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UNITED STATESSECURITIES 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, 1996
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
(I.R.S. EMPLOYERIDENTIFICATION NO.)
(STATE OR OTHER JURISDICTIONOF
INCORPORATION OR ORGANIZATION)
ENSERCH CENTER300 SOUTH ST. PAUL
STREETDALLAS, TEXAS
75201-5598
(ADDRESS OF PRINCIPAL EXECUTIVE (ZIP CODE)
OFFICE)
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 ($.01 par value).......................... New York Stock Exchange
Chicago Stock Exchange
London Stock Exchange
Preferred Stock (no par value):
Depositary Preferred Shares, Series E (each
representing 1/10 share of the Adjustable Rate
Cumulative Preferred Stock, Series E)............... New York Stock Exchange
Depositary Preferred Shares, Series F (each
representing 1/40 share of the Adjustable Rate
Cumulative Preferred Stock, Series F) (liquidation
preference $1,000 per share)........................ New York Stock Exchange
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 non-affiliates of the
Registrant as of March 26, 1997: $1,471,371,035.
Shares of the Registrant's Common Stock outstanding as of March 26, 1997:
70,484 840 shares.
Documents incorporated by reference and the Part of the Form 10-K into which
the document is incorporated: None
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to
the best of Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [_]
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FORM 10-K
ANNUAL REPORT
FOR THE FISCAL YEAR ENDED DECEMBER 31, 1996
TABLE OF CONTENTS
PAGE
----
PART I
ITEM 1. Business....................................................... 1
Recent Developments............................................ 1
ENSERCH/Texas Utilities Company Merger......................... 1
Business Segments.............................................. 2
Natural Gas and Oil Exploration and Production................. 2
General........................................................ 2
Recent Developments............................................ 2
Management Changes............................................. 2
Core Areas..................................................... 2
Offshore Activities--The Cooper Project........................ 2
Offshore Activities--The Allegheny Project..................... 3
Rocky Mountain Properties...................................... 3
International Operations....................................... 3
Sales Information.............................................. 3
Major Customers................................................ 3
Competition.................................................... 4
Government Regulation.......................................... 4
Environmental Matters.......................................... 4
Other Laws and Regulations..................................... 5
Natural Gas Pipeline, Processing & Marketing................... 5
Pipeline....................................................... 5
Gas Processing................................................. 6
Gas Marketing.................................................. 6
Competition.................................................... 6
Regulation..................................................... 7
Natural Gas Distribution....................................... 7
Competition.................................................... 8
Source and Availability of Raw Materials....................... 8
Regulation..................................................... 9
Power.......................................................... 10
Clean Air Act.................................................. 11
Patents and Licenses........................................... 11
Employees...................................................... 11
ITEM 2. Properties..................................................... 12
ITEM 3. Legal Proceedings.............................................. 14
ITEM 4. Submission of Matters to a Vote of Security Holders............ 14
PART II
ITEM 5. Market for Registrant's Common Equity and Related Stockholder
Matters....................................................... 15
ITEM 6. Selected Financial Data........................................ 15
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations......................................... 15
PAGE
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ITEM 8. Financial Statements and Supplementary Data................... 15
ITEM 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure..................................... 15
PART III
ITEM 10. Directors and Executive Officers of the Registrant............ 16
Directors..................................................... 16
Executive Officers............................................ 17
ITEM 11. Executive Compensation........................................ 18
Summary Compensation Table.................................... 18
Option Grants Table........................................... 19
Aggregated Option Exercise Table.............................. 20
Long-Term Incentive Plan Awards Table......................... 20
Pension Plan Table............................................ 21
Compensation of Directors..................................... 21
Employment Contracts, Termination of Employment and Change-in-
Control Arrangements......................................... 22
Board Compensation Committee Report on Executive
Compensation................................................. 23
Performance Graph............................................. 25
Compensation Committee Interlocks and Insider Participation... 26
ITEM 12. Security Ownership of Certain Beneficial Owners and
Management................................................... 26
Security Ownership of Certain Beneficial Owners............... 26
Stock Ownership of Management and Board of Directors.......... 27
ITEM 13. Certain Relationships and Related Transactions................ 27
Section 16(a) Beneficial Ownership Reporting Compliance....... 27
PART IV
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-
K............................................................ 28
APPENDIX A Financial Information........................................ A-1
ITEM 1. BUSINESS
ENSERCH Corporation ("ENSERCH" or the "Corporation") is an integrated
company focused on natural gas. It is the successor to a company organized in
1909 for the purpose of providing natural-gas service to North Texas. The
Corporation's operations include the following:
--Natural Gas and Oil Exploration and Production--Exploring for,
developing, producing and marketing natural gas and oil. (Enserch
Exploration, Inc. [83.3% owned] and related operations.)
--Natural Gas Pipeline, Processing & Marketing--Owning and operating
interconnected natural-gas transmission lines, underground storage
reservoirs, compressor stations and related properties, all within Texas;
gathering and processing natural gas to remove impurities and extract
liquid hydrocarbons for sale; and the wholesale and retail marketing of
natural gas in several areas of the U.S. (Lone Star Pipeline Company, a
division of the Corporation, Enserch Processing, Inc., Enserch Energy
Services, Inc. and related operations.)
--Natural Gas Distribution--Owning and operating some 550 local gas utility
distribution systems in Texas. (Lone Star Gas Company, a division of the
Corporation, and related operations.)
--Power and Other--Developing, financing and operating electric-power
generating plants and cogeneration facilities, operating thermal-energy
plants for large building complexes, such as universities and medical
centers, and developing gas distribution systems in Mexico and South
America. (Enserch Development Corporation, Lone Star Energy Company,
Enserch International Services, Inc. and related operations.)
RECENT DEVELOPMENTS
ENSERCH/Texas Utilities Company Merger. In April 1996, ENSERCH announced
that it had entered into a merger agreement with Dallas-based Texas Utilities
Company ("ENSERCH/TUC Merger"). Under the terms of the agreement, a new
holding company will acquire the businesses of ENSERCH, excluding the
businesses of Enserch Exploration, Inc. ("EEX") and Lone Star Energy Plant
Operations, Inc. ("LSEPO"). Shares of ENSERCH common stock will be
automatically converted into shares of the new holding company common stock on
a basis of approximately 0.2 shares of the new company for 1.0 shares of the
Corporation's common stock in a tax-free transaction.
Immediately prior to the consummation of the ENSERCH/TUC Merger, and as a
condition thereof, EEX will be merged into LSEPO ("EEX/LSEPO Merger"), LSEPO
will change its name to "Enserch Exploration, Inc." ("New EEX"), shares of EEX
will automatically be converted into shares of New EEX on a one-for-one basis
in a tax-free transaction, and ENSERCH will distribute to its shareholders, on
a pro rata basis, all of the shares of New EEX common stock it owns
("Distribution"). LSEPO, a wholly owned subsidiary of ENSERCH, operates and
maintains, under long-term contracts, a 255-megawatt ("MW") cogeneration
facility located in Sweetwater, Texas, a 62-MW cogeneration facility located
in Buffalo, New York, and a 160-MW cogeneration facility located in
Bellingham, Washington. In the EEX/LSEPO Merger, ENSERCH will receive
approximately 778,000 shares of New EEX for the value of LSEPO.
The mergers, including the transactions contemplated by the mergers, were
approved by the shareholders of EEX, ENSERCH and TUC, in separate meetings, on
November 15, 1996. All regulatory approvals have been received except for
approval by the Securities and Exchange Commission ("SEC") under the Public
Utility Holding Company Act of 1935 where the approval process is proceeding.
The Railroad Commission of Texas ("RRC") has indicated no objection to the
ENSERCH/TUC Merger, and the Antitrust Division of the U.S. Department of
Justice ("DOJ") has notified ENSERCH and TUC that its investigation of the
proposed merger has been closed without the DOJ taking any action or requiring
TUC or ENSERCH to take any action. ENSERCH has also announced receipt of a
favorable tax ruling from the Internal Revenue Service to the effect that
neither ENSERCH nor its shareholders will recognize taxable gain in the
Distribution.
The merger and transactions related thereto are fully described in the
Corporation's Proxy Statement dated September 23, 1996, as filed with the SEC,
which is incorporated herein by reference.
1
BUSINESS SEGMENTS
Financial information required hereunder is set forth under "Summary of
Business Segments" included in Appendix A to this report.
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION
GENERAL
EEX has been engaged in the exploration for and the development, production
and sale of natural gas and crude oil since 1918. From 1985 through December
30, 1994, this business was conducted primarily through Enserch Exploration
Partners, Ltd. ("EP"), a limited partnership in which a minority interest
(less than 1% since 1989) was held by the public. At year-end 1994, pursuant
to a plan for the reorganization of EP ("Reorganization"), EEX acquired,
through a series of transactions, all of the operating properties of EP
Operating Limited Partnership ("EPO"), EP's 99%-owned operating partnership,
in exchange for shares of EEX common stock. On December 30, 1994, the
Reorganization was consummated, EPO was merged into EEX, EP was liquidated,
and the EEX common stock held by EP was distributed to EP's limited and
general partners in accordance with their partnership interests.
EEX is one of the largest independent exploration and production companies
in the United States, with a reserve base of 1,572 billion cubic feet of
natural gas equivalent ("Bcfe") at January 1, 1997, as estimated by DeGolyer
and MacNaughton ("D&M"), independent petroleum consultants. Approximately 77%
of these reserves consist of natural gas.
RECENT DEVELOPMENTS
Management Changes. On January 13, 1997, EEX named Thomas M Hamilton
Chairman and President, Chief Executive Officer of EEX, David R. Henderson as
Executive Vice President, Worldwide Exploration, and B. K. Irani as Executive
Vice President, Production and Engineering. Mr. Hamilton came to EEX from
Pennzoil Company where he was Executive Vice President and President of
Pennzoil Exploration & Production Company. He succeeded Frederick S. Addy,
interim Chairman, President and Chief Executive Officer, who continues to
serve as a Director of EEX. Mr. Henderson previously was Senior Vice President
of worldwide exploration at Pennzoil Exploration & Production Company. Mr.
Irani has previously served as Senior Vice President, Offshore and
International of EEX.
Core Areas. Mr. Hamilton has initiated a review of EEX's business with a
focus on enhancing performance from EEX's core areas of activity and the
development of plans for maximizing the value of non-core assets through
optimization of cash flow and the disposition of low-return, high-cost
properties. EEX operations will be focused on existing core areas of East
Texas, the Gulf of Mexico Continental Shelf and the deep water of the Gulf of
Mexico. EEX intends to vigorously pursue international opportunities. The
existing core areas account for more than 75% of EEX's proved reserves and
approximately 50% of total production. More than 90% of EEX's total probable
reserves, as estimated by D&M, are in the existing core areas. Operating costs
for properties located in core areas are relatively lower than the overall
cost profile for EEX. Assets in non-core areas will be traded or sold with
proceeds reinvested into core areas or utilized to reduce debt.
Offshore Activities--The Cooper Project. Production began at the Cooper
Project in the Garden Banks area of the Gulf of Mexico in September 1995.
Considered a deep-water project by industry standards, the floating production
facility ("FPF") is moored in 2,200 feet of water on Block 388. A 24-slot
subsea template rests on the ocean floor directly under the FPF. The FPF is
capable of drilling and producing simultaneously and is designed to
accommodate up to 40 thousand barrels ("MBbls") of oil and 120 million cubic
feet ("MMcf") of gas per day. EEX is the operator and owns a 60% interest in
this project. An affiliate of Mobil Corporation has a 40% interest. At year-
end 1996, gross daily production at the project had reached approximately 10
MBbls of oil and condensate and 15 MMcf of natural gas per day. Additional
development and exploratory drilling of identified prospects is expected
during 1997 as a part of a long-term development plan for the Cooper Project.
2
In late July 1996, it was announced that mechanical problems had prevented
completion of the A-1 development well at the Cooper Project. EEX and its
partner are evaluating alternate drilling strategies to develop the extensive
proven hydrocarbon column at this location.
The A-2 development well reached total depth of 9,835 feet encountering
three pay zones in the 7,200-foot, 7,600-foot and 9,800-foot sands in January
1997. In March 1997, the well was initially completed in the 9,800-foot sand,
which has a total of 116 feet of oil pay.
The SB-3 exploratory well on Garden Banks Block 387 was also completed in
March 1997. The well was drilled to a total depth of 19,000 feet and was
completed in a 50-foot sand interval at a depth of 18,170 feet. Based on
initial flow rates, the well is expected to initially produce at rates in the
range of 20 to 25 MMcf of gas per day with associated condensate.
Offshore Activities--The Allegheny Project. This project comprises a four-
block unit in the Green Canyon area of the Gulf of Mexico and is located
approximately 150 miles south of New Orleans, Louisiana, in 2,200 to 3,400
feet of water. The Allegheny Project is located in an area of the Gulf where
there is a great deal of exploration and development activity. EEX is the
operator and has a 40% interest in this project, an affiliate of Mobil
Corporation has 40% and an affiliate of Reading & Bates Corporation has 20%.
Prior to 1996, three wells and one sidetrack had been drilled on Green
Canyon Block 254 with gross proved reserves equivalent to approximately 72
million barrels ("MMBbls") of oil attributed by D&M. During 1996, a well was
drilled on Block 298, bottoming on Block 297, reaching a total depth of 16,500
feet (measured depth), encountering 350 gross feet of pay (measured depth).
Although the well extended the field 3,000 feet to the south, subsequent
interpretation of the data revealed thinning of some previously mapped
reservoirs which, coupled with the newly discovered sands, resulted in a 20
MMBbl downward revision of reserves to 52 MMBbls gross proved reserves.
In 1996, EEX and its partners began to identify alternative development
scenarios for the Allegheny Project. A joint project team was formed to
evaluate alternatives that are currently available for the design and
construction of production facilities. The project team will also design and
implement a development plan to optimize production from this project. The
additional engineering study and design will delay the project from its
previously planned early 1999 start-up. However, the design changes should
favorably impact the project's economics.
Rocky Mountain Properties. During 1996, EEX sold substantially all of its
Rocky Mountain area properties, which were in six states, aggregated over
250,000 net acres and had proved reserves of 148 Bcfe at January 1, 1996.
These properties were mostly acquired as part of an acquisition in 1995 and
were not considered a core area for EEX.
International Operations. In the Mudi field on the island of Java in
Indonesia, where EEX owns a 25% working interest, a development plan was
approved in 1996. Five wells have been drilled and are expected to be
completed in this field, and a stepout delineation well is being drilled.
Production is expected to commence in late 1997 or early 1998 initially at an
estimated 20 MBbls of oil per day. Gross reserves are estimated to be 40
MMBbls of oil and condensate.
SALES INFORMATION
Sales data are set forth under "Natural Gas and Oil Exploration and
Production Operating Data" included in Appendix A to this report.
MAJOR CUSTOMERS
EEX sells its gas under both long- and short-term contracts. EEX markets
most of its gas through third-party gas marketing organizations while
maintaining a core staff to ensure market prices are received. In 1996,
Enserch
3
Energy Services, Inc. ("EES"), the ENSERCH natural-gas marketing subsidiary,
was EEX's largest gas customer, purchasing gas under two long-term variable-
price contracts which terminated December 31, 1996. A division of ENSERCH,
Lone Star Gas Company ("LSG"), purchases gas under a long-term fixed-price
service contract which ends in March 1997. In 1996, approximately 34% and 6%
of EEX's natural-gas volumes were sold to EES and LSG, respectively. The
termination of these contracts will not have a material adverse effect on
EEX's results of operations.
EEX sells its oil under contracts that are for one year or less. Prices
generally are based upon field posted prices plus negotiated bonuses.
EEX utilizes futures contracts, commodity price swaps and other financial
instruments to reduce exposure of its gas and oil production to price
volatility. See "Financial Review--Natural Gas and Oil Exploration and
Production--Hedging Results" and Note 7 of the Notes to Consolidated Financial
Statements included in Appendix A for additional information on hedging
activities.
COMPETITION
All phases of the gas and oil industry are highly competitive. EEX competes
in the acquisition of properties, the search for and development of reserves,
the production and sale of gas and oil and the securing of the labor and
equipment required to conduct operations. EEX's competitors include major gas
and oil companies, other independent gas and oil concerns and individual
producers and operators. Many of these competitors have financial and other
resources that substantially exceed those available to EEX. Gas and oil
producers also compete with other industries that supply energy and fuel.
GOVERNMENT REGULATION
The gas and oil industry is extensively regulated by federal, state and
local authorities. Legislation affecting the gas and oil industry is under
constant review for amendment or expansion. Numerous departments and agencies,
both federal and state, have issued rules and regulations binding on the gas
and oil industry and its individual members, some of which carry substantial
penalties for the failure to comply. These laws and regulations are frequently
amended, reinterpreted or expanded, and EEX is unable to predict the future
cost or impact of complying with such laws and regulations.
The RRC regulates the production of natural gas and oil by EEX in Texas.
Similar regulations are in effect in all states in which EEX 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.
Environmental Matters. Gas and oil operations are subject to extensive
federal, state and local laws and regulations, including the Comprehensive
Environmental Response, Compensation and Liability Act ("CERCLA"), also known
as the "Superfund Law," and similar state statutes and, with respect to
federal leases, to interruption or termination by governmental authorities on
account of environmental and other considerations. Regulations of the
Department of the Interior currently impose absolute liability upon the lessee
under a federal lease for the costs to clean-up pollution resulting from a
lessee's operations, and such lessee may also be subject to possible legal
liability for pollution damages. EEX maintains insurance against costs of
clean-up operations, but is not fully insured against all such risks. A
serious incident of pollution may result in the Department of the Interior
requiring lessees under federal leases to suspend or cease operation in the
affected area. With respect to any EEX operations conducted on offshore
federal leases, liability may generally be imposed under the Outer Continental
Shelf Lands Act for costs of clean-up and damages caused by pollution
resulting from such operations, other than damages caused by acts of war or
the negligence of third parties.
The Oil Pollution Act of 1990 and regulations thereunder impose a variety of
regulations on "responsible parties" (which includes owners and operators of
offshore facilities) related to the prevention of oil spills and
4
liability for damages resulting from such spills in the United States waters.
In addition, it imposes ongoing requirements on responsible parties, including
proof of financial responsibility to cover at least some costs in a potential
spill.
The operations of EEX are also subject to the Clean Water Act and the Clean
Air Act, as amended, and comparable state statutes. The EPA is currently
implementing regulations pursuant to the Clean Air Act, and the states are
also implementing programs. EEX may be required to incur certain capital
expenditures over the next five to ten years for air-pollution control
equipment.
EEX's onshore operations are subject to numerous United States federal,
state and local laws and regulations controlling the discharge of materials
into the environment or otherwise relating to the protection of the
environment, including CERCLA. These regulations, among other things, impose
absolute liability on the lessee under a lease for the cost of clean-up of
pollution resulting from a lessee's operations, subject the lessee to
liability for pollution damages, may require suspension or cessation of
operations in affected areas and impose restrictions on the injection of
liquids into subsurface aquifers that may contaminate groundwater. Persons who
are or were responsible for releases of hazardous substances under CERCLA may
be subject to joint and several liability for the remediation and clean-up
costs and for damages to natural resources. EEX has been named as a
potentially responsible party at a Texas State Superfund site. However, EEX
does not believe that any liabilities in connection with such matters will
have a material adverse effect on its business or results of operations.
For offshore operations, lessees must obtain the approval of the Mineral
Management Service ("MMS"), a federal agency, and various other federal and
state agencies' approval for exploration, development and production plans
prior to the commencement of such operations. Similarly, the MMS has
promulgated other regulations governing the plugging and abandoning of wells
located offshore and the removal of all production facilities. Under certain
circumstances, including but not limited to, conditions deemed to be a threat
or harm to the environment, the MMS may also require any EEX operation on
federal leases to be suspended or terminated in the affected area.
Other Laws and Regulations. Various laws and regulations require permits for
drilling wells and the maintenance of bonding requirements in order to drill
or operate wells and also regulate the spacing and location of wells, the
method of drilling and casing wells, the surface use and restoration of
properties upon which wells are drilled, the plugging and abandoning of wells,
the prevention of waste of gas and oil, the prevention and cleanup of
pollutants, the maintenance of certain gas/oil ratios and other matters.
EEX's operations are also subject to various conservation requirements.
These include the regulation of the size and shape of drilling and spacing
units or proration units, the density of wells which may be drilled, maximum
rates of production and unitization or pooling of oil and gas properties.
In the aggregate, compliance with federal and state rules and regulations is
not expected to have a material adverse effect on EEX's operations.
NATURAL GAS PIPELINE, PROCESSING & MARKETING
The Corporation's pipeline, processing & marketing business is comprised of
the partially rate-regulated business of Lone Star Pipeline Company ("LSP"),
the non-regulated gathering and gas processing operations of Enserch
Processing, Inc. ("EPI") and the non-regulated gas marketing operations of
EES. Operating data for this segment are set forth under "Natural Gas
Pipeline, Processing & Marketing Operating Data" included in Appendix A to
this report.
Pipeline. LSP owns and operates interconnected natural-gas transmission
lines, underground gas storage reservoirs, compressor stations and related
properties, all within Texas. Through these facilities, it transports natural
gas to the distribution systems of LSG. Rates for these services are regulated
by the RRC. LSP also transports natural gas for affiliates other than LSG and
third-party shippers. LSP's transmission system is connected to the major gas
hubs at Waha in West Texas, Katy in South Texas and Carthage in East Texas.
5
For the year ended December 31, 1996, 21% of total LSP's volumes were
transported to LSG for ultimate sale to residential and commercial customers,
34% represented volumes transported for ultimate destination to competitive
on-system industrial and power-generation markets and 45% represented volumes
transported for destination to off-system markets.
Revenues from transporting gas for LSG are influenced by seasonal
temperature variations. Most of LSG's residential and commercial gas customers
use gas for heating, and their needs are directly affected by the mildness or
severity of the heating season. Deliveries to electric-generation customers
are affected by the mildness or severity of both cooling and heating seasons.
The Corporation holds a 50% interest in a partnership, 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 non-
affiliated pipeline customers.
Gas Processing. The Corporation's operations for the gathering and
processing of natural gas for the recovery of natural gas liquids ("NGL") are
conducted by EPI.
EPI uses cryogenic and mechanical refrigeration processes at its NGL
extraction facilities. 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 85% 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, which is commonly termed "shrinkage."
To reduce the impact of shrinkage, EPI strives to replace "keep-whole" gas
processing contracts with "net-proceeds" contracts. Keep-whole contracts are
relatively more profitable during periods of high NGL prices and low gas costs
because they provide the processor with ownership of the entire gas stream.
However, as NGL prices decline relative to gas costs, these contracts become
relatively 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.
Gas Marketing. EES is a marketer of energy services, primarily to the U.S.
retail markets, in the Northeast, Midwest and West Coast. EES's marketing
activities typically consist of (i) contracting to purchase specific volumes
of gas from producers, pipelines and other suppliers at various points of
receipt to be supplied to end users over a specific period of time, (ii)
aggregating gas supplies and arranging for the transportation of these gas
supplies, (iii) negotiating to sell specific volumes of gas over a specified
period of time to end users and (iv) providing related risk-management
services to the customer.
The marketing activities of EES involve price commitments into the future
and, therefore, give rise to market risk, which represents the potential loss
that can be caused by a change in the market value of a particular commitment.
To manage these market risks, EES enters into a variety of transactions,
including forward contracts principally involving physical delivery of natural
gas and derivative financial instruments, including swaps, options, futures
and other contractual arrangements. See "Financial Review--Natural Gas
Pipeline, Processing & Marketing" and Note 7 of the Notes to Consolidated
Financial Statements included in Appendix A for additional information on
these activities.
Competition. LSP is the sole transporter of natural gas to LSG's
distribution systems. LSP competes with other pipelines in Texas to transport
natural gas to off-system markets. This business is highly competitive and
6
greatly influenced by the demand to move natural gas across Texas to supply
Northeast and upper Midwest U.S. markets. See "Natural Gas Distribution--
Competition."
