Document/Exhibit Description Pages Size
1: 10-K Enserch Corporation Form 10-K 12/31/93 94± 429K
2: EX-10.10 Performance Incentive Plan, 1994 5 18K
3: EX-21 List of Subsidiaries 3± 16K
4: EX-23.1 Independent Auditors' Consent 1 6K
5: EX-23.2 Degolyer and Macnaughton Consent 1 7K
6: EX-24 Powers of Attorney 12 36K
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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
(X) ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (FEE REQUIRED) For the fiscal year ended
December 31, 1993
OR
(_) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 (NO FEE REQUIRED) For the transition period
from to
Commission file number 1-3183
ENSERCH CORPORATION
Texas 75-0399066
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
ENSERCH Center
300 South St. Paul Street
Dallas, Texas 75201-5598
(Address of principal executive office) (Zip Code)
Registrant's Telephone Number, Including Area Code - (214) 651-8700
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Name of Each Exchange
Title of Each Class on which Registered
___________________ _______________________
Common Stock ($4.45 par value) New York Stock Exchange
Chicago Stock Exchange
London Stock Exchange
Preferred Stock (no par value)
Depositary Preferred Shares, New York Stock Exchange
Series E (each representing 1/10 share
of the Adjustable Rate Cumulative
Preferred Stock, Series E)
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None
Indicate by check mark whether 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 twelve months (or for such shorter period that the
Registrant was required to file such reports) and (2) has been subject to such
filing requirements for the past 90 days. Yes (X) No (_)
Aggregate market value of the voting stock held by nonaffiliates of the
Registrant as of March 14, 1994: $936,160,305.
Shares of the Registrant's Common Stock outstanding as of March 14, 1994:
66,754,461
Documents incorporated by reference and the Part of the Form 10-K into
which the document is incorporated: Proxy Statement filed on or about March 30,
1994 (Part III).
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. (_)
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FORM 10-K
ANNUAL REPORT
For the Fiscal Year Ended December 31, 1993
TABLE OF CONTENTS
[Enlarge/Download Table]
Page
PART I
ITEM 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Business Segments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Natural Gas Transmission and Distribution. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1
Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2
Source and Availability of Raw Materials. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3
Regulation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Natural Gas and Oil Exploration and Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5
Gulf of Mexico. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6
Onshore . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7
Competition . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Regulation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8
Natural Gas Liquids Processing . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Power and Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Energy Project Development. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9
Enserch Environmental Corporation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .10
Clean Air Act. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .11
Patents and Licenses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12
Employees. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12
Executive Officers of Registrant . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .12
ITEM 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .13
ITEM 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .16
ITEM 4. Submission of Matters to a Vote of Security Holders . . . . . . . . . . . . . . . . . . . . . . . . . . . .16
PART II
ITEM 5. Market for Registrant's Common Equity and Related Stockholder
Matters. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17
ITEM 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17
ITEM 8. Financial Statements and Supplementary Data . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17
PART III
ITEM 10. Directors and Executive Officers of the Registrant. . . . . . . . . . . . . . . . . . . . . . . . . . . . .17
ITEM 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17
ITEM 12. Security Ownership of Certain Beneficial Owners and Management. . . . . . . . . . . . . . . . . . . . . . .17
ITEM 13. Certain Relationships and Related Transactions. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .17
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on
Form 8-K . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .18
APPENDIX A Financial Information . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A-1
APPENDIX B Consolidated Financial Statement Schedules. . . . . . . . . . . . . . . . . . . . . . . . . . . . . B-1
PART I
ITEM 1. Business
ENSERCH Corporation ("ENSERCH" or the "Corporation") is an integrated
company focused on natural gas. It is the successor to a company originally
organized in 1909 for the purpose of providing natural-gas service to North
Texas. The Corporation's operations include the following:
- Natural Gas Transmission and Distribution - Owning and operating
interconnected natural-gas transmission pipelines, gathering lines,
underground gas storage reservoirs, compressor stations,
distribution systems and related properties; transporting,
distributing and selling natural gas to residential, commercial,
industrial, electric-generation, pipeline and other customers; and
compressing natural gas for motor vehicle usage. (Lone Star Gas
Company, a division of the Corporation, Enserch Gas Company, and
related operations.)
- Natural Gas and Oil Exploration and Production - Exploring for,
developing, producing and marketing natural gas and oil. (Enserch
Exploration, Inc., Enserch Exploration Partners, Ltd. [more than 99%
owned], Enserch International Exploration, Inc., and related
operations.)
- Natural Gas Liquids Processing - Gathering natural gas, processing
natural gas to produce liquids and marketing the products. (Enserch
Processing Partners, Ltd.)
- Power and Other - Developing, operating and maintaining independent
electric-generation power plants and cogeneration facilities; and
furnishing energy services under long-term contracts to large
building complexes, such as universities and medical centers
(Enserch Development Corporation and Lone Star Energy Company).
Providing environmental engineering and contracting services from
initial site assessment and feasibility studies to designs, actions
and remediation (Enserch Environmental Corporation).
On December 22, 1993, the Corporation completed the sale of the principal
operating assets of its former engineering and construction subsidiary, Ebasco
Services Incorporated, to a subsidiary of Raytheon Company. Also in December
1993, in a separate transaction, the Corporation completed the sale of its 49%
interest in Dorsch Consult. See "Financial Review" and Note 11 of the Notes to
Consolidated Financial Statements included in Appendix A to this report.
Business Segments
Financial information required hereunder is set forth under "Summary of
Business Segments" included in Appendix A to this report.
Natural Gas Transmission and Distribution
The Corporation's transmission and distribution business ("T&D") is
composed of the regulated business of Lone Star Gas Company ("Lone Star"),
and the nonregulated gas marketing operations of Enserch Gas Company
("EGC").
Lone Star owns and operates interconnected natural-gas transmission lines,
gathering lines, underground gas storage reservoirs, compressor stations,
distribution systems and related properties. Through and by such facilities, it
purchases, distributes and sells natural gas to about 1.25 million residential,
commercial, industrial and electric-generation customers in approximately 550
cities and towns, including the 11-county Dallas/Fort Worth Metroplex. Lone
Star also transports natural gas for unaffiliated pipeline and industrial
customers as market opportunities are available. About seven million people
in Texas, representing more than 40% of the total state population, reside in
Lone Star's service area.
EGC purchases and sells natural gas to industrial and electric-generation
customers, local distribution companies and other pipeline and gas marketing
companies.
The Corporation holds a 50% interest in a partnership named Gulf Coast
Natural Gas Company that operates a transmission system in the Texas Gulf Coast
area, which transports and sells natural gas to industrial and unaffiliated
pipeline customers.
For the year ended December 31, 1993, residential and commercial customers
accounted for 56% of T&D's total gas sales revenues and 34% of natural gas
volumes sold; industrial customers accounted for 12% and 17%, respectively, and
electric-generation customers accounted for 12% and 17%, respectively. Sales to
other customers accounted for 20% of T&D's natural gas revenues and 32% of
volumes sold. In 1993, 10% of T&D's gas sales volumes was sold to Texas
Utilities Fuel Company, compared with 12% in 1992. See "Financial Review -
Natural Gas Transmission and Distribution" included in Appendix A to this report
for a discussion of Lone Star's gas sales margin.
Operating data for the T&D segment are set forth under "Financial Review -
Natural Gas Transmission and Distribution Operating Data" included in Appendix A
to this report.
Revenues from Lone Star's gas sales are affected by seasonal variations.
The majority of Lone Star's residential and commercial gas customers uses gas
for heating. Revenues from these customers are affected by the mildness or
severity of the heating season. Gas sales to electric-generation customers are
affected by the mildness or severity of the cooling and heating seasons.
Reengineering activities taking place within Lone Star's distribution
operations have resulted in a number of process and system changes being made to
improve customer service and provide operating efficiencies. As a part of these
changes, the workforce will be reduced and many local offices will be closed.
A related $12 million pretax charge was taken in 1993 primarily to reflect
severance expenses.
Competition. Natural gas continues to face varying degrees of competition
from electricity, coal, natural gas liquids, oil and other refined products
throughout Lone Star's service territory. Pipeline systems of other companies,
both intrastate and interstate, extend into or through the areas in which Lone
Star's markets are located, setting up competitive situations with other sellers
of natural gas for existing and potential customers. Customer sensitivity to
energy prices and the availability of competitively priced gas in the
nonregulated markets continue to provide intense competition in the electric-
generation and industrial user markets. Competitive pressure from other
pipelines and alternative fuels has caused a continuing decline in sales by Lone
Star to industrial and electric-generation customers each year since 1981, most
of which has been replaced by sales of the Corporation's nonregulated companies.
Lone Star initiated a program in 1992 that provides its industrial cus-
tomers an opportunity to have transportation service for up to 50% of their
natural-gas requirements transported by Lone Star. The gas to be trans-
ported may be purchased by the industrial customers from third-party
suppliers. This has resulted in lower overall gas costs to the industrial
customers able to take advantage of this program, helping Lone Star maintain
long-term gas load, with no detrimental effect on other customers.
In Lone Star's service area, the intensity of competition among natural
gas, fuel oil, and coal is dependent upon relative prices of the products.
2
During most of 1993, natural gas was generally successful competing with
fuel oil but was generally unable to compete effectively with coal in
existing coal-fired units.
In response to highly competitive industrial and electric-generation
markets, T&D continues to expand its businesses of arranging transportation and
the purchase and sale of gas in the nonregulated markets. This is accomplished
through the gas marketing activities of EGC. EGC sales in 1993 were 244 billion
cubic feet ("Bcf"), which was 57 Bcf (including 42 Bcf purchased for resale from
affiliates) greater than in 1992. EGC continues to actively pursue sales to
customers not located on Lone Star's pipeline system. These "off-system" sales
efforts have been enhanced by the ability to transport interstate gas under the
Federal Energy Regulatory Commission ("FERC") open-access transportation plan.
EGC continues to purchase and resell gas subject to the Natural Gas Policy Act
of 1978 ("NGPA") without utility regulatory constraints, providing EGC more
opportunities to obtain supplies and market gas throughout the United States.
With more normal weather conditions in 1993, overall volumes of natural gas
sold or transported to industrial, electric-generation and pipeline markets by
T&D increased slightly compared with 1992 despite intense competition for gas
load and the commencement of commercial operation of a second nuclear power
plant in Lone Star's service area. In addition, the former Gulf Coast
operations of Enserch Gas Transmission Company ("EGT"), in which Lone Star
now has only a 50% interest, are not included in statistics after 1991.
Transportation volumes for the entire segment were 371 Bcf in 1993, up
64 Bcf compared with 1992.
In the current energy market, Lone Star's contracts for new gas reserves
have been at prices below its current systemwide weighted average cost of gas
and are expected to continue to be so in the foreseeable future.
Source and Availability of Raw Materials. Lone Star's gas supply is based
on contracts for the purchase of dedicated specific reserves and contracts with
other pipeline companies in the form of service agreements that are not related
to specific reserves or fields. Management has calculated that the total
contracted gas supply as of January 1, 1994, was 972 Bcf, or approximately six
times Lone Star's purchases during 1993. Of this total, 342 Bcf are dedicated
reserves, 52 BCF are gas in storage, and 578 Bcf, (including 372 Bcf under one
agreement) are committed to Lone Star under service agreements. The January 1,
1994, total gas supply estimate is 198 Bcf lower than the January 1, 1993,
estimate. The difference resulted from purchases of 175 Bcf from existing gas
supply, new supply additions of 5 Bcf and a net downward revision of 28 Bcf with
respect to estimates for existing sources and service agreements. New reserve
additions consisted of 5 Bcf of new dedicated reserves under old contracts. The
Corporation also has estimated the oil and natural gas liquids reserves of Lone
Star, as of January 1, 1994, to be 64,664 barrels.
In 1993, about 97% of Lone Star's gas requirement was purchased from some
370 independent producers and nonaffiliated pipeline companies, one of which
supplied approximately 12.8% of total requirements. The remainder of Lone
Star's requirement (3.2%) was supplied by affiliates.
Lone Star estimates its peak-day availability from presently contracted
sources to be 1.8 Bcf. Short-term peaking contracts and withdrawals from
underground storage raise this level to meet anticipated sales needs.
During 1993, the average daily demand of Lone Star's residential and
commercial customers was .4 Bcf. The estimated peak-day demand of such customers
(based upon an arithmetic-mean outside temperature of 15 degrees F.) was
1.9 Bcf. Lone Star's greatest daily demand in 1993 was on January 10, when
estimated actual deliveries to all customers reached 1.7 Bcf and there was
an arithmetic-mean temperature of 33 degrees F. The estimated deliveries to
3
residential and commercial customers on that day were 1.2 Bcf and another
.9 Bcf were transported by Lone Star.
To meet peak-day gas demands during winter months, Lone Star utilizes its
eight active underground storage fields, all of which are located in Texas.
These fields have an extraneous gas capacity of 74 Bcf. At December 31, 1993,
total extraneous gas in storage was approximately 52 Bcf. Gas withdrawn from
storage on January 10, 1993, the date of Lone Star's greatest daily demand in
1993, was .4 Bcf, or approximately 24% of the total 1.7 Bcf of Lone Star's
sales.
Lone Star historically has maintained a curtailment program designed to
achieve the highest load factor possible in the use of its pipeline system while
assuring continuous and uninterrupted service to its residential and commercial
customers. Under the program, industrial customers select their own rates and
relative priorities of service. Interruptible service contracts give Lone Star
the right to curtail gas deliveries up to 100% according to a strict priority
plan.
Estimates of gas supplies and reserves are not necessarily indicative of
Lone Star's ability to meet current or anticipated market demands or immediate
delivery requirements, because of factors such as the physical limitations of
gathering and transmission systems, the duration and severity of cold weather,
the availability of gas reserves from its suppliers, the ability to purchase
additional supplies on a short-term basis, and actions by federal and state
regulatory authorities. Lone Star's curtailment rights provide flexibility to
meet the human-needs requirements of its customers on a firm basis. Priority
allocations and price limitations imposed by federal and state regulatory
agencies, as well as other factors beyond the control of Lone Star, may affect
its ability to meet the demands of its customers.
Lone Star follows a program to place new supplies of gas under contract to
its pipeline system. In addition to being heavily concentrated in the
established gas-producing areas of central, north and east Texas, Lone Star's
intrastate pipeline system also extends into or near the major gas-producing
areas of the Texas Gulf Coast, and the Delaware and Val Verde Basins of West
Texas. Nine basins located in Texas are estimated to contain a substantial
portion of the nation's remaining onshore natural-gas reserves. Lone Star's
pipeline system provides access to all of these basins.
Lone Star's attractive service territory has been a primary factor in the
continued addition of new customers. The number of Lone Star customers in Texas
has steadily grown from 1986 to 1993. See "Financial Review - Natural Gas
Transmission and Distribution Operating Data" included in Appendix A to this
report.
Lone Star buys gas under long-term, intrastate contracts in order to assure
reliable supply to its customers. To obtain this reliability, Lone Star, in the
past, entered into many gas-purchase contracts that provided for minimum-
purchase ("take-or-pay") obligations to gas sellers. In the past, Lone Star
was unable to take delivery of all minimum gas volumes tendered by suppliers
under these contracts. Assuming normal weather conditions, it is expected
that normal gas purchases will substantially satisfy purchase obligations for
the year 1994 and thereafter. For a discussion of these take-or-pay obligations
and the Corporation's accounting policy with respect to gas-purchase contracts,
see "Financial Review - Gas-Purchase Contracts" and Note 1 to the Consolidated
Financial Statements included in Appendix A to this report.
Generally, EGC's gas supply is contracted for on a month-to-month basis at
prevailing market prices. The availability of gas is dependent on many factors,
including the overall demand for natural gas and market price.
4
Regulation. Lone Star is wholly intrastate in character. Its utility
operations in the state of Texas are subject to regulation by the Railroad
Commission of Texas ("RRC") and municipalities. Lone Star owns no certificated
interstate transmission facilities subject to the jurisdiction of FERC under the
Natural Gas Act, has no sales for resale under the rate jurisdiction of FERC,
and does not perform any transportation service that is subject to FERC juris-
diction under the Natural Gas Act.
In 1985, FERC issued Order 436, and later Order 500, which allow self-
implementing, voluntary transportation of natural gas, as opposed to mandatory
transportation for pipelines willing to assume FERC-imposed "open-access"
conditions and certain other price/rate controls. The Order imposed "open-
access" conditions that affect intrastate pipelines, such as Lone Star's
intrastate facilities, if the intrastate pipeline "voluntarily" elects to
transport gas for an interstate pipeline or local distribution company under
Section 311 of the NGPA. Lone Star became an open-access transporter effective
July 15, 1988, on its intrastate transmission facilities only. Transportation
by each company is performed pursuant to Section 311(a)(2) of the NGPA and is
subject to an exemption from the jurisdiction of the FERC under the Natural Gas
Act, pursuant to Section 601 of the NGPA.
The RRC regulates the intracompany charge for gas delivered to Texas
distribution systems for sale to residential and commercial consumers. The RRC
has original jurisdiction over rates charged to residential and commercial
customers for gas delivered outside incorporated cities and towns (environs
rates). Rates within incorporated cities and towns in Texas are subject to the
original jurisdiction of the municipal government, with appellate review by the
RRC. Proposed rate changes within the jurisdiction of the incorporated cities
and towns in Texas may be suspended for a period not to exceed 90 days beyond
the proposed effective date. The RRC may extend the time during which it
deliberates and decides a matter within its appellate jurisdiction to a maximum
of 185 days, but it may suspend rates within its original jurisdiction for 150
days beyond the proposed effective date.
Lone Star continuely reviews rates for all classes of customers in its
regulatory jurisdictions. Rate relief amounting to $1.9 million in annualized
revenue increases over and above changes in gas cost was achieved in Texas in
1993 through rate case filings, the operation of cost of service adjustment
clauses, and the operation of plant investment cost adjustments. About 110 of
the 550 cities and towns served by Lone Star had approved weather normalization
adjustment clauses as part of their rate structure by yearend 1993, representing
about 20% of Lone Star's residential and commercial sales volumes. These
clauses allow rates to be adjusted monthly to reflect the impact of warmer- or
colder-than-normal weather during the winter, minimizing the impact of
variations in weather on Lone Star's earnings.
Sales and transportation services to industrial and electric-generation
customers are provided under contract through contractual relations. Regulatory
authorities in Texas have jurisdiction to revise, review and regulate rates to
industrial and electric-generation customers but, historically, have not
exercised this jurisdiction. Contracts with these customers permit automatic
adjustment on a monthly basis for the full amount of increases or decreases in
the cost of gas.
Natural Gas and Oil Exploration and Production
The Corporation's natural gas and oil exploration and production operations
are collectively referred to herein as "Enserch Exploration." These operations
and this business are conducted primarily through Enserch Exploration Partners
Ltd. ("EP"), a limited partnership in which a minority interest (less than 1%)
is held by the public and a group of subsidiary companies. Activities include
geological and geophysical studies; acquisition of gas and oil leases; drilling
5
of exploratory wells; development and operation of producing properties;
acquisition of interests in developed or partially developed properties; and the
marketing of natural gas, crude oil and condensate.
In 1985, the Corporation formed EP to succeed to substantially all of the
domestic gas and oil exploration and production business of the Corporation.
The Corporation and an affiliate own more than 99% of the outstanding limited
partnership units. The remaining units--slightly more than 800,000--are
publicly held and traded on the New York Stock Exchange.
EP operates through EP Operating Limited Partnership ("EPO"), a Texas
limited partnership, in which EP holds a 99% limited partner's interest and the
general partners own a 1% interest. Enserch Exploration, Inc. is the managing
general partner and the Corporation is the special general partner of EP and
EPO.
Enserch Exploration is engaged in the exploration for and the development,
production and marketing of natural gas and crude oil throughout Texas, offshore
in the Gulf of Mexico, onshore in the Gulf Coast and Rocky Mountain areas and in
various other areas in the United States. Subsidiaries currently have interests
in three foreign countries.
Production offices are maintained in Dallas, Houston, Athens, Bridgeport,
Longview and Midland, Texas. At December 31, 1993, Enserch Exploration employed
382 persons, including 36 geologists, 21 geophysicists and 19 land
representatives who investigate prospective areas, generate drilling prospects,
review submitted prospects and acquire leasehold acreage in prospective areas.
In addition, Enserch Exploration maintains a staff of 56 engineers and 46
technologists who plan and supervise the drilling and completion of wells,
evaluate prospective gas and oil reservoirs, plan the development and management
of fields, and manage the daily production of gas and oil.
Enserch Exploration's natural-gas sales volumes for the year ended
December 31, 1993, represented 16% of the Corporation's consolidated natural-gas
sales volumes. Approximately 70% of Enserch Exploration's natural-gas sales
volumes (75% of gas revenues) for the year ended December 31, 1993, was sold to
affiliated customers. In 1993, affiliated revenues include gas sales under new
contracts effective March 1, 1993 with Enserch Gas Company covering essentially
all gas production not committed under existing contracts. Affiliated pur-
chasers do not have a preferential right to purchase natural gas produced by
Enserch Exploration other than under existing contracts.
The statistics for this business segment, which are set forth in the table
entitled "Financial Review - Natural Gas and Oil Exploration and Production
Operating Data" in Appendix A to this report, reflect the fluctuations in
product prices and volumes and certain unusual items which affected operating
income.
Following is a summary of Enserch Exploration's domestic exploration and
development activity during 1993:
Gulf of Mexico. Offshore exploration provides the Corporation the
opportunity to improve its ratio of production to reserve base by the addition
of gas wells with relatively higher production rates. This is coupled with
ongoing deep-water development projects, which are expected to provide long-term
reserves. State-of-the-art technology, including 3-D seismic, specialized
seismic processing, and innovative well completion and production techniques,
are being used to help accomplish these objectives.
Mississippi Canyon Block 441, the first development project in the Gulf of
Mexico that Enserch Exploration has operated, is indicative of this approach.
A 3-D seismic program, prior to field development, confirmed that the majority
of the reservoir lies beneath a shipping fairway. A production program was
developed that involved drilling highly deviated wells under the shipping
6
fairway, subsea completing the deep-water wells, and tying the wells back to a
conventional shallow-water production platform using bundled flowlines. The
high-angle wells required special gravel-pack completion techniques. After a
year of production, the field has been essentially maintenance free, producing
some 70 million cubic feet ("MMcf") of natural gas and more than 500 barrels
("Bbls") of condensate per day from six wells.
The 3-D seismic on Mississippi Canyon Block 441 is being reprocessed, using
depth migration and other state-of-the-art techniques to aid in the
identification of deeper exploratory targets, which, if successfully drilled,
could add to the field reserves. Enserch Exploration has a 37.5% working
interest in this project.
The Garden Banks Block 388 oil development project remains on schedule,
with initial production anticipated by mid-1995. Installation of the offshore
facilities, which consist of a subsea template, gathering and sales pipelines,
and shallow-water production facilities, will begin by mid-1994. After the rig
and all facilities are in place, the three existing wells will be connected,
with initial production from the first well expected to be approximately
5 thousand barrels ("MBbls") of oil and 5 MMcf of gas per day. Peak daily pro-
duction from the project is anticipated to be 40 MBbls of oil and 60 MMcf of
gas. Enserch Exploration is 100% owner and operator of the Garden Banks 388
project.
Another prospect delineated by seismic amplitude anomalies lies
approximately four miles to the west of Garden Banks Block 388 on Garden Banks
Blocks 386/387. If successfully drilled, this prospect could add production to
the Block 388 development by incorporating some of the production technology
that was utilized on Mississippi Canyon Block 441.
In 1994, an offset well to Enserch Exploration's discovery on Green Canyon
Block 254 is scheduled to be drilled. The exploratory well, which was drilled
in 1991, encountered 11 sands with a combined thickness of more than 360 feet of
oil pay. Enserch Exploration has a 25% working interest in this block and a
similar working interest in three adjacent blocks believed to be part of the
same project.
Onshore. Enserch Exploration participated in 78 development wells (62 net)
in 1993, with the majority completed as gas producers in East Texas. Thirty-
nine wells were in progress at yearend. In East Texas, Enserch Exploration is
positioned in a prolific gas-prone area which, despite its maturity, provides
growth opportunities. Enserch Exploration is one of the oldest and most active
operators in this basin in East Texas, which includes the Opelika, Tri-Cities,
Whelan, Willow Springs, North Lansing and Freestone fields.
In early 1993, Enserch Exploration initiated a 26-well program in East
Texas to accelerate the development of natural-gas reserves from the Travis Peak
formation in the Opelika field. The program was targeted to test new techniques
for shortening the average life of its reserve base. The project was completed
in seven months, yielding initial daily per well production rates of up to 1.8
MMcf of gas and 48 Bbls of oil. Enserch Exploration has a 100% working interest
in these wells.
Enserch Exploration performed additional development drilling in the
Freestone field, where seven well completions flowed at daily rates ranging from
1.0 MMcf to 2.3 MMcf of gas per well. Enserch Exploration has 50% to 100%
working interests in these wells.
In the Bralley field in West Texas, the combined daily oil production rate
from six wells increased to 800 Bbls from 500 Bbls following production
optimization work. Enserch Exploration owns a 50% working interest in each of
these wells.
7
In South Texas, seven wells drilled and completed in the Fashing field
flowed at daily rates of 1.2 MMcf to 2.6 MMcf of gas and 14 Bbls to 30 Bbls of
oil per well. Twelve wells drilled and completed in the Boonsville field in
north central Texas resulted in daily production of .4 MMcf to 1.5 MMcf of gas
per well.
Onshore development activity planned for 1994 includes drilling
approximately 35 wells outside East Texas. Some of the larger projects include
wells in the Fashing, Rancho Viejo and Boonsville fields.
In the Fashing field, results of three wells and a field study indicate
development potential for new wells, as well as recompletions that could result
in reserve additions.
Competition. Competition in the natural gas and oil exploration and
production business is intense. Domestically, competition is present from a
large number of firms of varying sizes and financial resources, some of which
are much larger than Enserch Exploration. Internationally, competition is from
a number of both U.S. and non-U.S. firms, generally major national and
international oil companies. Competition involves all aspects of marketing
products (including terms, prices, volumes and length of contracts), terms
relating to lease bonus and royalty arrangements, and the schedule of future
development activity.
Regulation. Environmental Protection Agency ("EPA") rules, regulations and
orders affect the operations of Enserch Exploration. EPA regulations promul-
gated under the Superfund Amendments and Reauthorization Act of 1986 require
Enserch Exploration to report on locations and estimates of quantities of
hazardous chemicals used in Enserch Exploration's operations. The EPA has
determined that most gas and oil exploration and production wastes are exempt
from the hazardous waste management requirements of the Resource Conservation
Recovery Act. However, the EPA determined that certain exploration and
production wastes resulting from the maintenance of production equipment and
transportation are not exempt, and these wastes must be managed and disposed of
as hazardous waste. Also, regulations issued by the EPA under the Clean Water
Act require a permit for "contaminated" stormwater discharges from exploration
and production facilities.
