Document/Exhibit Description Pages Size
1: 10-K Annual Report 68± 315K
2: EX-3 Articles of Incorporation/Organization or By-Laws 42± 168K
3: EX-3 Articles of Incorporation/Organization or By-Laws 15± 64K
4: EX-10 Material Contract 6± 25K
5: EX-10 Material Contract 5± 19K
6: EX-10 Material Contract 13± 50K
7: EX-10 Material Contract 12± 51K
8: EX-10 Material Contract 6± 23K
9: EX-10 Material Contract 16± 62K
10: EX-21 Subsidiaries of the Registrant 3± 17K
11: EX-23 Consent of Experts or Counsel 1 7K
12: EX-23 Consent of Experts or Counsel 1 9K
13: EX-24 Power of Attorney 13 40K
14: EX-27 Financial Data Schedule (Pre-XBRL) 1 10K
==================================================================
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, 1994
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 (I.R.S. Employer
of 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)
Depositary Preferred Shares, New York Stock Exchange
Series F (each representing
1/40 share of the Adjustable
Rate Cumulative Preferred Stock,
Series F) (liquidation preference
$1,000 per share)
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 10, 1995:
$934,309,376.
Shares of the Registrant's Common Stock outstanding as of
March 10, 1995: 67,038,643 shares.
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 24, 1995 (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. (X)
==================================================================
FORM 10-K
ANNUAL REPORT
For the Fiscal Year Ended December 31, 1994
TABLE OF CONTENTS
[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 . . . . . . . . . . .2
Regulation . . . . . . . . . . . . . . . . . . . . . . . . . .4
Natural Gas and Oil Exploration and Production. . . . . . . . . .4
Gulf of Mexico . . . . . . . . . . . . . . . . . . . . . . . .5
Onshore. . . . . . . . . . . . . . . . . . . . . . . . . . . .6
International. . . . . . . . . . . . . . . . . . . . . . . . .6
Competition. . . . . . . . . . . . . . . . . . . . . . . . . .7
Regulation . . . . . . . . . . . . . . . . . . . . . . . . . .7
Natural Gas Liquids Processing. . . . . . . . . . . . . . . . . .7
Power . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .8
Clean Air Act . . . . . . . . . . . . . . . . . . . . . . . . . .9
Patents and Licenses. . . . . . . . . . . . . . . . . . . . . . .9
Employees . . . . . . . . . . . . . . . . . . . . . . . . . . . .9
Executive Officers of Registrant. . . . . . . . . . . . . . . . .9
ITEM 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . . 10
ITEM 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . . 13
ITEM 4. Submission of Matters to a Vote of
Security Holders . . . . . . . . . . . . . . . . . . . . . . . 13
PART II
ITEM 5. Market for Registrant's Common Equity and Related
Stockholder Matters. . . . . . . . . . . . . . . . . . . . . . 13
ITEM 6. Selected Financial Data . . . . . . . . . . . . . . . . . . . . 13
ITEM 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations. . . . . . . . . 13
ITEM 8. Financial Statements and Supplementary Data . . . . . . . . . . 13
ITEM 9. Changes in and Disagreements with Accountants
on Accounting and Financial Disclosure . . . . . . . . . . . . 14
PART III
ITEM 10. Directors and Executive Officers of
the Registrant . . . . . . . . . . . . . . . . . . . . . . . . 14
ITEM 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . . 14
ITEM 12. Security Ownership of Certain Beneficial Owners
and Management . . . . . . . . . . . . . . . . . . . . . . . . 14
ITEM 13. Certain Relationships and Related Transactions. . . . . . . . . 14
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and
Reports on Form 8-K. . . . . . . . . . . . . . . . . . . . . . 14
APPENDIX A Financial Information. . . . . . . . . . . . . . . . . . . .A-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,
gas marketers, pipelines 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. [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 Company, a division of the
Corporation.)
- Power--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.)
In October 1994, the Corporation completed the divestiture of
its former engineering and construction segment by the sale of
Enserch Environmental Corporation, the subsidiary that had
conducted the Corporation's environmental business. See "Financial
Review" and Note 7 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 1.28 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 as market opportunities are available. About seven
million people in Texas, representing over 40% of the total state
population, reside in Lone Star's service area.
EGC purchases and sells natural gas to gas marketing
companies, industrial and electric-generation customers and to
unaffiliated pipeline and local distribution companies.
The Corporation holds a 50% interest in a partnership named
Gulf Coast Natural Gas Company, which operates a transmission
system in the Texas Gulf Coast area that transports and sells
natural gas primarily to industrial and unaffiliated pipeline
customers.
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.
For the year ended December 31, 1994, residential and
commercial customers accounted for 46% of T&D's total gas sales
revenues and 23% of natural-gas volumes sold, industrial and
electric-generation customers accounted for 19% and 22%,
respectively, and sales to gas marketers, pipelines and other
customers accounted for 35% and 55%, respectively. In 1994, 5% of
T&D's gas sales volumes was sold to Texas Utilities Fuel Company,
compared with 10% in 1993. 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.
Revenues from Lone Star's gas sales are affected by seasonal
variations. The majority of Lone Star's residential and commercial
gas customers use 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 both cooling and heating seasons.
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, creating competition from other sellers of
natural gas. 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 decline in sales
by Lone Star to industrial and electric-generation customers.
Sales by the Corporation's nonregulated companies, along with
transportation services provided by Lone Star, have served to
offset much of the effects of this decline.
Competition to serve electric-generation customers was
heightened in 1994, as it was the first full year of operation of
a new nuclear-powered electric generating unit, which brought the
number of operating units in Texas to four, versus one and one-half
functioning units in 1993. These units displace about 1 billion
cubic feet ("Bcf") of gas-fired generating capacity each day.
Texas gas markets experienced the full impact of these units in
1994. This and other factors resulted in a 27% decline in volumes
sold for electric generation from the prior year. However, most of
the decline was in the lower margin sales by EGC, while margins
from Lone Star's remaining long-term contracts that extend through
the end of the decade remain intact.
The purchase and sale of gas in nonregulated markets is
accomplished through the gas marketing activities of EGC, which
actively pursues sales to customers that are tied to pipelines
other than Lone Star's. Sales are accomplished by a trading group
that sells gas to other marketers, as well as to end-users. As
natural-gas markets continue to evolve following the implementation
of the 1992 Order 636 of the Federal Energy Regulatory Commission
("FERC"), additional opportunities are created in the broader,
more active trading markets and in serving off-system customers.
Services to customers on off-system pipelines include term
contracts with interruptible and firm deliveries, aggregation of
supply, nominations, scheduling of deliveries and storage. Some
sale opportunities allow for gas to move across Lone Star's system,
thereby generating incremental transportation revenue. Trading
activities with other marketing companies have become a
significantly larger segment of the off-system business. With the
advent of essentially instant price determination, margins are
attainable only by taking positions in the monthly markets and
selling as prices move from moment to moment. ENSERCH generally
takes positions in transactions that will be concluded within a few
months and generally no longer than twelve months. ENSERCH does not
enter into multi-year, fixed-term contracts without having a
corresponding supply or sale.
A portion of the sales made by EGC requires transportation on
Lone Star's pipeline system. Additionally, Lone Star provides
transportation services not related to EGC sales (nonaffiliated
transportation). The movement of gas from the West Texas and New
Mexico producing areas to the east provides a market for
transportation across Lone Star's system. Intense competition
exists within the transportation business, which has resulted in
downward pressure on the average rate received for transportation
services. Lone Star's transportation volumes were 389 Bcf in 1994,
a 5% increase from 1993; however, transportation revenues for 1994
of $52 million were about the same as 1993.
In the current energy market, Lone Star's contracts for new
gas reserves have been at prices below its current system-wide
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, 1995 was 1.02 trillion cubic feet ("Tcf"),
or approximately 6 times Lone Star's purchases during 1994. Of
this total, 349 Bcf are dedicated reserves, 47 Bcf are gas in
storage, 624 Bcf (including 284 Bcf under one agreement) are
committed to Lone Star under service agreements. The January 1,
1995 total gas supply estimate is 48 Bcf greater than the
January 1, 1994 estimate. The difference resulted from new supply
additions of 202 Bcf and a net upward revision of 9 Bcf with
respect to estimates for existing sources and service agreements,
less 163 Bcf purchased from existing gas supply. New reserve
additions consisted of 92 Bcf on new dedicated reserves under old
contracts and 110 Bcf of reserves added under new service and
peaking contracts.
In 1994, about 91% of Lone Star's gas requirement was
purchased from some 270 independent producers and nonaffiliated
pipeline companies, one of which supplied approximately 14.2% of
total requirements. The remaining 9% of Lone Star's requirement
was supplied by affiliates.
Lone Star estimates its peak-day availability from presently
contracted sources, including withdrawals from underground storage,
to be 1.7 Bcf. Short-term peaking contracts raise this level to
meet anticipated sales needs.
During 1994, the average daily demand of Lone Star's
residential and commercial customers was .3 Bcf. The estimated
peak-day demand of such customers (based upon an arithmetic-mean
outside temperature of 15 degrees F.) was 2.0 Bcf. Lone Star's
greatest daily demand in 1994 was on February 10, when estimated
actual deliveries to all customers reached 1.8 Bcf and there was an
arithmetic-mean temperature of 30 degrees F. The estimated
deliveries to residential and commercial customers on that day were
1.3 Bcf and another 1.3 Bcf were transported by Lone Star.
To meet peak-day gas demands during winter months, Lone Star
utilizes its seven active underground storage fields, all of which
are located in Texas. These fields have an extraneous gas capacity
of 62 Bcf. At December 31, 1994, total extraneous gas in storage
was approximately 50 Bcf. Gas withdrawn from storage on
February 10, 1994, the date of Lone Star's greatest daily demand in
1994, was .6 Bcf, or approximately 30% of the total 2.0 Bcf of Lone
Star's sales.
Lone Star has historically maintained a contractual right to
curtail, which is 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 include the right to curtail gas
deliveries up to 100% according to a strict priority plan. The
last curtailment was in 1990 and lasted for only 30 hours.
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 pursues a program designed 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, northern and eastern 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.
In the past, Lone Star purchased gas under long-term,
intrastate contracts in order to assure reliable supply to its
distribution customers. Many of these contracts provided for
minimum-purchase or payment ("take-or-pay") obligations to gas
sellers. Lone Star had been unable to take delivery of all minimum
gas volumes tendered by suppliers under these contracts. Based on
Lone Star's estimated gas demand, which assumes normal weather
conditions, requisite gas purchases are expected to substantially
satisfy purchase obligations for the year 1995 and thereafter. See
"Financial Review - Natural Gas Transmission and Distribution" and
Note 1 to Consolidated Financial Statements included in Appendix A
to this report.
Generally, EGC's gas supply is contracted for on a short-term
basis at prevailing market prices for similar packages of gas. The
availability of supply is dependent on many factors, including the
overall demand for natural gas and a nonregulated market price high
enough to warrant suppliers to sell.
Regulation. Lone Star Gas is wholly intrastate in character
and performs utility operations in the state of Texas subject to
regulation by the Railroad Commission of Texas ("RRC") and
municipalities in Texas. 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 jurisdiction under the Natural Gas
Act.
In July 1988, Lone Star became an open-access transporter
under Section 311 of the Natural Gas Policy Act of 1978 ("NGPA") on
its intrastate transmission facilities. Such transportation 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 local city council with appellate review by the
RRC.
Lone Star employs a continuing program of rate review for all
classes of customers in its regulatory jurisdictions. Rate relief
amounting to $2.5 million in annualized revenue increases over and
above changes in gas cost was achieved in Texas in 1994 through
rate case filings, the operation of cost of service adjustment
clauses, and the operation of plant investment cost adjustments.
About 128 of the 550 cities and towns served by Lone Star had
approved weather normalization adjustment clauses as part of their
rate structure by year-end 1994, 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 , minimizing the impact of variations
in weather on Lone Star's earnings.
Lone Star's sales and transportation services to industrial
and electric-generation customers is provided under competitively
negotiated contracts. 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 because of the existing competitive market.
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 include geological and geophysical studies;
acquisition of gas, oil and mineral leases; drilling 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.
The Corporation's domestic operations are currently conducted
through Enserch Exploration, Inc. ("Enserch Exploration" or "EEX"),
a newly organized, publicly traded Texas corporation listed on the
New York Stock Exchange under the symbol "EEX". During 1994,
domestic gas and oil operations were primarily conducted through
Enserch Exploration Partners, Ltd. ("EP"), a limited partnership in
which a minority interest (less than 1%) was held by the public.
At year-end 1994, pursuant to a plan for the reorganization of EP
("Reorganization"), EEX, through a series of transactions, acquired
all of the operating properties of EP from EP's 99%-owned operating
partnership, EP Operating Limited Partnership ("EPO"), in exchange
for shares of EEX common stock. On December 30, 1994, the
Reorganization was consummated, EP was dissolved, and the EEX
common stock held by EP was distributed to EP's limited and general
partners in accordance with their partnership interests. In this
report, "Enserch Exploration" or "EEX" is used to refer to either
EEX or EP, or both, when a distinction is not required.
In connection with the Reorganization, Enserch Exploration
Holdings, Inc. ("EEH"), (named Enserch Exploration, Inc. and the
Managing General Partner of EP prior to the Reorganization),
received EP's interests in and assumed EP's obligations under
certain equipment lease arrangements relative to the Garden Banks
Block 388 project and the Mississippi Canyon Block 441 project,
with the equipment being simultaneously subleased to EEX. ENSERCH
affiliates also assumed approximately $395 million principal amount
of EP's indebtedness, plus accrued interest. Upon the liquidation
of EP and distribution of EEX common stock, public unitholders of
EP received 805,914 shares of EEX common stock (.77%) and ENSERCH
and its affiliates received 103,775,328 shares (99.23%) of EEX's
104,581,242 shares then outstanding.
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 of the Corporation currently have
interests in three foreign countries.
Production offices are maintained in Dallas, Houston, Athens,
Bridgeport, Longview and Midland, Texas. At December 31, 1994,
Enserch Exploration had 373 employees, including 34 geologists, 20
geophysicists and 18 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 55 engineers and
45 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.
Variable-priced natural-gas sales, which include monthly and
long-term sales contracts, covered about 75% of 1994 natural-gas
sales. Enserch Exploration's natural-gas sales volumes for the
year ended December 31, 1994 represented 11% of the Corporation's
total natural-gas sales volumes. Approximately 80% of Enserch
Exploration's natural-gas sales volumes (75% of gas revenues) for
the year ended December 31, 1994 was sold to affiliated companies.
Effective March 1, 1993, EGC began marketing gas for Enserch
Exploration for all gas not covered under existing contracts.
Affiliated purchasers 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 that affected operating income.
Following is a summary of Enserch Exploration's exploration
and development activity during 1994:
Gulf of Mexico. Exploration in the Gulf of Mexico is an
important part of Enserch Exploration's exploratory program. A
total of 14 leases (over 37,000 acres) were acquired in the Gulf of
Mexico, primarily the result of the Central Gulf lease sale in
April 1994. These leases were purchased based on prospects
principally defined by three-dimensional ("3-D") seismic acquired
before the lease sale. Typically, successful wells in the Gulf
produce at high rates compared with onshore wells, which is
important in increasing cash flow and improving the ratio of
production to reserves. State-of-the-art technology, including
specialized 3-D seismic processing and innovative production
techniques, is being utilized to help achieve this objective.
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
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 two years of production, the
field has been essentially maintenance free. Production from the
field, which declined from initial levels due to expected water
encroachment, has stabilized and is expected to remain at current
levels of some 35 million cubic feet ("MMcf") of natural gas and
more than 150 barrels ("Bbls") of condensate per day for the
foreseeable future. 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.
Throughout 1994, work progressed on the conversion of a
semisubmersible rig to a floating production facility for the
development of the Garden Banks Block 388 unit. The majority of
the modification work on the major structural components has been
completed. The 24-slot subsea template has been installed, and the
two 12-inch gas and oil gathering lines have been installed and
connected to the shallow-water production facility located 54 miles
away. Completion operations on the two pre-drilled wells commenced
in early 1995 and should enable these wells to be brought on-stream
when the floating facility is moored on location and the production
riser is installed. The initial well was completed in mid-March
and tested at rates which indicate that the well will likely flow
at an initial daily rate of 6,000 barrels. The second well should
be completed in mid-1995, followed by additional development
drilling, with one such well expected to be completed in late 1995.
Initial daily oil production rates from the second pre-drilled well
is anticipated to be between 2,500 and 6,000 barrels.
Under an agreement with Mobil Producing Texas and New Mexico
Inc. ("Mobil"), an exploratory well was drilled in the third
quarter of 1994 in Enserch Exploration's Garden Banks unit on Block
387, approximately four miles from the discovery on Block 388. The
well, drilled in 2,200 feet of water to a depth of 11,893 feet,
encountered a total of 150 feet of oil pay in the two reservoirs
and added significant incremental reserve potential to the
development project. A delineation well will be drilled on Block
386 or 387 in 1995. Subsea completions tied into the production
facility on Block 388 will be utilized to produce these wells.
