Redemption of Preferred Stock............................................... (100)
Short-Term Debt............................................................. 89 28 (44)
Dividends................................................................... (258) (259) (242)
--------- --------- ---------
Total Financing Activities................................................ (291) (409) (454)
Other......................................................................... 40 (31) (23)
--------- --------- ---------
Increase (Decrease) in Cash and Cash Equivalents.............................. $ (14) $ 1 $ (45)
--------- --------- ---------
--------- --------- ---------
</TABLE>
CASH FLOWS FROM OPERATING ACTIVITIES
The decrease in cash provided from operating activities to $396 million in
1997 from $638 million in 1996 is primarily due to greater working capital
requirements in 1997. This was caused by actual gas costs incurred being higher
than amounts collected in rates and resulted in undercollected regulatory
balancing accounts at year-end 1997.
15
<PAGE>
The decrease in cash provided from operating activities to $638 million in
1996 from $663 million in 1995 is primarily due to lower noncore revenues and
lower amounts received from undercollected regulatory balancing accounts
partially offset by the favorable settlement of gas contract issues.
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>
YEAR ENDED DECEMBER 31
-------------------------------
CAPITAL EXPENDITURES 1997 1996 1995
- -------------------------------------------------------------------------------- --------- --------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Distribution.................................................................... $ 110 $ 124 $ 126
Transmission.................................................................... 14 24 19
Storage......................................................................... 10 5 19
Other........................................................................... 25 44 67
--------- --------- ---------
Total......................................................................... $ 159 $ 197 $ 231
--------- --------- ---------
--------- --------- ---------
</TABLE>
Capital expenditures for 1997 are $38 million lower than 1996, which is
primarily related to the customer information system completed in early 1996 and
other nonrecurring computer system expenditures in 1996.
Capital expenditures for 1996 are $34 million lower than 1995, which is
primarily due to the completion in early 1996 of a new customer information
system which increased the Company's responsiveness to customer needs and
reduced operating costs and less capital required for repairs to earthquake-
damaged storage facilities during 1995.
Capital expenditures are estimated to be approximately $180 million in 1998
and will be financed primarily by internally generated funds.
CASH FLOWS FROM FINANCING ACTIVITIES
Cash flow used for financing activities decreased $118 million in 1997
compared to 1996. The decrease was primarily due to the redemption of preferred
stock in 1996.
Cash flow for financing activities decreased $45 million in 1996 compared to
1995. The decrease is due to an increase in long- and short-term debt partially
offset by the redemption of preferred stock.
LONG-TERM DEBT
In 1997, cash was used for the repayment of $96 million of debt issued to
finance the Comprehensive Settlement (see Note 3 of Notes to Consolidated
Financial Statements) and repayment of $125 million First Mortgage Bonds. This
was partially offset by the issuance of $120 million in Medium Term Notes and
short-term borrowings used to finance working capital requirements.
16
<PAGE>
In 1996, cash was used for a $67 million redemption of the Swiss Franc
Bonds, and repayment of $79 million of debt issued to finance the Comprehensive
Settlement. This was partially offset by cash provided from the issuance of $75
million in Medium Term Notes.
Cash was used in 1995 primarily for the repayment of short- and long-term
debt, including $65 million of debt related to the Comprehensive Settlement.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents are $0, $14 million, and $13 million at December
31, 1997, 1996 and 1995, respectively. The Company anticipates that cash
required in 1998 for capital expenditures, dividends and debt payments will be
provided by cash generated from operating activities and existing cash balances.
In addition to cash from ongoing operations, the Parent and the Company have
available certain multi-year credit agreements that provide backing for the
Company's commercial paper program. At December 31, 1997, all bank lines of
credit were unused. (For further discussion see Note 7 of Notes to Consolidated
Financial Statements.)
COMPANY OPERATIONS
To fully understand the operations and financial results of the Company it
is important to understand the ratemaking procedures that the Company is
required to follow.
RATEMAKING PROCEDURES
The Company is regulated by the CPUC. It is the responsibility of the CPUC
to determine that utilities operate in the best interest of their customers and
have the opportunity to earn a reasonable return on investment.
On July 16, 1997, the CPUC issued its final decision on the Company's
application for PBR, which was filed with the CPUC in 1995.
PBR replaces the general rate case procedure and certain other regulatory
proceedings through December 31, 2002. Under ratemaking procedures in effect
prior to the PBR decision, the Company typically filed a general rate case with
the CPUC every three years. In a general rate case, the CPUC established a base
margin, which is the amount of revenue to be collected from customers to recover
authorized operating expenses (other than the cost of gas), depreciation, taxes
and return on rate base.
Under PBR, regulators allow future income potential to be tied to achieving
or exceeding specific performance and productivity measures, rather than relying
solely on expanding utility rate base in a market where the Company already has
a highly developed infrastructure. Key elements of the PBR include a reduction
in base rates, an indexing mechanism that limits future rate increases to the
inflation rate less a productivity factor, a sharing mechanism with customers if
earnings exceed the authorized rate of return on rate base and rate refunds to
customers if service quality deteriorates. The change in regulatory oversight
changes the way earnings are affected by various factors. For example, under PBR
earnings are more dependent on operational efficiencies and less on investment
in property, plant and equipment.
PBR retains the balancing account mechanism by which the Company refunds or
collects in the future the difference between actual core revenue and the
amounts authorized by the CPUC to be received in a rate case or other regulatory
proceedings. 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.
17
<PAGE>
The Commission's PBR decision established the following rules for the
Company:
- The decision ordered a net rate reduction of $164 million to an initial
base margin of $1.3 billion. The $164 million is comprised of a rate
reduction of $191 million, effective August 1, 1997, partially offset by a
$27 million rate increase to reflect inflation and customer growth
effective on January 1, 1998.
- Earnings up to 25 basis points exceeding the authorized rate of return on
rate base are retained 100% by shareholders. Earnings that exceed the
authorized rate of return on rate base by greater than 25 basis points are
shared between customers and shareholders on a sliding scale that begins
with 75% of earnings being given back to customers and declining to 0% as
earned returns approach 300 basis points above authorized amounts.
However, the decision rejects sharing of any amount by which actual
earnings may fall below the authorized rate of return. In 1998, the
Company is authorized to earn a 9.49% return on rate base.
- Revenue or margin per customer is indexed based on inflation less an
estimated productivity factor of 2.1% in the first year, increasing 0.1%
per year up to 2.5% in the fifth year. This factor includes 1% to
approximate the projected impact of declining rate base.
- The CPUC decision allows for pricing flexibility for residential and small
commercial customers, with any shortfalls being borne by shareholders and
with gains shared between shareholders and ratepayers.
- The decision allows the Company to continue offering some types of
products and services it currently offers (e.g. contract meter reading),
but the issue of other new product and service offerings was addressed in
the CPUC's Affiliate Transaction Decision. For further discussion see Note
3 of Notes to Consolidated Financial Statements.
The Company implemented the base margin reduction on August 1, 1997, and
implemented the remaining PBR elements on January 1, 1998. The CPUC intends for
its PBR decision to be in effect for five years. The CPUC decision also provides
the possibility that changes to the PBR mechanism could be adopted in a decision
to be issued in the Company's 1998 Biennial Cost Allocation Proceeding (BCAP)
application anticipated to become effective on August 1, 1999.
BCAP adjusts rates to reflect variances in core customer demand from
estimates adopted previously. The mechanism substantially eliminates the effect
on core income of variances in core market demand and gas costs subject to the
limitations of the Gas Cost Incentive Mechanism (GCIM) and the Comprehensive
Settlement. BCAP will continue under PBR. For further discussion, see Note 3 of
Notes to Consolidated Financial Statements.
The GCIM 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. The mechanism
permits full recovery of all costs within a "tolerance band" above and below the
benchmark price and refunds all savings within a "tolerance band" below the
benchmark price. The costs of purchases or savings outside the "tolerance band"
are shared equally between customers and shareholders. The GCIM is authorized by
the CPUC to be in effect through March 31, 1999.
In June 1997, the CPUC approved a $3.2 million pre-tax shareholder award for
the GCIM year ended March 31, 1996, which was recognized as income in 1997. Also
in June 1997, the Company filed an application with the CPUC requesting a
shareholder award for the annual period ending March 31, 1997. The CPUC is
expected to issue a final decision on this matter by mid-1998, and income
associated with this award will be recognized at that time.
18
<PAGE>
1995 - 1997 FINANCIAL RESULTS
Key financial and operating data for the Company are highlighted in the
table below.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1997 1996 1995
--------- --------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Operating revenues................................................................... $ 2,641 $ 2,422 $ 2,279
Cost of gas distributed.............................................................. $ 1,088 $ 923 $ 737
Operation and maintenance............................................................ $ 712 $ 725 $ 760
Net income (after preferred dividends)............................................... $ 231 $ 193 $ 203
Authorized return on rate base....................................................... 9.49% 9.42% 9.67%
Authorized return on common equity................................................... 11.60% 11.60% 12.00%
Weighted average rate base........................................................... $ 2,734 $ 2,777 $ 2,766
</TABLE>
1997 COMPARED TO 1996. The Company's operating revenues increased $219
million in 1997 compared to 1996 primarily due to an increase in the average
unit cost of gas which is recoverable in rates. To a lesser extent, the increase
was also due to increased throughput to UEG customers due to increased demand
for electricity.