Many states have issued new regulations under authority of the Clean Air
Act Amendments of 1990, and such regulations are in the process of being imple-
mented. These regulations may require certain gas and oil related installations
to obtain federally enforceable operating permits and may require the monitoring
of emissions; however, the impact of these regulations on Enserch Exploration
is expected to be minor.
Several states have adopted regulations on handling, transportation,
storage and disposal of naturally occurring radioactive materials that are found
in gas and oil operations. Although applicable to certain Enserch Exploration
facilities, it is not believed that such regulations will materially impact
current or future operations.
In the aggregate, compliance with federal and state environmental rules and
regulations is not expected to have a material effect on Enserch Exploration's
operations.
The RRC regulates the production of natural gas and oil by Enserch
Exploration in Texas. Similar regulations are in effect in all states in which
Enserch Exploration explores for and produces natural gas and oil. These
regulations generally require permits for the drilling of gas and oil wells and
regulate the spacing of the wells, the prevention of waste, the rate of
production, and the prevention and cleanup of pollution and other materials.
8
Natural Gas Liquids Processing
The Corporation's operations for the processing of natural gas for the
recovery of natural gas liquids ("NGL") is conducted by Enserch Processing
Partners, Ltd. ("Processing Partners"). Processing Partners is a limited
partnership that is wholly owned by the Corporation.
Processing Partners, which is among the top 25 NGL producers in the U.S.,
uses cryogenic and mechanical refrigeration processes at its NGL extraction
facilities. During these processes, NGL are condensed at extremely low
temperatures and are separated from natural gas. The mixed NGL stream
containing the heavier hydrocarbons ethane, propane, butane and natural gaso-
line, is pumped via pipeline to Mt. Belvieu, Texas. The remaining natural gas,
primarily methane, leaves the NGL plants in gas transmission lines for transport
to end-use customers. (See "Properties".)
About 70% of NGL product sales are under term contracts of one-to-three
years, with prices established monthly. NGL prices are influenced by a number
of factors, including supply, demand, inventory levels, the product composition
of each barrel, and the price of crude oil. Profitability is highly dependent
on the relationship of NGL product prices to the cost of natural gas lost in the
extraction process--"shrinkage."
The natural gas liquids processing area is highly competitive, including
competition regarding cost-sharing and interest-sharing arrangements among
producers, third-party owners and processors.
Power and Other
Energy Project Development. Enserch Development Corporation ("EDC") was
organized in 1986 to develop business opportunities primarily in the areas of
independent power, including cogeneration. EDC evaluates the risk and rewards
of these potential ventures; selects for development those ventures with the
highest potential of success; implements and controls development of each
venture; and brings together all the resources required to develop, finance,
construct, operate and manage the selected ventures. EDC focuses on employing
a strategy of maximizing the use of ENSERCH resources and minimizing the
Corporation's risk and investment. EDC, as of December 1993, had several
business opportunities in various phases of development throughout the United
States and internationally.
The first project completed by EDC, operating since 1989, was a gas-fired,
255-megawatt ("MW") cogeneration plant located near Sweetwater, Texas. The
electricity produced by the plant is purchased by Texas Utilities Electric
Company and thermal energy is sold to United Gypsum Company under a long-term
agreement. EDC developed and arranged financing for the project and one of its
subsidiaries is the managing general partner. Enserch Exploration and EGC
provide gas to the plant; Lone Star transports the gas and Lone Star Energy
Company ("LSEC") operates the plant.
In 1992, the second plant developed by EDC was completed. The 62-MW
natural gas-fired cogeneration facility in Buffalo, New York, supplies elec-
tricity to Niagara Mohawk Company and thermal energy to Outokumpu American
Brass, Inc. LSEC operates the plant.
EDC's third project, a 160-MW plant located in Bellingham, Washington,
began commercial operation July 1993. The electricity produced by the plant is
sold under a long-term power sales agreement with Puget Sound Power & Light.
Thermal energy in the form of steam and hot water is sold to Georgia-Pacific
Corporation.
9
In addition to operating the above mentioned cogeneration plants, LSEC owns
and/or operates four central thermal energy plants providing heating and cooling
to various institutional customers in Texas. The aggregate existing plant
capacity is nearly 50,000 tons of chilled water and 750 MMBtu's of steam or hot
water per hour. From the three plants owned by LSEC, institutional customers
receive thermal energy under long-term agreements that contain established rates
for units of steam or chilled water and certain escalation provisions for
increases in ad valorem taxes, utility and labor costs. When the agreements
expire, the plants become the property of the customers. Expiration dates are in
1996 and 1997. LSEC is actively pursuing new contracts to operate the plants
after the existing agreements expire. The expiration of the existing thermal-
energy plant agreements is not expected to have a significant impact on the
Corporation. LSEC also provides predictive maintenance services to outside
plant owners through its Plant Analytical Services affiliate, which was formed
in 1991.
As previously noted, LSEC operates the 255-MW Sweetwater cogeneration plant
in West Texas. Labor for operating and maintaining this facility is provided
under a fixed-cost contract with annual escalation provisions for increases in
labor costs. All other costs are borne by the facility owners. LSEC also
operates the 62-MW cogeneration plant in Buffalo, NY, and the 160-MW cogen-
eration facility in Bellingham, Washington. At both the Buffalo and Bellingham
plants, LSEC has fixed-cost operating and maintenance agreements with escalation
provisions. The contracts also include bonus or penalty provisions based upon
plant availability.
LSEC operates in the compressed natural gas ("CNG") market through its CNG
Division along with two natural gas vehicle affiliates, Fleet Star of Texas,
L.C. ("Fleet Star") and TRANSTAR Technologies, L.C., ("TRANSTAR"), each 50%
owned by LSEC. Fleet Star and FinaStar, a partnership between Fleet Star and
Fina Oil and Chemical, had six public stations in commercial operation at
December 31, 1993, and four additional stations were under construction. The
CNG Division and affiliates sold more than 1 million gallons of CNG into the
emerging transportation fuels market during 1993. TRANSTAR Technologies, L.C.,
provides turnkey natural gas vehicle conversion and other related services.
TRANSTAR was involved in the conversion of more than 300 vehicles to natural gas
during its first full year of operation in 1993 and enters 1994 with a backlog
of 120 units under contract to be converted.
The operations of the CNG Division and affiliates and the Plant Analytical
Services have been aligned under the Corporation's natural gas transmission and
distribution system for financial reporting purposes.
Enserch Environmental Corporation. The Corporation retained and will
continue to operate the former environmental division of Ebasco Services
Incorporated ("Ebasco"). This business is now operated through Enserch
Environmental Corporation ("Enserch Environmental"), a lower-tier subsidiary of
the Corporation. Enserch Environmental employs about 1,200 people and is
headquartered in New Jersey. Enserch Environmental had 1993 revenues of
$169 million, operating income of $5.7 million and its backlog at the end of
1993 was $600 million.
The Corporation's environmental business began in the 1960's as an out-
growth of Ebasco's licensing of plant sites in connection with the company's
power plant design and construction work. Enserch Environmental has extensive
experience in all aspects of the environmental market, from initial site assess-
ment and feasibility studies to remedial design, action and clean up. Over the
last five years, Enserch Environmental has completed projects valued in excess
of $1 billion in all areas of environmental and hazardous waste management ser-
vices for more than 300 clients. Enserch Environmental has completed
hundreds of environmental impact statements, licensing studies and baseline
environmental investigations.
10
With business, government and the public showing an increasing concern
about the environment, management believes that the environmental market will
grow and that Enserch Environmental will be a strong participant in it.
Clean Air Act
The impact of the 1990 amendments to the Clean Air Act ("CAA") on the
Corporation, its division, subsidiaries and affiliates, cannot be fully
ascertained until all the regulations that implement the provisions of the Act
have been promulgated. It is expected that a number of facilities or emission
sources will require a federally enforceable operating permit, and certain
emission sources may also be required to reduce emissions or to install enhanced
monitoring equipment under proposed rules and regulations. Management currently
believes, however, that if the rules and regulations implementing the CAA are
adopted as proposed, the cost of obtaining permits, operating costs that will
be incurred under the operating permit, new permit fee structures, capital
expenditures associated with equipment modifications to reduce emissions, or
any expenditures on enhanced monitoring equipment, in the aggregate, will not
have a material adverse effect on the Corporation's results of operations.
The CAA has created new marketing opportunities for the sale of natural gas
that may have a positive effect on the Corporation's results of operations.
Natural gas has long been recognized as a clean and efficient fuel. Title II
(Mobile Sources) requires lower emissions from light-duty vehicles and urban
buses that should make alternative fuels such as natural gas more attractive and
competitive. In addition, Clean Fuel Fleet programs under the CAA will require
a certain percentage of fleet vehicles to utilize clean-burning alternative
fuels such as natural gas in the near future. Further, because chlorofluoro-
carbon compounds ("CFCs"), commonly used as refrigerants in large air-
conditioning systems must be phased out of production by the year 2000, interest
has increased in the use of natural gas-powered absorption cooling systems that
do not use CFCs. In those areas that do not meet the CAA's National Ambient Air
Quality Standards for ozone, natural gas may play an important role in reduc-
ing ozone formation, and may be substituted for other fuels. Since Title IV
(Acid Rain) requires major reductions in sulphur dioxide emissions, princi-
pally from coal-fired electric power plants, natural gas is expected to be
considered as a cost-effective alternative for achieving reduced sulphur dioxide
emissions.
The CAA also is expected to create new marketing opportunities for Enserch
Environmental, which has considerable experience and expertise in the engineer-
ing and construction implications of environmental matters. Enserch Environ-
mental's comprehensive services extend into the areas regulated by the CAA,
including: Title III (Air Toxins) where regulated air toxins will ultimately
grow from 8 to more than 200 contaminants, and private industrial clients, par-
ticularly in the petroleum, petrochemical, chemical and pharmaceutical sectors,
will require air-quality assessment, monitoring, engineering and facility
upgrades; Title IV (Acid Rain) where electric-utility clients will require
conceptual engineering studies, air-quality studies and monitoring; Title II
(Mobile Sources) where increased emphasis is expected on environmental con-
sulting related to transportation systems--both the construction of new types of
infrastructure projects and the development of more sophisticated transporta-
tion systems; and Title V (Permits) where industrial facilities will be required
to obtain operating permits involving emission inventories, performing com-
pliance analysis and operational studies, and designing and installation of
emission monitors and/or enhanced monitoring systems.
The ultimate effect of these opportunities on the Corporation's business
cannot be quantified at this time as it will depend on the extent to which
natural gas is selected as an alternative fuel source and the services of
Enserch Environmental Corporation are utilized in these newly regulated areas.
11
Patent and Licenses
The Corporation, Lone Star and subsidiary companies have no material
patents, licenses, franchises (excluding gas-distribution franchises) or
concession.
Employees
At December 31, 1993, the Corporation, its division and subsidiaries,
employed approximately 5,600 persons.
Executive Officers of Registrant
[Download Table]
Name Age Office and Business Experience
D. W. BIEGLER 47 Chairman and President, Chief Executive Officer
since May 1993 and a Director of the Corporation
since September 1991; President and Chief
Operating Officer of the Corporation from
September 1991 to May 1993. He also served Lone
Star as President from July 1985 and as Chairman
from January 1989.
R. F. ALBOSTA 57 Chairman, President and Chief Executive Officer
of Enserch Environmental since December 1993. He
served as Vice President, Engineering and
Construction Division, of the Corporation from
March 1987 to May 1993. He also served Ebasco as
Chairman from April 1990, Chief Executive Officer
from April 1989 and President from July 1986 to
December 1993.
G. R. BRYAN 49 Chairman of EDC since February 1993. He also
served Lone Star as Senior Vice President,
Transmission, from February 1987 to February
1993.
GARY J. JUNCO 44 President and Chief Operating Officer of Enserch
Exploration, Inc. since January 1991. Senior
Vice President, Land and Marketing, from April
1987 to December 1990.
W. T. SATTERWHITE 60 Senior Vice President and General Counsel, Chief
Legal Officer of the Corporation since May 1972.
S. R. SINGER 63 Senior Vice President, Finance and Corporate
Development, Chief Financial Officer of the
Corporation since September 1968.
J. M. TALBERT 47 President and Chief Executive Officer of Lone
Star since May 1993. President and Chief
Operating Officer of Lone Star from January 1991
to May 1993. He also was President of Texas Oil
and Gas Corp. from 1987 through 1990.
R. B. Williams 61 Vice President, Administration, of the
Corporation since May 1989.
There are no family relationships between any of the above officers. All
officers of the Corporation, its division and subsidiaries are elected annually
by their respective Boards of Directors. Officers may be removed by their
respective Boards of Directors whenever, in their judgment, the best interest of
12
the Corporation, its division or subsidiaries, as the case may be, will be
served thereby.
ITEM 2. Properties
At December 31, 1993, Lone Star and certain subsidiaries of the Corporation
operated approximately 32,000 miles of transmission and gathering lines and
distribution mains, and operated 37 compressor stations having a total rated
horsepower of approximately 81,000. Lone Star owns eight active gas-storage
fields, all located on Lone Star's system in Texas. Lone Star also owns three
major gas-treatment plants to remove undesirable components from the gas stream.
See "Business - Natural Gas Transmission and Distribution - Source and
Availability of Raw Materials" for information concerning gas supply of Lone
Star.
As estimated by DeGolyer and MacNaughton, Enserch Exploration has net
proved reserves, as of January 1, 1994, of 1.09 trillion cubic feet ("Tcf") of
natural gas and 39.3 million barrels ("MMBbls") of oil and condensate, including
NGL attributable to leasehold interests. (See Note 13 of the Notes to
Consolidated Financial Statements included in Appendix A to this report for
additional information on gas and oil reserves.) All of these reserves are in
the United States.
Enserch Exploration's 1994 capital spending budget has been set at
$116 million, a 3% decrease from 1993 actual capital expenditures. More than
half of the 1994 capital expenditures is earmarked for domestic onshore
drilling. The exploration program includes a balance mix of projects with
regard to reserve potential and risk, focusing on as many core area oppor-
tunities as possible. See "Financial Review - Natural Gas and Oil Exploration
and Production" included in Appendix A to this report.
During 1993, Enserch Exploration filed Form EIA-23 with the Department of
Energy reflecting reserve estimates for the year 1992. Such reserve estimates
were not materially different from the 1992 reserve estimates reported in
Note 13 of the Notes to Consolidated Financial Statements included in
Appendix A to this report.
Operating data relating to Enserch Exploration are set forth under
"Financial Review - Natural Gas and Oil Exploration and Production Operating
Data" included in Appendix A to this report.
13
Enserch Exploration and subsidiary companies owned leasehold interests or
licenses in 17 states, offshore Texas and Louisiana, and three other countries
as of December 31, 1993, as follows:
[Enlarge/Download Table]
Gross Acres Net Acres(1)
_______________________________________________ _______________________________________________
Developed Undeveloped Total Developed Undeveloped Total
_______________________________________________ _______________________________________________
Alabama . . . . . 2,797 1,536 4,333 1,952 1,642 3,594
Arkansas. . . . . 16 10,550 10,566 16 5,783 5,799
Colorado. . . . . 11,812 23,746 35,558 4,127 15,133 19,260
Idaho . . . . . . 14,730 14,730 14,730 14,730
Kansas. . . . . . 560 14,950 15,510 360 8,267 8,627
Louisiana . . . . 4,025 29,510 33,535 1,218 18,254 19,472
Mississippi . . . 6,245 42,436 48,681 3,099 14,317 17,416
Montana . . . . . 6,135 49,825 55,960 3,237 34,168 37,405
Nebraska. . . . . 160 480 640 160 480 640
Nevada. . . . . . 38,633 38,633 27,916 27,916
New Mexico. . . . 2,680 5,907 8,587 1,902 4,276 6,178
North Dakota. . . 1,560 10,421 11,981 1,246 6,233 7,479
Ohio. . . . . . . 102 14,950 15,052
Oklahoma. . . . . 37,022 23,915 60,937 20,323 9,615 29,938
Texas . . . . . . 284,508 453,221 737,729 213,822 163,651 377,473
Utah. . . . . . . 3,719 109,742 113,461 533 54,081 54,614
Wyoming . . . . . 4,079 49,947 54,026 1,846 43,358 45,204
U.S. Offshore . . 51,927 320,689 372,616 8,459 114,674 123,133
_________ _________ _________ _______ _________ _________
Total U.S . . . . 417,347 1,215,188 1,632,535 262,300 536,578 798,878
_________ _________ _________ _______ _________ _________
Malaysia. . . . . 1,556,755 1,556,755 389,189 389,189
U.K.. . . . . . . 20,010 20,010 1,248 1,248
Indonesia . . . . 1,369,737 1,369,737 342,435 342,435
_________ _________ _________ _______ _________ _________
Total Non-U.S . . 2,946,502 2,946,502 732,872 732,872
_________ _________ _________ _______ _________ _________
Total Company . . 417,347 4,161,690 4,579,037 262,300 1,269,450 1,531,750
========= ========= ========= ======= ========= =========
<FN>
(1) Represents the proportionate interest of Enserch Exploration in the gross
acres under lease.
Enserch Exploration purchased about 220,000 net acres of leasehold
interests in 1993, 26,000 of which were in the Gulf of Mexico. Enserch Explora-
tion's Gulf of Mexico holdings totaled some 123,000 net acres, with an average
working interest of 36% in 64 leases covering 65 blocks with an overriding
royalty interest in six other leases. The company operates 23 leases cover-
ing 24 offshore blocks. Enserch Exploration also canceled, or allowed to
expire, eight Gulf of Mexico leases during the year. These leases had been con-
demned following drilling on or near them or after geophysical and geological
findings.
Enserch Exploration plans further drilling on undeveloped acreage but at
this time cannot specify the extent of the drilling or predict how successful it
will be in establishing the commercial reserves sufficient to justify retention
of the acreage. The primary terms under which the undeveloped acreage in the
United States can be retained by the payment of delay rentals without the
establishment of gas and oil reserves expire 30% in 1994, 17% in 1995, 25% in
1996, 13% in 1997, 4% in 1998, 1% in 1999 and 10% thereafter. A portion of the
undeveloped acreage may be allowed to expire prior to the expiration of primary
terms specified in this schedule by nonpayment of delay rentals. Aside from
14
Texas, the Gulf of Mexico, Malaysia and Indonesia, Enserch Exploration has no
material concentration of undeveloped acreage in single areas at this time.
Undeveloped acreage in other countries, which can be retained without the
establishment of gas or oil reserves, expires as follows: Indonesia - 25% in
1994, 30% in 1996, 20% in 1998 and 25% in 2000; United Kingdom - 100% in 2016;
Malaysia - 100% in 1996.
Enserch Exploration participated in 111 wells (79 net) during the year. Of
these wells, 83 (64 net) were completed successfully, resulting in a net success
rate of 81%. Of the successful wells, 7 wells (4 net) were exploratory and 76
wells (60 net) were development. At December 31, 1993, Enserch Exploration was
participating in 39 wells (21 net), which were either being drilled or in some
state of completion.
In the 1993 domestic drilling program, 16 wells (4.9 net) were offshore.
Of these wells, 9 (2.6 net) gas wells and 1 (.1 net) oil well were successfully
completed. During 1992, 4 (1.6 net) offshore wells were drilled, of which 2 (.8
net) gas wells were successfully completed.
At December 31, 1993, Enserch Exploration owned working interests in 1,303
(980 net) gas wells and 1,121 (277 net) oil wells in the United States. Of
these, 173 (141 net) gas wells and 37 (32 net) oil wells were dual completions
in single boreholes.
Drilling activity by Enserch Exploration during the three years ended
December 31, 1993, is set forth below:
[Enlarge/Download Table]
Exploratory Drilling Development Drilling
____________________ ____________________
United United
States Non-U.S. States Non-U.S.
______ ________ ______ ________
Productive Wells
1993:
Gross Wells 7.0 76.0
Net Wells 3.8 60.1
1992:
Gross Wells 3.0 12.0
Net Wells 2.2 6.3
1991:
Gross Wells 11.0 54.0
Net Wells 5.9 46.2
Nonproductive Wells
1993:
Gross Wells 24.0 2.0 2.0
Net Wells 13.0 .5 1.8
1992:
Gross Wells 13.0 1.0 5.0
Net Wells 8.1 .1 2.6
1991:
Gross Wells 15.0 2.0 10.0 1.0
Net Wells 7.8 .5 6.1 .3
<FN>
Note: Productive wells are either producing wells or wells capable of commercial
production, although currently shut-in. The term "Gross" refers to the
wells in which a working interest is owned, and the term "Net" refers to
gross wells multiplied by the percentage of Enserch Exploration's working
interest owned therein.
15
The number of wells drilled is not a significant measure or indicator of
the relative success or value of a drilling program because the significance of
the reserves and economic potential may vary widely for each project. It is
also important to recognize that reported completions may not necessarily track
capital expenditures, since Securities and Exchange Commission guidelines do not
allow a well to be reported as complete until it is ready for production. In
the case of offshore wells, this may be several years following initial drilling
because of construction of platforms, pipelines and other necessary facilities.
Additional information relating to the gas and oil activities of Enserch
Exploration is set forth in Note 13 of the Notes to Consolidated Financial
Statements included in Appendix A to this report.
Processing Partners has interest in 18 processing plants, 13 of which are
wholly owned. The products, which in 1993 were produced at an average of about
16,500 barrels per day, are sold to customers primarily at the Mt. Belvieu
fractionation and storage facility near Houston for use as chemical feedstock
and other purposes. The processing plants are capable of producing an aggre-
gate of about 27,000 barrels of NGL per day; daily production was up slightly
from the previous year. Lone Star estimates that as of January 1, 1994,
27.2 MMBbls of NGLs are attributable to contractual processing rights of Pro-
cessing Partners with respect to gas reserves owned by EP or third parties and
dedicated to Lone Star under various gas-purchase contracts or are being trans-
ported by Lone Star under various gas transportation agreements. See "Business
- Natural Gas Transmission and Distribution - Source and Availability of Raw
Materials" for additional reserves held by Lone Star.
LSEC owns and operates three central plants providing heating and cooling
to institutional customers in Dallas, El Paso and Galveston, Texas. LSEC also
operates a similar plant in San Antonio, Texas.
The Corporation owns a five-building office complex in Dallas, containing
approximately 453,000 square feet of space that the Corporation, Lone Star and
certain subsidiaries fully occupy. In addition, the Corporation leases a 21-
story, 400,000-square-foot building in Houston under a two-year lease that is
automatically extended each year unless terminated.
ITEM 3. Legal Proceedings
The utility division of the Corporation was named as a codefendant in a
lawsuit filed on November 10, 1988, in the 200th Judicial District Court of
Travis County, Texas. Plaintiffs were parties to gas-sale contracts that
provided for direct and indirect sale of gas to the utility division. Plain-
tiffs allege that defendants implemented a series of unilateral price decreases,
thereby improperly fixing prices paid for gas in three Texas counties in
violation of state antitrust laws and the Texas State Natural Resources Code.
Plaintiffs also allege breach of contract and fiduciary duties, fraud,
interference of contracts, conspiracy, economic duress, failure to reasonably
market the plaintiffs' gas, and perform the contracts in good faith and
discrimination by a common purchaser. Plaintiffs seek actual damages of
approximately $35 million and $20 million in punitive damages. Management
believes the allegations are without merit and that liability, if any, will not
have any material effect on the financial position of the Corporation.
Additional information required hereunder is set forth in Note 6 and
Note 10 to Consolidated Financial Statements included in Appendix A hereto.
ITEM 4. Submission of Matters to a Vote of Security Holders
Not applicable.
16
PART II
ITEM 5. Market for Registrant's Common Equity and Related Stockholder
Matters
The information required hereunder is set forth under "Common Stock Market
Prices and Dividend Information" included in Appendix A to this report.
ITEM 6. Selected Financial Data
The information required hereunder is set forth under "Selected Financial
Data" included in Appendix A to this report.
ITEM 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations
The information required hereunder is set forth under "Financial Review"
included in Appendix A to this report.
ITEM 8. Financial Statements and Supplementary Data
The information required hereunder is set forth under "Independent
Auditors' Report," "Management Report on Responsibility for Financial
Reporting," "Statements of Consolidated Income," "Statements of Consolidated
Cash Flows," "Consolidated Balance Sheets," "Statements of Consolidated Common
Shareholders' Equity," "Notes to Consolidated Financial Statements" and "Summary
of Business Segments" included in Appendix A to this report.
ITEM 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure
None.
PART III
ITEMS 10-13.
Pursuant to Instruction G(3) to Form 10-K, the information required in
Items 10-13 (except for information set forth at the end of Part I under
"Business - Executive Officers of Registrant") is incorporated by reference from
the Corporation's definitive proxy statement which is being filed pursuant to
Regulation 14A on or about March 30, 1994.
17
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)-1 Financial Statements
The following items appear in Appendix A to this report:
[Enlarge/Download Table]
Item Page
Selected Financial Data. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .A-2
Financial Review . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .A-4
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .A-18
Management Report on Responsibility for Financial Reporting. . . . . . . . . . . . . . . . . . . . . . . . . .A-19
Financial Statements:
Statements of Consolidated Income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .A-21
Statements of Consolidated Cash Flows. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .A-22
Consolidated Balance Sheets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .A-23
Statements of Consolidated Common Shareholders' Equity . . . . . . . . . . . . . . . . . . . . . . .A-24
Notes to Consolidated Financial Statements . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .A-25
Summary of Business Segments . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .A-54
Common Stock Market Prices and Dividend Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .A-55
(a)-2 Financial Statement Schedules
The following items are included in Appendix B to this report:
[Enlarge/Download Table]
Item Page
Independent Auditors' Report . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-2
Consolidated Financial Statement Schedules for the Three
Years Ended December 31, 1993:
V - Property, Plant and Equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-3
VI - Accumulated Depreciation and Amortization of Property, Plant
and Equipment. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-6
IX - Short-term Borrowings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-9
X - Supplementary Income Statement Information. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .B-10
Consolidated financial statement schedules, other than those listed
above, are omitted because of the absence of the conditions under which they are
required or because the required information is included in the consolidated
financial statements or notes thereto.
(a)-3 Exhibits. The following exhibits are filed herewith unless otherwise
indicated:
[Download Table]
3.1* Restated Articles of Incorporation of Registrant currently in
effect, filed as Exhibit 3.1 to Registrant's Form 10-K for the Year
Ended December 31, 1988.
3.2* Bylaws of Registrant, filed as Exhibit 4.13 to Registrant's
Registration Statement on Form S-3 (33-52525).