Mobil has an option to acquire a 40% interest in the entire
Garden Banks unit consisting of six blocks and in the unit's
production system. To obtain that option, Mobil drilled the
exploratory well on Block 387 and has conducted a new 3-D seismic
survey over the unit to further assess the deeper horizons
correlative to nearby prolific reserves and, to extend the original
option, Mobil has paid additional consideration. Enserch
Exploration, which currently owns 100% of the project, will remain
the operator.
Enserch Exploration has a 100% working interest in a
successful exploratory sidetrack well on Green Canyon Block 254,
which encountered more than 400 feet of net gas and oil pay below
12,000 feet. The well was an appraisal to a discovery well drilled
in 1991 that encountered multiple sands with a combined thickness
of more than 300 feet of net pay. Additional drilling is planned
for the first half of 1995. Enserch Exploration had a 25% working
interest in prior work on this project before assuming operations
and a 100% working interest in the sidetrack well. Enserch
Exploration also has a 25% working interest in three adjacent
blocks. Efforts are underway to acquire additional interests in
Block 254 and the adjacent blocks to raise Enserch Exploration's
interest.
Onshore. In 1994, the majority of developmental drilling
activity was focused in the Freestone, Boonsville and Fashing
fields, all in Texas, where some reserves were added by
establishing production in zones that had not produced in the past.
In Freestone, 12 successful wells were drilled. Initial potential
tests have ranged from 1.4 to 2.6 MMcf of gas per day. In the
Boonsville area, 13 wells were drilled and completed in 1994.
These include nine gas wells that had initial potentials averaging
0.8 MMcf of gas per day and four oil wells initially delivering an
average of 76 barrels per day. In Fashing field, five wells were
drilled in 1994, four of which have been completed, with initial
deliveries averaging 1.7 MMcf of gas per day. Completion
operations are in progress on the fifth well.
A large portion of the development drilling and recompletion
activity during the past several years has been in six major gas
fields in East Texas. To offset the decline rate of hundreds of
older wells, reworks, recompletions and development drilling are
required, all of which are sensitive to product prices. In East
Texas, the goal is to accelerate production while preserving or
increasing reserves and net present value of the fields. Enserch
Exploration's East Texas proved reserves are currently estimated to
be some 784 Bcf.
In 1994, Enserch Exploration and the Los Alamos National
Laboratory joined in a first-time effort to use technology
developed for energy and national defense in the field of natural-
gas exploration. Joint goals are to employ more effective and
efficient methods of recovery of resources, to increase reserves
and to develop applied science that will be available to the entire
natural-gas industry. The Enserch Exploration/Los Alamos team is
testing the extent to which producing formations have been drained
by hydraulic fracturing in the Opelika gas field located in East
Texas. Los Alamos scientists are deploying instrumentation to
verify the extent of hydraulic fracturing in the producing Travis
Peak formation. It may then be determined where additional
fracturing can be used to release trapped gas, thereby maximizing
the recovery of domestic gas reserves. The data acquisition phase
from the Opelika field has been completed, with significant
microseismic activity detected in surrounding observation wells
when the test well was hydraulically fractured. The computation
phase of the project generated encouraging preliminary results
regarding fracture orientation. Currently, Los Alamos'
instrumentation is being modified to enhance the quality of
acquired data to define fracture extent.
International. The Corporation's international activities,
conducted through Enserch International Exploration, Inc. and its
subsidiaries ("EIEI"), included participation in one exploration
project during 1994. On the island of Java in Indonesia,
delineation work continued in the Mudi field that was discovered in
1993. The discovery well was drilled to a total depth of 9,797
feet and encountered a gross oil column of approximately 600 feet
and tested at a rate of 1,350 barrels of oil per day. Further
appraisal of the structure was conducted in mid-1994 with the
successful completion of a sidetrack well. This well encountered
improved reservoir conditions and tested in excess of 2,000 barrels
of oil per day. A third well, drilled to a depth of 8,793 feet,
tested at slightly over 5,000 barrels of oil per day. The fourth
well on the structure was spudded in early 1995 and will further
assess the prospect. EIEI has a 25% working interest in this
project, which is subject to the right of Pertimina, the national
oil company of Indonesia, to assume one-half of the working
interest after EIEI recovers its capital costs.
Competition. Competition in the natural gas and oil
exploration and production business is intense and 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 promulgated 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 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 implemented. 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 the 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.
The Oil Pollution Act of 1990 ("OPA 90") requires responsible
parties to provide evidence of financial responsibility in the
amount of $150 million to clean up oil spills into the navigable
waters of the United States. The financial responsibility
requirements apply to offshore facilities and possibly to onshore
facilities in, on or under navigable waters. The Mineral
Management Service ("MMS") is the agency charged with the
administration and enforcement of OPA 90. The ultimate impact of
the financial responsibility requirements cannot be determined
until final regulations are issued by the MMS. Further
Congressional action on these requirements is also possible, and
the final MMS regulations could be challenged in court. The
$150 million requirement will not become effective until
regulations under OPA 90 are issued, probably in 1996. The
insurance industry has indicated that insurance will not be
available to evidence financial responsibility under OPA 90 as
currently written. However, EEX has qualified as a self-insurer
using the "identified assets" test under the current $35 million
financial responsibility requirement using EEX's interest in Tri-
Cities field as the identified assets. It is believed that EEX has
sufficient assets to qualify as a self-insurer for $150 million
under the identified assets test if the current self-insurance test
is included in the OPA 90 regulations. It is unclear whether the
new regulations will allow EEX to qualify as a self-insurer.
Alternatively, EEX believes it could meet the current OPA 90
financial responsibility requirements by the purchase of a surety
bond, although the cost of such bonds is generally much higher than
insurance. The availability of surety bonds generally could also
be affected by the requirements of the final MMS regulations.
In the aggregate, compliance with federal and state
environmental rules and regulations is not expected to have a
material adverse 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.
Natural Gas Liquids Processing
The Corporation's operations for the processing of natural gas
for the recovery of natural gas liquids ("NGL") are currently being
conducted by Enserch Processing Company ("EPC"), a division of the
Corporation. In 1994, these operations were conducted by Enserch
Processing Partners, Ltd., a limited partnership wholly owned by
the Corporation.
EPC 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 gasoline, is
pumped via pipeline to Mt. Belvieu, Texas. The remaining natural
gas, primarily methane, leaves the NGL plants in gas transmission
lines for transportation to end-use customers. See "Properties."
About 60% 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."
To reduce the impact of shrinkage, EPC is increasingly
emphasizing the replacement of keep-whole contracts with net-
proceeds gas processing contracts. Keep-whole contracts are
profitable during periods of high NGL prices and low gas costs
because they provide the processor with ownership of the entire gas
stream. As prices fluctuate, these contracts become less
profitable because the processor must absorb all the shrinkage
costs. Under net-proceeds contracts, the producer provides
shrinkage volumes, while the processor contributes plant facilities
and operational costs. Revenues from NGL sales are apportioned
between the parties, and the processor is no longer impacted by
natural-gas feedstock costs.
The NGL processing area is highly competitive, including
competition regarding cost-sharing and interest-sharing
arrangements among producers, third-party owners and processors.
Power
Enserch Development Corporation ("EDC") develops 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's resources and minimizing the
Corporation's risk and investment. As of December 1994, EDC 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, and Lone Star transports the gas.
In 1992, the second plant developed by EDC was completed. The 62-
MW natural gas-fired cogeneration facility in Buffalo, New York,
supplies electricity to Niagara Mohawk Company and thermal energy
to Outokumpu American Brass, Inc. EDC's third project, a 160-MW
plant located in Bellingham, Washington, began commercial operation
in July 1993. The electricity produced by the plant is sold under
a long-term power sales agreement with Puget Sound Power & Light,
and thermal energy in the form of steam and hot water is sold to
Georgia-Pacific Corporation. Lone Star Energy Company ("LSEC")
operates and maintains all three of the plants and has fixed-cost
operating and maintenance agreements for providing labor and
certain routine consumables at each plant. Each of the agreements
contain escalation provisions. The agreements for the Buffalo and
Bellingham plants also contain bonus or penalty provisions based
upon plant availability.
In addition to operating and maintaining 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 40,500 tons of chilled water and 775 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 and
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 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 ten public natural-gas fuel stations in
commercial operation at December 31, 1994. TRANSTAR provides
turnkey natural-gas vehicle conversion and other related services
and performed over 500 vehicular natural-gas conversions in 1994,
over a 100% increase in conversions from 1993.
The operations of the CNG Division and affiliates have been
aligned under the Corporation's natural gas transmission and
distribution business segment for financial reporting purposes.
Clean Air Act
The impact of the 1990 amendments to the Clean Air Act ("CAA")
on the Corporation, its divisions, 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 chloroflurocarbon 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 CFC's. 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 reducing ozone formation and may be
substituted for other fuels. Since Title IV (Acid Rain) requires
major reductions in sulphur dioxide emissions, principally from
coal-fired electric power plants, natural gas is expected to be
considered as a cost-effective alternative for achieving reduced
sulphur dioxide emissions.
Patents and Licenses
The Corporation, Lone Star and subsidiary companies have no
material patents, licenses, franchises (excluding gas-distribution
franchises) or concessions.
Employees
At December 31, 1994, the Corporation, its divisions and
subsidiaries, had approximately 4,200 employees.
Executive Officers of Registrant
[Download Table]
Name Age Office and Business Experience
D. W. BIEGLER 48 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.
G. R. BRYAN 50 Chairman of EDC since February 1993. He
also served Lone Star as Senior Vice
President, Transmission, from February
1987 to February 1993.
G. J. JUNCO 45 President and Chief Operating Officer of
EEX since September 1994. He also served
as President and Chief Operating Officer
of EEH since January 1991 and as Senior
Vice President, Land and Marketing, from
April 1987 to December 1990.
W. T. SATTERWHITE 61 Senior Vice President and General
Counsel, Chief Legal Officer of the
Corporation since May 1972.
S. R. SINGER 64 Senior Vice President, Finance and
Corporate Development, Chief Financial
Officer of the Corporation since
September 1968.
R. B. WILLIAMS 62 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 divisions and
subsidiaries, are elected annually by their respective Board of
Directors. Officers may be removed by their respective Board of
Directors whenever, in their judgment, the best interest of the
Corporation, its divisions or subsidiaries, as the case may be,
will be served thereby.
ITEM 2. PROPERTIES
At December 31, 1994, Lone Star and certain subsidiaries of
the Corporation operated approximately 32,000 miles of transmission
and gathering lines and distribution mains and operated 35
compressor stations having a total rated horsepower of
approximately 80,000. Lone Star owns seven 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 of January 1, 1995, Enserch Exploration had net proved
reserves of 1.04 Tcf of natural gas and 50.6 MMBbls of oil and
condensate, as estimated by DeGolyer and MacNaughton, independent
petroleum consultants. See Note 8 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, except 4.1 MMBbls of oil and condensate, are in the
United States.
See "Financial Review - Liquidity and Financial Resources"
included in Appendix A to this report for a discussion of the
Corporation's 1995 capital spending budget by segment. In light of
the recent lack of heating weather and lower gas prices, the
Corporation is proceeding cautiously in implementing its total
capital spending program until the amount of future cash flows can
be better ascertained. Announced 1995 capital expenditures of
$262 million could be reduced by up to $25 million for EEX and
$10 million for Lone Star if cash flows fail to reach budgeted
levels.
During 1994, Enserch Exploration filed Form EIA-23 with the
Department of Energy reflecting reserve estimates for the year
1993. Such reserve estimates were not materially different from
the 1993 reserve estimates reported in Note 8 of the Notes to
Consolidated Financial Statements included in Appendix A to this
report.
As of December 31, 1994, Enserch Exploration and EIEI owned
leasehold interests or licenses in 17 states, offshore Texas and
Louisiana, and three other countries as follows:
[Enlarge/Download Table]
Gross Acres Net Acres (a)
------------------------------------------- ----------------------------------------
Developed Undeveloped Total Developed Undeveloped Total
------------------------------------------- ----------------------------------------
Alabama....... 75 13,409 13,484 37 2,916 2,953
Arkansas...... 19,607 19,607 11,338 11,338
Colorado...... 10,349 15,866 26,215 3,257 10,711 13,968
Idaho......... 14,730 14,730 14,730 14,730
Kansas........ 400 8,717 9,117 200 4,512 4,712
Louisiana..... 1,861 31,009 32,870 681 17,941 18,622
Mississippi... 4,355 31,339 35,694 2,323 12,203 14,526
Montana....... 6,415 44,903 51,318 3,201 22,372 25,573
Nebraska...... 160 480 640 160 480 640
Nevada........ 90,160 90,160 39,403 39,403
New Mexico.... 2,600 7,827 10,427 1,862 4,301 6,163
North Dakota.. 1,560 6,776 8,336 1,246 4,005 5,251
Ohio.......... 102 14,950 15,052
Oklahoma...... 32,366 18,280 50,646 17,730 9,396 27,126
Texas......... 262,674 590,110 852,784 197,984 356,546 554,530
Utah.......... 3,719 109,742 113,461 533 54,081 54,614
Wyoming....... 3,558 54,559 58,117 1,641 43,565 45,206
U.S. Offshore. 56,800 272,632 329,432 12,860 133,720 146,580
------- --------- --------- ------- --------- ---------
Total U.S.... 386,994 1,345,096 1,732,090 243,715 742,220 985,935
------- --------- --------- ------- --------- ---------
Malaysia..... 1,556,755 1,556,755 389,189 389,189
U.K.......... 20,010 20,010 1,248 1,248
Indonesia.... 912,802 912,802 228,200 228,200
------- --------- --------- ------- --------- ---------
Total Non-U.S. 2,489,567 2,489,567 618,637 618,637
------- --------- --------- ------- --------- ---------
Total Company. 386,994 3,834,663 4,221,657 243,715 1,360,857 1,604,572
======= ========= ========= ======= ========= =========
<FN>
(a) Represents the proportionate interest of Enserch Exploration in the gross acres under lease.
</FN>
Enserch Exploration purchased about 191,000 net acres of
leasehold interests in 1994, 37,000 of which were in the Gulf of
Mexico. Enserch Exploration's Gulf of Mexico holdings totaled some
147,000 net acres, with an average working interest of 46% in 61
blocks and an overriding royalty interest in three other blocks.
The company operates 28 offshore blocks. Enserch Exploration also
canceled or allowed to expire 21 Gulf of Mexico leases during the
year, which had been condemned 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 as to 20% of
undeveloped acreage in 1995, 36% in 1996, 21% in 1997, 5% in 1998,
11% in 1999, 2% in 2000 and 5% 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 areas in 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 - 50% in 1995, 30% in 1996 and 20% in 1998;
United Kingdom - 100% in 2016; Malaysia - 100% in 1996.
EEX participated in 108 wells (74 net) during 1994. Of these
wells, 58 wells (44 net) were successfully completed, resulting in
a net success rate of 59%. Of the successful wells, 13 wells (10
net) were exploratory and 45 wells (34 net) were development. At
December 31, 1994, EEX and EIEI were participating in 43 wells (24
net), which were either being drilled or in some stage of
completion.
In the 1994 domestic drilling program, 5 wells (1.5 net) were
offshore. Of these wells, 2 gas wells (.4 net) and 1 oil well (.4
net) were successfully completed. During 1993, 16 offshore wells
(4.9 net) were drilled, of which 9 gas wells (2.6 net) and 1 oil
well (.1 net) were successfully completed.
At December 31, 1994, Enserch Exploration owned interests in
1,314 gas wells (1,008 net) and 1,043 oil wells (286 net) in the
United States and 3 oil wells (1 net) in Indonesia. Of these, 173
gas wells (141 net) and 37 oil wells (32 net) were dual completions
in single boreholes.
Completed drilling activity during the three years ended
December 31, 1994 is set forth below:
[Download Table]
Exploratory Drilling Development Drilling
---------------------- -------------------
United United
States Non-U.S. States Non-U.S.
---------------------- --------------------
Productive Wells
1994:
Gross Wells 13.0 45.0
Net Wells 9.8 34.3
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
Nonproductive Wells
1994:
Gross Wells 43.0 7.0
Net Wells 25.3 4.6
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
__________________
<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.
</FN>
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 the timing 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 8 of the Notes to
Consolidated Financial Statements included in Appendix A to this
report.
EPC has interests in 18 processing plants, 13 of which are
wholly owned. The products, which in 1994 were produced at an
average of about 16,800 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 aggregate 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,
1995, 28.5 MMBbls of NGL are attributable to contractual processing
rights of EPC with respect to gas reserves owned by Enserch
Exploration or third parties and dedicated to Lone Star under
various gas-purchase contracts or are being transported 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 three central plants providing heating and cooling
to institutional customers in Dallas, El Paso and Galveston 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. This case was dismissed on
November 29, 1994 following a settlement of the claim at an amount
that was not material to the financial position of the Corporation.
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 claimed that the utility
division failed to make certain production and minimum-purchase
payments under a gas-purchase contract, that it was fraudulently
induced to enter into a gas-purchase contract, that it 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 initially sought
actual damages in excess of $100 million in addition to punitive
damages. Following subsequent discovery proceedings of plaintiff's
expert witnesses on the utility division's alleged minimum-
purchase obligation, plaintiff's claim, under alternate damage
theories, appeared to be in an asserted range of from $75 million
to $235 million, plus an additional $68 million related to alleged
secondary damages. Following a jury verdict in favor of the
utility division, the court entered a judgement on December 14,
1994 and denied Plaintiff's motion for a new trial on February 16,
1995.
