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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 1-40
PACIFIC ENTERPRISES
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(Exact name of Registrant as specified in its charter)
California 94-0743670
- ---------------------------- ---------------------------------
(State of incorporation) (IRS Employer Identification No.)
555 West Fifth Street, Suite 2900, Los Angeles, California 90013-1011
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(Address of principal executive offices) (Zip Code)
(213) 895-5000
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(Registrant's telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
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Title of each class on which registered
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Common Stock and Associated New York Stock Exchange
Common Stock Purchase Rights Pacific Stock Exchange
Preferred Stock
$4.75 dividend
$4.50 dividend American Stock Exchange
$4.40 dividend Pacific Stock Exchange
$4.36 dividend
Securities registered pursuant to Section 12(g) of the Act: None
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Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months and (2) has been subject to such filing
requirements for the past 90 days.
Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this Form 10-K. /X/
The aggregate market value of Registrant's voting stock (Common Stock and
Preferred Stock) held by non-affiliates at March 16, 1998, was approximately
$3.3 billion. This amount excludes the market value of 801,813 shares of
Common Stock held by Registrant's directors and executive officers.
Registrant's Common Stock outstanding at March 16, 1998, numbered
83,385,572 shares.
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>
Information Incorporated
by Reference and Document
Annual Report in Which Information is or
On Form 10-K will be Contained
--------------- -----------------------------
<C> <S>
Part II - Information contained under
the captions "Management's
Discussion and Analysis,"
"Quarterly Financial Data,"
"Range of Market Prices of
Capital Stock" and "Selected
Financial Data and Comparative
Statistics 1987-1997," in
Registrant's 1997 Annual Report
to Shareholders.
Consolidated Financial
Statements, the Independent
Auditors' Report and the
Statement of Management
Responsibility for
Consolidated Financial
Statements appearing on
pages 31-55 of Registrant's
1997 Annual Report to
Shareholders.
Part III - Information contained under the
captions "Election of
Directors," "Share Ownership
of Directors and Executive
Officers" and "Executive
Compensation" in Registrant's
Proxy Statement for its Annual
Meeting of Shareholders
scheduled to be held on
May 7, 1998.
</TABLE>
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TABLE OF CONTENTS
<TABLE>
<CAPTION>
Page
<C> <S> <C> <C>
PART I
Item 1. Business........................................................5
Pacific Enterprises.............................................5
Southern California Gas Company.................................6
Operating Statistics.......................................7
Service Area...............................................8
Utility Services...........................................9
Demand for Gas.............................................9
Competition...............................................10
Supplies of Gas...........................................11
Rates and Regulation..................................... 13
Properties................................................15
Energy Management Services.....................................15
Pacific Enterprises International..............................16
Energy Trading.................................................16
Environmental Matters..........................................17
Employees......................................................17
Management.....................................................18
Item 2. Properties.....................................................19
Item 3. Legal Proceedings..............................................19
Item 4. Submission of Matters to a Vote of Security Holders............19
PART II
Item 5. Market for Registrant's Common Equity and Related Stockholder
Matters........................................................20
Item 6. Selected Financial Data........................................20
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations......................................20
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Item 7A. Quantitative and Qualitative Disclosures about Market Risk.....20
Item 8. Financial Statements and Supplementary Data....................20
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure.......................................20
PART III
Item 10. Directors and Executive Officers of the Registrant.............21
Item 11. Executive Compensation.........................................21
Item 12. Security Ownership of Certain Beneficial Owners and Management.21
Item 13. Certain Relationships and Related Transactions.................21
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports
on Form 8-K....................................................22
</TABLE>
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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 PACIFIC ENTERPRISES. ACCORDINGLY, WHILE PACIFIC
ENTERPRISES 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
PACIFIC ENTERPRISES
Pacific Enterprises is a Los Angeles-based energy services company
whose principal subsidiary is Southern California Gas Company, the nation's
largest natural gas distribution utility. Through other subsidiaries, Pacific
Enterprises also markets a wide range of unregulated energy products and
services, including natural gas, and has interests in international utility
operations in Argentina and Mexico, interstate and offshore natural gas
pipelines and centralized heating and cooling for large building complexes.
Pacific Enterprises was incorporated in California in 1907 as the
successor to a corporation organized in 1886. Its principal executive offices
are located at 555 West Fifth Street, Los Angeles, California 90013-1011 and
its telephone number is (213) 895-5000.
Pacific Enterprises 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. This strategic merger of equals will be a
tax free transaction accounted for as a pooling of interests in which common
shareholders of Pacific Enterprises and Enova will receive 1.5038 shares of
Sempra Energy common stock for each share of Pacific Enterprises common stock
and one share of Sempra Energy common stock for each share of Enova common
stock. The preferred stock of Pacific Enterprises will remain outstanding.
The combination was approved by the shareholders of both Pacific
Enterprises 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 Pacific Enterprises and Enova.
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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 Pacific
Enterprises 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.
To pursue opportunities in unregulated energy markets pending the
completion of the combination, Pacific Enterprises and Enova have formed a
joint venture to be named Sempra Energy Solutions (currently named Energy
Pacific) to market energy products and services. See "Energy Management
Services" below. In addition, in December 1997, Pacific Enterprises and Enova
jointly acquired Sempra Energy Trading Corp. (formerly AIG Trading
Corporation), a natural gas and power marketing firm with 90 employees
headquartered in Greenwich, Connecticut. Its business primarily focuses on
wholesale trading and marketing of natural gas, power and oil. See "Energy
Trading" below.
SOUTHERN CALIFORNIA GAS COMPANY
Pacific Enterprises' principal subsidiary, Southern California Gas Company
("SoCalGas"), 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 most of southern and part of central
California. SoCalGas provides natural gas service to residential, commercial,
industrial, utility electric generation and wholesale customers through
approximately 4.8 million meters in a 23,000-square-mile service area with a
population of approximately 17.6 million.
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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
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1997 1996 1995 1994 1993
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<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>
(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.
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SERVICE AREA
SoCalGas 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]
Natural gas service is also provided on a wholesale basis to the
distribution systems of the City of Long Beach, San Diego Gas & Electric
Company and Southwest Gas Corporation.
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UTILITY SERVICES
SoCalGas' 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 SoCalGas' 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.
SoCalGas 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 SoCalGas. Noncore customers have the option of purchasing
gas either from SoCalGas or from other sources (such as brokers or producers)
for delivery through SoCalGas' 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
SoCalGas' core market. Most noncore customers procure their own gas supply
rather than purchase gas from SoCalGas. Although the revenues from
transportation throughput are less than for gas sales, SoCalGas generally earns
the same margin whether SoCalGas 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 - SoCalGas
Operations - Markets.")
SoCalGas 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 SoCalGas may offer for sale to noncore customers are the same
supplies that it purchases to serve its core customers.
SoCalGas 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, SoCalGas stored approximately
15 billion cubic feet of customer-owned gas.
DEMAND FOR GAS
Natural gas is a principal energy source in SoCalGas' 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 SoCalGas' markets is largely
dependent upon the health and expansion of the southern California economy.
SoCalGas added approximately 43,700 new meters in 1997. This represents a
growth rate of approximately 0.9%. SoCalGas anticipates that customer growth
for 1998 will continue at about 1997 levels.
During 1997, approximately 97% of residential energy customers in
SoCalGas' 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.
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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, 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
SoCalGas' 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 SoCalGas' 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 SoCalGas' 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
SoCalGas' 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 - SoCalGas Operations
- - Factors Influencing Future Performance.")
COMPETITION
SoCalGas' throughput to enhanced oil recovery ("EOR") customers has
decreased significantly since 1992 because of the bypass of SoCalGas' system.
The decrease in revenues from EOR customers is subject to full balancing
account treatment, except for a 5% incentive to SoCalGas, and therefore, does
not have a material impact on earnings.
Bypass of other SoCalGas markets may also occur and SoCalGas 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. SoCalGas is continuing to reduce its costs
to maintain cost competitiveness to retain transportation customers.
To respond to bypass, SoCalGas may seek expedited review of long-term
gas transportation contracts with some noncore customers at lower than tariff
rates. In addition, SoCalGas allocates costs in a manner that eliminates
subsidization of core customer rates by noncore customers. This allocation
flexibility, together with negotiating authority, has enabled SoCalGas to
better compete with new interstate pipelines for noncore customers. In
addition, under a capacity brokering program, for a fee, SoCalGas 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 has improved SoCalGas' competitiveness
by reducing the cost of transportation service to noncore customers. (See
"Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations - SoCalGas Operations - Factors Influencing Future
Financial Performance.")
SoCalGas' 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
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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, SoCalGas delivered approximately 930 billion cubic feet
(Bcf) of natural gas through its system. Approximately 65% of these
deliveries were customer-owned gas for which SoCalGas provided transportation
services. The balance of gas deliveries was gas purchased by SoCalGas and
resold to customers.
Most of the natural gas delivered by SoCalGas is produced outside
of California. These supplies are delivered to SoCalGas' intrastate
transmission system by interstate pipeline companies (primarily El Paso
Natural Gas Company and Transwestern Pipeline Company) that provide
transportation services for supplies purchased from other sources by SoCalGas
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 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. SoCalGas 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 SoCalGas 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, SoCalGas' 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 SoCalGas' ability to compete in highly contested markets, SoCalGas does
not believe its inclusion will have a significant impact on volumes transported
or sold.
The following table sets forth the sources of gas deliveries by
SoCalGas from 1993 through 1997.
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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>
* Fixed charges primarily include pipeline demand charges, take or pay
settlement costs and other direct billed amounts allocated over the
quantities delivered by the interstate pipelines serving SoCalGas.
** The average commodity cost of gas purchased excludes fixed charges.
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Market sensitive gas supplies (supplies purchased on the spot
market as well as under longer-term contracts and ranging from one month to
ten years based on spot prices) accounted for approximately 70% of total gas
volumes purchased by SoCalGas 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.
SoCalGas estimates that sufficient natural gas supplies will be
available to meet the requirements of its customers well into the next
century.
RATES AND REGULATION
SoCalGas is regulated by the CPUC. The CPUC consists of five
commissioners appointed by the Governor of California for staggered six-year
terms. It is the responsibility of the CPUC to determine that utilities
operate in the best interest of 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 SoCalGas.
PERFORMANCE BASED REGULATION
On July 16, 1997, the CPUC issued its final decision on SoCalGas'
application for performance based regulation ("PBR"), which was filed with the
CPUC in 1995.
For the 5-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, SoCalGas
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 SoCalGas
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 SoCalGas 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 SoCalGas 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
SoCalGas:
- 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
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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, SoCalGas 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.
SoCalGas 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 SoCalGas' 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 1993 settlement that restructured certain
long-term gas supply contracts and resolved several regulatory matters. The
BCAP will continue under PBR.
The GCIM compares SoCalGas' cost of gas with the average market price
of 30-day firm spot supplies delivered to the SoCalGas 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, SoCalGas 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 - SoCalGas Operations - Factors Influencing Future
Performance.")
-14-
<PAGE>
ALLOWED RATE OF RETURN
For 1998, SoCalGas 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.
PROPERTIES
At December 31, 1997, SoCalGas 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 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
SoCalGas, has a 15% limited partnership interest in a 52-story office
building in downtown Los Angeles. SoCalGas leases, and currently occupies,
about half of the building. (See also "Item 2. Properties.")
ENERGY MANAGEMENT SERVICES
The Energy Management Services business unit of Pacific Enterprises
operates a number of domestic business ventures, including Sempra Energy
Solutions.
Sempra Energy Solutions is the joint venture between Pacific
Enterprises and Enova established in early 1997. Sempra Energy Solutions
primarily focuses on marketing new energy products and services.
Energy Management Services also includes Pacific Interstate Company
("PIC"), an interstate pipeline subsidiary, and Central Plants, Inc., a
subsidiary which operates centralized heating and cooling plants for commercial
buildings. PIC purchases gas from producers in Canada and from federal waters
offshore California and transports it for sale to SoCalGas and others. Of the
gas purchased by PIC, 90% was sold to SoCalGas in 1997. These deliveries
accounted for approximately 29% of the total volume of gas purchased by
SoCalGas and approximately 10% of SoCalGas' throughput.
In September 1997, Pacific Enterprises sold its interest in several
small electric generating facilities. The net investment in these assets was
$77 million at June 30, 1997, the effective date of the sale.
-15-
<PAGE>
In January 1998, through Sempra Energy Solutions, Pacific Enterprises
and Enova jointly acquired CES/Way International, the largest independent U.S.
company providing energy service performance contracting. CES/Way
International has approximately 125 employees and is headquartered in Houston,
Texas. The total cost of the acquisition was less than $100 million.
PACIFIC ENTERPRISES INTERNATIONAL
Pacific Enterprises International ("PEI") was established in late
1994 to participate in the international gas infrastructure market and began
operations in March 1995.
In April 1996, PEI acquired a 12.5% interest in each of two natural
gas utility holding companies in Argentina for $48.5 million. These utilities
serve approximately 1.1 million customers in central and southern Argentina
with about 625 million cubic feet of gas per day. PEI has a role in helping
manage these utilities by serving on the board of directors and providing
expertise in technological and operating areas.
On August 12, 1996, PEI and two partners were awarded Mexico's first
privatization license to build and operate a natural gas distribution system in
Mexicali, Baja California. The franchise was awarded to Distribuidora de Gas
Natural de Mexicali S. de R.L. de C.V. (DGN), a Mexican company formed by PEI,
Enova International (a subsidiary of Enova) and Proxima Gas. DGN will invest
approximately $20 to $25 million during an initial five-year period to provide
service to more than 25,000 commercial, industrial and residential users. PEI
has a 30% interest in DGN and has invested approximately $2 million and
$1 million in the Mexicali project during 1997 and 1996, respectively. In
August 1997, the system began distributing natural gas primarily to commercial
customers in Mexicali, and by December 1997 daily throughput reached
5.3 million cubic feet.
In 1997, DGN was awarded a license to build and operate a natural gas
pipeline in Chihuahua, a city of approximately 630,000 people in northern
Mexico. DGN began construction in late 1997 and will invest $50 million in the
first five years of operation. PEI has a 47.5% interest in this project and it
invested approximately $5 million during 1997.
Other international projects are currently under evaluation in Latin
America and the Pacific Rim.
ENERGY TRADING
In December 1997, Pacific Enterprises and Enova jointly acquired
Sempra Energy Trading Corp. (formerly AIG Trading Corporation), a natural gas
and power marketing firm with 90 employees headquartered in Greenwich,
Connecticut. Its business primarily focuses on wholesale trading and marketing
of natural gas, power and oil. Total cost of the acquisition was approximately
$225 million.
-16-
<PAGE>
ENVIRONMENTAL MATTERS
The CPUC has approved a collaborative settlement which provides for
rate recovery of 90 percent of environmental investigation and remediation
costs without reasonableness review. In addition, SoCalGas has the opportunity
to retain a portion of any insurance recovery to offset the 10 percent of costs
not recovered in rates.
At December 31, 1997, SoCalGas' estimated remaining liability for
investigation and remediation was approximately $72 million, of which 90
percent is authorized to be recovered through the rate recovery mechanism
described above. The estimated liability is subject to future adjustment
pending further investigation. (See "Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operation - SoCalGas
Operations - Factors Influencing Future Performance.") Because of expected
insurance and rate recovery, Pacific Enterprises believes that compliance
with environmental laws and regulations will not have a material adverse
effect on its consolidated results of operations or financial position.
SoCalGas 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 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, SoCalGas 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
Pacific Enterprises and its subsidiaries employ approximately
7,215 persons. Of these, approximately 6,615 are employed by SoCalGas.
Most field, clerical and technical employees of SoCalGas 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.
-17-
<PAGE>
MANAGEMENT
The executive officers of Pacific Enterprises are as follows:
<TABLE>
<CAPTION>
NAME AGE POSITION
<S> <C> <C>
Willis B. Wood, Jr. 63 Chairman and Chief Executive Officer
Richard D. Farman 62 President and Chief Operating Officer
Warren I. Mitchell 60 Executive Vice President, Pacific
Enterprises; President, Southern
California Gas Company
Neal E. Schmale 51 Executive Vice President and Chief
Financial Officer
Frederick E. John 52 Senior Vice President
Debra L. Reed 41 Senior Vice President, Southern
California Gas Company
Lee M. Stewart 52 Senior Vice President, Southern
California Gas Company
Dennis V. Arriola 37 Vice President and Treasurer
Leslie E. LoBaugh, Jr. 52 Vice President and General Counsel
Ralph Todaro 47 Vice President and Controller
</TABLE>
Executive officers are elected annually and serve at the pleasure of
the Board of Directors.