4.1* Shareholder Rights Plan - Filed as an Exhibit to Registrant's Form
8-A dated April 23, 1986.
10.1* Management Incentive Program - Unit Plan and Stock Option Plan, as
amended, and currently in effect, filed as Exhibit 10.1 to
Registrant's Form 10-K for the year ended December 31, 1991.
18
10.2* Director's Fee Deferral Plan and Form of Election and Agreement to
Defer Directors' Fees, as amended, and currently in effect, filed as
Exhibit 10.2 to Registrant's Form 10-K for the year ended December
31, 1991.
10.3* Director's Deferred Compensation Trust Agreement, as amended, and
currently in effect, filed as Exhibit 10.3 to Registrant's Form 10-K
for the year ended December 31, 1991.
10.4* Forms of employment contracts executed by certain executive officers
of the Corporation, filed as Exhibit 10.4 to Registrant's Form 10-K
for the year ended December 31, 1991.
10.5* Forms of trust agreements relating to compensation and supplemental
retirement income arrangements executed by certain executive
officers of the Corporation, filed as Exhibit 10.5 to Registrant's
Form 10-K for the year ended December 31, 1991.
10.6* ENSERCH Corporation 1981 Stock Option Plan, as amended, and
currently in effect, as filed as Exhibit 10.6 to Registrant's Form
10-K for the year ended December 31, 1991.
10.7* Agreement of Limited Partnership of Enserch Exploration Partners,
Ltd. and Amendment No. 1 thereto as currently in effect, filed as
Exhibit 10.7 to Registrant's Form 10-K for the year ended
December 31, 1992.
10.8* Agreement of Limited Partnership of EP Operating Limited Partnership
and Amendments No. 1 and No. 2 thereto as currently in effect, filed
as Exhibit 10.8 to Registrant's Form 10-K for the year ended
December 31, 1992.
10.9* Form of Change of Control Agreement executed by certain executive
officers of the Corporation filed as Exhibit 10.9 to Registrant's
Form 10-K for the year ended December 31, 1988.
10.10 ENSERCH Corporation Performance Bonus Plan - Calendar Year 1994.
10.11* ENSERCH Corporation 1991 Stock Option Plan, filed as Exhibit 10.12
to Registrant's Form 10-K for the Year Ended December 31, 1990.
10.12* Form of an Employment Assurance Agreement, Employment Bonus
Agreement and Incentive Agreement executed by an executive officer
of Registrant and certain employees of a subsidiary of Registrant,
filed as Exhibit 10.12 to Registrant's Form 10-K for the year ended
December 31, 1992.
21 Subsidiaries of the Registrant.
23.1 Deloitte & Touche consent to incorporation by reference in
Registration Statements No. 2-59259, No. 2-77572, No. 33-15623, No.
33-40589, No. 33-47911 and No. 33-52525.
23.2 DeGolyer and MacNaughton consent letter including consent to
incorporation by reference in Registration Statements No. 2-59259,
No. 2-77572, No. 33-15623, No. 33-40589, No. 33-47911 and
No. 33-52525.
24 Powers of Attorney.
99* Proxy Statement dated at or about March 30, 1994, being filed with
the Securities and Exchange Commission on or about March 30, 1994.
19
Long-term debt is described in Notes 3 and 4 of the Notes to Consolidated
Financial Statements included in Appendix A to this report. The Corporation
agrees to provide the Commission, upon request, copies of instruments defining
the rights of holders of such long-term debt, which instruments are not filed
herewith pursuant to Paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K.
___________________
*Incorporated herein by reference and made a part hereof.
(b) Reports on Form 8-K
Current Report on Form 8-K dated October 18, 1993, was filed on
October 22, 1993 (judgment entered in Exchange Offer suit).
Current Report on Form 8-K dated November 17, 1993, was filed on
November 29, 1993 (ENSERCH signs agreement to sell principal operating
assets of Ebasco Services Incorporated to Raytheon Engineers &
Constructors).
Current Report on Form 8-K dated December 22, 1993, was filed on
January 6, 1994 (ENSERCH closes Ebasco sale; sells 49% interest in
Dorsch Consult).
20
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.
ENSERCH Corporation
March 30, 1994 By: /s/ D. W. Biegler
D. W. Biegler,
Chairman and President,
Chief Executive Officer
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 in the capacities and on the date indicated.
Signature and Title Date
D. W. Biegler, Chairman and President, Chief
Executive Officer, and Director; William B. Boyd,
Director; B. A. Bridgewater, Jr., Director;
Lawrence E. Fouraker, Director; Preston M. Geren,
Jr., Director; Marvin J. Girouard, Director; March 30, 1994
Joseph M. Haggar, Jr., Director; W. C. McCord,
Director; Diana S. Natalicio, Director;
W. Ray Wallace, Director; S. R. Singer, Senior
Vice President, Finance and Corporate Development,
Chief Financial Officer; Jerry W. Pinkerton, Vice
President and Controller, Chief Accounting Officer
By: /s/ D. W. Biegler
D. W. Biegler
As Attorney-in-Fact
APPENDIX A
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
INDEX TO FINANCIAL INFORMATION
DECEMBER 31, 1993
Page
----
Selected Financial Data............................... A-2
Financial Review...................................... A-4
Independent Auditors' Report.......................... A-18
Management Report on Responsibility for
Financial Reporting................................. A-19
Financial Statements:
Statements of Consolidated Income................... A-21
Statements of Consolidated Cash Flows............... A-22
Consolidated Balance Sheets......................... A-23
Statements of Consolidated Common
Shareholders' Equity.............................. A-24
Notes to Consolidated Financial Statements............ A-25
Summary of Business Segments.......................... A-54
Common Stock Market Prices and Dividend Information... A-55
[Enlarge/Download Table]
SELECTED FINANCIAL DATA
ENSERCH Corporation and Subsidiary Companies
As of or for Year Ended December 31
---------------------------------------------------------------------
1993 1992 1991 1990 1989 1988
---- ---- ---- ---- ---- ----
(In millions except ratio and per share amounts)
INCOME STATEMENT DATA FOR
CONTINUING OPERATIONS (a)
Revenues
Natural gas transmission and distribution. . . $1,547.9 $1,318.3 $1,273.3 $1,285.1 $1,361.0 $1,270.2
Natural gas and oil exploration and production 189.8 171.5 183.6 213.9 184.0 180.7
Natural gas liquids processing . . . . . . . . 85.8 87.0 92.8 99.4 76.6 75.5
Power and other. . . . . . . . . . . . . . . . 217.5 191.3 153.6 138.6 135.2 130.9
Less intercompany revenues . . . . . . . . . . (138.9) (53.5) (49.2) (35.6) (40.3) (35.0)
Total revenues . . . . . . . . . . . . . 1,902.1 1,714.6 1,654.1 1,701.4 1,716.5 1,622.3
Operating Income (Loss)
Natural gas transmission and distribution. . . 101.5 (b) 102.0 111.5 101.7 136.4 115.2
Natural gas and oil exploration and production (37.3)(c) (6.2)(d) 10.9 31.9 43.4 36.1
Natural gas liquids processing . . . . . . . . 5.0 13.1 21.2 24.9 4.2 5.6
Power and other. . . . . . . . . . . . . . . . 15.5 20.2 9.0 7.0 8.5 19.8
General and other. . . . . . . . . . . . . . . (11.9) (16.9) (15.5) (18.3) (12.3) (18.1)
Total operating income . . . . . . . . . 72.8 112.2 137.1 147.2 180.2 158.6
Other Income (Expense) - Net . . . . . . . . . . .2(e) (12.5)(e) 14.0(e) 49.3(e) .7 (7.7)
Interest Expense . . . . . . . . . . . . . . . . (80.2)(f) (97.0) (95.6) (101.5) (95.0) (78.7)
Income (Taxes) Benefit . . . . . . . . . . . . . (7.5)(g) .8 (17.7) (25.6) (21.6) (19.0)
Income (Loss) from Continuing Operations (a) . . (14.7) 3.5 37.8 69.4 64.3 53.2
Income (Loss) per Share (After Provision
for Preferred Dividends) . . . . . . . . . . . (.41) (.14) .36 .84 .84 .66
Average Common and Dilutive Common
Equivalent Shares Outstanding. . . . . . . . . 66.6 65.7 65.1 65.0 59.8 57.8
---------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA
Cash Dividends Declared and Paid (h) . . . . . . $ .20 $ .80 $ .80 $ .80 $ .80 $ .80
Market Price
High . . . . . . . . . . . . . . . . . . . . . 22 5/8 16 1/2 21 3/8 28 1/8 27 1/2 20 3/4
Low. . . . . . . . . . . . . . . . . . . . . . 14 1/8 10 3/8 12 3/4 18 1/2 18 5/8 16 1/8
Common Shareholders' Equity per Share. . . . . . 9.70 9.16 10.51 11.18 10.88 9.71
Shares Outstanding at Year-end . . . . . . . . . 66.7 66.0 65.3 64.8 64.4 58.0
---------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET AND CASH FLOW DATA
Property, Plant and Equipment-Net. . . . . . . . $2,118.1 $2,065.8 $2,152.1 $2,118.0 $2,046.3 $1,828.5
Total Assets . . . . . . . . . . . . . . . . . . 2,760.3 3,145.7 3,163.1 3,264.2 3,254.2 2,970.1
Net Working Capital (Deficiency) . . . . . . . . (195.5) 2.5 (42.2) 64.3 (23.0) (54.8)
Current Ratio. . . . . . . . . . . . . . . . . . .72 1.00 .95 1.08 .97 .93
Unused Lines of Credit . . . . . . . . . . . . . $ 635.0(i) $ 485.0 $ 650.0 $ 600.0 $ 600.0 $ 650.0
Net Cash Flows from (for) Operating and
Investing Activities . . . . . . . . . . . . . 309.4 106.2 57.2 (37.1) (63.1) 215.7
---------------------------------------------------------------------------------------------------------------------------
CAPITAL STRUCTURE
Senior Long-term Debt. . . . . . . . . . . . . . $ 638.8 $ 865.3 $ 757.6 $ 772.5 $ 727.1 $ 617.5
Convertible Subordinated Debentures. . . . . . . 90.8 90.8 205.7 215.7 215.7 215.7
Preferred Stock. . . . . . . . . . . . . . . . . 175.0 175.0 175.0 175.0 175.0 175.0
Common Shareholders' Equity. . . . . . . . . . . 646.7 604.6 686.3 723.9 701.3 563.5
Total Capitalization . . . . . . . . . . . . . 1,551.3 1,735.7 1,824.6 1,887.1 1,819.1 1,571.7
Senior Long-term and Convertible Debt
Ratio (Percent). . . . . . . . . . . . . . . . 47.0 55.1 52.8 52.4 51.8 53.0
A-2
---------------
<FN>
(a) Income from continuing operations does not reflect the following:
1993 1992 1991 1990 1989 1988
---- ---- ---- ---- ---- ----
(In millions except per share)
Income (loss) from discontinued operations,
including gain or loss on disposal:
Engineering and construction (See Note 11) $73.9 $(16.2) $(18.7) $12.0 $5.7 $ (43.6)
Oil field services . . . . . . . . . . . 21.4 3.4 (204.2)
Extraordinary loss on extinguishment
of debt (See Note 2) . . . . . . . . . . (15.4)
Cumulative effect of change in accounting
for income taxes applicable to
continuing operations . . . . . . . . . 28.1
Per share:
Discontinued operations:
Engineering and construction. . . . . . $1.11 $(.25) $(.29) $ .19 $.09 $ (.75)
Oil field services. . . . . . . . . . . .33 .06 (3.54)
Extraordinary loss . . . . . . . . . . . (.23)
Cumulative effect. . . . . . . . . . . . .49
(b) Includes a $12.0 million pretax charge ($7.8 million after-tax, $.12 per share) for efficiency enhancements and
severance expenses accrued for staff reductions.
(c) Includes a $41.4 million pretax charge ($26.9 million after-tax, $.40 per share) as a result of an adverse judgment in
litigation that required additional payment in a limited partnership exchange offer made in 1989 and a $13.3 million
pretax write-off ($8.6 million after-tax, $.13 per share) of non-U.S. gas and oil properties.
(d) Includes a $16.5 million pretax write-off ($10.9 million after-tax, $.17 per share) of an idle pipeline and shallow-
water production facility from an abandoned offshore project.
(e) 1993 includes a $5.6 million pretax provision for litigation offset by pretax gains totaling $7.0 million from the sale
of a gas storage facility and the Corporation's minority investment in an insurance entity (all totaling a net gain of
$1.4 million after-tax, $.02 per share); 1992 includes a $15.5 million pretax provision for litigation ($10.2 million
after-tax, $.16 per share); 1991 includes a $15.1 million pretax gain from the sale of Oklahoma utility properties and
non-U. S. gas and oil properties; and 1990 includes a $34 million pretax gain ($22 million after-tax, $.34 per share)
on the sale of investment in Oceaneering International, Inc.
(f) Includes interest not related to borrowings of $8.2 million.
(g) Includes a $10.8 million ($.16 per share) charge to deferred federal income taxes resulting from the 1% increase in the
statutory federal income-tax rate on corporations.
(h) In addition, a distribution was made in 1990 of 2 million shares of Pool Energy Services Company common stock. The
approximate value per share of ENSERCH common stock of this distribution was $.33.
(i) In January 1994, the entire $650 million line of credit was unused. (See Note 2)
A-3
ENSERCH CORPORATION
FINANCIAL REVIEW
RESULTS OF OPERATIONS
Earnings applicable to common stock for the year 1993 were $47 million
($.70 per share), compared with a loss applicable to common stock for 1992 of
$41 million ($.62 per share) and 1991 earnings of $5 million ($.07 per share).
Results from continuing operations, after provision for preferred
dividends, were a loss of $27 million ($.41 per share) in 1993, a loss of
$9 million ($.14 per share) in 1992 and income of $23 million ($.36 per share)
in 1991. Results from continuing operations for 1993 were impacted by the
following items:
- An $8 million after-tax ($12 million pretax) charge for efficiency
enhancements and severance expenses accrued for staff reductions in
Natural Gas Transmission and Distribution operations;
- An $11 million charge to deferred federal income taxes resulting from
the 1% increase in the statutory federal income-tax rate on corpora-
tions;
- A $9 million after-tax ($13 million pretax) write-off of non-U.S.
gas and oil assets; and
- A $27 million after-tax ($41 million pretax) charge as a result of
an adverse judgment in litigation that required additional payment
in a limited partnership exchange offer made in 1989 beyond the
amount that the Corporation believes represented fair value. In
addition, there was a $4 million after-tax ($6 million pretax)
charge for additional interest awarded.
The 1992 results from continuing operations included an $11 million after-tax
($17 million pretax) write-off of abandoned offshore facilities and a
$10 million after-tax ($15 million pretax) provision for litigation. Results
from continuing operations in 1991 included after-tax gains totaling $10 mil-
lion from the sale of properties.
Revenues for 1993 were $1.9 billion, compared with $1.7 billion in both
1992 and 1991. Operating income for 1993 was $73 million, compared with
$112 million in 1992 and $137 million in 1991. Excluding the effects on
operating income of the unusual charges mentioned above, 1993 operating income
was $140 million versus $129 million for 1992 and $137 million for 1991.
Variations in operating income by business segment are discussed below.
The 1993 results include income from discontinued operations of
$74 million ($1.11 per share), representing after-tax gains totaling $68 mil-
lion ($1.03 per share) from the sale of the principal operating assets of
Ebasco Services Incorporated and the Corporation's 49% interest in Dorsch
Consult, and income from operations before the sale of $6 million. There was
a $16 million ($.25 per share) loss from discontinued operations in 1992,
primarily related to the sale of Humphreys and Glasgow International and
provisions for real estate formerly utilized by discontinued operations. In
1991, there was a loss of $19 million ($.29 per share). With these sales, the
Corporation has concluded its involvement in the engineering and construction
business and now reflects these results as discontinued operations.
A-4
Results for the year 1992 also included a $15 million ($.23 per share)
after-tax extraordinary loss from the extinguishment of high interest-rate debt
and the termination of an interest-rate hedge.
NATURAL GAS TRANSMISSION AND DISTRIBUTION
The six-year statistics for Transmission and Distribution operations
(See table of Operating Data) reflect the effects of variable weather
patterns and increasing significance of nonregulated markets.
Operating income for Transmission and Distribution operations for 1993
was $113 million before the $12 million charge relating to the ongoing
reengineering of this business ($101 million after the charge), compared
with $102 million for 1992 and $111 million for 1991. Normal winter weather,
combined with aggressive marketing of services and increased capacity,
contributed to higher sales and transportation volumes in 1993.
Volumes handled during the year were 645 billion cubic feet (Bcf), a 22%
increase from both 1992 and 1991. Gas throughput on Lone Star's pipeline
system reached 554 Bcf in 1993, its highest level since 1981. The volume of
gas sold by Lone Star Gas Company and Enserch Gas Company (EGC) in 1993 totaled
414 Bcf, 18% above the 1992 level and 14% greater than 1991. Sales by EGC
accounted for 59% of total gas sales volumes in 1993 versus 53% in 1992 and 51%
in 1991.
Residential and commercial (R&C) sales volumes were 139 Bcf in 1993, up
16% from the 1992 volumes of 121 Bcf and 8% higher than in 1991, primarily due
to colder winter weather. Heating degree days for 1993 rose 27% over the prior
year and were slightly above normal for the first year since 1989. Industrial
and electric-generation sales volumes of 138 Bcf were 6% greater than in 1992
but 15% less than 1991. Volumes sold to pipelines and others in 1993 totaled
136 Bcf, a 37% improvement from the 1992 level of 99 Bcf, which was improved
40% from the 1991 level of 71 Bcf.
The overall gas sales margin (revenue less cost of gas purchased and
off-system transportation expense) for 1993 improved 7% from the prior year.
The overall gross margin per thousand cubic feet (Mcf) on Lone Star's sales was
$2.09 in 1993, $2.06 in 1992 and $1.96 in 1991. Lone Star has an ongoing rate
program to monitor returns from cities and towns served by its distribution
system, as well as the transmission system that supplies them. In the
aggregate, rate increases provided $1.9 million in annual base-rate relief in
1993. The gross margin per Mcf on gas sold by EGC was $.11 in 1993, down from
$.13 in both 1992 and 1991.
The total gas transportation volume in 1993 was 371 Bcf, a 21%
improvement from 1992 volumes of 307 Bcf, which were slightly above the 1991
level. The gas transportation rate per Mcf averaged $.14 in 1993, compared
with $.15 in 1992 and $.16 in 1991. The margins on incremental volumes
generally are at lower rates and thereby reduce the average margin.
Lone Star's gas purchase contracts are discussed below.
A-5
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION
Operating income for Exploration and Production operations closely
follows fluctuations in product prices and volumes that are shown in the
table of Operating Data.
Before the previously noted litigation charge and write-offs of non-U.S.
gas and oil properties, operating income for Exploration and Production
operations was $17 million for 1993, compared with $10 million for 1992 and
$11 million for 1991. This improvement resulted from significantly increased
natural-gas prices and higher sales volumes.
Revenues for Exploration and Production operations for 1993 of $190 mil-
lion were 11% higher than 1992 and 3% above 1991. In 1993, natural-gas
revenues increased 23% to $146 million, with the average natural-gas price per
Mcf of $2.09 up 15% from the price in 1992 of $1.82. Natural-gas sales volumes
totaled 70 Bcf, a 7% increase from the year-ago period and virtually the same
as 1991. The increase in volumes for 1993 was principally due to accelerated
natural-gas development drilling in East Texas and offshore production from
Mississippi Canyon Block 441 in the Gulf of Mexico, which went on stream in the
second quarter of 1993. Oil revenues declined $8 million to $37 million in
1993 due to a 9% production decline and a 10% decrease in the average sales
price to $17.24 per barrel. The lower volumes in 1993 were primarily the
result of declining production from several North Texas reservoirs.
Spot-market sales, which include monthly and short-term industrial
sales, covered about 70% of 1993 gas sales, compared with 80% in 1992 and 75%
in 1991. During 1994, the percentage of gas sold in the spot market is
expected to be in the range of 75% to 85%.
Drilling activity during the first half of 1993 increased to levels last
experienced by the Corporation in 1987, primarily because of development work
in East Texas. ENSERCH participated in more than 100 wells (79 net) in 1993,
with the majority completed as gas producers in East Texas. Thirty-nine wells
were in progress at yearend. Recompletions and production optimization
measures played a major role in the 1993 production enhancement program.
Results for 1994 will include a full year of production from the
Mississippi Canyon Block 441 deep-water project in the Gulf of Mexico, which
began production in early 1993. The field is producing some 70 million cubic
feet (MMcf) of natural gas and more than 500 barrels of condensate per day from
six wells. ENSERCH is the operator, with a 37.5% working interest in the
project.
The Garden Banks Block 388 oil development project, also in the Gulf,
remains on schedule and on budget, with initial production anticipated by mid-
1995. The final major contract for the conversion of a semi-submersible
drilling rig to a floating production facility was finalized in early 1994.
Installation of the offshore facilities, consisting of the subsea template,
gathering and sales pipelines and shallow-water operations, will begin by mid-
year. Three previously drilled oil wells will be connected to the subsea
template. Initial daily production from three predrilled wells is expected to
total 15 thousand barrels (MBbls) of oil and 12 to 15 MMcf of gas by late 1995,
with peak daily production from the Garden Banks project anticipated in late
1996 at 40 MBbls of oil and 60 MMcf of gas. Gross proven reserves are
presently estimated to be equivalent to 28 million barrels (MMBbls) of oil by
DeGolyer and MacNaughton, an independent consulting firm. ENSERCH is 100%
interest owner and operator of the Garden Banks project.
A-6
ENSERCH has budgeted $116 million for exploration and production
activities in 1994, compared with expenditures of $120 million in 1993. In
1992, ENSERCH sharply curtailed its capital spending to $66 million in response
to poor prices for both natural gas and oil. If the early 1994 weakness in oil
prices persists throughout 1994, appropriate cutbacks in spending may be
undertaken. More than half of ENSERCH's 1994 capital expenditures is earmarked
for domestic onshore drilling.
The Corporation follows the full-cost method of accounting for the
acquisition, exploration and development costs of gas and oil properties. The
overall rate of amortization for U.S. properties was $.98 per million British
thermal units produced for both 1993 and 1992, compared with $.90 in 1991.
Costs of additional offshore projects and increased development costs
associated with older East Texas fields largely account for the increase from
1991.
During 1993, the Corporation wrote off some $13 million representing all
remaining capitalized costs associated with its non-U.S. gas and oil proper-
ties.
ENSERCH's natural-gas reserves at January 1, 1994, were 1.09 trillion
cubic feet (Tcf), compared with 1.10 Tcf the year earlier, as estimated by
DeGolyer and MacNaughton. Oil and condensate reserves, including natural gas
liquids attributable to leasehold interests, were 39 MMBbls, virtually the same
as the year-ago level.
At January 1, 1994, estimated future pretax net cash flows from
ENSERCH's owned proved gas and oil reserves, based on average prices and
contracts in effect in December 1993, were $2.0 billion, about the same as
the year earlier. The net present value of such cash flows, discounted at
the Securities and Exchange Commission (SEC)-prescribed 10%, was $1.1
billion, virtually the same as the prior year. These discounted cash flow
amounts are the basis for the SEC-prescribed cost-center ceiling for the
full-cost accounting method. The margin between the cost-center ceiling and
the unamortized capitalized costs of U.S. gas and oil properties was
approximately $75 million at December 31, 1993. Product prices are subject
to seasonal and other fluctuations. A significant decline in prices from
yearend 1993 or other factors, without mitigating circumstances, could cause
a future write-down of capitalized costs and a noncash charge against earnings.
In November 1993, an adverse judgment in litigation required additional
payment for a limited partnership exchange offer made in 1989. The award
included $41 million for the units and $21 million of prejudgment and
post-judgment interest ($15 million was charged against an existing reserve for
litigation). The $41 million additional payment was charged against income in
the fourth quarter. The Corporation had believed that any additional
consideration for the units should be capitalized; however, after further
review at the time of the judgment, the expensing of the final court-ordered
payment was prudent and necessary because it did not bring additional value.
NATURAL GAS LIQUIDS PROCESSING
Operating income for Natural Gas Liquids (NGL) Processing operations for
1993 was $5 million, compared with $13 million for 1992 and $21 million for
1991. Higher prices for natural gas, the feedstock used in NGL production, and
continued lower NGL sales prices caused margins to decline. The average NGL
A-7
sales price per barrel in 1993 of $12.34 was down 8% from 1992 and was 11%
below 1991, while NGL sales volumes of 6.0 MMBbls were virtually the same as
1992 and 1991.
POWER AND OTHER
ENSERCH's power and other activities, comprised of Enserch Development
Corporation, Lone Star Energy Company and Enserch Environmental Corporation,
had 1993 operating income of $15 million, compared with $20 million for 1992
and $9 million for 1991. Enserch Development Corporation's 1993 operating
income was $5.9 million, compared with $9.8 million for 1992 and $2.1 million
for 1991. Current year results included a $15 million pretax gain from the
sale of a position in a power project that had been scheduled for development,
while 1992 and 1991 results included development fees from cogeneration
projects of $15 million and $5 million, respectively. Lone Star Energy
Company's 1993 operating income was $3.9 million, some 8% higher than 1992 but
slightly below 1991.
Enserch Environmental Corporation, which was retained when Ebasco's
principal operating assets were sold in December 1993, had operating income for
1993 of $5.7 million, compared with $6.8 million for 1992 and $2.9 million for
1991. Backlog was $600 million at December 31, 1993.
OTHER INCOME AND EXPENSE ITEMS
Other income/(expense) for 1993 includes pretax gains totaling
$7 million from the sale of a gas storage facility and the Corporation's
minority investment in an insurance entity. Partially offsetting was a $5.6
million provision for the interest awarded in the judgment described earlier,
while the 1992 amount principally reflected a $15 million provision for
litigation. The sale of Oklahoma utility properties and non-U.S. gas and oil
properties in 1991 resulted in pretax gains of $15 million. Details of other
income/(expense) are included in Note 12.
Interest expense for 1993 was $80 million, including $8 million not
related to borrowings, compared with $97 million for 1992 and $96 million for
1991. The reduction is the result of ongoing restructuring of long-term debt
at lower rates and lower short-term interest rates. Interest capitalized in
1993 was $4.5 million, compared with $5.4 million in 1992 and $7.5 million in
1991.
Income-tax expense for 1993 includes an $11 million charge to deferred
federal income taxes resulting from the 1% increase in the statutory federal
income-tax rate on corporations. Excluding this charge, the income-tax benefit
on the loss from continuing operations equaled 46% of the pretax loss. At
December 31, 1993, the Corporation had domestic net operating-loss carryfor-
wards and suspended losses of $161 million and tax-credit carryforwards of
$37 million. The tax benefits of these carryforwards and suspended losses,
which total some $93 million, are available to reduce future income-tax
payments. Note 9 provides additional information on income taxes.