The Company's cost of gas distributed increased $165 million in 1997
compared to 1996 largely due to an increase in the average commodity cost of gas
purchased by the Company, excluding fixed pipeline charges, to $2.58 per
thousand cubic feet compared to $1.88 per thousand cubic feet in 1996.
The Company's operation and maintenance expenses decreased $13 million in
1997 compared to 1996 because of its continued emphasis on reducing costs. The
extent of this reduction was partially offset by reduced costs in 1996 from
favorable litigation settlements.
Net income increased $38 million in 1997 compared to 1996 primarily due to
increased throughput to UEG customers, lower operation and maintenance expenses
than amounts authorized in rates, and a nonrecurring non-cash charge of $26.6
million, after-tax, in 1996 partially offset by a lower margin established in
the PBR decision. The non-cash charge of $26.6 million in 1996 was the result of
continuing developments in the CPUC's restructuring of the electricity utility
industry. The charge was needed because the Company anticipated that throughput
to noncore UEG customers would be below the levels projected in 1993 at the time
of the Comprehensive Settlement (See Note 3 of Notes to Consolidated Financial
Statements). Consequently, the Company believed it would not realize the
remaining revenue enhancements that were applied to offset the costs of the
Comprehensive Settlement. In connection with the 1992 quasi-reorganization, the
Parent established a liability for this issue and therefore this charge had no
effect on Pacific Enterprises' consolidated net income.
1996 COMPARED TO 1995. The Company's operating revenues increased $143
million in 1996 compared to 1995 primarily due to an increase in the average
unit cost of gas. Gas costs are recoverable in revenues subject to the GCIM. The
increase in revenue was also generated by demand from refinery customers who
required 21 Bcf more gas in 1996 than in 1995. The increase in revenue was
partially offset by a decrease in UEG revenues due to a reduction in volumes
transported because of abundant inexpensive hydro-electricity.
The Company's cost of gas distributed increased $186 million in 1996 due
primarily to an increase in the average unit cost of gas. The average commodity
cost of gas purchased by the Company, excluding fixed charges for 1996, was
$1.88 per thousand cubic feet, compared to $1.42 per thousand cubic feet in
1995.
19
<PAGE>
The Company's operation and maintenance expenses decreased $35 million in
1996 compared to 1995. The decrease primarily reflects savings resulting from
the Company's continued improvements in efficiency and management's close
control of expenses and nonrecurring favorable settlements, totaling $28
million. One settlement was from gas producers for damages incurred to customer
and company equipment as a result of impure gas supplies, and the other reflects
the resolution of certain environmental insurance claims.
Net income (after preferred dividends) was $193 million in 1996 compared to
$203 million in 1995. The decline in the Company's earnings was primarily due to
a nonrecurring non-cash charge of $26.6 million, partially offset by the effects
of the nonrecurring favorable settlements and lower operating costs.
ACHIEVED AND AUTHORIZED RATE OF RETURN. The Company has achieved or
exceeded the rate of return on rate base authorized by the CPUC for 15
consecutive years. In 1997, the Company achieved a 11.62% return on rate base
compared to a 9.49% authorized return and a 16.74% return on equity compared to
a 11.60% authorized return. The improved returns were primarily due to lower
operating costs as a result of increased operating efficiencies.
In 1996, the Company achieved a 10.31% return on rate base compared to a
9.42% authorized return and a 13.59% return on equity compared to a 11.60%
authorized return. The improved returns were primarily due to lower operating
costs as a result of increased operating efficiencies and the favorable
settlements.
The Company plans to continue efforts to control costs in 1998. In 1998, the
Company is authorized to earn 9.49% return on rate base and 11.60% on common
equity, which is unchanged from 1997.
20
<PAGE>
OPERATING RESULTS
The table below summarizes the components of the Company's throughput and
rates charged to customers for the past three years. Rates include the customer
portion of the Comprehensive Settlement (See Note 3 of Notes to Consolidated
Financial Statements.) The amount included in rates for 1997, 1996 and 1995 were
$98 million, $90 million and $84 million, respectively.
<TABLE>
<CAPTION>
TRANSPORTATION
GAS SALES AND EXCHANGE TOTAL
-------------------- -------------------- --------------------
THROUGHPUT REVENUE THROUGHPUT REVENUE THROUGHPUT REVENUE
---------- ------- ---------- ------- ---------- -------
(DOLLARS IN MILLIONS, VOLUMES IN BILLION CUBIC FEET)
<S> <C> <C> <C> <C> <C> <C>
1997:
Residential............................................... 237 $1,726 3 $ 10 240 $1,736
Commercial/Industrial..................................... 80 502 314 255 394 757
Utility Electric Generation............................... 158 76 158 76
Wholesale................................................. 138 67 138 67
--- ------- --- ------- --- -------
Total in Rates............................................ 317 $2,228 613 $ 408 930 2,636
Balancing and Other....................................... 5
-------
Total Operating Revenues................................ $2,641
-------
-------
1996:
Residential............................................... 233 $1,603 3 $ 10 236 $1,613
Commercial/Industrial..................................... 82 473 297 236 379 709
Utility Electric Generation............................... 139 70 139 70
Wholesale................................................. 130 70 130 70
--- ------- --- ------- --- -------
Total in Rates............................................ 315 $2,076 569 $ 386 884 2,462
Balancing and Other....................................... (40)
-------
Total Operating Revenues................................ $2,422
-------
-------
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
-------
-------
</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.
Throughput, the total gas sales and transportation volumes moved through the
Company's system, increased in 1997 compared to 1996, primarily because of
higher demand for electricity from gas-fired electric generation and less
availability of hydro-electricity. The decrease in throughput in 1996 compared
to 1995 was a result of abundant inexpensive hydro-electricity resulting from
high levels of precipitation last winter reducing the gas demands of UEG
customers.
FACTORS INFLUENCING FUTURE FINANCIAL PERFORMANCE
Because of the ratemaking and regulatory process, electric and gas industry
restructurings and the changing energy marketplace, there are several factors
that will influence future financial performance of the Company. These factors
are summarized below.
21
<PAGE>
PERFORMANCE BASED REGULATION. PBR became effective on January 1, 1998,
except for a base margin reduction of $191 million which was effective August 1,
1997. Under PBR, regulators allow future income potential to be tied to
achieving or exceeding specific performance and productivity measures, rather
than relying solely on expanding utility rate base. The Company continues to
meet all criteria for continued application of Statement of Financial Accounting
Standards No. 71, "Accounting for the Effects of Certain Types of Regulation."
See Note 2 of Notes to Consolidated Financial Statements.
AFFILIATE TRANSACTION DECISION. On December 16, 1997, the CPUC adopted
rules establishing uniform standards of conduct governing the manner in which
California investor-owned utilities conduct business with their affiliates
providing energy or energy-related services within California. The objective of
these rules, which were effective January 1, 1998, is to ensure that the
utilities' energy affiliates do not gain an unfair advantage over other
competitors in the marketplace and that utility customers do not subsidize
affiliate activities. For further discussion of the key elements of the CPUC
decision, see Note 3 of the Notes to Consolidated Financial Statements.
Utility-to-utility transactions are also included under the definition of an
affiliate transaction unless the rules are modified in a subsequent merger or
other regulatory proceeding. On January 23, 1998, at the request of the
Administrative Law Judge presiding over the Parent/Enova merger proceeding, the
Parent and Enova jointly filed their comments regarding the impact of the
Affiliate Transaction Decision on the original estimate of merger synergy
savings. The filing indicated that the Affiliate Transaction rules, if applied
to utility-to-utility transactions, would significantly reduce the anticipated
synergy savings previously discussed in the "Introduction." The CPUC will
consider this issue as part of the Parent/Enova merger proceeding.
ALLOWED RATE OF RETURN. For 1998, the Company is authorized to earn a rate
of return on rate base of 9.49% and a rate of return on common equity of 11.6%,
which is unchanged from 1997.
MANAGEMENT CONTROL OF EXPENSES AND INVESTMENT. Over the past 15 years,
management has been able to control operating expenses and investment within the
amounts authorized to be collected in rates.
It is the intent of management to control operating expenses and investment
within the amounts authorized to be collected in rates in the PBR decision. The
Company intends to make the efficiency improvements, changes in operations and
cost reductions necessary to achieve this objective and earn its authorized rate
of return. However, in view of the earnings sharing mechanism and other elements
of the PBR authorized by the CPUC, it will be more difficult for the Company to
achieve returns in excess of authorized returns at levels that it has
experienced in 1997 and other recent years.
ELECTRIC INDUSTRY RESTRUCTURING. As a result of electric industry
restructuring, natural gas-generated electricity within the Company's service
area competes vigorously with electric power generated throughout the western
United States.