NGL processing is highly competitive and includes competition among
producers, third-party owners and processors for cost-sharing and interest-
sharing arrangements.
EES pursues markets connected to pipelines other than LSP's. 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 non-
regulated customers. This highly competitive market demands that a wide array
of services be offered, including term contracts with interruptible and firm
deliveries, risk management, aggregation of supply, nominations, scheduling of
deliveries and storage.
Regulation. LSP is wholly intrastate in character and performs
transportation services in the state of Texas subject to regulation by the
RRC. LSP 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.
LSP has been an open access transporter under Section 311 of the Natural Gas
Policy Act of 1978 ("NGPA") on its intrastate transmission facilities since
July 1988. 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 LSP's transportation charge to LSG for the transportation
of gas to LSG's distribution systems for sale to residential and commercial
customers. LSP's transportation services to other customers are provided under
standard or competitively negotiated contracts.
In October 1996, LSP filed a request with the RRC to increase the rate it
charges LSG to store and transport gas ultimately destined for residential and
commercial customers in the 550 Texas cities and towns served by LSG. LSG also
requested that the RRC separately set rates for costs to aggregate gas supply
for these cities. Rates currently in effect were set by the RRC in 1982. If
approved, the rate adjustment would increase annual revenues by approximately
$24.2 million. The purpose of the rate request is to allow for the recovery of
a substantial increase in the cost of doing business since 1982 and to cover
significant capital investments of approximately $420 million made during the
past 14 years to maintain and improve the reliability and safety of the
pipeline system and help reduce natural-gas supply costs. A number of cities
served by LSG have joined together in opposing the rate increase. The RRC is
expected to make a final ruling on the matter in mid-May.
NATURAL GAS DISTRIBUTION
LSG owns and operates natural-gas distribution systems and related
properties. Through these facilities, it purchases, distributes and sells
natural gas to over 1.3 million residential, commercial, industrial and
electric-generation customers in approximately 550 cities and towns, including
the 11-county Dallas/Fort Worth Metroplex. LSG also transports natural gas
within its distribution system as market opportunities require. Operating data
for this segment are set forth under "Natural Gas Distribution Operating Data"
included in Appendix A to this report.
For the year ended December 31, 1996, sales to residential and commercial
customers accounted for 91% of LSG's total gas sales revenues and 88% of
natural-gas volumes sold. Sales to industrial and electric-generation
customers accounted for the remainder.
LSG's gas sales revenues are influenced by seasonal temperature variations.
The majority of LSG's residential and commercial gas customers use gas for
heating, and their needs are directly affected by the mildness or severity of
the heating season, although some 65% of LSG's residential and commercial
volumes
7
are subject to weather normalization adjustments. Sales to electric-generation
customers are affected by the mildness or severity of both cooling and heating
seasons.
Competition. Customer sensitivity to energy prices and the availability of
competitively priced gas in the non-regulated markets continue to provide
intense competition in the electric-generation and industrial-user markets.
Natural gas faces varying degrees of competition from electricity, coal,
natural gas liquids, oil and other refined products throughout LSG's service
territory. Pipeline systems of other companies, both intrastate and
interstate, extend into or through the areas in which LSG's markets are
located, creating competition from other sellers of natural gas. Competitive
pressure from other pipelines and alternative fuels has caused a decline in
sales by LSG to industrial and electric-generation customers. Sales by the
Corporation's non-regulated companies, along with transportation services
provided by LSP, have served to offset much of the effects of this decline. As
developments in the energy industry point to a continuation of these
competitive pressures, LSG maintains its focus on customer service and the
creation of new services for its customers in order to remain its customers'
supplier of choice.
Source and Availability of Raw Materials. LSG's gas supply consists of
contracts for the purchase of dedicated specific reserves, contracts with
other pipeline companies in the form of service agreements that are not
related to specific reserves or fields, and gas in storage. The total gas
supply as of January 1, 1997, was 571 billion cubic feet ("Bcf"), which is
approximately 4 times LSG's purchases during 1996. Of this total, 148 Bcf are
dedicated reserves and 36 Bcf are working gas in storage. Management has
calculated that 387 Bcf, including 109 Bcf under one agreement, are committed
to LSG under service agreements. The January 1, 1997, total gas supply
estimate is 183 Bcf lower than the January 1, 1996, estimate. The difference
resulted from 147 Bcf purchased from existing gas supply, a net downward
revision of 70 Bcf with respect to estimates for existing sources and service
agreements, partially offset by new supply additions of 34 Bcf. The net
downward revision of existing sources and service agreements is comprised of
55 Bcf downward adjustment of service and peaking agreement availability, 10
Bcf downward adjustment of proved developed and unconnected reserves and 9 Bcf
from downward revisions and terminations of dedicated special reserves,
partially offset by 4 Bcf of additional gas in storage as compared to
inventory levels at January 1, 1996. New supply additions of 34 Bcf consisted
of 4 Bcf of new dedicated reserves under old contracts and 30 Bcf of
availability added under new peaking contracts.
In 1996, about 88% of LSG's gas requirement was purchased from some 264
independent producers and non-affiliated pipeline companies, one of which
supplied approximately 16% of total requirements. The remaining 12% of LSG's
requirement was supplied by affiliates.
LSG estimates its peak-day availability from long-term contracts and
withdrawals from underground storage to be 1.7 Bcf. Short-term peaking
contracts raise this level to meet anticipated sales needs.
During 1996, the average daily demand of LSG'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 1.9 Bcf.
LSG's greatest daily demand in 1996 was on February 3 when the arithmetic-mean
temperature was 21 degrees F. and deliveries to all customers reached 2.1 Bcf,
including estimated deliveries to residential and commercial customers of 1.9
Bcf.
To meet peak-day gas demands during winter months, LSG utilizes the service
of seven affiliated gas storage fields, all of which are located in Texas.
These fields have a working gas capacity of 47 Bcf and a day-one storage
withdrawal capacity of 1.3 Bcf per day.
LSG has historically maintained a contractual right to curtail, which is
designed to achieve the highest load factor possible in the use of the
pipeline system while assuring continuous and uninterrupted service to the
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 sales curtailment occurred in
1990 and lasted for only 30 hours.
8
Estimates of gas supplies and reserves are not necessarily indicative of
LSG'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. LSG'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 LSG, may affect its
ability to meet the demands of its customers.
The LSG supply program is designed to contract for new supplies of gas (and
to recontract targeted expiring sources) connected to LSP's pipeline system.
In addition to being heavily concentrated in the established gas-producing
areas of central, northern and eastern Texas, LSP's intrastate pipeline system
also extends into or near the major 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. LSP's pipeline system provides access to all of
these basins. LSP is well situated to receive large volumes into its system at
the major "hubs," such as Katy and Waha, as well as at the major third-party
owned storage facilities where suppliers maintain instantaneous high delivery
capabilities.
LSG buys gas under long-term, intrastate contracts in order to assure
reliable supply to its customers. Many of these contracts require minimum
purchases of gas. In the past, LSG had been unable to take delivery of all
minimum gas volumes tendered by suppliers under these contracts. Based on
estimated gas demand, which assumes normal weather conditions, requisite gas
purchases are expected to substantially satisfy purchase obligations for the
year 1997 and thereafter. See Note 8 of the Notes to Consolidated Financial
Statements included in Appendix A to this report.
Regulation. LSG is wholly intrastate in character and performs its
distribution utility operations in the state of Texas subject to regulation by
the RRC and municipalities in Texas. The RRC regulates the charge for the
transportation of gas by LSP to LSG's distribution systems for sale to LSG's
residential and commercial consumers. The RRC has original jurisdiction over
rates charged to 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. LSG's city gate rate for the cost of gas
ultimately delivered to residential and commercial customers is established by
the RRC and provides for full recovery of the actual cost of gas delivered,
including out-of-period costs such as gas-purchase contract settlement costs.
LSG employs a continuing program of rate review for all classes of customers
in its regulatory jurisdictions. Rate relief amounting to about $6.3 million
in annualized revenue increases, exclusive of changes in gas cost, was
achieved in Texas in 1996. Weather normalization adjustment clauses have been
approved by 270 of the 550 cities served by LSG, representing over 65% of
LSG's residential and commercial sales volumes. These clauses allow rates to
be adjusted to reflect the impact of warmer or colder-than-normal weather
during the winter months, minimizing the impact of variations in weather on
LSG's earnings.
LSG's sales to industrial customers are provided under rates reflected in
standard rate schedules and contracts. Transportation services to industrial
and electric-generation customers are provided under competitively negotiated
contracts. Industrial customers also have standard rate schedules for
transportation services. Regulatory authorities in Texas have jurisdiction to
revise, review and regulate rates to industrial and electric-generation
customers but, historically, have not actively exercised this jurisdiction
because of the existing competitive market. Sales contracts with these
customers permit automatic adjustment on a monthly basis for the full amount
of increases or decreases in the cost of gas.
On August 20, 1996, the RRC ordered a general inquiry into the rates and
services of LSG. The scope of the inquiry has not been defined, and an
evidentiary hearing has not been held. However, at the recently concluded rate
hearing requested by LSG and LSP, RRC examiners indicated that LSG's
historical natural gas
9
acquisition practices and costs will be reviewed. The Corporation believes any
retroactive rate action as a result of the review to be inappropriate and
unlawful.
ENSERCH operates in the liquefied and compressed natural-gas vehicular fuel
markets through the Alternative Fuel Division of Lone Star Energy Company
("LSEC"). This includes two affiliates, FleetStar of Texas, L.C. (a fueling
affiliate) and TRANSTAR Technologies, L.C. (a vehicle conversion affiliate),
which are both 50% owned by LSEC, as well as FinaStar, which is a partnership
between FleetStar and Fina Oil and Chemical and is 25% owned by LSEC. These
entities had 17 public and 10 private natural-gas fueling stations in
commercial operation at December 31, 1996, and sold 2.5 million equivalent
gallons during the year. TRANSTAR provides turnkey natural-gas vehicle
conversions and other related services and performed over 500 natural-gas
conversions during 1996. LSEC also owns and operates one liquefied natural-gas
(LNG) fueling station at the American Airlines DFW Airport maintenance
facility.
In South America, LSG is providing its distribution expertise to develop a
new infrastructure in support of gas systems being constructed to service
Santiago, Chile, and surrounding communities. Additionally, newly passed
legislation in Mexico has opened the door to partial ownership of gas pipeline
transmission systems by foreign companies. Based upon its geographic proximity
to the existing U.S.-based, natural-gas reserves, the Corporation's affiliates
are examining the economic potential to be gained by participating in the
developing natural-gas infrastructure in Mexico.
POWER
Enserch Development Corporation ("EDC") develops business opportunities
primarily in the areas of independent power, including cogeneration. EDC
evaluates the risks 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's efforts are currently focused on international
projects, with decreased emphasis on projects in the United States.
EDC has completed the development of three cogeneration plants, including a
255-MW plant in Sweetwater, Texas, that began operation in 1989, a 62-MW
natural gas-fired cogeneration facility in Buffalo, New York, that was
completed in 1992 and a 160-MW plant in Bellingham, Washington, that began
commercial operation in 1993. The electricity produced at the Sweetwater plant
is purchased by Texas Utilities Electric Company, and thermal energy is sold
to United Gypsum Company under a long-term agreement. A subsidiary of EDC is
the managing general partner of the plant, EEX and EES provide gas to the
plant, and LSP transports the gas. The Buffalo plant supplies electricity to
Niagara Mohawk Company and thermal energy to Outokumpu American Brass, Inc.
The electricity produced at the Bellingham 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. LSEPO,
a wholly owned subsidiary of LSEC, operates and maintains all three plants and
has fixed-cost operating and maintenance agreements for providing labor and
certain routine consumables at each plant, with each of the agreements
containing escalation provisions. The agreements for the Buffalo and
Bellingham plants also contain bonus or penalty provisions based upon plant
availability.
At the end of 1996, EDC, through its wholly owned subsidiary Enserch
International Ltd. ("EIL"), had two international projects in the construction
and drilling phase. Construction of a 36-MW coal-fired cogeneration facility
in the Zhejiang Province of the People's Republic of China, in which EDC has a
70% interest, began in the fourth quarter of 1995. Phase I of the plant is
expected to be completed in mid-1997 and the remainder in 1998. Electricity
will be sold to the Shaoxing Administration of Power Utilization, and steam
will be sold to several industrial users in the area. The second project, in
which EIL will have a 15% interest, is a 300 to 400-MW geothermal power plant
in Java, Indonesia. Drilling for geothermal resource will continue throughout
1997, and construction of the power-generation facility is scheduled to begin
in 1997. Electricity from the plant will be sold to the Indonesian electric
utility, PT PLN (PERSERO).
10
In addition to operating and maintaining cogeneration plants developed by
EDC, through its subsidiary LSEPO, LSEC owns and operates two central thermal
energy plants providing heating and cooling to various institutional customers
in Texas under agreements which expire in 1997. LSEC is actively pursuing new
contracts to operate the plants after the existing agreements expire. The
expiration of the existing agreements will not have a significant impact on
the Corporation.
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
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 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 ("CFC's"), 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, its divisions and subsidiary companies have no material
patents, licenses, franchises (excluding gas-distribution franchises) or
concessions.
EMPLOYEES
At December 31, 1996, the Corporation, its divisions and subsidiaries, had
approximately 4,010 employees.
11
ITEM 2. PROPERTIES
EEX's domestic activities were focused in four regions in 1996: the Gulf of
Mexico; East Texas; Mid-Continent and other; and the Gulf Coast Region of
Texas, Louisiana, Mississippi and Alabama. The following table sets forth
estimated net proved reserves of EEX by region, as estimated by D&M, at
January 1, 1997:
OIL
NATURAL AND GAS
GAS LIQUIDS TOTAL
REGION (BCF) (MMBBLS) BCFE
------ ------- -------- -------
Gulf of Mexico......................................... 126.5 28.0 294.7
East Texas............................................. 845.1 7.5 890.1
Mid-Continent and Other................................ 102.8 13.7 184.9
Gulf Coast............................................. 141.2 4.0 165.2
------- ---- -------
Total Domestic....................................... 1,215.6 53.2 1,534.9
International.......................................... .6 6.0 36.6
------- ---- -------
Total................................................ 1,216.2 59.2 1,571.5
======= ==== =======
See Note 12 of the Notes to Consolidated Financial Statements included in
Appendix A to this report for additional information on gas and oil reserves.
During 1996, EEX filed Form EIA-23 with the Department of Energy reflecting
reserve estimates for the year 1995. Such reserve estimates were not
materially different from the 1995 reserve estimates reported in Note 12 of
the Notes to Consolidated Financial Statements included in Appendix A to this
report.
Developed and undeveloped lease acreage as of December 31, 1996, are set
forth below:
DEVELOPED ACRES UNDEVELOPED ACRES
--------------- -------------------
GROSS NET(1) GROSS NET(1)
------- ------- --------- ---------
Domestic
Offshore.................................. 189,310 60,609 853,105 426,462
Onshore................................... 471,368 289,968 1,056,035 654,701
------- ------- --------- ---------
Total................................... 660,678 350,577 1,909,140 1,081,163
International............................... -- -- 2,489,567 618,637
------- ------- --------- ---------
Total................................... 660,678 350,577 4,398,707 1,699,800
======= ======= ========= =========
- --------
(1) Represents the proportionate interest of EEX in the gross acres under
lease.
EEX purchased about 252,000 net acres of leasehold interests in 1996, 99,000
of which were in the Gulf of Mexico. EEX's Gulf of Mexico holdings totaled
some 487,000 net acres, with an average working interest of 43% in 234 blocks
and an overriding royalty interest in 9 blocks. EEX operates 148 offshore
blocks. EEX also canceled or allowed to expire two Gulf of Mexico leases
during 1996 following review of drilling activity on or near these areas and
after analysis of geophysical and geological findings.
12
EEX 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 commercial reserves sufficient to justify retention of the
acreage. The primary terms under which the undeveloped acreage can be retained
by the payment of delay rentals without the establishment of gas and oil
reserves expire as follows:
UNDEVELOPED ACRES EXPIRING
-----------------------------------
DOMESTIC INTERNATIONAL
----------------- -----------------
GROSS NET GROSS NET
--------- ------- --------- -------
1997........................................ 551,741 312,456 730,242 182,560
1998........................................ 353,191 200,015 182,560 45,640
1999 and later.............................. 1,004,208 568,692 1,576,765 390,437
Drilling rights with regard to a portion of the undeveloped acreage may be
allowed to expire before the expiration of primary terms specified in this
schedule by non-payment of delay rentals.
At December 31, 1996, EEX owned interests in 1,670 gas wells (1,121.1 net)
and 1,801 oil wells (422 net) in the United States and 5 oil wells (1 net) in
Indonesia. Of these, 226 gas wells (166.4 net) and 43 oil wells (34.9 net)
were dual completions in single boreholes.
Drilling activity during the three years ended December 31, 1996, including
the activities of properties acquired in 1995 for all periods shown, is set
forth below:
1996 1995 1994
---------- ---------- ----------
GROSS NET GROSS NET GROSS NET
----- ---- ----- ---- ----- ----
Exploratory Wells:
Productive................................... 42 30.0 38 24.6 21 13.8
Dry.......................................... 32 20.7 47 26.8 56 30.5
--- ---- --- ---- --- ----
Total...................................... 74 50.7 85 51.4 77 44.3
=== ==== === ==== === ====
Development Wells:
Productive................................... 82 54.3 41 26.4 90 63.0
Dry.......................................... 5 4.0 6 3.5 15 7.5
--- ---- --- ---- --- ----
Total...................................... 87 58.3 47 29.9 105 70.5
=== ==== === ==== === ====
- --------
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 EEX's working
interest owned therein.
At December 31, 1996, EEX was participating in 71 wells (34 net), which were
either being drilled or in some stage of completion.
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
correspond to capital expenditures, since SEC 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 EEX is set
forth in Note 12 of the Notes to Consolidated Financial Statements included in
Appendix A to this report.
EEX leases approximately 205,000 square feet of office space for its offices
in Dallas, Texas, under leases expiring in December 1998 and August 2002.
13
LSP. At December 31, 1996, LSP operated approximately 8,000 miles of
transmission and gathering lines and operated 22 compressor stations having a
total rated horsepower of approximately 72,000. LSP also owns seven active
gas-storage fields, all located on its system in Texas, and three major gas-
treatment plants to remove undesirable components from the gas stream.
EPI. At December 31, 1996, EPI had interests in 17 processing plants, 13 of
which were wholly owned, and operated approximately 1,714 miles of gathering
lines.
LSG. At December 31, 1996, LSG operated approximately 23,500 miles of
distribution mains. See "Business--Natural Gas Distribution--Source and
Availability of Raw Materials" for information concerning gas supply of LSG.
LSEC. LSEC owns two central plants providing heating and cooling to
institutional customers in Dallas and El Paso. During 1997, ownership of these
plants will transfer to the institution which they serve.
The Corporation owns a five-building office complex in Dallas, containing
approximately 453,000 square feet of space that the Corporation, LSG, LSP 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. This building is sub-
leased, primarily to non-affiliated parties.
See "Financial Review--Liquidity and Financial Resources" included in
Appendix A to this report for a discussion of the Corporation's 1997 capital
spending budget by business segment.
ITEM 3. LEGAL PROCEEDINGS
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. Additional information required
hereunder is set forth in Note 8 of the Notes to Consolidated Financial
Statements included in Appendix A to this report.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
14
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.
15
PART III
ITEMS 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
DIRECTORS
The following biographical information sets forth the name, age, principal
occupation or employment during the past five years, Board committee
membership, certain other directorships held by each director, and the period
during which he or she has served as a director of the Corporation.
D. W. Biegler
Chairman and President, Chief Executive Officer, ENSERCH Corporation
Mr. Biegler, age 50, is Chairman and President, Chief Executive Officer of
the Corporation. Prior to his election to his present position in 1993, he
served LSG as President from 1985 and as Chairman from 1989 and was elected
President and Chief Operating Officer of the Corporation in 1991. Mr. Biegler
is a Director of Enserch Exploration, Inc., Texas Commerce Bank National
Association, and Trinity Industries, Inc. He has been a Director of the
Corporation since 1991.
B. A. Bridgewater, Jr.
Chairman, President and Chief Executive Officer, Brown Group, Inc.
Mr. Bridgewater, 63, is Chairman, President and Chief Executive Officer, and
Director, of Brown Group, Inc., a footwear company. Mr. Bridgewater has been a
Director of the Corporation since 1987 and serves as Chairman of the Policy
Committee and is a member of the Audit Committee. He is a Director of Enserch
Exploration, Inc., NationsBank Corporation, FMC Corporation, and McDonnell
Douglas Corporation.
Odie C. Donald
President, BellSouth Mobility, Inc.
Mr. Donald, age 47, is President, BellSouth Mobility, Inc., a cellular
telecommunications company. Mr. Donald has served in his present position
since 1992. He previously served BellSouth as Vice President, Marketing and
various other positions. He has been a Director of the Corporation since 1995
and is a member of the Compensation Committee and the Directors' Nominating
Committee.
Marvin J. Girouard
President and Chief Operating Officer, Pier 1 Imports, Inc.
Mr. Girouard, age 57, is President and Chief Operating Officer, and
Director, of Pier 1 Imports, Inc. Mr. Girouard has been a Director of the
Corporation since 1992 and is Chairman of the Compensation Committee and a
member of the Directors' Nominating Committee.
J. M. Haggar, Jr.
Retired Chairman of the Board, Haggar Apparel Company
Mr. Haggar, age 72, is retired Chairman of the Board, Haggar Apparel
Company, a manufacturer of apparel for men. Mr. Haggar has been a Director of
the Corporation since 1988 and is Chairman of the Directors' Nominating
Committee and a member of the Policy Committee. He is a Director of Brinker
International, Inc.
Thomas W. Luce, III
Partner, Hughes & Luce
Mr. Luce, age 56, is a partner of Hughes & Luce, a law firm he co-founded in
1973. From October 1991 to July of 1992, he served as Chairman and Chief
Executive Officer of First Southwest Company, a diversified investment banking
services firm. Mr. Luce has been appointed by Governors of Texas to four major
state positions. He is a Director of Dell Computer Corporation. He has been a
Director of the Corporation since 1995 and is a member of the Compensation
Committee and the Policy Committee.
16
W. C. McCord
Retired Chairman and Chief Executive Officer, ENSERCH Corporation
Mr. McCord, age 68, is retired Chairman and Chief Executive Officer of the
Corporation. Mr. McCord has been a Director of the Corporation since 1970 and
is a member of the Audit Committee and the Policy Committee. He is a Director
of Enserch Exploration, Inc., Lone Star Technologies, Inc. and Pool Energy
Services Co.
Diana S. Natalicio
President, University of Texas at El Paso
Dr. Natalicio, age 57, is President, University of Texas at El Paso. Dr.
Natalicio has been a Director of the Corporation since 1993 and is Chairman of
the Audit Committee and a member of the Director's Nominating Committee. She
is a Director of Sandia Corporation.
EXECUTIVE OFFICERS
NAME AGE TITLE
---- --- -----
D. W. Biegler...................... 50 Chairman and President, Chief Executive
Officer
G. R. Bryan........................ 52 Senior Vice President, Power and
Business Development
M. T. Hunter....................... 47 President and Chief Operating Officer of
Lone Star Pipeline Company
D. R. Long......................... 49 Senior Vice President, Administration
M. E. Rescoe....................... 44 Senior Vice President, Finance, and
Chief Financial Officer
W. T. Satterwhite.................. 63 Senior Vice President and General
Counsel
R. B. Williams..................... 64 President and Chief Operating Officer of
Lone Star Gas Company
Mr. Biegler has been 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 LSG as President from July 1985 and as Chairman from January 1989.
Mr. Bryan has been President and Chief Operating Officer of EES since May
1995; Chairman, President and Chief Operating Officer of EDC since February
1994. He also served LSG as Senior Vice President, Transmission, from February
1987 to February 1993.