All of Pacific Enterprises' executive officers have been employed
by Pacific Enterprises or its subsidiaries in management positions for more
than 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 Pacific Enterprises 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).
There are no family relationships between any of Pacific
Enterprises' executive officers.
-18-
<PAGE>
ITEM 2. PROPERTIES
Information with respect to the properties of Pacific Enterprises
subsidiaries is set forth in Item 1 of this Annual Report.
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 Pacific Enterprises 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 its 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 Pacific Enterprises' security holders.
-19-
<PAGE>
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
AND RELATED STOCKHOLDER MATTERS
Pacific Enterprises' Common Stock is traded on the New York and
Pacific Stock Exchanges. Information as to the high and low sales prices for
such stock as reported on the composite tape for stocks listed on the New York
Stock Exchange and dividends paid for each quarterly period during the two
years ended December 31, 1997 is set forth under the captions "Financial Review-
- -Range of Market Prices of Capital Stock" and "Quarterly Financial Data" in
Pacific Enterprises' 1997 Annual Report to Shareholders filed as Exhibit 13.01
to this Annual Report. Such information is incorporated herein by reference.
At December 31, 1997, there were 34,542 holders of record of Pacific
Enterprises' Common Stock.
ITEM 6. SELECTED FINANCIAL DATA
The information required by this Item is set forth under the caption
" Selected Financial Data and Comparative Statistics 1987-1997" in Pacific
Enterprises' 1997 Annual Report to Shareholders filed as Exhibit 13.01 to this
Annual Report. Such information is incorporated herein by reference.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information required by this Item is set forth under the caption
"Management's Discussion and Analysis" in Pacific Enterprises' 1997 Annual
Report to Shareholders filed as Exhibit 13.01 to this Annual Report. Such
information is incorporated herein by reference.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES
ABOUT MARKET RISK
The information required by this Item is set forth under the caption
"Management's Discussion and Analysis" in Pacific Enterprises' 1997 Annual
Report to Shareholders filed as Exhibit 13.01 to this Annual Report. Such
information is incorporated herein by reference.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Pacific Enterprises' consolidated financial statements required by
this Item are listed in Item 14(a)1 in Part IV of this Annual Report. The
consolidated financial statements listed in Item 14(a)1 are incorporated herein
by reference.
ITEM 9. CHANGES IN AND DISAGREEMENTS
WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE
None.
-20-
<PAGE>
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
Information required by this Item with respect to the Company's
directors is set forth under the caption "Election of Directors" in the
Company's Proxy Statement for its Annual Meeting of Shareholders scheduled to
be held on May 7, 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 Proxy
Statement for its Annual Meeting of Shareholders scheduled to be held on May 7,
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 Proxy Statement for its Annual Meeting
of Shareholders scheduled to be held on May 7, 1998. Such information is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED
TRANSACTIONS
None.
-21-
<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:
1.01 Independent Auditors' Report
(Contained in Exhibit 13.01).
1.02 Consolidated Statement of
Income for the years ended
December 31, 1997, 1996 and 1995
(Contained in Exhibit 13.01).
1.03 Consolidated Balance Sheet at
December 31, 1997 and 1996
(Contained in Exhibit 13.01).
1.04 Statement of Consolidated Cash Flows
for the years ended December 31, 1997,
1996 and 1995 (Contained in Exhibit 13.01).
1.05 Statement of Consolidated Shareholders'
Equity for the years ended
December 31, 1997, 1996 and 1995
(Contained in Exhibit 13.01).
1.06 Notes to Consolidated Financial
Statements (Contained in Exhibit 13.01).
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 Articles of Incorporation of
Pacific Enterprises
(Note 26, Exhibit 3.01).
3.02 Bylaws of Pacific Enterprises.
(Note 23; Exhibit 3.02).
-22-
<PAGE>
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 Common Stock Certificate of
Pacific Enterprises (Note 16; Exhibit 4.01).
4.02 Specimen Preferred Stock Certificates of Pacific
Enterprises (Note 8; Exhibit 4.02).
4.03 First Mortgage Indenture of Southern California
Gas Company to American Trust Company dated
October 1, 1940 (Note 1; Exhibit B-4).
4.04 Supplemental Indenture of Southern California Gas
Company to American Trust Company dated as of
July 1, 1947 (Note 2; Exhibit B-5).
4.05 Supplemental Indenture of Southern California
Gas Company to American Trust Company dated as
of August 1, 1955 (Note 3; Exhibit 4.07).
4.06 Supplemental Indenture of Southern California
Gas Company to American Trust Company dated as
of June 1, 1956 (Note 4; Exhibit 2.08).
4.07 Supplemental Indenture of Southern California
Gas Company to Wells Fargo Bank, National
Association dated as of August 1, 1972 (Note 6;
Exhibit 2.19).
4.08 Supplemental Indenture of Southern California
Gas Company to Wells Fargo Bank, National
Association dated as of May 1, 1976 (Note 5;
Exhibit 2.20).
4.9 Supplemental Indenture of Southern California
Gas Company to Wells Fargo Bank, National
Association dated as of September 15, 1981
(Note 9; Exhibit 4.25).
4.10 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 11; Exhibit 4.29).
-23-
<PAGE>
4.11 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 13; Exhibit 4.11).
4.12 Supplemental Indenture of Southern California Gas
Company to First Trust of California, National
Association, successor to Bankers Trust Company
of California, N.A. (Note 18; Exhibit 4.37).
4.13 Rights Agreement dated as of March 7, 1990
between Pacific Enterprises and Security
Pacific National Bank, as Rights
Agent (Note 19; Exhibit 4).
10. MATERIAL CONTRACTS
10.01 Form of Indemnification Agreement
between Pacific Enterprises and each of
its directors and officers
(Note 21; Exhibit 10.07).
10.2 Agreement and Plan of Merger
and Reorganization dated as of October 12,
1996, by and among Pacific Enterprises,
Enova, the New Holding Company,
Pacific Sub and Enova Sub
(Note 24; Exhibit 10.1).
10.3 Operating Agreement of Mineral JV, LLC,
dated as of January 13, 1997 (Note 25;
Exhibit 10.5).
EXECUTIVE COMPENSATION PLANS AND ARRANGEMENTS
10.4 Restatement and Amendment of Pacific
Enterprises 1979 Stock Option Plan
(Note 7; Exhibit 1.1).
10.5 Pacific Enterprises Supplemental Medical
Reimbursement Plan for Senior Officers
(Note 8; Exhibit 10.24).
10.6 Pacific Enterprises Financial Services
Program for Senior Officers (Note 8;
Exhibit 10.25).
10.7 Pacific Enterprises Supplemental
Retirement and Survivor Plan (Note 11;
Exhibit 10.36).
-24-
<PAGE>
10.8 Pacific Enterprises Stock Payment
Plan (Note 11; Exhibit 10.37).
10.9 Pacific Enterprises Pension Restoration
Plan (Note 8; Exhibit 10.28).
10.10 Southern California Gas Company Pension
Restoration Plan For Certain Management
Employees (Note 8; Exhibit 10.29).
10.11 Pacific Enterprises Executive Incentive
Plan (Note 13; Exhibit 10.13).
10.12 Pacific Enterprises Deferred Compensation
Plan for Key Management Employees (Note 12;
Exhibit 10.41).
10.13 Pacific Enterprises Employee Stock
Ownership Plan and Trust Agreement
as amended in toto effective October 1, 1992.
(Note 21; Exhibit 10.18).
10.14 Pacific Enterprises Stock Incentive Plan
(Note 15; Exhibit 4.01).
10.15 Pacific Enterprises Retirement Plan for
Directors (Note 21; Exhibit 10.20).
10.16 Pacific Enterprises Director's Deferred
Compensation Plan (Note 21; Exhibit 10.21).
10.17 Amended and Restated Pacific Enterprises Employee
Stock Option Plan (as of March 4, 1997)
(Note 26; Exhibit 10.17).
10.18 Form of Severance Agreement
(Note 26; Exhibit 10.18).
10.19 Form of Incentive Bonus Agreement
(Note 26; Exhibit 10.19).
11. STATEMENT RE COMPUTATION OF PER SHARE EARNINGS
11.01 Pacific Enterprises Computation of Earnings
per Share (see Consolidated Statement of
Income and Note 15 of the Notes to
Consolidated Financial Statements
contained in Exhibit 13.01).
-25-
<PAGE>
13. ANNUAL REPORT TO SECURITY HOLDERS
13.01 Pacific Enterprises 1997 Annual
Report to Shareholders. (Such
report, except for the portions
thereof which are expressly
incorporated by reference in this
Annual Report, is furnished for the
information of the Securities and
Exchange Commission and is not to
be deemed "filed" as part of this
Annual Report).
21. SUBSIDIARIES OF THE REGISTRANT
21.01 List of subsidiaries of Pacific Enterprises.
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 Pacific Enterprises
(contained on signature pages).
27. FINANCIAL DATA SCHEDULE
27.01 Financial Data Schedule.
(b) REPORTS ON FORM 8-K:
The following reports on Form 8-K were filed during the last quarter
of 1997: None
- ------------------------------
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.
-26-
<PAGE>
<TABLE>
<CAPTION>
Note
Reference Document
- --------- --------
<C><S>
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. 2-56034 filed by Southern California Gas
Company on April 14, 1976.
6 Registration Statement No. 2-59832 filed by Southern California Gas
Company on September 6, 1977.
7 Registration Statement No. 2-66833 filed by Pacific Lighting Corporation
on March 5, 1980.
8 Annual Report on Form 10-K for the year ended December 31, 1980, filed by
Pacific Lighting Corporation.
9 Annual Report on Form 10-K for the year ended December 31, 1981, filed by
Pacific Lighting Corporation.
10 [Intentionally Left Blank.]
11 Annual Report on Form 10-K for the year ended December 31, 1984, filed by
Pacific Lighting Corporation.
12 Annual Report on Form 10-K for the year ended December 31, 1985, filed by
Pacific Lighting Corporation.
13 Annual Report on Form 10-K for the year ended December 31, 1987, filed by
Pacific Enterprises.
14 [Intentionally Left Blank.]
15 Registration Statement No. 33-21908 filed by Pacific Enterprises on
May 17, 1988.
16 Annual Report on Form 10-K for the year ended December 31, 1988, filed by
Pacific Enterprises.
17 [Intentionally Left Blank.]
18 Registration Statement No. 33-50826 filed by Southern California Gas
Company on August 13, 1992.
19 Current Report on Form 8-K dated September 25, 1992, filed by Pacific
Enterprises.
20 [Intentionally Left Blank.]
21 Annual Report on Form 10-K for the year ended December 31, 1992, filed by
Pacific Enterprises.
22 [Intentionally Left Blank.]
23 Annual Report on Form 10-K for the year ended December 31, 1995, filed by
Pacific Enterprises.
-27-
<PAGE>
24 Current Report on Form 8-K dated October 15, 1996, filed by Pacific
Enterprises.
25 Registration Statement No. 333-21229 filed by Mineral Energy Company on
February 5, 1997.
26 Annual Report on Form 10-K for the year ended December 31, 1996, filed by
Pacific Enterprises.
</TABLE>
-28-
<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.
PACIFIC ENTERPRISES
By: WILLIS B. WOOD, JR.
----------------------------
Name: Willis B. Wood, Jr.
Title: Chairman and
Chief Executive Officer
Dated: March 20, 1998
-29-
<PAGE>
Each person whose signature appears below hereby authorizes Willis B.
Wood, Jr., Richard D. Farman, and Neal E. Schmale, 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>
SIGNATURE TITLE DATE
<S> <C> <C>
WILLIS B. WOOD, JR. Chairman, March 20, 1998
- --------------------------- Chief Executive Officer and
(Willis B. Wood, Jr. Director (Principal Executive
Officer)
NEAL E. SCHMALE Executive Vice President and March 20, 1998
- --------------------------- Chief Financial Officer
(Neal E. Schmale) (Principal Financial Officer)
RALPH TODARO Vice President and Controller March 20, 1998
- --------------------------- (Principal Accounting Officer)
Ralph Todaro
HYLA H. BERTEA Director March 20, 1998
- ---------------------------
(Hyla H. Bertea)
HERBERT L. CARTER Director March 20, 1998
- ---------------------------
(Herbert L. Carter)
RICHARD D. FARMAN Director March 20, 1998
- ---------------------------
(Richard D. Farman)
WILFORD D. GODBOLD, JR. Director March 20, 1998
- ---------------------------
(Wilford D. Godbold, Jr.)
IGNACIO E. LOZANO, JR. Director March 20, 1998
- ---------------------------
(Ignacio E. Lozano, Jr.)
RICHARD J. STEGEMEIER Director March 20, 1998
- ---------------------------
(Richard J. Stegemeier)
DIANA L. WALKER Director March 20, 1998
- ---------------------------
(Diana L. Walker)
</TABLE>
-30-
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS
INTRODUCTION
This section includes management's analysis of operating results from 1995
through 1997, and is intended to provide additional information about Pacific
Enterprises' (the Company or PE) 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.
Pacific Enterprises is a Los Angeles-based utility holding company whose
primary subsidiary is Southern California Gas Company (SoCalGas), the
nation's largest natural gas distribution utility, serving 4.8 million meters
throughout most of southern and part of central California. SoCalGas delivers
natural gas and related services to residential and small commercial and
industrial customers and stores and transports natural gas for utility
electric generation and wholesale customers. The Company's Energy Management
Services (EMS) business unit is engaged in interstate and offshore natural
gas transmission to serve its utility operations and centralized heating and
cooling for large building complexes. Through Pacific Enterprises
International (PEI), the Company invests in international energy utility
operations.
The Company and Enova Corporation (Enova), the parent company of San Diego
Gas & Electric Company (SDG&E), 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 common stock of each company will become
holders of common stock of Sempra Energy. This strategic merger of equals
will be a tax free transaction accounted for as a pooling of interests. The
combination was approved by the shareholders of both companies on March 11,
1997, but remains subject to approval by several regulatory and governmental
agencies, including the California Public Utilities Commission (CPUC). A
proposed decision issued February 23, 1998, by a CPUC law judge included many
of the proposals contained in the original merger application and recommends
approval of the merger. But the proposed decision, which the CPUC can adopt,
modify or reject, recommends savings from synergies and cost avoidances be
shared between customers and shareholders over a five-year period, reducing
total net savings to approximately $340 million. The merger application
proposed that savings of approximately $1 billion be shared equally between
customers and shareholders over 10 years. The proposed decision recommends
that SDG&E divest its gas-fired generation units (which is already in
progress) and that SoCalGas sell its options to purchase those portions of
the Kern River and Mojave Pipeline gas transmission facilities within
California by December 31, 1999. In addition, the proposed decision grants PE
and Enova $148 million in costs to achieve the merger, rather than the $202
million requested by the companies. It also recommends that savings to be
generated through utility-to-utility transactions should be allowed. To
pursue opportunities in unregulated energy markets pending the completion of
the combination, the Company and Enova have formed a joint venture named
Sempra Energy Solutions (formerly Energy Pacific) to market energy products
and services.
In December 1997, the Company and Enova jointly acquired Sempra Energy
Trading Corp. (formerly AIG Trading Corporation), a natural gas and power
marketing firm with 90 employees headquartered in Greenwich, Connecticut. Its
business primarily focuses on wholesale trading and marketing of natural gas,
power and oil. Total cost of the acquisition paid by PE and Enova was
approximately $225 million.
In January 1998, through Sempra Energy Solutions, the Company and
Enova jointly acquired CES/Way International, the largest independent U.S.
company providing energy service performance contracting. CES/Way
International has 125 employees and is headquartered in Houston, Texas. The
total cost of the acquisition paid by Sempra Energy Solutions was less than
$100 million.