A-8
LIQUIDITY AND FINANCIAL RESOURCES
Net cash flows from operating activities of continuing operations for 1993
were $192 million, compared with $211 million in 1992 and $184 million in 1991.
Net cash flows from continuing operations, before cash flow effects of gas-
purchase contract settlements and changes in current operating assets and
liabilities, were $155 million versus $150 million in 1992 and $184 million in
1991. Cash flows associated with gas-purchase contract settlements improved
substantially over the three-year period. Recoveries, net of payments,
provided $51 million in 1993 and $26 million in 1992, while there were net
payments of $7 million in 1991. (These payments are discussed in detail under
"Gas-Purchase Contracts.") In 1993, there was a cash requirement of $14 mil-
lion for the increase in current operating assets and liabilities, compared with
decreases that provided $36 million in 1992 and $7 million in 1991.
Cash of $118 million was provided by investing activities in 1993, compared
with cash requirements of $105 million and $127 million in 1992 and 1991,
respectively. These amounts include cash provided by discontinued operations
of $320 million in 1993, $14 million in 1992 and $37 million in 1991. Cash
provided by discontinued operations in 1993 includes net proceeds of $198 mil-
lion from the sale of the principal operating assets of Ebasco and the 49%
interest in Dorsch and proceeds of $100 million from the limited recourse sale
of retained Ebasco receivables, while 1992 includes net proceeds of $41 million
from the sale of Humphreys and Glasgow International.
There was a net cash requirement for capital spending and other investing
activities of $203 million in 1993, compared with $119 million in 1992 and
$164 million in 1991. The increase in 1993 is primarily due to a higher level
of capital spending for natural-gas and oil exploration and development
programs.
Property, plant and equipment additions by business segments for the past
three years and planned for 1994 are as follows:
[Download Table]
Planned
1994 1993 1992 1991
------- ---- ---- ----
(In millions)
Natural Gas Transmission
and Distribution . . . . . . . . . . . . . . . . . $116 $ 92 $ 76 $ 92
Natural Gas and Oil
Exploration and Production . . . . . . . . . . . . 116 120 66 124
Natural Gas Liquids Processing,
Power and Other. . . . . . . . . . . . . . . . . . 6 10 3 5
The planned expenditures for 1994 are expected to be funded from internal cash
flow and external financings as required.
In 1993, net cash flows from operating and investing activities totaled
$309 million. In addition, $11 million was provided by the sale of common
stock to employee stock plans and there was a $29 million net decrease in cash
and cash equivalents. After the payment of cash dividends of $26 million, net
cash of $324 million was available to reduce outstanding borrowings, with long-
term debt reduced $200 million and commercial paper and other short-term
borrowings decreased $121 million. In 1992, there was $51 million available
to reduce borrowings or for temporary investment.
A-9
In June 1993, the Corporation borrowed $200 million under its interim-term
(13-month) bank lines, with the interest rate based on the London Interbank
Offering Rate plus a fixed percentage. The proceeds were used in refinancing
maturing debt consisting of $76 million net due on a Swiss Franc Note that had
an effective interest rate of 8.9% and $100 million of 11 5/8% Notes that
matured in May 1993, with the remainder used to reduce commercial paper
borrowings. The $200 million interim-term borrowing was repaid in December
1993 in connection with the sale of Ebasco assets and Dorsch.
In February 1993, the Corporation announced a reduction in the quarterly
cash dividend on common stock to $.05 per share from $.20 per share, resulting
in a change in annual cash requirements of about $40 million.
In 1992, Enserch Exploration Partners Ltd. (EP) entered into operating
lease arrangements to provide financing for its portion of the offshore
platforms and related facilities for the Mississippi Canyon Block 441 (37.5%
owned) and Garden Banks Block 388 (100% owned) projects. A total of $34 mil-
lion was required for the Mississippi Canyon Block 441 project, which was com-
pleted in early 1993. The lease arrangement to fund the construction costs
for the Garden Banks facility is estimated to total $235 million when
completed in 1995. (See Note 6.)
Total capitalization was $1.6 billion at December 31, 1993, a decrease of
$184 million from yearend 1992. The decrease reflects a $226 million reduction
in senior long-term debt and a $42 million increase in common shareholders'
equity. Common shareholders' equity, as a percentage of total capitalization,
increased to 41.7% at December 31, 1993 from 34.8% at the end of 1992. At
December 31, 1993, $350 million of shareholders' equity was free of any
restrictions for payment of dividends or acquisition of capital stock.
The current ratio at December 31, 1993 was .72, compared with 1.0 at
yearend 1992 and .95 at yearend 1991. The decline in 1993 was partially
attributable to the sale of $34 million of Ebasco's working capital and the
classification of a $62 million payment relating to the judgment described
above as a current liability. This payment was made in January 1994.
ENSERCH uses the commercial paper market and commercial banking facilities
for short-term needs. Commercial paper and other short-term borrowings, net
of temporary cash investments, totaled $32 million at December 31, 1993,
compared with $121 million at yearend 1992 and $156 million at the end of 1991.
Bank lines for either short- or interim-term borrowings totaled $650 million
at yearend 1993. Presently, all of these lines are unused.
In February 1994, the Corporation issued $150 million of 10-year term notes
at a coupon rate of 6.375%. The proceeds were used in March to fully redeem
the $75 million of Series D Adjustable Rate Preferred Stock at par value and
to retire all outstanding sinking fund debentures, which had a combined
principal balance of $74 million. The premium for early retirement was
$1.4 million. The preferred stock had a minimum dividend rate of 7.5%,
equivalent to 11.54% on a tax-adjusted basis. The sinking fund debentures
had a weighted average interest rate of 8.5%.
In March 1994 the Corporation filed a shelf registration statement with
the Securities and Exchange Commission for the sale from time to time of up
to $450 million in the aggregate of securities, which can be its
senior or subordinated debt securities, or its equity securities or the
securities of a special purpose subsidiary. Proceeds received from any sale
will be used to repay obligations of the Corporation, unless otherwise set
A-10
forth in a prospectus supplement. The type and terms of any security to be
offered will be determined at the time of each offering.
Even though inflation has abated considerably from the levels of the early
1980s, and was only about 2.5% in 1993, it continues to have some influence on
the Corporation's operations. Most notable is that allowances for depreciation
and amortization based on the historical cost of fixed assets may be insuffi-
cient to cover the replacement of some long-lived fixed assets.
GAS-PURCHASE CONTRACTS
Lone Star is a fully integrated intrastate natural-gas utility from well-
head to end use and owns its own gathering, transmission and distribution
facilities. Lone Star buys gas under long-term, intrastate contracts in
order to assure reliable supply to its customers. To obtain this relia-
bility, Lone Star entered into many gas-purchase contracts that provide for
minimum-purchase ("take-or-pay") obligations to gas sellers. In the past,
Lone Star was unable to take delivery of all minimum gas volumes tendered by
suppliers under these contracts. This situation principally resulted from
general economic conditions, the restructuring of regulations in the natural-
gas industry, customers having the availability of lower-priced natural gas
from competitive sources, certain capacity limitations, Railroad Commission
of Texas (RRC) rules regulating takes of gas, and warmer-than-normal winter
temperatures that reduced sales demand. During past years, numerous claims
have been made by gas suppliers asserting Lone Star's failure to meet its
minimum purchase obligations, and other claims such as disputing prices paid
for gas purchased under contracts. Lone Star has substantially reduced the
potential assertions resulting from such claims through negotiations and
contractual and statutory provisions. Producer settlement obligations in
Lone Star's contracts have been reduced substantially in recent years.
Claims asserted for events during 1992 and anticipated claims for 1993 are
negligible.
Take-or-pay contract provisions generally allow for payments to be recouped
by taking gas in future periods without payment in accordance with the terms
of the contract. When the gas is taken, the previous advance payment becomes
a part of gas cost that is charged to customers. Alternatively, Lone Star, in
many cases, has negotiated "nonrecoupable" payments that generally are much
less in amount than comparable recoupable payments but provide no rights to
recoup gas in future periods. Nonrecoupable settlement payments are included
in gas costs recovered through customer billings as described below.
Obligations to purchase gas in the future are estimated to be as follows
(in millions): 1994, $150; 1995, $120; 1996, $95; 1997, $90; 1998, $80; and
thereafter, not more than $70, with the final contracts expiring in 2003.
Based on Lone Star's estimated gas demand of about 170 Bcf annually, which
assumes normal weather conditions, it is expected that normal gas purchases
will substantially satisfy purchase obligations for the year 1994 and
thereafter; however, any payments that may be required to be made for
obligations not met are recoupable under contract provisions or are recoverable
from customers as gas purchase costs. Therefore, a provision for loss is not
required.
Lone Star's regulated rates for residential and commercial customers
and its contractual rates for industrial and electric-generation customers
include gas costs recorded each month (including out-of-period costs), an
allowance for other costs and expenses, and a return on investment. Its
residential and commercial distribution rates are set at the cost of service
within each city
A-11
by the local municipal governments. The RRC has appellate jurisdiction over
the city distribution rates and original jurisdiction over the rates outside
city limits. The RRC regulates the intracompany city gate rate or charge for
the transmission service outside city limits that is included as a cost for
distribution service to residential and commercial customers within city
limits. The RRC provides a gas cost recovery mechanism in the city gate rate
that is designed to match gas costs with revenues on a timely basis to prevent
margin erosion or excesses by allowing both positive and negative gas cost
changes to flow through to the customers. The Texas city gate gas cost
recovery mechanism limits the amount of out-of-period gas costs, of which
producer settlements are a part, that can be charged to customers in a
particular month. The existing recovery mechanism does, however, allow for
ultimate recovery of gas costs, including such out-of-period payments.
Similarly, contractual provisions provide for recovery of the allocated share
of these costs from industrial and electric-generation customers. Therefore,
a provision for loss is not required.
At December 31, 1993, the approximate amount of unsettled gas-purchase
contract claims asserted by suppliers, as well as estimated claims that are
probable of assertion, was $80 million. Of this total, approximately $70
million relates to a claim filed in 1993 primarily related to asserted
obligations for purchases for early through mid-1980s. (See Note 6.) In some
cases, the claimed amount includes other asserted damages in addition to the
take-or-pay claim. The possibility exists that additional gas-purchase
contract claims might be asserted by other claimants. Lone Star expects to
resolve the foregoing claims at substantially less than the claimed amounts.
Due to the different forms of settlement, as discussed above, the ultimate
liability to a supplier, if any, generally cannot be reasonably estimated prior
to settlement; however, a liability is recorded in the financial statements for
those claims when a settlement is probable and an amount can be reasonably
estimated. A provision for loss is not required since settlement payments are
recoupable under contracts or recoverable through billings to customers, as
previously discussed.
At December 31, 1993, there was an unrecovered balance of gas-purchase
contract settlements of $111 million, down from $173 million at December 31,
1992. The balances include take-or-pay settlements, amounts relating to
pricing and amounts related to the settlement of other contractual matters.
Of the $111 million, $63 million represented prepayments for gas expected to
be recouped under contracts covering future gas purchases. The remaining
$48 million represented amounts expected to be recovered from customers under
the existing gas cost recovery provisions. Lone Star expects to recoup or
recover the remaining balances of gas settlement payments made to date, as well
as future payments to be made in settlement of remaining claims. The period
of recovery is dependent on the overall demand for gas by Lone Star's
customers, which is influenced by weather conditions.
A summary of transactions related to unrecovered gas settlement payments
during the two years ended December 31, 1993, is as follows:
A-12
[Download Table]
Recoupable Recoverable
Prepayments Settlements Total
----------- ----------- -----
(In millions)
December 31, 1991. . . . . . . . . . . . . . $ 97 $111 $208
Gas-purchase contract settlements 21 19 40
Recouped and recovered. . . . . . . . . . (30) (45) (75)
---- ---- ----
December 31, 1992. . . . . . . . . . . . . . 88 85 173
Gas-purchase contract settlements 1 10 11
Recouped and recovered. . . . . . . . . . (24) (48) (72)
Other . . . . . . . . . . . . . . . . . . (2) 1 (1)
---- ---- ----
December 31, 1993. . . . . . . . . . . . . . $ 63 $48 $111
==== ==== ====
FOURTH-QUARTER RESULTS
Earnings applicable to common stock for the fourth quarter of 1993 were
$36 million ($.53 per share), compared with a loss of $33 million ($.49 per
share) for the fourth quarter of 1992. Fourth quarter income from discontinued
operations was $70 million ($1.04 per share), compared with a loss of
$16 million ($.25 per share) for the same period a year earlier. Results for
the fourth quarter of 1992 also included a $10 million after-tax extraordinary
loss from debt extinguishment. There was a loss from continuing operations
after provision for preferred dividends for the fourth quarter of 1993 of
$34 million ($.51 per share) versus a loss of $6 million ($.08 per share) for
the year-ago period. Results for the 1993 and 1992 fourth quarters included
all of the unusual items noted for the full year, except for after-tax charges
of $10.8 million for the increase in the statutory federal income tax rate,
$3.6 million for litigation and $2.0 million for write-offs of non-U.S. gas and
oil properties that occurred earlier in 1993. Before unusual items, operating
income for the 1993 fourth quarter was $28 million, compared with $52 million
for the year-earlier quarter. In addition to the unusual items noted, fourth
quarter 1993 operating income was reduced by some $10 million of other year-end
provisions. Results for the fourth quarter of 1992 were enhanced by develop-
ment fees of $15 million from a cogeneration project. Fundamental results were
about the same in both quarters.
NEW ACCOUNTING STANDARDS
SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other Than
Pensions," which mandates the accounting for medical and life insurance and
other nonpension benefits provided to retired employees, was adopted by the
Corporation effective January 1, 1993. (See Note 8.)
SFAS No. 112, "Employer's Accounting for Postemployment Benefits," will
become effective for the Corporation in 1994. This standard covers the
accounting for estimated costs of benefits provided to former or inactive
employees before their retirement. The Corporation currently accrues costs of
benefits to former or inactive employees by varying methods. The new standard
is not expected to have a significant effect on results of operations or
financial condition.
A-13
[Enlarge/Download Table]
NATURAL GAS TRANSMISSION AND DISTRIBUTION OPERATING DATA
----------------------------------------------------------------------------------------------------------------------------
For Year Ended December 31 1993 1992 1991 1990 1989 1988
----------------------------------------------------------------------------------------------------------------------------
Operating Income (in millions) . . . . $ 101.5(a) $ 102.0 $ 111.5 $ 101.7 $ 136.4 $ 115.2
======== ======== ======== ======== ======== ========
Natural Gas Sales Revenues
by Customer (in millions)
Residential & commercial . . . . . $ 823.8 $ 716.5 $ 702.9 $ 684.3 $ 756.8 $ 701.3
Industrial & electric generation . 357.2 350.8 373.8 418.3 444.9 446.8
Pipeline & other . . . . . . . . . 293.7 185.2 124.9 112.9 90.5 59.0
-------- -------- -------- -------- -------- --------
Total gas sales revenues. . . . $1,474.7 $1,252.5 $1,201.6 $1,215.5 $1,292.2 $1,207.1
======== ======== ======== ======== ======== ========
Natural Gas Revenues (in millions)
Lone Star Gas Company Sales. . . . . $ 954.2 $ 905.1 $ 895.7 $ 916.9 $1,026.3 $ 998.0
Enserch Gas Company Sales (b). . . . 520.5 347.4 305.9 298.6 265.9 209.1
-------- -------- -------- -------- -------- --------
Total gas sales revenues. . . . 1,474.7 1,252.5 1,201.6 1,215.5 1,292.2 1,207.1
Gas transportation . . . . . . . . . 52.2 46.9 48.9 47.0 46.0 45.4
-------- -------- -------- -------- -------- --------
Total natural gas revenues. . . 1,526.9 1,299.4 1,250.5 1,262.5 1,338.2 1,252.5
Other. . . . . . . . . . . . . . . . 21.0 18.9 22.8 22.6 22.8 17.7
-------- -------- -------- -------- -------- --------
Total revenues. . . . . . . . . $1,547.9 $1,318.3 $1,273.3 $1,285.1 $1,361.0 $1,270.2
======== ======== ======== ======== ======== ========
Natural Gas Sales Volumes
by Customer (Bcf)
Residential & commercial . . . . . 139.3 120.6 128.5 122.6 140.3 132.9
Industrial & electric generation . 138.0 130.3 163.2 164.1 171.5 162.7
Pipeline & other . . . . . . . . . 136.2 99.3 70.9 58.9 47.9 30.3
-------- -------- -------- -------- -------- --------
Total gas sales volumes . . . . 413.5 350.2 362.6 345.6 359.7 325.9
======== ======== ======== ======== ======== ========
Natural Gas Volumes (Bcf)
Lone Star Gas Company Sales. . . . . 169.5 163.4 178.9 180.9 212.1 207.7
Enserch Gas Company Sales (b). . . . 244.0(c) 186.8 183.7 164.7 147.6 118.2
-------- -------- -------- -------- -------- --------
Total gas sales volumes . . . . 413.5 350.2 362.6 345.6 359.7 325.9
======== ======== ======== ======== ======== ========
Gas transportation
For associated . . . . . . . . . . 139.8 129.5 133.0 118.4 115.3 92.9
For others (nonassociated) . . . . 231.3 177.8 165.9 134.7 135.7 139.9
-------- -------- -------- -------- -------- --------
Total . . . . . . . . . . . . . 371.1 307.3 298.9 253.1 251.0 232.8
======== ======== ======== ======== ======== ========
Lone Star System throughput. . . . . 554.0 482.6 501.6 456.8 495.4 465.8
Off-system sales (d) . . . . . . . . 90.8 45.4 26.9 23.5
-------- -------- -------- -------- -------- --------
Total throughput (e). . . . . . 644.8 528.0 528.5 480.3 495.4 465.8
======== ======== ======== ======== ======== ========
Natural Gas Sales Revenues per Mcf
by Customer
Residential & commercial . . . . . $ 5.91 $ 5.94 $ 5.47 $ 5.58 $ 5.39 $ 5.28
Industrial & electric generation . 2.59 2.69 2.29 2.55 2.59 2.75
Pipeline & other . . . . . . . . . 2.16 1.86 1.76 1.92 1.89 1.95
-------- -------- -------- -------- -------- --------
Composite . . . . . . . . . . . $ 3.57 $ 3.58 $ 3.31 $ 3.52 $ 3.59 $ 3.70
======== ======== ======== ======== ======== ========
Natural Gas Revenues per Mcf
Lone Star Gas Company Sales. . . . . $ 5.63 $ 5.54 $ 5.01 $ 5.07 $ 4.84 $ 4.81
Enserch Gas Company Sales (b). . . . 2.13 1.86 1.67 1.81 1.80 1.77
Natural Gas Purchase Cost per Mcf
Lone Star Gas. . . . . . . . . . . . $ 3.54 $ 3.48 $ 3.05 $ 3.20 $ 3.10 $ 3.08
Enserch Gas Company (b). . . . . . . 2.02 1.73 1.54 1.66 1.67 1.63
Gas Transportation Rate per Mcf. . . . $ .14 $ .15 $ .16 $ .19 $ .18 $ .19
Natural Gas Customers
(at December 31) (in thousands). . . 1,265 1,243 1,224 (f) 1,249 1,241 1,234
Heating Degree Days. . . . . . . . . . 2,508 1,980 2,179 2,015 2,632 2,365
% of normal (2,407) (g). . . . . . . 104.2 82.3 90.5 83.7 109.3 98.3
Cooling Degree Days. . . . . . . . . . 2,767 2,415 2,670 2,791 2,563 2,711
% of normal (2,603) (g). . . . . . . 106.3 92.8 102.6 107.2 98.5 104.1
A-14
------------------
<FN>
(a) Includes a $12.0 million pretax charge ($7.8 million after-tax, $.12 per share) for efficiency enhancements and severance
expenses accrued for staff reductions.
(b) Prior to 1992, also included Enserch Gas Transmission Company (EGT). The former operations of EGT are now only 50% owned
and are not included in statistics after 1991.
(c) Includes 42 Bcf purchased for resale from affiliates.
(d) Includes off-system sales never entering Lone Star's pipeline system.
(e) Total throughput is the sum of gas sales volumes and gas transportation volumes for others. Gas transported by Lone Star
for Enserch Gas Company is reported in both sales and associated transportation.
(f) Oklahoma properties sold in 1991 had 36,000 customers.
(g) As determined by the Department of Commerce based on National Weather Service data for the 30 year period 1961-1990.
A-15
[Enlarge/Download Table]
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION OPERATING DATA
----------------------------------------------------------------------------------------------------------------------------
For Year Ended December 31 1993 1992 1991 1990 1989 1988
----------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) (in millions). $(37.3)(a) $ (6.2)(b) $ 10.9 $ 31.9 $ 43.4 $ 36.1
====== ====== ====== ====== ====== ======
Revenues - After Royalties (in millions)
Natural gas (c) . . . . . . . . . . $146.4 $118.6 $123.4 $142.9 $139.2 $147.8
Oil and condensate . . . . . . . . . 36.9 45.1 56.7 68.6 58.0 47.8
Natural gas liquids. . . . . . . . . 4.1 6.5 2.0 2.2 1.9 1.8
Other revenues - net . . . . . . . . 2.4 1.3 1.5 .2 3.8 7.3
Less minority interest in EP . . . . (18.9) (24.0)
------ ------ ------ ------ ------ ------
Total revenues . . . . . . . . . $189.8 $171.5 $183.6 $213.9 $184.0 $180.7
====== ====== ====== ====== ====== ======
Sales Volumes
Natural gas (Bcf) (c). . . . . . . . 70.0 65.2 70.1 76.9 76.3 81.2
Oil and condensate (MMBbl) . . . . . 2.1 2.3 2.8 3.1 3.3 3.2
Average Sales Price
Natural gas (per Mcf). . . . . . . . $ 2.09 $ 1.82 $ 1.76 $ 1.85 $ 1.81 $ 1.83
Oil and condensate (per Bbl) . . . . 17.24 19.20 20.31 22.39 17.37 15.12
Net Wells
Drilled. . . . . . . . . . . . . . . 79 19 67 53 18 52
Productive . . . . . . . . . . . . . 64 8 52 42 14 35
Proved Reserves (at December 31)
Gas (Bcf). . . . . . . . . . . . . . 1,086 1,101 1,168 1,237 1,230 1,150
Oil and condensate (MMBbl)(d). . . . 39.3 39.2 40.0 32.3 28.1 32.7
Standardized Measure of Discounted
Future Net Cash Flows (in millions). $ 831 $ 820 $ 812 $ 963 $ 840 $ 731
Data in Equivalent Energy Content
(per MMBtu) (e)
Average sales price. . . . . . . . . $ 2.16 $ 2.04 $ 2.03 $ 2.17 $ 2.00 $ 1.91
Average production costs . . . . . . .56 .55 .60 .54 .52 .49
U. S. Amortization rate. . . . . . . .98 .98 .90 .78 .72 .66
-------------------------------------------------
<FN>
NOTE: The Corporation held a proportional ownership interest in Enserch Exploration Partners, Ltd. (EP) of approximately 87%
prior to October 1989 and in excess of 99% thereafter. Data reflected in the table above include 100% of EP for all
periods.
(a) Includes a $41.4 million pretax charge ($26.9 million after-tax, $.40 per share) as a result of an adverse judgment in
litigation that required additional payment in a limited partnership exchange offer made in 1989 and a $13.3 million
pretax write-off ($8.6 million after-tax, $.13 per share) of non-U. S. gas and oil properties.
(b) Includes a $16.5 million pretax write-off ($10.9 million after-tax, $.17 per share) of an idle pipeline and shallow-water
production facility from an abandoned offshore project.
(c) Excludes products purchased for resale. Includes affiliated revenues and volumes.
(d) Reserves include natural gas liquids attributable to leasehold interests.
(e) For the purpose of providing a common unit of measure, natural gas, oil and natural gas liquids are converted to an
approximate equivalent unit on the basis of relative energy content: one Mcf of natural gas equals 1.05 MMBtu, one barrel
of oil equals 5.6 MMBtu and one barrel of natural gas liquids equals 4.2 MMBtu.
A-16
[Enlarge/Download Table]
NATURAL GAS LIQUIDS PROCESSING OPERATING DATA
----------------------------------------------------------------------------------------------------------------------------
For Year Ended December 31 1993 1992 1991 1990 1989 1988
----------------------------------------------------------------------------------------------------------------------------
Operating Income (in millions) . . . . $ 5.0 $ 13.1 $ 21.2 $ 24.9 $ 4.2 $ 5.6
======== ======== ======== ======== ======== ========
Revenues (in millions)
Natural gas liquids (a). . . . . . . $ 73.6 $ 79.0 $ 84.8 $ 91.8 $ 71.6 $ 72.9
Other. . . . . . . . . . . . . . . . 12.2 8.0 8.0 7.6 5.0 2.6
-------- -------- -------- -------- -------- --------
Total . . . . . . . . . . . . . . $ 85.8 $ 87.0 $ 92.8 $ 99.4 $ 76.6 $ 75.5
======== ======== ======== ======== ======== ========
Natural Gas Liquids
Sales volumes (MMBbl) (a). . . . . . 6.0 5.9 6.1 6.4 7.2 7.5
Average sales price (per Bbl). . . . $ 12.34 $ 13.35 $ 13.92 $14.27 $ 9.96 $ 9.73
Proved Reserves of Natural Gas
Liquids Under Contractual
Processing Rights (MMBbl). . . . . . 27.2 28.2 28.4 28.7 30.7 36.6
<FN>
(a) Excludes products purchased for resale.
A-17
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of ENSERCH Corporation:
We have audited the accompanying consolidated balance sheets of ENSERCH
Corporation and subsidiary companies as of December 31, 1993 and 1992, and the
related statements of consolidated income, cash flows and common shareholders'
equity for each of the three years in the period ended December 31, 1993.
These financial statements are the responsibility of the Corporation's
management. Our responsibility is to express an opinion on these financial
statements based on our audits. We have previously audited the consolidated
balance sheets of ENSERCH Corporation and subsidiary companies as of December
31, 1991, 1990, 1989 and 1988 and the related statements of consolidated
income, cash flows and common shareholders' equity for the years ended December
31, 1990, 1989, and 1988 (not presented herewith), and have expressed
unqualified opinions thereon.
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, such consolidated financial statements present fairly, in
all material respects, the financial position of ENSERCH Corporation and
subsidiary companies at December 31, 1993 and 1992, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1993, in conformity with generally accepted accounting principles.
Also, in our opinion, the information set forth in the accompanying table of
selected financial data for the years 1988 through 1993 is fairly stated in all
material respects in relation to the consolidated financial statements from
which such information has been derived.