Mr. Hunter has been President and Chief Operating Officer of LSP since June
1995. Previously he served as President and Chief Operating Officer of
Mississippi River Transmission Corporation, a subsidiary of Noram Energy Corp.
Mr. Long has been Senior Vice President, Administration, since May 1995. He
previously served LSG as Vice President, Human Resources and Services, from
January 1995 to May 1995, and as Vice President, Human Resources and Facility
Development, from June 1990 to January 1995.
Mr. Rescoe has been Senior Vice President, Finance, and Chief Financial
Officer since September 1995. Previously he served as Senior Managing Director
of Bear, Stearns & Co. from 1992 to July 1995 and was a Senior Vice President,
Finance, of Kidder, Peabody & Co. from 1983 to 1992.
Mr. Satterwhite has been Senior Vice President and General Counsel, Chief
Legal Officer of the Corporation since May 1972.
Mr. Williams has been President and Chief Operating Officer of LSG since May
1995. He served as Vice President, Administration, of the Corporation from May
1989 to May 1995.
17
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 the judgment of the Board,
the best interest of the Corporation, its divisions or subsidiaries, as the
case may be, will be served thereby.
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The table below sets forth annual compensation, long-term compensation, and
all other compensation paid by the Corporation and its subsidiaries for
services rendered during the periods shown for each individual serving as the
chief executive officer and each of the other four most highly compensated
executive officers in 1996 (the "named executive officers").
SUMMARY COMPENSATION TABLE
LONG-TERM COMPENSATION
------------------------------------
AWARDS PAYOUTS
-------------------------- ---------
OTHER ALL
ANNUAL RESTRICTED SECURITIES LONG-TERM OTHER
ANNUAL COMPENSATION COMPEN- STOCK UNDERLYING INCENTIVE COMPEN-
NAME AND ----------------------- SATION AWARDS OPTIONS PAYOUTS SATION
PRINCIPAL POSITION YEAR SALARY($) BONUS($) ($)(2) ($) (#) ($)(5) ($)(6)
------------------ ---- --------- -------- ------- ---------- ---------- --------- -------
D. W. Biegler........... 1996 600,000 330,000 3,600 556,800(3)(4) 50,000 1,009,208 768,525
Chairman and President, 1995 593,750 245,822 8,400 (4) 25,000 0 27,525
Chief Executive Officer 1994 550,000 317,625 4,050 (4) 0 0 28,394
G. R. Bryan............. 1996 300,000 150,000 1,510 185,600(3)(4) 24,000 374,112 13,833
President, Power Group 1995 254,167 0 4,040 (4) 10,000 0 1,500
1994 242,417 11,815 1,530 (4) 0 0 3,000
M. T. Hunter............ 1996 310,000 150,000 1,000 185,600(3)(4) 24,000 185,600 7,408
President and Chief 1995 175,000 90,035 1,500 (4) 15,000 0 450
Operating
Officer, Lone Star 1994 0 0 0 0 0 0 0
Pipeline Company(1)
M. E. Rescoe............ 1996 280,000 112,000 950 185,600(3)(4) 24,000 167,040 2,937
Senior Vice President, 1995 128,333 0 450 (4) 11,000 0 0
Finance,
Chief Financial 1994 0 0 0 0 0 0 0
Officer(1)
W. T. Satterwhite....... 1996 282,000 112,800 735 92,800(3)(4) 15,000 225,970 245,320
Senior Vice President, 1995 270,667 87,080 1,940 (4) 5,000 0 24,642
General Counsel 1994 265,000 116,600 855 (4) 0 0 25,542
- --------
(1) M. T. Hunter joined the Corporation as an executive officer on June 1,
1995. Mr. Rescoe joined the Corporation on July 17, 1995, and became an
executive officer on September 1, 1995.
(2) Includes non-preferential dividends paid on non-vested restricted stock.
(3) Value of restricted stock awarded in 1996 under the ENSERCH Corporation
1991 Stock Incentive Plan ("1991 Plan") on which restrictions were lifted
under change-in-control provisions in the Corporation's 1991 Plan.
Approval by the Corporation's Board of Directors of the ENSERCH/TUC Merger
constituted such a change in control. Values are based on the market value
of the stock on the date the restrictions were lifted.
(4) The restricted stock awards to named executive officers under the 1991
Plan are subject to performance-based criteria. Restricted stock awards in
1996 to the named executive officers are reported under the "Long-Term
Incentive Plan Awards" table, and reference is made to such table for
information on the number of restricted shares awarded in 1996.
(5) Payouts of restricted stock awarded in years prior to 1996 on which
restrictions were lifted under change-in-control provisions in the 1991
Plan, as follows: Mr. Biegler--42,000 shares; Mr. Bryan--20,200 shares;
Mr. Hunter--10,000 shares; Mr. Rescoe--9,000 shares; and Mr. Satterwhite--
9,700 shares. Restrictions were also lifted on shares of EEX restricted
stock granted to Mr. Biegler (25,000 shares) and Mr. Satterwhite (5,000
shares) under the EEX stock incentive plan ("1996 Plan") change-in-control
provision.
18
Approval by the EEX Board of Directors of the EEX/LSEPO merger constituted
such a change in control. Payout values are based on the market value of
the stock on the date the restrictions were lifted.
(6) For 1996, includes company matching contributions to the Employee Stock
Purchase and Savings Plan and Deferred Compensation Plan, respectively, as
follows: D. W. Biegler--$900, $18,000; G. R. Bryan--$900, $9,000; M. T.
Hunter--$675, $2,800; M. E. Rescoe--$0, $0; and W. T. Satterwhite--$900,
$8,460. For 1996, also includes interest paid on delayed bonus payments as
follows: D. W. Biegler--$8,652; G. R. Bryan--$3,933; M. T. Hunter--$3,933;
M. E. Rescoe--$2,937; and W. T. Satterwhite--$2,958. Also includes all
accruals in 1996 resulting from change-in-control provisions of (a)
deferred compensation under a Special Supplemental Compensation Plan for
D. W. Biegler of $740,973 and (b) under an expired employment contract for
W. T. Satterwhite of $233,002.
OPTION GRANTS TABLE
The table below shows, for each of the named executive officers, certain
information with respect to options granted in 1996 under the 1991 Plan.
OPTION GRANTS IN LAST FISCAL YEAR
NUMBER OF
SECURITIES
UNDERLYING PERCENTAGE OF TOTAL
OPTIONS OPTIONS GRANTED EXERCISE PRICE GRANT DATE
GRANTED(1) TO EMPLOYEES PER SHARE EXPIRATION PRESENT
NAME (#) IN FISCAL YEAR ($/SH)(2) DATE(1) VALUE(3)
---- ---------- ------------------- -------------- ---------- ----------
D. W. Biegler........... 50,000 15.3% $15.125 2/16/06 $332,465
G. R. Bryan............. 24,000 7.4 15.125 2/16/06 159,583
M. T. Hunter............ 24,000 7.4 15.125 2/16/06 159,583
M. E. Rescoe............ 24,000 7.4 15.125 2/16/06 159,583
W. T. Satterwhite....... 15,000 4.6 15.125 2/16/06 99,739
- --------
(1) Options are exercisable in stages of 25% on the first through the fourth
anniversaries of the grant. Options become fully vested in the event of a
"change in control" as defined in the 1991 Plan. Approval by the Board of
Directors of the Corporation of the ENSERCH/TUC Merger constituted a
"change in control" as defined in the 1991 Plan. As a result, the options
became fully vested upon such approval.
(2) Fair market value on the date of grant.
(3) Represents the hypothetical present value of the option determined using
Black-Scholes Options Valuation Method based upon the terms of the option
grant and the Corporation's stock price as of the date of the grant. The
actual value, if any, an executive may realize will depend on the excess
of the stock price over the exercise price on the date the option is
exercised, and there is no assurance that the value ultimately realized
will be at or near the value estimated by the Black-Scholes Option
Valuation Method. The assumptions used to arrive at the values shown are
as follows: Risk Free Interest Rate of 5.99% based on the ten-year
Treasury bond rate on the date of the Grant, Stock Price Volatility of 29%
based on the historical return volatility using weekly stock prices over
the prior three years, Dividend Yield of 1.3289% based on the annual
dividend rate of twenty cents per share, and Date of Exercise on the
expiration date of February 16, 2006.
19
AGGREGATED OPTION EXERCISE TABLE
The table below shows, for each of the named executive officers, the
information specified with respect to exercised, exercisable and unexercisable
options under all existing stock option plans.
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR AND FISCAL YEAR-END OPTION
VALUES
NUMBER OF SECURITIES VALUE OF UNEXERCISED
UNDERLYING UNEXERCISED IN-THE-MONEY
OPTIONS AT OPTIONS AT
SHARES DECEMBER 31, 1996 DECEMBER 31, 1996
ACQUIRED ON VALUE (#) ($)
EXERCISE REALIZED ------------------------- -------------------------
NAME (#) ($) EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- -------- ----------- ------------- ----------- -------------
D. W. Biegler........... 33,950 167,544 246,948 0 1,639,783 0
G. R. Bryan............. 5,900 32,450 68,675 0 493,209 0
M. T. Hunter............ 39,000 252,938 0 0 0 0
R. E. Rescoe............ 11,000 62,562 24,000 0 189,000 0
W. T. Satterwhite....... 37,400 191,675 63,000 0 379,063 0
LONG-TERM INCENTIVE PLAN ("LTIP") AWARDS TABLE
The table below shows for each of the named executive officers, certain
information with respect to awards of performance-based restricted stock made
pursuant to the 1991 Plan.
LONG-TERM INCENTIVE PLANS--AWARDS IN LAST FISCAL YEAR
ESTIMATED FUTURE PAYOUTS UNDER
NON-STOCK PRICE BASED PLANS (1)
PERFORMANCE PERIOD ---------------------------------
NUMBER OF UNTIL MATURATION THRESHOLD(2) TARGET(2) MAXIMUM(2)
SHARES OR PAYOUT(3)(4) (#) (#) (#)
--------- ------------------ ------------ --------- ----------
D. W. Biegler........... 30,000 01/01/96-12/31/98 1,500 30,000 30,000
G. R. Bryan............. 10,000 01/01/96-12/31/98 500 10,000 10,000
M. T. Hunter............ 10,000 01/01/96-12/31/98 500 10,000 10,000
M. E. Rescoe............ 10,000 01/01/96-12/31/98 500 10,000 10,000
W. T. Satterwhite....... 5,000 01/01/96-12/31/98 250 5,000 5,000
- --------
(1) Performance-based restricted shares have been awarded and will be earned
at the end of a three-year performance period based upon the three year
total shareholder return of the Corporation compared to the weighted
average of the total shareholder return of the peer group of companies
used in the performance graph in the 1995 Proxy Statement. Regular cash
dividends are paid on the restricted shares prior to vesting at the same
rate as paid to all shareholders. All restrictions are lifted in the event
of a change in control and are subject to allocation in the event of
retirement, disability or death during the performance period.
(2) All shares are earned if at the end of the performance term the
Corporation's total shareholder return is at or above 110% of the weighted
average of the peer group. For each percentage point that the
Corporation's total shareholder return is below 110% of the weighted
average of the peer group but above 100%, 2.5% of the shares will be
forfeited and for each percentage point below 100%, 5% of the shares will
be forfeited with no shares earned below 85%.
(3) Shares earned at the end of the three-year performance period will remain
restricted, subject to continued employment for two additional years.
(4) Approval by the Corporation's Board of Directors of the ENSERCH/TUC Merger
constituted a "change in control" as defined in the 1991 Plan. As a
result, the forfeiture provisions with respect to these shares lapsed upon
such approval.
20
PENSION PLAN TABLE
The table below illustrates the amount of annual compensation benefit
payable on a normal retirement basis beginning at normal retirement age to a
person in specified average salary and years-of-service classifications under
the Retirement and Death Benefit Program of ENSERCH Corporation and
Participating Subsidiary Companies (the "Program"), the Income Restoration
Plan, and any annuities previously purchased in satisfaction of the
Corporation's pension obligations.
PENSION PLAN TABLE
YEARS OF SERVICE
--------------------------------------------------------------
REMUNERATION(1) 15 20 25 30 35 40 45
- --------------- -------- -------- -------- -------- -------- -------- --------
$275,000 $ 69,085 $ 92,114 $115,142 $138,170 $161,199 $168,074 $174,949
350,000 88,773 118,364 147,955 177,545 207,136 215,886 224,636
425,000 108,460 144,614 180,767 216,920 253,074 263,699 274,324
500,000 128,148 170,864 213,580 256,295 299,011 311,511 324,011
575,000 147,835 197,114 246,392 295,670 344,949 359,324 373,699
650,000 167,523 223,364 279,205 335,045 390,886 407,136 423,386
725,000 187,210 249,614 312,017 374,420 436,824 454,949 473,074
800,000 206,898 275,864 344,830 413,795 482,761 502,761 522,761
875,000 226,585 302,114 377,642 453,170 528,699 550,574 572,449
950,000 246,273 328,364 410,455 492,545 574,636 598,386 622,136
- --------
(1) Highest average covered compensation over any consecutive five-year
period.
Covered compensation under the Program includes base wages and annual
performance-based bonuses. The credited years of service under the Program, as
of February 29, 1996, for Messrs. Biegler, Bryan, Hunter, Rescoe and
Satterwhite 28.6, 26.6, 1.7, 1.6, and 30.5 years, respectively, and the
highest average covered compensation during any consecutive five-year period
for each of them is $774,780, $346,204, $317,962, $372,615, and $346,881,
respectively. The normal retirement benefit is in the form of a benefit
guaranteed for ten years and life thereafter and is not subject to any
deduction for Social Security or other offset amounts.
COMPENSATION OF DIRECTORS
Directors are compensated by an annual retainer fee of $20,000 plus $1,200
for each board or committee meeting attended with a maximum of $1,800 if more
than one meeting is held on the same day. In addition, a $2,400 per annum fee
is paid for services on a Board Committee, with an additional $1,200 per annum
paid to the Chairman of a Board Committee. Directors who are also officers of
the Corporation do not receive fees. Directors may elect, pursuant to a
Deferred Compensation Plan for Directors, to defer all or part of their
compensation each year. Deferred amounts, including any gain based upon the
experience of investments selected by the Director as provided in the Plan,
will be distributed upon retirement from the Board (or death) in a lump sum or
in equal annual installments over a ten-year period. A participant may elect a
lump-sum payment of both principal and interest at any time reduced by a
forfeiture amount as provided in the Plan.
Each non-employee director with one or more full years of service on May 9,
1994, will be provided with deferred compensation following retirement from
the Board (or upon his or her death while serving as a member of the Board)
payable in installments totaling $25,000 annually for a period of years equal
to years of service on the Board prior to May 9, 1994, not to exceed ten. A
Directors' Deferred Compensation Trust has been established, and an amount
sufficient to pay all amounts payable under the deferred compensation
arrangement is placed in the trust from time to time. Upon the replacement of
a director or the elimination of his position following a specified change in
control, a director may elect to receive in a lump sum the principal amount
discounted at 4% per annum over the number of years payments would have
otherwise been made. For service following May 9, 1994, each non-employee
director with less than ten full years of service on May 9, 1994, will receive
restricted stock following the completion of each full year of service for a
maximum of ten years (reduced
21
by the number of full years of service on May 9, 1994). Any year in which a
previous award of restricted stock is forfeited is not counted in computing
such maximum number of years. The number of shares of restricted stock awarded
is determined by dividing $25,000 by the average of the closing price of the
Common Stock for the last twenty trading days in April (the "Award Value").
The restricted period applicable to restricted stock awarded to non-employee
directors is ten years during which time the restrictions will be lifted if
the director dies, the market value of the Common Stock increases to 1.5 times
the Award Value, or if the average closing price for the twenty trading days
immediately preceding the tenth anniversary of the award date is equal to or
greater than the Award Value. If the restrictions have not been lifted by the
end of such ten-year period, the stock will be forfeited.
Mr. McCord represents the Corporation's interest in a foreign company in
which the Corporation once had an investment and has continuing obligations
for which he is paid a fee by the Corporation of $5,000 for each board meeting
of the foreign company attended. During 1996, such Board met once.
EMPLOYMENT CONTRACTS, TERMINATION OF EMPLOYMENT AND CHANGE-IN-CONTROL
ARRANGEMENTS
Each named executive officer has executed a change-in-control agreement with
the Corporation that sets forth certain benefits in the event their employment
is terminated subsequent to a change in control of the Corporation (as defined
in the Agreements). The Agreements are for continuous three-year terms until
terminated by the Corporation upon specified notice and continue for three
years following a change in control of the Corporation. The Agreements provide
that if the officer is terminated or if the officer elects to terminate
employment under certain circumstances within three years following a change
in control of the Corporation, the officer shall be entitled to a lump-sum
severance payment of three times the sum of the officer's base salary and
target bonus (but not in excess of the aggregate base salary that could be
earned up to the officer's normal retirement date), a prorated bonus in the
year of termination, the value over exercise price of certain unexercised
stock options, a three-year continuation of employee benefits, the equivalent
of two years of service credit under the retirement program, and reimbursement
of certain legal fees, expenses, and any exercise taxes. The approval of the
ENSERCH/TUC Merger on November 15, 1996, was a change in control under these
agreements.
Messrs. Biegler, Satterwhite and Rescoe have agreed with the Corporation to
the modification of their respective change-in-control agreements pursuant to
which, upon the satisfaction of all conditions prerequisite to the ENSERCH/TUC
Merger, and prior to the effective time of the ENSERCH/TUC Merger, ENSERCH
will pay each of these individuals a lump-sum cash payment in the amount of
$2,790,000 in the case of Mr. Biegler, $789,600 in the case of Mr. Satterwhite
and $784,000 in the case of Mr. Rescoe in lieu of (i) their respective rights
to receive such payment in the event the change-in-control agreement payment
provisions are subsequently activated and (ii) their respective rights to
receive any of the other benefits under the change-in-control agreements in
the event of a voluntary termination by them during the period from the
thirteenth through eighteenth month following a change in control. The
Corporation has also agreed to pay Mr. Biegler a bonus in the amount of
$900,000 prior to the effective time of the ENSERCH/TUC Merger conditioned
upon his continued employment with the Corporation to the effective time of
the ENSERCH/TUC Merger. The payments made to Messrs. Biegler, Satterwhite and
Rescoe and the modification of their change-in-control agreements will be
treated as payments under their existing change-in-control agreements
entitling them to any tax gross-up payments as therein provided. The
Corporation's Executive Deferred Compensation Plan has been amended so that
Messrs. Biegler, Satterwhite and Rescoe may defer all of the payments made
under the modification to their change-in-control agreements under such Plan.
Except for the foregoing modifications, the terms of the change-in-control
agreements of these employees will remain in effect following the ENSERCH/TUC
Merger.
Effective upon the closing of the ENSERCH/TUC Merger, the Corporation has
entered into retention bonus arrangements with G. R. Bryan and M. T. Hunter.
Under each of these arrangements, ENSERCH will pay the executive officer a
cash bonus equal to 50% of his current annual salary upon his attainment of
six months of continuous employment following the ENSERCH/TUC Merger and an
additional cash bonus equal to 100% of his current annual salary upon his
attainment of eighteen months of continuous employment following the
ENSERCH/TUC Merger. The bonus payments will not become payable in the event
that, on or prior to the
22
particular bonus payment date, the employee (i) terminates employment, (ii)
dies or becomes disable or (iii) is terminated for cause. For purposes of the
retention bonus arrangements, termination for cause means (i) an act or acts
of dishonesty or material violation of an employment policy by, or at the
direction of, the employee, (ii) willful failure or refusal of the employee to
perform services as properly required by TUC or the Corporation; (iii) any
action or failure to act on the part of the employee which is intended to
result in injury to the assets, business or prospects of TUC or the
Corporation or (iv) the employee's conviction of a felony.
BOARD COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
COMPENSATION COMMITTEE REPORT
The Board of Directors delegates responsibility for executive compensation
to the Compensation Committee, except compensation matters relating to the
Chairman and President, Chief Executive Officer are decided by the full Board,
after recommendation by the Committee. No member of the Committee is a former
officer or employee of the Corporation or any of its subsidiaries and no
member of the Committee participates in the compensation described in the
following report. The Committee retains its own consultant to advise on
matters related to executive compensation. The Corporation has used a
consultant since 1981 to assist in such matters. The following is the
Committee's report on executive compensation for 1996.
In determining executive compensation, the Committee is guided by three
primary objectives:
--Offer incentive for business success by putting a significant portion of
each executive's total pay at risk, based on company performance
(observing in the short term desirable operating results and, in the long
term, total shareholder return).
--Attract and keep outstanding executives by providing compensation
opportunities consistent with those observed in the Corporation's industry
for similar positions.
--Encourage career service by providing retirement income consistent with
industry practice.
The Committee's action regarding compensation of executives in the first
quarter of the year was consistent with past practices and the above stated
objectives. However, compensation matters were impacted by the Board's
decision in April of 1996 to merge with TUC, change-in-control provisions of
various plans, and the issues that developed while posturing the Corporation
for the transition into TUC.
Salary levels for the named executive officers are based upon assessment of
each individual's performance, experience and value in attaining corporate
financial and strategic objectives and are set within salary ranges based on
surveys of prevailing practice with the mid-point targeted for the expected
level of performance, experience and value. The Committee, in its salary
decisions, is guided by these comparative data, and by the annual rate of
salary movement in industries in which the Corporation competes for
executives. The Corporation compares its annual cash payments (salary and
performance incentive) for named executive officers to recognized annual
surveys both in its industry and in industry generally. The Corporation also
uses comparisons with such surveys for guidance in hiring executives. General
industry practice is observed, as it has been for over a decade, from
Management Compensation Service's (MCS) annual survey of executive
compensation (385 companies participated in 1996). Gas and petroleum industry
practice is observed from surveys conducted by the American Gas Association
and by a major national consulting firm. Together they constitute a
statistically valid data base for this purpose, and the Committee is guided by
it. Many of the companies in the MCS survey are in the S&P 500; the industry
specific surveys used include many of those companies found in the performance
graph's gas industry peer group. The sole use of the smaller number of
companies in that peer group would produce pay data comparisons that are not
statistically meaningful or useful for the purpose of salary comparisons, nor
does the group of companies in that peer group include necessarily all of the
companies that are the most direct competitors for executive talent.
During 1996, the aggregate salaries of the named executive officers summed
to an amount equal to 2.38% below the sum of the size-adjusted median survey
salaries for their positions. Four of the named executive
23
officers received salary increases during 1996, which, on an annualized basis,
amounted to 1.14% of the named executive officers' aggregate salaries.
It is the practice of the Corporation, which is endorsed and effected by the
Committee, to encourage both desirable annual operating results and long term
total shareholder return by annual incentive opportunities that put an
important portion of total pay at risk subject to the achievement of financial
and operating goals. The portion of compensation at risk is intentionally
higher at higher levels in the Corporation. Consequently much of a named
executive officer's compensation is at risk, with potential annual and long-
term incentives, at target levels, placing up to 50% of total compensation
opportunity at risk. The Committee also considers comparative data when
determining the size of both annual and long-term incentive awards.
The named executive officers participate in the Corporation's Performance
Incentive Plan. The level of this opportunity is designed to be consistent
with industry practice. Their target awards in 1996 ranged from 40% to 55% of
salary. Change-in-control provisions of the plan caused payment of bonuses
during the year to each named executive officer equivalent to 100% of goal
achievement.