Effective March 31, 1998, California consumers are scheduled to be given the
option of selecting their electric energy provider from a variety of local and
out-of-state producers. The implementation of electric industry restructuring
has no direct impact on the Company's operations. However, future volumes of
natural gas transported for current utility electric generation customers may be
adversely affected to the extent these regulatory changes divert electricity
generated from the Company's service territory. In addition, the electric
industry restructuring has set a mandated 10% reduction of electric rates to
core customers as of January 1, 1998; however, electricity is unlikely to
overcome the entire cost advantage of natural gas for existing uses.
The Company has considered the effect of Statement of Financial Accounting
Standard No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" on the Company's financial statements,
including the potential effect of electric industry restructuring. Although the
Company believes that the volume of gas transported by the Company may be
adversely
22
<PAGE>
impacted by electric industry restructuring, it is not anticipated to result in
an impairment of assets as defined in SFAS 121, because the expected
undiscounted future cash flows from the Company's investment in its gas
transportation infrastructure is greater than its carrying amount.
GAS INDUSTRY RESTRUCTURING. The gas industry experienced an initial phase
of restructuring during the 1980's by deregulating gas sales to noncore
customers. On January 21, 1998, the CPUC released a staff report initiating a
project to assess the current market and regulatory framework for California's
natural gas industry. The general goals of the plan are to consider reforms to
the current regulatory framework emphasizing market-oriented policies benefiting
California natural gas consumers.
NONCORE BYPASS. The Company's throughput to enhanced oil recovery (EOR)
customers in the Kern County area has decreased significantly since 1992 because
of the bypass of the Company's system by competing interstate pipelines. The
decrease in revenues from EOR customers did not have a material impact on the
Company's earnings.
Bypass of other markets also may occur, and the Company is fully at risk for
a reduction in non-EOR, noncore volumes due to bypass. However, significant
additional bypass would require construction of additional facilities by
competing pipelines. The Company is continuing to reduce its costs to maintain
cost competitiveness to retain transportation customers.
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 approved changes in the 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 new 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 may result from external factors such as weather, electric
deregulation, the increased use of hydro-electric power, competing pipeline
bypass of the Company's system and a downturn in general economic conditions. In
addition, many noncore customers are especially sensitive to the price
relationship between natural gas and alternate fuels, as they are capable of
readily switching from one fuel to another, subject to air quality regulations.
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 limited as a
result of the Comprehensive Settlement (see Note 3 of Notes to Consolidated
Financial Statements).
EXCESS INTERSTATE PIPELINE CAPACITY. Existing interstate pipeline capacity
into California exceeds current demand by over one Bcf per day. This situation
has reduced the market value of the capacity well below the Federal Energy
Regulatory Commission's ("FERC") tariffs. The Company has exercised its
step-down option on both the El Paso and Transwestern systems, thereby reducing
its firm interstate capacity obligation from 2.25 Bcf per day to 1.45 Bcf per
day.
FERC-approved settlements have resulted in a reduction in the costs that the
Company may have possibly been required to pay for the capacity released back to
El Paso and Transwestern that cannot be remarketed. Of the remaining 1.45 Bcf
per day of capacity, the Company's core customers use 1.05 Bcf per day at the
full FERC tariff rate. The remaining 0.4 Bcf per day of capacity is marketed at
significant discounts. Under existing regulation in California, unsubscribed
capacity costs associated with the remaining 0.4 Bcf per day are recoverable in
customer rates. While including the unsubscribed pipeline cost in rates may
impact the Company's ability to compete in highly contested markets, the Company
does not believe its inclusion will have a significant impact on volumes
transported or sold.
23
<PAGE>
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
agencies applicable to commercial and industrial customers utilizing natural gas
are not generally required by those using electricity. However, anticipated
advancements in natural gas technologies are expected to enable gas equipment to
remain competitive with alternate energy sources. Environmental laws also
require cleanup 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 matters, see Note 5 of Notes to Consolidated Financial Statements.
UNION CONTRACT. Most field, clerical and technical employees of the Company
are represented by the Utilities Workers' Union of America or the International
Chemical Workers' Union. The existing contract with these employees on wages and
working conditions will expire on March 31, 1999. Terms of the contract allow an
extension through March 31, 2000.
CALIFORNIA ECONOMY. Growth in the Company's markets is largely dependent on
the health and expansion of the southern California economy. The Company added
approximately 43,700 new meters in 1997. This represents a growth rate of
approximately 0.9%. The Company anticipates that customer growth will continue
at 1997 levels. Southern California has finally emerged from its prolonged
recession and job growth in 1997 was stronger than the U.S. average.
OTHER INCOME AND INTEREST EXPENSE
OTHER INCOME AND DEDUCTIONS. Other income-net, which primarily consists of
interest income from short-term investments and interest income on regulatory
accounts receivable balances, was $7 million, $1 million and $6 million in 1997,
1996 and 1995, respectively. The increase from 1996 is primarily due to higher
interest income on regulatory accounts receivable balances in 1997. The decrease
from 1995 is primarily due to unusually high short-term investments in 1995, as
a result of overcollected gas costs that were refunded to customers in the
fourth quarter of 1995. This was partially offset by higher interest income on
regulatory accounts receivable balances in 1996 compared to 1995. Other-net
expense consists primarily of contributions and amortization of loss on
reacquired debt.
INTEREST EXPENSE. Interest expense was $87 million, $86 million and $91
million in 1997, 1996 and 1995, respectively. Interest expense for 1997
increased only slightly compared to 1996. Interest expense in 1996 was reduced
from the 1995 level as a result of the lower long-term debt balance maintained
throughout the year, the redemption of $67 million Swiss Franc bonds and
refinancing of Company debt at lower interest rates.
RISK MANAGEMENT
Market risk generally represents the risk of loss that may result from the
potential change in the value of a financial instrument as a result of
fluctuations in interest and currency exchange rates and equity and commodity
prices. Market risk is inherent to both derivative and non-derivative financial
instruments. The following is a discussion of the Company's primary market risk
exposures as of December 31, 1997, including a discussion of how these exposures
are managed.
INTEREST RATE RISK. The Company has historically funded its operations
through long-term bond issues with fixed interest rates. With the restructuring
of the regulatory process, greater flexibility has been permitted within the
debt management process. As a result, recent debt offerings have been selected
with short-term maturities. The Company also evaluates the use of a combination
of fixed and floating rate debt. Interest rate swaps, subject to regulatory
constraints, may be used to adjust interest rate exposures when appropriate,
based upon market conditions.
24
<PAGE>
A portion of the Company's borrowings are denominated in foreign currencies,
which exposes the Company to market risk associated with exchange rate
movements. The Company's policy generally is to hedge major foreign currency
cash exposures through swap transactions. These contracts are entered into with
major international banks thereby minimizing the risk of credit loss.
The Company employes a variance/covariance approach in its calculation of
Value at Risk (VaR), which measures the potential losses in fair value or
earnings that could arise from changes in market conditions, using a 95%
confidence level and assuming a one-year holding period. VaR is a statistical
measure that takes into consideration historical volatilities and correlations
of market data (i.e., interest rates and currency exchange rates). The VaR,
which is the potential loss in fair value of long-term debt sensitive to changes
in interest rates, is estimated at $116 million as of December 31, 1997. The
total VaR is attributable to debt obligations with fixed interest rates. The VaR
attributable to currency exchange rates nets to zero as a result of a currency
swap which is directly matched to the Company's Swiss Franc debt obligation.
NATURAL GAS PRICE RISK. The Company is subject to price risk on its natural
gas purchases if its cost exceeds a 2% tolerance band above the GCIM benchmark
price. Price risk is influenced by physical contract positions, financial
contract positions, basis risk, system demand, and regulation. The Company
becomes subject to price risk when positions are incurred during the buying,
selling, and storage of natural gas.
A Gas Acquisition Committee, composed of officers of the Company and Pacific
Enterprises, is responsible for establishing natural gas price risk management
objectives and strategies that are consistent with the Price Risk Management
Policy. The Committee also monitors results of all natural gas purchasing
activities to ensure that such activities are effective and conducted in a
manner consistent with approved policies and procedures.
As part of the Price Risk Management Policy, the Company has established
fixed price and basis position limits. Volumetric limits define the maximum
position exposure each management level within the Company is authorized to
accept without obtaining higher approval.
In addition to the position limits, internal controls are in place to set
individual contract limits, monitor established credit limits, require current
reporting of trading activities and ensure proper segregation of duties.
The Company monitors and controls credit exposure through a credit approval
process and the assignment and monitoring of credit limits. Credit exposure is
defined as the "balance owed" to the Company on current market valuation. Credit
exposure represents the positive contract value that might be forfeited in the
event of counterparty default. Credit exposure is computed on a daily
mark-to-market basis. The current credit exposure and credit limit of each
supplier is monitored on an ongoing basis and reported weekly to the Company's
management and the Parent's Treasury Department.