Additional information required hereunder is set forth in
Note 4 of the Notes to Consolidated Financial Statements included
in Appendix A to this report. In addition, the Corporation is a
party to lawsuits arising in the ordinary course of its business.
The Corporation believes, based on its current knowledge and the
advice of counsel, that all lawsuits and claims would not have a
material adverse effect on its financial condition.
ITEM 4. Submission of Matters to a Vote of Security Holders
Not applicable.
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," "Summary of Business Segments" and "Quarterly Results"
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 24, 1995.
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:
[Download Table]
Item Page
Selected Financial Data . . . . . . . . . . . . . . . . . . . A-2
Financial Review. . . . . . . . . . . . . . . . . . . . . . . A-3
Independent Auditors' Report. . . . . . . . . . . . . . . . . A-9
Management Report on Responsibility for
Financial Reporting. . . . . . . . . . . . . . . . . . . .A-10
Financial Statements:
Statements of Consolidated Income. . . . . . . . . . . .A-11
Statements of Consolidated Cash Flows. . . . . . . . . .A-12
Consolidated Balance Sheets. . . . . . . . . . . . . . .A-13
Statements of Consolidated Common
Shareholders' Equity. . . . . . . . . . . . . . . . .A-14
Notes to Consolidated Financial Statements. . . . . . . . . .A-15
Summary of Business Segments. . . . . . . . . . . . . . . . .A-26
Quarterly Results . . . . . . . . . . . . . . . . . . . . . .A-27
Common Stock Market Prices and Dividend Information . . . . .A-28
(a)-2 Financial Statement Schedules
Consolidated financial statement schedules 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:
3.1 Restated Articles of Incorporation of Registrant
currently in effect.
3.2 Bylaws of Registrant currently in effect.
4.1* Shareholder Rights Plan - Filed as an Exhibit to
Registrant's Form 8-A dated April 23, 1986.
Executive Compensation Plan and Arrangements
(Exhibits 10.01 though 10.12):
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.
10.2 ENSERCH Corporation Deferred Compensation Plan for
Directors.
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 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.
10.5* 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.
10.6* 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.
10.7 ENSERCH Corporation Performance Incentive Plan - Calendar
Year 1995.
10.8* ENSERCH Corporation 1991 Stock Incentive Plan, filed as
Exhibit 10.12 to Registrant's Form 10-K for the Year
Ended December 31, 1990.
10.9 ENSERCH Corporation Deferred Compensation Plan and
Amendment No. 1 thereto dated March 28, 1995.
10.10 ENSERCH Corporation Deferred Compensation Trust.
10.11 ENSERCH Corporation Retirement Income Restoration Plan
and Amendment No. 1 thereto dated September 30, 1994.
10.12 ENSERCH Corporation Retirement Income Restoration Trust.
21 Subsidiaries of the Registrant.
23.1 Deloitte & Touche LLP consent to incorporation by
reference in Registration Statements No. 2-59259, No.
2-7572, 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.
27 Financial Data Schedule.
99* Proxy Statement dated at or about March 24, 1995 being
filed with the Securities and Exchange Commission on or
about March 24, 1995.
Long-term debt is described in Note 2 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 December 9, 1994, was filed
on December 12, 1994 (Reorganization of Enserch Exploration
Partners, Ltd. into a new corporation, Enserch Exploration, Inc.).
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 , 1995 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 Title Date
--------- ----- ----
* Chairman and President, March 30 1995
---------------------- Chief Executive Officer, ----,
D. W. Biegler and Director
* Director March 30 1995
---------------------- ----,
Frederick S. Addy
* Director March 30 1995
---------------------- ----,
William B. Boyd
* Director March 30 1995
---------------------- ----,
B. A. Bridgewater, Jr.
Director
----------------------
Odie C. Donald
* Director March 30 1995
---------------------- ----,
Lawrence E. Fouraker
* Director March 30 1995
---------------------- ----,
Preston M. Geren, Jr.
* Director March 30 1995
---------------------- ----,
Marvin J. Girouard
* Director March 30 1995
---------------------- ----,
Joseph M. Haggar
Director
----------------------
Thomas W. Luce, III
* Director March 30 1995
---------------------- ----,
W. C. McCord
* Director March 30 1995
---------------------- ----,
Diana S. Natalicio
* Director March 30 1995
---------------------- ----,
W. Ray Wallace
* Senior Vice President, March 30 1995
---------------------- Finance and Corporate ----,
S. R. Singer Development, Chief
Financial Officer
* Vice President and March 30 1995
---------------------- Controller, Chief ----,
J. W. Pinkerton Accounting Officer
*By: /s/ D. W. Biegler
----------------------
D. W. Biegler,
Individually and as
Attorney-in-Fact
APPENDIX A
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
INDEX TO FINANCIAL INFORMATION
DECEMBER 31, 1994
Page
----
Selected Financial Data............................... A-2
Financial Review...................................... A-3
Independent Auditors' Report.......................... A-9
Management Report on Responsibility for
Financial Reporting................................. A-10
Financial Statements:
Statements of Consolidated Income................... A-11
Statements of Consolidated Cash Flows............... A-12
Consolidated Balance Sheets......................... A-13
Statements of Consolidated Common
Shareholders' Equity.............................. A-14
Notes to Consolidated Financial Statements............ A-15
Summary of Business Segments.......................... A-26
Quarterly Results..................................... A-27
Common Stock Market Prices and Dividend Information... A-28
[Enlarge/Download Table]
SELECTED FINANCIAL DATA
ENSERCH Corporation and Subsidiary Companies
As of or for Year Ended December 31
---------------------------------------------------------------------
1994 1993 1992 1991 1990 1989
---- ---- ---- ---- ---- ----
(In millions except ratio and per share amounts)
INCOME STATEMENT DATA
Revenues
Natural gas transmission and distribution $1,689.0 $1,547.9 $1,318.3 $1,273.3 $1,285.1 $1,361.0
Natural gas and oil exploration and production 179.1 189.8 171.5 183.6 213.9 184.0
Natural gas liquids processing. . . . . . 87.4 85.8 87.0 92.8 99.4 76.6
Power . . . . . . . . . . . . . . . . . . 45.5 48.6 45.7 37.3 28.1 28.5
Less intercompany revenues. . . . . . . . (143.6) (138.9) (53.5) (49.2) (35.6) (40.3)
Total revenues. . . . . . . . . . . . . 1,857.4 1,733.2 1,569.0 1,537.8 1,590.9 1,609.8
Operating Income (Loss)
Natural gas transmission and distribution 63.2 101.5 (a) 102.0 111.5 101.7 136.4
Natural gas and oil exploration and production 25.6(b) (37.3)(c) (6.2)(b) 10.9 31.9 43.4
Natural gas liquids processing. . . . . . 1.0 5.0 13.1 21.2 24.9 4.2
Power . . . . . . . . . . . . . . . . . . 5.8 9.8 13.4 6.1 2.5 2.4
General and other . . . . . . . . . . . . (8.2) (11.9) (16.9) (15.5) (18.3) (12.3)
Total operating income. . . . . . . . . 87.4 67.1 105.4 134.2 142.7 174.1
Other Income (Expense) - Net (d) . . . . . (6.5) .2 (12.4) 14.1 49.3 .7
Interest Expense . . . . . . . . . . . . . (68.2) (77.0) (94.3) (92.9) (99.0) (92.9)
Income (Taxes) Benefit . . . . . . . . . . 69.0(e) (6.5)(e) 2.5 (17.7) (25.7) (20.0)
Income (Loss) from Continuing Operations . 81.7 (16.2) 1.2 37.7 67.3 61.9
Income (Loss) from Discontinued Operations 20.6 75.4 (13.8) (18.6) 35.5 11.5
Extraordinary Loss on Extinguishment of Debt (15.4)
Net Income (Loss). . . . . . . . . . . . . 102.3 59.2 (28.0) 19.1 102.8 73.4
Earnings (Loss) Applicable to Common Stock 90.7 46.6 (41.0) 4.8 88.6 59.1
Per Share of Common Stock
Income (loss) from continuing operations after
provision for preferred dividends . . . 1.05 (.43) (.18) .36 .81 .80
Discontinued operations . . . . . . . . . .31 1.13 (.21) (.29) .55 .19
Extraordinary loss. . . . . . . . . . . . (.23)
Earnings (Loss) Applicable to Common Stock 1.36 .70 (.62) .07 1.36 .99
Average Common and Dilutive Common
Equivalent Shares Outstanding . . . . . . 66.8 66.6 65.7 65.1 65.0 59.8
----------------------------------------------------------------------------------------------------------------------------
COMMON STOCK DATA
Cash Dividends Declared and Paid (f) . . . $ .20 $ .20 $ .80 $ .80 $ .80 $ .80
Market Price
High. . . . . . . . . . . . . . . . . . . 19 1/8 22 5/8 16 1/2 21 3/8 28 1/8 27 1/2
Low . . . . . . . . . . . . . . . . . . . 12 1/8 14 1/8 10 3/8 12 3/4 18 1/2 18 5/8
Common Shareholders' Equity per Share. . . 10.84 9.70 9.16 10.51 11.18 10.88
Shares Outstanding at Year-end . . . . . . 67.0 66.7 66.0 65.3 64.8 64.4
----------------------------------------------------------------------------------------------------------------------------
BALANCE SHEET DATA
Property, Plant and Equipment - Net. . . . $2,252.6 $2,118.1 $2,065.8 $2,152.1 $2,118.0 $2,046.3
Total Assets . . . . . . . . . . . . . . . 2,846.3 2,760.3 3,145.7 3,163.1 3,264.2 3,254.2
Net Working Capital (Deficiency) . . . . . (161.0) (195.5) 2.5 (42.2) 64.3 (23.0)
Current Ratio. . . . . . . . . . . . . . . .75 .72 1.00 .95 1.08 .97
Unused Lines of Credit . . . . . . . . . . $ 600.0 $ 635.0 $ 485.0 $ 650.0 $ 600.0 $ 600.0
----------------------------------------------------------------------------------------------------------------------------
CAPITAL STRUCTURE
Senior Long-term Debt. . . . . . . . . . . $ 724.9 $ 638.8 $ 865.3 $ 757.6 $ 772.5 $ 727.1
Convertible Subordinated Debentures. . . . 90.8 90.8 90.8 205.7 215.7 215.7
Preferred Stock. . . . . . . . . . . . . . 175.0 175.0 175.0 175.0 175.0 175.0
Common Shareholders' Equity. . . . . . . . 725.4 646.7 604.6 686.3 723.9 701.3
Total Capitalization. . . . . . . . . . . 1,716.1 1,551.3 1,735.7 1,824.6 1,887.1 1,819.1
Senior Long-term and Convertible Debt
Ratio (Percent) . . . . . . . . . . . . . 47.5 47.0 55.1 52.8 52.4 51.8
---------------
<FN>
(a) Includes a $12.0 million pretax charge ($7.8 million after-tax, $.12 per share) principally for severance expenses
associated with re-engineering distribution operations.
(b) 1994 includes a $7.6 million pretax ($4.9 million after-tax, $.07 per share) gain from the sale of an inactive offshore
pipeline and facilities. 1992 includes a $16.5 million pretax write-down ($10.9 million after-tax, $.17 per share) of
an inactive offshore pipeline and facilities.
(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 and a $13.3 million pretax write-off ($8.6 million after-tax, $.13 per share) of non-U.S. gas and oil
assets.
(d) 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 assets ($10.0
million after-tax, $.15 per share); and 1990 includes a $34 million pretax gain ($22 million after-tax, $.34 per share)
from the sale of investment in Oceaneering International, Inc.
(e) 1994 includes a $70.0 million ($1.05 per share) reduction of deferred income taxes as a result of the conversion of
partnerships to corporate form and resulting change in tax status. 1993 includes a $10.8 million ($.16 per share)
charge from the 1% increase in the statutory federal income-tax rate on corporations.
(f) A distribution also 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.
ENSERCH CORPORATION
FINANCIAL REVIEW
Earnings applicable to common stock for the year 1994 were $91 million
($1.36 per share), compared with 1993 earnings of $47 million ($.70 per share)
and a loss applicable to common stock for 1992 of $41 million ($.62 per
share).
CONTINUING OPERATIONS - Results from continuing operations, after provision
for preferred dividends, were income of $70 million ($1.05 per share) in 1994,
a loss of $29 million ($.43 per share) in 1993, and a loss of $12 million
($.18 per share) in 1992. The 1994 results from continuing operations
included a $70 million reduction of deferred income taxes associated with the
conversion of Enserch Exploration Partners, Ltd. and other partnerships to
corporate form and the resulting change in tax status (see Note 6). The 1994
results also included a $4.9 million after-tax ($7.6 million pretax) gain from
the sale of an inactive offshore pipeline. Results for 1993 were impacted by
an $8 million after-tax ($12 million pretax) charge principally for severance
expenses associated with the re-engineering of Lone Star Gas Company's
distribution operations, an $11 million charge from the 1% increase in the
statutory federal income-tax rate on corporations, 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. The 1992 results included an $11 million after-tax
($17 million pretax) write-down of an inactive offshore pipeline and
facilities and a $10 million after-tax ($15 million pretax) provision for
litigation.
Operating income for 1994 was $87 million, compared with $67 million in 1993
and $105 million in 1992. Excluding the effects of the unusual items
mentioned above, operating income was $80 million for 1994, $134 million for
1993 and $122 million for 1992. Variations in operating income by business
segment are discussed below.
NATURAL GAS TRANSMISSION AND DISTRIBUTION - The table of Operating Data
reflects the effects of variable weather patterns and increasing activity in
non-utility markets. Operating income for 1994 was $63 million, compared with
$101 million in 1993 and $102 million in 1992. From 1993 to 1994, there was
a decline of $39 million in margin on gas sales, and operating expenses for
1994 increased some $6 million (2%) because transitional costs for the re-
engineering of the distribution operations exceeded savings that began to be
realized.
Lone Star's residential and commercial sales volumes of 126 billion cubic feet
(Bcf) in 1994 were 10% below the 1993 volumes of 139 Bcf. The 1993 volumes
were 16% above 1992. The fluctuations are mostly attributable to differences
in winter weather. In 1994, total heating degree days were 91% of the average
for the 30-year period ended in 1990, compared with 104% in 1993 and 82% in
1992.
The margin decline on sales by Lone Star included approximately $8 million
attributable to year-to-year differences in heating weather and $17 million
due to higher unrecovered gas-purchase costs. Gas-purchase expense includes
the cost of gas delivered, which is directly flowed-through to customers, plus
the cost of the excess of purchased volumes over delivered volumes. The
latter costs fluctuate from year to year due to various factors, including
temperature extremes, metering variances and billing estimates.
Sales by Enserch Gas Company (EGC), the ENSERCH gas marketing affiliate,
accounted for 72% of total gas sales volumes in 1994, 59% in 1993 and 53% in
1992. EGC's 1994 margin declined $14 million compared with 1993. Gas prices
were strong in early 1994 due to record cold weather in the Northeast and
remained somewhat stable until midyear, but prices declined rapidly later in
the year as industry storage facilities were generally full and normally
expected colder fourth-quarter weather failed to materialize throughout most
of the country. Additionally, gas demand for electric generation was lower
than expected during the summer months as a result of fewer days of above-
100-degree temperatures and an increase in nuclear generating capacity in
Texas. The combination of these market pressures eroded much of the margin on
EGC's gas sales. From time to time, EGC enters into contracts to purchase gas
for physical delivery up to one year later. The 1994 margin decline for EGC
also includes a $4 million charge recorded on forward purchase contracts to
reflect lower year-end market prices.
In the past, Lone Star was unable to take delivery of all gas tendered by
suppliers under contract minimum-purchase requirements, resulting in sizable
advance payments for gas and settlement payments. At December 31, 1994, there
was an unrecovered balance of gas-purchase contract settlements of
$61 million. The unrecovered balance has declined substantially each year
from $208 million at year-end 1991. The balances include take-or-pay settle-
ments, amounts relating to pricing and amounts related to the settlement of
other contractual matters. Of the $61 million, $31 million represented
prepayments expected to be recouped under contracts covering future gas
purchases, and $30 million represented amounts to be recovered from customers
under the existing gas-cost recovery provisions. Based on Lone Star's
estimated gas demand, which assumes normal weather conditions, requisite gas
purchases are expected to substantially satisfy purchase obligations for the
year 1995 and thereafter. Outstanding supplier claims approximated
$10 million as of December 31, 1994. A previously reported claim asserting
damages ranging from $75 million to $235 million was decided in Lone Star's
favor by a jury in the fourth quarter of 1994; the decision is subject to
plaintiff's motion for new trial and later appeal to a higher court. Lone
Star expects to recoup or recover the remaining balances of gas settlement
payments made to date, as well as any future payments made in settlement of
remaining claims.
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION - Operating income closely
follows fluctuations in product prices and volumes, as shown in the table of
Operating Data. Excluding effects of the previously discussed unusual items,
operating income was $18 million for 1994, $17 million for 1993 and
$10 million for 1992.