DELOITTE & TOUCHE
Dallas, Texas
February 7, 1994
A-18
MANAGEMENT REPORT ON RESPONSIBILITY FOR FINANCIAL REPORTING
The management of ENSERCH Corporation is responsible for the preparation,
presentation and integrity of the financial statements contained in this
report. These statements have been prepared in conformity with accounting
principles generally accepted in the United States and include amounts that
represent management's best estimates and judgments. Management has estab-
lished practices and procedures designed to support the reliability of the
estimates and minimize the possibility of a material misstatement. Management
also is responsible for the accuracy of the other information presented in the
annual report and for its consistency with the financial statements.
Management has established and maintains internal accounting controls that
provide reasonable assurance as to the integrity and reliability of the
financial statements, the protection of assets from unauthorized use or
disposition, and the prevention and detection of fraudulent financial
reporting. The system of internal control provides for appropriate division
of responsibility and is documented by written policies and procedures that are
communicated to employees with significant roles in the financial reporting
process and updated as necessary. Management continually monitors compliance
with the system of internal accounting controls. The Corporation maintains a
strong internal audit function that evaluates the adequacy of the system of
internal accounting controls. As part of the annual audit of the financial
statements, Deloitte & Touche also performs a study and evaluation of the
system of internal accounting controls as necessary to determine the nature,
timing, and extent of their auditing procedures. The Board of Directors
maintains an Audit Committee composed of Directors who are not employees. The
Audit Committee meets periodically with management, the independent auditors
and the internal auditors to discuss significant accounting, auditing, internal
accounting control and financial reporting matters. A procedure exists whereby
either the independent or the internal auditors through the independent
auditors may request, directly to the Audit Committee, a meeting with the
Committee.
Management has given proper consideration to the independent and internal
auditors' recommendations concerning the system of internal accounting controls
and has taken corrective action believed appropriate in the circumstances.
Management further believes that, as of December 31, 1993, the overall system
of internal accounting controls is sufficient to accomplish the objectives
discussed herein.
A-19
Management recognizes its responsibility for establishing and maintaining
a strong ethical climate so that the Corporation's affairs are conducted
according to the highest standards as defined in the Corporation's Statement
of Policies. The Statement of Policies is publicized throughout the Corpora-
tion and addresses, among other issues, open communication within the
Corporation; the disclosure of potential conflicts of interest; compliance with
the laws, including those relating to financial disclosure; and the confidenti-
ality of proprietary information.
s/D. W. Biegler
------------------------------
D. W. Biegler
Chairman and President,
Chief Executive Officer
s/S. R. Singer
------------------------------
S. R. Singer
Senior Vice President,
Finance and Corporate
Development, Chief
Financial Officer
s/J. W. Pinkerton
------------------------------
J. W. Pinkerton
Vice President and Controller,
Chief Accounting Officer
February 7, 1994
A-20
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31
-----------------------------------------------------------------------------------------------------------
1993 1992 1991
-------- -------- --------
(In thousands except per share amounts)
Revenues
Natural gas transmission and distribution. . . . . . $1,547,919 $1,318,258 $1,273,282
Natural gas and oil exploration and production . . . 189,796 171,544 183,590
Natural gas liquids processing . . . . . . . . . . . 85,785 86,966 92,817
Power and other. . . . . . . . . . . . . . . . . . . 217,559 191,277 153,609
Less intercompany revenues . . . . . . . . . . . . . (138,934) (53,484) (49,156)
---------- ---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . 1,902,125 1,714,561 1,654,142
---------- ---------- ----------
Costs and Expenses
Gas purchase . . . . . . . . . . . . . . . . . . . . 1,021,107 902,346 849,613
Operating expenses . . . . . . . . . . . . . . . . . 574,240 478,116 457,771
Depreciation and amortization. . . . . . . . . . . . 144,761 142,712 124,838
Gross receipts and production taxes. . . . . . . . . 55,924 52,517 53,444
Payroll, ad valorem and other taxes. . . . . . . . . 33,281 26,662 31,397
---------- ---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . 1,829,313 1,602,353 1,517,063
---------- ---------- ----------
Operating Income . . . . . . . . . . . . . . . . . . . 72,812 112,208 137,079
Other Income (Expense) - Net (Note 12) . . . . . . . . 174 (12,452) 14,070
Interest Expense (Note 12) . . . . . . . . . . . . . . (80,226) (97,050) (95,627)
---------- ---------- ----------
Income (Loss) before Income Taxes. . . . . . . . . . . (7,240) 2,706 55,522
Income Taxes (Benefit)(Note 9) . . . . . . . . . . . . 7,472 (808) 17,748
---------- ---------- ----------
Income (Loss) from Continuing Operations . . . . . . . (14,712) 3,514 37,774
Income (Loss) from Discontinued Operations (Note 11) . 73,949 (16,162) (18,709)
Extraordinary Loss on Extinguishment of Debt (Note 2). (15,358)
---------- ---------- ----------
Net Income (Loss). . . . . . . . . . . . . . . . . . . 59,237 (28,006) 19,065
Provision for Dividends on Preferred Stock . . . . . . 12,663 12,952 14,300
---------- ---------- ----------
Earnings (Loss) Applicable to Common Stock . . . . . . $ 46,574 $ (40,958) $ 4,765
========== ========== ==========
Per Share of Common Stock
Income (loss) from continuing operations
after provision for dividends on
preferred stock. . . . . . . . . . . . . . . . . . $ (.41) $ (.14) $ .36
Discontinued operations. . . . . . . . . . . . . . . 1.11 (.25) (.29)
Extraordinary loss . . . . . . . . . . . . . . . . . (.23)
---------- ---------- ----------
Earnings (loss) applicable to common stock . . . . . $ .70 $ (.62) $ .07
========== ========== ==========
Cash dividends declared. . . . . . . . . . . . . . . $ .20 $ .80 $ .80
========== ========== ==========
Average Common and Dilutive Common
Equivalent Shares Outstanding. . . . . . . . . . . . 66,598 65,695 65,074
========== ========== ==========
Operating Income (Loss) of Major Business Segments
(Excludes general corporate expenses)
Natural gas transmission and distribution. . . . . . $ 101,458 $ 101,996 $ 111,487
Natural gas and oil exploration and production . . . (37,293) (6,175) 10,910
Natural gas liquids processing . . . . . . . . . . . 5,037 13,092 21,211
Power and other. . . . . . . . . . . . . . . . . . . 15,478 20,167 8,953
<FN>
See Notes to Consolidated Financial Statements.
A-21
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31
-----------------------------------------------------------------------------------------------------------------------
1993 1992 1991
-------- -------- --------
(In thousands)
OPERATING ACTIVITIES
Income (loss) from continuing operations . . . . . . . . . . . . . $(14,712) $ 3,514 $ 37,774
Adjustments to reconcile income (loss) to net cash flows
Depreciation and amortization. . . . . . . . . . . . . . . . . . 144,761 142,712 124,838
Deferred income tax expense (benefit) (Note 9) . . . . . . . . . 16 (8,332) 17,020
Recoveries (payments) of gas purchase contract settlements -
net, excluding effect of sales of associated
accounts receivable. . . . . . . . . . . . . . . . . . . . . . 50,825 25,612 (6,646)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24,923 11,906 4,351
-------- -------- --------
Net cash flows provided by continuing operating
activities before changes in current operating
assets and liabilities . . . . . . . . . . . . . . . . . . 205,813 175,412 177,337
Cash effect of changes in current operating
assets and liabilities (Note 12) . . . . . . . . . . . . . . . (13,984) 35,733 6,826
-------- -------- --------
Net Cash Flows from Operating Activities . . . . . . . . . . 191,829 211,145 184,163
-------- -------- --------
INVESTING ACTIVITIES
Property, plant and equipment additions. . . . . . . . . . . . . (221,529) (145,122) (221,452)
Proceeds from disposition of significant assets. . . . . . . . . 7,825 16,640 52,869
Property, plant and equipment retirements. . . . . . . . . . . . 7,386 6,186 7,847
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,466 3,583 (2,797)
Discontinued operations
Operations . . . . . . . . . . . . . . . . . . . . . . . . . . 22,435 (27,502) 36,596
Proceeds from sale of assets . . . . . . . . . . . . . . . . . 198,113 41,222
Proceeds from sale of retained accounts receivable . . . . . . 99,897
-------- -------- --------
Net Cash Flows from (used for) Investing Activities. . . . . 117,593 (104,993) (126,937)
-------- -------- --------
Net Cash Flows from Operating and Investing Activities . . 309,422 106,152 57,226
-------- -------- --------
FINANCING ACTIVITIES
Change in commercial paper and other short-term borrowings . . . (120,912) 1,743 (2,776)
Issuance of senior long-term debt. . . . . . . . . . . . . . . . 200,000 346,897
Retirement of senior long-term debt. . . . . . . . . . . . . . . (423,523) (239,281) (3,100)
Retirement of convertible subordinated debentures. . . . . . . . (115,000) (9,928)
Settlement of foreign currency swap. . . . . . . . . . . . . . . 23,089
Premium paid on extinguishment of debentures . . . . . . . . . . (7,467)
Other financing activities - net . . . . . . . . . . . . . . . . (2,335) (8,198) 17,586
Issuance of common stock . . . . . . . . . . . . . . . . . . . . 10,876 10,376 9,410
Cash dividends paid. . . . . . . . . . . . . . . . . . . . . . . (25,967) (65,650) (66,605)
-------- -------- --------
Net Cash Flows used for Financing Activities . . . . . . . . (338,772) (76,580) (55,413)
-------- -------- --------
Net (Decrease) Increase in Cash and Equivalents. . . . . . . . . . (29,350) 29,572 1,813
Cash and Equivalents at Beginning of Year. . . . . . . . . . . . . 48,553 18,981 17,168
-------- -------- --------
Cash and Equivalents at End of Year. . . . . . . . . . . . . . . . $ 19,203 $ 48,553 $ 18,981
======== ======== ========
Amounts paid (refunded)
Interest (net of amount capitalized) . . . . . . . . . . . . . . $101,157 $108,881 $115,829
======== ======== ========
Income taxes - net . . . . . . . . . . . . . . . . . . . . . . . $ 20,443 $ 6,087 $ (1,984)
======== ======== ========
<FN>
Information on noncash financing activities is presented in Note 12.
See Notes to Consolidated Financial Statements.
A-22
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
December 31
-----------------------
1993 1992
--------- ----------
(In thousands)
ASSETS
Current Assets
Cash and equivalents (Note 12). . . . . . . . . . . . . . . $ 19,203 $ 48,553
Accounts receivable (Notes 6 & 12). . . . . . . . . . . . . 224,947 293,358
Costs associated with unbilled revenues (Note 12) . . . . . 18,517 244,317
Gas stored underground. . . . . . . . . . . . . . . . . . . 109,615 116,404
Gas purchase settlements recoverable from customers . . . . 42,800 56,263
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 92,485 88,593
---------- ----------
Total current assets. . . . . . . . . . . . . . . . 507,567 847,488
---------- ----------
Investments
Advances and prepayments for gas . . . . . . . . . . . . . 35,444 61,232
Affiliates and other (Note 12). . . . . . . . . . . . . . . 50,764 58,232
---------- ----------
Total investments . . . . . . . . . . . . . . . . . 86,208 119,464
---------- ----------
Property, Plant and Equipment (at cost)
Natural gas transmission and distribution . . . . . . . . . 1,508,531 1,436,247
Natural gas and oil exploration and production (full-cost
method)(Notes 1 & 13) . . . . . . . . . . . . . . . . . . 1,950,516 1,892,129
Natural gas liquids processing. . . . . . . . . . . . . . . 69,028 64,343
Power and other . . . . . . . . . . . . . . . . . . . . . . 39,733 36,783
General . . . . . . . . . . . . . . . . . . . . . . . . . . 26,248 22,778
Discontinued operations . . . . . . . . . . . . . . . . . . 66,053
---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . . . 3,594,056 3,518,333
Less accumulated depreciation and amortization. . . . . . . 1,476,003 1,452,568
---------- ----------
Net property, plant and equipment . . . . . . . . . 2,118,053 2,065,765
---------- ----------
Other Assets. . . . . . . . . . . . . . . . . . . . . . . . . 48,433 112,963
---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . . $2,760,261 $3,145,680
========== ==========
LIABILITIES
Current Liabilities
Commercial paper and other short-term borrowings (Note 2) . $ 31,500 $ 152,412
Current maturities of senior long-term debt (Note 3). . . . 10,600 6,600
Accounts payable and other accrued liabilities. . . . . . . 442,395 492,344
Billings in excess of costs and advances on uncompleted
contracts. . . . . . . . . . . . . . . . . . . . . . . . . 17,284 69,309
Accrued interest. . . . . . . . . . . . . . . . . . . . . . 34,021 45,686
Litigation judgment payable (Note 10) . . . . . . . . . . . 62,035
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 105,250 78,641
---------- ----------
Total current liabilities . . . . . . . . . . . . . 703,085 844,992
---------- ----------
Senior Long-term Debt (Note 3). . . . . . . . . . . . . . . . 628,227 858,695
---------- ----------
Convertible Subordinated Debentures (Note 4). . . . . . . . . 90,750 90,750
---------- ----------
Other Liabilities
Deferred income taxes (Note 9). . . . . . . . . . . . . . . 321,364 332,568
Assignment of future gas purchase credits (Note 12) . . . . 12,163 35,900
Accrued unfunded pension costs (Note 7) . . . . . . . . . . 43,027 47,381
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . 139,927 155,756
---------- ----------
Total other liabilities . . . . . . . . . . . . . . 516,481 571,605
---------- ----------
Commitments and Contingent Liabilities (Note 6) . . . . . . .
Shareholders' Equity (Note 5)
Adjustable rate preferred stock . . . . . . . . . . . . . . 175,000 175,000
Common shareholders' equity . . . . . . . . . . . . . . . . 646,718 604,638
---------- ----------
Shareholders' equity. . . . . . . . . . . . . . . . 821,718 779,638
---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . . $2,760,261 $3,145,680
========== ==========
<FN>
See Notes to Consolidated Financial Statements.
A-23
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED COMMON SHAREHOLDERS' EQUITY
Year Ended December 31
-----------------------------------------
1993 1992 1991
---- ---- ----
(In thousands)
Common Stock - $4.45 par value,
authorized 100 million shares (Note 5)
Balance at beginning of year . . . . . . . . . . . . . . $293,849 $290,593 $288,201
Issued for stock plans (622; 732; and 538 shares). . . 2,770 3,256 2,392
-------- -------- --------
Balance at end of year (Outstanding shares:
66,656; 66,034; and 65,302). . . . . . . . . . . . . . 296,619 293,849 290,593
-------- -------- --------
Paid in Capital
Balance at beginning of year . . . . . . . . . . . . . . 353,789 395,105 392,736
Excess of proceeds over par value of
common stock issued for stock plans. . . . . . . . . 8,106 7,120 7,018
Dividends declared in excess of retained earnings. . . (22,780) (48,436) (4,758)
Other. . . . . . . . . . . . . . . . . . . . . . . . . 109
-------- -------- --------
Balance at end of year . . . . . . . . . . . . . . . . . 339,115 353,789 395,105
-------- -------- --------
Retained Earnings (Deficit)
Balance at beginning of year . . . . . . . . . . . . . . (45,092) 42,388
Net income (loss). . . . . . . . . . . . . . . . . . . 59,237 (28,006) 19,065
Dividends declared (Note 5). . . . . . . . . . . . . . (25,939) (65,521) (66,211)
Transfer of dividends declared in excess of
retained earnings to paid in capital . . . . . . . . 22,780 48,436 4,758
Other. . . . . . . . . . . . . . . . . . . . . . . . . (2) (1)
-------- -------- --------
Balance at end of year . . . . . . . . . . . . . . . . . 10,984 (45,092)
-------- -------- --------
Foreign Currency Translation Adjustment
Balance at beginning of year . . . . . . . . . . . . . . 2,092 576 558
Change during the year . . . . . . . . . . . . . . . . (1,471) (1,104) 676
Deferred income tax effects. . . . . . . . . . . . . . (590) (658)
Recognized upon sale of related entities,
net of deferred income tax effects (Note 11) . . . . (621) 3,210
-------- -------- --------
Balance at end of year . . . . . . . . . . . . . . . . . 2,092 576
-------- -------- --------
Common Shareholders' Equity. . . . . . . . . . . . . . . . $646,718 $604,638 $686,274
======== ======== ========
<FN>
See Notes to Consolidated Financial Statements.
A-24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ENSERCH Corporation and Subsidiary Companies
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
All dollar amounts, except per share amounts, in the notes to the consoli-
dated financial statements are stated in thousands unless otherwise indicated.
Basis of Financial Statements - The consolidated financial statements
include all subsidiaries during the period of ownership and control. The
equity method of accounting is used for investments in affiliates in which
ENSERCH Corporation (ENSERCH or the Corporation) does not have voting control.
Lone Star Gas Company (Lone Star), the gas utility division of ENSERCH
Corporation and principal company in the natural gas transmission and distribu-
tion business operations, is subject to the accounting requirements prescribed
by the National Association of Regulatory Utility Commissioners. Lone Star's
rates are established by the Railroad Commission of Texas and by municipal
governments.
The statements of consolidated income and cash flows previously reported
for 1992 and 1991 have been restated to reflect the engineering and construction
segment as a discontinued operation. Current year reported results reflect the
realignment of the segments of business for financial reporting purposes. All
prior year amounts have been reclassified to reflect the new alignments.
Revenue Recognition - Lone Star records revenues on the basis of cycle
meter readings throughout the month and accrues revenues for gas delivered
but not billed to customers from the meter reading dates to the end of the
month.
The environmental business of the Corporation follows the generally
accepted accounting practice of reporting revenues and income from long-term
contracts on the percentage of completion basis using estimates of total
contract revenue and costs at completion. These estimates are updated
throughout the terms of the contracts and adjustments are made as appro-
priate. All known or anticipated losses on these contracts are charged to
earnings when identified.
Gas and Oil Properties - The full-cost method, as prescribed by the Securi-
ties and Exchange Commission (SEC), is used whereby the costs of proved and
unproved gas and oil properties, together with successful and unsuccessful
exploration and development costs, are capitalized by cost centers on a
country-by-country basis. The carrying value for each cost center is limited
to the present value of estimated future net revenues of proved reserves, the
cost of excluded properties and the lower of cost or market value of unproved
properties being amortized. Dry-hole costs resulting from exploration
activities are classified as evaluated costs and are included in the amortiza-
tion base. Costs directly associated with the acquisition and evaluation of
unproved properties are excluded from the amortization base until the related
properties are evaluated. Such unproved properties are assessed periodically
and a provision for impairment is made to the full-cost amortization base when
appropriate. Sales of gas and oil properties are credited to capitalized costs
unless the sale would have a significant impact on the amortization rate.
Gas Purchase Contracts - The Corporation has made accruals for payments to
producers that may be required for settlement of gas purchase contract claims
asserted or that are probable of assertion. Lone Star's rates billed to
customers provide for the recovery of the actual cost of gas (including out-of-
period costs such as gas purchase contract settlement costs). The Corporation
A-25
continually evaluates its position relative to asserted and unasserted take-or-
pay claims, above-market prices or future commitments. Based on this
evaluation and its experience to date, management believes that the Corporation
has not incurred losses for which reserves should be provided at December 31,
1993.
Depreciation and Amortization - Depreciation is provided principally by the
straight-line method over the estimated service lives of the related assets.
Amortization of evaluated gas and oil properties is computed on the unit-of-
production method by cost center using estimated proved gas and oil reserves
quantified on the basis of their equivalent energy content.
Lone Star's plants are depreciated over approximately 40 years; amortiza-
tion of gas and oil properties was approximately 6.0% in 1993 and 5.7% in both
1992 and 1991.
Earnings Per Share of Common Stock - Earnings per share applicable to com-
mon stock are based on the weighted average number of common shares, including
common equivalent shares when dilutive, outstanding during the year. Common
equivalent shares consist of those shares issuable upon the assumed conversion
of the 10% Convertible Subordinated Debentures during the periods in which they
were outstanding (which were not dilutive in 1992 and 1991) and exercise of
stock options under the treasury stock method. The 6 3/8% Convertible
Subordinated Debentures were not common stock equivalents. Fully diluted
earnings per share are not presented since the assumed exercise of stock
options and conversion of debentures would not be dilutive.
Gas Stored Underground - Gas stored underground is valued at average cost.
The volume of gas that is available for sale within 24 months is classified as
a current asset. The remainder is included in property, plant and equipment.
Fair Value of Financial Instruments - The Corporation has estimated the
fair values of its financial instruments using available market information and
other valuation methodologies in accordance with SFAS No. 107, "Disclosures
About Fair Value of Financial Instruments". Accordingly, the estimates
presented are not necessarily indicative of the amounts that the Corporation
could realize in a current market exchange. Determinations of fair value are
based on subjective data and significant judgment relating to timing of
payments and collections and the amounts to be realized. Different market
assumptions and/or estimation methodologies might have a material effect on the
estimated fair value amounts.
The estimated fair value amounts for specific groups of financial
instruments are presented within the footnotes applicable to such items. When
available, values were based on market quotes from a securities exchange or a
broker-dealer. When such quotes were not available, fair value estimates were
made using a discounted cash flow approach based on the interest rates
currently available for debt with similar terms and maturities.
The fair value of financial instruments for which estimated fair value
amounts have not been specifically presented is estimated to approximate the
related book value.
A-26
2. LINES OF CREDIT AND BORROWINGS
The Corporation maintains domestic and foreign lines of credit that provide
for short- and interim-term (13-month) borrowings and also support commercial
paper borrowings in the U.S. and Europe. Foreign lines provide for borrowings
in either U.S. dollars or in local foreign currencies, with maturities of not
more than 13 months. At December 31, 1993, the aggregate lines of credit were:
[Download Table]
Domestic bank loan lines............... $400,000
Foreign bank loan lines................ 250,000
--------
Total.............................. $650,000
========
The domestic lines are subject to renegotiation annually by May 1 and the
foreign lines by November 1. All lines are on a fee basis and do not require
compensating balances or restrictions on the use of cash. All lines provide
for borrowing at the prime rate or at rates related to the London Interbank
Offering Rate (LIBOR), the banks' certificate of deposit rate, or a money
market based rate.
As of December 31, 1993, $15 million was used to support a letter of credit
issued in connection with the appeal of a lawsuit. This letter of credit was
canceled in January 1994, following satisfaction of amounts awarded under the
lawsuit.
The Corporation has an interest-rate swap agreement, expiring in 1995,
whereby the Corporation pays interest at the rate of 12.26% per annum on a
notional amount of $100 million and receives interest at a floating rate based
on LIBOR. Through November 1992, the notional amount of the swap was matched
to variable interest-rate debt, including commercial paper, and was accounted
for as an interest-rate hedge. In December 1992, the Corporation repaid all
variable rate debt, and the swap arrangement could no longer be accounted for
as an interest-rate hedge. A charge of $10.4 million (net of income-tax
benefit of $5.4 million) was recorded for the estimated cost to terminate the
hedge. (See Notes 3 and 4 for other debt extinguishments.)
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3. SENIOR LONG-TERM DEBT
Senior long-term debt as of December 31 is summarized below:
[Enlarge/Download Table]
1993 1992
-------- --------
5% Swiss franc note (SF144 million)
due 1993 . . . . . . . . . . . . . $ $102,411
11 5/8% Notes due 1993. . . . . . . . . 100,000
8.7% Note due 1994. . . . . . . . . . . 29,316 29,316
9.11% Average rate note due 1994. . . . 100,000 100,000
8% Notes due 1997 . . . . . . . . . . . 100,000 100,000
7% Notes due 1999 . . . . . . . . . . . 150,000 150,000
9.06% Note due 1993 through 1999. . . . 86,800 93,400
8 7/8% Notes due 2001 . . . . . . . . . 100,000 100,000
Sinking fund debentures:
7 1/2% Due 1996. . . . . . . . . . 7,500 9,750
7.65% Due 1998 . . . . . . . . . . 8,949 12,325
8.95% Due 1999 . . . . . . . . . . 18,125 21,875
8 3/4% Due 2001. . . . . . . . . . 19,966 23,716
8 1/2% Due 2002. . . . . . . . . . 19,177 23,677
Other . . . . . . . . . . . . . . . . . (1,006) (1,175)
-------- --------
Total. . . . . . . . . . . . . . 638,827 865,295
Less current maturities. . . . . . . . . . 10,600* 6,600
-------- --------
Noncurrent . . . . . . . . . . . $628,227 $858,695
======== ========
<FN>
* Excludes $129,316 due in 1994 and $73,717 called for early redemption in
1994, all of which will be refinanced on a long-term basis.
In February 1994, the Corporation issued $150 million of 6 3/8% Notes due
2004 in a public offering. Part of the net proceeds of this issue will be used
in March 1994 for early redemption, including call premiums of $1.4 million,
of all the $73.7 million principal amount of the sinking fund debentures
outstanding at December 31, 1993. The remainder of the net proceeds will be
used to redeem in March 1994, all of the $75 million Adjustable Rate Preferred
Stock, Series D. (See Note 5).
In June 1993, the Corporation borrowed $200 million under its interim-term
(13-month) bank lines, with the interest rate based on LIBOR plus a fixed
percentage. The proceeds were used in refinancing maturing debt consisting of
$76 million net due on a Swiss Franc Note that had an effective interest rate
of 8.9% and $100 million of 11 5/8% Notes that matured in May 1993, with the
remainder used to reduce commercial paper borrowings. The $200 million
interim-term borrowing was repaid in December 1993 in connection with the sale
of Ebasco assets and Dorsch.
In March 1992, the Corporation issued $100 million of 8% Notes due 1997 and
$100 million of 8 7/8% Notes due 2001 and in August 1992, issued $150 million
of 7% Notes due 1999, all in public offerings. The net proceeds were used for
early redemption of higher interest-rate debt and convertible subordinated
debentures (see Note 4). The Corporation recognized an extraordinary loss of
A-28
$2.4 million (net of income taxes of $1.2 million) representing the call
premiums, unamortized costs and other expenses associated with the early
extinguishment.
The Corporation has a borrowing of $100 million from a foreign bank under
a variable interest-rate note agreement due November 11, 1994, which provides
for interest at a rate based on LIBOR plus a fixed percentage. The Corporation
entered into a separate $100 million interest-rate swap that fixes interest
payments at an average rate of 9.11% per annum.
The 9.06% Note provides for varying increasing levels of semi-annual
principal payments, including an aggregate of $10.6 million for 1994, with the
last payment due December 28, 1999.
Excluding the sinking fund debentures that have been called for redemption
in March 1994, maturities of senior long-term debt for the following five years
are: 1994, $139.9 million; 1995, $10.6 million; 1996, $13.4 million; 1997,
$117.4 million; and 1998, $17.4 million. The 1994 amount includes $100 million
for the 9.11% Note and $29.3 million for the 8.7% Note which will be refinanced
on a long-term basis. The Corporation is not required to maintain compensating
balances for any of its senior long-term debt.