<PAGE>
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:
SOURCES AND (USES) OF CASH
<TABLE>
<CAPTION>
Year Ended December 31
(Dollars in millions) 1997 1996 1995
- -------------------------------------------------------------------
<S> <C> <C> <C>
Operating Activities $ 350 $ 608 $ 698
Investing Activities:
Capital Expenditures (187) (204) (240)
Investments (118) (62)
Financing Activities:
Long-Term Debt (125) (97) (207)
Short-Term Debt 92 29 (44)
Issuance of
Common Stock 17 8 6
Repurchase of
Common Stock (48) (24)
Redemption of
Preferred Stock (210) (30)
Common and
Preferred Dividends (126) (123) (121)
-----------------------------------
Total Financing
Activities (190) (417) (396)
Other 42 (20) 2
-----------------------------------
Increase (Decrease) in Cash
and Cash Equivalents $ (103) $ (95) $ 64
- --------------------------------------------------------------------
- --------------------------------------------------------------------
</TABLE>
CASH FLOWS FROM OPERATING ACTIVITIES
The decrease in cash flow from operating activities to $350 million in 1997
from $608 million in 1996 was primarily due to greater working capital
requirements at SoCalGas 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. In addition,
higher taxes were paid in 1997 compared to 1996.
pacific enterprises 20.
<PAGE>
[chart]
The decrease in cash flow from operating activities to $608 million in
1996 from $698 million in 1995 was primarily due to lower noncore revenues
and lower amounts received from undercollected regulatory balancing accounts,
partially offset by favorable settlements described under "SoCalGas
Operations."
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures primarily represent rate base investment at SoCalGas.
The table below summarizes capital expenditures by utility plant
classification:
CAPITAL EXPENDITURES
<TABLE>
<CAPTION>
Year Ended December 31
----------------------------------
(Dollars in millions) 1997 1996 1995
-------------------------------------------------------------------
<S> <C> <C> <C>
SoCalGas:
Distribution $ 110 $ 124 $ 126
Transmission 14 24 19
Storage 10 5 19
Other 25 44 67
---------- --------------------
Total SoCalGas 159 197 231
Other 28 7 9
---------- --------------------
Total Expenditures $ 187 $ 204 $ 240
-------------------------------------------------------------------
-------------------------------------------------------------------
</TABLE>
Capital expenditures were $17 million lower in 1997 than in 1996. The
decrease was due to lower capital spending at SoCalGas primarily related to
the customer information system completed in early 1996, and other
nonrecurring computer system expenditures in 1996. The decrease was partially
offset by higher capital expenditures related to the purchase of a data
processing facility and a plant expansion at Pacific Interstate Company.
Capital expenditures for 1996 were $36 million lower than in 1995,
primarily due to the completion in 1996 of a new customer information system
and by capital required for repairs to earthquake-damaged storage facilities
during 1995.
Capital expenditures are estimated to be $200 million in 1998. They will
be financed primarily by internally generated funds and will largely
represent investment in SoCalGas operations.
INVESTMENTS
Investments in 1997 include $112 million representing the Company's 50%
ownership interest in Sempra Energy Trading Corp. and $7 million invested in
the two natural gas distribution systems in Mexico (Chihuahua and Mexicali).
Investments have been reduced by proceeds from the sale of several small
electric generation facilities in 1997.
Investments in 1996 include PEI's acquisition of a 12.5% interest in two
utility holding companies that control natural gas distribution utilities in
Argentina, and the investment in the Mexicali natural gas distribution
system. The acquisition price of the Argentina investment was $48.5 million,
and funds invested in the Mexicali project totaled $1 million through the end
of 1996.
CASH FLOWS FROM FINANCING ACTIVITIES
Cash flow used for financing activities decreased $227 million in 1997
compared to 1996. The decrease was primarily due to the redemption of
preferred stock in 1996.
Cash flow used for financing activities increased $21 million in 1996
compared to 1995. The increase was primarily due to the redemption of
preferred stock and repurchase of common stock, partially offset by a
decrease in long- and short-term debt repayments.
LONG-TERM DEBT
In 1997, cash was used for the repayment of $96 million of debt issued to
finance the Comprehensive Settlement (see Note 4 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
at SoCalGas.
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.
STOCK PURCHASES AND REDEMPTION
In 1996, the Board of Directors authorized the redemption of up to 4.25
million shares of the Company's common stock, representing approximately 5%
of the outstanding shares. The Company has repurchased 1,539,700 shares and
816,000 shares under this program for the years ended December 31, 1997 and
1996, respectively. During 1997, the Company paid approximately $48 million
to repurchase shares under the program. Prior to the completion of the
business combination with Enova, the repurchase program will be terminated.
The Company redeemed $210 million of variable dividend rate remarketed
preferred stocks in 1996, of which $100 million was issued by SoCalGas. In
1995, $30 million of preferred stock was redeemed.
On February 2, 1998, SoCalGas redeemed all outstanding shares of its 7 3/4%
Series Preferred Stock at a cost of $25.09 per share, or $75.3 million
including accrued dividends.
DIVIDENDS
In 1997, the Company paid dividends of $122 million on common stock and $4
million on preferred stock for a total of $126 million. This compares to $123
million in 1996 and $121 million in 1995. The increases in 1997 and 1996 were
primarily due to increases in the quarterly common stock dividend amount in
the second quarter of 1997 and 1996, partially offset by a reduction in the
number of shares outstanding.
pacific enterprises 21.
<PAGE>
[chart]
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTINUED)
The quarterly dividend rate was increased from $.34 per share to $.36 per
share in the second quarter of 1996, and to $.38 per share in the second
quarter of 1997. The increase in the quarterly common dividend resulted in an
increase in common dividends paid to $1.50 per share in 1997 from $1.42 per
share in 1996.
CAPITALIZATION
The debt to capitalization ratio was 51% at year-end 1997, slightly below the
52% ratio in 1996.
The debt to capitalization ratio increased to 52% in 1996 from 50% in 1995
due to a reduction in equity from the redemption of preferred stock and
repurchase of common stock, partially offset by the repayment of debt.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents were $153 million at December 31, 1997, of which
$151 million was at PEholding company (Parent). This cash is available for
investment in energy-related domestic and international projects, repurchase
of common and preferred stock, the retirement of debt and other corporate
purposes.
The Company anticipates that cash required in 1998 for capital
expenditures, dividends, debt payments and merger-related costs will be
provided by cash generated from operating activities and existing cash
balances.
In addition to cash from ongoing operations, the Parent and SoCalGas have
multi-year credit agreements that permit term borrowing of up to $950
million. At December 31, 1997, all bank lines of credit were unused. For
further discussion, see Note 8 of Notes to Consolidated Financial Statements.
RESULTS OF CONSOLIDATED OPERATIONS
Consolidated operations include SoCalGas, Energy Management Services, Pacific
Enterprises International, Parent and Other.
The following table shows the effect of nonrecurring events on reported
results:
<TABLE>
<CAPTION>
Year Ended December 31
----------------------------------
1997 1996 1995
- -------------------------------------------------------------------
<S> <C> <C> <C>
Reported earnings
per share- basic $ 2.22 $ 2.37 $ 2.12
Nonrecurring events:
Contract settlement
charges .05
Litigation settlement
benefits (.19)
Merger-related expenses .19 .05
Unamortized discount .03
----------------------------------
Adjusted earnings
per share $ 2.41 $ 2.26 $ 2.17
- -------------------------------------------------------------------
- -------------------------------------------------------------------
</TABLE>
1997 COMPARED TO 1996
Net income for 1997 decreased to $184 million, or $2.22 per share of common
stock, compared to net income of $203 million, or $2.37 per share, in 1996.
Nonrecurring expenses relating to the merger with Enova were $16 million
and $4 million, after-tax, for 1997 and 1996, respectively. These
nonrecurring expenses primarily consist of investment banking, legal,
regulatory and consulting fees. Merger-related expenses for 1997 include a $4
million after-tax loss on the sale of small electric generating facilities at
EMS.
Also contributing to lower net income for 1997 when compared to 1996 was
the absence of favorable litigation settlements totaling $16.1 million,
after-tax, or $.19 per share. One settlement was from gas producers for $5.6
million, after-tax, for damages incurred to Company and customer equipment as
a result of impure gas supplies. The other settlement reflects the resolution
of environmental insurance claims, which benefited earnings by $10.5 million,
after-tax.
Net income also was negatively affected in 1997 by start-up costs and
increased operating expenses related to energy products and services offered
by EMS' joint venture, Sempra Energy Solutions. Sempra Energy Solutions is
not expected to be profitable during 1998. Lower net income at EMS also
resulted from the sale of the small electric generating facilities, effective
June 30, 1997.
Partially offsetting the lower consolidated net income in 1997 was an
increase in SoCalGas' net income from 1996. This increase was primarily due
to increased throughput to utility electric generation (UEG) customers and
lower operating and maintenance expenses than amounts authorized in rates.
The performance based regulation decision that went into effect on August 1,
1997, resulted in a rate reduction to customers (see additional discussion in
"Ratemaking Procedures"). This lower margin partially offset the higher
SoCalGas net income effects previously described.
The weighted average number of shares of common stock outstanding
decreased 2% in 1997, to 81.4 million shares from 82.6 million shares in
1996, due primarily to the repurchase of 1.5 million shares in 1997.
Book value per share increased to $17.13 from $16.58, primarily due to net
income earned in 1997, net of common and preferred dividends paid, and a
decrease in the number of shares outstanding.
1996 COMPARED TO 1995
Net income for 1996 increased to $203 million, or $2.37 per share of
common stock, compared to net income of $185 million, or $2.12 per share in
1995.
Net income for 1996 included net benefits of $12.1 million, after-tax,
from nonrecurring items previously discussed.
Net income also benefited from lower operating and maintenance expenses at
SoCalGas and lower interest expense than was authorized in rates. Interest
expense in 1996 was reduced from its 1995 level as a result of the lower
long-term debt balance maintained throughout the year and the redemption of
$67 million of Swiss Franc bonds. This was partially offset by higher general
and administrative expenses at PEI and EMS, a reduction in the authorized
return on equity for SoCalGas to 11.6% from 12% and
pacific enterprises 22.
<PAGE>
[chart]
lower noncore revenues at SoCalGas as a result of decreased UEG
transportation volumes (for further discussion see "SoCalGas Operations").
Results for 1995 included a nonrecurring charge of $3.8 million,
after-tax, for the resolution of certain power sales contract issues at EMS.
The weighted average number of shares of common stock outstanding
increased to 82.6 million in 1996 from 82.3 million in 1995.
Book value per share increased to $16.58 in 1996 from $15.71 in 1995. The
increase primarily was due to net income earned in 1996 net of common and
preferred dividends.
SOCALGAS OPERATIONS
MARKETS
SoCalGas markets are comprised of core and noncore customers. There are
approximately 4.8 million core customers (4.6 million residential and 200,000
small commercial and industrial). The noncore market consists of
approximately 1,600 customers, which includes eight UEG and four wholesale
customers, with the remainder being large commercial and industrial
customers. Most noncore customers procure their own gas (delivered through
the SoCalGas distribution system) rather than purchase gas from SoCalGas.
Although the revenues from transportation throughput are less than for gas
sales, SoCalGas generally earns the same margin whether it buys the gas and
sells it to the customer or transports gas already owned by the customer. For
1998, approximately 88% of the total margin authorized is contributed by the
core market, with 12% contributed by the noncore market.
RATEMAKING PROCEDURES
To understand the operations and financial results of SoCalGas, it is
important to understand the ratemaking procedures that SoCalGas follows.
SoCalGas 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 SoCalGas'
application for performance based regulation (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, SoCalGas 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 SoCalGas
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.
The Commission's PBR decision established the following rules for SoCalGas:
- - 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, SoCalGas 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 SoCalGas 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 Transactions Decision. For further discussion see Note 4
of Notes to Consolidated Financial Statements.
pacific enterprises 23.
<PAGE>
[chart]
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTINUED)
SoCalGas 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 SoCalGas' 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 4 of Notes to Consolidated Financial Statements.
The GCIM compares SoCalGas' cost of gas with the average market price of
30-day firm spot supplies delivered to the SoCalGas service area. The
mechanism permits full recovery of all costs within a "tolerance band"
above and 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, SoCalGas 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.
1995-1997 FINANCIAL RESULTS
Key financial and operating data for SoCalGas are highlighted in the
following table:
<TABLE>
<CAPTION>
Year Ended December 31
---------------------------------
(Dollars in millions) 1997 1996 1995
-------------------------------------------------------------------
<S> <C> <C> <C>
Operating revenues $ 2,641 $ 2,422 $ 2,279
Cost of gas $ 1,088 $ 923 $ 737
Operating expenses $ 712 $ 725 $ 760
Income from operations
before interest and taxes $ 492 $ 431 $ 451
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.
SoCalGas' 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.
SoCalGas' 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 SoCalGas, excluding fixed pipeline charges, to $2.58
per thousand cubic feet compared to $1.88 per thousand cubic feet in 1996.
SoCalGas' operating 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 operating 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 electric utility industry. The charge was needed
because SoCalGas anticipated that throughput to noncore UEG customers would
be below the levels projected in 1993 at the time of the Comprehensive
Settlement (see Note 4 of Notes to Consolidated Financial Statements).
Consequently, SoCalGas 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 Company
established a liability for this issue and therefore this charge had no
effect on consolidated net income.
1996 COMPARED TO 1995
SoCalGas' operating revenues increased $143 million in 1996 compared to
1995. The increase was primarily due to an increase in the cost of gas in
1996 compared to 1995. 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 billion cubic feet (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.
SoCalGas' cost of gas distributed increased $186 million in 1996
compared to 1995, due primarily to an increase in the average unit cost of
gas. The average commodity cost of gas purchased by SoCalGas, excluding
fixed charges for 1996, was $1.88 per thousand cubic feet, compared to
$1.42 per thousand cubic feet in 1995.
pacific enterprises 24.
<PAGE>
[chart]
SoCalGas' operating expenses decreased $35 million in 1996 compared to
1995. The decrease was primarily due to the nonrecurring favorable
settlements from gas producers and environmental insurance claims totaling
$28 million and also reflects savings as a result of SoCalGas' continued
improvements in efficiency and management's close control of expenses.
Net income decreased $10 million in 1996 compared to 1995, primarily due
to the nonrecurring non-cash charge of $26.6 million previously discussed.
The decline in 1996 earnings was partially offset by the effects of the
nonrecurring favorable settlements and lower operating costs.
OPERATING RESULTS
The table below summarizes the components of SoCalGas' throughput and rates
charged to customers for the past three years. Rates include the customer
portion of the Comprehensive Settlement (see Note 4 of Notes to
Consolidated Financial Statements) of $98 million, $90 million, and $84
million, for 1997, 1996 and 1995, respectively.
Throughput, the total gas sales and transportation volumes moved through
SoCalGas' system, increased in 1997, primarily because of higher demand for
electricity from gas-fired electric generation. The decrease in throughput
in 1996 from 1995 was a result of abundant inexpensive hydro-electricity
resulting from high levels of precipitation the previous winter.
FACTORS INFLUENCING FUTURE PERFORMANCE
Performance of the Company in the near future will primarily depend on the
results of SoCalGas. 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. These factors are summarized below.
- - 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.
SoCalGas 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.
<TABLE>
<CAPTION>
Gas Sales Transportation & Exchange Total
(Dollars in millions, ---------------------- ------------------------- ----------------------
volumes in billion cubic feet) Throughput Revenue Throughput Revenue Throughput Revenue
- ------------------------------------------------------------------------------------------------------------------
<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>
pacific enterprises 25.
<PAGE>
[chart]
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTINUED)
- - 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 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. For further discussion of the key elements of
the CPUC decision, see Note 4 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 PE/Enova merger proceeding, the
Company and Enova jointly filed their comments regarding the impact of the
Affiliate Transaction Decision on the original estimate of merger synergies.
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 PE/Enova merger proceeding.
- - ALLOWED RATE OF RETURN. For 1998, SoCalGas 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. SoCalGas 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 SoCalGas 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 SoCalGas' 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 SoCalGas' 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 SoCalGas' 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" (SFAS 121) 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 SoCalGas may be adversely 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 SoCalGas' 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. SoCalGas' throughput to enhanced oil recovery (EOR)
customers in the Kern County area has decreased significantly since 1992
because of the bypass of SoCalGas' system by competing interstate pipelines.
The decrease in revenues from EOR customers did not have a material impact
on SoCalGas' earnings.
Bypass of other markets also may occur, and SoCalGas 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. SoCalGas is continuing to reduce its
costs to maintain cost competitiveness to retain transportation customers.