Revenues for 1994 of $179 million were 6% lower than 1993, which was 11% above
1992. In 1994, natural-gas revenues decreased slightly to $145 million, with
the average natural-gas price per thousand cubic feet of $2.15 up from $2.09
in 1993 and $1.82 in 1992. Natural-gas sales volumes were 67 Bcf in 1994,
70 Bcf in 1993 and 65 Bcf in 1992. The decrease in volumes in 1994 was
principally due to reduced production from several high-volume fields in South
Texas and offshore Louisiana. The increase in volumes from 1992 to 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 $6 million to $31 million in 1994 due to a 6% production decline and
an 11% decrease in the average sales price to $15.38 per barrel. Oil revenues
decreased to $37 million in 1993 from $45 million in 1992, as production
declined 9% and the average sales price dropped 10%. The lower volumes were
primarily the result of declining production from several North Texas
reservoirs.
Throughout 1994, work progressed on the conversion of a semisubmersible rig
to a floating production facility for the development of the Garden
Banks Block 388 unit. The majority of the modification work on the major
structural components has been completed. The 24-slot subsea template has
been installed, and the two 12-inch oil and gas gathering lines have been
installed and connected to the shallow-water production facility located
54 miles away.
Completion operations on two pre-drilled wells commenced in early 1995 and
should enable these wells to be brought on-stream when the floating facility
is moored on location and the production riser is installed. These activities
should be completed in mid-1995, followed by additional development drilling,
with one such well expected to be completed in late 1995. Initial daily oil
production rates from the pre-drilled wells are anticipated to be between
2,500 and 5,000 barrels of oil per well.
Mobil Producing Texas and New Mexico Inc. (Mobil) has an option to acquire,
for consideration, a 40% interest in the entire Garden Banks unit consisting
of six blocks and in the unit's production system. If Mobil exercises its
option, Enserch Exploration, which currently owns 100% of the project, will
remain the operator.
Operating results for 1995 are expected to be negatively impacted by the
midyear commencement of production from the two pre-drilled wells on Garden
Banks Block 388. Revenues from the early levels of production are not
expected to be sufficient to cover operating costs, amortization and the
equipment lease costs on the floating production platform and related
facilities. Some operating costs and amortization vary with production;
however, other costs and the equipment lease costs are essentially fixed.
Results are expected to improve significantly for 1996 as production begins
from several development wells and equipment lease and other fixed costs are
spread over significantly more production.
ENSERCH has budgeted $160 million for exploration and production activities
in 1995, compared with expenditures of $133 million in 1994 and $120 million
in 1993.
ENSERCH's natural-gas reserves at January 1, 1995, were 1.04 trillion cubic
feet (Tcf), compared with 1.09 Tcf the year earlier, as estimated by DeGolyer
and MacNaughton, independent petroleum consultants. Oil and condensate
reserves, including natural gas liquids attributable to leasehold interests,
were 51 million barrels (MMBbls), compared with the year-earlier level of
39 MMBbls. The increase is associated with Garden Banks Block 388 and the
Mudi project in Indonesia.
The Corporation follows the full-cost method of accounting for gas and oil
properties. The overall rate of amortization for U.S. properties was
$1.04 per million British thermal units produced for 1994, compared with $.98
for both 1993 and 1992. The Mississippi Canyon capital lease and higher
onshore exploratory costs largely account for the increase in 1994. Product
prices are subject to seasonal and other fluctuations. A decline in prices
from year-end 1994 or other factors, without mitigating circumstances, would
cause a future write-down of capitalized costs that could be significant and
a noncash charge against earnings.
ENSERCH uses gas and oil swaps, collars and futures agreements to hedge
volatile product prices for a portion (normally 30 to 70 percent) of
anticipated future gas and oil production. Hedges resulted in a net increase
in gas revenues of $5.0 million in 1994, compared with a decrease of
$4.1 million in 1993. Hedges reduced oil revenues $.7 million in 1994 but
added $.4 million in 1993. At December 31, 1994, ENSERCH had outstanding
swaps, collars and futures agreements extending through December 1995 to
exchange payments on some 17.8 Bcf of gas and 1.2 MMBbls of oil on which
ENSERCH had $4.1 million of net unrealized gains. At December 31, 1994,
realized gains on hedging activities of $.9 million were deferred.
On December 30, 1994, through a series of transactions, Enserch Exploration,
Inc. (EEX), a newly organized Texas corporation, acquired all of the operating
properties of Enserch Exploration Partners, Ltd. (EP), and EP received common
stock of EEX. EP was then liquidated, and its partners received one share of
EEX common stock for each limited and general partnership interest held. The
ENSERCH companies also received EP's interests in and assumed EP's obligations
under certain equipment lease arrangements (the equipment was simultaneously
subleased to EEX) and assumed approximately $395 million principal amount of
EP's indebtedness, plus accrued interest. Upon the liquidation of EP and
distribution of EEX common stock, public unitholders of EP received
805,914 shares of EEX common stock (.77%) and the ENSERCH companies received
103,775,328 shares (99.23%) of EEX's 104,581,242 shares outstanding.
NATURAL GAS LIQUIDS PROCESSING - Fluctuations in natural gas liquids (NGL)
demand caused by overall economic conditions, price volatility for NGL
products and natural-gas feedstock costs are the major factors that influence
financial results in the NGL processing business, as shown in the table of
Operating Data. Operating income was $1 million for 1994, $5 million for 1993
and $13 million for 1992. Small operating losses were incurred during the
first three quarters of 1994. However, in the last quarter, NGL prices
improved and feedstock costs declined, and the restored margins were
sufficient to more than offset the losses incurred earlier in 1994.
POWER - ENSERCH's power activities, comprised of Enserch Development
Corporation (EDC) and Lone Star Energy Company (LSE), had 1994 operating
income of $5.8 million, compared with $9.8 million for 1993 and $13.4 million
for 1992. In the second quarter of 1994, EDC and LSE began earning management
and incentive fees from operating a 160-megawatt cogeneration plant in
Bellingham, Washington, developed by EDC, which should provide a steady stream
of future income. EDC's 1994 operating income was $1.7 million, compared with
$5.9 million for 1993 and $9.8 million for 1992. Results for 1993 included
a $15 million gain from the sale of a position in a power project that had
been scheduled for development, and 1992 results included a $15 million fee
from development of the Bellingham project. LSE's operating income was
$4.1 million for 1994, $3.9 million for 1993 and $3.6 million for 1992.
OTHER - Other income/expense consists principally of gains on disposal of
assets, interest income and discounts on sales of receivables. In addition,
1993 includes a $5.6 million provision for interest awarded in the judgment
described earlier, and 1992 includes a $15 million provision for litigation.
Interest expense for 1994 was $68 million, compared with $77 million for 1993,
which included $8 million not related to borrowings, and $94 million for 1992.
The reduction from 1992 reflects the results of a program to refinance long-
term debt at lower rates. Over the three-year period, short-term interest
rates were at their lowest level in 1993.
DISCONTINUED OPERATIONS - The 1994 income from discontinued operations of
$21 million ($.31 per share) arose from the sale of Enserch Environmental
Corporation, partially offset by a $10 million ($17.5 million pretax) loss
provision to recognize that costs and expenses incurred for the wind-up of
other discontinued businesses would be greater than previously estimated. The
1993 results of $75 million ($1.13 per share) primarily arose from the sale
of the principal operating assets of Ebasco Services Incorporated. The
$14 million ($.21 per share) loss in 1992 primarily related to the sale of
Humphreys and Glasgow International and provisions for real estate formerly
utilized by discontinued operations. With the sale of Enserch Environmental,
the Corporation has now completed the divestiture of its engineering and
construction business. Remaining assets, including receivables, and
obligations are expected to be substantially settled by year-end 1996 (see
Note 7).
LIQUIDITY AND FINANCIAL RESOURCES - Net cash flows from operating activities
of continuing operations reflect the previously described variances in
operating income and related changes in current operating assets and
liabilities and for 1994 totaled $94 million, compared with $197 million in
1993 and $213 million in 1992. The amount provided in 1994 is after the
$62 million payment relating to the adverse judgment in litigation described
earlier. Net recoveries of gas-purchase contract settlements were some
$50 million in both 1994 and 1993, twice the 1992 amount.
Discontinued operations required cash of $.9 million in 1994, after the net
proceeds from the sale of Enserch Environmental of $98 million. Enserch
Environmental operations required cash for working capital of $32 million,
which was recovered in the sale. Also included is the remittance of
$22 million for December 1993 collections of sold receivables plus the payment
of accrued expenses, taxes and other retained obligations relating to the sale
of Ebasco. Cash provided by discontinued operations in 1993 included net
proceeds from the sale of the principal operating assets of Ebasco and
$100 million from the limited recourse sale of Ebasco receivables.
Planned property, plant and equipment additions for 1995 total $262 million
and include $96 million designated for Transmission and Distribution,
$160 million for Exploration and Production and $6 million for other
requirements. The planned expenditures are expected to be funded from
internal cash flow and external financings as required and exclude costs of
the floating production platform and related facilities of the Garden Banks
project, which is financed by an operating lease arrangement aggregating
$235 million. The cost of these facilities is expected to be $330 million,
which includes design modifications and other costs for Block 388 facilities
and for the recent discovery on Block 387. Financing options for the
additional costs currently are being evaluated, including an addition to the
current operating lease arrangement.
In the first quarter of 1994, $150 million of 6 3/8% Notes due 2004 were
issued in a public offering, and $74 million of sinking fund debentures and
$75 million of Series D Adjustable Rate Preferred Stock were redeemed. In
April 1994, $75 million of Series F Adjustable Rate Preferred Stock was sold,
which has a substantially lower dividend rate than the Series D. Net proceeds
were used to repay $29 million of maturing senior long-term debt and to reduce
commercial paper borrowings. In November 1994, $150 million of privately
placed variable-rate long-term debt due in 1998 was issued. The proceeds were
used to retire $100 million of maturing 9.11% debt and to reduce short-term
borrowings.
Total capitalization at December 31, 1994 was $1.7 billion, an increase of
$165 million from year-end 1993, reflecting $86 million more senior long-term
debt and $79 million growth in shareholders' equity. As a percentage of total
capitalization, common shareholders' equity increased slightly to 42.3% at
December 31, 1994. At December 31, 1994, $423 million of shareholders' equity
was free of any restrictions for payment of dividends or acquisition of
capital stock.
The current ratio at December 31, 1994 was .75 versus .72 at year-end 1993 and
1.0 at year-end 1992, with the decline from 1992 substantially attributable
to the sale of Ebasco and Enserch Environmental.
ENSERCH uses the commercial paper market and commercial banking facilities for
short-term needs. Bank lines in the form of a three-year revolving agreement
totaled $600 million, all unused at year-end 1994.
Inflation during recent years has had little effect on capital costs and
results of operations.
FOURTH-QUARTER RESULTS - Earnings applicable to common stock for the fourth
quarter of 1994 were $89 million ($1.33 per share), compared with $36 million
($.53 per share) for the fourth quarter of 1993. Income from continuing
operations after provision for preferred dividends for the fourth quarter of
1994 was $70 million ($1.05 per share) versus a loss of $35 million ($.52 per
share) for the year-ago period. Results for the 1994 and 1993 fourth quarters
included all of the unusual items noted for the full year, except in 1993 the
$11 million charge for the increase in the statutory federal income-tax rate
and $2.0 million of the after-tax write-offs of non-U.S. gas and oil assets
occurred earlier. Fourth-quarter income from discontinued operations was
$19 million ($.28 per share), compared with $70 million ($1.05 per share) for
the 1993 period. Excluding effects of unusual items, operating income for the
1994 fourth quarter was $14 million, compared with $27 million for the year-
earlier quarter, with the decline primarily due to lower results for the
Transmission and Distribution business segment.
[Enlarge/Download Table]
NATURAL GAS TRANSMISSION AND DISTRIBUTION OPERATING DATA
----------------------------------------------------------------------------------------------------------------------------
For Year Ended December 31 1994 1993 1992 1991 1990 1989
----------------------------------------------------------------------------------------------------------------------------
Operating Income (in millions) . . . $ 63.2 $ 101.5(a) $ 102.0 $ 111.5 $ 101.7 $ 136.4
======== ======== ======== ======== ======== ========
Natural Gas Sales Revenues
by Customer (in millions)
Residential & commercial . . . . $ 744.3 $ 823.8 $ 716.5 $ 702.9 $ 684.3 $ 756.8
Industrial & electric generation 306.4 357.2 350.8 373.8 418.3 444.9
Gas marketers, pipelines and
other. . . . . . . . . . . . . 569.9 293.7 185.2 124.9 112.9 90.5
-------- -------- -------- -------- -------- --------
Total gas sales revenues . . . $1,620.6 $1,474.7 $1,252.5 $1,201.6 $1,215.5 $1,292.2
======== ======== ======== ======== ======== ========
Natural Gas Revenues (in millions)
Lone Star Gas Company Sales. . . . $ 861.3 $ 954.2 $ 905.1 $ 895.7 $ 916.9 $1,026.3
Enserch Gas Company Sales (b). . . 759.3 520.5 347.4 305.9 298.6 265.9
-------- -------- -------- -------- -------- --------
Total gas sales revenues . . . 1,620.6 1,474.7 1,252.5 1,201.6 1,215.5 1,292.2
Gas transportation . . . . . . . . 51.6 52.2 46.9 48.9 47.0 46.0
-------- -------- -------- -------- -------- --------
Total natural gas revenues . . 1,672.2 1,526.9 1,299.4 1,250.5 1,262.5 1,338.2
Other. . . . . . . . . . . . . . . 16.8 21.0 18.9 22.8 22.6 22.8
-------- -------- -------- -------- -------- --------
Total revenues . . . . . . . . $1,689.0 $1,547.9 $1,318.3 $1,273.3 $1,285.1 $1,361.0
======== ======== ======== ======== ======== ========
Natural Gas Sales Volumes
by Customer (Bcf)
Residential & commercial . . . . 125.7 139.3 120.6 128.5 122.6 140.3
Industrial & electric generation 122.5 138.0 130.3 163.2 164.1 171.5
Gas marketers, pipelines
and others . . . . . . . . . . 297.3 136.2 99.3 70.9 58.9 47.9
-------- -------- -------- -------- -------- --------
Total gas sales volumes. . . . 545.5 413.5 350.2 362.6 345.6 359.7
======== ======== ======== ======== ======== ========
Natural Gas Volumes (Bcf)
Lone Star Gas Company Sales. . . . 152.2 169.5 163.4 178.9 180.9 212.1
Enserch Gas Company Sales (b). . . 393.3 244.0 186.8 183.7 164.7 147.6
-------- -------- -------- -------- -------- --------
Total gas sales volumes. . . . 545.5 413.5 350.2 362.6 345.6 359.7
======== ======== ======== ======== ======== ========
Gas transportation
For associated . . . . . . . . . 133.6 139.8 129.5 133.0 118.4 115.3
For others (nonassociated) . . . 255.8 231.3 177.8 165.9 134.7 135.7
-------- -------- -------- -------- -------- --------
Total. . . . . . . . . . . . . 389.4 371.1 307.3 298.9 253.1 251.0
======== ======== ======== ======== ======== ========
Lone Star System throughput. . . . 551.3 554.0 482.6 501.6 456.8 495.4
Off-system sales (c) . . . . . . . 250.0 90.8 45.4 26.9 23.5
-------- -------- -------- -------- -------- --------
Total throughput (d) . . . . . 801.3 644.8 528.0 528.5 480.3 495.4
======== ======== ======== ======== ======== ========
Natural Gas Sales Revenues per Mcf
by Customer
Residential & commercial . . . . $ 5.92 $ 5.91 $ 5.94 $ 5.47 $ 5.58 $ 5.39
Industrial & electric generation 2.50 2.59 2.69 2.29 2.55 2.59
Gas marketers, pipeline
and others . . . . . . . . . . 1.92 2.16 1.86 1.76 1.92 1.89
-------- -------- -------- -------- -------- --------
Composite. . . . . . . . . . . $ 2.97 $ 3.57 $ 3.58 $ 3.31 $ 3.52 $ 3.59
======== ======== ======== ======== ======== ========
Natural Gas Revenues per Mcf
Lone Star Gas Company Sales. . . . $ 5.66 $ 5.63 $ 5.54 $ 5.01 $ 5.07 $ 4.84
Enserch Gas Company Sales (b). . . 1.93 2.13 1.86 1.67 1.81 1.80
Natural Gas Purchase Cost per Mcf
Lone Star Gas Company. . . . . . . $ 3.38 $ 3.54 $ 3.48 $ 3.05 $ 3.20 $ 3.10
Enserch Gas Company (b). . . . . . 1.89 2.02 1.73 1.54 1.66 1.67
Gas Transportation Rate per Mcf. . . $ .13 $ .14 $ .15 $ .16 $ .19 $ .18
Natural Gas Customers
(at December 31) (in thousands). . 1,281 1,265 1,243 1,224 1,249 1,241
Heating Degree Days. . . . . . . . . 2,201 2,508 1,980 2,179 2,015 2,632
% of normal (2,407) (e). . . . . . 91.4 104.2 82.3 90.5 83.7 109.3
Cooling Degree Days. . . . . . . . . 2,676 2,767 2,415 2,670 2,791 2,563
% of normal (2,603) (e). . . . . . 102.8 106.3 92.8 102.6 107.2 98.5
------------------
<FN>
(a) Includes a $12.0 million charge principally for severance expenses associated with re-engineering distribution operations.