The Corporation in 1996 offered additional incentive for stock price growth
and total shareholder return through the award of performance-based restricted
stock and stock options under the 1991 Stock Incentive Plan, in which all
named executive officers participated. Performance-based restricted stock and
stock option awards to them in 1996 and options held by them at year end are
described in the Tables. The awards of performance-based restricted stock are
subject to forfeiture in whole or in part unless specific performance goals
which have been determined by the Compensation Committee are achieved. Awards
in 1996 were made to achieve the earlier stated objective of causing a
significant portion of each executive's total pay to be at risk and dependent
on total shareholder return primarily through stock price growth as well as
the objective of keeping outstanding executives by providing compensation
opportunities similar to those provided in the Corporation's industry. In
doing so, the Committee considered the number of options already owned by each
named executive, if any, and the objective that each such person have an
important incentive for stock price gain. In determining the size of
performance-based restricted stock and stock option awards, the Committee used
its discretion and was not bound by any pre-adopted formulas. For Messrs.
Biegler, Satterwhite and Rescoe, it took into account the size of awards of
performance-based restricted stock and stock options awarded to them by EEX,
an 83%-owned subsidiary. Change-in-control provisions of the 1991 Stock
Incentive Plan caused restrictions on the performance-based restricted stock
to be lifted and full vesting of stock option awards as shown in the Tables.
The Corporation encourages career employment, and it is endorsed by our
Committee. Its retirement benefits are an essential part of that policy. They
are described, for the named executive officers, in the Retirement Benefit
Table and its footnotes. The Committee periodically reviews executive
retirement benefits to ensure that they continue to meet the Corporation's
needs and are consistent with good corporate practice.
No formal policy has been adopted by the Corporation with respect to
qualifying compensation paid to its executive officers for deductibility under
Section 162(m) of the Internal Revenue Code. In the event that any new
compensation programs are proposed in the future, it is expected that they
will be structured with a view toward qualifying for deductibility just as
were the amendments to the 1991 Stock Option Plan as approved by shareholders
in 1994. The Committee does not anticipate that current compensation levels
will result in loss of any tax deductibility.
A decision by the Board to terminate the Special Supplemental Compensation
Plan resulted in an accelerated accrual for the account of D. W. Biegler as
described in a note to the Summary Compensation Table. Change-in-control
provisions of a trust relating to an expired employment contract for W. T.
Satterwhite resulted in an accrual during the year as described in a note to
the Summary Compensation Table.
Compensation Committee
Marvin G. Girouard, Chairman
Odie C. Donald
Thomas W. Luce, III
24
PERFORMANCE GRAPH
Set forth below is a line graph comparing for the last five fiscal years the
yearly percentage change in the cumulative total shareholder return on the
Corporation's Common Stock against the cumulative total return of the S&P 500
Composite Stock Index and peer-group index. The graph assumes that the value
of the investment in the Corporation's Common Stock and each index was $100 at
December 31, 1991, and that all dividends are reinvested. The returns of each
component company have been weighted according to their respective stock
market capitalization at the beginning of each period for which a return is
indicated.
COMPARISON OF FIVE-YEAR CUMULATIVE TOTAL RETURN
[CHART]
1991 1992 1993 1994 1995 1996
---- ---- ---- ---- ---- ----
December 31,
ENSERCH......................................... 100 110 128 105 131 188
S&P 500......................................... 100 108 118 120 165 203
Peer Index(1)................................... 100 105 120 104 141 182
- --------
(1) The Peer Group consists of Chesapeake Utilities, Columbia Gas System,
Consolidated Natural Gas, Eastern Enterprises, Energen Corporation,
ENSERCH Corporation, Equitable Resources, K N Energy Inc., National Fuel &
Gas, National Gas & Oil, Noram, Inc., ONEOK Inc., Pennsylvania
Enterprises, Questar Corporation, South Jersey Industries, Southwest Gas
Corporation, Southwestern Energy, UGI Corporation, Valley Resources,
Washington Energy, and Wicor Inc. In 1995, the American Gas Association
("AGA") Diversified/Integrated company index provided total return data
for the above companies. Since the AGA no longer publishes that index,
data are now calculated by the Corporation.
25
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
At various times during 1996, the following individuals served as a member
of the Corporation's Compensation Committee: Mr. Frederick S. Addy, Mr. Odie
C. Donald, Mr. Marvin J. Girouard and Mr. Thomas W. Luce, III. None of these
persons was or has been an officer or employee of the Corporation or any of
its subsidiaries, except that Mr. Addy served as interim Chairman and
President of EEX, following his resignation from the Corporation's Board of
Directors.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
The Corporation is aware of the following beneficial owner, as of December
31, 1996, of more than 5% of its Common Stock.
NAME AND ADDRESS NUMBER OF SHARES PERCENT
BENEFICIAL OWNER BENEFICIALLY OWNED OF CLASS
---------------- ------------------ --------
Wellington Management Company....................... 5,008,450(1) 7.19%
75 State Street
Boston, MA 02109
Prudential Insurance Company of America............. 3,664,300(2) 5.49%
751 Broad Street
Newark, NJ 07102-3777
- --------
(1) These common shares were reported as being owned primarily by The
Vanguard/Windsor Fund, Inc. of the Vanguard Group of Investment Companies
whom Wellington Management Company serves as investment adviser.
Wellington Management Company reported the beneficial ownership of 177,500
shares with shared voting power and 5,008,450 shares with shared
dispositive power. The shares beneficially owned by The Vanguard/Windsor
Fund, Inc. include 4,669,000 shares with sole voting power and shared
dispositive power.
(2) Includes 248,393 shares with sole voting and dispositive power, 3,576,700
shares with shared voting power and 3,664,300 shares with shared
dispositive power.
26
STOCK OWNERSHIP OF MANAGEMENT AND BOARD OF DIRECTORS
Each director, the named executive officers, and all directors and executive
officers as a group, reported beneficial ownership as of February 28, 1997, of
Common Stock of the Corporation and EEX as follows:
ENSERCH EEX
------------------------- ---------------------
NUMBER OF NUMBER OF
SHARES SHARES
BENEFICIALLY PERCENT BENEFICIALLY PERCENT
NAME OWNED(1) OF CLASS OWNED(2) OF CLASS
---- ------------ -------- ------------ --------
D. W. Biegler................. 307,923(3) * 46,000(4) *
B. A. Bridgewater, Jr......... 5,944 * 1,000 *
Odie C. Donald................ 1,809 * 0 *
Marvin J. Girouard............ 4,144 * 0 *
J. M. Haggar, Jr.............. 5,432 * 0 *
Thomas W. Luce, III........... 1,500 * 0 *
W. C. McCord.................. 66,301 * 2,000 *
Diana S. Natalicio............ 3,444 * 0 *
G. R. Bryan................... 99,879(3)(5) * 0 *
M. T. Hunter.................. 53 * 0 *
W. T. Satterwhite............. 105,159(3) * 9,500(4) *
M. E. Rescoe.................. 28,512(3) * 20,008(4) *
All Directors and Executive
Officers as a Group.......... 740,643 1.1 83,378 *
- --------
* Less than 1%
(1) The number of shares owned includes shares held in the Corporation's
Employee Stock Purchase and Savings Plan.
(2) The number of shares owned includes shares held in the Corporation's
Employee Stock Purchase and Savings Plan and restricted shares awarded
under the EEX Revised and Amended 1996 Stock Incentive Plan, where
applicable.
(3) The totals include shares subject to stock options exercisable within 60
days of the Record Date: D. W. Biegler 246,948 shares; W. C. McCord 65,000
shares; G. R. Bryan 68,675 shares; W. T. Satterwhite 63,000 shares;M. E.
Rescoe 24,000 shares; and all directors and executive officers as a group
541,123 shares.
(4) The totals include shares subject to stock options exercisable within 60
days of the Record Date: D. W. Biegler 35,000 shares; W. T. Satterwhite
7,500 shares; M. E. Rescoe 14,000 shares; and all directors and executive
officers as a group 56,500 shares.
(5) Of the shares listed, 64 are shares deemed beneficially owned by Mr. Bryan
because of sole or shared voting or investment power.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
SECTION 16(A) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
Section 16(a) of the Securities Exchange Act of 1934 requires the officers
and directors of the Corporation, and persons who own more than 10% of a
registered class of the equity securities of the Corporation, to file reports
of beneficial ownership and changes in beneficial ownership with the SEC and
the New York Stock Exchange. Based solely on its review of the copies of such
reports received by it, or written representations from certain reporting
persons that no Forms 5 were required for those persons, the Corporation
believes that during 1996, its officers, directors and greater than 10%
shareholders complied with all applicable filing requirements, except for the
following: one report covering one transaction was filed approximately 30 days
late by Mr. D. R. Long, an executive officer of the Corporation, following the
exercise of options; one report covering five transactions and one report
covering three transactions were filed 85 days and 35 days late, respectively,
by Mr. W. C. McCord, a Director of the Corporation, following the exercise of
options.
27
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
(A)-1 FINANCIAL STATEMENTS
The following items appear in the Financial Information section included in
Appendix A to this report:
ITEM PAGE
---- ----
Selected Financial Data................................................. A-2
Financial Review........................................................ A-4
Natural Gas and Oil Exploration and Production Operating Data.......... A-11
Natural Gas Pipeline, Processing & Marketing Operating Data............ A-12
Natural Gas Distribution Operating Data................................ A-13
Independent Auditors' Report............................................ A-14
Management Report on Responsibility for Financial Reporting............. A-15
Financial Statements:
Statements of Consolidated Income...................................... A-16
Statements of Consolidated Cash Flows.................................. A-17
Consolidated Balance Sheets............................................ A-18
Statements of Consolidated Common Shareholders' Equity................. A-19
Notes to Consolidated Financial Statements.............................. A-20
Summary of Business Segments............................................ A-39
Quarterly Results....................................................... A-40
Common Stock Market Prices and Dividend Information..................... A-41
(A)-2 FINANCIAL STATEMENT SCHEDULES
The 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:
2.1* Amended and Restated Agreement and Plan of Merger dated as of April
13, 1996, to the Corporation's Proxy Statement dated September 23,
1996.
2.2* Stock Option Agreement dated as of April 13, 1996, attached as Annex
II to the Corporation's Proxy Statement dated September 23, 1996.
2.3* Form of Agreement and Plan of Distribution included as Exhibit A to
the Plan of Merger attached as Annex I to the Corporation's Proxy
Statement dated September 23, 1996.
3.1 Restated Articles of Incorporation of the Corporation currently in
effect.
3.2* Bylaws of the Corporation, filed as Exhibit 3.2 to the Corporation's
Form 10-K for the year ended December 31, 1994.
4.1* Shareholder Rights Plan, filed as an Exhibit to the Corporation's Form
8-A dated March 26, 1996.
Executive Compensation Plan and Arrangements (Exhibits 10.1 though 10.11):
10.1* ENSERCH Corporation Deferred Compensation Plan for Directors, filed as
Exhibit 10.2 to the Corporation's Form 10-K for the year ended
December 31, 1994.
10.2* Director's Deferred Compensation Trust Agreement, as amended, and
currently in effect, filed as Exhibit 10.3 to the Corporation's Form
10-K for the year ended December 31, 1991.
10.3* 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 the Corporation's Form
10-K for the year ended December 31, 1991.
28
10.4* ENSERCH Corporation 1981 Stock Option Plan, as amended, and currently
in effect, as filed as Exhibit 10.6 to the Corporation's Form 10-K
for the year ended December 31, 1991.
10.5 Form of Change of Control Agreement executed by certain executive
officers of the Corporation.
10.6 ENSERCH Corporation, Lone Star Gas Company, Lone Star Pipeline
Company, Lone Star Pipeline Company--Processing Division, and Power
Group Performance Incentive Plans--Calendar Year 1997.
10.7* ENSERCH Corporation 1991 Stock Incentive Plan, filed as Exhibit 10.12
to the Corporation's Form 10-K for the Year Ended December 31, 1990.
10.8 ENSERCH Corporation Deferred Compensation Plan dated September 30,
1994 and Amendment No. 1 thereto dated March 28, 1995, Amendment No.
2 dated January 1, 1996, Amendment No. 3 dated September 23, 1996,
Amendment No. 4 dated November 6, 1996 and Amendment No. 5 dated
February 18, 1996.
10.9 ENSERCH Corporation Deferred Compensation Trust dated September 30,
1994, and Amendment No. 1 thereto effective January 1, 1996.
10.10 ENSERCH Corporation Retirement Income Restoration Plan dated December
28, 1990, and Amendment No. 1 thereto dated September 30, 1994,
Amendment No. 1-A dated February 13, 1996, and Amendment No. 2
effective January 1, 1996.
10.11 ENSERCH Corporation Retirement Income Restoration Trust dated
September 30, 1994, and Amendment No. 1 thereto effective January 1,
1996.
10.12* Form of Tax Allocation Agreement included as Exhibit B to the Plan of
Merger attached as Annex I to the Corporation's Proxy Statement dated
September 23, 1996.
10.13* Form of Tax Assurance Agreement included as Exhibit C to the Plan of
Merger attached as Annex I to the Corporation's Proxy Statement dated
September 23, 1996.
21 Subsidiaries of the Corporation.
23.1 Deloitte & Touche LLP consent to incorporation by reference in
Registration Statements No. 2-59259, No. 2-77572, No. 33-15623, No.
33-40589, No. 33-47911, No. 33-52525, No. 33-61635 and No. 333-12391.
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, No. 33-52525,
No. 33-61635 and No. 333-12391.
24 Powers of Attorney.
27 Financial Data Schedule.
99* Proxy Statement of the Corporation dated September 23, 1996, as filed
with the SEC.
- --------
* Incorporated herein by reference and made a part hereof.
Long-term debt is described in Note 3 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.
(B) REPORTS ON FORM 8-K
Current Report on Form 8-K dated November 22, 1996, was filed on November
22, 1996 (Results of vote on proposals at Special Meeting of Shareholders held
on November 15, 1996).
29
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
By: /s/ D. W. Biegler
-----------------------------------
D. W. BIEGLER,
CHAIRMAN AND PRESIDENT,
CHIEF EXECUTIVE OFFICER
March 27, 1997
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS
REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS IN THE CAPACITIES AND ON
THE DATE INDICATED.
SIGNATURE AND TITLE DATE
D. W. Biegler, Chairman and
President, Chief Executive Officer
and Director; B. A. Bridgewater,
Jr., Director; Odie C. Donald,
Director; Marvin J. Girouard,
Director; Joseph M. Haggar, Jr.,
Director; Thomas W. Luce, III,
Director; W. C. McCord, Director;
Diana S. Natalicio, Director; M. E.
Rescoe, Senior Vice President, March 27, 1997
Finance and Chief Financial Officer;
J. W. Pinkerton, Vice President and
Controller, Chief Accounting Officer
By: /s/ D. W. Biegler
-----------------------------------
D. W. BIEGLERINDIVIDUALLY AND
ASATTORNEY-IN-FACT
30
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
INDEX TO FINANCIAL INFORMATION
DECEMBER 31, 1996
PAGE
----
Selected Financial Data.................................................... A-2
Financial Review........................................................... A-4
Natural Gas and Oil Exploration and Production Operating Data............ A-11
Natural Gas Pipeline, Processing & Marketing Operating Data.............. A-12
Natural Gas Distribution Operating Data.................................. A-13
Independent Auditors' Report............................................... A-14
Management Report on Responsibility for Financial Reporting................ A-15
Financial Statements:
Statements of Consolidated Income........................................ A-16
Statements of Consolidated Cash Flows.................................... A-17
Consolidated Balance Sheets.............................................. A-18
Statements of Consolidated Common Shareholders' Equity................... A-19
Notes to Consolidated Financial Statements................................. A-20
Summary of Business Segments............................................... A-39
Quarterly Results.......................................................... A-40
Common Stock Market Prices and Dividend Information........................ A-41
A-1
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
SELECTED FINANCIAL DATA
AS OF OR FOR YEAR ENDED DECEMBER 31
----------------------------------------------------------------------
1996 1995 1994 1993 1992 1991
-------- -------- -------- -------- -------- --------
(IN MILLIONS EXCEPT RATIO AND PER SHARE AMOUNTS)
INCOME STATEMENT DATA
Revenues (a)
Natural gas and oil
exploration and
production............. $ 331.2 $ 220.9 $ 179.3 $ 189.8 $ 171.5 $ 183.6
Natural gas pipeline,
processing &
marketing.............. 1,126.5 996.4 1,235.6 908.0 639.5 590.4
Natural gas
distribution........... 895.2 893.8 881.3 973.9 923.4 913.2
Power and other......... 37.8 39.8 45.5 48.6 45.7 37.3
Less intercompany
revenues............... (248.1) (219.7) (246.2) (241.4) (152.4) (159.8)
-------- -------- -------- -------- -------- --------
Total revenues.......... 2,142.6 1,931.2 2,095.5 1,878.9 1,627.7 1,564.7
Operating Income
(Loss) (a)
Natural gas and oil
exploration and
production............. 32.2 (12.0) 25.4 (b) (37.3)(c) (6.2)(b) 10.9
Natural gas pipeline,
processing &
marketing.............. 63.4 60.1 27.2 73.4 67.7 78.7
Natural gas
distribution........... 68.2 54.6 38.3 34.2 (d) 48.4 54.1
Power and other......... (8.2) 3.5 5.8 9.8 13.4 6.1
General and other....... (9.3) (8.5) (8.1) (11.9) (16.8) (15.4)
-------- -------- -------- -------- -------- --------
Total operating income.. 146.3 (e) 97.7 88.6 68.2 106.5 134.4
Other Income (Expense)--
Net (f)................. (11.2) (1.0) (6.0) .1 (12.6) 14.6
Interest and Other
Financing Costs......... (94.9) (83.3) (69.3) (77.7) (94.5) (92.9)
Income (Taxes) Benefit... (15.7) (.9) 68.7 (g) (6.6)(g) 2.2 (17.8)
Minority Interest........ (1.8) .6 (.5) -- .2 (.5)
-------- -------- -------- -------- -------- --------
Income (Loss) from
Continuing Operations... 22.7 13.1 81.5 (16.0) 1.8 37.8
Income (Loss) from
Discontinued
Operations.............. (1.6) 20.6 75.4 (13.8) (18.6)
Extraordinary Loss on
Extinguishment of Debt.. (2.1) -- -- -- (15.3) --
-------- -------- -------- -------- -------- --------
Net Income (Loss)........ 19.0 13.1 102.1 59.4 (27.3) 19.2
Earnings (Loss)
Applicable to Common
Stock................... 7.7 1.4 90.5 46.7 (40.3) 4.9
Per Share of Common Stock
Income (loss) from
continuing operations
after provision for
preferred dividends.... .16 .02 1.03 (.42) (.16) .35
Discontinued
operations............. (.02) -- .30 1.11 (.21) (.28)
Extraordinary loss...... (.03) -- -- -- (.23) --
-------- -------- -------- -------- -------- --------
Earnings (loss)
applicable to common
stock.................. .11 .02 1.33 .69 (.60) .07
Average Common and
Dilutive Common
Equivalent Shares
Outstanding............. 69.4 68.3 68.0 67.8 66.9 66.3
- --------------------------------------------------------------------------------
COMMON STOCK DATA
Cash Dividends Declared
and Paid................ $ .20 $ .20 $ .20 $ .20 $ .80 $ .80
Market Price
High.................... 23 3/4 18 5/8 19 1/8 22 5/8 16 1/2 21 3/8
Low..................... 14 1/8 12 5/8 12 1/8 14 1/8 10 3/8 12 3/4
Common Shareholders'
Equity per Share........ 10.58 10.50 10.65 9.54 9.00 10.32
Shares Outstanding at
Year-end................ 70.3 68.5 68.2 67.9 67.2 66.5
- --------------------------------------------------------------------------------
BALANCE SHEET DATA
Property, Plant and
Equipment--Net.......... $2,943.4 $2,726.8 $2,253.5 $2,119.1 $2,065.9 $2,152.2
Total Assets............. 3,744.6 3,381.1 2,888.5 2,806.0 3,158.9 3,169.8
Net Working Capital
(Deficiency)............ (115.5) (185.5) (157.1) (191.8) 2.5 (42.5)
Current Ratio............ .85 .74 .77 .74 1.00 .95
Unused Revolving or Line
of Credit Agreements.... $ 490.0 $ 600.0 $ 600.0 $ 635.0 $ 485.0 $ 650.0
- --------------------------------------------------------------------------------
CAPITAL STRUCTURE
Senior Long-term Debt.... $ 958.5 $ 885.2 $ 726.3 $ 640.0 $ 865.3 $ 757.6
Convertible Subordinated
Debentures.............. 90.8 90.8 90.8 90.8 90.8 205.7
Mandatorily Redeemable
Preferred Securities of
Subsidiary of EEX....... 150.0 150.0 -- -- -- --
Minority Interest in
Subsidiaries............ 159.4 156.4 12.1 8.8 5.1 5.5
Preferred Stock.......... 175.0 175.0 175.0 175.0 175.0 175.0
Common Shareholders'
Equity.................. 743.4 719.2 726.2 647.6 605.4 686.5
-------- -------- -------- -------- -------- --------
Total Capitalization.... 2,277.1 2,176.6 1,730.4 1,562.2 1,741.6 1,830.3
Senior Long-term and
Convertible Debt Ratio
(Percent)............... 46.1 44.8 47.2 46.8 54.9 52.6
See Notes on page A-3.
A-2
NOTES TO SELECTED FINANCIAL DATA
(a) Revenues and operating income (loss) by segments have been restated to
reflect the realignment of certain businesses between segments to conform
to the 1996 presentation.
(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 ($10.9 million after-tax, $.16 per
share) write-down of the inactive offshore pipeline and facilities.
(c) Includes a $41.4 million pretax ($26.9 million after-tax, $.40 per share)
charge as a result of an adverse judgment in litigation and a $13.3
million pretax ($8.6 million after-tax, $.13 per share) write-down of non-
U.S. gas and oil properties.
(d) Includes a $12.0 million pretax ($7.8 million after-tax, $.12 per share)
charge principally for severance expenses associated with re-engineering
distribution operations.
(e) Includes a $5.8 million pretax ($3.8 million after-tax, $.05 per share)
charge for merger related expenses.
(f) 1996 includes $6.8 million pretax ($6.7 million after-tax, $.10 per share)
of expenses related to the pending merger with Texas Utilities Company and
income of $2.2 million pretax ($1.4 million after-tax, $.02 per share)
from the early termination of an interest-rate swap; 1992 includes a $15.5
million pretax ($10.2 million after-tax, $.15 per share) provision for
litigation; 1991 includes a $15.1 million pretax ($10.0 million after-tax,
$.15 per share) gain from the sale of Oklahoma utility properties and non-
U. S. gas and oil assets.
(g) 1994 includes a $70.0 million ($1.03 per share) reduction of deferred
income taxes associated with the reorganization of partnerships to form
Enserch Exploration, Inc. 1993 includes a $10.8 million ($.16 per share)
charge from the 1% increase in the statutory federal income-tax rate on
corporations.
A-3
ENSERCH CORPORATION
FINANCIAL REVIEW
MERGER WITH TUC
On April 15, 1996, ENSERCH Corporation announced that it had entered into a
merger agreement with Texas Utilities Company (TUC). Prior to the merger,
ENSERCH's approximate 83% interest in Enserch Exploration, Inc. (EEX),
represented by approximately 105 million shares of EEX common stock, will be
distributed to ENSERCH shareholders. Lone Star Gas Company and Lone Star
Pipeline Company, the local distribution and pipeline companies of ENSERCH,
and other businesses will become a part of TUC. Based on ENSERCH shares
outstanding at December 31, 1996 and its financial statements as of that date,
TUC will acquire these operations through the issuance of approximately $560
million of TUC common stock and the assumption of ENSERCH debt and preferred
stock of approximately $1.25 billion.
Within a $4.00 (approximately 10%) price range variation above or below the
April 12, 1996 closing price of TUC common stock ($39.625 per share), each
holder of ENSERCH common stock will receive sufficient shares of TUC common
stock to provide $8.00 of value. Based on the December 31, 1996 closing price
of TUC common stock of $40.75, each ENSERCH share would be converted into
approximately .2 shares of TUC common stock. Above or below the 10% threshold,
the value received will move up or down pro rata with the price of TUC common
stock. Also, based on the ENSERCH shares outstanding at December 31, 1996 and
estimated EEX shares to be owned by ENSERCH, each holder of ENSERCH common
stock would receive approximately 1.5 shares of EEX common stock. The final
determination of TUC and EEX shares received by ENSERCH shareholders will be
based on the value of the TUC shares for a specified period prior to closing
and the actual number of ENSERCH and EEX shares outstanding on the closing
date.