The estimated fair value of the Corporation's senior long-term debt,
including related interest-rate swaps, was $669 million at December 31, 1993,
and $888 million at December 31, 1992. Such amounts do not include prepayment
penalties which would be incurred upon the early extinguishment of certain debt
issues.
4. CONVERTIBLE SUBORDINATED DEBENTURES
As of December 31, 1993 and 1992, $90,750 of 6 3/8% Convertible
Subordinated Debentures Due 2002 were outstanding and convertible into
shares of the Corporation's common stock at $26.88 per share (equal to 37.20
shares per $1 thousand principal amount). The Corporation, at its option,
may redeem the 6 3/8% Debentures at 103.82% of the principal amount, plus
accrued interest, through March 31, 1994, and at declining premiums there-
after. The estimated fair value of the Corporation's convertible
subordinated debentures was $92 million and $83 million at December 31, 1993
and 1992, respectively.
An extraordinary loss of $2.5 million (net of income-tax benefit of $1.3
million) was recorded for the call premiums and other expenses associated with
the early extinguishment of the 10% Debentures in 1992.
5. SHAREHOLDERS' EQUITY
As of December 31, 1993, 8,368,968 shares of unissued common stock were
reserved for issuance for stock plans and conversion of convertible subordinat-
ed debentures. The Corporation is authorized to issue up to 2,000,000 shares
of preferred stock and 2,000,000 shares of voting preference stock.
A-29
Adjustable Rate Preferred Stock - Information concerning issued and out-
standing shares of adjustable rate preferred stock at December 31, 1993 and
1992, is summarized below:
[Download Table]
Stated
Value Shares
Per Share Outstanding Amount
--------- ----------- ------
Series D........................ $ 50 1,500,000 $ 75,000
Series E........................ $1,000 100,000 100,000
--------- --------
Total.................... 1,600,000 $175,000
========= ========
The Corporation has called for redemption at par in March 1994, all
outstanding shares of the Series D preferred stock at $50 per share, plus
accrued dividends. The Series E stock is deposited with a bank under a
depositary agreement and is represented by 1,000,000 Depositary Shares. The
Series E preferred stock is redeemable at the option of the Corporation at
$103.00 per depositary share through April 30, 1994, thereafter at $100 per
depositary share. Holders of the preferred stock are entitled to its stated
value upon involuntary liquidation.
Dividend rates are determined quarterly, in advance, based on the
"Applicable Rate" (such rate being the highest of the three-month U.S. Treasury
bill rate, the U.S. Treasury ten-year constant maturity rate and the U.S.
Treasury twenty-year constant maturity rate, as defined), as set forth below:
[Download Table]
Per Annum Rate (Adjusted Quarterly)
------------------------------------------------
Series D Series E
------------------------- -------------------
Dividend rate 0.10% below 1.20% below
Applicable Rate Applicable Rate
Minimum rate 7.50% 7.00%
Maximum rate 15.50% 13.00%
Shareholder Rights Plan - The outstanding shares of common stock include
one voting preference stock contingent purchase right. The rights are
exercisable only if a person or group acquires beneficial ownership of 20% or
more, or commences a tender or exchange offer upon consummation of which such
person or group would beneficially own 30% or more of the Corporation's com-
mon stock. Under those conditions, each right could be exercised to purchase
one two-hundredth share of a new series of voting preference stock at an
exercise price of $60.
If any person becomes the beneficial owner of 30% or more of the Corpora-
tion's common stock, or if a 20%-or-more shareholder engages in certain self-
dealing transactions, or if in a merger transaction with the Corporation in
which the Corporation is the surviving corporation and its common stock is not
changed or converted, then each right not owned by such person or related
parties will entitle its holder to purchase, at the right's then-current
exercise price, shares of the Corporation's common stock (or, in certain
circumstances as determined by the Board of Directors, other consideration)
having a value of twice the right's exercise price. In addition, if the
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Corporation is involved in a merger or other business combination transaction
with another person in which its common stock is changed or converted, or sells
50% or more of its assets or earning power to another person, each right will
entitle its holder to purchase, at the right's then-current exercise price,
common stock of such other person having a value of twice the right's exercise
price.
The rights, which have no voting privileges, expire on May 5, 1996. The
Corporation will generally be entitled to redeem the rights at $.05 per right
at any time until the 15th day following public announcement that a 20%
position has been acquired.
Management Incentive Program - As of December 31, 1993, the Corporation's
Management Incentive Program consisted of two separate plans, the Unit Plan and
the Non-Qualified Performance - Stock Option Plan. Key employees participating
in the Unit Plan and Stock Option Plan totaled 62 and 8, respectively.
Under the Unit Plan, a maximum of 900,000 units outstanding at one time
could be awarded from time to time to key employees by the Board of Directors.
Benefits are payable in cash. At December 31, 1993 and 1992, 316,500 and
347,750 units, respectively, were outstanding. The Unit Plan was terminated
by the Board of Directors in February 1994.
Under the Non-Qualified Performance - Stock Option Plan, options were
granted to key employees to purchase shares of common stock at an exercise
option price equal to par value ($4.45). Outstanding options at December 31,
1993, covered 13,277 shares.
1981 Stock Option Plan - Incentive Stock Options and Non-Qualified Stock
Options were granted to key employees to purchase shares of the Corporation's
common stock at an option price of not less than the fair market value of the
common stock on the date of grant. This plan terminated on September 17, 1991,
and no additional grants of stock options will be made. Options exercised in
1993 were at prices ranging from $16.375 to $21.00 per share. No options were
exercised in 1992 and options exercised in 1991 were at a price of $17.00 per
share. Option prices of grants outstanding at December 31, 1993, ranged from
$16.375 to $25.625 per share. As of December 31, 1993, options to purchase
1,307,568 shares were outstanding under such plan. The number of key employees
participating in the plan was 108 as of December 31, 1993.
1991 Stock Option Plan - Non-Qualified Stock Options may be granted to key
employees for the purchase of not more than 2,000,000 shares of the Corpora-
tion's common stock at an option price of not less than the fair market value
of the common stock on the date of grant. In February 1994, the Board of
Directors amended the 1991 Stock Option Plan, subject to shareholder approval,
to include provisions for Restricted Stock. A total of 88,500 shares of
performance-based Restricted Stock have been authorized for issuance to certain
executive officers, subject to shareholder approval of the plan amendments.
Performance criteria for lifting the restrictions is related to three-year
total shareholder return compared to the weighted average of a peer group of
companies. Options exercised in 1993 were at prices ranging from $12.50 to
$19.00 per share. No options were exercised in 1992 or 1991. Option prices
of grants outstanding at December 31, 1993, ranged from $12.50 to $19.00 per
share. As of December 31, 1993, options to purchase 1,068,125 shares had been
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granted and were outstanding under such plan. The number of key employees
participating in the plan was 122 as of December 31, 1993.
A summary of all stock option transactions follows:
[Download Table]
1993 1992 1991
---- ---- ----
Outstanding at beginning of
year. . . . . . . . . . . 2,327,410 2,019,069 1,532,405
Granted . . . . . . . . . . 257,000 342,600 580,000
Expired . . . . . . . . . . (80,170) (34,259) (90,336)
Exercised . . . . . . . . . (115,270) (3,000)
--------- --------- ---------
Outstanding at end of year. 2,388,970 2,327,410 2,019,069
========= ========= =========
Exercisable at end
of year . . . . . . . . . 1,737,127 1,294,973 1,030,364
========= ========= =========
Dividends - Restrictions on the payment of dividends on common stock (other
than stock dividends) or acquisitions of the Corporation's capital stock are
contained in the Corporation's several trust indentures and other agreements
relating to senior long-term debt and in the Restated Articles of Incorporation
of the Corporation. At December 31, 1993, the amount of dividends on common
stock that could be paid under the most restrictive of these agreements
exceeded the combined total of the retained earnings and paid in capital of the
Corporation which was $350,099 and represented the effective limitation on
common stock dividends. Following the redemption of all of the outstanding
sinking fund debentures and the Adjustable Rate Preferred Stock, Series D, all
of which have been called for redemption in March 1994, $342,139 of the
Corporation's common shareholders' equity as of December 31, 1993, would have
been free of such restrictions.
Dividends declared are summarized below:
[Download Table]
1993 1992 1991
---- ---- ----
Adjustable Rate Preferred
Stock:
Series D ($3.7688, $3.9313
and $4.3625 per share). . $ 5,653 $ 5,897 $ 6,544
Series E ($7.000, $7.0125
and $7.625 per
depositary share) . . . . 7,000 7,013 7,625
Common Stock ($.20, $.80 and
$.80 per share) . . . . . . 13,286 52,611 52,042
------- ------- -------
Total . . . . . . . . . . . $25,939 $65,521 $66,211
======= ======= =======
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6. COMMITMENTS AND CONTINGENT LIABILITIES
Legal Proceedings - On June 25, 1993, a lawsuit was filed against the
utility division of the Corporation in the 4th Judicial District Court of Rusk
County, Texas. The plaintiff claims that the utility division failed to make
certain production and minimum purchase payments under a gas- purchase
contract. The plaintiff contends that it was fraudulently induced to enter
into a gas-purchase contract which the utility division never intended to
perform; that the plaintiff was fraudulently induced and coerced into
releasing the utility division from its obligation to make minimum purchase
payments; and that the contract was breached. The plaintiff seeks actual
damages in excess of $100 million in addition to punitive damages equal to the
savings produced from a gas price reduction program implemented by the utility
in 1982 or equal to the value of gas supply in excess of its needs which were
added pursuant to a program established in 1978 to increase gas supply.
A lawsuit was filed on February 24, 1987, in the 112th Judicial District of
Sutton County, Texas, against subsidiaries and affiliates of the Corporation
as well as its utility division. The plaintiffs have claimed that defendants
failed to make certain production and minimum purchase payments under a gas-
purchase contract. In this connection, the plaintiffs have alleged a
conspiracy to violate purchase obligations, improper accounting of amounts due,
fraud, misrepresentation, duress, failure to properly market gas and failure
to act in good faith. In this case, plaintiffs seek actual damages in excess
of $5 million and punitive damages in an amount equal to 0.5% of the consoli-
dated gross revenues of the Corporation for the years 1982-1986 (approximately
$85 million), interest, costs and attorneys' fees.
Management of the Corporation believes that the named defendants have
meritorious defenses to the claims made in these and other actions. In the
opinion of management, the Corporation will incur no liability from these and
all other pending claims and suits that would be considered material for
financial reporting purposes.
Long-term Contracts - The Corporation's environmental business enters into
contracts which have provisions for significant financial penalties should
certain terms of performance not be achieved. Such contract provisions have
not and are not expected to have a material effect on the Corporation's
operations.
Gas-Purchase Contracts - See "Financial Review - Gas-Purchase Contracts"
for a discussion of commitments and contingencies relating to gas-purchase
contracts.
Environmental Matters - The Corporation is subject to federal, state, and
local environmental laws and regulations. These laws and regulations, which
are constantly changing, regulate the discharge of materials into the
environment. Environmental expenditures are expensed or capitalized depending
on their future economic benefit. The level of future expenditures for
environmental matters, including costs of obtaining operating permits, enhanced
equipment monitoring and modifications under the Clean Air Act and cleanup
obligations, cannot be fully ascertained at this time. However, it is
management's opinion that such costs, when finally determined, will not have
A-33
a material adverse effect on the consolidated financial position of the
Corporation.
Lease Commitments - In May 1992, EP entered into an operating lease
arrangement to provide financing for its portion of the offshore platform and
related facilities for the 37 1/2% owned Mississippi Canyon Block 441 project.
A total of $34 million was required for the Mississippi Canyon project, which
was completed in early 1993. EP leased the facilities for an initial period
through May 20, 1994, with an option to renew the lease, with the consent of
the lessor, for up to 10 successive six-month periods. The lease has been
renewed through November 20, 1994 and the Corporation expects to renew the
lease for all renewal periods. EP has the option to purchase the facilities
throughout the lease periods and as of December 31, 1993, has guaranteed an
estimated residual value for the facilities of approximately $27 million should
the lease not be renewed. Expenses incurred under the lease in 1993 were $2.1
million. The estimated future minimum net rentals for the Mississippi Canyon
operating lease is $6.3 million for 1994.
In September 1992, EP entered into an operating lease arrangement to pro-
vide financing for the offshore platform and related facilities of its 100%
owned Garden Banks Block 388 project. The lessor will fund the construction
cost of the facilities quarterly, up to a maximum of $235 million. As of
December 31, 1993, a total of $60 million had been advanced to EP under the
lease as agent for the lessor, $31 million of which was unexpended and
reflected as a current liability. EP will lease the facilities for an
initial period through March 31, 1997, with the option to renew the lease,
with the consent of the lessor, for up to three successive two-year periods.
EP, as agent for the lessors, will acquire, construct and operate the units
of leased property and has guaranteed completion of construction of the
facilities. EP has the option to purchase the facilities throughout the
lease periods and has guaranteed an estimated residual value for the facil-
ities of approximately $188 million, assuming the full lease amounts are
advanced and expended, should the lease not be renewed. The estimated future
minimum net rentals for the Garden Banks operating lease are as follows:
$4.8 million for 1994; $9.1 million for 1995; $9.1 million for 1996; and
$2.3 million for 1997. Lease payments are being deferred during the con-
struction period and will be amortized when production begins.
In addition, the Corporation had a number of other noncancelable long-term
operating leases at December 31, 1993, principally for office space and
machinery and equipment. Future minimum net rentals under these noncancelable
long-term operating leases aggregate $9.7 million for 1994; $8.9 million for
1995; $6.6 million for 1996; $6.5 million for 1997; $4.7 million for 1998; and
$51.9 million thereafter. Future minimum rental income to be received for
subleased office space is $9.3 million over the next five years. Rental
expenses incurred under operating leases aggregated $14.3 million in 1993;
$19.4 million in 1992; and $20.3 million in 1991. Rental income received for
subleased office space was $3.4 million in 1993; $4.7 million in 1992; and
$4.7 million in 1991.
Sales of Receivables - The Corporation has an agreement, which has been
extended to 1996, with a commercial bank for the limited recourse sale of up
to $100 million of Lone Star's receivables. Additional receivables are
continually sold to replace those collected. The agreement the Corporation had
A-34
for the limited recourse sale of up to $75 million of Ebasco accounts
receivable was assumed by the purchaser as part of the sale of Ebasco. In
December 1993, the Corporation entered into an agreement with a bank for the
limited recourse sale of $100 million of receivables retained from the sale of
Ebasco. This program is self-liquidating as new receivables will not be sold
to replace those collected. As of December 31, 1993 and 1992, the uncollected
balances of receivables sold under all existing agreements were $200 million
and $175 million, respectively.
Contingent Support Agreement - In connection with the sale of its oil field
services segment to Pool Energy Services Co. (PESC) in 1990, ENSERCH entered
into a Contingent Support Agreement (Agreement) by which ENSERCH is providing
PESC with limited financial support. PESC is obligated to repay ENSERCH for
any amounts paid out under guarantees and contingent obligations, together with
interest accrued thereon.
Support provided under the Agreement at January 1, 1994, consists of
(i) the guarantee supporting the financing of PESC's Saudi Arabian affiliate,
Pool Arabia, Ltd., totaling $3.1 million until July 31, 1996, and (ii) the
$31 million guarantee outstanding in connection with a facility lease that is
reduced periodically until fully released in March 2003. The stock of Pool
International, Inc. has been pledged to ENSERCH as collateral for the
Agreement. ENSERCH's lien on this collateral will remain so long as the
guarantee of the Pool Arabia loan is outstanding.
Guarantees - In addition to guarantees mentioned above, the Corporation
and/or its subsidiaries are the guarantor on various commitments and obliga-
tions of others aggregating some $60 million at December 31, 1993. The
Corporation is exposed to loss in the event of nonperformance by other parties.
However, the Corporation does not anticipate nonperformance by the counterpart-
ies.
Financial Instruments With Concentrations of Credit Risk - The transmission
and distribution operations have trade receivables from a few large industrial
customers in the north central area of Texas arising from the sale of natural
gas. The environmental operations have several large receivables from projects
that are subject to governmental funding approvals.
A change in economic conditions in a particular region or industry or
change in local taxing authority may affect the ability of customers to meet
their contractual obligations. The Corporation believes that its provision for
possible losses on uncollectible accounts receivable of continuing operations
is adequate for its credit loss exposure. At December 31, 1993 and 1992, the
allowance for possible losses deducted from accounts receivable on the balance
sheet was $4,105 and $6,590, respectively.
7. RETIREMENT PLANS
The Corporation has retirement plans covering substantially all its
employees and employees of its subsidiaries. Upon the sale of the principal
operating assets of Ebasco in 1993, the Corporation retained the obligations
related to the Ebasco pension plan, including the obligation for benefits due
Ebasco employees hired by the purchaser to date of sale and Ebasco employees
A-35
terminated as a result of the sale. The employees hired by the purchaser are
considered fully vested with full rights in the plan but frozen benefits. The
terminated employees are due the benefits for which they were eligible at the
date of their termination. Since no further benefits will accrue to these two
groups of former Ebasco employees, the Corporation recognized a plan curtail-
ment gain in 1993 of $6.9 million, which was included as a part of the gain on
the sale. The following table sets forth the funded status of all plans as of
September 30, 1993 (adjusted to reflect the effects of the sale of Ebasco) and
1992, and the amounts recognized in the consolidated balance sheet at
December 31:
[Enlarge/Download Table]
1993 1992
------ ------
(In millions)
Actuarial present value
of accumulated benefit
obligations:
Vested . . . . . . . . . . . . . . . . . . . . $268.5 $188.3
Nonvested. . . . . . . . . . . . . . . . . . . . . . 8.8 14.9
------ ------
Total . . . . . . . . . . . . . . . . . . . . $277.3 $203.2
====== ======
Plan assets at fair value. . . . . . . . . . . . . . . $243.2 $220.1
Projected benefit obligations. . . . . . . . . . . . . 311.7 235.2
------ ------
Underfunded status . . . . . . . . . . . . . . . . . $(68.5) $(15.1)
====== ======
Consisting of:
Unrecognized amounts:
Net asset at transition . . . . . . . . . . . . . $ 9.7 $ 11.0
Prior service cost . . . . . . . . . . . . . . . . (1.7) (5.5)
Net actuarial gain (loss) . . . . . . . . . . . . (26.3) 35.5
Recognized amounts - Accrued pension
cost as of December 31:
Current.. . . . . . . . . . . . . . . . . . . . . (7.2) (8.8)
Noncurrent. . . . . . . . . . . . . . . . . . . . (43.0) (47.3)
------ ------
Total. . . . . . . . . . . . . . . . . . . . . . . $(68.5) $(15.1)
====== ======
The accumulated benefit obligations represent the actuarial present value
of benefits based on employees' history of service and compensation up to the
measurement dates (September 30, 1993 and 1992). The projected benefit obliga-
tions include additional assumptions about future compensation levels. The
accumulated benefit obligations and the projected benefit obligations for 1993
and 1992 were determined using an assumed discount rate of 7.25% and 8.5%,
respectively, and an assumed rate of compensation increase of 4% for both 1993
and 1992. The assumed long-term rate of return on plan assets was 9.5% for
1993 and 10% for 1992. The benefit obligations fluctuate with the assumed
discount rate. When the rate declines, as it did in 1993 from the broad
reduction in interest rates, the actuarial present value of benefit obligations
increases. Some $68 million of the increase in the benefit obligations was
primarily due to the reduction in the assumed discount rate in 1993 and is
reflected in the unrecognized net actuarial gain (loss).
A-36
The Corporation and its subsidiaries make annual contributions to the plans
in such amounts as are necessary, on an actuarial basis, to satisfy minimum
funding requirements of ERISA. Accrued pension cost represents the amount of
pension cost recognized in excess of contributions paid.
Benefits vary by plan and generally are determined by the participant's
years of credited service and average compensation during the highest five
years prior to retirement or during each participant's career. Plan assets
consist primarily of preferred and common stocks, corporate bonds and U.S.
government securities.
The components of pension cost were as follows:
[Download Table]
1993 1992 1991
---- ---- ----
(In millions)
Service cost (benefits earned). . . . . . . . . . $ 12.5 $ 13.3 $ 11.1
Interest cost on projected benefits 19.5 18.4 16.8
Return on plan assets:
Actual. . . . . . . . . . . . . . . . . . . . . (28.0) (22.7) (39.0)
Portion deferred. . . . . . . . . . . . . . . . 6.2 3.3 22.5
Other amortization - net. . . . . . . . . . . . . (2.3) (2.3) (1.5)
------ ------ -----
Pension expense. . . . . . . . . . . . . . $ 7.9 $ 10.0 $ 9.9
====== ====== =====
8. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other Than
Pensions," became effective in January 1993 and mandates the accounting for
medical and life insurance and other nonpension benefits provided to retired
employees. The new standard requires accrual of these benefits over the
working life of the employee, similar in manner to the requirement for pension
benefits, rather than charging to expense on a cash basis.
The Corporation and its subsidiaries provide varying postretirement medical
benefits to its retirees and employees based on their hiring date, years of
service and retirement date. Except for Ebasco employees, retirees and their
dependents who retired on or before December 31, 1990, and employees age 62 or
older on that date who subsequently retire, are entitled to full medical
coverage. Employees hired before July 1, 1989 who retire with a minimum of
five years of service are provided with an annual subsidy, based on years of
service, with which to purchase medical coverage. Employees hired after July
1, 1989, are not eligible for medical benefits when they retire.
Ebasco provided limited postretirement medical benefits to certain of its
employees who retired prior to January 1, 1993. Upon the sale of the principal
operating assets of Ebasco in 1993, the Corporation retained the obligations
to retirees of Ebasco under this plan.
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The Corporation does not prefund its obligations under the plan. The
following table sets forth the funded status of all plans as of September 30,
1993, and the amounts recognized in the consolidated balance sheet at December
31, 1993 (in millions):
[Download Table]
Accumulated postretirement benefit
obligation:
Active participants fully eligible $ 1.6
Active participants not fully eligible 8.4
Retirees and dependents 72.9
-------
Total $ 82.9
=======
Underfunded Status $(82.9)
=======
Consists of:
Unrecognized amounts:
Transition obligation $(66.2)
Net actuarial loss (14.8)
Recognized amount - Accrued
postretirement cost (1.9)
-------
Total $(82.9)
=======
The accumulated postretirement benefit obligation represents the actuarial
present value of employee medical and life insurance benefits based on
employees' history of service up to the measurement date (September 30, 1993.)
It was determined using an assumed discount rate of 7.25% and an assumed
medical cost trend rate of 12% for 1994 declining to a rate of 6% after the
year 2002. If the medical cost trend rate was increased by 1%, the December
31, 1993 accumulated postretirement benefit obligation would have increased by
$7.0 million and the 1993 net periodic benefit cost would have increased by $.9
million.
The accumulated postretirement benefit obligation as of January 1, 1993,
was $70 million assuming an 8 1/2% discount rate. This transition obligation is
being amortized over allowable periods up to 20 years. In 1993, the reduction
in the discount rate to 7.25% was the primary cause of the increase in the
benefit obligation, which is reflected in the net actuarial loss.
The components of postretirement benefit cost for 1993 were as follows (in
millions):
[Download Table]
Service cost (benefits earned) $ .4
Interest cost on projected benefits 5.6
Amortization of unrecognized transition obligation 4.0
------
Total expense $ 10.0
======
Accrued postretirement benefit cost represents the amount of benefit cost
recognized in excess of benefits paid. Cash payments totaled $8.1 million in
1993, $7.5 million in 1992 and $6.9 million in 1991.
A-38
Of the amounts noted above, about $34 million of the unrecognized transi-
tion obligation and $4.7 million of the 1993 expense are attributable to Lone
Star's rate-regulated activities. Lone Star's related cash payments in 1993
were $2.7 million. Cash basis is the method of recovery currently followed
in the rate-making process. Lone Star has deferred approximately $.5 million
of the $2.0 million difference in the 1993 net periodic expense and cash pay-
ments, although the full amount is subject to future recovery through rates.
9. INCOME TAXES
The provision (benefit) for income taxes on continuing operations is
summarized below:
[Download Table]
1993 1992 1991
---- ---- ----
Current
Federal. . . . . . . . . . . . . $ 7,239 $ 6,533 $ 58
State. . . . . . . . . . . . . . 661 541 27
Foreign. . . . . . . . . . . . . (444) 450 643
------- ------- -------
Total. . . . . . . . . . . . . 7,456 7,524 728
------- ------- -------
Deferred
Federal. . . . . . . . . . . . . (439) (8,332) 17,020
State. . . . . . . . . . . . . . 455
------- ------- -------
Total. . . . . . . . . . . . . 16 (8,332) 17,020
------- ------- -------
Total. . . . . . . . . . . . $7,472 $ (808) $17,748
======= ======= =======
A-39
A reconciliation between income taxes (benefit) computed at the federal
statutory rate and income-tax expense (benefit) of continuing operations is
shown below:
[Download Table]
1993 1992 1991
---- ---- ----
Income (loss) from continuing
operations before income taxes:
Domestic. . . . . . . . . . . . . . . . . . $ 11,229 $ 10,813 $ 60,230
Foreign . . . . . . . . . . . . . . . . . . (18,469) (8,107) (4,708)
-------- -------- --------
Total . . . . . . . . . . . . . . . . . . . (7,240) 2,706 55,522
Federal statutory rate. . . . . . . . . . . 35% 34% 34%
-------- -------- --------
Income taxes (benefit) computed at
the federal statutory rate. . . . . . . . . (2,534) 920 18,877
Impact of 1% increase in
federal statutory rate. . . . . . . . . . . 10,810
State and foreign taxes. . . . . . . . . . . . . 596 654 442
Tax benefit of common stock
dividends paid to employee
stock ownership plan. . . . . . . . . . . . (316) (1,103) (981)
Other - net. . . . . . . . . . . . . . . . . . . (1,084) (1,279) (590)
-------- -------- --------
Total income-tax
expense (benefit) . . . . . . . . . . . . $ 7,472 $ (808) $ 17,748
======== ======== ========
Effective tax rate. . . . . . . . . . . . . 103.2% (29.9)% 32.0%
======== ======== ========
Deferred income taxes are provided for all significant temporary
differences by the liability method, whereby deferred tax assets and liabil-
ities are determined by the tax laws and statutory rates in effect at the
balance sheet date. Temporary differences which give rise to significant
deferred tax assets and liabilities at December 31, 1993 are as follows:
A-40
[Enlarge/Download Table]
Total Current Noncurrent
-------- ------- ----------
Deferred tax assets:
Net operating-loss carryforwards
and suspended losses from
partnerships . . . . . . . . . . . . . . . $ 56,405 $ 26,326 $ 30,079
Investment and other
tax credit carryforwards. . . . . . . . . . 36,835 36,835
Accrued pension costs . . . . . . . . . . . . 17,406 17,406
Reserves for injury
and damage claims . . . . . . . . . . . . . 17,351 3,710 13,641
All other . . . . . . . . . . . . . . . . . . 53,645 13,516 40,129
-------- -------- --------
Total . . . . . . . . . . . . . . . . . . 181,642 43,552 138,090
-------- -------- --------
Deferred tax liabilities:
Accelerated depreciation. . . . . . . . . . 182,892 182,892
Exploration and intangible
development costs . . . . . . . . . . . . 248,027 248,027
Deferred gas costs associated
with gas-purchase contract
settlements . . . . . . . . . . . . . . . 17,832 14,999 2,833
All other . . . . . . . . . . . . . . . . . 25,904 202 25,702
-------- -------- --------
Total . . . . . . . . . . . . . . . . . . 474,655 15,201 459,454
-------- -------- --------
Net deferred tax liability (asset) $293,013 $(28,351)* $321,364
======== ======== ========
<FN>
* Included in other current assets in the accompanying balance sheet.