(b) In March 1993, Enserch Gas Company (EGC) began marketing gas for Natural Gas and Oil Exploration and Production operations.
Prior to 1992, also included Enserch Gas Transmission Company, 50% owned after 1991.
(c) Includes off-system sales never entering Lone Star's pipeline system.
(d) Total throughput is the sum of gas sales volumes and gas transportation volumes for others. Gas transported by Lone Star
for EGC is reported in both sales and associated transportation.
(e) Based on National Weather Service data for the 30 year period 1961-1990, as determined by the Department of Commerce.
[Enlarge/Download Table]
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION OPERATING DATA
----------------------------------------------------------------------------------------------------------------------------
For Year Ended December 31 1994 1993 1992 1991 1990 1989
----------------------------------------------------------------------------------------------------------------------------
Operating Income (Loss) (in millions) $ 25.6(a) $(37.3)(b) $ (6.2)(a) $ 10.9 $ 31.9 $ 43.4
====== ====== ====== ====== ====== ======
Revenues - After Royalties (in millions)
Natural gas (c). . . . . . . . . . $144.5 $146.4 $118.6 $123.4 $142.9 $139.2
Oil and condensate . . . . . . . . 30.9 36.9 45.1 56.7 68.6 58.0
Natural gas liquids. . . . . . . . 2.4 4.1 6.5 2.0 2.2 1.9
Other revenues - net . . . . . . . 1.3 2.4 1.3 1.5 .2 3.8
Less minority interest in EP . . . (18.9)
------ ------ ------ ------ ------ ------
Total revenues . . . . . . . . $179.1 $189.8 $171.5 $183.6 $213.9 $184.0
====== ====== ====== ====== ====== ======
Sales Volumes
Natural gas (Bcf) (c). . . . . . . 67.1 70.0 65.2 70.1 76.9 76.3
Oil and condensate (MMBbl) . . . . 2.0 2.1 2.3 2.8 3.1 3.3
Average Sales Price
Natural gas (per Mcf). . . . . . . $ 2.15 $ 2.09 $ 1.82 $ 1.76 $ 1.85 $ 1.81
Oil and condensate (per Bbl) . . . 15.38 17.24 19.20 20.31 22.39 17.37
Net Wells
Drilled. . . . . . . . . . . . . . 74 79 19 67 53 18
Productive . . . . . . . . . . . . 44 64 8 52 42 14
Proved Reserves (at December 31)
Gas (Bcf). . . . . . . . . . . . . 1,042 1,086 1,101 1,168 1,237 1,230
Oil and condensate (MMBbl)(d). . . 50.6 39.3 39.2 40.0 32.3 28.1
Standardized Measure of Discounted
Future Net Cash Flows (in millions) $ 827 $ 831 $ 820 $ 812 $ 963 $ 840
Data in Equivalent Energy Content
(per MMBtu) (e)
Average sales price. . . . . . . . $ 2.15 $ 2.16 $ 2.04 $ 2.03 $ 2.17 $ 2.00
Average production costs . . . . . .55 .56 .55 .60 .54 .52
U. S. amortization rate. . . . . . 1.04 .98 .98 .90 .78 .72
-------------------------------------------------
<FN>
(a) 1994 includes a $7.6 million gain from the sale of an inactive offshore pipeline and facilities. 1992 includes a $16.5
million write-down of an inactive offshore pipeline and facilities.
(b) 1993 includes a $41.4 million charge as a result of an adverse judgment in litigation and a $13.3 million write-off of
non-U. S. gas and oil assets.
(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.
[Enlarge/Download Table]
NATURAL GAS LIQUIDS PROCESSING OPERATING DATA
----------------------------------------------------------------------------------------------------------------------------
For Year Ended December 31 1994 1993 1992 1991 1990 1989
----------------------------------------------------------------------------------------------------------------------------
Operating Income (in millions) . . . $ 1.0 $ 5.0 $ 13.1 $ 21.2 $ 24.9 $ 4.2
======== ======== ======== ======== ======== ========
Revenues (in millions)
Natural gas liquids. . . . . . . . $ 68.9 $ 73.6 $ 79.0 $ 84.8 $ 91.8 $ 71.6
Other. . . . . . . . . . . . . . . 18.5 12.2 8.0 8.0 7.6 5.0
-------- -------- -------- -------- -------- --------
Total . . . . . . . . . . . . . $ 87.4 $ 85.8 $ 87.0 $ 92.8 $ 99.4 $ 76.6
======== ======== ======== ======== ======== ========
Natural Gas Liquids
Sales volumes (MMBbl). . . . . . . 5.9 6.0 5.9 6.1 6.4 7.2
Average sales price (per Bbl). . . $ 11.65 $ 12.34 $ 13.35 $ 13.92 $ 14.27 $ 9.96
Proved Reserves of Natural Gas
Liquids Under Contractual
Processing Rights (MMBbl). . . . . 28.5 27.2 28.2 28.4 28.7 30.7
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, 1994 and 1993, 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, 1994.
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, 1992, 1991, 1990 and 1989 and the related statements of
consolidated income, cash flows and common shareholders' equity for the years
ended December 31, 1991, 1990, and 1989 (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, 1994 and 1993, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1994, in conformity with generally accepted accounting
principles. Also, in our opinion, the information set forth in the
accompanying table of selected financial data for the years 1989 through 1994
is fairly stated in all material respects in relation to the consolidated
financial statements from which such information has been derived.
DELOITTE & TOUCHE LLP
Dallas, Texas
February 10, 1995
MANAGEMENT REPORT ON RESPONSIBILITY FOR FINANCIAL REPORTING
The management of ENSERCH Corporation is responsible for the preparation,
presentation and integrity of the financial statements and other information
contained in this report. The financial 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 established practices and procedures designed to support the
reliability of the estimates and minimize the possibility of a material
misstatement.
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 is supported by written policies
and procedures, and the control environment is regularly evaluated by both
Deloitte & Touche LLP,the independent auditors, and the Corporation's internal
auditors. 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. The independent auditors and the internal auditors have
free access to the Audit Committee.
Management believes that, as of December 31, 1994, the overall system of
internal accounting controls is sufficient to accomplish the objectives
discussed herein.
/s/ D. W. Biegler /s/ S. R. Singer /s/ J. W. Pinkerton
_______________________ ______________________ ______________________
D. W. Biegler S. R. Singer J. W. Pinkerton
Chairman, President and Senior Vice President, Vice President and
Chief Executive Officer Finance and Corporate Controller,
Development, Chief Chief Accounting Officer
Financial Officer
February 10, 1995
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31
-----------------------------------------------------------------------------------------------------------
1994 1993 1992
-------- -------- --------
(In thousands except per share amounts)
Revenues
Natural gas transmission and distribution. . . . . $1,689,024 $1,547,919 $1,318,258
Natural gas and oil exploration and production . . 179,140 189,796 171,544
Natural gas liquids processing . . . . . . . . . . 87,446 85,785 86,966
Power . . . . . . . . . . . . . . . . . . . . . . 45,499 48,635 45,728
Less intercompany revenues . . . . . . . . . . . . (143,678) (138,934) (53,484)
---------- ---------- ----------
Total. . . . . . . . . . . . . . . . . . . . 1,857,431 1,733,201 1,569,012
---------- ---------- ----------
Costs and Expenses
Gas purchase . . . . . . . . . . . . . . . . . . . 1,208,147 1,021,107 902,346
Operating expenses . . . . . . . . . . . . . . . . 354,390 415,331 342,584
Depreciation and amortization. . . . . . . . . . . 126,733 144,242 142,383
Gross receipts and production taxes. . . . . . . . 50,723 55,924 52,517
Payroll, ad valorem and other taxes. . . . . . . . 29,989 29,465 23,736
---------- ---------- ----------
Total. . . . . . . . . . . . . . . . . . . . 1,769,982 1,666,069 1,463,566
---------- ---------- ----------
Operating Income. . . . . . . . . . . . . . . . . . 87,449 67,132 105,446
Other Income (Expense) - Net. . . . . . . . . . . . (6,506) 174 (12,472)
Interest Expense . . . . . . . . . . . . . . . . . (68,242) (77,004) (94,313)
---------- ---------- ----------
Income (Loss) before Income Taxes . . . . . . . . . 12,701 (9,698) (1,339)
Income Taxes (Benefit). . . . . . . . . . . . . . . (68,974) 6,483 (2,502)
---------- ---------- ----------
Income (Loss) from Continuing Operations. . . . . . 81,675 (16,181) 1,163
Income (Loss) from Discontinued Operations . . . . 20,642 75,418 (13,811)
Extraordinary Loss on Extinguishment of Debt. . . . (15,358)
---------- ---------- ----------
Net Income (Loss) . . . . . . . . . . . . . . . . . 102,317 59,237 (28,006)
Provision for Dividends on Preferred Stock. . . . . 11,619 12,663 12,952
---------- ---------- ----------
Earnings (Loss) Applicable to Common Stock. . . . . $ 90,698 $ 46,574 $ (40,958)
========== ========== ==========
Per Share of Common Stock
Income (loss) from continuing operations
after provision for dividends on
preferred stock . . . . . . . . . . . . . . . . $ 1.05 $ (.43) $ (.18)
Discontinued operations . . . . . . . . . . . . . .31 1.13 (.21)
Extraordinary loss . . . . . . . . . . . . . . . . (.23)
---------- ---------- ----------
Earnings (loss) applicable to common stock . . . . $ 1.36 $ .70 $ (.62)
========== ========== ==========
Cash dividends declared. . . . . . . . . . . . . . $ .20 $ .20 $ .80
========== ========== ==========
Average Common and Dilutive Common
Equivalent Shares Outstanding. . . . . . . . . . . 66,845 66,598 65,695
========== ========== ==========
Operating Income (Loss) of Major Business Segments
(Excludes general corporate expenses)
Natural gas transmission and distribution. . . . . $ 63,178 $ 101,458 $ 101,996
Natural gas and oil exploration and production . . 25,617 (37,293) (6,175)
Natural gas liquids processing . . . . . . . . . . 1,007 5,037 13,092
Power. . . . . . . . . . . . . . . . . . . . . . . 5,761 9,795 13,379
<FN>
See Notes to Consolidated Financial Statements.
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31
-----------------------------------------------------------------------------------------------------------------------
1994 1993 1992
-------- -------- --------
(In thousands)
OPERATING ACTIVITIES
Income (loss) from continuing operations . . . . . . . . . . . $ 81,675 $(16,181) $ 1,163
Depreciation and amortization. . . . . . . . . . . . . . . . . 126,733 144,242 142,383
Deferred income-tax benefit. . . . . . . . . . . . . . . . . . (59,167) (775) (9,682)
Recoveries of gas-purchase contract settlements. . . . . . . . 49,602 50,825 25,612
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2,707) (5,563) (4,830)
Changes in current operating assets and liabilities:
Accounts receivable. . . . . . . . . . . . . . . . . . . . . 15,588 (6,205) 12,605
Other current assets . . . . . . . . . . . . . . . . . . . . (33,109) (13,455) 19,007
Accounts payable and other accrued liabilities . . . . . . . (4,029) 24,738 6,473
Other current liabilities. . . . . . . . . . . . . . . . . . (17,867) (27,358) 5,246
Litigation judgment payable. . . . . . . . . . . . . . . . . (62,498) 47,032 15,466
-------- -------- --------
Net Cash Flows from Operating Activities . . . . . . . . . 94,221 197,300 213,443
-------- -------- --------
INVESTING ACTIVITIES
Additions of property, plant and equipment . . . . . . . . . . (260,010) (218,611) (144,318)
Retirements of property, plant and equipment . . . . . . . . . 8,206 7,386 6,186
Proceeds from disposition of significant assets. . . . . . . . 8,500 7,825 16,640
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,009 (2,886) 5,828
Discontinued operations. . . . . . . . . . . . . . . . . . . . (942) 318,408 8,373
-------- -------- --------
Net Cash Flows from (used for) Investing Activities. . . . (237,237) 112,122 (107,291)
-------- -------- --------
FINANCING ACTIVITIES
Change in commercial paper and other short-term borrowings . . 119,500 (120,912) 1,743
Issuance of senior long-term debt. . . . . . . . . . . . . . . 299,117 200,000 346,897
Retirement of senior long-term debt and
convertible debentures . . . . . . . . . . . . . . . . . . . (214,983) (423,523) (361,748)
Settlement of foreign currency swap. . . . . . . . . . . . . . 23,089
Issuance of Series F Preferred Stock . . . . . . . . . . . . . 72,797
Retirement of Series D Preferred Stock . . . . . . . . . . . . (75,000)
Other financing activities - net . . . . . . . . . . . . . . . (53,113) (2,335) (8,198)
Issuance of common stock . . . . . . . . . . . . . . . . . . . 3,451 10,876 10,376
Cash dividends paid. . . . . . . . . . . . . . . . . . . . . . (25,071) (25,967) (65,650)
-------- -------- --------
Net Cash Flows from (used for) Financing Activities. . . . 126,698 (338,772) (76,580)
-------- -------- --------
Net (Decrease) Increase in Cash and Equivalents. . . . . . . . . (16,318) (29,350) 29,572
Cash and Equivalents at Beginning of Year. . . . . . . . . . . . 19,203 48,553 18,981
-------- -------- --------
Cash and Equivalents at End of Year. . . . . . . . . . . . . . . $ 2,885 $ 19,203 $ 48,553
======== ======== ========
Amounts paid
Interest (net of amount capitalized) . . . . . . . . . . . . . $ 66,378 $101,157 $108,881
======== ======== ========
Income taxes - net . . . . . . . . . . . . . . . . . . . . . . $ 5,464 $ 20,443 $ 6,087
======== ======== ========
<FN>
See Notes to Consolidated Financial Statements.
[Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
December 31
-----------------------
1994 1993
--------- ----------
(In thousands)
ASSETS
Current Assets
Cash and equivalents . . . . . . . . . . . . . . . . . . $ 2,885 $ 19,203
Accounts receivable. . . . . . . . . . . . . . . . . . . 193,385 224,947
Gas stored underground . . . . . . . . . . . . . . . . . 114,862 109,615
Advances and prepayments for gas . . . . . . . . . . . . 28,622 32,951
Gas-purchase settlements recoverable from customers. . . 23,943 42,800
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 126,896 78,051
---------- ----------
Total current assets . . . . . . . . . . . . . . 490,593 507,567
---------- ----------
Investments. . . . . . . . . . . . . . . . . . . . . . . 56,010 86,208
---------- ----------
Property, Plant and Equipment (at cost)
Natural gas transmission and distribution. . . . . . . . 1,596,773 1,508,531
Natural gas and oil exploration and production (full-cost
method). . . . . . . . . . . . . . . . . . . . . . . 2,070,318 1,950,516
Natural gas liquids processing . . . . . . . . . . . . . 76,333 69,028
Power. . . . . . . . . . . . . . . . . . . . . . . . . . 32,186 31,564
General and other. . . . . . . . . . . . . . . . . . . . 26,672 34,417
---------- ----------
Total. . . . . . . . . . . . . . . . . . . . . . 3,802,282 3,594,056
Less accumulated depreciation and amortization . . . . . 1,549,717 1,476,003
---------- ----------
Net property, plant and equipment. . . . . . . . 2,252,565 2,118,053
---------- ----------
Other Assets . . . . . . . . . . . . . . . . . . . . . . 47,131 48,433
---------- ----------
Total. . . . . . . . . . . . . . . . . . . . . $2,846,299 $2,760,261
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Commercial paper . . . . . . . . . . . . . . . . . . . $ 151,000 $ 31,500
Current maturities of senior long-term debt. . . . . . . 10,600 10,600
Accounts payable and other accrued liabilities . . . . 401,587 442,395
Accrued interest . . . . . . . . . . . . . . . . . . . . 35,885 34,021
Litigation judgment payable. . . . . . . . . . . . . . . 62,035
Other. . . . . . . . . . . . . . . . . . . . . . . . . 52,522 122,534
---------- ----------
Total current liabilities. . . . . . . . . . . . 651,594 703,085
---------- ----------
Senior Long-term Debt. . . . . . . . . . . . . . . . . . 714,324 628,227
---------- ----------
Convertible Subordinated Debentures. . . . . . . . . . . 90,750 90,750
---------- ----------
Other Liabilities
Deferred income taxes. . . . . . . . . . . . . . . . . 280,051 321,364
Accrued pension costs. . . . . . . . . . . . . . . . . . 53,617 43,027
Other. . . . . . . . . . . . . . . . . . . . . . . . . . 155,493 152,090
---------- ----------
Total other liabilities. . . . . . . . . . . . . 489,161 516,481
---------- ----------
Commitments and Contingent Liabilities (Note 4). . . . .
Shareholders' Equity
Adjustable rate preferred stock. . . . . . . . . . . . 175,000 175,000
Common shareholders' equity. . . . . . . . . . . . . . 725,470 646,718
---------- ----------
Shareholders' equity . . . . . . . . . . . . . . 900,470 821,718
---------- ----------
Total. . . . . . . . . . . . . . . . . . . . . $2,846,299 $2,760,261
========== ==========
<FN>
See Notes to Consolidated Financial Statements.