- - NONCORE PRICING. To respond to bypass, SoCalGas 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 SoCalGas to
better compete with new interstate pipelines for noncore customers.
pacific enterprises 26.
<PAGE>
[chart]
- - NONCORE THROUGHPUT. SoCalGas' 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 SoCalGas' system and a downturn in general
economic conditions. In addition, many noncore customers are especially
sensitive to the price relationship between natural gas and alternate fuels,
as they are capable of readily switching from one fuel to another, subject
to air quality regulations. SoCalGas is at risk for the lost revenue.
Through July 31, 1999, any favorable earnings effect of higher revenues
resulting from higher throughput to noncore customers has been limited as a
result of the Comprehensive Settlement (see Note 4 of Notes to Consolidated
Financial Statements).
- - EXCESS INTERSTATE PIPELINE CAPACITY. Existing interstate pipeline capacity
into California exceeds current demand by over one billion cubic feet (Bcf)
per day. This situation has reduced the market value of the capacity well
below the Federal Energy Regulatory Commission's (FERC) tariffs. SoCalGas
has exercised its step-down option on both the El Paso and Transwestern
systems, thereby reducing its firm interstate capacity obligation from 2.25
Bcf per day to 1.45 Bcf per day.
FERC-approved settlements have resulted in a reduction in the costs that
SoCalGas 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, SoCalGas' 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.
- - ENVIRONMENTAL MATTERS. SoCalGas' 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 of 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, SoCalGas believes that
compliance with these laws will not have a significant impact on its
financial statements. For further discussion of environmental matters, see
Note 6 of Notes to Consolidated Financial Statements.
- - UNION CONTRACT. Most field, clerical and technical employees of SoCalGas
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 SoCalGas markets is largely dependent on the
health and expansion of the southern California economy. SoCalGas 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.
ENERGY MANAGEMENT SERVICES
Energy Management Services operates a number of domestic business ventures,
including Sempra Energy Solutions, the joint venture with Enova,
established in 1997. Sempra Energy Solutions primarily focuses on providing
new energy products and services, and marketing natural gas. EMS also
includes Pacific Interstate Company (PIC), an interstate pipeline
subsidiary, and a subsidiary which operates centralized heating and cooling
plants for commercial buildings. PIC purchases gas from producers in Canada
and from federal waters offshore California and transports it for sale to
SoCalGas and others. Of the gas purchased by PIC, 90% was sold to SoCalGas
in 1997. These deliveries accounted for approximately 29% of the total
volume of gas purchased by SoCalGas and approximately 10% of SoCalGas'
throughput.
In September 1997, the Company sold its interest in several small
electric generating facilities. The net investment in these assets was $77
million at June 30, 1997, the effective date of the sale.
Net losses of EMS for 1997 were $5 million compared to net income of $6
million in 1996. The decrease in earnings is primarily due to start-up costs
incurred by Sempra Energy Solutions and income lost due to the sale of the
small electric generating facilities. EMS is not expected to be profitable
in 1998.
Net income of EMS for 1996 decreased to $6 million compared to $8 million
in 1995. The decrease was primarily due to start-up costs of several new
products and services launched during 1996.
pacific enterprises 27.
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTINUED)
PACIFIC ENTERPRISES INTERNATIONAL
Pacific Enterprises International was established to participate in the
international natural gas infrastructure market and began operations in March
1995.
Net losses were $8 million in 1997 compared to $5 million in 1996. The
increase in net loss was primarily due to increased expenditures for project
costs related to bids for various international natural gas systems.
On August 12, 1996, PEI and two partners were awarded Mexico's first
privatization license, allowing the consortium to build and operate a natural
gas distribution system in Mexicali, Baja California. The franchise was
awarded to Distribuidora de Gas Natural de Mexicali S. de R.L. de C.V. (DGN),
a Mexican company formed by PEI, Enova International (a subsidiary of Enova
Corporation) and Proxima Gas. DGN will invest approximately $20 million to
$25 million during an initial five-year period to provide service to more
than 25,000 commercial, industrial and residential users. PEI has a 30%
interest in the consortium and invested approximately $2 million and $1
million in the Mexicali project during 1997 and 1996, respectively. In August
1997, the system began distributing natural gas primarily to commercial
customers in Mexicali, and by December daily throughput reached 5.3 million
cubic feet.
In 1997, DGN was awarded a license to build and operate a natural gas
pipeline in Chihuahua, a city of almost 630,000 people in northern Mexico.
DGN began construction in late 1997 and will invest $50 million in the first
five years of operation. PEI's share in this project is 47.5% and it invested
$5 million during 1997.
Other international projects are currently under evaluation in Latin
America and the Pacific Rim. PEI is not expected to be profitable in 1998.
PARENT COMPANY AND OTHER
The Parent is a holding company which provides support services to its
subsidiaries and joint ventures.
Expenses were higher in 1997 due to costs related to the merger with Enova
Corporation. Merger-related costs of $16 million and $4 million, after-tax,
for 1997 and 1996, respectively, primarily consist of investment banking,
legal, regulatory and consulting fees. Merger costs for 1997 include a $4
million after-tax loss on the sale of the small electric generating
facilities.
Expenses were lower in 1996 compared to 1995 due to the savings realized
from the reorganization of the Company into business units which was
completed in July 1995. In addition, 1995 expenses include costs related to
this reorganization. The savings were partially offset by expenses related to
the proposed merger with Enova.
OTHER INCOME, INTEREST EXPENSE AND INCOME TAXES
OTHER INCOME
Other income, which primarily consists of interest income from short-term
investments and regulatory accounts receivable balances, increased in 1997 to
$39 million from $25 million in 1996. The increase was due to higher interest
from short-term investments at the Parent during much of 1997 because foreign
investments were lower than anticipated.
Other income decreased in 1996 to $25 million from $34 million in 1995.
Short-term investment income decreased at both SoCalGas and the Parent. The
decrease at SoCalGas was 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. The decrease in short-term investments at the Parent
was due to cash outflows for the $49 million investment into PEI for the
purchase of the Argentina utility holding companies and $110 million for the
preferred stock redemption.
INTEREST EXPENSE
Interest expense for 1997 increased only slightly to $103 million from $97
million in 1996. Interest expense for 1996 decreased to $97 million from $108
million in 1995. Interest expense was reduced from its 1995 level as a result
of the lower long-term debt balance maintained throughout the year and the
redemption of $67 million of Swiss Franc bonds.
INCOME TAXES
Income tax expense for 1997 was $151 million, unchanged from 1996. The
effective income tax rates were 45% and 43% for 1997 and 1996, respectively.
Income tax expense was unchanged for 1997, despite lower earnings, due to
fewer deductions from capitalized information systems costs at SoCalGas.
Income tax expense for 1996 increased to $151 million from $129 million in
1995. The increase of $22 million was primarily due to an increase in
earnings before taxes to $354 million in 1996 from $314 million in 1995.
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.
pacific enterprises 28.
<PAGE>
INTEREST RATE RISK
SoCalGas has historically funded utility 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.
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 employs 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
SoCalGas 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. SoCalGas 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
SoCalGas, 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, SoCalGas has established
fixed price and basis position limits. Volumetric limits define the maximum
position exposure each management level within SoCalGas 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.
SoCalGas 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 SoCalGas 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
SoCalGas management and the Company'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.
SEMPRA ENERGY TRADING CORP.
Sempra Energy Trading Corp. derives a substantial portion of its revenue from
trading activities in natural gas, petroleum and electricity. Trading profits
are earned as Sempra Energy Trading acts as a dealer in structuring and
executing transactions that permit its counterparties to manage their risk
profiles. In addition, Sempra Energy Trading takes positions in energy
markets based on the expectation of future market conditions. These positions
may be offset with similar positions or may be offset in the exchange traded
markets. These positions include options, forwards, futures and swaps.
Market risk arises from the potential change in the value of financial
instruments and physical commodities based on fluctuations in natural gas,
petroleum and electricity commodity exchange prices and basis. Market risk is
also affected by changes in volatility and liquidity in markets in which
these instruments are traded. A Risk Management Committee, composed of the
Company's and Enova's Officers, is responsible for monitoring operating
performance and
pacific enterprises 29.
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS (CONTINUED)
compliance with established risk management policies. Sempra Energy Trading
has established position and stop-loss limits for each line of business to
monitor its market risk and traders are required to maintain positions within
these market risk limits. The position limits are monitored during the day by
Sempra Energy Trading's senior management, who determine whether to adjust
the company's market risk profile.
Credit risk is the risk that a counterparty will fail to perform its
contractual obligations. Sempra Energy Trading maintains credit policies and
systems to minimize overall credit risk. These policies include an evaluation
of potential counterparties' financial condition, and the use, when
appropriate, of standardized agreements that allow for the netting of
positive and negative exposures associated with a single counterparty and
collateral requirements. Sempra Energy Trading monitors credit risk exposure
through an approval process and the assignment of credit limits. These credit
limits are established based on risk and return considerations under terms
customarily available in the industry.
Sempra Energy Trading utilizes financial instruments which include
futures, exchange traded and over-the-counter options, and commodity swaps
and forwards. The fair values of Sempra Energy Trading's financial
instruments and related balance sheet items are subject to change as a result
of potential market changes in commodity prices. All of Sempra Energy
Trading's market risk sensitive instruments are entered into for trading
purposes. The following table provides the potential changes in net principal
transaction revenues resulting from hypothetical 10% increases and 10%
decreases in the applicable commodity prices for significant commodity
market-price sensitive instruments held on December 31, 1997. This
quantitative information about market risk is limited because it does not
take into account potential hedging transactions or changes to the market
risk profile of the portfolio by management in reaction to such changes in
market conditions. Additionally, it does not take into account anticipated
management reaction to breaches of counterparty credit limitations caused by
the shocks within a given risk category. (See the discussion on the
management of credit risk above.) Further, inherent limitations arise from
assuming that hypothetical 10% increases and 10% decreases in commodity
prices move in the same direction and this information does not recognize
co-movements in prices.
The following table presents the impact on Sempra Energy Trading's net
principal transaction revenues resulting from a 10% increase and a 10%
decrease in the respective December 31, 1997 commodity price:
<TABLE>
<CAPTION>
(Dollars in thousands)
- --------------------------------------------------------------------
Commodity 10% Increase 10% Decrease
- --------------------------------------------------------------------
<S> <C> <C>
Crude oil and derivatives $ 3,288 $ (3,288)
Natural Gas (2,441) 2,441
Emission credits (81) 81
Electricity (540) 540
- --------------------------------------------------------------------
- --------------------------------------------------------------------
</TABLE>
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 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 $30 million over the life of the
project.
INFORMATION REGARDING FORWARD LOOKING STATEMENTS
This Annual Report contains forward-looking statements with respect to
matters inherently involving various 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 the Company. Accordingly, while the Company
believes these assumptions are reasonable, there can be no assurance that
they will approximate actual experience, or that the expectations will be
realized.
pacific enterprises 30.
<PAGE>
CONSOLIDATED STATEMENT OF INCOME
<TABLE>
<CAPTION>
Year Ended December 31
-------------------------------
(Dollars in millions, except share and per-share amounts) 1997 1996 1995
- -------------------------------------------------------------------------------------------
<S> <C> <C> <C>
REVENUES AND OTHER INCOME
Operating Revenues $ 2,738 $ 2,563 $ 2,343
Other 39 25 34
-------------------------------
Total 2,777 2,588 2,377
-------------------------------
EXPENSES
Cost of Gas Distributed 1,059 866 682
Operating Expenses 918 910 920
Depreciation and Amortization 256 255 243
Franchise Payments and Other Taxes 99 98 98
Preferred Dividends of a Subsidiary 7 8 12
-------------------------------
Total 2,339 2,137 1,955
-------------------------------
Income from Operations Before
Interest and Income Taxes 438 451 422
Interest 103 97 108
-------------------------------
Income from Operations Before Income Taxes 335 354 314
Income Taxes 151 151 129
-------------------------------
Net Income 184 203 185
Dividends on Preferred Stock 4 5 10
Preferred Stock Original Issue Discount 2
-------------------------------
Net Income Applicable to Common Stock $ 180 $ 196 $ 175
-------------------------------
Net Income Per Share of Common Stock:
Basic $ 2.22 $ 2.37 $ 2.12
-------------------------------
Diluted $ 2.21 $ 2.36 $ 2.12
-------------------------------
Common Dividends Declared Per Share $ 1.50 $ 1.42 $ 1.34
WEIGHTED AVERAGE NUMBER OF SHARES OF COMMON STOCK -------------------------------
OUTSTANDING (IN THOUSANDS) 81,354 82,626 82,265
- -------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
pacific enterprises 31.
<PAGE>
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
December 31
------------------
(Dollars in millions) 1997 1996
- ------------------------------------------------------------------------
<S> <C> <C>
ASSETS
Current Assets:
Cash and cash equivalents $ 153 $ 256
Accounts receivable--trade
(less allowance for doubtful receivables
of $19 in 1997 and 1996) 480 401
Accounts and notes receivable--other 50 80
Income taxes receivable 3 58
Deferred income taxes 9
Gas in storage 25 28
Other inventories 16 22
Regulatory accounts receivable--net 355 285
Prepaid expenses 21 22
------------------
Total current assets 1,103 1,161
------------------
Investments and Other Assets:
Other investments 191 115
Other receivables 62 16
Regulatory assets 394 552
Other assets 73 105
------------------
Total investments and other assets 720 788
------------------
Property, Plant and Equipment 6,097 6,080
Less accumulated depreciation and amortization 2,943 2,843
------------------
Total property, plant and equipment--net 3,154 3,237
------------------
Total assets $4,977 $5,186
- ------------------------------------------------------------------------
- ------------------------------------------------------------------------
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
pacific enterprises 32.
<PAGE>
CONSOLIDATED BALANCE SHEET
<TABLE>
<CAPTION>
December 31
----------------------
(Dollars in millions) 1997 1996
- ----------------------------------------------------------------------------
<S> <C> <C>
LIABILITIES
Current Liabilities:
Short-term debt $ 354 $ 262
Accounts payable--trade 133 241
Accounts payable--other 304 336
Other taxes payable 30 29
Deferred income taxes 7
Long-term debt due within one year 148 149
Accrued interest 52 41
Other 87 80
----------------------
Total current liabilities 1,115 1,138
----------------------
Long-Term Debt:
Long-term debt 988 1,095
Debt of Employee Stock Ownership Plan 130 130
----------------------
Total long-term debt 1,118 1,225
----------------------
Deferred Credits and Other Liabilities:
Long-term liabilities 183 166
Customer advances for construction 34 42
Postretirement benefits other than pensions 217 224
Deferred income taxes 272 321
Deferred investment tax credits 61 64
Other deferred credits 413 471
Commitments and Contingent Liabilities (Note 6)
----------------------
Total deferred credits and other liabilities 1,180 1,288
----------------------
Preferred Stocks of a Subsidiary 95 95
----------------------
SHAREHOLDERS' EQUITY
Capital Stock:
Preferred 80 80
Common 1,064 1,095
----------------------
Total capital stock 1,144 1,175
Retained earnings, after elimination of
accumulated deficit of $452 million against
common stock at December 31, 1992 as part
of the quasi-reorganization 372 314
Less deferred compensation relating to
Employee Stock Ownership Plan (47) (49)
----------------------
Total shareholders' equity 1,469 1,440
----------------------
Total liabilities and shareholders' equity $4,977 $5,186
- ----------------------------------------------------------------------------
- ----------------------------------------------------------------------------
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
pacific enterprises 33.