The VaR methodology employed by the Company with respect to natural gas
price risk is applied to physical, as well as financial, natural gas positions.
The methodology involves determining the fair value impact of the maximum
expected adverse price change for the aggregate net position in each forward
month, using a 95% confidence level and assuming a one month holding period. The
value derived for each forward month is then aggregated to arrive at the total
VaR. In making these calculations, volatilities are based upon the respective
forward month's implied volatility derived from quoted option prices. As of
December 31, 1997, the total VaR of the Company's natural gas positions was not
material to the Company's financial position.
YEAR 2000
In 1997, the Company began a multi-year project to modify its computer
systems as necessary to ensure continued effective operations in the year 2000
and beyond. The initial focus of the project is on the
25
<PAGE>
systems key to customer safety, gas operations, external reporting, and billing
and collection processes. The project is expected to be completed in the spring
of 1999. During 1997, the Company incurred expenses of $10 million on the
project, and expects to spend approximately $27 million over the life of the
project. An assessment of the readiness of external entities which the Company
interfaces with, such as vendors, customers and others, is ongoing.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information required by this item is set forth under "Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations--Risk
Management."
26
<PAGE>
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
STATEMENT OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1997 1996 1995
--------- --------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
OPERATING REVENUES................................................................... $ 2,641 $ 2,422 $ 2,279
--------- --------- ---------
OPERATING EXPENSES
Cost of Gas Distributed.............................................................. 1,088 923 737
Operation............................................................................ 640 643 673
Maintenance.......................................................................... 72 82 87
Depreciation......................................................................... 251 248 237
Income Taxes......................................................................... 174 145 151
Local Franchise Payments............................................................. 36 34 34
Ad Valorem Taxes..................................................................... 35 35 34
Payroll and Other Taxes.............................................................. 27 26 26
--------- --------- ---------
Total.............................................................................. 2,323 2,136 1,979
--------- --------- ---------
Net operating revenue.............................................................. 318 286 300
--------- --------- ---------
OTHER INCOME AND (DEDUCTIONS)
Interest Income...................................................................... 1 1 8
Regulatory Interest.................................................................. 15 4 1
Allowance for Equity Funds Used During Construction.................................. 2 4 5
Income Taxes on Non-Operating Income................................................. (4) (3)
Other--Net........................................................................... (7) (5) (8)
--------- --------- ---------
Total.............................................................................. 7 1 6
--------- --------- ---------
INTEREST CHARGES AND (CREDITS)
Interest on Long-Term Debt........................................................... 82 80 87
Other Interest....................................................................... 6 8 7
Allowance for Borrowed Funds Used During Construction................................ (1) (2) (3)
--------- --------- ---------
Total.............................................................................. 87 86 91
--------- --------- ---------
Net Income........................................................................... 238 201 215
Dividends on Preferred Stock......................................................... 7 8 12
--------- --------- ---------
Net Income Applicable to Common Stock................................................ $ 231 $ 193 $ 203
--------- --------- ---------
--------- --------- ---------
</TABLE>
See Notes To Consolidated Financial Statements.
27
<PAGE>
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
DECEMBER 31
--------------------
1997 1996
--------- ---------
(DOLLARS IN
MILLIONS)
<S> <C> <C>
ASSETS
Utility Plant--at original cost............................................................. $ 5,978 $ 5,963
Less: Accumulated Depreciation.............................................................. 2,904 2,795
--------- ---------
Utility plant--net........................................................................ 3,074 3,168
--------- ---------
Current Assets:
Cash and cash equivalents................................................................. 14
Accounts receivable--trade (less allowance for doubtful
receivables of $17 in 1997 and $16 in 1996)............................................. 499 413
Regulatory accounts receivable--net....................................................... 355 296
Income taxes receivable................................................................... 11
Deferred income taxes..................................................................... 11 22
Gas in storage............................................................................ 25 28
Materials and supplies.................................................................... 13 13
Prepaid expenses.......................................................................... 14 13
--------- ---------
Total current assets.................................................................. 917 810
--------- ---------
Regulatory Assets........................................................................... 214 376
--------- ---------
Total................................................................................. $ 4,205 $ 4,354
--------- ---------
--------- ---------
CAPITALIZATION AND LIABILITIES
Capitalization:
Common equity:
Common stock $ 835 $ 835
Retained earnings....................................................................... 535 555
--------- ---------
Total common equity................................................................... 1,370 1,390
Preferred stock........................................................................... 97 97
Long-term debt............................................................................ 968 1,090
--------- ---------
Total capitalization.................................................................. 2,435 2,577
--------- ---------
Current Liabilities:
Short-term debt........................................................................... 351 262
Accounts payable--trade................................................................... 119 178
Accounts payable--affiliates.............................................................. 30 44
Accounts payable--other................................................................... 268 296
Other taxes payable....................................................................... 30 28
Accrued income taxes...................................................................... 39
Long-term debt due within one year........................................................ 147 147
Accrued interest.......................................................................... 52 41
Other accrued liabilities................................................................. 78 63
--------- ---------
Total current liabilities............................................................. 1,114 1,059
--------- ---------
Customer Advances for Construction.......................................................... 34 42
Deferred Income Taxes....................................................................... 373 405
Deferred Investment Tax Credits............................................................. 61 64
Other Deferred Credits...................................................................... 188 207
Commitments and Contingent Liabilities (Note 5)
--------- ---------
Total................................................................................. $ 4,205 $ 4,354
--------- ---------
--------- ---------
</TABLE>
See Notes To Consolidated Financial Statements.
28
<PAGE>
STATEMENT OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1997 1996 1995
--------- --------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income.............................................................................. $ 238 $ 201 $ 215
Items Not Requiring Cash:
Depreciation.......................................................................... 251 248 237
Deferred income taxes................................................................. (15) 15 60
Deferred investment tax credits....................................................... (3) (3) (3)
Allowance for funds used during construction.......................................... (4) (6) (9)
Other................................................................................. (21) 24 53
Net Change in Other Working Capital Components:
Accounts receivable................................................................... (86) (14) 125
Regulatory accounts receivable........................................................ 36 50 184
Gas in storage........................................................................ 3 27 9
Other current assets.................................................................. (1) 20 13
Accounts payable...................................................................... (101) 90 (16)
Other taxes payable................................................................... 51 (18) (72)
Deferred income taxes................................................................. 21 (6) (76)
Other current liabilities............................................................. 27 10 (57)
--------- --------- ---------
Net cash provided by operating activities........................................... 396 638 663
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital Expenditures for Utility Plant.................................................. (159) (197) (231)
(Increase) Decrease in Other Assets--Net................................................ 40 (31) (23)
--------- --------- ---------
Net cash used in investing activities............................................... (119) (228) (254)
--------- --------- ---------
CASH FLOWS FROM FINANCING ACTIVITIES:
Dividends............................................................................... (258) (259) (242)
Issuance of Long-Term Debt.............................................................. 120 75
Payments of Long-Term Debt.............................................................. (242) (153) (168)
Redemption of Preferred Stock........................................................... (100)
Increase (Decrease) in Short-Term Debt.................................................. 89 28 (44)
--------- --------- ---------
Net cash used in financing activities............................................... (291) (409) (454)
--------- --------- ---------
Increase (Decrease) in Cash and Cash Equivalents........................................ (14) 1 (45)
Cash and Cash Equivalents--January 1.................................................... 14 13 58
--------- --------- ---------
Cash and Cash Equivalents--December 31.................................................. $ $ 14 $ 13
--------- --------- ---------
SUPPLEMENTAL DISCLOSURE OF
CASH FLOW INFORMATION:
Cash Paid During the Year for:
Interest (net of amount capitalized).................................................. $ 75 $ 85 $ 82
--------- --------- ---------
--------- --------- ---------
Income taxes.......................................................................... $ 132 $ 127 $ 232
--------- --------- ---------
--------- --------- ---------
</TABLE>
See Notes To Consolidated Financial Statements.
29
<PAGE>
STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
PREFERRED COMMON RETAINED
STOCK STOCK EARNINGS
----------- ----------- -----------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
BALANCE AT DECEMBER 31, 1994...................................................... $ 197 $ 835 $ 643
Net Income........................................................................ 215
Cash Dividends Declared:
Preferred stock................................................................. (12)
Common stock.................................................................... (233)
----- ----- -----
BALANCE AT DECEMBER 31, 1995...................................................... 197 835 613
Net Income........................................................................ 201
Cash Dividends Declared:
Preferred stock................................................................. (8)
Common stock.................................................................... (251)
Preferred Stock Redeemed (1000 shares)............................................ (100)
----- ----- -----
BALANCE AT DECEMBER 31, 1996...................................................... 97 835 555
Net Income........................................................................ 238
Cash Dividends Declared:
Preferred stock................................................................. (7)
Common stock.................................................................... (251)
----- ----- -----
BALANCE AT DECEMBER 31, 1997...................................................... $ 97 $ 835 $ 535
----- ----- -----
----- ----- -----
</TABLE>
The number of shares of preferred stock and common stock authorized and
outstanding at December 31, 1997 and 1996, is set forth in Note 10 of Notes to
Consolidated Financial Statements.