[Enlarge/Download Table]
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED COMMON SHAREHOLDERS' EQUITY
Year Ended December 31
-----------------------------------------
1994 1993 1992
---- ---- ----
(In thousands)
Common Stock - $4.45 par value,
authorized 100 million shares
Balance at beginning of year. . . . . . . . . . . . . . $296,619 $293,849 $290,593
Issued for stock plans (298; 622; and 732 shares) . . 1,324 2,770 3,256
-------- -------- --------
Balance at end of year (Outstanding shares:
66,954; 66,656; and 66,034) . . . . . . . . . . . . . 297,943 296,619 293,849
-------- -------- --------
Paid in Capital
Balance at beginning of year. . . . . . . . . . . . . . 339,115 353,789 395,105
Excess of proceeds over par value of
common stock issued for stock plans . . . . . . . . 3,107 8,106 7,120
Dividends declared in excess of retained earnings . . (22,780) (48,436)
Series F preferred stock issuance costs . . . . . . . (2,203)
-------- -------- --------
Balance at end of year. . . . . . . . . . . . . . . . . 340,019 339,115 353,789
-------- -------- --------
Retained Earnings (Deficit)
Balance at beginning of year. . . . . . . . . . . . . . 10,984 (45,092)
Net income (loss) . . . . . . . . . . . . . . . . . . 102,317 59,237 (28,006)
Dividends declared. . . . . . . . . . . . . . . . . . (24,952) (25,939) (65,521)
Transfer of dividends declared in excess of
retained earnings to paid in capital. . . . . . . . 22,780 48,436
Other . . . . . . . . . . . . . . . . . . . . . . . . (1) (2) (1)
-------- -------- --------
Balance at end of year. . . . . . . . . . . . . . . . . 88,348 10,984 (45,092)
-------- -------- --------
Foreign Currency Translation Adjustment
Balance at beginning of year. . . . . . . . . . . . . . 2,092 576
Net change during the year. . . . . . . . . . . . . . (2,092) 1,516
-------- -------- --------
Balance at end of year. . . . . . . . . . . . . . . . . 2,092
-------- -------- --------
Unamortized Restricted Stock Compensation
Balance at beginning of year. . . . . . . . . . . . . .
Shares granted (88.5) . . . . . . . . . . . . . . . . (1,261)
Cancellations (13.8). . . . . . . . . . . . . . . . . 192
Amortization. . . . . . . . . . . . . . . . . . . . . 140
Market valuation adjustments. . . . . . . . . . . . . 89
-------- -------- --------
Balance at end of year. . . . . . . . . . . . . . . . . (840)
-------- -------- --------
Common Shareholders' Equity . . . . . . . . . . . . . . $725,470 $646,718 $604,638
======== ======== ========
<FN>
See Notes to Consolidated Financial Statements.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
ENSERCH Corporation and Subsidiary Companies
All dollar amounts, except per share amounts, in the notes to the consolidated
financial statements are stated in thousands unless otherwise indicated.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER INFORMATION
The consolidated financial statements include the accounts of ENSERCH
Corporation (ENSERCH or the Corporation) and its majority owned subsidiaries.
The statements of consolidated income and cash flows for 1993 and 1992 have
been restated to reflect the environmental business sold in 1994 as a
discontinued operation.
Earnings per share applicable to common stock are based on the weighted
average number of common shares outstanding during the year, including common
equivalent shares when dilutive. Fully diluted earnings per share are not
presented since the assumed exercise of stock options and conversion of
debentures would not be dilutive.
All highly liquid investments in the United States with a maturity of three
months or less are considered to be cash equivalents.
Information by business segments is presented after the notes and is an
integral part of these financial statements. Non-U.S. operations provided
less than 10% of consolidated revenues and employed less than 10% of
consolidated assets for all periods presented. No customer provided more than
10% of consolidated revenues.
Natural Gas Transmission and Distribution - The Lone Star Gas Company (Lone
Star) division is subject to the accounting requirements prescribed by the
National Association of Regulatory Utility Commissioners. Rates are
established by the Railroad Commission of Texas and by municipal governments.
Lone Star records revenues on the basis of cycle meter readings throughout the
month and accrues revenues for gas delivered from the meter reading dates to
the end of the month. The transmission and distribution system is depreciated
by the straight-line method over approximately 40 years. Gas stored
underground is valued at average cost.
Lone Star has made accruals for payments that may be required for settlement
of gas-purchase contract claims asserted or that are probable of assertion.
Lone Star's rates provide for the recovery of the actual cost of gas,
including out-of-period costs such as gas-purchase contract settlement costs.
Lone Star continually evaluates its position relative to asserted and
unasserted take-or-pay claims, above-market prices or future commitments.
Management believes that the Corporation has not incurred losses for which
reserves should be provided at December 31, 1994.
Natural Gas and Oil Exploration and Production - The full-cost accounting
method prescribed by the Securities and Exchange Commission is followed for
gas and oil properties. Costs directly associated with the acquisition and
evaluation of unproved gas and oil 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. Amortization of evaluated
gas and oil properties is computed on the unit-of-production method using
estimated proved gas and oil reserves quantified on the basis of their
equivalent energy content. Amortization of gas and oil properties was
approximately 5.8% in 1994, 6.0% in 1993 and 5.7% in 1992. At December 31,
1994, estimates of future site restoration, dismantlement and abandonment
costs, as assessed on an overall cost center basis, were less than estimates
of future salvage values. Therefore, no accruals were required.
Gas and oil swaps, collars and futures agreements are used to hedge volatile
product prices for a portion (normally 30 to 70 percent) of anticipated future
gas and oil production. The purpose of these hedging activities is to fix the
prices to be received. Under these agreements, payments are received or made
based on the differential between a fixed and a variable product price. These
agreements are settled in cash at or prior to expiration or exchanged for
physical delivery contracts. Realized gains and losses on hedging activities
are deferred and included in income during the month that the related physical
sale occurs. In the event of nonperformance by counterparties, ENSERCH would
be exposed to price risk. ENSERCH does not obtain collateral to support the
agreements but monitors the financial viability of counterparties. ENSERCH
has no off-balance sheet risk of accounting loss.
ENSERCH's 99.2% ownership of Enserch Exploration Partners, Ltd. (EP) was held
primarily through Enserch Processing Partners Limited (EPPL). On December 30,
1994, Enserch Exploration, Inc. (EEX), a newly organized Texas corporation,
acquired all of the partnership interests of EP Operating Limited Partnership
(EPO), the operating partnership of EP in which EP owned a 99% interest and
other ENSERCH companies owned a 1% interest. EPO was then merged into EEX and
thereafter, EP was liquidated. Following the liquidation of EP, EPPL redeemed
ENSERCH's interest in EPPL in exchange for EEX stock and EPPL's operating
assets. ENSERCH's natural gas and oil exploration and production and natural
gas liquids processing operations are now conducted in corporate form.
2. BORROWINGS AND LINES OF CREDIT
[Download Table]
Senior Long-term Debt at December 31: 1994 1993
-------- --------
8.7% Note due 1994 . . . . . . . . . . . . . . . . . . . . . $ $ 29,316
9.11% Average rate note due 1994 . . . . . . . . . . . . . . 100,000
8% Notes due 1997. . . . . . . . . . . . . . . . . . . . . . 100,000 100,000
Variable rate note due 1998 (Interest based on LIBOR). . . . 150,000
7% Notes due 1999. . . . . . . . . . . . . . . . . . . . . . 150,000 150,000
9.06% Note due 1995 through 1999 . . . . . . . . . . . . . . 76,200 86,800
8 7/8% Notes due 2001 . . . . . . . . . . . . . . . . . . . 100,000 100,000
6 3/8% Notes due 2004. . . . . . . . . . . . . . . . . . . . 150,000
7 1/2% to 8.95% Sinking fund debentures
due 1996 to 2002 . . . . . . . . . . . . . . . . . . . . . 73,717
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,276) (1,006)
-------- --------
Total . . . . . . . . . . . . . . . . . . . . . . . 724,924 638,827
Less current maturities. . . . . . . . . . . . . . . . . . . 10,600 10,600
-------- --------
Noncurrent. . . . . . . . . . . . . . . . . . . . . $714,324 $628,227
======== ========
[Download Table]
1995 1996 1997 1998 1999
---- ---- ---- ---- ----
Maturities $10,600 $13,400 $117,400 $167,400 $167,400
The Convertible Subordinated Debentures have an interest rate of 6 3/8%, are
due 2002 and are convertible into common stock at $26.88 per share (equal to
37.20 shares per $1 thousand principal amount). The Debentures may be
redeemed at 103.19% of the principal amount, plus accrued interest, through
March 31, 1995 and at declining premiums thereafter.
Commercial paper totaled $151 million at December 31, 1994 and $32 million at
year-end 1993. The average year-end interest rate on commercial paper
borrowings was 6.3% in 1994 versus 3.5% in 1993.
Lines of credit are maintained that provide for short- and interim-term
borrowings and also support commercial paper borrowings. The aggregate lines
of credit totaled $600 million at December 31, 1994 and expire in 1997. All
lines are on a fee basis and none require compensating balances or restrict
the use of cash. All lines provide for borrowing at prevailing market rates.
The 1992 extraordinary loss included a $10.4 million ($15.8 million pretax)
charge for the estimated cost to terminate an interest-rate swap agreement and
charges totaling $5.0 million ($7.3 million pretax) for call premiums and
other expenses associated with the early extinguishment of high interest-rate
debt. The swap, which expired in January 1995, hedged the interest rate on
$100 million of variable-rate debt.
[Enlarge/Download Table]
Interest Costs: 1994 1993 1992
---- ---- ----
Interest costs incurred. . . . . . . . . . . . . . . . $ 73,192 $ 81,465(a) $ 99,739
Interest capitalized . . . . . . . . . . . . . . . . . (4,950) (4,461) (5,426)
-------- -------- --------
Interest charged to expense. . . . . . . . . . . . . . $ 68,242 $ 77,004(a) $ 94,313
======== ======== ========
<FN>
(a) Includes interest not related to borrowings of $8.2 million.
[Enlarge/Download Table]
Fair Value of Financial Instruments at December 31: 1994 1993
------------------- ---------------------
Estimated Estimated
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- ---------- -------- ---------
Recoverable gas-purchase contracts (a). . . . . $ 30,264 $ 29,726 $ 47,660 $ 48,864
Senior long-term debt (b) . . . . . . . . . . . 726,200 695,981 639,833 668,878
Convertible debentures (c). . . . . . . . . . . 90,750 77,138 90,750 92,111
<FN>
Estimated fair value: (a) discounted cash flows; (b) variable-rate debt - approximates carrying amount,
exchange traded debt - quoted market prices, and other debt - discounted value using rates for debt with
similar characteristics; (c) quoted market prices.
The fair value of other financial instruments consisting primarily of cash and
equivalents, accounts receivable, investments, commercial paper and other
short-term borrowings, accounts payable and other accrued liabilities and
accrued interest approximates carrying value. The estimated fair value of
senior long-term debt does not reflect prepayment penalties, which would be
incurred upon early extinguishment.
3. SHAREHOLDERS' EQUITY
As of December 31, 1994, 8,071,367 shares of unissued common stock were
reserved for issuance under stock plans and conversion of convertible
subordinated 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.
[Enlarge/Download Table]
December 31, 1994 December 31, 1993
Stated ----------------------- ------------------------
Adjustable Rate Value Shares Shares
Preferred Stock: Per Share Outstanding Amount Outstanding Amount
--------- ----------- ------ ----------- ------
Series D (Redeemed) . . . . . $ 50 $ 1,500,000 $ 75,000
Series E. . . . . . . . . . . 1,000 100,000 $100,000 100,000 100,000
Series F. . . . . . . . . . . 1,000 75,000 75,000
-------- --------
Total. . . . . . . . . . . $175,000 $175,000
======== ========
The Series F stock was sold in April 1994 for net proceeds of $73 million and
is represented by three million depositary shares (stated value $25 per
share). The Series E stock is represented by one million depositary shares
(stated value $100 per share).
The Series F stock is redeemable at $25 per depositary share beginning after
May 1, 1999, and the Series E stock is redeemable at the option of the
Corporation at $100 per depositary share at any time. Holders of the
preferred stock are entitled to its stated value upon involuntary liquidation.
Dividend rates are determined quarterly, in advance, based on the "Applicable
Rate" (highest of the three-month Treasury bill rate, the Treasury ten-year
constant maturity rate and either the Treasury twenty-year or thirty-year
constant maturity rate, as defined), as set forth below:
[Enlarge/Download Table]
Per Annum Rate (Determined Quarterly)
--------------------------------------------------------------------
Series D Series E Series F
------------- ------------ -------------
Dividend rate 0.10% below 1.20% below 87% of
Applicable Rate Applicable Rate Applicable Rate
Minimum rate 7.50% 7.00% 4.50%
Maximum rate 15.50% 13.00% 10.50%
[Download Table]
Dividends declared: 1994 1993 1992
---- ---- ----
Adjustable Rate Preferred Stock:
Series D ($.42, $3.77, $3.93 per share) $ 625 $ 5,653 $ 5,897
Series E ($7.00, $7.00, $7.01 per depositary share) 7,000 7,000 7,013
Series F ($1.32 per depositary share) 3,955
Common Stock ($.20, $.20, $.80 per share) 13,372 13,286 52,611
------- ------- -------
Total $24,952 $25,939 $65,521
======= ======= =======
Dividends - Restrictions on the payment of dividends on common stock (other
than stock dividends) or acquisitions of capital stock are contained in a loan
agreement relating to senior long-term debt and in the Restated Articles of
Incorporation. At December 31, 1994, the amount of dividends on common stock
that could be paid under the most restrictive of these agreements was
$423 million.
Shareholder Rights Plan - The outstanding shares of common stock include one
voting preference stock contingent purchase right, which is exercisable only
under specific conditions. 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 or will entitle its holder to
purchase, at a specified 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. The
rights have no voting privileges, expire on May 5, 1996 and are generally
redeemable at $.05 per right until the 15th day following public announcement
that a 20% position has been acquired.
Stock Options - Stock options have been awarded to key employees and are
outstanding under three plans. Options for 9,055 shares granted under a
former plan have an exercise option price equal to par value ($4.45). Options
granted under the other plans have an exercise price of not less than the fair
market value of the common stock on its grant date. At December 31, 1994,
there were 126 participants in the stock option plans. Options become
exercisable over four years and generally expire ten years after the date of
the grant.
[Enlarge/Download Table]
1994 Number of Options
Summary of stock option activity: Price ----------------------------------------
Range 1994 1993 1992
--------------------------------------------------------
Outstanding - Beginning
of year. . . . . . . . . . . . . . $ 4.45-$25.63 2,388,970 2,327,410 2,019,069
Granted. . . . . . . . . . . . . . . $18.25 144,700 257,000 342,600
Exercised (a). . . . . . . . . . . . $ 4.45-$12.50 (32,347) (115,270)
Canceled or expired. . . . . . . . . $12.50-$25.63 (192,500) (80,170) (34,259)
--------- --------- ---------
Outstanding - End of year. . . . . . $ 4.45-$25.63 2,308,823 2,388,970 2,327,410
========= ========= =========
Exercisable. . . . . . . . . . . . . $12.50-$25.63 1,838,175 1,737,127 1,294,973
========= ========= =========
<FN>
(a) Price ranges for options exercised in 1993 were $12.50 to $21.00 per share. No options were exercised
in 1992.
The current stock option plan was amended in February 1994 to include
provisions for granting restricted stock. At December 31, 1994, a total of
74,700 shares of performance-based restricted stock had been issued to certain
executive officers and were outstanding. Performance criteria for lifting the
restrictions is related to three-year total shareholder return compared with
the weighted average of a peer group of companies.
4. COMMITMENTS AND CONTINGENT LIABILITIES
Legal Proceedings - A lawsuit was filed on February 24, 1987, in the 112th
Judicial District of Sutton County, Texas, against subsidiaries and affiliates
of the Corporation and its utility division. The plaintiffs have claimed that
defendants failed to make certain production and minimum-purchase payments
under a gas-purchase contract. 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. Plaintiffs seek actual damages in excess of $5 million and
punitive damages in an amount equal to 0.5% of the consolidated gross revenues
of the Corporation for the years 1982-1986 (approximately $85 million),
interest, costs and attorneys' fees.
Management of the Corporation believes it has meritorious defenses to the
claims made in this and other actions brought in the ordinary course of
business. In the opinion of management, the Corporation will incur no
liability from this and all other pending claims and suits that is material
for financial reporting purposes.
Environmental Matters - The Corporation is subject to federal, state and local
environmental laws and regulations that 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 until the regulations that
implement the applicable laws have been approved and adopted. However, the
capital expenditures required to achieve compliances with the Clean Air Act
regulations, in their current form, have been estimated to range from $5 to
$20 million, with expenditures to be made over a two-to three-year period.
It is management's opinion that all such costs, when finally determined, will
not have a material adverse effect on the consolidated financial position or
results of operations of the Corporation.
Commitments - Future minimum commitments are as follows (in millions):
[Download Table]
1995 1996 1997 1998 1999 Thereafter
---- ---- ---- ---- ---- ----------
Operating leases . . . . . . . . . . $24.0 $24.0 $12.1 $ 7.4 $5.8 $70.9
Capital leases . . . . . . . . . . . 4.2 4.0 3.9 3.7 1.7 23.3
Gas-purchase contracts . . . . . . . 170.0 110.0 110.0 80.0 30.0 10.0
Lease Commitments - In 1992, the Corporation entered into operating lease
arrangements to provide financing for its portion of the offshore platforms
and related facilities for the Mississippi Canyon Block 441 (MC 441)(37.5%
owned) and Garden Banks Block 388 (GB 388) (100% owned) projects. The leases
contain fixed-priced purchase options and, if terminated, require a guaranteed
residual payment.