<PAGE>
STATEMENT OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31
-------------------------------------------
(Dollars in millions) 1997 1996 1995
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Cash Flows from Operating Activities
Net Income $ 184 $ 203 $ 185
Adjustments to Reconcile Net Income to
Net Cash Provided by (Used in)
Operating Activities:
Depreciation and amortization 256 255 243
Deferred income taxes (35) 33 71
Other-net (15) 13 (3)
Net change in other working capital components (40) 104 202
-------------------------------------------
Net cash provided by operating activities 350 608 698
-------------------------------------------
Cash Flows from Investing Activities
Expenditures for Property, Plant and Equipment (187) (204) (240)
Acquisition of Sempra Energy Trading (112)
Increase in Foreign Investments (7) (50)
Increase in Other Investments (19) (12) (2)
Proceeds from Disposition of Properties 20 2
(Increase) Decrease in Other Receivables,
Regulatory Assets and Other Assets 42 (20) 2
-------------------------------------------
Net cash used in investing activities (263) (286) (238)
-------------------------------------------
Cash Flows from Financing Activities
Sale of Common Stock 17 8 6
Repurchase of Common Stock (48) (24)
Redemption of Preferred Stock (110) (30)
Redemption of Preferred Stock of a Subsidiary (100)
Increase in Long-Term Debt 120 75
Decrease in Long-Term Debt (245) (172) (207)
Increase (Decrease) in Short-Term Debt 92 29 (44)
Common and Preferred Dividends (126) (123) (121)
Net cash used in financing activities (190) (417) (396)
-------------------------------------------
Increase (Decrease) in Cash and Cash Equivalents (103) (95) 64
Cash and Cash Equivalents, January 1 256 351 287
-------------------------------------------
Cash and Cash Equivalents, December 31 $ 153 $ 256 $ 351
- -------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
pacific enterprises 34.
<PAGE>
STATEMENT OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
Year Ended December 31
-------------------------------------------
(Dollars in millions) 1997 1996 1995
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Changes in Other Working Capital Components
(Excluding cash and cash equivalents,
short-term debt and long-term debt
due within one year)
Current Assets:
Receivables $ (34) $ (58) $ 114
Income taxes receivable 55 12 (30)
Deferred income taxes 11 (42)
Inventories 5 27 22
Regulatory accounts receivable-net 25 46 198
Other 2 16 2
------------------------------------------
Total 53 54 264
------------------------------------------
Current Liabilities:
Accounts payable (139) 53 7
Deferred income taxes 26
Other taxes payable 2 (18) (6)
Other 18 15 (63)
------------------------------------------
Total (93) 50 (62)
------------------------------------------
Net change in other working
capital components $ (40) $ 104 $ 202
------------------------------------------
Supplemental Disclosure of Cash Flow Information
Cash Paid During the Year for:
Interest (net of amount capitalized) $ 92 $ 100 $ 101
Income taxes $ 112 $ 92 $ 129
Supplemental Schedule of Non-Cash Investing and
Financing Activities
The Company sold the assets of several small electric
generation plants. In conjunction with the sale,
a note receivable was assumed as follows:
Fair value of the assets sold $ 77
Cash received (20)
Loss on sale (6)
-----
Note receivable $ 51
-----
- -------------------------------------------------------------------------------------------------
- -------------------------------------------------------------------------------------------------
</TABLE>
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
pacific enterprises 35.
<PAGE>
STATEMENT OF CONSOLIDATED SHAREHOLDERS' EQUITY
<TABLE>
<CAPTION>
Deferred
Compensation
Relating to
Preferred Stock Common Stock Employee
----------------- ------------------ Stock Total
Years Ended December 31, 1997, 1996, and 1995 Number of No par Number of No par Retained Ownership Shareholders'
(Dollars in millions) shares value shares value Earnings Plan Equity
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C>
Balances at December 31, 1994 1,101,453 $218 82,111,263 $1,092 $172 $(54) $1,428
Net Income 185 185
Cash Dividends Declared:
Preferred stock (10) (10)
Common stock (111) (111)
Common Stock Sold 232,310 6 6
Quasi-Reorganization Adjustment 13 13
Redemption of Preferred Stock (300,100) (30) (30)
Common Stock Released from ESOP 103,098 2 2
- -----------------------------------------------------------------------------------------------------------------------------------
Balances at December 31, 1995 801,353 188 82,446,671 1,111 236 (52) 1,483
Net Income 203 203
Cash Dividends Declared:
Preferred stock (5) (5)
Common stock (118) (118)
Common Stock Sold 292,108 8 8
Common Stock Repurchased (816,000) (24) (24)
Redemption of Preferred Stock (1,100) (108) (2) (110)
Common Stock Released from ESOP 90,690 3 3
- -----------------------------------------------------------------------------------------------------------------------------------
Balances at December 31, 1996 800,253 80 82,013,469 1,095 314 (49) 1,440
Net Income 184 184
Cash Dividends Declared:
Preferred stock (4) (4)
Common stock (122) (122)
Common Stock Sold 536,862 17 17
Common Stock Repurchased (1,539,700) (48) (48)
Common Stock Released from ESOP 92,818 2 2
- -----------------------------------------------------------------------------------------------------------------------------------
Balances at December 31, 1997 800,253 $ 80 81,103,449 $1,064 $372 $(47) $1,469
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
THE NUMBER OF SHARES OF COMMON STOCK AUTHORIZED AT DECEMBER 31, 1997 AND 1996
IS 600,000,000. THE NUMBER OF SHARES OF PREFERRED STOCK AND CLASS A PREFERRED
STOCK AUTHORIZED AND OUTSTANDING AT DECEMBER 31, 1997 AND 1996 IS SET FORTH
IN NOTE 12 OF NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
SEE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS.
pacific enterprises 36.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. MERGER AGREEMENT WITH ENOVA CORPORATION
On October 14, 1996, Pacific Enterprises (the Company) 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 Company and Enova announced that the name of the new company will be
Sempra Energy.
As a result of the combination, the Company 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 Company'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, Southern California Gas
Company (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. The merger could
result in a net savings of $1.1 billion in synergies and cost avoidances over
a 10-year period for Sempra Energy. In the interim, the Company and Enova
have formed a joint venture named Sempra Energy Solutions to provide
integrated energy and energy-related products and services.
For a portion of 1997, the Company owned indirect interests in several
small electric generation facilities considered to be "qualifying facilities"
(QF) under the Public Utility Regulatory Policies Act. Qualifying facility
status is not available to any facilities that are more than 50% owned by an
electric utility or an electric utility holding company.
Because some of the plants already were owned in partnership with an
electric utility, they would have lost their QF status upon completion of the
merger. In September 1997, the Company sold all its small electric generation
plants, resulting in an after-tax loss on the sale of approximately $4
million.
In connection with the merger, costs of $16 million and $4 million,
after-tax, for 1997 and 1996 respectively, were incurred and charged to
expense. The merger costs and expenses consisted primarily of legal,
accounting, and investment banking fees. The merger-related expense for 1997
includes the $4 million after-tax loss on the sale of the qualifying
facilities.
Sempra Energy is incorporated in California and, as an intrastate holding
company, will be exempt from substantially all of the Public Utility Holding
Company Act except for provisions requiring Security and Exchange Commission
approval for acquisitions of utility stock of additional utilities.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include the accounts of all
subsidiaries of the Company. Investments in 50%-or-less owned joint ventures
and partnerships are accounted for by the equity method 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), SoCalGas'
accounting policies reflect the financial effects of rate regulation
authorized by the CPUC. Interstate natural gas transmission subsidiaries
follow accounting policies authorized by FERC.
The regulated subsidiaries apply 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, assets which are being recovered
or are probable of recovery through customer rates. As of December 31, 1997,
the Company had $394 million of regulatory
pacific enterprises 37.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
assets which included the following: costs of reacquiring debt of $43
million; postretirement benefit costs (See Note 13) of $194 million; deferred
income taxes of $66 million (See Note 5); and other costs of $91 million.
Maintenance of the regulatory assets and regulatory accounts receivable
represents the only difference in the application of GAAP for the utility
versus non-regulated entities.
REGULATORY ACCOUNTS RECEIVABLE -- NET
Authorized regulatory balancing accounts are maintained to accumulate
undercollections and overcollections from the revenue and cost estimates
adopted by the CPUC in setting rates. SoCalGas makes periodic filings with
the CPUC to adjust future gas rates to account for such variances.
INVENTORIES
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 SoCalGas, 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.
PROPERTY, PLANT AND EQUIPMENT
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. ACQUISITION OF AIG TRADING CORPORATION
On December 31, 1997, the Company and Enova jointly completed their
acquisition, with each acquiring a 50% interest, of Sempra Energy Trading
Corp. (formerly AIG Trading Corporation), a leading natural gas and power
marketing firm headquartered in Greenwich, Connecticut, for a total cost of
$225 million.
Sempra Energy Trading's primary business focus is wholesale trading
and marketing of natural gas, power and oil to customers primarily in North
America. Sempra Energy Trading had net assets of $30 million at December 31,
1997.
An allocation of the purchase price has not yet been completed. Any
difference between the cost and underlying equity in the net assets will be
amortized over a period of not more than 15 years.
pacific enterprises 38.
<PAGE>
As of December 31, 1997, Sempra Energy Trading's trading assets and
trading liabilities approximate the following:
<TABLE>
<CAPTION>
(Dollars in millions) 1997
- --------------------------------------------------------------------
<S> <C>
Trading Assets:
Unrealized gains on swaps and forwards $ 497
Due from commodity clearing
organization and clearing brokers 41
OTC commodity options purchased 33
Due from trading counterparties 16
------
Total $ 587
------
Trading Liabilities:
Unrealized losses on swaps and forwards $ 487
Due to trading counterparties 41
OTC commodity options written 29
------
Total $ 557
- --------------------------------------------------------------------
- --------------------------------------------------------------------
</TABLE>
The notional amounts of the financial instruments are provided below
and include a maturity profile as of December 31, 1997 based upon the
expected timing of the future cash flows. The notional amounts do not
necessarily represent the amounts exchanged by parties to the financial
instruments and do not measure Sempra Energy Trading's exposure to credit or
market risks. The notional or contractual amounts are used to summarize the
volume of financial instruments but do not reflect the extent to which
positions may offset one another. Accordingly, Sempra Energy Trading is
exposed to much smaller amounts potentially subject to risk.
The Company and Enova have jointly and severally guaranteed certain trade
obligations of Sempra Energy Trading with credit-worthy counterparties in
connection with authorized transactions and in connection with funding. The
total obligations guaranteed by the Company as of December 31, 1997 are $190
million.
4. REGULATORY MATTERS
SoCalGas 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 SoCalGas'
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 of
<TABLE>
<CAPTION>
Notional Amount by Maturity
(Dollars in millions) Within One Year One to Five Years Five to Ten Years After Ten Years Total
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Forwards and commodity swaps $ 3,175 $ 458 $ 90 $ 74 $ 3,797
Futures 856 189 1,045
Options purchased 704 52 756
Options written 592 62 654
----------------------------------------------------------------------------------------
Total $ 5,327 $ 761 $ 90 $ 74 $ 6,252
- -----------------------------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
pacific enterprises 39.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
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, SoCalGas 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 SoCalGas 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.
SoCalGas 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
Proceedings (BCAP) application which is anticipated to become effective on
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 than 150 basis points and are forecasted to
continue to vary by at least 150 basis points for the next year. If this
occurs, there would be an automatic adjustment of rates for the change in the
cost of capital according to a pre-established formula which applies a
percentage of the change to various capital components.
RESTRUCTURING OF GAS SUPPLY CONTRACTS
In 1993, SoCalGas and the Company's gas supply subsidiaries restructured
long-term gas supply contracts with suppliers of California offshore and
Canadian gas. In the past, SoCalGas' cost of these supplies had been
substantially in excess of its average delivered cost of gas for all gas
supplies.
The restructured contracts substantially reduced the ongoing delivered
costs of these gas supplies and provided lump sum payments totaling $391
million to the suppliers. The expiration date for the Canadian gas supply
contract was shortened from 2012 to 2003.
COMPREHENSIVE SETTLEMENT OF REGULATORY ISSUES
On July 20, 1994, the CPUC approved a comprehensive settlement (Comprehensive
Settlement) of a number of pending regulatory issues including rate recovery
of a significant portion of the restructuring costs associated with long-term
gas supply contracts discussed above. The Comprehensive Settlement.permits
SoCalGas to recover in utility rates approximately 80% of the contract
restructuring costs of $391 million and accelerated amortization of related
pacific enterprises 40.
<PAGE>
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 SoCalGas to its customers for
the five-year period commencing August 1, 1994. Rates charged to the
customers are established based upon SoCalGas' recorded throughput to these
customers for 1991. SoCalGas 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 SoCalGas' 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.
* REASONABLENESS REVIEWS. The Comprehensive Settlement includes settlement of
all pending reasonableness reviews with respect to SoCalGas' gas purchases
from April 1989 through March 1992, as well as certain other future
reasonableness review issues.
* GAS COST INCENTIVE MECHANISM. 0n April 1, 1994, SoCalGas implemented a new
process for evaluating SoCalGas' 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 SoCalGas' cost of gas with a benchmark level, which is the
average price of 30-day firm spot supplies delivered to SoCalGas' 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 SoCalGas' purchased 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 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 SoCalGas an
annual allowance for increases in operating and maintenance expenses. In
1996, attrition was calculated on the inflation rate in excess of 3%
authorizing SoCalGas to collect $12 million in rates. No attrition allowance
was authorized for 1997 based on an agreement reached as part of the PBR
application.
pacific enterprises 41.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The Company recorded the impact of the Comprehensive Settlement in 1993.
Upon giving effect to liabilities previously recognized by the Company and
SoCalGas, the costs of the Comprehensive Settlement, including the
restructuring of gas supply contracts, did not result in any additional
charge to the Company's consolidated earnings.
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.
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 PE/Enova merger proceeding, the
Company and Enova jointly filed their comments regarding the impact of the
Affiliate Transaction Decision on the original estimate of merger synergies.
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.
pacific enterprises 42.
<PAGE>
As required by the decision, SoCalGas has filed compliance plans with the
CPUC addressing the Company's implementation of the new rules. In addition,
SoCalGas has filed for exemptions on certain rules as well as petitions for
rehearing which seek revision and clarification on certain aspects of the
rules.
5. INCOME TAXES
A reconciliation of the difference between computed statutory federal income
tax expense and actual income tax expense from operations is as follows:
<TABLE>
<CAPTION>
Year Ended December 31
-------------------------------
(Dollars in millions) 1997 1996 1995
- ---------------------- ------- -------- --------
<S> <C> <C> <C>
Computed statutory federal
income tax expense $117 $124 $110
Increases (reductions)
resulting from:
Depreciation and other
items not deferred
--SoCalGas 23 23 20
Capitalized expenses
not deferred
--SoCalGas (3) (11) (10)
State income taxes
--net of federal
income tax benefit 23 20 20
Investment tax credits (3) (3) (3)
Other--net (6) (2) (8)
--------- -------- ---------
Income tax expense
from operations $151 $151 $129
- ----------------------------------------------------------------------
- ----------------------------------------------------------------------
</TABLE>
The components of income tax expense from operations are as follows:
<TABLE>
<CAPTION>
Year Ended December 31
--------------------------
(Dollars in millions) 1997 1996 1995
- ---------------------- ------ ------ ------
<S> <C> <C> <C>
Federal:
Current $143 $ 68 $ 70
Deferred (22) 51 28
----- ---- -----
121 119 98
----- ---- -----
State:
Current 25 25 32
Deferred 5 7 (1)
----- ---- -----
30 32 31
----- ---- -----
Total:
Current 168 93 102
Deferred (17) 58 27
----- ---- -----
$151 $151 $129
- --------------------------------------------------------
- --------------------------------------------------------
</TABLE>
The principal components of net deferred tax liabilities are as follows:
<TABLE>
<CAPTION>
December 31, 1997
--------------------------------
(Dollars in millions) Assets Liabilities Total
- ---------------------- ------ ----------- -----
<S> <C> <C> <C>
Accelerated depreciation
for tax purposes $(495) $(495)
Comprehensive Settlement $117 117
Regulatory accounts
receivable (161) (161)
Postretirement benefits 81 81
Restructuring costs deferred
for tax purposes 54 54
Deferred investment tax credits 27 27
Customer advances
for construction (14) (14)
Regulatory asset (90) (90)
Other regulatory 157 (47) 110
Other 92 92
----- ------ ------
Total deferred income tax
assets (liabilities) $528 $(807) $(279)
- ----------------------------------------------------------------------
- ----------------------------------------------------------------------
</TABLE>
<TABLE>
<CAPTION>
December 31, 1996
-------------------------------
(Dollars in millions) Assets Liabilities Total
- ---------------------- ------ ----------- -----
<S> <C> <C> <C>
Accelerated depreciation
for tax purposes $(541) $(541)
Comprehensive Settlement $137 (47) 90
Regulatory accounts
receivable (132) (132)
Postretirement benefits 87 87
Restructuring costs deferred
for tax purposes 46 46
Deferred investment tax credits 28 28
Partnership income (35) (35)
Customer advances
for construction 20 20
Regulatory asset (109) (109)
Other regulatory 143 (50) 93
AMT carryforward 24 24
Other 123 (6) 117
---- ----- ------
Total deferred income tax
assets (liabilities) $608 $(920) $(312)
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
</TABLE>
pacific enterprises 43.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Income tax expense recognized for a period is the amount of tax currently
payable adjusted by the change in aggregate deferred tax assets and
liabilities. Deferred taxes are recorded to recognize the future tax
consequences of events that have been recognized in the financial statements
or tax returns. No valuation allowance has been provided for deferred tax
assets since they are expected to be realized through either reversal of
existing temporary differences or future taxable income.