See Notes To Consolidated Financial Statements.
30
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. MERGER AGREEMENT WITH ENOVA CORPORATION
On October 14, 1996, Pacific Enterprises (Parent) and Enova Corporation
(Enova), the parent company of San Diego Gas & Electric (SDG&E), announced an
agreement, which both Boards of Directors unanimously approved, for the
combination of the two companies in a tax-free, strategic merger of equals to be
accounted for as a pooling of interests. The combination was approved by the
shareholders of both companies on March 11, 1997. On December 16, 1997, the
Parent and Enova announced that the name of the new company will be Sempra
Energy.
As a result of the combination, the Parent and Enova will become
subsidiaries of Sempra Energy and their common shareholders will become common
shareholders of the new holding company. Pacific Enterprises' common
shareholders will receive 1.5038 shares of Sempra Energy's common stock for each
share of the Parent's common stock, and Enova common shareholders will receive
one share of Sempra Energy's common stock for each share of Enova common stock.
Preferred stock of Pacific Enterprises, SoCalGas, and SDG&E will remain
outstanding.
The merger is subject to approval by certain governmental and regulatory
agencies including the California Public Utilities Commission (CPUC), the
Securities and Exchange Commission and Federal Energy Regulatory Commission
(FERC) and the expiration of the waiting period under the Hart-Scott-Rodino
Antitrust Improvements Act. Approval of the merger and commencement of
operations is expected to occur during the summer of 1998.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Southern California Gas Company (the Company) is a subsidiary of Pacific
Enterprises. 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 1997 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 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, 1997, the Company had $214 million of regulatory assets which
included the following: costs of reacquiring debt--$43 million; deferred income
taxes--$66 million (see Note 4); environmental remediation--$72 million (see
Note 5); and other costs--$33 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.
31
<PAGE>
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 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 method of accounting
for gas in storage inventory had been used by the Company, inventory would have
been higher than reported at December 31, 1997 and 1996 by $75 million and $43
million, respectively. Other inventories are generally stated at the lower of
cost, determined on an average cost basis, or market.
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 its cost. Interest expense of $4 million, $6
million and $9 million in 1997, 1996 and 1995, respectively, 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.
3. REGULATORY MATTERS
The Company is regulated by the CPUC. It is the responsibility of the CPUC
to determine that utilities operate in the best interest of their customers
while providing utilities with the opportunity to earn a reasonable return on
investment.
PERFORMANCE BASED REGULATION
On July 16, 1997, the CPUC issued its final decision on the Company's
application for performance based regulation (PBR), which was filed with the
CPUC in 1995.
PBR replaces the general rate case and certain other regulatory proceedings
through December 31, 2002. Under PBR, regulators allow future income potential
to be tied to achieving or exceeding specific performance and productivity
measures, rather than relying solely on expanding utility rate base in a market
where the Company already has a highly developed infrastructure. Key elements of
the PBR include a reduction in base rates, an indexing mechanism that limits
future rate increases to the inflation rate less a productivity factor, a
sharing mechanism with customers if earnings exceed the authorized rate
32
<PAGE>
of return on ratebase, and rate refunds to customers if service quality
deteriorates. Specifically, the key elements of PBR include the following:
- The decision required a net rate reduction of $164 million for an initial
base margin of $1.3 billion. The $164 million is comprised of a rate
reduction of $191 million effective August 1, 1997, which is partially
offset by an estimated $27 million rate increase reflecting inflation and
customer growth, effective January 1, 1998.
- Earnings up to 25 basis points exceeding the authorized rate of return on
ratebase are retained 100% by shareholders. Earnings that exceed the
authorized rate of return on rate base by greater than 25 basis points are
shared between customers and shareholders on a sliding scale that begins
with 75% of earnings being given back to customers and declining to 0% as
earned returns approach 300 basis points above authorized amounts.
However, the decision rejects sharing of any amount by which actual
earnings fall below the authorized rate of return. In 1998, the Company is
authorized to earn a 9.49% return on rate base.
- Revenue or margin per customer is indexed based on inflation less an
estimated productivity factor of 2.1% in the first year, increasing 0.1%
per year up to 2.5% in the fifth year. This factor includes 1% to
approximate the projected impact of a declining rate base.
- The CPUC decision allows for pricing flexibility for residential and small
commercial customers, with any shortfalls being borne by shareholders and
with any gains shared between shareholders and customers.
- The decision allows the Company to continue offering some types of
products and services it currently offers (e.g. contract meter reading)
but the issue of other new product and service offerings was addressed in
the CPUC's Affiliate Transaction Decision.
The Company implemented the base margin reduction effective August 1, 1997,
and all other PBR elements on January 1, 1998. The CPUC intends the PBR decision
to be in effect for five years; however, the CPUC decision allows for the
possibility that changes to the PBR mechanism could be adopted in a decision to
be issued in the Company's 1998 Biennial Cost Allocation Proceeding (BCAP)
application which is anticipated to become effective August 1, 1999.
Under PBR, annual cost of capital proceedings are replaced by an automatic
adjustment mechanism if changes in certain indices exceed established
tolerances. The mechanism is triggered if actual interest rates increase or
decrease by more that 150 basis points and are forecasted to vary by at least
150 basis points for the next year. If this occurs, there would be an automatic
adjustment of rates for the change in the cost of capital according to a
pre-established formula which applies a percentage of the change to various
capital components.
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
33
<PAGE>
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 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 result of the Comprehensive Settlement.
34
<PAGE>
- 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 April 1, 1994, the Company implemented a
new process for evaluating the Company's gas purchases, substantially
replacing the previous process of reasonableness reviews. Initially a
three-year pilot program, the CPUC recently extended the Gas Cost Incentive
Mechanism (GCIM) program through March 31, 1999.
GCIM 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 mechanism permits full recovery of all costs within a
"tolerance band" above the benchmark price and refunds all savings within a
"tolerance band" below the benchmark price. The costs of purchases or
savings outside the "tolerance band" are shared equally between customers
and shareholders.
The CPUC approved the use of gas futures for managing risk associated with
the GCIM. The Company enters into gas futures contracts in the open market
on a limited basis to mitigate risk and better manage gas costs.
Since the Company's purchase gas costs were below the specified GCIM
benchmark for the annual period ended March 1996, the CPUC, in June 1997,
approved a $3.2 million pre-tax award to shareholders under the procurement
portion of the incentive mechanism. This $3.2 million award was recognized
as income in the second quarter of 1997.
In June 1997, the Company filed its annual GCIM application with the CPUC
requesting an award of $10.8 million, pre-tax, for the annual period ended
March 31, 1997. The CPUC is expected to issue a final decision on this
matter by mid-1998, at which time the approved award will be recognized as
income.
- ATTRITION ALLOWANCES. The Comprehensive Settlement authorized the Company
an annual allowance for increases in operating and maintenance expenses.
In 1996, attrition was calculated on the inflation rate in excess of 3%
authorizing the Company to collect $12 million in rates. No attrition
allowance was authorized for 1997 based on an agreement reached as part of
the PBR application.
The Company recorded the impact of the Comprehensive Settlement in 1993.
Upon giving effect to liabilities previously recognized by the Company, the
costs of the Comprehensive Settlement, including the restructuring of gas supply
contracts, did not result in any additional charge to the Parent's consolidated
earnings.
BCAP
In the second quarter of 1997, the CPUC issued a decision on the Company's
1996 BCAP filing. The CPUC decision extends the recovery period of approximately
$20 million in noncore costs, resulting in a noncore rate decrease and leaves in
place the existing residential rate structure. The decision did not adopt the
Company's proposal to increase flexibility in offering discounts to utility
electric generating customers to retain load or prevent bypass. The Company
implemented the new rates and core residential monthly gas pricing on June 1,
1997.
The BCAP substantially eliminates the effect on core income of variances in
core market demand and gas costs subject to the limitations of the GCIM and the
Comprehensive Settlement. The CPUC's PBR decision indicates that it will address
issues such as throughput forecast, cost allocation, rate design and other
matters which may arise from the Company's PBR experience during the 1998 BCAP.
35
<PAGE>
TRANSACTIONS BETWEEN UTILITY AND AFFILIATED COMPANIES
On December 16, 1997, the CPUC adopted rules, effective January 1, 1998,
establishing uniform standards of conduct governing the manner in which
California investor-owned utilities conduct business with their energy-related
affiliates (Energy Affiliates). The objective of the Affiliate Transaction rules
is to ensure that utility affiliates do not gain an unfair advantage over other
competitors in the marketplace and that utility customers do not subsidize
affiliate activities. The rules establish standards relating to non-
discrimination, disclosure, and information exchange and separation of
activities.
Key elements of the Affiliate Transaction Decision are as follows:
- Allows unregulated affiliates to operate within the utility's service
territory.
- Requires non-discriminatory pricing which mandates that all transactions
between the utility and its Energy Affiliates be tariffed or competitively
bid, excluding permitted corporate support services and certain joint
purchases.