The transaction was approved at special meetings of the shareholders of
ENSERCH, EEX and TUC held separately on November 15, 1996. All regulatory
approvals have been received, except for approval by the Securities and
Exchange Commission (SEC) under the Public Utility Holding Company Act of 1935
where the approval process is proceeding. The Railroad Commission of Texas
(RRC) has indicated no objection to the transaction, and the Antitrust
Division of the U.S. Department of Justice (DOJ) has notified ENSERCH and TUC
that its investigation of the transaction has been closed without the DOJ
taking any action or requiring TUC or ENSERCH to take any action. ENSERCH has
also received a favorable tax ruling from the Internal Revenue Service to the
effect that neither ENSERCH nor its shareholders will recognize taxable gain
on the distribution of EEX shares to ENSERCH common shareholders.
RESULTS OF OPERATIONS
Earnings applicable to common stock for the year 1996 were $7.7 million
($.11 per share), compared with $1.4 million ($.02 per share) for 1995 and $90
million ($1.33 per share) for 1994. The 1996 results were affected by several
unusual items which totaled $12.7 million, or $.18 per share. Excluding these,
there was a year-to-year improvement in earnings of $19 million, or $.27 per
share. The unusual items include $9.0 million after-tax ($10.4 million pretax)
affecting income from continuing operations for expenses associated with the
pending distribution of EEX shares to ENSERCH shareholders and merger of
ENSERCH with TUC, net of a $1.4 million after-tax ($2.2 million pretax) gain
on early termination of an interest-rate swap; a $2.1 million after-tax
extraordinary charge from an early extinguishment of debt to facilitate the
merger; and a $1.6 million loss from discontinued operations.
CONTINUING OPERATIONS, INCLUDING EXPLORATION AND PRODUCTION OPERATIONS
Income from continuing operations (including exploration and production
operations), after provision for preferred dividends, was $11.4 million ($.16
per share) in 1996, $1.4 million ($.02 per share) in 1995 and $70 million
($1.03 per share) in 1994. The 1996 results included several unusual items
that reduced income from continuing operations by $9.0 million ($.13 per
share), while 1994 benefited from nonrecurring items that together totaled $75
million ($1.10 per share). Excluding these unusual items from 1996 and 1994
results, income
A-4
from continuing operations for 1996 was $20.4 million ($.29 per share),
compared with $1.4 million ($.02 per share) in 1995 and a loss of $5.1 million
($.07 per share) in 1994. The 1994 nonrecurring items included a $70 million
reduction of deferred income taxes associated with the reorganization of
partnerships to form EEX and a $4.9 million after-tax ($7.6 million pretax)
gain by EEX from the sale of assets.
Operating income for 1996 was $146 million versus $98 million in 1995 and
$89 million in 1994. Operating income for 1996 was reduced $5.8 million by
merger related expenses, and operating income for 1994 benefited from the $7.6
million gain from the sale of assets. Excluding these unusual items, operating
income was $152 million, $98 million and $81 million for 1996, 1995 and 1994,
respectively. Variations in revenues and operating income for each business
segment are discussed below.
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION
Reserves
EEX's natural-gas reserves at January 1, 1997 were 1.22 trillion cubic feet
(Tcf), compared with 1.36 Tcf the year earlier, as estimated by DeGolyer and
MacNaughton, independent petroleum consultants. Additions to and purchases of
natural-gas reserves in 1996 replaced gas produced from retained properties
after adjusting for the sale of 124 billion cubic feet (Bcf) of gas reserves.
As a result, natural-gas reserves at year-end 1996 for retained properties
were little changed from the year earlier. Oil and condensate reserves of 59
million barrels (MMBbls) at January 1, 1997 were 8.6 MMBbls below the year-
earlier level, after adjusting for the sale of 3.7 MMBbls. The decrease
resulted principally from downward revisions of 8.2 MMBbls at EEX's deep-water
projects in the Gulf of Mexico, primarily due to the performance of two
producing wells at the Cooper project in the Garden Banks area and the
thinning of some previously mapped reservoirs as a result of additional
drilling at the Allegheny project in the Green Canyon Block 254 area.
Operating Results
Operating income of the natural gas and oil exploration and production
business segment is strongly influenced by fluctuations in product prices and
volumes as shown in the table of Operating Data. Operating income for 1996 was
$32 million, compared with a loss of $12 million for 1995 and income of $25
million in 1994, which benefited from the previously noted $7.6 million gain
from the sale of assets.
The significant improvement in operating results from 1995 to 1996 primarily
resulted from higher commodity prices and a full year of production from the
properties acquired in 1995 and from the Cooper project which began producing
in late September 1995, partially offset by increases in related operating
costs. Revenues for 1996 of $331 million were $110 million higher than in
1995, reflecting a $64 million increase in natural-gas revenues and a $46
million improvement in oil and other revenues. The average natural-gas sales
price per thousand cubic feet (Mcf) was $2.20 in 1996, compared with $1.74 in
1995, and sales volumes of 101 Bcf were 11% greater than in 1995. The higher
oil revenues reflect a 15% improvement in the average sales price and a 52%
increase in sales volumes. Operating expenses for 1996 were $66 million higher
than in 1995, with about $35 million of the increase attributable to costs
associated with the acquired properties and some $25 million of the increase
related to direct costs of the Cooper project. The $6 million net increase in
all other expenses reflects higher general and administrative (G&A) costs and
increased exploration expenses, principally international. G&A costs for 1996
include expenses associated with the pending distribution and merger and costs
related to changes in EEX management.
Excluding the impact of the acquired properties, which contributed income of
$6.9 million to 1995 operating results, and the $7.6 million gain from the
sale of assets in 1994, there was a decrease in operating results from 1994 to
1995 of $37 million. Revenues declined $29 million and operating expenses,
primarily related to the Cooper project, increased $8 million. Natural-gas
revenues for 1995, excluding acquired properties, decreased $37 million (25%),
caused by a 15% decline in the average sales price ($23 million) and a 12%
decrease in sales volumes ($14 million). The lower volumes in 1995 primarily
resulted from less capital spending to replace gas production due to low gas
prices and the normal decline in production. Oil revenues for 1995, excluding
acquired
A-5
properties, increased $8 million from 1994, reflecting a 10% improvement in
the average sales price and a 12% increase in sales volumes from the start-up
of production from the Cooper project and increased production from
exploration and development activities in North Texas.
Full-Cost Accounting Method
The total amortization rate per Mcf of natural-gas equivalent was $1.11 in
1996, compared with $1.04 in 1995 and $1.08 in 1994. The rate for 1996 was
unfavorably impacted by the downward reserve revisions in two offshore deep-
water projects. The 1995 rate benefited from reserve additions on the
Allegheny project and the properties acquired that year and the credit to
capitalized costs as a result of EEX's common stock sale in September 1995.
The SEC-prescribed full-cost accounting rules require registrants to
calculate the cost center ceiling limitation at the end of each quarter using
current prices and costs. The margin between the cost center ceiling and the
unamortized capitalized costs of U.S. gas and oil properties was over $500
million at December 31, 1996 based on average December 1996 prices of $3.37
per Mcf of natural gas and $23.33 per barrel of oil. Product prices generally
have the greatest impact on the cost center ceiling. Gas and oil prices are
subject to seasonal and other fluctuations and have declined sharply since the
end of 1996. If there is not a substantial improvement in prices or mitigating
changes in the other factors involved in the calculation by the end of the
first quarter, the carrying value of EEX's gas and oil properties almost
certainly will be above the SEC-prescribed cost center ceiling. Based on
circumstances existing through mid-March 1997 and assuming no pricing
improvement or mitigating changes, the projected first-quarter write-down of
capitalized costs would result in a non-cash, after-tax charge to the earnings
of EEX ranging from $225 to $250 million. After minority interest, the impact
on ENSERCH earnings of a non-cash, after-tax write-down of this magnitude
would range from $190 to $210 million, or approximately $3.00 per share of
common stock. A write-down will not affect the ENSERCH merger with TUC or the
ENSERCH businesses to be merged.
Hedging Results
EEX manages a portion of the risk associated with fluctuations in the price
of natural gas and oil through the use of hedging techniques such as gas and
oil swaps, collars and futures agreements. As a result of such hedge
transactions to fix the net prices to be received, losses or gains occur and
either offset or add to actual prices received to achieve the new fixed
prices. In total, gas and oil price hedging activities reduced 1996 revenues
by $20 million but increased 1995 and 1994 revenues by $.1 million and $4.3
million, respectively. At December 31, 1996, EEX had outstanding swaps,
collars and futures agreements that were entered into as hedges extending
through December 31, 1997 to exchange payments on 32 Bcf of natural gas and
365 thousand barrels of oil. At December 31, 1996, there were $3.0 million of
net unrealized and unrecognized hedging gains based on the difference between
the strike price and the NYMEX futures price for the applicable trading month.
In addition, there were $5.1 million of realized losses on hedging activities
which were deferred and will be applied as a reduction in revenues in January
1997, the month of physical sale of production.
NATURAL GAS PIPELINE, PROCESSING & MARKETING
Operating income from the natural gas pipeline, processing & marketing
segment was $63 million in 1996, $60 million in 1995 and $27 million in 1994.
The table of Operating Data provides revenue and other statistical data for
the segment.
Pipeline
Lone Star Pipeline Company had 1996 operating income of $47 million versus
$49 million in 1995 and $25 million in 1994. The lower results in 1996 were
primarily attributable to higher operating and maintenance expenses, while the
favorable comparison from 1994 to 1995 principally came from a $25 million
reduction in the cost of gas lost in transmission and significant out-of-
period adjustments made in 1994. Pipeline revenues for 1996 were $153 million,
compared with $143 million in 1995 and $141 million in 1994. Pipeline volumes
totaled 652 Bcf in 1996, up significantly from the 561 Bcf in 1995 and 542 Bcf
in 1994. Revenues from transporting gas for ultimate delivery to residential
and commercial customers are affected by seasonal temperature variations.
A-6
There was a near normal level of heating weather in 1996 versus below normal
levels in both 1995 and 1994. Below normal heating weather resulted in reduced
operating income for pipeline operations by an estimated $5 million in 1995
and some $4 million in 1994.
In the first quarter of 1997, the Corporation announced that it would
voluntarily credit customers for a transportation fee it discovered that was
legally charged according to the rate structure but was unintentionally
charged residential and commercial customers during the period 1991 through
1995. The amount of such refund is expected to be approximately $11 million.
In October 1996, Lone Star Pipeline Company filed a request with the RRC to
increase the rate it charges Lone Star Gas Company to store and transport gas
ultimately destined for residential and commercial customers in the 550 Texas
cities and towns served by Lone Star Gas Company. Lone Star Gas Company also
requested that the RRC separately set rates for costs to aggregate gas supply
for these cities. Rates currently in effect were set by the RRC in 1982. If
approved, the rate adjustment would increase annual revenues by approximately
$24.2 million. The purpose of the rate request is to allow for the recovery of
a substantial increase in the cost of doing business since 1982 and to cover
significant capital investments of approximately $420 million made during the
past 14 years to maintain and improve the reliability and safety of the
pipeline system and help reduce natural-gas supply costs. A number of cities
served by Lone Star Gas Company have joined together in opposing the rate
increase. The RRC is expected to make a final ruling on the matter in mid-May.
Gas Processing
Operating income for natural gas gathering and processing operations of
Enserch Processing, Inc. was $23 million in 1996, compared with $4.7 million
in 1995 and $1.2 million in 1994. 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. Overall margin on plant
sales for 1996 was approximately 70% higher than in both 1995 and 1994, with
the average NGL sales price per barrel of $15.93 up 37% from the 1995 average
price, which was virtually unchanged from 1994. NGL sales volumes for 1996 of
6.1 MMBbls were slightly ahead of both 1995 and 1994.
Gas Marketing
Gas marketing operations, which are conducted through Enserch Energy
Services, Inc. (EES), had an operating loss of $6.4 million in 1996, compared
with income of $6.1 million in 1995 and $.9 million in 1994. In June 1995,
ENSERCH completed business combinations with two retail marketing companies,
which expanded its energy services capabilities. The loss in 1996 was
attributable to both a sharp decline in gas margin, which was precipitated by
unusual markets in the first quarter of the year, and higher operating
expenses from integrating operations and developing information systems. The
higher income for 1995 compared with 1994 was primarily due to an improvement
in gas margin versus the year earlier, partially offset by an increase in
operating expenses. Revenues for 1996 were 10% higher than in 1995, with a 46%
increase in gas prices more than offsetting a 25% decline in sales volumes.
Revenues for 1995 were 25% lower than in 1994 due to both lower sales volumes
and gas prices. The decline in sales volumes for both 1996 and 1995 was
primarily due to the decision to de-emphasize some wholesale marketing and
focus on end use customers. As part of its natural gas marketing activities,
EES enters into forward contracts involving physical delivery of natural gas
and derivative financial instruments, including swaps, options, futures and
other contractual arrangements to offset price risks of gas supply. These
activities involve price commitments into the future and, therefore, give rise
to market risk. EES applies hedge accounting to its business activities. At
December 31, 1996, natural gas marketing operations had net commitments to
sell approximately 21 Bcf of natural gas through the year 2001 with offsetting
net financial positions to purchase approximately 22 Bcf. At December 31,
1996, there was a net unrealized and unrecognized gain of $.7 million on these
contracts.
NATURAL GAS DISTRIBUTION
The table of Operating Data reflects the effects of variable weather
patterns on natural gas distribution operations conducted by Lone Star Gas
Company. Operating income for 1996 was $68 million, compared with $55 million
in 1995 and $38 million in 1994. Overall margin on gas sales for 1996 was up
8% from 1995, reflecting distribution rate improvements and near normal levels
of heating weather in 1996 versus below normal levels in both 1995 and 1994.
Mild winter weather caused reductions in operating income for this segment of
an
A-7
estimated $5.5 million in 1995 and $3 million in 1994. The operating income
improvement from 1994 to 1995 reflects lower operating expenses resulting from
cost reduction measures initiated in prior years. Sales volumes to the
residential and commercial customer category in 1996 were 8% higher than in
1995, which was virtually the same as in 1994.
Distribution rate increases granted in 1996 will, on a normal weather basis,
increase annual revenues by approximately $6.3 million. Over 65% of Lone
Star's volumes sold to residential and commercial customers are now covered by
a weather normalization clause.
POWER AND OTHER
ENSERCH's power activities had a 1996 operating loss of $8.2 million,
compared with income of $3.5 million in 1995 and $5.8 million in 1994. The
segment's earnings from operating thermal and power projects were offset by
expenses of development activities and losses totaling $7.0 million, including
an accrual of $3.3 million to cover anticipated future losses, associated with
contracts entered into in prior years to transport gas to a cogeneration
project. No development projects were closed in the three years ended December
31, 1996. At year-end 1996, a 70%-owned 36-megawatt (MW) coal-fired
cogeneration facility was under construction in the People's Republic of
China. Phase I of the plant is expected to be completed in mid-1997; the
remainder in 1998. Also, the drilling phase of a geothermal project to be 15%-
owned was underway in Indonesia. Construction of the 300 to 400-MW power-
generation facility is scheduled to begin in 1997.
OTHER EXPENSES
Other expense in 1996 includes $6.8 million of professional fees and other
expenses associated with the pending distribution of shares of EEX and merger
of ENSERCH with TUC and a $2.2 million gain on the early termination of an
interest-rate swap in conjunction with EEX's refinancing of its obligations in
preparation for the distribution. The year 1994 included $2.7 million of costs
associated with the reorganization of partnerships to form EEX and a $1.4
million loss on the early redemption of sinking fund debentures. Other amounts
consist principally of gains on disposals of assets and interest income, less
losses from unconsolidated affiliates and discounts on sales of receivables.
Interest and other financing costs for 1996 were $95 million, compared with
$83 million in 1995 and $69 million in 1994. The increases in both 1996 and
1995 were primarily due to debt associated with the financing of the
acquisition in June 1995 by EEX.
DISCONTINUED OPERATIONS
A $1.6 million after-tax ($.02 per share) loss provision was recorded in the
fourth quarter of 1996 in recognition that certain claims and accounts
receivable were recently settled at amounts less than previously estimated and
that the period to wind up the discontinued engineering and construction
businesses will be longer than previously expected with attendant increases in
costs and expenses. The 1994 income from discontinued operations of $21
million ($.30 per share) arose from the sale of Enserch Environmental
Corporation, partially offset by a $10 million after-tax loss provision for
windup of other discontinued businesses. At December 31, 1996, discontinued
businesses had assets of $46 million, consisting principally of retained
claims and accounts receivable, and current and other liabilities and reserves
of $18 million. The Corporation has filed suit against certain parties to
recover amounts outstanding. Management expects that substantially all
disputes will be resolved by year-end 1997 and that adequate provision for
uncollectible claims and accounts receivable, income-tax matters and expenses
for windup of discontinued operations has been made.
The merger of ENSERCH with TUC will be preceded by the distribution of EEX
shares to ENSERCH common shareholders. To facilitate the distribution, Lone
Star Energy Plant Operations, Inc. (LSEPO), an indirect wholly owned
subsidiary of ENSERCH, will merge with EEX; LSEPO will be the surviving
corporation of that merger, and its name will be changed to Enserch
Exploration, Inc. The merger enables the distribution to be tax-free to
ENSERCH and its shareholders. LSEPO, under long-term contracts, operates and
maintains three cogeneration facilities.
A-8
Following the distribution, the historical financial statements of ENSERCH
will be restated to reflect the exploration and production segment and LSEPO
as discontinued operations. ENSERCH's restated results of operations will be
as follows:
YEAR ENDED DECEMBER 31
---------------------------
1996 1995 1994
------- -------- --------
(IN THOUSANDS)
Income (Loss) from Continuing Operations.......... $ 9,751 $ 21,362 $ (5,661)
Income (Loss) from Discontinued Operations:
Engineering and Construction.................... (1,560) -- 20,642
Exploration and Production*..................... 12,947 (8,309) 87,113
Extraordinary Loss on Extinguishment of Debt...... (2,096) -- --
------- -------- --------
Net Income........................................ 19,042 13,053 102,094
Provision for Dividends on Preferred Stock........ 11,339 11,690 11,619
------- -------- --------
Earnings Applicable to Common Stock............... $ 7,703 $ 1,363 $ 90,475
======= ======== ========
Per Share of Common Stock:
Income (loss) from continuing operations after
provision for preferred dividends.............. $ (.02) $ .14 $ (.25)
Discontinued operations......................... .16 (.12) 1.58
Extraordinary loss.............................. (.03) -- --
------- -------- --------
Earnings applicable to common stock............. $ .11 $ .02 $ 1.33
======= ======== ========
- --------
* The following reconciles net income (loss) of EEX and LSEPO to income (loss)
from the discontinued exploration and production business segment:
Net income (loss) of EEX.......................... $10,774 $(12,502) $ 7,477
Net income of LSEPO............................... 933 1,370 813
Differences in amounts reported by EEX and LSEPO
and amounts reported for the discontinued
business by ENSERCH in its consolidated financial
statements (after-tax):
Amortization of costs capitalized by ENSERCH not
incurred by EEX................................ (1,550) (4,544) (4,112)
Litigation judgment against ENSERCH............. -- -- (485)
Effects of property sub-lease transactions...... 2,248 2,279 --
Reduction of deferred income taxes associated
with the reorganization of partnerships to form
EEX............................................ -- -- 70,000
Interest on debt assumed by ENSERCH Corporation
in connection with the reorganization of
partnerships to form EEX in 1994............... -- -- 13,597
Activities not conducted through EEX and other.. 2,334 4,173 (84)
Eliminate minority interest..................... (1,792) 915 (93)
------- -------- --------
Income (loss) from discontinued exploration and
production business segment...................... $12,947 $ (8,309) $ 87,113
======= ======== ========
EXTRAORDINARY LOSS
The extraordinary loss in 1996 of $2.1 million ($.03 per share) represents a
premium incurred in connection with the prepayment of ENSERCH's 9.06% Notes to
facilitate the merger with TUC. The early redemption of the Notes will reduce
future interest expense.
A-9
LIQUIDITY AND FINANCIAL RESOURCES
Net cash flows from operating activities of continuing operations (including
exploration and production operations) for 1996 totaled $266 million, up from
$239 million in 1995 and $91 million in 1994. Income before depreciation and
amortization and deferred income taxes for 1996 was $62 million higher than in
1995; however, recoveries of producer settlements, which are now substantially
complete, were $43 million less than in 1995, and changes in other assets and
liabilities resulted in a year-to-year reduction in cash flows of $7 million.
Changes in current operating assets and liabilities provided $20 million in
1996 versus $5 million in 1995. The 1994 cash flows reflect a $62 million
payment relating to an adverse final judgment.
Investing activities in 1996 required cash flows of $250 million versus $605
million in 1995, which included $342 million for business acquisitions, and
$236 million in 1994. Additions to property, plant and equipment were $40
million greater than in 1995; however, sales and retirements from property,
plant and equipment for 1996 provided $86 million more than in the year
earlier. Sales and retirements in 1996 include net proceeds of $111 million
received by EEX from sales of properties. Cash required for investments in
unconsolidated affiliates for 1996 totaled $60 million, including $34 million
for gas distribution and transmission projects in Chile and Mexico and $25
million for a geothermal power project in Indonesia.
In July 1996, ENSERCH borrowed $100 million under its bank lines of credit
and reduced outstanding commercial paper by the same amount. In September
1996, ENSERCH borrowed $60 million under its bank lines to prepay the
remaining $58.9 million principal balance of its 9.06% Notes, plus the $3.2
million prepayment premium.
Discontinued engineering and construction operations required cash of $7.3
million in 1996, $28 million in 1995 and $.9 million in 1994. The 1995
requirement was principally for the repurchase of previously sold receivables.
The 1994 amount includes net proceeds of $98 million from the 1994 sale of
Enserch Environmental, less working capital requirements of $32 million for
that business in 1994 prior to the sale and less cash required for retained
obligations relating to the 1993 sale of Ebasco.
Total capitalization at December 31, 1996 was $2.3 billion, up slightly from
the $2.2 billion at year-end 1995. Common shareholders' equity plus minority
interest in subsidiaries increased $27 million over 1995, but decreased as a
percentage of total capitalization from 40.2% at December 31, 1995 to 39.6% at
year-end 1996. At December 31, 1996, $569 million of common shareholders'
equity was free of restrictions as to the payment of dividends and redemption
of capital stock.
ENSERCH has future credit availability in the form of a three-year revolving
credit agreement totaling $650 million, $490 million of which was unused at
December 31, 1996. In addition, EEX has a $350 million five-year revolving
credit agreement, $235 million of which was unused at December 31, 1996, and
other affiliates have four-year revolving credit agreements aggregating $30
million, $5 million of which was unused at year-end 1996.
Planned property, plant and equipment additions for 1997 will range from
$175 to $200 million for natural gas and oil exploration and production, $41
million for natural gas pipeline, processing & marketing, $71 million for
natural gas distribution and $1 million for other requirements. The planned
expenditures are expected to be funded from internal cash flow and external
financings as required.
Inflation during recent years has had little effect on capital asset costs
and results of operations.
FOURTH-QUARTER RESULTS
Earnings applicable to common stock for the fourth quarter of 1996 were
$10.5 million ($.15 per share), compared with $7.8 million ($.11 per share)
for the fourth quarter of 1995. Earnings for the 1996 fourth quarter included
the $1.6 million after-tax ($.02 per share) loss provision for discontinued
operations, expenses of $6.3 million after-tax ($.09 per share) relating to
the pending distribution and merger and the $1.4 million after-tax ($.02 per
share) gain on the early termination of the interest-rate swap. Excluding
these items, fourth quarter 1996 earnings applicable to common stock improved
$9.2 million ($.13 per share) from the year-earlier period, and operating
income was $28 million higher, with improvements in all three major business
segments.