SoCalGas 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, SoCalGas
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.
6. COMMITMENTS AND CONTINGENT LIABILITIES
ENVIRONMENTAL OBLIGATIONS
SoCalGas 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 and its
subsidiaries have been named as potentially responsible parties 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, SoCalGas 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, SoCalGas' estimated remaining investigation and
remediation liability was $72 million, of which 90% is authorized to be
recovered 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.
OTHER COMMITMENTS AND CONTINGENCIES
At December 31, 1997 commitments for capital expenditures were approximately
$16 million.
7. LEASES
The Company and its subsidiaries have 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 or the
subsidiaries.
pacific enterprises 44.
<PAGE>
Rental expense under space operating leases was $56 million, $58 million
and $66 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
(Dollars in millions) Lease Payments
- -----------------------------------------------
<S> <C>
Year Ended December 31:
1998 $ 37
1999 37
2000 37
2001 34
2002 35
Later years 263
-----
Total $443
- -----------------------------------------------
- -----------------------------------------------
</TABLE>
In connection with the quasi-reorganization and loss on disposal of
discontinued operations (see Note 16), the Company established reserves of
$102 million to fairly value operating leases related to its headquarters and
other leases at December 31, 1992. The remaining amount of these reserves was
$79 million at December 31, 1997.
8. COMPENSATING BALANCES AND SHORT-TERM BORROWING ARRANGEMENTS
The Company has a $300 million multi-year credit agreement requiring annual
fees of .07%. SoCalGas has an additional $650 million multi-year credit
agreement requiring annual fees of .07%. The interest rates on these lines
vary and are derived from formulas based on market rates and the companies'
credit ratings. The multi-year credit agreements expire in February 2001. At
December 31, 1997, all bank lines of credit were unused. SoCalGas' lines of
credit provide backing for its commercial paper program.
At December 31, 1997 and 1996, SoCalGas had $351 million and $358
million, respectively, of commercial paper obligations outstanding.
Approximately $94 million of the outstanding commercial paper in 1997 relates
to the restructuring costs associated with certain long-term gas supply
contracts under the Comprehensive Settlement (see Note 4). 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
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.
9. LONG-TERM DEBT
<TABLE>
<CAPTION>
December 31
--------------------
(Dollars in millions) 1997 1996
- --------------------------------------------------------------------
<S> <C> <C>
Southern California Gas Company
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 7, 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
------- -------
1,130 1,253
OTHER
8% - 9.5% 1998-2002 21 7
------- -------
Total 1,151 1,260
------- -------
Less:
Long-term debt due within one year 148 149
Unamortized debt discount
less premium 15 16
------- -------
163 165
------- -------
Long-term debt $ 988 $1,095
- -------------------------------------------------------------------
- -------------------------------------------------------------------
</TABLE>
pacific enterprises 45.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
The annual principal payment requirements of long-term debt, including
debt of the Employee Stock Ownership Plan (ESOP), for the years 1998 through
2002 are $148 million, $207 million, $31 million, $121 million, and $101
million, respectively. Substantially all of utility plant serves as
collateral for the First Mortgage Bonds, and certain assets of the
non-utility subsidiaries are pledged as collateral for their obligations.
DEBT OF EMPLOYEE STOCK OWNERSHIP PLAN AND TRUST
(TRUST) (SEE NOTE 13)
The TRUST covers substantially all employees and is used to partially fund
the Company's retirement savings program. It has an ESOP feature and holds
approximately 2.1 million shares of common stock of the Company. The variable
rate ESOP debt held by the TRUST bears interest at a rate necessary to place
or remarket the notes at par. Principal is due on November 30, 1999 and
interest is payable monthly through 1999. The Company is obligated to make
contributions to the TRUST sufficient to satisfy debt service requirements.
As the Company makes contributions to the TRUST, these contributions, plus
any dividends paid on the unallocated shares of the Company's common stock
held by the TRUST, will be used to repay the debt. As dividends are increased
or decreased, required contributions are reduced or increased, respectively.
Interest on ESOP debt amounted to $6 million in 1997 and 1996, and $7 million
in 1995. Dividends used for debt service amounted to $3 million in each of
the years ended 1997, 1996 and 1995, and are deductible for federal income
tax purposes.
CURRENCY RATE SWAP
In February 1986, SoCalGas issued SFr. 100 million of 5 1/8% bonds maturing on
February 6, 1998. SoCalGas hedged the currency exposure by entering into a
swap transaction with a major international bank. As a result, the bond
issue, interest payments, and other ongoing costs were swapped for fixed
annual payments. The terms of the swap result in a U.S. dollar liability of
$47 million at an interest rate of 9.725%.
10. 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 because of the
relatively short maturity of these instruments. The debt of the ESOP
approximated fair market value as of December 31, 1997 and 1996, based upon
the variable interest rate feature of the debt outstanding.
The fair value of SoCalGas' 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 SoCalGas 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>
Carrying Fair
(Dollars in millions) Amount Value
- ----------------------------------------------------------------
<S> <C> <C>
1997:
Long-Term Debt of SoCalGas $1,115 $1,159
Preferred Stocks of SoCalGas $ 95 $ 94
1996:
Long-Term Debt of SoCalGas $1,237 $1,248
Preferred Stocks of SoCalGas $ 95 $ 92
- ----------------------------------------------------------------
- ----------------------------------------------------------------
</TABLE>
As a result of the GCIM (See Note 4), SoCalGas 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. SoCalGas' 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.
pacific enterprises 46.
<PAGE>
11. PREFERRED STOCKS OF A SUBSIDIARY
The amount of preferred stocks of SoCalGas outstanding at December 31 is as
follows:
<TABLE>
<CAPTION>
Number Millions
of Shares of Dollars
- -------------------------------------------------------------------
<S> <C> <C>
1997:
6%, $25 par value 28,664 $ 1
6% Series A, $25 par value 783,032 19
Series Preferred, no par value
7 3/4%, $25 Stated Value 3,000,000 75
-----
$ 95
-----
1996:
6%, $25 par value 29,361 $ 1
6% Series A, $25 par value 783,032 19
Series Preferred, no par value
7 3/4%, $25 Stated Value 3,000,000 75
-----
$ 95
-----
- -------------------------------------------------------------------
- -------------------------------------------------------------------
</TABLE>
On February 2, 1998, SoCalGas redeemed all outstanding shares of 73/4%
Series Preferred Stock at a total price per share of $25.09. This total price
per share consisted of a redemption price of $25 and $0.09 of unpaid
dividends accruing to the date of redemption. The total cost to SoCalGas was
approximately $75.3 million.
12. PREFERRED STOCK
The number of shares of preferred stock and class A authorized and
outstanding are shown in the table below:
<TABLE>
<CAPTION>
Redemption December 31, 1997 December 31, 1996
------------------------- ------------------------
Price Shares Shares Shares Shares
Per Share Authorized Outstanding Authorized Outstanding
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Preferred stock -- cumulative, no par value:
$4.75 Dividend $100.00 200,000 200,000 200,000 200,000
$4.50 Dividend 100.00 300,000 300,000 300,000 300,000
$4.40 Dividend 101.50 100,000 100,000 100,000 100,000
$4.36 Dividend 101.00 200,000 200,000 200,000 200,000
$4.75 Dividend 101.00 253 253 253 253
Unclassified 9,199,747 9,199,747
---------- ------- --------- -------
Total 10,000,000 800,253 10,000,000 800,253
---------- ------- --------- -------
Class A preferred stock -- cumulative, no par value 5,000,000 5,000,000
- -----------------------------------------------------------------------------------------------------------------
- -----------------------------------------------------------------------------------------------------------------
</TABLE>
All or any part of every series of presently outstanding preferred stock
is subject to redemption at the Company's option at any time upon not less
than 30 days notice, at the applicable redemption prices for each series,
together with the accrued and accumulated dividends to the date of
redemption. None of the outstanding series of preferred stock has any
conversion rights.
At December 31, 1995, the Company had 1,100 shares of Remarketed
Preferred, Series A Stock (RP) outstanding with a liquidation preference of
$100,000 per share. In April 1996, the Company exercised its option to redeem
the RP shares, in whole, at $100,000 per share plus accumulated dividends. In
connection with the redemption of the RP, the Company recorded a $2.4 million
nonrecurring deduction to income applicable to common stock to reflect the
write-off of the original issuance underwriting discount.
13. PENSION, POSTRETIREMENT AND OTHER EMPLOYEE BENEFIT PLANS
Pension Plans
The Company and certain subsidiaries have noncontributory defined benefit
pension plans covering substantially all of their employees. Over 90% of the
employees covered by the plans are employed by SoCalGas. 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 plans 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.
pacific enterprises 47.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Pension expense was as follows:
<TABLE>
<CAPTION>
Year Ended December 31
------------------------------
(Dollars in millions) 1997 1996 1995
- -------------------------------------------------------------------
<S> <C> <C> <C>
Service cost on benefits
earned during the period $ 35 $ 39 $ 27
Interest cost on projected
benefit obligation 104 103 91
Actual return on plan assets (287) (220) (333)
Net amortization and
deferral 153 107 223
------------------------------
Net periodic pension cost 5 29 8
Special early retirement
program 13 18
Regulatory adjustment 3 2
------------------------------
Total pension expense $ 18 $ 32 $ 28
- -------------------------------------------------------------------
- -------------------------------------------------------------------
</TABLE>
A reconciliation of the plans' funded status to the pension liability
recognized in the Consolidated Balance Sheet is as follows:
<TABLE>
<CAPTION>
December 31
----------------------
(Dollars in millions) 1997 1996
- ------------------------------------------------------------------
<S> <C> <C>
Actuarial present value of pension
benefit obligations:
Accumulated benefit obligation,
including $1,176 and $1,168 in
vested benefits at December 31,
1997 and 1996, respectively $ 1,227 $ 1,205
Effect of future salary increases 285 231
------- -------
Projected benefit obligation 1,512 1,436
Less: Plan assets at fair value,
primarily publicly traded
common stocks and pooled
equity funds (1,954) (1,774)
Unrecognized net gain 533 415
Unrecognized prior service cost (32) (35)
Unrecognized transition obligation (4) (5)
------- -------
Accrued pension liability included
in the Consolidated
Balance Sheet $ 55 $ 37
- -------------------------------------------------------------------
- -------------------------------------------------------------------
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 asset 8.00% 8.00%
- ------------------------------------------------------------------
- ------------------------------------------------------------------
</TABLE>
Postretirement Benefit Plan
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 may 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.
The net periodic postretirement benefit expense was as follows:
<TABLE>
<CAPTION>
Year Ended December 31
------------------------------
(Dollars in millions) 1997 1996 1995
- -------------------------------------------------------------------
<S> <C> <C> <C>
Service cost on benefits
earned during
the period $ 14 $ 17 $ 13
Interest cost on
projected benefit
obligation 32 33 31
Actual return on
plan assets (57) (32) (37)
Net amortization
and deferral 36 13 23
----- ----- -----
Net periodic
postretirement
benefit cost 25 31 30
Special early
retirement program 2
Regulatory adjustment 13 13 13
----- ----- -----
Net postretirement
benefit expense $ 40 $ 44 $ 43
- -------------------------------------------------------------------
- -------------------------------------------------------------------
</TABLE>
pacific enterprises 48.
<PAGE>
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
----------------------
(Dollars in millions) 1997 1996
- ------------------------------------------------------------------
<S> <C> <C>
Accumulated postretirement
benefit obligation:
Retirees $ 214 $ 209
Fully eligible active plan
participants 246 171
Other active plan participants 28 21
----- -----
488 401
Less: plan assets at fair value, primarily
publicly traded common stocks
and pooled equity funds (349) (274)
Unrecognized prior service cost 15 78
Unrecognized net gain 63 19
----- -----
Net postretirement benefit liability
included in the Consolidated
Balance Sheet $ 217 $ 224
- ------------------------------------------------------------------
- ------------------------------------------------------------------
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 $9.8 million on the
aggregate of the service and interest cost components of net periodic
postretirement cost for 1997 and $72.5 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 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 $41 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 $8 million in 1997, 1996, and 1995.
Employee Stock Ownership Plan
The Company retained Pacific Enterprises Employee Stock Ownership Plan and
Trust (TRUST) subsequent to the sale of the retailing operations in 1992 (See
Notes 9 and 16). The TRUST covers substantially all employees and is used to
partially fund the Company's retirement savings plan program. All
contributions to the TRUST are made by the Company, and there are no
contributions by the participants. As the Company makes contributions to the
ESOP, the ESOP debt service is paid and shares are released proportionately
to the total expected debt service.
pacific enterprises 49.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
Compensation expense is charged and equity is credited for the market
value of the shares released. However, tax deductions are allowed based on
the cost of the shares. Dividends on unallocated shares are used to pay debt
service and are charged against liabilities. The TRUST held 2.1 million and
2.2 million shares of common stock with fair values of $80.3 million and
$67.6 million at December 31, 1997 and 1996, respectively.
14. STOCK BASED COMPENSATION
The Company accounts for stock options issued to employees under the
provisions described in Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees" (APB 25). In 1995, Statement of
Financial Accounting Standards No. 123, "Accounting for Stock Based
Compensation" (SFAS 123) was issued. This statement established a
fair-value-based method of accounting for employee stock options or similar
equity instruments and encourages, but does not require, all companies to
adopt that method of accounting for all of their employee stock compensation
plans.
SFAS 123 allows companies to continue to measure compensation cost for
employee stock options or similar equity instruments using the intrinsic
value method of accounting described in APB 25. The Company has elected to
remain with this method and is required to make pro forma disclosures of net
income and earnings per share as if SFAS 123 accounting had been applied.
The Company's Employee Stock Option Plan provides for the granting of
stock options to officers and other employees of the Company and its
subsidiaries. The option price is equal to the market price of the Company's
stock at the date of grant. The stock options expire in ten years from the
date of grant. All options granted prior to 1997 became immediately
exercisable upon approval of the business combination with Enova by the
Company's shareholders. The options were originally scheduled to vest
annually over a service period ranging from three to five years. The
authorized number of options granted each year may not exceed 1% of the
outstanding common stock at the beginning of the year. Any grant of options
in the future, as well as those granted in 1997, will continue to vest
annually over a service period ranging from three to five years.
The plan allows for the granting of dividend equivalents based upon
performance goals. This feature provides grantees, upon exercise of the
option, with the opportunity to receive all or a portion of the cash
dividends that would have been paid on the shares if the shares had been
outstanding since the grant date. Dividend equivalents are not payable if the
Company does not meet the established performance goal, or if the exercise
price exceeds the market value of the shares purchased. The percentage of
dividends paid as dividend equivalents will depend upon the extent to which
the performance goals are met.
Stock option activity for the years ended December 31, 1995, 1996, and
1997 is summarized in the following tables:
Options with Performance Features
<TABLE>
<CAPTION>
Shares Wtd. Avg
Under Exercise Exercisable
Option Prices at Year-End
- --------------------------------------------------------------------
<S> <C> <C> <C>
December 31, 1994 1,002,060 $ 26.59 412,160
Granted 562,700 24.40
Exercised (227,400) 20.21
Canceled (66,560) 41.51
- --------------------------------------------------------------------
December 31, 1995 1,270,800 $ 25.98 366,900
Granted 685,200 27.00
Exercised (62,500) 21.46
Canceled (51,400) 39.46
- --------------------------------------------------------------------
December 31, 1996 1,842,100 $ 26.14 588,067
Granted 691,650 30.63
Exercised (238,920) 24.86
Canceled (47,340) 30.63
- --------------------------------------------------------------------
December 31, 1997 2,247,490 $ 27.56 1,600,680
- --------------------------------------------------------------------
- --------------------------------------------------------------------
</TABLE>
pacific enterprises 50.