A total of $34 million was required for the MC 441 project. The lease was
modified in the second quarter of 1994 with terms that resulted in capital
lease accounting treatment, a noncash investing and financing transaction.
The noncurrent portion of the lease obligation of $28 million is included in
other noncurrent liabilities.
Under the GB 388 lease arrangement, the lessor will fund the construction cost
of the facilities quarterly, up to a maximum of $235 million, all of which had
been advanced under the lease at December 31, 1994. The facilities will be
leased for an initial period through March 31, 1997. The lease may be
extended for up to three successive two-year periods on such terms as the
Corporation and lessor may agree. The Corporation is constructing the leased
property and has guaranteed completion of construction. The Corporation has
the option to purchase the facilities throughout the lease period and has
guaranteed an estimated residual value for the facilities of approximately
$188 million should the lease terminate. Lease payments are deferred during
construction and will be amortized when production begins.
The cost of the Garden Banks facilities is expected to be $330 million, which
includes design modifications and other costs for Block 388 facilities and for
the recent discovery on Block 387. Financing options for the additional costs
currently are being evaluated, including an addition to the current operating
lease arrangement.
The Corporation had a number of other noncancelable long-term operating leases
at December 31, 1994, principally for office space and machinery and
equipment. Rental expenses incurred under all operating leases aggregated
$7.9 million in 1994, $10.8 million in 1993 and $14.2 million in 1992. Rental
income received for subleased office space was $3.6 million in 1994,
$3.4 million in 1993 and $4.7 million in 1992. Future minimum rental income
to be received for subleased office space is $7.7 million over the next five
years.
Gas-Purchase Contracts - Lone Star buys gas under long-term, intrastate
contracts in order to assure reliable supply to its customers. Many of these
contracts require minimum purchases ("take-or-pay") of gas. Based on Lone
Star's estimated gas demand, which assumes normal weather conditions,
requisite gas purchases are expected to substantially satisfy purchase
obligations for the year 1995 and thereafter.
Gas Marketing - Enserch Gas Company (EGC) enters into contracts to purchase
and sell natural gas for physical delivery in the future. At December 31,
1994, EGC had a net commitment to purchase natural gas through January 1996,
for which a $4 million charge was recorded to reflect lower year-end market
prices.
Sales of Receivables - The Corporation has an agreement until 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. In a separate agreement, a limited recourse sale of
receivables retained from the sale of Ebasco occurred. As of December 31,
1994 and 1993, the uncollected balances of receivables sold were $133 million
and $200 million, respectively.
Guarantees - The Corporation and/or its subsidiaries are the guarantor on
various commitments and obligations of others aggregating some $111 million
at December 31, 1994. The Corporation is exposed to loss in the event of
nonperformance by other parties. However, the Corporation does not anticipate
nonperformance by the counterparties.
Concentrations of Credit Risk - Natural Gas Transmission and Distribution
operations have trade receivables from a few large industrial customers in
North Central Texas arising from the sale of natural gas. A change in
economic conditions may affect the ability of customers to meet their
contractual obligations. At December 31, 1994 and 1993, the allowance for
possible losses deducted from accounts receivable was $4,686 and $4,753,
respectively. The Corporation believes that its provision for possible losses
on uncollectible accounts receivable is adequate for its credit loss exposure.
5. EMPLOYEE BENEFIT PLANS
Pension Plan - A defined benefit pension plan provides retirement income
benefits for substantially all employees. Accrued retirement costs are funded
to the extent such amounts are deductible for federal income tax purposes.
Plan assets include equity and fixed-income securities and cash. Benefits are
based on years of credited service and average compensation.
[Download Table]
Components of net pension expense (in millions): 1994 1993 1992
----- ----- -----
Service cost - benefits earned during the period . . $ 4.8 $12.5 $13.3
Interest cost on projected benefit obligation. . . . 8.1 19.5 18.4
Actual return on assets. . . . . . . . . . . . . . . (3.9) (28.0) (22.7)
Net amortization and deferral. . . . . . . . . . . . (2.3) 3.9 1.0
----- ----- -----
Net periodic pension expense . . . . . . . . . . . . $ 6.7 $ 7.9 $10.0
===== ===== =====
Valuation Assumptions:
Discount rate. . . . . . . . . . . . . . . . . . . . 9.0% 7.25% 8.5%
Rate of increase in compensation levels. . . . . . . 4.0% 4.0% 4.0%
Expected long-term rate of return on assets. . . . . 9.5% 9.5% 10.0%
[Download Table]
Amounts Recognized (in millions):
Actuarial present value of pension benefit obligation:
Vested benefit obligation. . . . . . . . . . . . . $(237.4) $(268.5)
======= =======
Accumulated benefit obligation . . . . . . . . . . $(249.6) $(277.3)
======= =======
Projected pension benefit obligation . . . . . . . $(271.4) $(311.7)
Plan assets at fair value. . . . . . . . . . . . . . 231.7 243.2
------- -------
Projected benefit obligation in excess of plan assets (39.7) (68.5)
Unrecognized net asset at transition . . . . . . . . (8.0) (9.7)
Unrecognized prior service cost (credit) . . . . . . (2.2) 1.7
Unrecognized net actuarial (gain) loss . . . . . . . (3.7) 26.3
------- -------
Accrued pension cost . . . . . . . . . . . . . . . . $ (53.6) $ (50.2)
======= =======
ENSERCH retained the pension obligations to former Ebasco and Enserch
Environmental employees, and no further benefits will accrue, thus the decline
in service cost in 1994. Plan curtailment gains of $2.2 million in 1994 and
$6.9 million in 1993 were recognized in discontinued operations. During 1994,
the Ebasco pension plan was merged with the ENSERCH plan.
Investment Plan - A voluntary contributory investment plan is available to
substantially all employees. The Corporation matches a portion of employees'
contributions with ENSERCH common stock. Costs under the plans were
$1.9 million, $3.5 million and $3.5 million in 1994, 1993 and 1992,
respectively.
Postretirement Benefits Other than Pensions - Some retirees, including those
of Ebasco, and their dependents receive postretirement medical benefits that
vary in level based on their years of service and retirement date. Employees
hired after July 1, 1989 are not eligible for medical benefits when they
retire. Obligations are not prefunded.
[Enlarge/Download Table]
Components of net periodic postretirement benefit cost (in millions): 1994 1993
------- -------
Service cost - benefits earned during the period . . . . . . . $ .4 $ .4
Interest cost on projected benefit obligation. . . . . . . . . 5.5 5.6
Net amortization and deferral. . . . . . . . . . . . . . . . . 4.3 4.0
------- -------
Net periodic postretirement benefit cost . . . . . . . . . . . $ 10.2 $ 10.0
======= =======
Valuation Assumptions:
Discount rate. . . . . . . . . . . . . . . . . . . . . . . . . 9.0% 7.25%
Medical cost trend rate. . . . . . . . . . . . . . . . . . . . 12.0% 12.0%
Amounts Recognized (in millions):
Accumulated postretirement benefit obligations:
Retirees and dependents. . . . . . . . . . . . . . . . . . . . $ (75.2) $ (72.9)
Fully eligible active plan participants. . . . . . . . . . . . (1.0) (1.6)
Other active plan participants . . . . . . . . . . . . . . . . (6.7) (8.4)
------- -------
Accumulated postretirement benefit obligation. . . . . . . . (82.9) (82.9)
Unrecognized obligation at transition. . . . . . . . . . . . . 62.1 66.2
Unrecognized net actuarial loss. . . . . . . . . . . . . . . . 15.1 14.8
------- -------
Accrued postretirement benefit cost. . . . . . . . . . . . . . $ (5.7) $ (1.9)
======= =======
The assumed health care cost trend rate is 12.0% for 1994, declining gradually
to 6.0% in 2003, and remaining at that level thereafter. If the health care
cost trend rate were increased by 1%, the accumulated postretirement benefit
obligation as of December 31, 1994 would be increased by $4.8 million and the
net periodic postretirement benefit cost for 1994 by $.4 million.
Prior to 1993, benefit costs were expensed as paid and amounted to
$7.5 million for 1992.
6. INCOME TAXES
[Download Table]
Provision (benefit) for income taxes
on continuing operations: 1994 1993 1992
---- ---- ----
Current
Federal. . . . . . . . . . . . . . . . . . $(10,417) $ 7,239 $ 6,533
State. . . . . . . . . . . . . . . . . . . 560 463 197
Foreign. . . . . . . . . . . . . . . . . . 50 (444) 450
------- ------- -------
Total. . . . . . . . . . . . . . . . . . (9,807) 7,258 7,180
------- ------- -------
Deferred
Federal. . . . . . . . . . . . . . . . . . (59,167) (1,230) (9,682)
State. . . . . . . . . . . . . . . . . . . 455
------- ------- -------
Total. . . . . . . . . . . . . . . . . . (59,167) (775) (9,682)
------- ------- -------
Total . . . . . . . . . . . . . . . . $(68,974) $ 6,483 $(2,502)
======= ======= =======
[Enlarge/Download Table]
Reconciliation of income taxes (benefit) computed at the federal statutory rate and income-tax expense
(benefit) of continuing operations:
1994 1993 1992
---- ---- ----
Income (loss) from continuing
operations before income taxes:
Domestic . . . . . . . . . . . . . . . . . . $ 15,995 $ 8,771 $ 6,768
Foreign. . . . . . . . . . . . . . . . . . . (3,294) (18,469) (8,107)
-------- -------- --------
Total. . . . . . . . . . . . . . . . . . . 12,701 (9,698) (1,339)
Federal statutory rate . . . . . . . . . . . . 35% 35% 34%
-------- -------- --------
Income taxes (benefit) computed at
the federal statutory rate . . . . . . . . 4,445 (3,394) (455)
Impact of 1% increase in
federal statutory rate . . . . . . . . . . 10,810
Change in tax status . . . . . . . . . . . . . (70,000)
State and foreign taxes. . . . . . . . . . . . 397 467 427
Other - net. . . . . . . . . . . . . . . . . . (3,816) (1,400) (2,474)
-------- -------- --------
Total income-tax
expense (benefit). . . . . . . . . . . . $(68,974) $ 6,483 $(2,502)
======== ======== ========
At the completion of the conversion of EP and EPPL to corporate form, the tax
basis of certain properties of ENSERCH and subsidiary companies receiving EEX
stock in the conversion exceeded the financial basis of such properties.
Also, the financial basis of ENSERCH and subsidiary companies in EEX exceeds
their tax basis in the EEX stock. ENSERCH expects to ultimately recover the
excess financial basis tax free. As a result of the conversion and related
change in tax status, deferred income taxes applicable to the difference
between the financial and tax basis of ENSERCH and subsidiary companies'
investment in the partnerships were reduced by $70 million.
Deferred income taxes provided by the liability method for significant
temporary differences based on tax laws and statutory rates in effect at the
December 31, 1994 and 1993 balance sheet dates are as follows:
[Enlarge/Download Table]
1994 1993
---------------------------------- -------------------------------
Total Current Noncurrent Total Current Noncurrent
---------- ---------- ---------- ------- --------- ----------
Deferred tax assets:
Loss carryforwards . . . . . . $ 71,856 $ 891 $ 70,965 $ 56,405 $ 26,326 $ 30,079
Investment and other tax-
credit carryforwards . . . . 26,726 26,726 36,835 36,835
Accrued pension costs. . . . . 16,491 16,491 17,406 17,406
Reserves for injury and damage
claims . . . . . . . . . . . 8,163 2,800 5,363 17,351 3,710 13,641
All other. . . . . . . . . . . 59,429 29,123 30,306 53,645 13,516 40,129
-------- -------- -------- ------- -------- --------
Total. . . . . . . . . . . . 182,665 32,814 149,851 181,642 43,552 138,090
-------- -------- -------- ------- -------- --------
Deferred tax liabilities:
Property-related
differences. . . . . . . . . 151,452 151,452 182,892 182,892
Exploration and intangible
development costs. . . . . . . 218,289 218,289 248,027 248,027
Deferred gas-purchase contract
settlements . . . . . . . . . . 10,145 8,398 1,747 17,832 14,999 2,833
All other. . . . . . . . . . . . 58,414 58,414 25,904 202 25,702
-------- -------- -------- -------- -------- --------
Total. . . . . . . . . . . . 438,300 8,398 429,902 474,655 15,201 459,454
-------- -------- -------- -------- -------- --------
Net deferred tax liability (asset)$255,635 $(24,416)(a) $280,051 $293,013 $(28,351)(a) $321,364
======== ======== ======= ======== ======== ========
<FN>
(a) Included in other current assets in the balance sheet.
At December 31, 1994, domestic net operating-loss carryforwards total
$205 million, which begin to expire in 2003, and tax-credit carryforwards
total $27 million, which begin to expire in 1999. The tax benefits of these
carryforwards of $99 million, as shown above, are available to reduce future
income-tax payments.
[Download Table]
Cash payments (refunds) of income taxes: 1994 1993 1992
---- ---- ----
Federal:
Alternative minimum tax. . . . . . . . . . . $(1,279) $15,400 $ 6,514
Refund of prior year tax payments. . . . . . (2,462)
------- ------- -------
Total. . . . . . . . . . . . . . . . . . . . (1,279) 15,400 4,052
State. . . . . . . . . . . . . . . . . . . . . 6,743 4,193 1,427
Foreign. . . . . . . . . . . . . . . . . . . . 850 608
------- ------- -------
Total. . . . . . . . . . . . . . . . . . . . $ 5,464 $20,443 $ 6,087
======= ======= =======
7. DISCONTINUED OPERATIONS
In October 1994, the Corporation sold Enserch Environmental Corporation, which
conducted the former environmental businesses of Ebasco, for $98 million. The
principal operating assets of Ebasco were sold in December 1993 for net
proceeds of $191 million. Also in December 1993, Dorsch Consult was sold for
$9.3 million, including the assumption of debt. In 1992, the business of H&G
Engineering was sold. Discontinued operations are summarized as follows:
[Enlarge/Download Table]
Operating information 1994 1993 1992
---- ---- ----
Revenues . . . . . . . . . . . . . . . . . . . . . . $ 72,081 $ 1,416,450 $1,256,443
Cost and expenses. . . . . . . . . . . . . . . . . . 68,246 1,391,002 1,231,980
---------- ---------- ----------
Operating income . . . . . . . . . . . . . . . . . . 3,835 25,448 24,463
Other income (expense) - net . . . . . . . . . . . . (583) (14,378)
Interest expense . . . . . . . . . . . . . . . . . . (1,241) (12,488) (15,452)
Income taxes . . . . . . . . . . . . . . . . . . . . (1,225) (5,373) (1,368)
---------- ---------- ----------
Income (loss) from operations. . . . . . . . . . . . 1,369 7,004 (6,735)
Gain (loss) on sale, net of income-tax provision
of $15,750 in 1994 and benefits of $6,725
in 1993 and $1,713 in 1992 . . . . . . . . . . . . 29,250 68,414 (7,076)
Provision for additional costs and
expenses for the wind-up of discontinued
businesses, net of tax benefit of $7,523 . . . . . (9,977)
---------- ---------- ----------
Total . . . . . . . . . . . . . . . . . . . . . $ 20,642 $ 75,418 $ (13,811)
========== ========== ==========
The tax effect of the 1993 gain on sale differs from tax at the statutory rate
because of permanent differences in financial and tax basis of the assets
sold. The determination of the gain on the sale of the principal operating
assets of Ebasco in 1993 involved significant estimates, including the final
purchase price, realization of the estimated value of retained assets and
related income-tax matters. In 1994, a loss provision of $17.5 million pretax
($10.0 million after-tax) was recorded in recognition that costs and expenses
incurred for the wind-up of discontinued businesses would be greater than
previously estimated. At December 31, 1994, the retained assets of
discontinued businesses consisted principally of billed and unbilled accounts
receivable and retainages (net of valuation allowances) of $36 million and
liabilities of $48 million.
8. SUPPLEMENTARY GAS AND OIL INFORMATION
Gas and Oil Producing Activities - The following tables set forth information
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.
[Download Table]
Capitalized costs (in millions): 1994 1993
-------- --------
Proved gas and oil properties. . . . . . . . . . . $1,946.5 $1,851.6
Unproved gas and oil properties. . . . . . . . . . 108.2 84.4
-------- --------
Total . . . . . . . . . . . . . . . . . . . $2,054.7 $1,936.0
======== ========
Accumulated depreciation and
amortization . . . . . . . . . . . . . . . . . . $ 836.3 $ 792.4
======== ========
[Enlarge/Download Table]
Costs incurred (in millions): 1994 1993 1992
------------------ ---------------- ------------------
Non- Non- Non-
U.S. U.S. U.S. U.S. U.S. U.S.