A-10
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION OPERATING DATA (A)
FOR YEAR ENDED DECEMBER 31
------------------------------------------------------------
1996 1995 1994 1993 1992 1991
-------- -------- -------- -------- -------- --------
Operating Income (Loss)
(in millions).......... $ 32.2 $ (12.0) $ 25.4 $ (37.3) $ (6.2) $ 10.9
Revenues (in millions).. $ 331.2 $ 220.9 $ 179.3 $ 189.8 $ 171.5 $ 183.6
Sales Volumes
Natural gas (Bcf)...... 100.5 90.2 67.1 70.0 65.2 70.1
Oil and condensate
(MMBbls).............. 5.1 3.4 2.0 2.1 2.3 2.8
Average Sales Price
Natural gas (per Mcf).. $ 2.20 $ 1.74 $ 2.15 $ 2.09 $ 1.82 $ 1.76
Oil and condensate (per
Bbl).................. 19.47 16.86 15.38 17.24 19.20 20.31
Net Wells
Drilled................ 109 81 74 79 19 67
Productive............. 84 51 44 64 8 52
Proved Reserves (at
December 31)
Natural gas (Bcf)...... 1,216.2 1,362.8 1,041.7 1,086.5 1,101.4 1,168.1
Oil and condensate
(MMBbls).............. 59.2 71.5 50.6 39.3 39.2 40.0
Total Bcfe (b)........ 1,571.5(c) 1,791.8 1,345.3 1,322.3 1,336.6 1,408.1
Standardized Measure of
Discounted Future Net
Cash Flows (in
millions).............. $ 1,735 $ 1,238 $ 827 $ 831 $ 820 $ 812
Data in Equivalent
Energy Content
(per Mcfe) (b)
Production revenue..... $ 2.43 $ 1.93 $ 2.21 $ 2.21 $ 2.07 $ 2.08
Production and
operating costs (d)... .58 .44 .39 .37 .36 .40
Depreciation and
amortization.......... 1.11 1.04 1.08 1.03 1.01 .93
- --------
(a) Revenues and operating income (loss) have been restated to reflect the
realignment of certain businesses between segments to conform to the 1996
presentation.
(b) Oil and natural gas liquids are converted to Mcf equivalents (Mcfe) on the
basis of one barrel equals 6.0 Mcfe.
(c) Reserves decreased 146.2 Bcfe in 1996 as a result of the sale of
properties.
(d) Excludes production, severance and ad valorem taxes.
OPERATING INCOME RECONCILIATION FROM EEX TO ENSERCH SEGMENT
Operating income (loss)
of EEX................. $ 36.8 $ (6.2) $ 32.0 $ 15.2 $ (1.2) $ (34.0)
Amortization of costs
capitalized by ENSERCH
not incurred by EEX.... (2.4) (7.0) (6.3) (9.0) (6.5) (6.9)
Write-down of
capitalized cost under
the full-cost ceiling
limitation by EEX not
required by ENSERCH.... -- -- -- -- -- 52.0
Litigation judgment
against ENSERCH........ -- -- -- (41.4) -- --
Effects of intercompany
lease transactions..... (1.2) 2.5 -- -- -- --
Activities not conducted
through EEX............ (1.0) (1.3) (.3) (2.1) 1.5 (.2)
-------- -------- -------- -------- -------- --------
Operating income (loss)
of ENSERCH's
natural gas and oil
exploration and
production segment..... $ 32.2 $ (12.0) $ 25.4 $ (37.3) $ (6.2) $ 10.9
A-11
NATURAL GAS PIPELINE, PROCESSING & MARKETING OPERATING DATA (A)
FOR YEAR ENDED DECEMBER 31
----------------------------------------------
1996 1995 1994 1993 1992 1991
-------- ------ -------- ------ ------ ------
Operating Income (Loss) (in
millions)
Pipeline....................... $ 46.8 $ 49.3 $ 25.1 $ 51.7 $ 41.2 $ 45.0
Gas Processing................. 23.0 4.7 1.2 5.0 13.1 21.2
Gas Marketing.................. (6.4) 6.1 .9 16.7 13.4 12.5
-------- ------ -------- ------ ------ ------
Total......................... $ 63.4 $ 60.1 $ 27.2 $ 73.4 $ 67.7 $ 78.7
Revenues (in millions)
Pipeline (b)................... $ 152.6 $143.5 $ 141.0 $143.4 $135.9 $185.6
Gas Processing--Natural gas
liquids (c)................... 97.4 69.7 68.7 73.6 79.0 84.9
Gas Marketing.................. 825.0 750.5 997.4 666.2 406.7 297.9
Other (d)...................... 51.5 32.7 28.5 24.8 17.9 22.0
-------- ------ -------- ------ ------ ------
Total revenues................ $1,126.5 $996.4 $1,235.6 $908.0 $639.5 $590.4
Volumes
Pipeline (Bcf) (e)............. 652.3 561.1 541.6 542.8 472.9 481.2
Gas Processing (MMBbls)........ 6.1 6.0 5.9 6.0 5.9 6.1
Gas Marketing (Bcf)............ 315.3 419.2 488.4 306.7 210.9 173.3
Average Sales Price
Natural Gas Liquids (per Bbl).. $ 15.93 $11.66 $ 11.65 $12.34 $13.35 $13.92
Gas Marketing (per Mcf)........ $ 2.62 $ 1.79 $ 2.04 $ 2.17 $ 1.93 $ 1.72
- --------
(a) Prior year amounts have been restated to reflect the realignment of
certain businesses between segments to conform to the 1996 presentation.
(b) Includes transportation services for affiliates and third-parties and
other miscellaneous revenues.
(c) Represents revenues from sales of plant production.
(d) Includes revenues from natural-gas products purchased for resale,
gathering fees and other miscellaneous revenues.
(e) Includes intrahub wheeling of gas, which does not utilize pipeline
capacity, of approximately 56 Bcf in 1996, 6 Bcf in 1995, 27 Bcf in 1994 and
32 Bcf in 1993.
A-12
NATURAL GAS DISTRIBUTION OPERATING DATA (A)
FOR YEAR ENDED DECEMBER 31
-----------------------------------------
1996 1995 1994 1993 1992 1991
------ ------ ------ ------ ------ ------
Operating Income (in millions)...... $ 68.2 $ 54.6 $ 38.3 $ 34.2 $ 48.4 $ 54.1
Natural Gas Sales Revenues by
Customer (in millions)
Residential & commercial........... $789.8 $766.5 $744.3 $823.8 $716.5 $702.9
Industrial (b)..................... 28.5 55.7 63.5 69.6 88.9 100.3
Electric generation................ 48.1 50.9 53.2 58.7 97.5 89.6
------ ------ ------ ------ ------ ------
Total gas sales revenues.......... 866.4 873.1 861.0 952.1 902.9 892.8
Gas transportation revenues (c)..... 13.5 11.5 11.3 11.5 9.9 10.0
Other revenues...................... 15.3 9.2 9.0 10.3 10.6 10.4
------ ------ ------ ------ ------ ------
Total revenues.................... $895.2 $893.8 $881.3 $973.9 $923.4 $913.2
Natural Gas Sales Volumes by
Customer (Bcf)
Residential & commercial........... 135.3 125.7 125.7 139.3 120.6 128.5
Industrial......................... 7.4 13.6 15.3 16.9 20.3 25.8
Electric generation................ 11.2 11.0 11.0 12.4 21.3 23.3
------ ------ ------ ------ ------ ------
Total gas sales volumes........... 153.9 150.3 152.0 168.6 162.2 177.6
Natural Gas Sales Revenues (per Mcf)
Residential & commercial........... $ 5.84 $ 6.10 $ 5.92 $ 5.91 $ 5.94 $ 5.47
Industrial......................... 3.88 4.11 4.16 4.12 4.37 3.90
Electric generation................ 4.30 4.62 4.84 4.75 4.56 3.85
Natural Gas Purchase Cost (per
Mcf)............................... $ 3.86 $ 4.12 $ 4.09 $ 4.16 $ 4.10 $ 3.67
Heating Degree Days................. 2,413 2,173 2,201 2,508 1,980 2,179
% of normal (2,407)................ 100.2 90.3 91.4 104.2 82.3 90.5
Cooling Degree Days................. 2,800 2,656 2,676 2,767 2,415 2,670
% of normal (2,603)................ 107.6 102.0 102.8 106.3 92.8 102.6
- --------
(a) Revenues and operating income have been restated to reflect the
realignment of certain businesses between segments to conform to the 1996
presentation.
(b) Decrease from 1995 to 1996 is attributable to customers taking advantage
of a program, available since mid-1995, to transport gas purchased from
other suppliers. The transportation fees earned by Lone Star Gas are
sufficient to replace the margin lost on the gas sales.
(c) Represents the portion of transportation revenues attributable to the
distribution system. Related volumes are included within Natural Gas
Pipeline, Processing & Marketing statistics.
A-13
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, 1996 and 1995, 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, 1996.
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, 1994, 1993, 1992 and 1991 and the related statements of consolidated
income, cash flows and common shareholders' equity for the years ended
December 31, 1993, 1992, and 1991 (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, 1996 and 1995, and the results of their
operations and their cash flows for each of the three years in the period
ended December 31, 1996, 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 1991 through 1996
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, 1997
A-14
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 the
Corporation's internal auditors and Deloitte & Touche LLP, the Corporation's
independent 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, 1996, the overall system of
internal accounting controls is sufficient to accomplish the objectives
discussed herein.
_________________________ _________________________ _________________________
D. W. Biegler M. E. Rescoe J. W. Pinkerton
Chairman, President and Senior Vice President, Vice President and
Chief Executive Officer Finance, Chief Financial Controller, Chief
Officer Accounting Officer
February 10, 1997
A-15
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED INCOME
YEAR ENDED DECEMBER 31
-------------------------------------------
1996 1995 1994
------------- ------------- -------------
(IN THOUSANDS EXCEPT PER SHARE AMOUNTS)
REVENUES
Natural gas and oil exploration
and production................. $ 331,204 $ 220,878 $ 179,331
Natural gas pipeline, processing
& marketing.................... 1,126,450 996,424 1,235,572
Natural gas distribution........ 895,224 893,849 881,336
Power and other................. 37,808 39,817 45,499
Less intercompany revenues...... (248,061) (219,728) (246,230)
------------- ------------- -------------
Total.......................... 2,142,625 1,931,240 2,095,508
------------- ------------- -------------
COSTS AND EXPENSES
Gas purchase.................... 1,227,916 1,170,732 1,432,301
Operating expenses.............. 469,313 405,580 366,512
Depreciation and amortization... 204,845 168,262 126,979
Gross receipts and production
taxes.......................... 56,215 51,086 50,723
Payroll, ad valorem and other
taxes.......................... 38,016 37,851 30,347
------------- ------------- -------------
Total.......................... 1,996,305 1,833,511 2,006,862
------------- ------------- -------------
OPERATING INCOME................. 146,320 97,729 88,646
Other Expense--Net............... (11,222) (1,033) (6,048)
Interest and Other Financing
Costs........................... (94,870) (83,324) (69,310)
------------- ------------- -------------
Income before Income Taxes and
Minority Interest............... 40,228 13,372 13,288
Income (Taxes) Benefit........... (15,738) (921) 68,737
Minority Interest................ (1,792) 602 (573)
------------- ------------- -------------
Income from Continuing Opera-
tions........................... 22,698 13,053 81,452
Income (Loss) from Discontinued
Operations...................... (1,560) -- 20,642
Extraordinary Loss on Extinguish-
ment of Debt.................... (2,096) -- --
------------- ------------- -------------
NET INCOME....................... 19,042 13,053 102,094
Provision for Dividends on Pre-
ferred Stock.................... 11,339 11,690 11,619
------------- ------------- -------------
Earnings Applicable to Common
Stock........................... $ 7,703 $ 1,363 $ 90,475
============= ============= =============
PER SHARE OF COMMON STOCK
Income from continuing
operations after provision
for dividends on preferred
stock......................... $ .16 $ .02 $ 1.03
Discontinued operations......... (.02) -- .30
Extraordinary loss.............. (.03) -- --
------------- ------------- -------------
Earnings applicable to common
stock.......................... $ .11 $ .02 $ 1.33
============= ============= =============
Cash dividends declared......... $ .20 $ .20 $ .20
============= ============= =============
Average Common and Dilutive
Common Equivalent Shares
Outstanding..................... 69,441 68,323 68,049
============= ============= =============
OPERATING INCOME (LOSS) OF MAJOR
BUSINESSES
(Excludes general corporate
expense)
Natural gas and oil exploration
and production................. $ 32,224 $ (12,023) $ 25,420
Natural gas pipeline, processing
& marketing
Pipeline....................... 46,822 49,288 25,082
Gas processing................. 22,979 4,737 1,204
Gas marketing.................. (6,357) 6,128 959
Natural gas distribution........ 68,157 54,634 38,334
Power and other................. (8,239) 3,478 5,761
See Notes to Consolidated Financial Statements.
A-16
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
YEAR ENDED DECEMBER 31
-------------------------------
1996 1995 1994
--------- --------- ---------
(IN THOUSANDS)
OPERATING ACTIVITIES
Income from continuing operations............ $ 22,698 $ 13,053 $ 81,452
Depreciation and amortization................ 204,845 168,262 126,979
Deferred income-tax expense (benefit)........ 10,737 (5,680) (59,151)
Recoveries of gas-purchase contract settle-
ments....................................... 7,927 51,297 49,602
Other........................................ (38) 7,283 (2,544)
Changes in current operating assets and lia-
bilities
Accounts receivable.......................... (113,250) (31,476) 13,038
Other current assets......................... (16,396) 1,787 (34,014)
Accounts payable............................. 106,424 18,503 (2,142)
Other current liabilities.................... 43,433 16,057 (20,041)
Litigation judgment payable.................. -- -- (62,498)
--------- --------- ---------
Net Cash Flows from Operating Activities.... 266,380 239,086 90,681
--------- --------- ---------
INVESTING ACTIVITIES
Purchases of businesses, net of cash ac-
quired...................................... -- (341,650) (122)
Additions to property, plant and equipment... (336,639) (297,026) (260,058)
Sales and retirements of property, plant and
equipment................................... 145,580 59,699 16,756
Investments in unconsolidated affiliates..... (59,627) (8,785) --
Other........................................ 778 (17,397) 7,005
--------- --------- ---------
Net Cash Flows used for Investing
Activities................................. (249,908) (605,159) (236,419)
--------- --------- ---------
FINANCING ACTIVITIES
Change in commercial paper and other short-
term borrowings............................. (49,000) 32,759 116,271
Borrowings by EEX............................ 136,000 530,000 --
Issuance of mandatorily redeemable preferred
securities of subsidiary.................... -- 150,000 --
Issuance of EEX common stock................. 249 207,872 --
Repayment of borrowings by EEX............... (181,000) (485,000) --
Issuance of senior long-term debt............ 160,000 150,000 300,145
Debt issuance costs.......................... (786) (944) (883)
Borrowings under revolving credit agreement.. 25,000 -- --
Retirement of senior long-term debt.......... (66,960) (162,677) (214,983)
Prepayment premium on early extinguishment of
debt........................................ (3,226) -- --
Issuance of Series F Preferred Stock......... -- -- 72,797
Retirement of Series D Preferred Stock....... -- -- (75,000)
Change in advances under lease arrangements.. (21,520) 9,883 (32,157)
Change in assignments of future gas purchase
credits..................................... -- (17,191) (21,000)
Other........................................ 23 (784) 1
Issuance of ENSERCH common stock............. 27,678 4,408 3,451
Cash dividends paid.......................... (25,144) (25,401) (25,071)
--------- --------- ---------
Net Cash Flows from Financing Activities.... 1,314 392,925 123,571
--------- --------- ---------
Net Cash Flows used for Discontinued
Operations................................... (7,274) (28,102) (942)
--------- --------- ---------
Net Increase (Decrease) in Cash and
Equivalents.................................. 10,512 (1,250) (23,109)
Cash and Equivalents at Beginning of Year..... 8,561 9,811 32,920
--------- --------- ---------
Cash and Equivalents at End of Year........... $ 19,073 $ 8,561 $ 9,811
========= ========= =========
Amounts paid (refunded)
Interest and other financing costs (net of
amount capitalized)......................... $ 94,045 $ 95,059 $ 66,926
========= ========= =========
Income taxes--net............................ $ 1,421 $ (5,659) $ 5,245
========= ========= =========
Purchases of businesses
Fair value of assets acquired................ -- $ 495,998 --
Cash paid for acquisitions................... -- 341,650 --
---------
Liabilities assumed.......................... -- $ 154,348 --
=========
Information on noncash investing and financing activities is presented in Note
8.
See Notes to Consolidated Financial Statements.
A-17
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31
------------------------
1996 1995
----------- -----------
(IN THOUSANDS)
ASSETS
Current Assets
Cash and equivalents................................ $ 19,073 $ 8,561
Accounts receivable................................. 382,404 296,178
Gas stored underground.............................. 119,178 107,633
Other............................................... 121,837 121,544
----------- -----------
Total current assets............................... 642,492 533,916
----------- -----------
Investments.......................................... 115,633 64,974
----------- -----------
Property, Plant and Equipment (at cost)
Natural gas and oil exploration and production
(full-cost method)................................. 2,863,883 2,583,802
Natural gas pipeline, processing & marketing........ 866,298 825,848
Natural gas distribution............................ 1,025,015 948,076
Power and other..................................... 27,312 32,702
General............................................. 22,785 23,761
----------- -----------
Total.............................................. 4,805,293 4,414,189
Less accumulated depreciation and amortization...... (1,861,914) (1,687,409)
----------- -----------
Net property, plant and equipment.................. 2,943,379 2,726,780
----------- -----------
Other Assets......................................... 43,073 55,424
----------- -----------
Total.............................................. $ 3,744,577 $ 3,381,094
=========== ===========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Commercial paper.................................... $ 138,000 $ 187,000
Current portion of senior long-term debt............ 1,598 14,760
Payables under leasing arrangements................. 8,714 14,671
Accounts payable.................................... 428,354 329,844
Other current liabilities........................... 163,376 130,977
Liabilities for discontinued operations............. 17,933 42,120
----------- -----------
Total current liabilities.......................... 757,975 719,372
----------- -----------
Senior Long-term Debt................................ 956,971 870,476
----------- -----------
Convertible Subordinated Debentures.................. 90,750 90,750
----------- -----------
Other Liabilities
Deferred income taxes............................... 288,299 277,076
Accrued pension costs............................... 44,070 54,959
Capital lease obligations........................... 241,735 28,454
Other............................................... 136,960 139,391
----------- -----------
Total other liabilities............................ 711,064 499,880
----------- -----------
Mandatorily Redeemable Preferred Securities of
Subsidiary of EEX................................... 150,000 150,000
----------- -----------
Minority Interest in Subsidiaries.................... 159,426 156,434
----------- -----------
Commitments and Contingent Liabilities (Note 8)
Shareholders' Equity
Adjustable rate preferred stock..................... 175,000 175,000
Common shareholders' equity......................... 743,391 719,182
----------- -----------
Shareholders' equity................................ 918,391 894,182
----------- -----------
Total.............................................. $ 3,744,577 $ 3,381,094
=========== ===========
See Notes to Consolidated Financial Statements.
A-18
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED COMMON SHAREHOLDERS' EQUITY
YEAR ENDED DECEMBER 31
-----------------------------
1996 1995 1994
--------- -------- --------
(IN THOUSANDS)
Common Stock--authorized 100 million shares
Balance at beginning of year................... $ 304,897 $303,301 $301,977
Issued for stock plans (1,764; 358; and 298
shares)...................................... 7,363 1,596 1,324
Change in par value to $.01 from $4.45 per
share........................................ (311,557) -- --
--------- -------- --------
Balance at end of year (par value: $.01; $4.45;
and $4.45
outstanding shares: 70,280; 68,516; and
68,158)....................................... 703 304,897 303,301
--------- -------- --------
Paid in Capital
Balance at beginning of year................... 338,857 334,672 333,768
Excess of proceeds over par value of common
stock issued for stock plans................. 21,794 3,866 3,217
Series F preferred stock issuance costs....... -- -- (2,203)
Other......................................... 567 319 (110)
Change in par value of common stock........... 311,557 -- --
--------- -------- --------
Balance at end of year......................... 672,775 338,857 334,672
--------- -------- --------
Retained Earnings
Balance at beginning of year................... 76,941 89,054 11,913
Net income.................................... 19,042 13,053 102,094
Dividends declared............................ (25,209) (25,162) (24,952)
Other......................................... -- (4) (1)
--------- -------- --------
Balance at end of year......................... 70,774 76,941 89,054
--------- -------- --------
Foreign Currency Translation Adjustment
Balance at beginning of year................... -- -- --
Change during the year........................ (1,325) -- --
Deferred income tax effects................... 464 -- --
--------- -------- --------
Balance at end of year......................... (861) -- --
--------- -------- --------
Unamortized Restricted Stock Compensation
Balance at beginning of year................... (1,513) (840) --
Shares granted................................ (1,284) (865) (1,261)
Cancellations................................. -- 64 192
Market valuation adjustments.................. (73) (332) 89
Amortization.................................. 2,870 460 140
--------- -------- --------
Balance at end of year......................... -- (1,513) (840)
--------- -------- --------
Common Shareholders' Equity..................... $ 743,391 $719,182 $726,187
========= ======== ========
See Notes to Consolidated Financial Statements.
A-19
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
All dollar amounts, except per share amounts, in the notes to 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.
Information by business segments is presented elsewhere herein and is an
integral part of these financial statements. The preparation of financial
statements requires the use of significant estimates and assumptions by
management; actual results could differ from those estimates.
The financial statements for years prior to 1996 have been restated to
reflect the realignment of certain activities for purposes of business segment
presentations.
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 purchased in the United States with a maturity
of three months or less at date of purchase are considered to be cash
equivalents.
Derivative Instruments--The Corporation frequently enters into swaps,
futures, options and other derivative contracts in connection with its natural
gas marketing activities conducted by Enserch Energy Services, Inc. (EES) or
to hedge the impact of market fluctuations in gas and oil prices on
anticipated future gas and oil production of Enserch Exploration, Inc. (EEX)
or other contractual commitments. The Corporation defers the impact of changes
in the market value of contracts that serve as hedges until the related
transaction is completed. The Corporation also enters into interest-rate swaps
to manage risk associated with interest rates and reduce the Corporation's
exposure to interest rate fluctuations. Interest-rate swaps are valued on a
periodic basis, with resulting differences deferred and recognized as an
adjustment to interest and other financing costs over the term of the
agreement.
Stock-Based Compensation--Statement of Financial Accounting Standards No.
123, "Accounting for Stock-Based Compensation," (SFAS123) encourages, but does
not require, companies to record compensation cost for stock-based employee
compensation plans at fair value. The Corporation has chosen to continue to
account for stock-based compensation using the intrinsic value method
prescribed in Accounting Principles Board Opinion No. 25, "Accounting for
Stock Issued to Employees," (APB25) and related Interpretations. Accordingly,
compensation cost for stock options is measured as the excess, if any, of the
quoted market price of the Corporation's stock at the date of the grant over
the amount an employee must pay to acquire the stock. The final compensation
cost for restricted stock awards is based on the quoted market price of the
Corporation's stock at the date the award becomes vested. See Note 6.
Natural Gas and Oil Exploration and Production--The full-cost accounting
method, as prescribed by the Securities and Exchange Commission (SEC), is
followed for gas and oil properties. Under this method, all acquisition,
exploration and development costs incurred, including salaries, benefits and
other internal costs directly attributable to these activities, are
capitalized. All costs associated with production and general corporate
activities are expensed in the period incurred. 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
A-20
content. Amortization of gas and oil properties was approximately 8.0% in
1996, 6.0% in 1995 and 5.8% in 1994. Depreciation of other property, plant and
equipment is provided principally by the straight-line method over the
estimated service lives of the related assets. At December 31, 1996, 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.