<PAGE>
OPTIONS WITHOUT PERFORMANCE FEATURES
<TABLE>
<CAPTION>
Shares Wtd. Avg
Under Exercise Exercisable
Option Prices at Year-End
- ---------------------------------------------------------------------
<S> <C> <C> <C>
December 31, 1994 1,102,550 $ 26.64 413,950
Granted 0 0.00
Exercised (160,080) 22.49
Canceled (119,770) 27.63
- ---------------------------------------------------------------------
December 31, 1995 822,700 $ 27.30 431,200
Granted 0 0.00
Exercised (140,000) 23.04
Canceled (32,000) 38.72
- ---------------------------------------------------------------------
December 31, 1996 650,700 $ 27.66 395,940
Granted 0 0.00
Exercised (328,400) 22.47
Canceled (9,800) 53.00
- ---------------------------------------------------------------------
December 31, 1997 312,500 $ 32.29 312,500
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
</TABLE>
As mentioned above, all options granted prior to 1997 became exercisable
upon approval of the business combination with Enova by the Company's
shareholders. Information on options outstanding at December 31, 1997 is as
follows:
OUTSTANDING OPTIONS
<TABLE>
<CAPTION>
Wtd. Wtd.
Range of Number Average Average
Exercise of Remaining Exercise
Prices Shares Life Price
- ---------------------------------------------------------------------
<S> <C> <C> <C>
$ 19.25-24.25 902,900 6.19 $ 22.50
$ 25.25-30.63 1,330,990 8.43 $ 28.64
$ 36.25-47.25 326,100 2.27 $ 41.72
---------
2,559,990 6.85 $ 28.14
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
</TABLE>
EXERCISABLE OPTIONS
<TABLE>
<CAPTION>
Wtd.
Range of Number Average
Exercise of Exercise
Prices Shares Price
- ---------------------------------------------------------------------
<S> <C> <C>
$ 19.25-24.25 900,400 $ 22.50
$ 25.25-30.63 686,680 $ 26.77
$ 36.25-47.25 326,100 $ 41.72
---------
1,913,180 $ 27.31
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
</TABLE>
The fair value of each option grant (including the dividend equivalent)
was estimated on the date of grant using the Black-Scholes option-pricing
model. Weighted average fair values for options granted in 1997, 1996 and
1995 were $7.87, $7.52 and $7.32, respectively.
The assumptions that were used to determine these fair values are as
follows:
<TABLE>
<CAPTION>
Year Ended December 31
---------------------------------------
1997 1996 1995
- --------------------------------------------------------------------
<S> <C> <C> <C>
Stock price volatility 18% 19% 19%
Risk-free rate of return 6.4% 6.1% 7.1%
Annual dividend yield 0% 0% 0%
Expected Life 3.8 Years 4.3 Years 4.3 Years
- ---------------------------------------------------------------------
- ---------------------------------------------------------------------
</TABLE>
No compensation expense has been recognized for the Company's stock based
compensation plans except for the dividend equivalent performance based
options. The Company recorded compensation expense of $16.9 million, $5.5
million and $3.4 million in 1997, 1996 and 1995, respectively.
If compensation expense for the Company's stock based compensation plans
had been determined based on the fair value of the stock options at the grant
dates consistent with the method outlined in SFAS 123, net income and
earnings per share would have been adjusted to the pro forma amounts
indicated below:
<TABLE>
<CAPTION>
Year Ended December 31
-------------------------------------
(Dollars in millions,
except per share data) 1997 1996 1995
- --------------------------------------------------------------------
<S> <C> <C> <C>
Net Income:
As Reported $ 184 $ 203 $ 185
Pro Forma $ 187 $ 203 $ 185
Earnings Per Share - Basic:
As Reported $ 2.22 $ 2.37 $ 2.12
Pro Forma $ 2.25 $ 2.38 $ 2.13
Earnings Per Share - Diluted:
As Reported $ 2.21 $ 2.36 $ 2.12
Pro Forma $ 2.24 $ 2.37 $ 2.13
- --------------------------------------------------------------------
- --------------------------------------------------------------------
</TABLE>
pacific enterprises 51.
<PAGE>
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
15. EARNINGS PER SHARE
Prior to 1997, the Company reported earnings per share (EPS) in accordance
with Accounting Principles Board Opinion No. 15, "Earnings per Share" (APB
15). In February 1997, Statement of Financial Accounting Standards No. 128,
"Earnings Per Share" (SFAS 128) was issued.
SFAS 128 established standards for computing and presenting EPS and
applies to entities with publicly held common stock or potential common
stock. This statement simplifies the standards for computing EPS previously
found in APB 15, and makes them comparable to international EPS standards.
SFAS 128 replaces the presentation of primary EPS with a presentation of
basic EPS based upon the weighted average number of common shares for the
period. It also requires dual presentation of basic and diluted EPS on the
face of the income statement for all entities with complex capital structures
and requires a reconciliation of the numerator and denominator of the basic
EPS computation to the numerator and denominator of the diluted EPS
computation. SFAS 128 was adopted by the Company at the end of 1997 and EPS
for all prior periods was restated.
The Company has stock options outstanding which represent the only forms
of potential common stock at December 31, 1997. Dilutive options or warrants
that are issued during a period or that expire or are canceled during a
period are included in the denominator of diluted EPS for the period that
they were outstanding.
The reconciliation between the numerator and denominator for basic and
diluted EPS is as follows:
<TABLE>
<CAPTION>
(Dollars in millions, Income Shares Per-Share
except per-share amounts) (Numerator) (Denominator) Amount
- ----------------------------------------------------------------------
<S> <C> <C> <C>
December 31, 1997:
Net Income $ 184
Less: Dividends on
Preferred Stock (4)
----------------------------------------
Basic EPS:
Net Income Applicable
to Common Stock $ 180 81,354 $ 2.22
----------------------------------------
----------------------------------------
Effect of Dilutive Securities:
Stock Options 390
----------------------------------------
Diluted EPS:
Net Income Applicable
to Common Stock $ 180 81,744 $ 2.21
----------------------------------------
----------------------------------------
December 31, 1996:
Net Income $ 203
Less: Dividends on
Preferred Stock (5)
Preferred Stock
Original Issue Discount (2)
----------------------------------------
Basic EPS:
Net Income Applicable
to Common Stock $ 196 82,626 $ 2.37
----------------------------------------
----------------------------------------
Effect of Dilutive Securities:
Stock Options 221
----------------------------------------
Diluted EPS:
Net Income Applicable
to Common Stock $ 196 82,847 $ 2.36
----------------------------------------
----------------------------------------
December 31, 1995:
Net Income $ 185
Less: Dividends on
Preferred Stock (10)
----------------------------------------
Basic EPS:
Net Income Applicable
to Common Stock $ 175 82,265 $ 2.12
----------------------------------------
----------------------------------------
Effect of Dilutive Securities:
Stock Options 73
----------------------------------------
Diluted EPS:
Net Income Applicable
to Common Stock $ 175 82,338 $ 2.12
----------------------------------------
----------------------------------------
</TABLE>
pacific enterprises 52.
<PAGE>
16. DISCONTINUED OPERATIONS AND QUASI-REORGANIZATION
During 1993, the Company completed a strategic plan to refocus on its natural
gas utility and related businesses. The strategy included the divestiture of
its retailing operations and substantially all of its oil and gas exploration
and production business. In connection with the divestitures, the Company
effected a quasi-reorganization for financial reporting purposes effective
December 31, 1992. Fair value adjustments charged to common stock totaled
$190 million. Additionally, the accumulated deficit in retained earnings of
$452 million at December 31, 1992 was eliminated by a reduction in the common
stock account.
In connection with the sale of its retailing operations, the Company
assumed the retailing group's Employee Stock Ownership Plan (ESOP) and
related indebtedness (See Notes 9 and 13). In addition, the retailing group's
buyer agreed to reimburse the Company for a portion of the ESOP quarterly
debt service. In April 1994, the Company received a $65 million payment from
the buyer. This payment primarily reflected the settlement of the buyer's
remaining debt service obligation. It also canceled a warrant granted to the
Company in connection with the sale of retailing operations to purchase
approximately 10% of the buyer's common stock. Since the sale of the
retailing operations was recorded prior to the quasi-reorganization, the
settlement and resolution of other contingencies related to the ESOP resulted
in a $114 million increase to shareholders' equity, of which $37 million was
to common stock.
Certain of the liabilities established in connection with discontinued
operations and the quasi-reorganization were favorably resolved in 1995,
including the sale of ownership in the Company's headquarters building and
settlement of certain lawsuits remaining from the oil and gas operations.
Excess reserves of $13 million resulting from the favorable resolution of
these issues have been added to shareholders' equity. Other liabilities will
be resolved in future years. As of December 31, 1997, the provisions for
these matters are adequate.
pacific enterprises 53.
<PAGE>
STATEMENT OF MANAGEMENT RESPONSIBILITY FOR CONSOLIDATED FINANCIAL STATEMENTS
The consolidated financial statements have been prepared by management. The
integrity and objectivity of these financial statements and the other
financial information in the Annual Report, including the estimates and
judgments on which they are based, are the responsibility of management. The
financial statements have been audited by Deloitte & Touche LLP, independent
certified public accountants, appointed by the Board of Directors. Their
report is shown on page 55. 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 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 it 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.
/s/ Willis B. Wood, Jr.
Willis B. Wood, Jr.
Chairman, and Chief Executive Officer
/s/ Neal E. Schmale
Neal E. Schmale
Executive Vice President and Chief Financial Officer
January 27, 1998
pacific enterprises 54.
<PAGE>
INDEPENDENT AUDITORS' REPORT
Pacific Enterprises:
We have audited the consolidated financial statements of Pacific Enterprises
and subsidiaries (pages 31 to 53) 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 Pacific
Enterprises and 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.
/s/ Deloitte & Touche LLP
Los Angeles, California
January 27, 1998
pacific enterprises 55.
<PAGE>
SELECTED FINANCIAL DATA AND COMPARATIVE STATISTICS 1987-1997
<TABLE>
<CAPTION>
(Dollars in millions, except per share amounts) 1997 1996 1995 1994
-----------------------------------------------------
<S> <C> <C> <C> <C>
Consolidated:
Operating revenues from continuing operations $2,738 $2,563 $2,343 $2,664
-----------------------------------------------------
-----------------------------------------------------
Income from continuing operations $ 184 $ 203 $ 185 $ 172
-----------------------------------------------------
Income (loss) from discontinued operations
Net income (loss) 184 203 185 172
Dividends on preferred stock 4 5 10 12
Preferred stock original issue discount 2
-----------------------------------------------------
Net income (loss) applicable to common stock $ 180 $ 196 $ 175 $ 160
-----------------------------------------------------
-----------------------------------------------------
Net income (loss) per share of common stock:
Basic:
Continuing operations $ 2.22 $ 2.37 $ 2.12 $ 1.95
-----------------------------------------------------
Discontinued operations $ 2.22 $ 2.37 $ 2.12 $ 1.95
-----------------------------------------------------
-----------------------------------------------------
Diluted:
Continuing operations $ 2.21 $ 2.36 $ 2.12 $ 1.95
-----------------------------------------------------
Discontinued operations $ 2.21 $ 2.36 $ 2.12 $ 1.95
-----------------------------------------------------
-----------------------------------------------------
Cash dividends per share of common stock $ 1.50 $ 1.42 $ 1.34 $ 1.26
Book value per share $17.13 $16.58 $15.71 $14.74
Capital expenditures of continuing operations $ 187 $ 204 $ 240 $ 249
Total assets $4,977 $5,186 $5,259 $5,445
Capitalization:
Short-term debt $ 354 $ 262 $ 234 $ 278
Long-term debt due within one year 148 149 100 128
Long-term debt 988 1,095 1,241 1,420
Long-term debt of ESOP 130 130 130 130
Obligations under capital leases
Preferred stocks of a subsidiary:
Redeemable
Nonredeemable 95 95 195 195
Preferred stock 80 80 188 218
Common stock 1,064 1,095 1,111 1,092
Retained earnings 372 314 236 172
Less deferred compensation relating to esop (47) (49) (52) (54)
-----------------------------------------------------
Total capitalization $3,184 $3,171 $3,383 $3,579
-----------------------------------------------------
-----------------------------------------------------
Number of employees 7,215 7,643 7,860 8,484
SoCalGas:
Gas revenues:
Residential $1,736 $1,613 $1,554 $1,713
Commercial/industrial 756 708 751 798
Utility electric generation 76 70 104 118
Wholesale 67 70 62 98
Exchange 1 1 1 1
-----------------------------------------------------
Gas revenues in rates 2,636 2,462 2,472 2,728
Regulatory balancing accounts and other 5 (40) (193) (141)
-----------------------------------------------------
Total operating revenue $2,641 $2,422 $2,279 $ 2,587
-----------------------------------------------------
-----------------------------------------------------
Gas volumes delivered (billion cubic feet):
Residential 240 236 239 256
Commercial/industrial 388 374 351 348
Utility electric generation 158 139 205 260
Wholesale 138 130 129 146
Exchange 6 5 13 10
-----------------------------------------------------
Total throughput 930 884 937 1,020
-----------------------------------------------------
-----------------------------------------------------
Core 323 314 325 341
Noncore 607 570 612 679
-----------------------------------------------------
Total throughput 930 884 937 1,020
-----------------------------------------------------
-----------------------------------------------------
Gas volumes sold 317 315 338 362
Gas volumes transported or exchanged 613 569 599 658
-----------------------------------------------------
Total throughput 930 884 937 1,020
-----------------------------------------------------
-----------------------------------------------------
Number of customers:
Residential 4,624,279 4,582,553 4,526,150 4,483,324
Commercial 183,146 184,425 184,470 187,518
Industrial 22,642 22,952 22,976 23,505
Utility electric generation/wholesale 12 12 11 11
-----------------------------------------------------
Total number of customers 4,830,079 4,789,942 4,733,607 4,694,358
-----------------------------------------------------
-----------------------------------------------------
Gas purchased (billion cubic feet):
Market gas 229 226 206 247
Affiliates 95 96 99 101
Other long-term supplies 5 12 29 36
-----------------------------------------------------
Total gas purchased 329 334 334 384
-----------------------------------------------------
-----------------------------------------------------
Average cost of gas purchased excluding fixed costs
(per thousand cubic feet) $ 2.58 $ 1.88 $ 1.42 $ 1.68
Weighted average rate base $2,734 $ 2,777 $ 2,766 $ 2,862
Authorized rate of return on:
Rate base 9.49% 9.42% 9.67% 9.22%
Common equity 11.60% 11.60% 12.00% 11.00%
Degree days 1,126 1,195 1,241 1,459
pacific enterprises 56.