- Allows utilities to share logos with their parent company and their Energy
Affiliates; however, in California, the relationship of the affiliated
companies to the utility must be clearly communicated.
- Prohibits joint marketing activities and joint use of call centers by
utilities and their Energy Affiliates.
- Permits corporate support services (such as corporate oversight,
government support systems, and personnel) to be provided by the utility,
its holding company or a separate affiliate created solely to provide such
services.
- Prohibits utilities from sharing office space, computers and office
equipment with Energy Affiliates, except in connection with providing
corporate support services.
- Eliminates a parent company from the definition of an "affiliate" unless
it is directly involved in marketing energy products or services.
Utility-to-utility transactions are also included under the definition of an
affiliate transaction unless the rules are modified in a subsequent merger or
other regulatory proceeding. On January 23, 1998, at the request of the
Administrative Law Judge presiding over the Parent/Enova merger proceeding, the
Parent and Enova jointly filed their comments regarding the impact of the
Affiliate Transaction Decision on the original estimate of merger synergy
savings. The filing indicated that the Affiliate Transaction rules, if applied
to utility-to-utility transactions, would significantly reduce anticipated
synergy savings previously discussed in Note 1.
As required by the decision, the Company has filed compliance plans with the
CPUC addressing the Parent's implementation of the new rules. In addition, the
Company has filed for exemptions on certain rules as well as petitions for
rehearing which seek revision and clarification on certain aspects of the rules.
36
<PAGE>
4. 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
-------------------------------
1997 1996 1995
--------- --------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Computed statutory federal income tax expense................................... $ 146 $ 122 $ 128
Increase (reductions) resulting from:
Excess book over tax depreciation............................................... 23 23 20
State income taxes--net of federal income tax benefit........................... 26 19 21
Capitalized expenses not deferred............................................... (3) (11) (10)
Amortization of deferred investment tax credits................................. (3) (3) (3)
Resolution of proposed tax deficiency........................................... (6) (4) (3)
Other--net...................................................................... (5) 2 (2)
--------- --------- ---------
Total income tax expense...................................................... $ 178 $ 148 $ 151
--------- --------- ---------
--------- --------- ---------
</TABLE>
The components of income tax expense are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1997 1996 1995
--------- --------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Federal:
Current....................................................................... $ 138 $ 100 $ 119
Deferred...................................................................... 3 18 0
--------- --------- ---------
141 118 119
--------- --------- ---------
State:
Current....................................................................... 38 30 37
Deferred...................................................................... (1) 0 (5)
--------- --------- ---------
37 30 32
--------- --------- ---------
Total:
Current....................................................................... 176 130 156
Deferred...................................................................... 2 18 (5)
--------- --------- ---------
$ 178 $ 148 $ 151
--------- --------- ---------
--------- --------- ---------
</TABLE>
The principal components of net deferred tax liabilities are as follows:
<TABLE>
<CAPTION>
DECEMBER 31
------------------------------------------------------------------------
1997 1996
----------------------------------- -----------------------------------
ASSETS LIABILITIES TOTAL ASSETS LIABILITIES TOTAL
----------- ----------- --------- ----------- ----------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C>
Depreciation............................................ $ (455) $ (455) $ (455) $ (455)
Comprehensive Settlement................................ $ 114 114 $ 134 (47) 87
Regulatory accounts receivable.......................... (161) (161) (132) (132)
Deferred investment tax credits......................... 27 27 28 28
Customer advances for construction...................... 14 14 20 20
Regulatory asset........................................ (11) (11) (24) (24)
Other regulatory........................................ 158 (48) 110 143 (50) 93
----- ----- --------- ----- ----- ---------
Total deferred income tax assets (liabilities)........ $ 313 $ (675) $ (362) $ 325 $ (708) $ (383)
----- ----- --------- ----- ----- ---------
----- ----- --------- ----- ----- ---------
</TABLE>
37
<PAGE>
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, 1997 and 1996, $66 million and $93 million, respectively, of
deferred income taxes have been offset by an equivalent amount in regulatory
assets.
5. 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, 1997, ten of these sites have been
remediated, of which seven have received certification from the California
Environmental Protection Agency. Two sites are in the process of being
remediated. 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 two industrial waste
disposal sites.
In 1994, the CPUC approved a collaborative settlement which provides for
rate recovery of 90% of environmental investigation and remediation costs
without reasonableness reviews. In addition, the Company has the opportunity to
retain a percentage of any insurance recoveries to offset the 10% of costs not
recovered in rates.
At December 31, 1997, the Company's estimated remaining investigation and
remediation liability was $72 million, of which 90% is authorized to be received
through the mechanism discussed above. 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 consolidated results of operations or financial position.
Estimated liabilities for environmental remediation are recorded when
amounts are probable and estimable. Amounts authorized to be recovered in rates
under the mechanism described above are recorded as a regulatory asset. Possible
recoveries of environmental remediation liabilities from third parties are not
deducted from the liability.
LITIGATION
The Company is a defendant in various lawsuits arising in the normal course
of business. The Company believes that the resolution of these pending claims
and legal proceedings will not have a material adverse effect on the Company's
consolidated results of operations or financial position.
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 reservation charge. The Company
recovers such fixed charges in rates. Estimated minimum commitments as of
December 31, 1997 are as follows: 1998--$179 million, 1999--$182 million,
2000--$184 million, 2001--$186 million, 2002--$186 million, after 2002--$635
million.
38
<PAGE>
OTHER COMMITMENTS AND CONTINGENCIES
At December 31, 1997, commitments for capital expenditures were
approximately $16 million.
6. LEASES
The Company has leases on real and personal property expiring at various
dates from 1998 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 $44 million, $45 million and $45
million in 1997, 1996 and 1995, respectively. The following is a schedule of
future minimum operating lease commitments as of December 31, 1997:
<TABLE>
<CAPTION>
FUTURE MINIMUM
LEASE PAYMENTS
---------------------
(DOLLARS IN MILLIONS)
<S> <C>
Year Ending December 31:
1998..................................................................... $ 19
1999..................................................................... 19
2000..................................................................... 18
2001..................................................................... 16
2002..................................................................... 18
Later years.............................................................. 159
-----
Total.................................................................. $ 249
-----
-----
</TABLE>
7. COMPENSATING BALANCES AND SHORT-TERM BORROWING ARRANGEMENTS
The Company has a $650 million multi-year credit agreement requiring annual
fees of .07%. 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 in February 2001. The Company's line of credit provides
backing for its commercial paper program. At December 31, 1997, the bank line of
credit was unused.
At December 31, 1997 and 1996, the Company had $351 million and $358
million, respectively, of commercial paper obligations outstanding.
Approximately $94 million of the outstanding commercial paper relates to the
restructuring costs associated with certain long-term gas supply contracts under
the Comprehensive Settlement (See Note 3). The weighted average annual interest
rate of commercial paper obligations outstanding was 5.78% and 5.36% at December
31, 1997 and 1996, respectively.
At December 31, 1996, the Company classified $96 million of the commercial
paper as long-term debt, since it was the Company's intent to continue to
refinance that portion of the debt on a long-term basis. No commercial paper was
reclassified as long-term debt at December 31, 1997.
39
<PAGE>
8. LONG-TERM DEBT
<TABLE>
<CAPTION>
DECEMBER 31
--------------------
1997 1996
--------- ---------
(DOLLARS IN
MILLIONS)
<S> <C> <C>
FIRST MORTGAGE BONDS:
6 1/2% December 15, 1997..................................................................... $ 125
5 1/4% March 1, 1998......................................................................... $ 100 100
6 7/8% August 15, 2002....................................................................... 100 100
5 3/4% November 15, 2003..................................................................... 100 100
8 3/4% October 1, 2021....................................................................... 150 150
7 3/8% March 1, 2023......................................................................... 100 100
7 1/2% June 15, 2023......................................................................... 125 125
6 7/8% November 1, 2025...................................................................... 175 175
OTHER LONG-TERM DEBT:
5.98% Notes, August 28, 1997................................................................. 22
6.21% Notes, November 1, 1999................................................................ 75 75
6 3/8% Notes, October 29, 2001............................................................... 120
8 3/4% Notes, July 6, 2000................................................................... 30 30
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 47
5.33% Commercial Paper, February 8, 2001..................................................... 96
Other, 6 3/8%, May 14, 2006.................................................................. 8 8
--------- ---------
Total outstanding............................................................................ 1,130 1,253
--------- ---------
Less:
Payments due within one year................................................................. 147 147
Unamortized debt discount less premium....................................................... 15 16
--------- ---------
162 163
--------- ---------
Long-Term Debt................................................................................. $ 968 $ 1,090
--------- ---------
--------- ---------
</TABLE>
The annual principal payment requirements of long-term debt for the years
1998 through 2002 are $147 million, $75 million, $30 million, $120 million and
$100 million, respectively. Substantially all of utility plant serves as
collateral for the First Mortgage Bonds.