Natural Gas Pipeline--Lone Star Pipeline Company (Lone Star Pipeline or LSP)
is subject to regulatory utility accounting requirements. The rate LSP charges
to Lone Star Gas Company (Lone Star Gas or LSG) for transportation and storage
of gas ultimately consumed by residential and commercial customers is
established by the Railroad Commission of Texas (RRC). The pipeline system is
generally depreciated by the straight-line method over approximately 40 years.
Natural Gas Distribution--Lone Star Gas is also subject to regulatory
utility accounting requirements. LSG's city gate rate for the cost of gas
ultimately delivered to residential and commercial customers is established by
the RRC and provides for full recovery of the actual cost of gas delivered,
including out-of-period costs such as gas-purchase contract settlement costs.
LSG's rates to residential and commercial customers are established by the
municipal governments of the cities and towns served, with the RRC having
appellate jurisdiction. Lone Star Gas 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 distribution system
is depreciated by the straight-line method over approximately 40 years. Gas
stored underground is valued at average cost.
2. CHANGE IN ORGANIZATION, ACQUISITIONS AND DISPOSITIONS
On April 15, 1996, ENSERCH Corporation announced that it had entered into a
merger agreement with Texas Utilities Company (TUC), subject to shareholder
and regulatory approval. The merger is to be preceded by the distribution of
ENSERCH's approximate 83% interest in EEX to the ENSERCH shareholders in a
tax-free transaction. On November 15, 1996, in separate meetings, the
shareholders of TUC, ENSERCH and EEX approved the mergers and the related
distribution. The companies are currently awaiting approval of the merger by
the SEC.
Prior to December 30, 1994, the operations of EEX, a corporation, were
conducted through Enserch Exploration Partners, Ltd. (EP), a partnership.
ENSERCH's 99.2% ownership of EP was held primarily through Enserch Processing
Partners Limited (EPPL). On December 30, 1994, EEX 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. In 1995,
ENSERCH sold its international gas and oil operations and its SACROC
operations to EEX for 1,240,000 shares of EEX common stock and $4.2 million in
cash.
On June 8, 1995, EEX acquired all the capital stock of a gas and oil
exploration and production company for cash of $340 million and assumed bank
debt of $115 million. The acquisition was accounted for as a purchase. The
assets acquired and the liabilities assumed were recorded at their fair value.
Essentially all of the valuation adjustment was assigned to gas and oil
properties. Pro forma results of operations assuming the acquisition had
occurred at the beginning of 1995 are: revenues, $1,979,564; operating income,
$97,272; net income, $2,793; and loss applicable to common stock, ($8,897)
($.13 per share).
On June 29, 1995, ENSERCH purchased the principal operating assets of a
nonregulated marketer of natural gas, for approximately $9 million in cash,
including some $8 million of cost in excess of net assets acquired. The
acquisition was accounted for as a purchase. The goodwill is being amortized
over 20 years.
A-21
Operations of the acquired companies have been included in the accompanying
consolidated financial statements from their respective dates of acquisition.
Effective June 30, 1995, the Corporation exchanged 1,204,098 shares of
ENSERCH common stock for 100% of the outstanding shares of a company, which,
through its subsidiary, is a marketer of natural gas and natural-gas services.
The transaction was accounted for as a pooling-of-interests.
On September 26, 1995, EEX sold 20 million shares of its common stock to the
public for net proceeds of approximately $208 million, and ENSERCH's ownership
percentage was reduced from 99.2% to 83.4%. As a result of the stock sale,
ENSERCH's equity interest in EEX, after the reduction in ownership percentage,
increased $59 million. In accordance with the full-cost accounting method,
ENSERCH credited the $59 million to the carrying value of gas and oil
properties, with no gain recognized on the sale since the sale did not
significantly alter the relationship between capitalized costs and proved
reserves.
3. BORROWINGS AND LINES OF CREDIT
1996 1995
Senior Long-term Debt at December 31: -------- --------
8% Notes due 1997........................................ $100,000 $100,000
7% Notes due 1999........................................ 150,000 150,000
9.06% Notes due 1996 through 1999........................ -- 65,600
Subsidiary Revolving Credit Agreement Maturing 2000...... 25,000 --
ENSERCH Revolving Credit Agreement Maturing 2001......... 160,000 --
EEX Bank Revolving Credit Agreement Maturing 2001........ 115,000 160,000
8 7/8% Notes due 2001.................................... 100,000 100,000
6 3/8% Notes due 2004.................................... 150,000 150,000
7 1/8% Notes due 2005.................................... 150,000 150,000
Other.................................................... 8,569 9,636
-------- --------
Total.................................................. 958,569 885,236
Less current maturities.................................. 1,598* 14,760
-------- --------
Noncurrent............................................. $956,971 $870,476
======== ========
1997 1998 1999 2000 2001
------ -------- -------- ------- --------
Maturities........................ $1,598* $101,900 $152,100 $29,500 $375,000
--------
* Excludes the $100 million of 8% Notes due March 1997 which are intended
to be refinanced on a long-term basis prior to maturity and have been
classified as long term on the balance sheet as of December 31, 1996.
In April 1996, certain subsidiaries of the Corporation entered into
revolving credit agreements with several banks that mature in 2000 aggregating
$30 million, $5 million of which was unused at December 31, 1996. The proceeds
were used to acquire a 10% interest in Metrogas, S.A., a Chilean company. The
interest rate is based on LIBOR and was 5.75% at December 31, 1996.
In July 1996, the Corporation borrowed $100 million under its bank lines of
credit to pay down commercial paper balances. An additional $60 million was
drawn down in September 1996 to pay off the outstanding balance of the 9.06%
Notes due through 1999, including a prepayment premium of $3.2 million ($2.1
million after-tax) which has been accounted for as an extraordinary loss on
early extinguishment of debt.
A-22
In October 1996, the Corporation entered into a revolving credit agreement
with a group of banks that replaces the previous bank lines of credit. The
revolving credit agreement expires in 2001 and has a maximum limit of $650
million, $490 million of which was unused at December 31, 1996. The entire
$650 million facility is on a fee basis, does not require compensating
balances or restrict the use of cash, and supports the Corporation's
commercial paper program. The agreement provides that loans may be made under
either domestic or Eurocurrency notes at prevailing market rates. Under the
credit agreement, the rates for interest and facility fees change when the
Corporation's debt rating changes. The interest rate in effect on borrowings
outstanding at December 31, 1996 was 5.82%. The credit agreement requires
maintenance of certain financial ratios and restricts encumbrance of assets
and creation of indebtedness. At December 31, 1996, the Corporation was in
compliance with these financial ratio requirements.
EEX has a $350 million revolving credit line that matures on August 1, 2001,
$235 million of which was unused at December 31, 1996. The interest rate
ranges from LIBOR (5.61% in effect at December 31, 1996) plus .35% to .75% per
annum, plus a facility fee of from .15% to .25% per annum, depending upon
EEX's consolidated capitalization ratio.
The convertible subordinated debentures have an interest rate of 6 3/8%, are
due in 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 101.91% of the principal amount, plus accrued interest, through
March 31, 1997 and at declining premiums thereafter.
Commercial paper totaled $138 million at December 31, 1996 and $187 million
at December 31, 1995. The weighted average interest rate in effect on
commercial paper borrowings at December 31, 1996 and 1995 was 5.95% and 6.0%,
respectively.
Interest and Other 1996 1995 1994
Financing Costs: ------- ------- -------
Interest costs in-
curred................. $91,829 $85,118 $74,260
Dividends on preferred
securities of subsidi-
ary.................... 9,560 4,123 --
Interest capitalized.... (6,519) (5,917) (4,950)
------- ------- -------
Charged to expense...... $94,870 $83,324 $69,310
======= ======= =======
4. MANDATORILY REDEEMABLE PREFERRED SECURITIES OF SUBSIDIARY
On August 4, 1995, a subsidiary ("Issuer") of EEX completed the private
placement of $150 million of adjustable rate mandatorily redeemable preferred
securities for which EEX is also obligated. The dividends on the preferred
securities are based on LIBOR plus .696% and are reflected in interest and
other financing costs in the statements of consolidated income. In November
1995, EEX entered into an interest-rate swap to effectively fix the rate for
the dividend on these preferred securities at 6.37% as of December 31, 1996
(see Note 7). The mandatory redemption date for Issuer's preferred securities
is August 4, 2005 or earlier under certain conditions.
5. SHAREHOLDERS' EQUITY
At the special shareholders meeting on November 15, 1996, shareholders of
the Corporation approved a change in the par value of ENSERCH common stock
from $4.45 per share to $.01 per share to facilitate the distribution of the
Corporation's interest in EEX. The reduction in par value was recorded by the
transfer of $312 million to the paid-in-capital account.
A-23
As of December 31, 1996, 5,920,940 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.
Adjustable Rate Preferred
Stock at
December 31, 1996 and STATED VALUE PER SHARES OUTSTANDING
1995: -------------------- --------------------
PREFERRED DEPOSITARY PREFERRED DEPOSITARY
SHARE SHARE SHARES SHARES AMOUNT
--------- ---------- --------- ---------- --------
Series E................. $1,000 $100 100,000 1,000,000 $100,000
Series F................. 1,000 25 75,000 3,000,000 75,000
--------
Total.................. $175,000
========
The Series E stock is redeemable at the option of the Corporation at stated
value at any time, and the Series F stock is redeemable at stated value after
May 1, 1999. Holders of the preferred stock are entitled to its stated value
upon involuntary liquidation.
Dividend rates are determined quarterly, in advance, based on the
"Applicable Rate" (highest of the three-month Treasury bill rate, the Treasury
ten-year constant maturity rate and either the Treasury twenty-year or thirty-
year constant maturity rate, as defined), as set forth below:
PER ANNUM RATE (DETERMINED QUARTERLY)
-------------------------------------
SERIES E SERIES F
------------------ ------------------
Dividend rate.......................... 1.20% below 87% of
Applicable Rate Applicable Rate
Minimum rate........................... 7.00% 4.50%
Maximum rate........................... 13.00% 10.50%
1996 1995 1994
Dividends Declared: ------- ------- -------
Adjustable Rate Preferred Stock:
Series D (redeemed in 1994)($.42 per share)....... $ -- $ -- $ 625
Series E ($7.00, $7.00, $7.00 per depositary
share)........................................... 7,000 7,000 7,000
Series F ($1.45, $1.54, $1.32 per depositary
share)........................................... 4,360 4,610 3,955
Common Stock ($.20, $.20, $.20 per share).......... 13,849 13,552 13,372
------- ------- -------
Total............................................ $25,209 $25,162 $24,952
======= ======= =======
Dividends--Restrictions on the payment of dividends on common stock (other
than stock dividends) or acquisitions of capital stock are contained in the
Restated Articles of Incorporation. At December 31, 1996, $569 million of
common shareholders' equity was free of such restrictions.
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, 2006 and are generally
redeemable at $.01 per right until the 10th day following public announcement
that a 15% position has been acquired. The Shareholders Rights Plan has been
amended so that the proposed merger with TUC will not trigger the activation
of shareholders rights thereunder.
A-24
6. STOCK COMPENSATION PLANS
The Corporation currently has three fixed option plans. Stock options have
been awarded to key employees and are outstanding under all three plans.
Options for 7,651 shares granted under a former plan have an exercise price of
$4.45, while 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.
Options become exercisable over four years and generally expire ten years
after the date of the grant. At December 31, 1996, there were 76 participants
in the stock option plans. As a result of the agreement to merge with TUC, all
stock options became fully vested and exercisable. Any ENSERCH options not
exercised prior to the consummation of the merger will be exchanged for
options for TUC common stock of an equivalent value.
WEIGHTED AVERAGE
Summary of Stock Option EXERCISE PRICE NUMBER OF OPTIONS
Activity: ----------------- --------------------------------
1996 1995 1996 1995 1994
-------- -------- ---------- --------- ---------
Outstanding--Beginning of
year..................... $ 17.27 $ 17.67 2,514,598 2,308,823 2,388,970
Granted.................. $ 15.13 $ 13.63 326,300 263,200 144,700
Exercised (a)............ $ 16.47 $ 12.93 (1,579,289) (27,825) (32,347)
Canceled or expired...... $ 17.87 $ 20.11 (79,301) (29,600) (192,500)
---------- --------- ---------
Outstanding--End of year.. $ 17.71 $ 17.27 1,182,308 2,514,598 2,308,823
========== ========= =========
Exercisable............... 1,182,308 1,957,637 1,838,175
========== ========= =========
- --------
(a)Price ranges for options exercised in 1996 were $4.45 to $21.13; in 1995
were $12.50 to $17.00 and in 1994 were $4.45 to $12.50.
Summary of Stock Options Outstanding at December 31, 1996:
WEIGHTED
NUMBER AVERAGE WEIGHTED
RANGE OF OF REMAINING AVERAGE
EXERCISE OPTIONS CONTRACTUAL EXERCISE
PRICES OUTSTANDING LIFE (YEARS) PRICE
-------------- ----------- ------------ --------
$4.45 7,651 3 $ 4.45
$12.50-$18.25 573,800 7 15.00
$19.00-$23.875 600,857 3 20.46
--------- ------
1,182,308 $17.71
========= ======
The weighted average fair value of stock options granted in 1996 and 1995
was $4.97 and $4.80, respectively. The fair value for these options granted
since December 31, 1994 was estimated at the date of grant using a Black-
Scholes option pricing model with the following weighted average assumptions
for 1996 and 1995, respectively: risk-free interest rates of 5.48% and 7.17%;
dividend yields of 1.33% and 1.48%; volatility factor of the expected market
price of the Corporation's common stock of .29; and a weighted average
expected life of the options of 6.3 years.
The current stock option plan includes provisions for issuing the
Corporation's common stock under performance-based grants. The Corporation
granted 83,500 and 59,000 shares of restricted stock under its stock option
plan in 1996 and 1995, respectively. The weighted average grant-date fair
value of these restricted shares was $15.38 and $14.66, respectively. Fair
value is equal to the market value of the Corporation's common stock on the
date of grant. Upon the Board of Directors' agreement to merge with TUC in
April 1996, (see Note 2), all restrictions were lifted on the 211,956 shares
of restricted stock outstanding. The unamortized portion of the cost of these
shares of $3.1 million was charged to compensation expense.
Pro forma information regarding net income and earnings per share is
mandated by SFAS123 and has been determined as if the Corporation had
accounted for its employee stock options under the fair value method of
A-25
that Statement. Had compensation cost for the Corporation's stock option plans
been determined based on the fair value at the grant dates for awards under
those plans in accordance with the provision of SFAS123, the Corporation's net
income and earnings per share for the years ended December 31, 1996 and 1995
would have been reduced to the pro forma amounts indicated below:
1996 1995
------ ------
Net income (after provision for dividends on preferred
stock):
As reported................................................ $7,703 $1,363
Pro forma *................................................ 5,498 1,179
Earnings per share:
As reported................................................ $ .11 $ .02
Pro forma *................................................ .08 .02
--------
* Includes the Corporation's approximate 83% interest in EEX's SFAS123 pro
forma adjustments for EEX stock options of $.9 million in 1996 and $.1
million in 1995.
The effects of applying SFAS123 in this pro forma disclosure are not
indicative of future amounts. SFAS123 does not apply to awards prior to 1995.
No additional awards in future years are anticipated.
7. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Corporation's operations involve managing market risks related to
changes in interest rates and commodity prices. Derivative financial
instruments, specifically swaps, futures, options and other contracts, are
used to reduce and manage those risks.
Interest-Rate Swaps--EEX has an interest-rate swap on a notional amount of
$150 million to fix the interest rate associated with the mandatorily
redeemable preferred securities of subsidiary. The notional amount declines on
a schedule that parallels the estimated redemption of the securities and
terminates in July 2000. Under the swap agreement, EEX is to receive interest
on the outstanding notional amount at a rate (5.53% in effect at December 31,
1996) based on LIBOR, reset quarterly, and is to pay a fixed rate of 5.8%. The
net effect of the swap fixes the rate on the preferred dividends at 6.37% at
December 31, 1996. The Corporation is exposed to market risk under this swap
arrangement due to the possibility of exchanging a lower interest rate for a
higher interest rate. The counterparties are major financial institutions, and
the risk of incurring losses related to credit risk is considered by the
Corporation to be remote.
In December 1996, in connection with the refinancing of the Garden Banks
operating lease arrangement (see Note 8), a related interest-rate swap on a
notional amount of $150 million, which had been in effect since December 1995,
was terminated. The Corporation recognized a $2.2 million ($1.4 million after-
tax) gain as a result of the early termination of the agreement.
Hedging Activities--The Corporation, through EEX, enters into swaps, futures
and other derivative contracts to hedge the price risks associated with a
portion of anticipated future gas and oil production. 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. The Corporation does
not obtain collateral to support the agreements but monitors the financial
viability of counterparties and believes its credit risk is minimal on these
transactions. In the event of nonperformance by counterparties, the
Corporation would be exposed to price risk. The Corporation has some risk of
accounting loss since the price received for the product at the actual
physical delivery point may differ from the prevailing price at the delivery
point required for settlement of the hedging transaction.
At December 31, 1996, EEX had outstanding swaps, collars and futures
agreements that were entered into as hedges extending through December 31,
1997 to exchange payments on 32 billion cubic feet (Bcf) of natural gas and
365 thousand barrels (MBbls) of oil. The weighted average strike price and
market price per thousand cubic feet (Mcf) of natural gas was $2.47 and $2.37,
respectively, and the weighted average strike price and
A-26
market price per barrel of oil was $25.00 and $25.32, respectively. At
December 31, 1996, there were $3.0 million of net unrealized and unrecognized
hedging gains based on the difference between the strike price and the NYMEX
futures price for the applicable trading month. In addition, there were $5.1
million of realized losses on hedging activities which were deferred and will
be applied as a reduction in revenues in January 1997, the month of physical
sale of production.
EEX recognized in revenues a net loss of $20.3 million in 1996 and net gains
of $.1 million in 1995 and $4.3 million in 1994 on hedging activities related
to the sale of its gas and oil production.
Natural Gas Marketing Activities--The Corporation, through EES, is a
marketer of natural gas and natural-gas services. As part of these business
activities, EES enters into a variety of transactions, including forward
contracts principally involving physical delivery of natural gas and
derivative financial instruments, including swaps, options, futures and other
contractual arrangements. The derivative transactions are concentrated with
established energy companies and major financial institutions.
EES's marketing activities involve price commitments into the future and,
therefore, give rise to market risk, which represents the potential loss that
can be caused by a change in the market value of a particular commitment. Net
open portfolio positions often result from the origination of new transactions
or in response to changing market conditions. The Corporation closely monitors
and manages its exposure to market risk.
Credit risk relates to the risk of loss that the Corporation would incur as
a result of nonperformance by counterparties pursuant to the terms of their
contractual obligations. The Corporation maintains credit policies with regard
to its counterparties that management believes significantly minimize overall
credit risk. The Corporation does not obtain collateral to support the
agreements but monitors the financial viability of counterparties and believes
its credit risk is minimal on these transactions.
EES enters into contracts to purchase and sell natural gas for physical
delivery in the future. At December 31, 1996, EES had net commitments to sell
22 trillion British thermal units (Btu's) (about 21 Bcf) of natural gas
through the year 2001 with offsetting net financial positions to purchase 23
trillion Btu's (about 22 Bcf). At December 31, 1996, there was a net
unrealized and unrecognized gain of $.7 million on these contracts.
Fair Value of Financial 1996 1995
Instruments at December 31: --------------------- ---------------------
CARRYING ESTIMATED CARRYING ESTIMATED
OR NOTIONAL FAIR OR NOTIONAL FAIR
AMOUNT VALUE AMOUNT VALUE
----------- --------- ----------- ---------
On-balance sheet liabilities
Senior long-term debt (a)...... $(960,119) $(959,649) $(887,079) $(908,425)
Convertible debentures (b)..... (90,750) (90,977) (90,750) (88,027)
Off-balance sheet assets
(liabilities)
Recoverable gas-purchase con-
tracts (c).................... 1,300 1,558 5,769 5,872
Receivables sold with limited
recourse (d).................. 100,000 100,000 100,000 100,000
Interest-rate swaps (e)........ -- 925 -- (2,664)
EEX gas and oil swaps (e)...... -- 2,990 -- (1,324)
EES derivatives (f)............ -- 749 -- 2,695
Financial guarantees (e)....... -- (104,044) -- (119,095)
- --------
Estimated fair value: (a) variable-rate debt--approximates carrying amount,
exchange traded debt--quoted market prices, and other debt--discounted value
using rates for debt with similar characteristics; (b) quoted market prices;
(c) discounted cash flows; (d) approximates carrying or notional amount; (e)
based either on quotes or the cost to terminate or otherwise settle the
agreements; (f) based on mark-to-market valuations.
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, accrued interest and mandatorily
redeemable preferred securities of subsidiary, approximated carrying value.
The estimated fair
A-27
value of senior long-term debt does not reflect prepayment penalties, which
would be incurred upon early extinguishment.
8. 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 initially 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. Under amended pleadings filed in January 1997, plaintiffs have
added allegations of negligence and gross negligence in connection with the
measurement of gas and conversion. Plaintiffs seek actual damages in excess of
$5 million and punitive damages in an amount equal to .5% of the consolidated
gross revenues of the Corporation for the years 1982-1986 (approximately $85
million), interest, costs and attorneys' fees.
On September 20, 1994, the first of 21 asbestos related lawsuits was filed
against former subsidiaries of the Corporation and numerous other unrelated
defendants in the District Court of Wyandotte County, Kansas. There are
currently 280 plaintiffs who claim to have been exposed to asbestos and
asbestos related products at their places of employment since 1935. The
plaintiffs are claiming damages of $123 million for physical and psychological
injuries under theories of negligence, strict liability and breach of
warranty. An agreement has been reached to settle the case against the
Corporation in an amount that is not material to the Corporation.
On October 30, 1995, a lawsuit was filed in the Supreme Court of Western
Australia by Woodside Petroleum Ltd. and its joint venture partners against
the Corporation, a former subsidiary of the Corporation, and others.
Plaintiffs seek damages of approximately $18 million from the Corporation
based on an indemnity arrangement and approximately $208 million from the
other defendants for alleged breaches of contract and breaches of a trade
practice act, all in connection with the construction of an offshore gas and
condensate drilling production platform. The Corporation has agreed to
indemnify the current owner of the former subsidiary pursuant to the
provisions in the prior sales agreement. The Corporation is reviewing the
relevant documents and facts in order to determine the extent, if any, of its
potential liability in the lawsuit.
On April 16, 1996, the Corporation and certain directors of the Corporation,
were named as defendants in a lawsuit, Frederick Rand vs. ENSERCH Corporation,
et al, filed by an alleged shareholder in the 193rd District Court of Dallas
County, Texas. In this action, the plaintiff seeks, among other things, to
enjoin the Corporation's newly adopted shareholders rights plan and the merger
agreement between the Corporation and TUC. The plaintiff also seeks to have
the lawsuit certified as a class action. Plaintiff has taken no action since
the original filing in the case. Defendants have filed motions to challenge
plaintiff's capacity to bring the lawsuit, to determine if his allegations are
sufficient to support a lawsuit and to suspend potential discovery activity.
Hearings on the defendants' motions and a preliminary setting for the trial,
which had been initially scheduled for early September 1996, have not been
rescheduled.
Management of the Corporation believes it has meritorious defenses to the
claims made in these and other actions brought in the ordinary course of
business. In the opinion of management, the Corporation will incur no
liability from these 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, 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. 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.
A-28
Commitments--Future minimum commitments are as follows (in millions):
1997 1998 1999 2000 2001 THEREAFTER
------ ------ ----- ----- ----- ----------
Operating leases................... $ 12.7 $ 10.4 $ 8.0 $ 8.2 $ 7.9 $ 70.3
Capital leases (a)................. 12.2 23.3 25.1 30.9 26.0 236.7
Gas-purchase contracts............. 119.0 92.0 42.0 11.0 2.0 2.0
--------
(a)Includes a total of $109.4 million representing interest.