<PAGE>
1993 1992 1991 1990 1989 1988 1987
----------------------------------------------------------------------------
(Dollars in millions, except per share amounts)
Consolidated:
Operating revenues from continuing operations $2,899 $2,900 $3,007 $3,376 $3,344 $3,301 $3,385
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Income from continuing operations $ 181 $ 136 $ 167 $ 142 142 $ 142 $ 148
Income (loss) from discontinued operations (686) (255) (201) 64 75 101
----------------------------------------------------------------------------
Net income (loss) 181 (550) (88) (59) 206 217 249
Dividends on preferred stock 15 16 16 17 13 6 6
Preferred stock original issue discount
----------------------------------------------------------------------------
Net income (loss) applicable to common stock $ 166 $ (566) $(104) $ (76) $ 193 $ 211 $ 243
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net income (loss) per share of common stock:
Basic:
Continuing operations $ 2.06 $ 1.60 $ 2.09 $ 1.78 $ 1.98 $ 2.20 $ 2.40
Discontinued operations (9.17) (3.54) (2.87) .99 1.23 1.70
----------------------------------------------------------------------------
$ 2.06 (7.57) $(1.45) $(1.09) $ 2.97 $ 3.43 $ 4.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Diluted:
Continuing operations $ 2.06 $ 1.60 $ 2.09 $ 1.78 $ 1.98 $ 2.20 $ 2.40
Discontinued operations (9.16) (3.54) (2.87) .99 1.22 1.70
----------------------------------------------------------------------------
$ 2.06 $(7.56) $(1.45) $(1.09) $ 2.97 $ 3.42 $ 4.10
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Cash dividends per share of common stock $ .60 $ .44 $ 2.62 $ 3.48 $ 3.48 $ 3.48 $ 3.48
Book value per share $12.19 $ 9.44 $19.74 $23.07 $27.10 $28.26 $27.05
Capital expenditures of continuing operations $ 331 $ 329 $ 335 $ 386 $ 340 $ 351 $ 328
Total assets $5,596 $5,414 $5,462 $5,702 $5,874 $5,496 $4,374
Capitalization:
Short-term debt $ 267 $ 215 $ 123 $ 491 $ 637 $ 572 $ 128
Long-term debt due within one year 58 217 25 30 30 65 72
Long-term debt 1,262 1,774 1,776 1,161 1,045 1,220 1,067
Long-term debt of ESOP 132 141 149 163 173 31 38
Obligations under capital leases 25 26
Preferred stocks of a subsidiary:
Redeemable 60 60 60
Nonredeemable 195 195 195 145 70 20 20
Preferred stock 258 258 258 258 258 110 110
Common stock 1,048 859 1,458 1,385 1,331 1,066 875
Retained earnings 116 146 419 738 770 771
Less deferred compensation relating to esop (138) (148) (163) (173) (189) (31) (38)
----------------------------------------------------------------------------
Total capitalization $3,198 $3,511 $3,967 $3,879 $4,153 $3,908 $3,129
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of employees 9,200 9,884 40,953 42,370 43,891 40,538 27,928
SoCalGas:
Gas revenues:
Residential $1,653 $1,484 $1,674 $1,548 $1,484 1,482 $1,496
Commercial/industrial 853 836 977 1,057 1,016 1,008 1,059
Utility electric generation 147 195 149 235 483 554 662
Wholesale 117 129 145 165 192 252 302
Exchange 4 6 7 8 8 12 18
----------------------------------------------------------------------------
Gas revenues in rates 2,774 2,650 2,952 3,013 3,183 3,308 3,537
Regulatory balancing accounts and other 37 190 (22) 200 92 (86) (225)
----------------------------------------------------------------------------
Total operating revenue $2,811 $2,840 $2,930 $3,213 $3,275 $3,222 $3,312
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gas volumes delivered (billion cubic feet):
Residential 248 244 249 262 255 253 259
Commercial/industrial 339 363 460 436 400 344 269
Utility electric generation 213 221 170 159 202 199 309
Wholesale 148 149 142 139 146 144 159
Exchange 17 24 26 30 30 39 55
----------------------------------------------------------------------------
Total throughput 965 1,001 1,047 1,026 1,033 979 1,051
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Core 339 335 351 372 364 n/a n/a
Noncore 626 666 696 654 669 n/a n/a
----------------------------------------------------------------------------
Total throughput 965 1,001 1,047 1,026 1,033 979 1,051
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gas volumes sold 352 355 411 515 594 654 759
Gas volumes transported or exchanged 613 646 636 511 439 325 292
----------------------------------------------------------------------------
Total throughput 965 1,001 1,047 1,026 1,033 979 1,051
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Number of customers:
Residential 4,459,250 4,445,500 4,429,896 4,381,563 4,295,838 4,196,010 4,086,365
Commercial 187,602 189,364 193,051 193,409 192,269 190,908 189,611
Industrial 23,924 24,419 25,642 26,530 26,957 27,133 27,227
Utility electric generation/wholesale 11 10 10 10 9 9 8
----------------------------------------------------------------------------
Total number of customers 4,670,787 4,659,293 4,648,599 4,601,512 4,515,073 4,414,060 4,303,211
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Gas purchased (billion cubic feet):
Market gas 244 219 308 375 363 306 319
Affiliates 97 99 99 103 104 118 113
Other long-term supplies 28 42 39 53 149 247 343
----------------------------------------------------------------------------
Total gas purchased 369 360 446 531 616 671 775
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Average cost of gas purchased excluding fixed costs
(per thousand cubic feet) $ 2.21 $ 2.24 $ 2.40 $ 2.59 $ 2.46 $ 2.39 $ 2.20
Weighted average rate base $2,769 $2,720 $2,663 $2,549 $ 2,386 $2,268 $2,167
Authorized rate of return on:
Rate base 9.99% 10.49% 10.79% 10.75% 10.96% 10.93% 11.51%
Common equity 11.90% 12.65% 13.00% 13.00% 13.00% 12.75% 13.90%
Degree days 1,203 1,258 1,409 1,432 1,344 1,354 1,498
</TABLE>
pacific enterprises 57.
<PAGE>
QUARTERLY FINANCIAL DATA (UNAUDITED)
<TABLE>
<CAPTION>
Three Months Ended
-----------------------------------------
1997
-----------------------------------------
(Dollars are in millions, except per-share amounts) Mar 31 Jun 30 Sep 30 Dec 31 Total
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 794 $ 592 $ 609 $ 743 $ 2,738
Net income $ 50 $ 57 $ 37 $ 40 $ 184
Net income per share of common stock-basic $ .60 $ .70 $ .44 $ .47 $ 2.22
Dividends declared per share of common stock $ .36 $ .76 $ $ .38 $ 1.50
Dividends paid per share of common stock $ .36 $ .38 $ .38 $ .38 $ 1.50
Weighted average number of shares of common stock
outstanding (in thousands) 81,936 81,192 81,142 81,158 81,354
- ----------------------------------------------------------------------------------------------------------
Three Months Ended
-----------------------------------------
1996
-----------------------------------------
(Dollars are in millions, except per-share amounts) Mar 31 Jun 30 Sep 30 Dec 31 Total
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Operating revenues $ 631 $ 560 $ 596 $ 776 $ 2,563
Net income $ 51 $ 56 $ 48 $ 48 $ 203
Net income per share of common stock-basic $ .57 $ .67 $ .57 $ .56 $ 2.37
Dividends declared per share of common stock $ .34 $ .72 $ $ .36 $ 1.42
Dividends paid per share of common stock $ .34 $ .36 $ .36 $ .36 $ 1.42
Weighted average number of shares of common stock
outstanding (in thousands) 82,430 82,605 82,758 82,652 82,626
- ----------------------------------------------------------------------------------------------------------
</TABLE>
RANGE OF MARKET PRICES OF CAPITAL STOCK
<TABLE>
<CAPTION>
1997
------------------------------------------------------------------------------------
Three Months Ended Mar 31 Jun 30 Sep 30 Dec 31
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Common Stock $31 3/8 - 29 5/8 $33 7/8 - 29 3/4 $34 13/16 - 31 9/16 $37 5/8 - 30 5/8
Preferred Stock:
$4.75 $73 1/8 - 70 1/2 $77 - 69 1/2 $81 - 72 3/4 $82 7/8 - 74
$4.50 $72 - 66 $71 7/32 - 65 3/8 $75 - 67 5/8 $80 5/16 - 64
$4.40 $67 3/4 - 63 $70 1/4 - 63 5/8 $71 1/2 - 65 1/8 $77 - 65 5/8
$4.36 $69 - 63 1/2 $70 1/2 - 63 $72 3/4 - 66 1/2 $77 25/32 - 64 1/2
- ----------------------------------------------------------------------------------------------------------
1996
------------------------------------------------------------------------------------
Three Months Ended Mar 31 Jun 30 Sep 30 Dec 31
- ----------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Common Stock $29 5/8 - 25 1/4 $29 5/8 - 24 1/2 $31 3/8 - 28 1/2 $32 1/2 - 28 3/4
Preferred Stock:
$4.75 $75 1/2 - 64 1/4 $67 - 63 3/8 $70 - 61 $74 - 66 1/4
$4.50 $73 - 63 1/4 $65 5/8 - 58 1/8 $66 5/16 - 58 7/8 $70 - 64 3/8
$4.40 $69 7/8 - 58 7/8 $67 1/2 - 61 $64 3/4 - 59 7/8 $67 3/4 - 61 1/4
$4.36 $68 - 58 1/4 $61 1/2 - 58 3/4 $64 3/8 - 58 5/8 $71 - 60 5/8
- ----------------------------------------------------------------------------------------------------------
</TABLE>
MARKET PRICES FOR THE COMMON STOCK ARE AS REPORTED ON THE COMPOSITE TAPE FOR
STOCKS LISTED ON THE NEW YORK STOCK EXCHANGE. MARKET PRICES FOR THE PREFERRED
STOCK WERE OBTAINED FROM THE AMERICAN STOCK EXCHANGE.
THE NUMBER OF SHAREHOLDERS OF COMMON STOCK AT DECEMBER 31, 1997 IS 34,542.
pacific enterprises 58.
<PAGE>
Exhibit 21.01
-------------
List of Subsidiaries
of Pacific Enterprises
----------------------
Atlantic-Pacific Glendale, L.L.C.
Argelec Holdco
Arggas Holdco
Arggen Holdco
Argentina Gas & Electric Company
Atlantic-Pacific Las Vegas, L.L.C.
Bangor Gas Company, L.L.C.
Bangor Pacific Corporation
Central Plants, Inc.
CES/Way Holding Company
CES/Way International, Inc.
EcoTrans OEM Corporation
ElecArg Holdco
Energy Alliance I
Energy Pacific, LLC
Energy Pacific Glendale
Energy Pacific Las Vegas
Ensource
ESHold, Inc.
Frontier Pacific
Frontier Energy, L.L.C.
FTM Sports Corporation
GSHold, Inc.
Mexico City Disco Holding, Ltd.
Pacific Enerchange
Pacific Energy Leasing
Pacific Enterprises ABC Corporation
Pacific Enterprises Commercial Loans, Inc.
Pacific Enterprises Energy Management Services
Pacific Enterprises Energy Services
Pacific Enterprises International
Pacific Enterprises International (Cayman I)
Pacific Enterprises International (Cayman II)
Pacific Enterprises International Argentina I
Pacific Enterprises International Argentina II
Pacific Enterprises International Brazil Holding I, Ltd.
Pacific Enterprises International Brazil Holding II, Ltd.
Pacific Enterprises International Holdings I
Pacific Enterprises International Holdings II
Pacific Enterprises International Indonesia
Pacific Enterprises International Latin America
Pacific Enterprises International Mexico I
Pacific Enterprises International River Plate Holdings
Pacific Enterprises International River Plate Operations
Pacific Enterprises Leasing Company
Pacific Enterprises LNG Company
Pacific Enterprises Oil Company
Pacific Enterprises Oil Company (USA)
<PAGE>
Pacific Enterprises Oil Company (Western)
Pacific Interstate Company
Pacific Interstate Mojave Company
Pacific Interstate Offshore Company
Pacific Interstate Transmission Company
Pacific Interstate Transmission Company (Arctic)
Pacific Lighting Corporation
Pacific Lighting Gas Development Company
Pacific Lighting Land Company
Pacific Lighting Real Estate Group
Pacific Offshore Pipeline Company
Pacific Enterprises LNG Company
Pacific Synthetic Fuel Company
Pacific Western Resources Company
Pay'n Save Drug Stores, Incorporated
PEI Brazil Service Corporation
PEI Mexico Service Corporation
PEI Uruguay Holdings I, Ltd.
PEI Uruguay Holdings II, Ltd.
PEI Uruguay Operator I, Ltd.
PEI Uruguay Operator II, Ltd.
Presley RAC Finance Co., Inc.
Presley-Home Mac Finance Co., Inc.
Sempra
Sempra Corporation
Sempra Energy
Sempra Energy Holding Co.
Sempra Energy Trading
Southern California Gas Company
Southern California Gas Tower
Rosarito PowerCo Holding, Ltd.
Rosarito Transco Holding, Ltd.
Toluca Disco Holding, Ltd.
<PAGE>
Exhibit 23.01
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statement Nos.
2-96782, 33-26357, 2-66833, 2-96781, 33-21908 and 33-54055 of Pacific
Enterprises on Forms S-8 and Registration Statement Nos. 33-24830 and
33-44338 of Pacific Enterprises on Forms S-3 of our reports dated January 27,
1998, appearing in and incorporated by reference in this Annual Report on
Form 10-K of Pacific Enterprises for the year ended December 31, 1997.
DELOITTE & TOUCHE LLP
Los Angeles, California
March 23, 1998
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE CONDENSED
STATEMENT OF CONSOLIDATED INCOME, BALANCE SHEET, AND CASH FLOWS AND IS QUALIFIED
IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<CIK> 0000075527
<NAME> PACIFIC ENTERPRISES
<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> 271
<TOTAL-CURRENT-ASSETS> 1,103
<TOTAL-DEFERRED-CHARGES> 394
<OTHER-ASSETS> 135
<TOTAL-ASSETS> 4,977
<COMMON> 1,064
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 372
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,389
0
80
<LONG-TERM-DEBT-NET> 988
<SHORT-TERM-NOTES> 354
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0
<LONG-TERM-DEBT-CURRENT-PORT> 148
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,018
<TOT-CAPITALIZATION-AND-LIAB> 4,977
<GROSS-OPERATING-REVENUE> 2,738
<INCOME-TAX-EXPENSE> 151
<OTHER-OPERATING-EXPENSES> 0
<TOTAL-OPERATING-EXPENSES> 2,339
<OPERATING-INCOME-LOSS> 438
<OTHER-INCOME-NET> 39
<INCOME-BEFORE-INTEREST-EXPEN> 438
<TOTAL-INTEREST-EXPENSE> 103
<NET-INCOME> 184
4
<EARNINGS-AVAILABLE-FOR-COMM> 180
<COMMON-STOCK-DIVIDENDS> 122
<TOTAL-INTEREST-ON-BONDS> 0
<CASH-FLOW-OPERATIONS> 350
<EPS-PRIMARY> 2.22
<EPS-DILUTED> 2.21
</TABLE>
<TABLE> <S> <C>
<PAGE>
<ARTICLE> UT
<MULTIPLIER> 1,000,000
<S> <C> <C> <C>
<PERIOD-TYPE> 3-MOS 12-MOS 6-MOS
<FISCAL-YEAR-END> DEC-31-1996 DEC-31-1996 DEC-31-1997
<PERIOD-END> MAR-31-1996 DEC-31-1996 JUN-30-1997
<BOOK-VALUE> PER-BOOK PER-BOOK PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 3,262 3,167 3,207
<OTHER-PROPERTY-AND-INVEST> 54 185 96
<TOTAL-CURRENT-ASSETS> 855 1,161 880
<TOTAL-DEFERRED-CHARGES> 632 552 490
<OTHER-ASSETS> 111 121 148
<TOTAL-ASSETS> 4,914 5,186 4,833
<COMMON> 1,112 1,095 1,061
<CAPITAL-SURPLUS-PAID-IN> 0 0 0
<RETAINED-EARNINGS> 255 314 328
<TOTAL-COMMON-STOCKHOLDERS-EQ> 1,316 1,360 1,341
0 0 0
80 80 80
<LONG-TERM-DEBT-NET> 1,206 1,095 1,052
<SHORT-TERM-NOTES> 84 262 116
<LONG-TERM-NOTES-PAYABLE> 0 0 0
<COMMERCIAL-PAPER-OBLIGATIONS> 0 0 0
<LONG-TERM-DEBT-CURRENT-PORT> 97 149 296
0 0 0
<CAPITAL-LEASE-OBLIGATIONS> 0 0 0
<LEASES-CURRENT> 0 0 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 2,131 2,240 1,948
<TOT-CAPITALIZATION-AND-LIAB> 4,914 5,186 4,833
<GROSS-OPERATING-REVENUE> 631 2,563 1,386
<INCOME-TAX-EXPENSE> 40 151 86
<OTHER-OPERATING-EXPENSES> 0 0 0
<TOTAL-OPERATING-EXPENSES> 519 2,137 1,157
<OPERATING-INCOME-LOSS> 118 451 244
<OTHER-INCOME-NET> 6 25 15
<INCOME-BEFORE-INTEREST-EXPEN> 0 0 0
<TOTAL-INTEREST-EXPENSE> 27 97 51
<NET-INCOME> 51 203 107
4 7 2
<EARNINGS-AVAILABLE-FOR-COMM> 47 196 105
<COMMON-STOCK-DIVIDENDS> 28 118 94
<TOTAL-INTEREST-ON-BONDS> 0 0 0
<CASH-FLOW-OPERATIONS> 301 608 360
<EPS-PRIMARY> .57 2.37 1.30
<EPS-DILUTED> .57 2.36 1.29
</TABLE>