CURRENCY RATE SWAPS
In February 1986, the Company issued SFr. 100 million of 5 1/8% bonds
maturing on February 6, 1998. The Company hedged the currency exposure by
entering into a swap transaction with a major international bank. As a result,
the bond issue, interest payments, and other ongoing costs were swapped for
fixed annual payments. The terms of the swap result in a U.S. dollar liability
of $47 million at an interest rate of 9.725%.
9. FINANCIAL INSTRUMENTS
The fair value of a financial instrument is the amount at which the
instrument could be exchanged in a current transaction between willing parties,
other than in a forced sale or liquidation. The amounts disclosed represent
management's best estimates of fair value.
The carrying amounts of financial instruments including cash and cash
equivalents, accounts receivable, accounts payable and short-term debt
approximated fair value as of December 31, 1997 and 1996
40
<PAGE>
because of the relatively short maturity of those instruments. The carrying
amount of the currency swaps approximates fair value.
The fair value of the Company's long-term debt, 6% 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>
1997 1996
---------------------- ----------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
----------- --------- ----------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C>
Long-Term Debt........................................................... $ 1,115 $ 1,159 $ 1,237 $ 1,248
Preferred Stocks......................................................... $ 97 $ 95 $ 97 $ 93
</TABLE>
As a result of the GCIM (See Note 3), 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's policy is to use gas
futures contracts to mitigate risk and better manage gas costs. The CPUC has
approved the use of gas futures for managing risk associated with the GCIM. For
the year ended December 31, 1997, gains or losses from gas futures contracts are
not material to the Company's financial statements.
10. CAPITAL STOCK
The amount of capital stock outstanding at December 31, is as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1997 DECEMBER 31, 1996
------------------------- -------------------------
NUMBER OF MILLIONS OF NUMBER OF MILLIONS OF
SHARES DOLLARS SHARES DOLLARS
------------ ----------- ------------ -----------
<S> <C> <C> <C> <C>
PREFERRED STOCK:
cumulative, voting(a)(b):
6%, $25 par value.......................................... 79,011 $ 3 79,011 $ 3
6%, Series A, $25 par value................................ 783,032 19 783,032 19
Series Preferred, no par value 7 3/4%,
$25 Stated Value(c)...................................... 3,000,000 75 3,000,000 75
----- -----
Total.................................................. $ 97 $ 97
----- -----
----- -----
PREFERENCE STOCK--cumulative, voting, no par value(a)(b).......
COMMON STOCK--no par value(a)(b)............................... 91,300,000 $ 835 91,300,000 $ 835
----- -----
----- -----
</TABLE>
- ------------------------
(a) The Company's Articles of Incorporation authorize the following stocks: 100
million shares of Common Stock without par value; 160,000 shares of 6%
Preferred Stock--$25.00 par value; 840,000 shares of 6% Preferred
Stock--$25.00 par value, Series A; 5 million shares of Series Preferred
Stock without par value and 5 million shares of Preference Stock without par
value.
41
<PAGE>
(b) 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 Preferred Stock and the holders of Common
Stock.
(c) On February 2, 1998, the Company redeemed all outstanding shares of 7 3/4%
Series Preferred Stock at a total price of $25.09. This total price per
share consisted of a redemption price of $25 and $.09 of unpaid dividends
accruing to the date of redemption. The total cost to the Company was
approximately $75.3 million.
11. TRANSACTIONS WITH AFFILIATES
Pacific Interstate Transmission Company, Pacific Interstate Offshore Company
and Pacific Offshore Pipeline Company, subsidiaries of the Parent and gas supply
affiliates of the Company, sell and transport gas to the Company under tariffs
approved by the Federal Energy Regulatory Commission. During 1997, 1996, and
1995, billings for such gas purchases totaled $252 million, $186 million and
$141 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 3).
12. 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.
42
<PAGE>
Pension expense was as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1997 1996 1995
--------- --------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Service cost on benefits earned during the period....................................... $ 32 $ 34 $ 26
Interest cost on projected benefit obligation........................................... 94 93 84
Actual return on plan assets............................................................ (268) (204) (315)
Net amortization and deferral........................................................... 142 100 211
--------- --------- ---------
Net periodic pension cost............................................................... 23 6
Special early retirement program........................................................ 13 18
Regulatory adjustment................................................................... 3 4
--------- --------- ---------
Total pension expense................................................................. $ 13 $ 26 $ 28
--------- --------- ---------
--------- --------- ---------
</TABLE>
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
--------------------
19967 1996
--------- ---------
(DOLLARS IN
MILLIONS)
<S> <C> <C>
Actuarial present value of pension benefit obligations:
Accumulated benefit obligation, including $1,057 and $1,048 in vested benefits at December
31, 1997 and 1996, respectively.......................................................... $ 1,105 $ 1,082
Effect of future salary increases.......................................................... 261 208
--------- ---------
Projected benefit obligation................................................................. 1,366 1,290
Less: plan assets at fair value, primarily publicly traded common stocks and pooled equity
funds...................................................................................... (1,834) (1,653)
Unrecognized net gain........................................................................ 520 404
Unrecognized prior service cost.............................................................. (36) (38)
Unrecognized transition obligation........................................................... (4) (4)
--------- ---------
Accrued pension liability included in the Consolidated Balance Sheet......................... $ 12 $ (1)
--------- ---------
--------- ---------
Deferred pension charge included in the Consolidated Balance Sheet........................... $ $ (3)
--------- ---------
--------- ---------
The plans' major actuarial assumptions include:
Weighted average discount rate............................................................. 7.00% 7.50%
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
The Company's postretirement benefit plan currently provides medical and
life insurance benefits to qualified retirees. In the past, employee
cost-sharing provisions have been implemented to control the increasing costs of
these benefits. Other changes could occur in the future. The Company's policy is
to fund these benefits at a level which is fully 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.
43
<PAGE>
The net periodic postretirement benefit expense was as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
-------------------------------
1997 1996 1995
--------- --------- ---------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C>
Service cost on benefits earned during the period........................................ $ 13 $ 15 $ 12
Interest cost on projected benefit obligation............................................ 31 30 29
Actual return on plan assets............................................................. (56) (30) (36)
Net amortization and deferral............................................................ 44 24 35
--- --- ---
Net periodic postretirement benefit cost................................................. 32 39 40
Special early retirement program......................................................... 2
Regulatory adjustment.................................................................... (1) (1)
--- --- ---
Total postretirement benefit expense................................................... $ 34 $ 38 $ 39
--- --- ---
--- --- ---
</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
--------------------
1997 1996
--------- ---------
(DOLLARS IN
MILLIONS)
<S> <C> <C>
Accumulated post-retirement benefit obligation:
Retirees....................................................................................... $ 202 $ 192
Fully eligible active plan participants........................................................ 234 156
Other active plan participants................................................................. 27 19
--------- ---------
463 367
Less: plan assets at fair value, primarily publicly traded common stocks and pooled equity
funds.......................................................................................... (343) (264)
Unrecognized net transition obligation........................................................... (128) (132)
Unrecognized net pension service cost............................................................
Unrecognized net gain............................................................................ 8 29
--------- ---------
Net postretirement benefit liability included in the Consolidated Balance Sheet.................. $ $
--------- ---------
--------- ---------
Deferred postretirement benefit charge included in the Consolidated Balance Sheet................ $ $ (1)
--------- ---------
--------- ---------
The plan's major actuarial assumptions include:
Health care cost trend rate.................................................................... 7.00% 7.00%
Weighted average discount rate................................................................. 7.00% 7.50%
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 and ultimate health care cost trend rate is 6.5% for 1998 and
thereafter. The effect of a one-percentage-point increase in the assumed health
care cost trend rate for each future year is $9.2 million on the aggregate of
the service and interest cost components of net periodic postretirement cost for
1997 and $68.8 million on the accumulated postretirement benefit obligation at
December 31, 1997. The estimated income tax rate used in the return on plan
assets is zero since the assets are invested in tax exempt funds.
POSTEMPLOYMENT BENEFITS
The Company accrues its 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
44
<PAGE>
recovered in rates as paid, and as such, have been reflected as a regulatory
asset. At December 31, 1997 and 1996 the liability was $39 million and $40
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
1995, 1996 and 1997 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 1997, 1996 and 1995.
45
<PAGE>
STATEMENT OF MANAGEMENT RESPONSIBILITY
FOR CONSOLIDATED FINANCIAL SERVICES
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
47. 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 must exercise
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
Neal E. Schmale,
EXECUTIVE VICE PRESIDENT AND CHIEF
FINANCIAL OFFICER
January 27, 1998
46
<PAGE>
INDEPENDENT AUDITORS' REPORT
Southern California Gas Company:
We have audited the consolidated financial statements of Southern California
Gas Company and subsidiaries (pages 27 to 45) as of December 31, 1997 and 1996,
and for each of the three years in the period ended December 31, 1997. 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, 1997 and 1996,
and the results of their operations and their cash flows for each of the three
years in the period ended December 31, 1997 in conformity with generally
accepted accounting principles.