At December 31, 1993, the Corporation had domestic net operating-loss
carryforwards and suspended losses from partnerships of $161 million which
begin to expire in 2003, and tax-credit carryforwards of $37 million, which
begin to expire in 1999. The tax benefits of these carryforwards and suspended
losses, which total some $93 million as shown above, are available to reduce
future income-tax payments.
The Corporation made payments (received refunds) for income taxes as
follows:
[Enlarge/Download Table]
1993 1992 1991
---- ---- ----
Federal:
Alternative minimum tax . . . . $15,400 $ 6,514 $ 1,812
Refund of prior year
tax payments . . . . . . . . . (2,462) (7,981)
------- ------- --------
Total . . . . . . . . . . . . . . . . . . . . 15,400 4,052 (6,169)
State . . . . . . . . . . . . . . . . . . . . . . 4,193 1,427 1,540
Foreign . . . . . . . . . . . . . . . . . . . . . 850 608 2,645
------- ------- --------
Total . . . . . . . . . . . . . . . . . . . . $20,443 $ 6,087 $ (1,984)
======= ======= ========
A-41
10. LITIGATION JUDGMENT
On April 12, 1989, a complaint captioned MacLane Gas Company Limited
Partnership v. ENSERCH Corporation, et al, was filed as a class action in the
Court of Chancery of the State of Delaware. As previously reported, the
complaint, as amended, sought damages in connection with the Corporation's
exchange offer of its common stock for the Enserch Exploration Partners, Ltd.
units held by the public. Following a trial of the case, the Trial Court found
that the prospectus did not disclose adequately the basis of the exchange
ratio, that the structure and timing of the transaction was unfair to the
unitholders and that the price paid was not a fair price. Damages of $3.42 per
unit were awarded to the plaintiff class. The Delaware Supreme Court affirmed
the Trial Court's judgment and subsequently denied the Corporation's motion for
rehearing. The award included $41 million additional consideration for the
units and $21 million of prejudgment and post-judgment interest ($15 million
was charged against an existing reserve for litigation). The $41 million
additional payment was charged against income in the fourth quarter. The
judgment was paid on January 18, 1994. See "Financial Review" for additional
information.
11. DISCONTINUED OPERATIONS
In December 1993, the Corporation completed the sale of the principal
operating assets of Ebasco for net estimated proceeds of $191 million. The
assets sold include the ongoing operations and goodwill in Ebasco's energy,
infrastructure and quality-engineering services businesses. The Corporation
retained Ebasco's environmental services business, which had net assets of $33
million at December 31, 1993, and will be operated through Enserch Environmen-
tal Corporation. (It is now included in the Power and Other business segment.)
In addition, the Corporation retained other net assets and liabilities of
$99 million at December 31, 1993, including billed and unbilled accounts
receivable and retainages of $119 million, environmental remediation contracts
with a net book value of $15 million, an accrued pension liability of $32
million and other miscellaneous assets and liabilities.
Also in December 1993, in a separate transaction, the Corporation
completed the sale of it's 49% interest in Dorsch Consult for $9.3 million,
including the assumption of debt. In 1992, the Corporation sold its interest
in the business of H&G Engineering.
A-42
Information relating to the discontinued engineering and construction
segment is summarized as follows:
[Download Table]
1993 1992 1991
---- ---- ----
Revenues $1,247,526 $1,110,894 $1,180,531
Cost and expenses 1,227,758 1,093,193 1,184,556
---------- ---------- ----------
Operating income (loss) 19,768 17,701 (4,025)
Other income (expense) - net (583) (14,398) (5,063)
Interest expense (9,266) (12,715) (16,350)
Income (taxes) benefit (4,384) 326 6,729
---------- ---------- ----------
Income (loss) from operations 5,535 (9,086) (18,709)
Gain (loss) on sale, net of
income-tax benefits of $6,725
in 1993 and $1,713 in 1992 68,414 (7,076)
---------- ---------- ----------
Total from discontinued
operations $ 73,949 $ (16,162) $ (18,709)
========== ========== ==========
The tax effect of the gain on sale differs from tax at the statutory rate
because of permanent differences in book and tax basis of the assets sold. The
determination of the gain on sale involved significant estimates including the
final purchase price, realization of the estimated value of retained assets,
and related income-tax matters. In management's opinion, adequate provision
has been made for these matters.
12. SUPPLEMENTAL FINANCIAL INFORMATION
Quarterly Results (Unaudited) - The results of operations by quarters are
summarized below and have been restated for the discontinuance of the
engineering and construction business segment and the realignment of operations
for segment of business reporting that became effective in the first quarter
of 1993. Consolidated operating income and net income were not affected by the
realignment. In the opinion of the Corporation, after the restatement, all
adjustments (consisting only of normal recurring accruals) necessary for a fair
presentation have been made.
A-43
[Enlarge/Download Table]
Quarter Ended
----------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------- -----------
1993:
Revenues . . . . . . . . . . . . . . . . . . . . . . $593,549 $394,227 $372,140 $542,209
Operating Income (Loss). . . . . . . . . . . . . . . 79,727 26,831 1,456 (35,202)(b)(c)
Income (Loss) from Continuing
Operations. . . . . . . . . . . . . . . . . . . . 38,276 5,353 (27,363)(a) (30,978)(b)(c)
Discontinued Operations. . . . . . . . . . . . . . . (66) (298) 4,549 69,764
Net Income (Loss). . . . . . . . . . . . . . . . . . 38,210 5,055 (22,814) 38,786
Earnings (Loss) Applicable to
Common Stock. . . . . . . . . . . . . . . . . . . 35,026 1,889 (25,970) 35,629
Per Share of Common Stock:
Income (loss) from continuing
operations after provision for
dividends on preferred stock. . . . . . . . . . $ .53 $ .03 $ (.46) $ (.51)
Discontinued operations . . . . . . . . . . . . . .07 1.04
-------- -------- -------- --------
Earnings (loss) applicable to
common stock. . . . . . . . . . . . . . . . $ .53 $ .03 $ (.39) $ .53
======== ======== ======== ========
Operating Income (Loss) of
Business Segments:
Natural gas transmission
and distribution. . . . . . . . . . . . . . . . $ 74,182 $ 6,125 $ (1,711) $ 22,862 (b)
Natural gas and oil exploration
and production. . . . . . . . . . . . . . . . . 3,745 6,014 4,563 (51,615)(c)
Natural gas liquids processing. . . . . . . . . . 3,341 1,552 628 (484)
Power and other . . . . . . . . . . . . . . . . . 1,006 15,661 767 (1,956)
General corporate expense . . . . . . . . . . . . (2,547) (2,521) (2,791) (4,009)
-------- -------- -------- --------
Total . . . . . . . . . . . . . . . . . . . . $ 79,727 $ 26,831 $ 1,456 $(35,202)
======== ======== ======== ========
<FN>
(a) Includes $10.8 million in deferred tax expense for the 1% increase in the federal tax
rate on corporations.
(b) Includes a $7.8 million charge for efficiency enhancements and severance expenses
accrued for staff reductions ($12.0 million pretax).
(c) Includes a $26.9 million charge as a result of an adverse judgment in litigation that
required additional payment in a limited partnership exchange offer made in 1989
($41.4 million pretax) and a $6.7 million write-off of non-U.S. gas and oil properties
($10.3 million pretax).
A-44
[Enlarge/Download Table]
Quarter Ended
------------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
1992:
Revenues . . . . . . . . . . . . . . . . . . . . . . $489,832 $341,429 $332,127 $551,173
Operating Income . . . . . . . . . . . . . . . . . . 66,396 5,971 4,111 35,730(a)
Income (Loss) from Continuing
Operations. . . . . . . . . . . . . . . . . . . . 31,992 (12,540) (13,315) (2,623)(a)(b)
Discontinued Operations. . . . . . . . . . . . . . . 2,365 (797) (1,331) (16,399)
Extraordinary Loss . . . . . . . . . . . . . . . . . (3,934) (994) (10,430)
Net Income (Loss). . . . . . . . . . . . . . . . . . 34,357 (17,271) (15,640) (29,452)
Earnings (Loss) Applicable to Common
Stock . . . . . . . . . . . . . . . . . . . . . . 31,111 (20,535) (18,885) (32,649)
Per Share of Common Stock:
Income (loss) from continuing
operations after provision for
dividends on preferred stock. . . . . . . . . . $ .44 $ (.24) $ (.25) $ (.08)
Discontinued operations . . . . . . . . . . . . . .04 (.01) (.02) (.25)
Extraordinary loss. . . . . . . . . . . . . . . . (.06) (.02) (.16)
-------- -------- -------- --------
Earnings (loss) applicable to
common stock. . . . . . . . . . . . . . . $ .48 $ (.31) $ (.29) $ (.49)
======== ======== ======== ========
Operating Income (Loss) of
Business Segments:
Natural gas transmission
and distribution. . . . . . . . . . . . . . . $ 60,419 $ 5,912 $ (1,756) $ 37,421
Natural gas and oil exploration
and production. . . . . . . . . . . . . . . . 4,717 (841) 2,841 (12,892)(a)
Natural gas liquids processing. . . . . . . . . 2,801 2,735 5,198 2,358
Power and other . . . . . . . . . . . . . . . . 1,651 1,639 1,749 15,128
General corporate expense . . . . . . . . . . . (3,192) (3,474) (3,921) (6,285)
-------- -------- -------- --------
Total . . . . . . . . . . . . . . . . . . . $ 66,396 $ 5,971 $ 4,111 $ 35,730
======== ======== ======== ========
<FN>
(a) Includes an $11 million after-tax write-off ($16.5 million pretax) of an idle pipeline
and shallow-water production facility from an abandoned offshore project charged to
operating income.
(b) Includes a $10 million after-tax provision for litigation ($15 million pretax) charged
to other income/(expense).
A-45
Reconciliation of Previously Reported Quarterly Information
Quarterly amounts previously reported for the year 1992 and the first
three quarters of 1993 have been restated in the above tables to give effect
to the discontinued engineering and construction operations referred to in Note
11. The restatement affected the various components of the quarterly results
as follows:
[Enlarge/Download Table]
Increase (Decrease)
Quarter Ended
------------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
1993:
Revenues . . . . . . . . . . . . . . . . . . . . $(364,936) $(277,905) $(305,040)
Operating Income . . . . . . . . . . . . . . . . (5,903) (326) (4,256)
Income (Loss) from Continuing
Operations. . . . . . . . . . . . . . . . . . 66 298 (4,549)
1992:
Revenues . . . . . . . . . . . . . . . . . . . . $(287,398) $(243,537) $(256,650) $(323,309)
Operating Income . . . . . . . . . . . . . . . . (12,188) (1,455) (973) (3,085)
Income (Loss) from Continuing
Operations. . . . . . . . . . . . . . . . . . (2,365) 797 1,331 16,399
Other Income (Expense) - Net - is summarized below
1993 1992 1991
---- ---- ----
Provision for litigation . . . . . . . . . . . . . . . . . . . . . $ (5,608) $(15,466) $
Gain on disposal of assets. . . . . . . . . . . . . . . . . . . . . 6,893 103 15,637
Discount on sales of receivables. . . . . . . . . . . . . . . . . . (3,426) (3,634) (3,336)
Other interest income . . . . . . . . . . . . . . . . . . . . . . . 1,611 1,817 1,769
Interest income on settlements with the IRS . . . . . . . . . . . . 3,147
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 704 1,581
-------- -------- -------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 174 $(12,452) $14,070
======== ======== =======
Disposal of Significant Assets
In 1993, the Corporation sold a gas storage facility and a minority-
investment in an insurance entity and realized a pretax gain of $7.0 million.
Effective January 1, 1992, the Corporation transferred the assets and
business of Enserch Gas Transmission Company to a new partnership, Gulf Coast
Natural Gas Company, for $19 million and a 50% ownership of the new partner-
ship. No gain or loss resulted from the transfer. The Corporation uses the
equity method to account for its interest in the new partnership.
In December 1991, the Corporation completed the sale of Enserch Nether-
lands, Inc., for $32.1 million and recorded a pretax gain on the sale of $6.0
million. In June 1991, the Corporation completed the sale of its Oklahoma
utility properties, for approximately $31 million, and recorded a pretax gain
on the sale of $9.1 million.
A-46
[Enlarge/Download Table]
Interest Costs - are summarized below
1993 1992 1991
---- ---- ----
Interest capitalized . . . . . . . . . . . . . . . . . . . . . $ 4,461 $ 5,426 $ 7,466
Interest charged to expense. . . . . . . . . . . . . . . . . . 80,226(a) 97,050 95,627
-------- -------- --------
Interest costs incurred. . . . . . . . . . . . . . . . . . . $ 84,687 $102,476 $103,093
======== ======== ========
<FN>
(a) Includes interest not related to borrowings in 1993 of $8.2 million.
Cash Flows - The Corporation considers all highly liquid investments in the
United States with a maturity of three months or less to be cash equivalents.
The decrease (increase) in current operating assets and liabilities for con-
tinuing operations is summarized below.
[Enlarge/Download Table]
1993 1992 1991
---- ---- ----
Decrease (increase) in current operating
assets and liabilities:
Accounts receivable. . . . . . . . . . . . . . . . . . . . . $(51,308) $ 10,226 $ 74,817
Effect of sales of gas-purchase contract
settlement receivables . . . . . . . . . . . . . . . . . . (11,503) (51,246)
Costs associated with unbilled revenues. . . . . . . . . . . 32,335 (6,242) (6,993)
Gas stored underground . . . . . . . . . . . . . . . . . . . 6,789 15,817 4,665
Other current assets . . . . . . . . . . . . . . . . . . . . 4,212 7,376 31,476
Accounts payable and other accrued
liabilities. . . . . . . . . . . . . . . . . . . . . . . . 19,367 10,005 (30,589)
Billings in excess of costs and advances on
uncompleted contracts. . . . . . . . . . . . . . . . . . . (4,208) 2,344 294
Accrued taxes. . . . . . . . . . . . . . . . . . . . . . . . 2,424 8,491 (11,750)
Other current liabilities. . . . . . . . . . . . . . . . . . (23,595) (781) (3,848)
-------- -------- --------
Cash effect of changes in current operating
assets and liabilities . . . . . . . . . . . . . . . . . $(13,984) $ 35,733 $ 6,826
======== ======== ========
Supplemental disclosure of noncash financing and investing activities
The $15.8 million pretax charge in 1992 for termination of an interest-rate
hedge described in Note 2 was a noncash transaction.
A-47
Environmental business long-term contracts
The following tabulation indicates accounts receivable and the components
of unbilled costs, estimated earnings and retainages relating to uncompleted
contracts as of December 31, 1993:
[Download Table]
Accounts receivable - Amounts billed . . . . . . . . . . . . . . $19,156
=======
Unbilled costs, estimated earnings and
retainages on uncompleted contracts:
Costs and fees billable pursuant to
contract terms. . . . . . . . . . . . . . . . . . . . . . . $11,485
Retainages, due upon substantial
completion of contracts . . . . . . . . . . . . . . . . . . 3,312
Unrecovered costs not billed - limited to
estimated realizable value and related
to project scope changes, pending
authorization . . . . . . . . . . . . . . . . . . . . . . . 3,720
-------
Total . . . . . . . . . . . . . . . . . . . . . . . . . $18,517
=======
In accordance with industry practice, unbilled costs and fees relating to
contracts having a duration of longer than one year are classified as current
assets. Costs and fees on long-term contracts that have been billed to
clients, but that have not yet been paid, are included in accounts receivable.
Unbilled costs and fees on uncompleted contracts are generally includable in
the following month's billings, or become billable on a progress basis,
pursuant to the terms of the contract billing schedule. The balances billable
pursuant to retainage provisions in contracts will be due upon substantial
completion of the contract and acceptance by the client.
Assignment of Future Gas Purchase Credits - At December 31, 1993 and 1992,
assignments of future gas purchase credits from advances and prepayments for
gas were $38,191 and $54,114, respectively (of which $26,028 and $18,214,
respectively, were current). The credits are reduced by an amount equal to the
reduction in the related asset, advances and prepayments for gas, which are
based upon amounts of gas purchased by the Corporation under related gas
purchase contracts. The assignment of future gas purchase credits provided for
an average annual finance charge of 3.6% during December 1993.
Restructuring Charges - In December 1993, the Corporation recognized a $12
million charge for efficiency enhancements and severance expenses accrued for
staff reductions in Natural Gas Transmission and Distribution operations.
Business Segments - Information by business segments presented elsewhere herein
is an integral part of these financial statements.
A-48
13. SUPPLEMENTARY GAS AND OIL INFORMATION
Gas and Oil Producing Activities - The following tables set forth informa-
tion relating to gas and oil producing activities. Reserve data for natural
gas liquids attributable to leasehold interests owned by the Corporation are
included in oil and condensate.
[Enlarge/Download Table]
-------------------------------------------------------------------------------------------
1993 1992
-------------------------------------------------------------------------------------------
(In millions)
Capitalized costs:
Proved gas and oil properties . . . . . . . . . . . $1,851.6 $1,780.8
Unproved gas and oil properties . . . . . . . . . . 84.4 98.0
-------- --------
Total . . . . . . . . . . . . . . . . . . . . . $1,936.0 $1,878.8
======== ========
Accumulated depreciation and
amortization. . . . . . . . . . . . . . . . . . $ 792.4 $ 753.9
======== ========
[Enlarge/Download Table]
--------------------------------------------------------------------------
1993 1992 1991
--------------------------------------------------------------------------
Non- Non- Non-
U.S. U.S. U.S. U.S. U.S. U.S.
---- ---- ---- ---- ---- ----
(In millions)
Costs incurred:
Property acquisition costs:
Proved . . . . . . . . . . . . . . . $ 8.3 $ $ .9 $ $ .7 $
Unproved . . . . . . . . . . . . . . 12.6 .8 9.1 (.1) 9.6
Exploration costs . . . . . . . . . . . 36.8 4.9 35.4 2.7 47.4 9.4
Development costs . . . . . . . . . . . 63.0 16.6 63.3 .3
------ ------ ------ ------ ------ ------
Total. . . . . . . . . . . . . . . . $120.7 $ 5.7 $ 62.0 $ 2.6 $121.0 $ 9.7
====== ====== ====== ====== ====== ======
Amortization
(Per MMBtu)(a) . . . . . . . . . . . . . $ .98 $ .98 $ .90
<FN>
(a) Amortization expense per unit of production converted to a common unit of measure, millions
of British thermal units (MMBtu). All non-U.S. producing operations were sold during 1991.
A-49
Excluded Costs - The following table sets forth the composition of
capitalized costs excluded from the amortizable base as of December 31, 1993:
[Enlarge/Download Table]
Amounts Incurred In
----------------------------------------------- Total As of
Prior December 31,
1993 1992 1991 Years 1993
---- ---- ---- ----- -----------
(In millions)
Property acquisition costs $12.4 $ 5.3 $ 3.9 $18.7 $40.3
Exploration costs. . . . . . . . . 5.6 11.0 9.4 3.2 29.2
Interest capitalized . . . . . . . 4.0 4.4 2.9 3.6 14.9
----- ----- ----- ----- ------
Total. . . . . . . . . . . . . $22.0 $20.7 $16.2 $25.5 $84.4
===== ===== ===== ===== ======
Approximately 43% of the excluded costs relates to offshore activities in
the Gulf of Mexico and the remainder is domestic onshore exploration activi-
ties. The anticipated timing of the inclusion of these costs in the amortiza-
tion computation will be determined by the rate at which exploratory and
development activities continue, which are expected to be accomplished within
ten years.
Gas and Oil Reserves (Unaudited) - The following table of estimated
proved and proved developed reserves of gas and oil has been prepared by the
Corporation utilizing estimates of yearend reserve quantities provided by
DeGolyer and MacNaughton, independent petroleum consultants. Reserve estimates
are inherently imprecise and estimates of new discoveries are more imprecise
than those of producing gas and oil properties. Accordingly, the reserve
estimates are expected to change as additional performance data becomes
available. Oil reserves (which include condensate and natural gas liquids
attributable to leasehold interests) are stated in thousands of barrels (MBbl).
Gas reserves are stated in million cubic feet (MMcf).
A-50
[Download Table]
United States
-------------------
Oil Gas
MBbl MMcf
---- ----
Proved Reserves:
Balance, January 1, 1991 . . . . . . . . . . . . 31,108 1,224,134
Revisions of previous estimates . . . . . . . . (285) (54,842)
Extensions, discoveries and
additions. . . . . . . . . . . . . . . . . . 1,478 57,081
Purchase of minerals in place . . . . . . . . . 10,516 12,307
Sales of minerals in place. . . . . . . . . . . (36) (549)
Production. . . . . . . . . . . . . . . . . . . (2,769) (70,056)
------ ---------
Balance, December 31, 1991. . . . . . . . . . . 40,012 1,168,075
Revisions of previous estimates . . . . . . . . 552 (6,811)
Extensions, discoveries and
additions. . . . . . . . . . . . . . . . . . 1,444 20,817
Purchase of minerals in place . . . . . . . . . 102 198
Sales of minerals in place. . . . . . . . . . . (42) (15,665)
Production. . . . . . . . . . . . . . . . . . . (2,837) (65,188)
------ ---------
Balance, December 31, 1992. . . . . . . . . . . 39,231 1,101,426
Revisions of previous estimates . . . . . . . . 1,344 20,196
Extensions, discoveries and
additions. . . . . . . . . . . . . . . . . . 1,292 34,549
Purchase of minerals in place . . . . . . . . . 3 4,379
Sales of minerals in place. . . . . . . . . . . (40) (4,042)
Production. . . . . . . . . . . . . . . . . . . (2,481) (70,026)
------ ---------
Balance, December 31, 1993. . . . . . . . . . . 39,349 1,086,482
====== =========
Proved Developed Reserves:
January 1, 1991. . . . . . . . . . . . . . . . . 21,628 1,036,852
December 31, 1991.. . . . . . . . . . . . . . . 19,738 974,822
December 31, 1992 . . . . . . . . . . . . . . . 14,844 676,851
December 31, 1993 . . . . . . . . . . . . . . . 15,380 735,093
Included in the U.S.-Oil reserve estimates are natural gas liquids for
leasehold interest of 1,019 MBbl for 1991; and 985 MBbl for 1992; and 1,117
MBbl for 1993.
A-51
[Enlarge/Download Table]
Results of Operations - are as follows:
----------------------------------------------------------------------------------------------------------------------------
1993 1992 1991
----------------------------------------------------------------------------------------------------------------------------
Non- Non- Non-
Total U.S. U.S. Total U.S. U.S. Total U.S. U.S.
----- ------ ------ ----- ------ ------ ----- ------ ------
(In millions)
Producing Activities (excluding
corporate overhead and
interest costs):
Revenues (a) . . . . . . . . $191.0 $191.0 $ $170.3 $170.3 $ $182.2 $179.5 $ 2.7
Production costs . . . . . . 48.5 48.5 46.4 46.3 .1 53.7 52.2 1.5
Exploration costs (b). . . . 7.9 6.3 1.6 10.0 8.2 1.8 12.2 9.9 2.3
Depreciation and
amortization (c) . . . . . 99.3 86.0 13.3 82.4 82.0 .4 81.4 79.6 1.8
Income tax effects . . . . . 12.3 17.5 (5.2) 10.5 11.3 (.8) 11.8 12.8 (1.0)
------ ------ ----- ------ ------ ----- ------ ------ -----
Net producing activities . $23.0 $ 32.7 $(9.7) $ 21.0 $ 22.5 $(1.5) $ 23.1 $ 25.0 $(1.9)
====== ====== ===== ====== ====== ===== ====== ====== =====
<FN>
(a) Includes intersegment revenues of $110.0 million in 1993; $32.8 million in 1992 and $33.0 million in 1991, and is net of
royalty interests.
(b) Includes internal costs that cannot be directly identified with acquisition, exploration or development activities.
(c) Includes write-off of costs related to unsuccessful non-U.S. exploratory projects: $13.3 million, $.4 million and
$1.1 million in 1993, 1992 and 1991, respectively.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Gas and Oil Reserve Quantities (Unaudited) - has been
prepared by the Corporation using estimated future production rates and
associated production and development costs. Continuation of economic con-
ditions existing at the balance sheet date was assumed. Accordingly,
estimated future net cash flows were computed by: applying contracts and
prices in effect in December to estimated future production of proved gas and
oil reserves; estimating future expenditures to develop proved reserves; and
estimating costs to produce the proved reserves based on average costs for
the year. Average prices used in the computations were:
[Enlarge/Download Table]
1993 1992 1991
---- ---- ----
Gas (per Mcf)............................................................. $ 2.38 $ 2.20 $ 2.03
Oil- U.S. (per barrel).................................................... 11.73 16.89 18.35
Because of the imprecise nature of reserve estimates and the unpredictable
nature of the other variables used, the standardized
measure should be interpreted as indicative of the order of magnitude only
and not as precise amounts.