----- ---- ---- ---- ---- ----
Property acquisition costs:
Proved . . . . . . . . . . . . $ 1.6 $ $ 8.3 $ $ .9 $
Unproved . . . . . . . . . . . 20.6 12.6 .8 9.1 (.1)
Exploration costs. . . . . . . . 58.7 3.3 36.8 4.9 35.4 2.7
Development costs. . . . . . . . 84.2 63.0 16.6
------ ------ ------ ------ ------ ------
Total. . . . . . . . . . . . . $165.1 $ 3.3 $120.7 $ 5.7 $ 62.0 $ 2.6
====== ====== ====== ====== ====== ======
Amortization
(Per MMBtu)(a) . . . . . . . . $ 1.04 $ .98 $ .98
<FN>
(a) Amortization expense per unit of production converted to a common unit of measure, millions of British thermal
units (MMBtu).
Costs excluded from the amortizable base as of December 31, 1994(in millions):
[Download Table]
Total at
Prior December 31,
Year Incurred 1994 1993 1992 Years 1994
---- ---- ---- ----- ------------
Property acquisition costs. . . . . $20.6 $11.4 $ 4.2 $10.5 $ 46.7
Exploration costs . . . . . . . . . 19.3 3.8 6.8 9.0 38.9
Development costs . . . . . . . . . 9.9 9.9
Interest capitalized. . . . . . . . 4.5 3.4 3.0 1.8 12.7
----- ----- ----- ----- ------
Total . . . . . . . . . . . . . $54.3 $18.6 $14.0 $21.3 $108.2
===== ===== ===== ===== ======
Approximately 41% of the excluded costs relates to offshore activities in the
Gulf of Mexico, about 57% is domestic onshore exploration activities and the
remainder is non-U.S. The anticipated timing of the inclusion of these costs
in the amortization computation will be determined by the rate at which
exploratory and development activities continue, which are expected to be
accomplished within ten years.
The following information is required and defined by the Financial Accounting
Standards Board. The disclosure does not represent the results of operations
based on historical financial statements. In addition to requiring different
determinations of revenues and costs, the disclosure excludes the impact of
interest expense and corporate overheads.
[Enlarge/Download Table]
1994 1993 1992
-------------- --------------- ---------------
Results of Operations Non- Non- Non-
(in millions): U.S. U.S. U.S. U.S. U.S. U.S.
----- ---- ----- ------ ---- ----
Revenues:
Affiliated. . . . . . . . $110.0 $ $110.0 $ $ 32.8 $
Nonaffiliated . . . . . . 63.5 81.0 137.5
Less:
Production costs . . . . . 45.6 48.5 46.3 .1
Exploration costs(a) . . . 7.0 1.0 6.3 1.6 8.2 1.8
Depreciation and
amortization (b) . . . . 85.6 86.0 13.3 82.0 .4
Income-tax effects . . . . 12.3 (.3) 17.5 (5.2) 11.3 (.8)
------ ------ ----- ----- ------ -----
Net producing
activities . . . . . . . . $ 23.0 $ (.7) $ 32.7 $(9.7) $ 22.5 $(1.5)
====== ====== ===== ===== ====== =====
<FN>
(a) Includes internal costs that cannot be directly identified with acquisition, exploration or development
activities.
(b) Excludes a $7.6 million gain from the sale of an inactive offshore pipeline and facilities in 1994 and the
$16.5 million write-down of that pipeline and facilities in 1992. The pipeline and facilities were not
related to gas and oil producing activities. Amounts for 1993 and 1992 include write-off of costs related
to unsuccessful non-U.S. exploratory projects of $13.3 million and $.4 million, respectively.
Hedging Activities - At December 31, 1994, ENSERCH had outstanding swaps,
collars and futures agreements extending through December 31, 1995 to exchange
payments on 17.8 Bcf of natural gas and 1.2 MMBbls of oil on which ENSERCH had
$4.1 million of net unrealized gains based on the difference between the
strike price and the NYMEX futures price for the applicable trading month.
At December 31, 1994, realized gains on hedging activities of $.9 million were
deferred. The weighted average strike price and market price per Mcf of
natural gas was $2.06 and $1.84, respectively, and the weighted average strike
price and market price per barrel of oil was $17.98 and $17.82, respectively.
Gas and Oil Reserves (Unaudited) - The following table of estimated proved and
proved developed reserves of gas and oil has been prepared utilizing estimates
of year-end 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 become available.
[Enlarge/Download Table]
United States
----------------------------------------------------------
Gas (MMcf) Oil (MBbl)(a)
---------------------------------- -------------------------
1994 1993 1992 1994 1993 1992
--------- --------- --------- ------ ------ ------
At January 1 . . . . . . . . . . . . . 1,086,482 1,101,426 1,168,075 39,349 39,231 40,012
Changes in reserves
Revisions of previous estimates . . (25,106) 20,196 (6,811) (499) 1,344 552
Extension, discoveries
and additions. . . . . . . . . . 47,580 34,549 20,817 9,877 1,292 1,444
Purchase of minerals in place . . . 787 4,379 198 14 3 102
Sales of minerals in place. . . . . (894) (4,042) (15,665) (28) (40) (42)
Production. . . . . . . . . . . . . (67,113) (70,026) (65,188) (2,227) (2,481) (2,837)
--------- --------- --------- ------ ------ ------
At December 31 . . . . . . . . . . . . 1,041,736 1,086,482 1,101,426 46,486 39,349 39,231
========= ========= ========= ====== ====== ======
Proved Developed Reserves:
At January 1. . . . . . . . . . . . 735,093 676,851 974,822 15,380 14,844 19,738
At December 31. . . . . . . . . . . 698,643 735,093 676,851 14,437 15,380 14,844
--------------
<FN>
(a) Includes condensate and natural gas liquids attributable to leasehold interests of 911 MBbl for 1994,
1,117 MBbl for 1993, and 985 MBbl for 1992.
In 1994, foreign (non-U.S.) extensions, discoveries and additions resulted in
4,105 MBbl of oil at December 31, 1994.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved
Gas and Oil Reserve Quantities (Unaudited) - has been prepared using estimated
future production rates and associated production and development costs.
Continuation of economic conditions 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: Gas (per Mcf) $2.29 in 1994, $2.38 in 1993 and $2.20 in 1992; Oil (per
barrel) $14.07 in 1994, $11.73 in 1993 and $16.89 in 1992.
Because reserve estimates are imprecise and changes in the other variables are
unpredictable, the standardized measure should be interpreted as indicative
of the order of magnitude only and not as precise amounts.
[Enlarge/Download Table]
Standardized Measure (in millions): 1994 1993 1992
-------- -------- --------
Future cash inflows. . . . . . . . . . . . . . . . . . $3,101.1 $3,047.0 $3,080.0
Future production and development costs. . . . . . . . 1,218.5 1,057.9 1,057.2
-------- -------- --------
Future net cash flows. . . . . . . . . . . . . . . . . 1,882.6 1,989.1 2,022.8
Less 10% annual discount . . . . . . . . . . . . . . . 788.5 886.5 910.2
-------- -------- --------
Discounted future net cash flows before income tax . . 1,094.1 1,102.6 1,112.6
Future income-tax expense. . . . . . . . . . . . . . . (499.3) (528.0) (556.5)
Plus 10% annual discount on income taxes . . . . . . . 232.4 256.0 263.6
-------- -------- --------
Standardized measure of discounted future net
cash flows . . . . . . . . . . . . . . . . . . . . $ 827.2 $ 830.6 $ 819.7
======== ======== ========
[Download Table]
Change in Standardized Measure (in millions):
Sales and transfers of gas and oil produced, net of
production costs. . . . . . . . . . . . . . . . . . . $(120.8) $(136.2) $(115.8)
Changes in prices, net of production and future
development costs.. . . . . . . . . . . . . . . . . . (15.6) (.5) 21.8
Extensions, discoveries and improved recovery,
less related costs. . . . . . . . . . . . . . . . . . 121.3 41.4 22.3
Other purchases of minerals in place. . . . . . . . . . 1.6 9.4 .9
Revisions of previous quantity estimates. . . . . . . . (87.1) (28.5) 17.3
Sale of minerals in place.. . . . . . . . . . . . . . . (1.3) (4.9)
Accretion of discount . . . . . . . . . . . . . . . . . 102.7 105.4 102.8
Net change in income taxes. . . . . . . . . . . . . . . 5.1 20.9 (40.2)
Other . . . . . . . . . . . . . . . . . . . . . . . . . (9.3) (1.0) 3.3
------- ------- -------
Total. . . . . . . . . . . . . . . . . . . . . . . . . $(3.4) $ 10.9 $ 7.5
======= ======= =======
[Enlarge/Download Table]
SUMMARY OF BUSINESS SEGMENTS
ENSERCH Corporation and Subsidiary Companies
Natural Gas
Natural Gas and Oil
Transmission Exploration Natural Gas General
and and Liquids and
Distribution Production Processing Power Other Consolidated
------------ ---------- ----------- ------- ------- ------------
(In thousands)
Revenues from Nonaffiliates
1994 . . . . . . . . . . . . . . . $1,669,941 $ 68,949 $73,042 $ 45,499 $ $1,857,431
1993 . . . . . . . . . . . . . . . 1,528,435 79,780 76,351 48,635 1,733,201
1992 . . . . . . . . . . . . . . . 1,302,922 138,708 81,654 45,728 1,569,012
Intersegment Revenues from
Affiliates (eliminated
in consolidation)
1994 . . . . . . . . . . . . . . . 19,083 110,191 14,404 143,678
1993 . . . . . . . . . . . . . . . 19,484 110,016 9,434 138,934
1992 . . . . . . . . . . . . . . . 15,336 32,836 5,312 53,484
Operating Income (Loss)
1994 . . . . . . . . . . . . . . . 63,178 25,617 1,007 5,761 (8,114) 87,449
1993 . . . . . . . . . . . . . . . 101,458 (37,293) 5,037 9,795 (11,865) 67,132
1992 . . . . . . . . . . . . . . . 101,996 (6,175) 13,092 13,379 (16,846) 105,446
Depreciation and Amortization
1994 . . . . . . . . . . . . . . . 40,373 79,594 4,744 1,403 619 126,733
1993 . . . . . . . . . . . . . . . 37,484 100,687 4,003 1,470 598 144,242
1992 . . . . . . . . . . . . . . . 35,711 100,167 3,805 1,578 1,122 142,383
Identifiable Assets
1994 . . . . . . . . . . . . . . . 1,326,322 1,295,231 34,112 41,794 148,840(a) 2,846,299
1993 . . . . . . . . . . . . . . . 1,313,722 1,193,525 26,123 32,632 194,259(a) 2,760,261
1992 . . . . . . . . . . . . . . . 1,333,171 1,167,349 24,761 14,706 603,693(a) 3,145,680
Gross Additions to Property,
Plant and Equipment
1994 . . . . . . . . . . . . . . . 116,599 133,254 9,042 622 493 260,010
1993 . . . . . . . . . . . . . . . 91,923 119,566 5,779 373 970 218,611
1992 . . . . . . . . . . . . . . . 75,795 65,787 1,228 432 1,076 144,318
<FN>
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 with those received from nonaffiliated customers for
similar products or services.
(a) Includes $62,622 in 1994, $102,291 in 1993 and $463,136 in 1992 related to discontinued operations.
Quarterly Results (Unaudited) - The results of operations by quarters are
summarized below and have been restated for the discontinuance of the
environmental business. 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.
[Enlarge/Download Table]
Quarter Ended
-----------------------------------------------------------
March 31 June 30 September 30 December 31
----------- ---------- ------------ -----------
1994:
Revenues. . . . . . . . . . . . . . . . . . . . . . . $565,702 $350,149 $439,726 $501,854
Operating Income (Loss) . . . . . . . . . . . . . . . 70,909 (775) (4,135) 21,450(a)
Income (Loss) from Continuing Operations. . . . . . . 35,364 (11,971) (14,966) 73,248(a)(b)
Income from Discontinued Operations . . . . . . . . . 562 743 399 18,938
Net Income (Loss) . . . . . . . . . . . . . . . . . . 35,926 (11,228) (14,567) 92,186
Earnings (Loss) Applicable to Common Stock. . . . . . 33,082 (14,000) (17,547) 89,163
Per Share of Common Stock:
Income (loss) from continuing operations after
provision for dividends on preferred stock . . . . $ .49 $ (.22) $ (.27) $ 1.05
Discontinued operations. . . . . . . . . . . . . . . .01 .01 .01 .28
-------- -------- -------- --------
Earnings (loss) applicable to
common stock. . . . . . . . . . . . . . . . . . . . $ .50 $ (.21) $ (.26) $ 1.33
======== ======== ======== ========
1993:
Revenues. . . . . . . . . . . . . . . . . . . . . . . $552,512 $353,190 $331,101 $496,398
Operating Income (Loss) . . . . . . . . . . . . . . . 78,461 25,556 188 (37,073)(d)(e)
Income (Loss) from Continuing Operations. . . . . . . 37,989 5,067 (27,688)(c) (31,549)(d)(e)
Income (Loss) from Discontinued Operations. . . . . . 221 (12) 4,874 70,335
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) $ (.52)
Discontinued operations. . . . . . . . . . . . . . . .07 1.05
-------- -------- -------- --------
Earnings (loss) applicable to
common stock. . . . . . . . . . . . . . . . . . . . $ .53 $ .03 $ (.39) $ .53
======== ======== ======== ========
<FN>
(a) Includes a $4.9 million gain from the sale of an inactive offshore pipeline and facilities ($7.6 million pretax).
(b) Includes a $70 million reduction of deferred income taxes as a result of the conversion of partnerships to corporate
form and resulting change in tax status.
(c) Includes a $10.8 million charge from the 1% increase in the statutory federal income-tax rate on corporations.
(d) Includes a $7.8 million charge principally for severance expenses associated with re-engineering Lone Star Gas Company's
distribution operations ($12.0 million pretax).
(e) Includes a $26.9 million charge as a result of an adverse judgment in litigation ($41.4 million pretax) and a $6.7
million write-off of non-U.S. gas and oil assets ($10.3 million pretax).
Reconciliation of Previously Reported Quarterly Information
[Enlarge/Download Table]
Quarterly amounts previously reported for 1993 and the first two quarters of 1994 have
been decreased to give effect to the sale of the environmental business as follows:
Quarter Ended
----------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
1994:
Revenues. . . . . . . . . . . . . . . . . . . . . $(40,015) $(45,742)
Operating Income (Loss) . . . . . . . . . . . . . (1,933) (856)
Income (Loss) from Continuing Operations. . . . . (562) (743)
1993:
Revenues. . . . . . . . . . . . . . . . . . . . . $(41,037) $(41,037) $(41,039) $(45,811)
Operating Income (Loss) . . . . . . . . . . . . . (1,266) (1,275) (1,268) (1,871)
Income (Loss) from Continuing Operations. . . . . (287) (286) (325) (571)
COMMON STOCK MARKET PRICES AND DIVIDEND INFORMATION
MARKET PRICES - ENSERCH COMMON STOCK
The Corporation's common stock is traded principally 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.
[Enlarge/Download Table]
1994 1993 1992
------------------- ------------------- --------------------
High Low High Low High Low
------------------- ------------------- --------------------
First Quarter . . . . . $19 1/8 $12 7/8 $19 1/8 $14 1/8 $14 3/8 $10 3/8
Second Quarter. . . . . 15 1/4 12 5/8 19 5/8 16 7/8 16 3/8 12 1/8
Third Quarter . . . . . 16 1/2 13 1/8 22 5/8 17 1/2 16 1/8 14
Fourth Quarter. . . . . 15 12 1/8 21 1/4 15 1/2 16 1/2 13 3/4
1991 1990 1989
------------------- ------------------- --------------------
High Low High Low High Low
------------------- ------------------- --------------------
First Quarter . . . . . $20 1/2 $16 7/8 $28 $23 3/8 $22 1/8 $18 5/8
Second Quarter. . . . . 21 3/8 17 1/8 27 7/8 23 24 7/8 19 1/4
Third Quarter . . . . . 18 3/4 15 5/8 28 1/8 24 26 1/4 22 7/8
Fourth Quarter. . . . . 17 1/2 12 3/4 27 5/8 18 1/2 27 1/2 20 7/8
[Download Table]
COMMON STOCK DATA AT YEAR END 1994 1993 1992 1991 1990 1989
----- ------ ------ ------ ------ ------
Shareholders of Record 19,614 20,406 22,832 23,979 25,090 27,062
------ ------ ------ ------ ------ -------
Shares Outstanding (000's) 66,954 66,656 66,034 65,302 64,764 64,436
------ ------ ------ ------ ------ ------
DIVIDENDS PER SHARE OF COMMON STOCK
As of December 31, 1994, the Corporation had paid 202 consecutive quarterly
cash dividends on its common stock. At December 31, 1994, $423 million of
common shareholders' equity 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, cash
requirements and other relevant factors. In February 1995, a quarterly cash
dividend of $.05 per share was declared, payable March 6, 1995, to
shareholders of record on February 24, 1995. Quarterly cash dividends on
common stock were $.05 per share (annual rate of $.20 per share) in both 1994
and 1993 and $.20 per share (annual rate of $.80 per share) for the four
preceeding years.
In November 1990, two million shares of PESC common stock obtained in
connection with the sale of Pool Company were distributed to ENSERCH
shareholders, which had a value equivalent to $.33 per share of ENSERCH common
stock.
Dates Referenced Herein and Documents Incorporated by Reference
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