DELOITTE & TOUCHE LLP
Los Angeles, California
January 27, 1998
47
<PAGE>
QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
1997
--------------------------------------------------
THREE MONTHS ENDED
--------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
----------- ----------- ----------- -----------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C>
Operating revenues.................................. $ 738 $ 575 $ 607 $ 721
Net operating revenue............................... $ 82 $ 91 $ 72 $ 73
Net income.......................................... $ 60 $ 72 $ 55 $ 51
Net income applicable to common stock............... $ 58 $ 70 $ 54 $ 49
</TABLE>
<TABLE>
<CAPTION>
1996
--------------------------------------------------
THREE MONTHS ENDED
--------------------------------------------------
MARCH 31 JUNE 30 SEPT. 30 DEC. 31
----------- ----------- ----------- -----------
(DOLLARS IN MILLIONS)
<S> <C> <C> <C> <C>
Operating revenues.................................. $ 620 $ 497 $ 575 $ 730
Net operating revenue............................... $ 79 $ 54 $ 73 $ 80
Net income.......................................... $ 57 $ 32 $ 53 $ 59
Net income applicable to common stock............... $ 54 $ 30 $ 51 $ 58
</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 5,
1998. Such information is incorporated herein by reference.
Information required by this Item with respect to the Company's executive
officers is set forth in Item 1 of this Annual Report.
ITEM 11. EXECUTIVE COMPENSATION
Information required by this Item is set forth under the caption "Election
of Directors" and "Executive Compensation" in the Company's Information
Statement for its Annual Meeting of Shareholders scheduled to be held on May 5,
1998. 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 5, 1998. Such information is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
48
<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 Independent Auditors' Report.
1.02 Statement of Consolidated Income for the years ended December 31, 1997,
1996, and 1995.
1.03 Consolidated Balance Sheet at December 31, 1997 and 1996.
1.04 Statement of Consolidated Cash Flows for the years ended December 31,
1997, 1996 and 1995.
1.05 Statement of Consolidated Shareholders' Equity for the years ended
December 31, 1997, 1996, 1995 and 1994.
1.06 Notes to Consolidated Financial Statements.
2. FINANCIAL STATEMENT SCHEDULES: Schedules for which provision is made in
Regulation S-X are not required under the instructions contained therein,
are inapplicable, or the information is included in the Notes to the
Consolidated Financial Statements.
3. ARTICLES OF INCORPORATION AND BY-LAWS:
3.01 Restated Articles of Incorporation of Southern California Gas Company
(Note 29; Exhibit 3.01).
3.02 Bylaws of Southern California Gas Company. (Note 28; Exhibit 3.02)
4. INSTRUMENTS DEFINING THE RIGHTS OF SECURITY HOLDERS:
(Note: As permitted by Item 601(b)(4)(iii) of Regulation S-K, certain
instruments defining the rights of holders of long-term debt for which the
total amount of securities authorized thereunder does not exceed ten percent
of the total assets of Southern California Gas Company and its subsidiaries
on a consolidated basis are not filed as exhibits to this Annual Report. The
Company agrees to furnish a copy of each such instrument to the Commission
upon request.)
4.01 Specimen Preferred Stock Certificates of Southern California Gas
Company (Note 13; Exhibit 4.01).
4.02 First Mortgage Indenture of Southern California Gas Company to American
Trust Company dated as of October 1, 1940 (Note 1; Exhibit B-4).
4.03 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of July 1, 1947 (Note 2; Exhibit B-5).
4.04 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of August 1, 1955 (Note 3; Exhibit 4.07).
4.05 Supplemental Indenture of Southern California Gas Company to American
Trust Company dated as of June 1, 1956 (Note 4; Exhibit 2.08).
4.06 Supplemental Indenture of Southern California Gas Company to Wells
Fargo Bank, National Association dated as of August 1, 1972 (Note 7;
Exhibit 2.19).
4.07 Supplemental Indenture of Southern California Gas Company to Wells
Fargo Bank, National Association dated as of May 1, 1976 (Note 6;
Exhibit 2.20).
49
<PAGE>
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 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 Amended and Restated Pacific Enterprises Employee Stock Option Plan
(Note 29; Exhibit 10.10).
10.11 Master Affiliate Service Agreement dated as of September 1, 1996
between Southern California Gas Company and Pacific Enterprises Energy
Services, as amended (Note 29; Exhitit 10.11).
21. SUBSIDIARIES OF THE REGISTRANT
21.01 List of subsidiaries of Southern California Gas Company.
23. CONSENTS OF EXPERTS AND COUNSEL
23.01 Independent Auditors' Consent.
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).
50
<PAGE>
27. FINANCIAL DATA SCHEDULE
27.01 Financial Data Schedule.
(b) Reports on Form 8-K:
No reports on Form 8-K were filed during the last quarter of 1997.
- ------------------------
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.
51
<PAGE>
<TABLE>
<CAPTION>
NOTE
REFERENCE DOCUMENT
- ------------- -------------------------------------------------------------------------------------------------------
<S> <C>
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.
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.
</TABLE>
52
<PAGE>
<TABLE>
<CAPTION>
NOTE
REFERENCE DOCUMENT
- ------------- -------------------------------------------------------------------------------------------------------
<S> <C>
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.
28 Annual Report on Form 10-K for the year ended December 31, 1995, filed by Southern California Gas
Company.
29 Annual Report on Form 10-K for the year ended December 31, 1996, filed by Southern California Gas
Company.
</TABLE>
53
<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.
<TABLE>
<S> <C> <C>
SOUTHERN CALIFORNIA GAS COMPANY
By: /s/ WARREN I. MITCHELL
-----------------------------------------
Name: Warren I. Mitchell
Title: PRESIDENT
Dated: March 20, 1998
</TABLE>
Each person whose signature appears below hereby authorizes Warren I.
Mitchell, Neal E. Schmale, 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.
<TABLE>
<CAPTION>
NAME TITLE DATE
- ------------------------------ -------------------------- -------------------
<C> <S> <C>
/s/ WARREN I. MITCHELL President
- ------------------------------ (Principal Executive March 20, 1998
(Warren I. Mitchell) Officer)
Executive Vice President
/s/ NEAL E. SCHMALE and Chief Financial
- ------------------------------ Officer (Principal March 20, 1998
(Neal E. Schmale) Financial Officer)
/s/ RALPH TODARO Vice President and
- ------------------------------ Controller (Principal March 20, 1998
(Ralph Todaro) Accounting Officer)
/s/ HYLA H. BERTEA
- ------------------------------ Director March 20, 1998
(Hyla H. Bertea)
/s/ HERBER L. CARTER
- ------------------------------ Director March 20, 1998
(Herbert L. Carter)
/s/ WILFORD D. GODBOLD, JR.
- ------------------------------ Director March 20, 1998
(Wilford D. Godbold, Jr.)
</TABLE>
54
<PAGE>
<TABLE>
<CAPTION>
NAME TITLE DATE
- ------------------------------ -------------------------- -------------------
<C> <S> <C>
/s/ IGNACIO E. LOZANO, JR.
- ------------------------------ Director March 20, 1998
(Ignacio E. Lozano, Jr.)
/s/ RICHARD J. STEGEMEIER
- ------------------------------ Director March 20, 1998
(Richard J. Stegemeier)
/s/ DIANA L. WALKER
- ------------------------------ Director March 20, 1998
(Diana L. Walker)
</TABLE>
55
<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.
333-45537, 33-51322, 33-53258, 33-59404 and 33-52663 of Southern California Gas
Company on Forms S-3 of our report dated January 27, 1998, appearing in this
Annual Report on Form 10-K of Southern California Gas Company for the year ended
December 31, 1997.
DELOITTE & TOUCHE LLP
Los Angeles, California
March 23, 1998
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE
CONDENSED STATEMENT OF CONOLIDATED INCOME, BALANCE SHEET AND CASH FLOWS AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> 12-MOS
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,074
<OTHER-PROPERTY-AND-INVEST> 0
<TOTAL-CURRENT-ASSETS> 917
<TOTAL-DEFERRED-CHARGES> 214
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 4,205
<COMMON> 835
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 535
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,370
0
97
<LONG-TERM-DEBT-NET> 968
<SHORT-TERM-NOTES> 351
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 147
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 1,272
<TOT-CAPITALIZATION-AND-LIAB> 4,205
<GROSS-OPERATING-REVENUE> 2,641
<INCOME-TAX-EXPENSE> 174
<OTHER-OPERATING-EXPENSES> 2,149
<TOTAL-OPERATING-EXPENSES> 2,323
<OPERATING-INCOME-LOSS> 318
<OTHER-INCOME-NET> 7
<INCOME-BEFORE-INTEREST-EXPEN> 325
<TOTAL-INTEREST-EXPENSE> 87
<NET-INCOME> 238
7
<EARNINGS-AVAILABLE-FOR-COMM> 231
<COMMON-STOCK-DIVIDENDS> 0
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 396
<EPS-PRIMARY> 0
<EPS-DILUTED> 0
</TABLE>