[Enlarge/Download Table]
-------------------------------------------------------------------------------------------------------
1993 1992 1991
--------------------------------------------------------------------------------------------------------
(In millions)
Future cash inflows.......... $3,047.0 $3,080.0 $3,077.6
Future production and
development costs.......... 1,057.9 1,057.2 1,008.4
-------- -------- --------
Future net cash flows........ 1,989.1 2,022.8 2,069.2
Less 10% annual discount..... 886.5 910.2 1,004.3
-------- -------- --------
Discounted future net cash
flows before income tax.... 1,102.6 1,112.6 1,064.9
Future income tax expenses... 528.0 556.5 535.0
Plus 10% annual discount
on income taxes............ 256.0 263.6 282.3
-------- -------- --------
Standardized measure of
discounted future net
cash flows................. $ 830.6 $ 819.7 $ 812.2
======== ======== ========
A-52
The following table sets forth an analysis of changes in the standardized
measure of discounted future net cash flows from proved gas and oil reserves:
[Enlarge/Download Table]
---------------------------------------------------------------------------------------------------------------
1993 1992 1991
---------------------------------------------------------------------------------------------------------------
(In millions)
Sales and transfers of gas
and oil produced, net of
production costs. . . . . . . . . . . . . . . . . . . $(136.2) $(115.8) $(118.9)
Changes in prices, net of
production and future
development costs.. . . . . . . . . . . . . . . . . . (.5) 21.8 (264.4)
Extensions, discoveries,
and improved recovery,
less related costs. . . . . . . . . . . . . . . . . . 41.4 22.3 47.4
Other purchases of minerals
in place. . . . . . . . . . . . . . . . . . . . . . . 9.4 .9 84.8
Revisions of previous
quantity estimates. . . . . . . . . . . . . . . . . . (28.5) 17.3 (37.9)
Sale of minerals in place. . . . . . . . . . . . . . . . (4.9) (22.0)
Accretion of discount. . . . . . . . . . . . . . . . . . 105.4 102.8 111.8
Net change in income taxes . . . . . . . . . . . . . . . 20.9 (40.2) 52.4
Other. . . . . . . . . . . . . . . . . . . . . . . . . . (1.0) 3.3 (4.4)
------- ------- -------
Total . . . . . . . . . . . . . . . . . . . . . . . . $ 10.9 $ 7.5 $(151.2)
======= ======= =======
A-53
[Enlarge/Download Table]
SUMMARY OF BUSINESS SEGMENTS
ENSERCH Corporation and Subsidiary Companies
Natural Gas
Natural Gas and Oil Discontinued
Transmission Exploration Natural Gas Power General Engineering
and and Liquids and and and
Distribution Production Processing Other Other Construction Consolidated
------------ ---------- ----------- ------- ------- ------------ ------------
(In thousands)
Revenues from Nonaffiliates
1993 . . . . . . . . . . . . . . $1,528,435 $ 79,780 $76,351 $217,559 $ $ $1,902,125
1992 . . . . . . . . . . . . . . 1,302,922 138,708 81,654 191,277 1,714,561
1991 . . . . . . . . . . . . . . 1,261,138 150,622 88,773 153,609 1,654,142
Intersegment Revenues from
Affiliates (eliminated
in consolidation) (a)
1993 . . . . . . . . . . . . . . 19,484 110,016(b) 9,434 138,934
1992 . . . . . . . . . . . . . . 15,336 32,836 5,312 53,484
1991 . . . . . . . . . . . . . . 12,144 32,968 4,044 49,156
Operating Income (Loss) of
Major Business Segments
1993 . . . . . . . . . . . . . . 101,458(c) (37,293)(d,e) 5,037 15,478 (11,868) 72,812
1992 . . . . . . . . . . . . . . 101,996 (6,175)(f) 13,092 20,167 (16,872) 112,208
1991 . . . . . . . . . . . . . . 111,487 10,910 21,211 8,953 (15,482) 137,079
Depreciation and Amortization
1993 . . . . . . . . . . . . . . 37,484 100,687(e) 4,003 1,989 598 144,761
1992 . . . . . . . . . . . . . . 35,711 100,167(f) 3,805 1,907 1,122 142,712
1991 . . . . . . . . . . . . . . 35,647 82,340 3,906 1,817 1,128 124,838
Identifiable Assets
1993 . . . . . . . . . . . . . . 1,313,722 1,193,525 26,123 109,579 117,312 2,760,261
1992 . . . . . . . . . . . . . . 1,333,171 1,167,349 24,761 81,890 142,557 395,952 3,145,680
1991 . . . . . . . . . . . . . . 1,351,549 1,226,984 30,034 76,498 95,892 382,135 3,163,092
Gross Additions to Property,
Plant and Equipment
1993 . . . . . . . . . . . . . . 91,923 119,566 5,779 3,291 970 221,529
1992 . . . . . . . . . . . . . . 75,795 65,787 1,228 1,236 1,076 145,122
1991 . . . . . . . . . . . . . . 91,809 124,564 1,525 1,415 2,139 221,452
<FN>
(a) Certain of the business segments provide services or sell products to one or more of the other segments. Generally, such
sales are made at prices comparable to those received from nonaffiliated customers for similar products or services.
(b) Includes sales of $91 million under new contracts with Enserch Gas Company commencing in early 1993 covering essentially
all gas production not committed under long-term contracts.
(c) Includes a $12.0 million charge for efficiency enhancements and severance expenses accrued for staff reductions.
(d) Includes a $41.4 million charge as a result of an adverse judgment in litigation that required additional payment in a
limited partnership exchange offer made in 1989.
(e) Includes a $13.3 million write-off of non-U. S. gas and oil properties.
(f) Includes a $16.5 million write-off of an idle pipeline and shallow-water production facility from an abandoned offshore
project.
Note: Non-U. S. operations provided less than 10% of consolidated revenues and employed less than 10% of consolidated assets
for all periods shown. No customer provided more than 10% of consolidated revenues for any period shown.
A-54
COMMON STOCK MARKET PRICES AND DIVIDEND INFORMATION
MARKET PRICES - ENSERCH COMMON STOCK
The Corporation's common stock is principally traded on the New York Stock
Exchange. The following table shows the high and low sales prices per share
of the common stock of the Corporation reported in the New York Stock Exchange
- Composite Transactions report for the periods shown as quoted in The Wall
Street Journal (WSJ).
[Enlarge/Download Table]
1993 1992 1991
----------------- --------------- ----------------
High Low High Low High Low
----------------- --------------- ----------------
First Quarter . . . . . . $19 1/8 $14 1/8 $14 3/8 $10 3/8 $20 1/2 $16 7/8
Second Quarter. . . . . . 19 5/8 16 7/8 16 3/8 12 1/8 21 3/8 17 1/8
Third Quarter . . . . . . 22 5/8 17 1/2 16 1/8 14 18 3/4 15 5/8
Fourth Quarter. . . . . . 21 1/4 15 1/2 16 1/2 13 3/4 17 1/2 12 3/4
1990 1989 1988
----------------- --------------- ----------------
High Low High Low High Low
----------------- --------------- ----------------
First Quarter . . . . . . $28 $23 3/8 $22 1/8 $18 5/8 $20 $16 1/4
Second Quarter. . . . . . 27 7/8 23 24 7/8 19 1/4 19 7/8 16 1/8
Third Quarter . . . . . . 28 1/8 24 26 1/4 22 7/8 20 3/4 17
Fourth Quarter. . . . . . 27 5/8 18 1/2 27 1/2 20 7/8 19 5/8 16 3/4
[Download Table]
COMMON STOCK DATA
1993 1992 1991 1990 1989 1988
---- ---- ---- ---- ---- ----
Shareholders of Record. . 20,406 22,832 23,979 25,090 27,062 28,534
------ ------ ------ ------ ------ ------
Shares Outstanding at
Yearend (OOOs). . . . . 66,656 66,034 65,302 64,764 64,436 58,022
------ ------ ------ ------ ------ ------
DIVIDENDS PER SHARE OF COMMON STOCK
As of December 31, 1993, the Corporation had paid 198 consecutive
quarterly cash dividends on its common stock. At December 31, 1993, $350
million of the consolidated common shareholders' equity of the Corporation
was free of restrictions as to the payment of dividends and redemption of
capital stock. The declaration of future dividends will be dependent upon
business conditions, earnings, the cash requirements of the Corporation and
other relevant factors. In February 1994, the Corporation declared a
quarterly cash dividend of 5 cents per share payable March 7, 1994, to share-
holders of record on February 18, 1994.
[Download Table]
1993 1992 1991 1990 1989 1988
---- ---- ---- ---- ---- ----
First Quarter . . . . . $.05 $.20 $.20 $.20 $.20 $.20
Second Quarter. . . . . .05 .20 .20 .20 .20 .20
Third Quarter . . . . . .05 .20 .20 .20 .20 .20
Fourth Quarter. . . . . .05 .20 .20 .20 .20 .20
---- ---- ---- ---- ---- ----
$.20 $.80 $.80 $.80 $.80 $.80
==== ==== ==== ==== ==== ====
A-55
Two million shares of PESC common stock, obtained in connection with the
sale of Pool Company and set aside as a special dividend to ENSERCH sharehold-
ers, were distributed in November 1990. The common stock was distributed at
the rate of one share of PESC for every 32.368 shares of ENSERCH common stock,
equivalent to $.33 per share.
A-56
APPENDIX B
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
DECEMBER 31, 1993
Page
----
Independent Auditors' Report................................. B-2
Consolidated Financial Statement Schedules
for the Three Years Ended December 31, 1993:
V - Property, Plant and Equipment..................... B-3
VI - Accumulated Depreciation and Amortization
of Property, Plant and Equipment................ B-6
IX - Short-Term Borrowings............................. B-9
X - Supplementary Income Statement Information........ B-10
B-1
INDEPENDENT AUDITORS' REPORT
ENSERCH CORPORATION:
We have audited the consolidated financial statements of ENSERCH
Corporation and subsidiary companies as of December 31, 1993 and 1992, and
for each of the three years in the period ended December 31, 1993, and
have issued our report thereon dated February 7, 1994; (included elsewhere
in this Form 10-K). Our audits also included the consolidated financial
statement schedules of ENSERCH Corporation listed in Item 14. These
consolidated financial statement schedules are the responsibility of the
Corporation's management. Our responsibility is to express an opinion
based on our audits. In our opinion, such consolidated financial
statement schedules, when considered in relation to the basic consolidated
financial statements taken as a whole, present fairly in all material
respects the information set forth therein.
DELOITTE & TOUCHE
Dallas, Texas
February 7, 1994
B-2
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1993
Balance at Balance at
Beginning Additions Other End of
Classification (a) of Year at Cost Retirements Changes Year
-------------- ---------- --------- ----------- ------- ----------
(In thousands)
Natural Gas Transmission
and Distribution
Transmission system. . $ 654,902 $ 31,236 $ 10,335 $ 1,356 (b) $ 677,159
Distribution system. . 781,345 60,687 10,660 831,372
---------- -------- --------- -------- ----------
Total. . . . . . . . 1,436,247 91,923 20,995 1,356 1,508,531
---------- -------- --------- -------- ----------
Natural Gas and Oil
Exploration and
Production . . . . . . . 1,892,129 119,566 47,049 (14,130) (c) 1,950,516
Natural Gas Liquids
Processing . . . . . . . 64,343 5,779 840 (254) (d) 69,028
Power and Other . . . . . 36,783 3,291 (341) (e) 39,733
General . . . . . . . . . 22,778 970 69 2,569 (f) 26,248
---------- -------- --------- -------- ----------
Total Continuing
Operations . . . . . 3,452,280 221,529 68,953 (10,800) 3,594,056
Discontinued Operations . 66,053 14,191 76,478 (3,766) (g)
---------- -------- --------- -------- ----------
Total . . . . . . . . . $3,518,333 $235,720 $ 145,431 $(14,566) $3,594,056
========== ======== ========= ======== ==========
--------------------
<FN>
(a) Effective as of December 31, 1993, operations have been realigned for segment of business reporting. Previously reported
amounts have been reclassified to reflect the new alignment.
(b) Represents transfers of $885 and other adjustments of $471.
(c) Represents writeoff of non-U.S. gas and oil property of ($13,306) transfers of ($587) and other adjustments of ($237).
(d) Represents writeoff of abandoned leases of ($297) and transfers of $43.
(e) Represents transfers.
(f) Represents transfers of $2,596 and tenant reimbursement of previously capitalized construction costs of ($27).
(g) Represents transfers of ($2,596), reclassification of equipment held for resale of ($1,119) and foreign currency
translation adjustment of ($51).
NOTE: See Note 1 of the Notes to Consolidated Financial Statements for rates used in computing depreciation and amortization.
B-3
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1992
Balance at Balance at
Beginning Additions Other End of
Classification (a) of Year at Cost Retirements Changes Year
-------------- ---------- --------- ----------- ------- ----------
(In thousands)
Natural Gas Transmission
and Distribution
Transmission system. . $ 707,877 $ 35,034 $ 63,892 $(24,117) (b) $ 654,902
Distribution system. . 747,169 40,761 6,585 - 781,345
---------- -------- --------- -------- ----------
Total. . . . . . . . 1,455,046 75,795 70,477 (24,117) 1,436,247
---------- -------- --------- -------- ----------
Natural Gas and Oil
Exploration and
Production . . . . . . . 1,960,446 65,787 127,454 (6,650) (c) 1,892,129
Natural Gas Liquids
Processing . . . . . . . 63,512 1,228 388 (9) (d) 64,343
Power and Other . . . . . 35,617 1,236 91 21 (e) 36,783
General . . . . . . . . . 22,301 1,076 27 (572) (f) 22,778
---------- -------- --------- -------- ----------
Total Continuing
Operations . . . . 3,536,922 145,122 198,437 (31,327) 3,452,280
Discontinued Operations . 81,324 5,068 19,194 (1,145) (g) 66,053
---------- -------- --------- -------- ----------
Total. . . . . . . . $3,618,246 $150,190 $ 217,631 $(32,472) $3,518,333
========== ======== ========= ======== ==========
--------------------
<FN>
(a) Effective as of December 31, 1993, operations have been realigned for segment of business reporting. Previously reported
amounts have been reclassified to reflect the new alignment.
(b) Represents reclassification of gas stored underground of ($24,133) to current assets and transfers of $16.
(c) Represents reimbursement of prior year expenditures being financed under an operating lease arrangement of ($6,164),
write-off of non-U.S. exploratory costs of ($400) and transfers of ($86).
(d) Represents write-off of abandoned leases of ($69), transfers of $49 and other adjustments of $11.
(e) Represents transfers.
(f) Represents write-off.
(g) Represents foreign currency translation adjustments of ($1,065) and reclassification of ($80) to investments following
reduction of ownership in a joint venture to less than 50%.
B-4
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1991
Balance at Balance at
Beginning Additions Other End of
Classification (a) of Year at Cost Retirements Changes Year
-------------- ---------- --------- ----------- ------- ----------
(In thousands)
Natural Gas Transmission
and Distribution
Transmission system. . $ 684,173 $ 60,984 $ 37,286 $ 6 (b) $ 707,877
Distribution system. . 736,720 30,825 20,376 - 747,169
---------- -------- -------- -------- ----------
Total. . . . . . . . 1,420,893 91,809 57,662 6 1,455,046
---------- -------- -------- -------- ----------
Natural Gas and Oil
Exploration and
Prouction. . . . . . . . 1,947,828 124,564 112,168 222 (c) 1,960,446
Natural Gas Liquids
Processing . . . . . . . 62,045 1,525 58 63,512
Power and Other . . . . . 34,260 1,415 58 35,617
General . . . . . . . . . 20,458 2,139 267 (29) (b) 22,301
---------- -------- -------- -------- ----------
Total Continuing
Operations . . . . 3,485,484 221,452 170,213 199 3,536,922
Discontinued Operations . 84,702 7,249 3,035 (7,592) (d) 81,324
---------- -------- -------- -------- ----------
Total. . . . . . . . $3,570,186 $228,701 $173,248 $ (7,393) $3,618,246
========== ======== ======== ======== ==========
--------------------
<FN>
(a) Effective as of December 31, 1993, operations have been realigned for segment of business reporting. Previously reported
amounts have been reclassified to reflect the new alignment.
(b) Represents transfers.
(c) Represents other adjustments of $1,299, write-off of non-U.S. exploratory costs of ($1,100) and transfers of $23.
(d) Represents reclassification of ($6,017) to investments following reduction of ownership in a joint venture to less than
50%, write-off of equipment of ($840) and foreign currency translation adjustments of ($735).
B-5
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1993
Deductions from
Reserves
------------
Additions Retirements,
---------------------- Renewals
Balance at Charged to Charged and Balance
Beginning Costs and to Other Replace- Other at End
Description (a) of Year Expenses Accounts(b) ments Changes of Year
----------- ---------- ---------- ----------- ---------- ------- ----------
(In thousands)
Natural Gas Transmission
and Distribution
Transmission system. $ 261,731 $ 16,820 $2,031 $ 6,632 $ 509 (d) $274,459
Distribution system. 294,330 20,664 2,931 10,730 307,195
---------- -------- ------ -------- ------- ----------
Total. . . . . . . 556,061 37,484 4,962 17,362 509 581,654
---------- -------- ------ -------- ------- ----------
Natural Gas and Oil
Exploration and
Production . . . . . 760,651 87,381 335 47,223 (429) (e) 800,715
Natural Gas Liquids
Processing . . . . . 48,775 4,003 103 836 (285) (f) 51,760
Power and Other . . . . 28,634 1,989 187 (g) 30,810
General . . . . . . . . 8,394 598 526 44 1,590 (e) 11,064
---------- -------- ------ -------- ------- ----------
Total Continuing
Operations . . . 1,402,515 131,455 (c) 5,926 65,465 1,572 1,476,003
Discontinued Operations 50,053 4,363 51,668 (2,748) (h)
---------- -------- ------ -------- ------- ----------
Total. . . . . . . $1,452,568 $135,818 $5,926 $117,133 $(1,176) $1,476,003
========== ======== ====== ======== ======= ==========
---------------
<FN>
(a) Effective as of December 31, 1993, operations have been realigned for segment of business reporting. Previously reported
amounts have been reclassified to reflect the new alignment.
(b) Depreciation of service equipment, etc., charged, together with other expenses of operating such equipment, to operating and
construction accounts on the basis of use.
(c) Charged to income as follows:
Depreciation and amortization.................................................................................. $131,455
Exploration and production (see Schedule V) -
Write-off of non-U.S. gas and oil properties................................................................. 13,306
--------
Total...................................................................................................... $144,761
========
(d) Represents transfers of $510 and other adjustments of ($1).
(e) Represents transfers.
(f) Represents writeoff of abandoned leases of ($297) and transfers of $12.
(g) Represents transfers of $186 and other adjustments of $1.
(h) Represents transfers of ($1,869), reclassification of equipment held for resale of ($881) and foreign currency translation
adjustment of $2.
B-6
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1992
Deductions from
Reserves
------------
Additions Retirements,
---------------------- Renewals
Balance at Charged to Charged and Balance
Beginning Costs and to Other Replace- Other at End
Description (a) of Year Expenses Accounts(b) ments Changes of Year
----------- ---------- ---------- ----------- ---------- ------- ----------
(In thousands)
Natural Gas Transmission
and Distribution
Transmission system. $ 266,541 $ 16,080 $2,190 $ 23,088 $ 8 (d) $ 261,731
Distribution system. 279,835 19,631 2,792 7,928 294,330
---------- -------- ------ -------- ----- ----------
Total. . . . . . . 546,376 35,711 4,982 31,016 8 556,061
---------- -------- ------ -------- ----- ----------
Natural Gas and Oil
Exploration and
Production . . . . . . 784,607 99,767 357 124,072 (8) (d) 760,651
Natural Gas Liquids
Processing . . . . . . 43,482 3,805 101 (845)(e) 542 (f) 48,775
Power and Other . . . . 26,814 1,907 87 28,634
General . . . . . . . . 7,565 1,099 2 24 (248) (g) 8,394
---------- -------- ------- -------- ----- ----------
Total Continuing
Operations . . . 1,408,844 142,289(c) 5,442 154,354 294 1,402,515
Discontinued Operations 57,267 5,504 12,023 (695) (h) 50,053
---------- -------- ------- -------- ----- ----------
Total. . . . . . . $1,466,111 $147,793 $5,442 $166,377 $(401) $1,452,568
========== ======== ====== ======== ===== ==========
---------------
<FN>
(a) Effective as of December 31, 1993, operations have been realigned for segment of business reporting. Previously reported
amounts have been reclassified to reflect the new alignment.
(b) Depreciation of service equipment, etc., charged, together with other expenses of operating such equipment, to operating and
construction accounts on the basis of use.
(c) Charged to income as follows:
Depreciation and amortization.................................................................................. $142,289
Exploration and production (see Schedule V) -
Write-off of non-U.S. exploratory costs...................................................................... 400
General -
Amortization of other intangibles............................................................................ 23
--------
Total...................................................................................................... $142,712
========
(d) Represents transfers.
(e) Includes a $940 adjustment to the salvage valve of a retired processing plant.
(f) Represents reclassification of reserves of $600, write-off of abandoned leases of ($69) and other adjustments of $11.
(g) Represents write-off.
(h) Represents foreign currency translation adjustments of ($688) and reclassification of ($7) to investments following reduction
of ownership in a joint venture to less than 50%.
B-7
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ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE VI - ACCUMULATED DEPRECIATION AND
AMORTIZATION OF PROPERTY, PLANT AND EQUIPMENT
For the Year Ended December 31, 1991
Deductions from
Reserves
------------
Additions Retirements,
---------------------- Renewals
Balance at Charged to Charged and Balance
Beginning Costs and to Other Replace- Other at End
Description (a) of Year Expenses Accounts(b) ments Changes of Year
----------- ---------- ---------- ----------- ---------- ------- ----------
(In thousands)
Natural Gas Transmission
and Distribution
Transmission system. $ 267,158 $ 16,614 $2,423 $ 19,657 $ 3 (d) $ 266,541
Distribution system. 271,452 19,033 2,593 13,243 279,835
---------- -------- ------ -------- ------- ----------
Total. . . . . . . 538,610 35,647 5,016 32,900 3 546,376
---------- -------- ------ -------- ------- ----------
Natural Gas and Oil
Exploration and
Production . . . . . . 789,042 81,240 330 86,339 334 (e) 784,607
Natural Gas Liquids
Processing . . . . . . 39,673 3,906 73 169 (1) (d) 43,482
Power and Other . . . . 25,054 1,817 57 26,814
General . . . . . . . . 6,742 1,083 6 249 (17) (d) 7,565
---------- -------- ------ -------- ------- ----------
Total Continuing
Operations . . . 1,399,121 123,693(c) 5,425 119,714 319 1,408,844
Discontinued Operations 53,061 7,642 2,246 (1,190) (f) 57,267
---------- -------- ------ -------- ------- ----------
Total. . . . . . . $1,452,182 $131,335 $5,425 $121,960 $ (871) $1,466,111
========== ======== ====== ======== ======= ==========
---------------
<FN>
(a) Effective as of December 31, 1993, operations have been realigned for segment of business reporting. Previously reported
amounts have been reclassified to reflect the new alignment.
(b) Depreciation of service equipment, etc., charged, together with other expenses of operating such equipment, to operating and
construction accounts on the basis of use.
(c) Charged to income as follows:
Depreciation and amortization.................................................................................. $123,693
Exploration and production (see Schedule V) -
Write-off of non-U.S. exploratory costs...................................................................... 1,100
General -
Amortization of other intangibles............................................................................ 45
--------
Total...................................................................................................... $124,838
========
(d) Represents transfers.
(e) Represents other adjustments of $319 and transfers of $15.
(f) Represents reclassification of $(844) to investments following reduction of ownership in a joint venture to less than 50%,
foreign currency translation adjustment of $(348) and other adjustments of $2.
B-8
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ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE IX - SHORT-TERM BORROWINGS
For the Three Years Ended December 31, 1993
Weighted Maximum Average Weighted
Average Amount Amount Average
Interest Outstanding Outstanding Interest Rate
Balance at Rate at at any During the During the
Classification Year End Year End Month End Year(a) Year(a)
-------------- ---------- -------- ----------- ----------- -------------
(In thousands except percents)
1993:
Short-term bank loans(b). $ $ 2,185 $ 599(c) 15.18%(c)
Commercial paper. . . . . $ 31,500 3.53% $208,100 $115,555 3.64%
1992:
Short-term bank loans(b). $152,412(d) 4.04%(e) $152,412 $ 44,923 5.96%
Commercial paper. . . . . $ $197,090 $111,318 4.69%
1991:
Short-term bank loans(b). $ 87,698 7.89%(e) $127,885 $107,691 6.91%
Commercial paper. . . . . $ 69,300 5.52% $157,385 $ 89,754 6.09%
---------------
<FN>
(a) Based on month-end balances.
(b) Includes loans for subsidiary companies and overdraft facilities.
(c) Amounts represent balances and rates in effect for certain non-U.S. bank loans
of foreign entities included in discontinued operations.
(d) Balance includes $150.0 million in short-term borrowings for Corporate which was repaid in January 1993. Balance also
includes $2.4 million for overdraft facilities related to discontinued operations.
(e) Interest rates at yearend 1992 and 1991 reflect a foreign overdraft facility at effective rates of 8.25% and 15%,
respectively, which was considered to be a hedge of an investment in a foreign subsidiary.
Note: See Notes 2 and 3 of the Notes to Consolidated Financial Statements in this Form 10-K for information concerning lines
of credit and borrowings.
B-9
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ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
For the Three Years Ended December 31, 1993
Classification 1993 1992 1991
-------------- ---- ---- ----
(In thousands)
Maintenance and repairs (a). . . . . . . . $ 39,783 $ 37,764 $ 37,997
======== ======== ========
Taxes, other than income taxes (a):
Gross receipts and gross production. . . $ 55,924 $ 52,517 $ 53,450
Ad valorem . . . . . . . . . . . . . . . 21,782 20,279 19,371
Social security. . . . . . . . . . . . . 14,350 12,063 11,601
Miscellaneous. . . . . . . . . . . . . . (2,851)(b) (5,680)(b) 419(b)
-------- -------- --------
Total . . . . . . . . . . . . . . . $ 89,205 $ 79,179 $ 84,841
======== ======== ========
---------------
<FN>
(a) Amounts represent results of continuing operations. Previously reported amounts for 1992 and 1991 have been restated to
reflect the engineering and construction business segment as a discontinued operation.
(b) Reflects refunds in state franchise taxes applicable to several prior years of $3.4 million in 1993, $7.8 million in 1992
and $3.2 million in 1991.
Depreciation and amortization expense not separately disclosed in the statements of consolidated income and advertising costs
are less than 1% of revenues and therefore are not presented herein.
B-10
EXHIBIT INDEX
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Exhibit
Number Document Description
_______ ____________________
10.10 ENSERCH Corporation Performance Bonus Plan - Calendar Year 1994.
21 Subsidiaries of the Registrant.
23.1 Deloitte & Touche consent to incorporation by reference in
Registration Statements No. 2-59259, No. 2-77572, No. 33-15623, No.
33-40589, No. 33-47911 and No. 33-52525.
23.2 DeGolyer and MacNaughton consent letter including consent to
incorporation by reference in Registration Statements No. 2-59259,
No. 2-77572, No. 33-15623, No. 33-40589, No. 33-47911 and No.
33-52525.
24 Powers of Attorney.
Dates Referenced Herein and Documents Incorporated by Reference
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