Lease Commitments--EEX's portion of the equipment and facilities used in
developing and producing reserves in the Mississippi Canyon Block 441 and
Garden Banks Block 388 projects (37.5% and 60% working interests,
respectively) were financed under equipment leases between certain financial
institutions and subsidiaries of the Corporation.
In connection with the reorganization of EEX into corporate form in December
1994, EEX entered into three subleases with a subsidiary of ENSERCH for such
offshore facilities. Through a series of transactions in 1996, the Corporation
and EEX arranged for EEX to directly lease this equipment from financial
institutions. Under the terms of the new agreements, all of the leases require
capital lease accounting treatment.
In October 1996, EEX refinanced the capital lease obligations for the
Mississippi Canyon Block 441 facilities. EEX executed a new five-year capital
lease arrangement for $16 million with a financial institution ending in
October 2001 and repaid its sublease arrangement with an ENSERCH subsidiary,
which repaid the former capital lease obligation. EEX has the option to
purchase the facilities for fair market value at the end of the lease or for a
fixed amount at an early buy out date in July 2000. There are no renewal
options.
In December 1996, EEX entered into new lease arrangements for $229 million
with a group of financial institutions for the Garden Banks Block 388
facilities, which amount includes the balance of its sublease arrangements
with an ENSERCH subsidiary and purchase of additional equipment. EEX's new
capital lease arrangements replace the ENSERCH subsidiary's former $210
million operating lease. The new capital lease arrangements have an initial
term extending through December 2010. The leases may be renewed for up to five
years. EEX has the option to purchase the facilities for fair market value at
the end of the initial term or any renewal term, or for fixed amounts at the
end of the initial term. The leases also contain several early buy out options
at various dates at fixed prices or the greater of fixed prices or fair market
value.
In June 1996, EEX entered into a $200 million operating lease agreement to
provide financing for the construction of the facilities to be used in
developing and producing reserves in the Green Canyon Block 254 project (40%
owned). Through December 31, 1996, EEX had drawn $18 million under the
agreement, $5.5 million of which had not been expended and was reflected in
current liabilities as an advance under leasing arrangements. The initial
lease term extends through June 2003 and may be extended for up to three
successive three-year periods. EEX has the option to purchase the facilities
at the end of the initial term and at December 31, 1996 has guaranteed an
estimated residual value of approximately $15 million should the lease
terminate. Lease payments will be deferred until production commences.
Capital lease transactions resulted in noncash investing and financing
transactions of $210 million in 1996 and $34 million in 1994.
The Corporation had a number of other noncancelable long-term operating
leases at December 31, 1996, principally for office space and machinery and
equipment. Rental expenses incurred under all operating leases aggregated
$28.1 million in 1996, $13.1 million in 1995 and $8.4 million in 1994. Rental
income received for subleased office space was $4.0 million in 1996,
$3.4 million in 1995 and $3.6 million in 1994. Future minimum rental income to
be received for subleased office space is $8.5 million over the next five
years.
A-29
Gas-Purchase Contracts--Lone Star Gas Company buys gas under long-term,
intrastate contracts in order to assure reliable supply to its customers. Many
of these contracts require minimum purchases of gas. LSG has made accruals for
payments that may be required for settlement of gas-purchase contract claims
asserted or that are probable of assertion. LSG continually evaluates its
position relative to asserted and unasserted claims, above-market prices or
future commitments. Management believes that LSG has not incurred losses for
which reserves should be provided at December 31, 1996. Based on estimated gas
demand, which assumes normal weather conditions, requisite gas purchases are
expected to substantially satisfy purchase obligations for the year 1997 and
thereafter.
Sales of Receivables--The Corporation has sold $100 million of receivables
under an amended limited recourse agreement that matures on September 25,
1997. Additional receivables are continually sold to replace those collected.
The agreement is expected to be extended. The uncollected balances of
receivables sold were $100 million at both year-end 1996 and 1995.
Guarantees--The Corporation and/or its subsidiaries are the guarantor on
various commitments and obligations of others aggregating some $104 million at
December 31, 1996. 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--Lone Star Gas 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, 1996 and 1995, the allowance for possible losses deducted from
accounts receivable was $5,319 and $5,174, respectively. The Corporation
believes that its provision for possible losses on uncollectible accounts
receivable is adequate for its credit loss exposure.
Inquiry into Lone Star Gas Company Rates--On August 20, 1996, the RRC
ordered a general inquiry into the rates and services of Lone Star Gas. The
scope of the inquiry has not been defined, and an evidentiary hearing has not
been held. However, at the recently concluded rate hearing requested by Lone
Star Gas and Lone Star Pipeline, RRC examiners indicated that LSG's historical
natural gas acquisition practices and costs will be reviewed. The Corporation
believes any retroactive rate action as a result of the review to be
inappropriate and unlawful.
A-30
9. 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.
Components of Net Pension Expense (in millions):
1996 1995 1994
------- ------- ------
Service cost--benefits earned during the period..... $ 5.2 $ 3.8 $ 7.5
Interest cost on projected benefit obligation....... 24.4 23.5 22.6
Actual (return) loss on assets...................... (40.4) (46.8) 3.8
Net amortization and deferral....................... 14.3 24.0 (27.4)
------- ------- ------
Net periodic pension expense........................ $ 3.5 $ 4.5 $ 6.5
======= ======= ======
Valuation Assumptions:
Discount rate....................................... 7.75% 7.65% 9.00%
Rate of increase in compensation levels............. 4.00% 4.00% 4.00%
Expected long-term rate of return on assets......... 9.50% 9.50% 9.50%
Amounts Recognized (in millions):
Actuarial present value of pension benefit obliga-
tion:
Vested benefit obligation.......................... $(302.4) $(297.0)
======= =======
Accumulated benefit obligation..................... $(305.0) $(299.3)
======= =======
Projected pension benefit obligation............... $(333.9) $(327.9)
Plan assets at fair value........................... 285.8 263.1
------- -------
Projected benefit obligation in excess of plan as-
sets............................................... (48.1) (64.8)
Unrecognized net asset at transition................ (3.4) (6.0)
Unrecognized prior service cost (credit)............ (3.6) (3.5)
Unrecognized net actuarial loss..................... 3.4 16.9
------- -------
Accrued pension cost................................ $ (51.7) $ (57.4)
======= =======
ENSERCH retained the pension obligations to former engineering and
construction employees. No further benefits will accrue for the former
employees. A plan curtailment gain of $2.2 million in 1994 was recognized in
discontinued operations.
The Corporation has approved the offer of an early-retirement option to 354
employees in connection with the pending merger with TUC. Early retirement
elections cannot be made until the merger is finalized and their impact on the
actuarial evaluation, therefore, cannot be determined at this time.
Investment Plan--A voluntary contributory investment plan is available to
substantially all employees. The Corporation matches a portion of employees'
contributions. Costs under the plans were $2.1 million, $1.8 million, and $1.9
million in 1996, 1995, and 1994, respectively.
A-31
Postretirement Benefits Other than Pensions--Some retirees 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.
Components of Net Periodic Postretirement Benefit Cost (in millions):
1996 1995 1994
------ ------ ------
Service cost--benefits earned during the period......... $ .3 $ .2 $ .4
Interest cost on projected benefit obligation........... 5.5 6.0 5.5
Net amortization and deferral........................... 4.0 3.6 4.3
------ ------ ------
Net periodic postretirement benefit cost................ $ 9.8 $ 9.8 $ 10.2
====== ====== ======
Valuation Assumptions:
Discount rate........................................... 7.75% 7.65% 9.00%
Medical cost trend rate................................. 6.50% 7.00% 12.00%
Amounts Recognized (in millions):
Accumulated postretirement benefit obligations:
Retirees and dependents................................ $(66.0) $(68.3)
Fully eligible active plan participants................ (.5) (.3)
Other active plan participants......................... (6.7) (6.9)
------ ------
Accumulated postretirement benefit obligation........... (73.2) (75.5)
Unrecognized obligation at transition................... 53.0 58.1
Unrecognized net actuarial loss......................... 10.7 10.0
------ ------
Accrued postretirement benefit cost..................... $ (9.5) $ (7.4)
====== ======
The assumed health care cost trend rate is 6.5% for 1996, declining
gradually to 4.5% after 1999, 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, 1996 and the net periodic
postretirement benefit cost for 1996 would be increased by $4.2 million and
$.3 million, respectively.
A-32
10. INCOME TAXES
Provision (Benefit) for Income Taxes on Continuing Operations:
1996 1995 1994
------- ------- --------
Current
Federal............................................. $ 4,746 $ 6,230 $(10,196)
State............................................... 176 321 560
Foreign............................................. 79 50 50
------- ------- --------
Total.............................................. 5,001 6,601 (9,586)
------- ------- --------
Deferred
Federal............................................. 10,708 (5,680) (59,151)
Foreign............................................. 29 -- --
------- ------- --------
Total.............................................. 10,737 (5,680) (59,151)
------- ------- --------
Total............................................. $15,738 $ 921 $(68,737)
======= ======= ========
Reconciliation of Income Taxes Computed at the Federal Statutory Rate to
Provision for Income Taxes (Benefit) of Continuing Operations:
1996 1995 1994
------- ------- --------
Income (loss) from continuing operations before
income taxes and after minority interest:
Domestic......................................... $47,717 $18,143 $ 15,993
Foreign.......................................... (9,281) (4,169) (3,278)
------- ------- --------
Total........................................... $38,436 $13,974 $ 12,715
======= ======= ========
Income taxes computed at the federal statutory
rate of 35%...................................... $13,453 $ 4,891 $ 4,450
State and foreign taxes........................... 185 242 397
Increase in (reduction of) prior year tax liabili-
ties............................................. 723 (3,590) (3,734)
Nondeductible distribution and merger related
costs............................................ 2,275 -- --
Nondeductible meals and entertainment............. 429 427 360
Change in tax status.............................. -- -- (70,000)
Amortization of property basis difference from EEX
stock sale....................................... (1,550) (454) --
Percentage depletion.............................. (338) (324) (22)
Tax benefit of dividends to ESOP.................. -- -- (256)
Other--net........................................ 561 (271) 68
------- ------- --------
Provision for Income Taxes (Benefit).............. $15,738 $ 921 $(68,737)
======= ======= ========
At the completion of the conversion of EP and EPPL to corporate form in
1994, 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 in 1994.
A-33
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, 1996 and 1995 balance sheet dates are as follows:
1996 1995
-------------------------------- --------------------------------
TOTAL CURRENT NONCURRENT TOTAL CURRENT NONCURRENT
-------- -------- ---------- -------- -------- ----------
Deferred Tax Assets:
Net operating-loss and
other
tax-credit
carryforwards.......... $159,739 $ -- $159,739 $103,915 $ -- $103,915
Retirement and other
employee benefit
obligations............ 23,883 3,225 20,658 27,811 3,078 24,733
Accruals and
allowances............. 25,201 11,893 13,308 27,755 15,452 12,303
Losses of controlled
foreign corporations... 14,016 -- 14,016 9,848 -- 9,848
All other............... 19,891 8,053 11,838 14,212 4,356 9,856
-------- -------- -------- -------- -------- --------
Total................. 242,730 23,171 219,559 183,541 22,886 160,655
-------- -------- -------- -------- -------- --------
Deferred Tax
Liabilities:
Exploration and
intangible development
costs.................. 183,013 -- 183,013 201,865 -- 201,865
Property-related
differences............ 264,103 -- 264,103 173,997 -- 173,997
Deferred gas-purchase
contract settlements... -- -- -- 1,553 1,553 --
All other............... 62,132 1,390 60,742 61,877 8 61,869
-------- -------- -------- -------- -------- --------
Total................. 509,248 1,390 507,858 439,292 1,561 437,731
-------- -------- -------- -------- -------- --------
Net Deferred Tax
Liability (Asset)...... $266,518 $(21,781)(a) $288,299 $255,751 $(21,325)(a) $277,076
======== ======== ======== ======== ======== ========
- --------
(a)Included in other current assets in the balance sheet.
At December 31, 1996, domestic net operating-loss carryforwards total $387
million, which begin to expire in 2003, and tax-credit carryforwards total $24
million, which begin to expire in 1999. The tax benefits of these carryforwards
of $160 million, as shown above, are available to reduce future income-tax
payments.
1996 1995 1994
Cash Payments (Refunds) of Income Taxes: ------- -------- --------
Federal:
Current year, including alternative minimum tax..... $ 6,430 $ 8,363 $ 10,650
Prior years......................................... (5,330) (10,413) (12,148)
------- -------- --------
Total.............................................. 1,100 (2,050) (1,498)
State................................................ 132 (3,609) 6,743
Foreign.............................................. 189 -- --
------- -------- --------
Total.............................................. $ 1,421 $ (5,659) $ 5,245
======= ======== ========
A-34
11. DISCONTINUED OPERATIONS
In October 1994, the Corporation sold Enserch Environmental Corporation,
which conducted the former environmental businesses of Ebasco Services
Incorporated (Ebasco), for $98 million. The principal operating assets of
Ebasco were sold in December 1993. Discontinued operations are summarized as
follows:
1996 1995 1994
Operating Information: -------- -------- ---------
Revenues....................................... $ -- $ -- $ 72,081
Cost and expenses.............................. -- -- 68,246
-------- -------- ---------
Operating income............................... -- -- 3,835
Interest expense............................... -- -- (1,241)
Income taxes................................... -- -- (1,225)
-------- -------- ---------
Income from operations......................... -- -- 1,369
Gain on sale, net of income-tax provision of
$15,750....................................... -- -- 29,250
Provision for additional costs and expenses for
the wind-up of discontinued businesses, net of
income-tax provision of $2,160 in 1996 and tax
benefit of $7,523 in 1994..................... (1,560) -- (9,977)
-------- -------- ---------
Total........................................ $ (1,560) $ -- $ 20,642
======== ======== =========
Cash Flow Information:
Net cash flows from (used for)
Operating activities.......................... $ (7,274) $(28,102) $(107,487)
Proceeds from sales of assets................. -- -- 97,749
Investing activities.......................... -- -- 8,796
-------- -------- ---------
Net cash flows from (used for) discontinued
operations.................................. $ (7,274) $(28,102) $ (942)
======== ======== =========
Loss provisions of $1.6 million after-tax and $10.0 million after-tax were
recorded in 1996 and 1994, respectively, in recognition that certain claims
and accounts receivable were settled at amounts less than previously estimated
and costs and expenses incurred for the windup of discontinued businesses
would be greater than previously estimated.
At December 31, 1996, discontinued businesses had assets of $46 million,
consisting principally of retained claims and accounts receivable of the
Ebasco and Enserch Environmental business units, and current and other
liabilities and reserves of $18 million. The Corporation has filed suit
against certain parties to recover amounts outstanding. Management expects
that substantially all disputes will be resolved by year-end 1997 and that
adequate provision for uncollectible claims and accounts receivable, income-
tax matters and expenses for windup of discontinued operations has been made.
A-35
12. 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.
1996 1995
Capitalized Costs (in millions): -------- --------
Proved gas and oil properties................................ $2,614.7 $2,362.1
Unproved gas and oil properties.............................. 234.0 199.3
-------- --------
Total...................................................... $2,848.7 $2,561.4
======== ========
Accumulated depreciation and amortization.................... $1,067.3 $ 933.4
======== ========
1996 1995 1994
Costs Incurred (in millions): ------------ ------------ ------------
NON- NON- NON-
U.S. U.S. U.S. U.S. U.S. U.S.
------ ----- ------ ----- ------ -----
Property acquisition costs:
Proved................................. $ 3.2 $ -- $356.3 $ -- $ 1.6 $ --
Unproved............................... 23.4 -- 133.3 -- 20.6 --
Exploration costs....................... 84.6 2.8 68.7 9.0 58.7 3.3
Development costs....................... 100.4 .6 77.6 -- 56.8 --
------ ----- ------ ----- ------ -----
Total................................. $211.6 $ 3.4 $635.9 $ 9.0 $137.7 $ 3.3
====== ===== ====== ===== ====== =====
Amortization (Per MMBtu) (a)............ $ 1.08 -- $ 1.01 -- $ 1.04 --
- --------
(a) Amortization expense per unit of production converted to a common unit of
measure, millions of British thermal units (MMBtu); on a per thousand
cubic feet of gas equivalent (Mcfe) basis, the amounts are: $1.09, $1.03
and $1.06.
Costs Excluded from the Amortizable Base as of December 31, 1996 (in
millions):
TOTAL AT
PRIOR DECEMBER 31,
YEAR INCURRED 1996 1995 1994 YEARS 1996
- ------------- ----- ------ ------ ----- ------------
Property acquisition costs............... $19.2 $ 56.5 $ 15.7 $ 1.2 $ 92.6
Exploration costs........................ 21.8 14.3 10.5 2.7 49.3
Interest capitalized..................... 5.5 3.6 1.8 1.5 12.4
Development costs........................ 7.7 28.5 33.2 10.3 79.7
----- ------ ------ ----- ------
Total.................................. $54.2 $102.9 $ 61.2 $15.7 $234.0
===== ====== ====== ===== ======
Approximately 51% of the excluded costs relates to offshore activities in
the Gulf of Mexico, about 45% 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.
A-36
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 interest expense
and corporate overhead.
1996 1995 1994
Results of Operations (in millions): ------------ ------------ ------------
NON- NON- NON-
U.S. U.S. U.S. U.S. U.S. U.S.
------ ----- ------ ----- ------ -----
Revenues:
Affiliated.......................... $ 86.0 $ -- $ 86.7 $ -- $110.0 $ --
Nonaffiliated....................... 262.6 -- 131.9 -- 63.5 --
Less:
Production costs (a)................ 98.0 -- 67.2 -- 44.0 --
Exploration costs (b)............... 10.2 2.3 9.6 2.3 8.4 1.0
Depreciation and amortization (c)... 147.5 -- 116.4 .9 85.6 --
Income-tax effects.................. 32.2 (.8) 8.6 (1.1) 12.4 (.3)
------ ----- ------ ----- ------ -----
Net producing activities............ $ 60.7 $(1.5) $ 16.8 $(2.1) $ 23.1 $ (.7)
====== ===== ====== ===== ====== =====
- --------
(a) Includes severance, ad valorem and production taxes.
(b) Includes internal costs that cannot be directly identified with
acquisition, exploration or development activities.
(c) Amount for 1995 includes a write-down of non-U.S. exploratory projects of
$.9 million. Amount for 1994 excludes a $7.6 million gain from the sale of
an inactive offshore pipeline and facilities, which were not related to gas
and oil producing activities.
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.
GAS (MMCF) OIL (MBBLS)(A)
U. S. Reserves: ------------------------------- -----------------------
1996 1995 1994 1996 1995 1994
--------- --------- --------- ------ ------- ------
At January 1............ 1,362,763 1,041,736 1,086,482 66,537 46,486 39,349
Changes in reserves
Revisions of previous
estimates............. (7,935) 26,802 (25,106) (8,173) 2,312 (499)
Extensions, discoveries
and additions......... 72,854 62,249 47,580 4,315 21,466 9,877
Purchase of minerals in
place................. 12,347 336,668 787 -- 11,417 14
Sales of minerals in
place................. (123,861) (14,497) (894) (3,730) (11,274) (28)
Production............. (100,544) (90,195) (67,113) (5,740) (3,870) (2,227)
--------- --------- --------- ------ ------- ------
At December 31.......... 1,215,624 1,362,763 1,041,736 53,209 66,537 46,486
========= ========= ========= ====== ======= ======
Proved Developed Re-
serves
At January 1........... 937,372 698,643 735,093 30,110 14,437 15,380
At December 31......... 859,094 937,372 698,643 27,938 30,110 14,437
- --------
(a) Includes condensate and natural gas liquids attributable to leasehold
interests of 1,103 MBbls for 1996, 3,593 MBbls for 1995 and 911 MBbls for
1994.
GAS(MMCF) OIL (MBBLS)
Non-U.S. Reserves: --------- -----------------
1996 1996 1995 1994
--------- ----- ----- -----
At January 1........................................ -- 4,963 4,105 --
Extensions, discoveries and additions.............. 618 1,045 858 4,105
--- ----- ----- -----
At December 31...................................... 618 6,008 4,963 4,105
=== ===== ===== =====
Proved Developed.................................... -- -- -- --
A-37
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 prices and contracts 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) $3.37 in 1996; $2.19 in 1995 and $2.29 in 1994. Oil (per
barrel) $23.33 in 1996; $16.91 in 1995 and $14.07 in 1994.
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.
1996 1995 1994
Standardized Measure (in millions): --------- -------- ---------
Future cash inflows........................... $ 5,474.3 $4,180.7 $ 3,101.1
Future production and development costs....... (1,552.9) (1,568.9) (1,218.5)
Future income-tax expense..................... (1,019.3) (539.1) (499.3)
--------- -------- ---------
Future net cash flows......................... 2,902.1 2,072.7 1,383.3
Less 10% annual discount...................... 1,167.6 834.8 556.1
--------- -------- ---------
Standardized measure of discounted future net
cash flows................................... $ 1,734.5 $1,237.9 $ 827.2
========= ======== =========
Change in Standardized Measure (in millions):
Sales and transfers of gas and oil produced,
net of production costs...................... $ (254.4) $ (151.4) $ (120.8)
Changes in prices, net of production and fu-
ture development costs....................... 1,097.0 63.1 (15.6)
Extensions, discoveries and improved recovery,
less related costs........................... 185.0 175.8 121.3
Purchases of minerals in place................ 3.2 367.6 1.6
Revisions of previous quantity estimates...... (238.7) (122.8) (87.1)
Sales of minerals in place.................... (125.2) (22.9) (1.3)
Accretion of discount......................... 141.6 103.3 102.7
Net change in income taxes.................... (349.4) 7.6 5.1
Other......................................... 37.5 (9.6) (9.3)
--------- -------- ---------
Total....................................... $ 496.6 $ 410.7 $ (3.4)
========= ======== =========
As the estimates of future site restoration, dismantlement and abandonment
costs on an overall cost center basis are less than estimates of future
salvage value, such costs were not included in the standardized measure.
13. OTHER EXPENSE--NET
1996 1995 1994
Summary of Other Income (Expense)--Net: --------- -------- ---------
Gain on disposal of assets.................... $ 26 $ 3,057 $ 135
Gain on termination of interest-rate swap..... 2,211 -- --
Discount on sale of receivables............... (5,149) (5,607) (4,774)
Interest income............................... 2,736 2,544 1,937
Merger and distribution expenses.............. (6,791) -- --
Loss on reacquired debentures................. -- (287) (1,350)
Professional fees for restructuring........... -- -- (2,683)
Equity in losses of unconsolidated affili-
ates......................................... (3,821) (821) (377)
Other......................................... (434) 81 1,064
--------- -------- ---------
Total....................................... $ (11,222) $ (1,033) $ (6,048)
========= ======== =========
A-38
SUMMARY OF BUSINESS SEGMENTS
The Corporation's major business segments are natural gas and oil
exploration and production; natural gas pipeline, processing & marketing;
natural gas distribution; and power and other. Through these business
segments, the Corporation is engaged in (1) natural gas and oil exploration
and production--exploring for, developing, producing and marketing natural gas
and oil, (2) natural gas pipeline, processing & marketing--owning and
operating interconnected natural gas transmission lines, underground storage
reservoirs, compressor stations and related properties, all within Texas;
gathering and processing natural gas to remove impurities and extract liquid
hydrocarbons for sale; and the wholesale and retail marketing of natural gas
in several areas of the U.S., (3) natural gas distribution--owning and
operating some 550 local gas utility distribution systems in Texas, and (4)
power and other--developing, financing and operating electric power generating
plants and cogeneration facilities; operating thermal energy plants for large
building complexes, such as universities and medical centers; and developing
gas distribution systems in Mexico and South America.
NATURAL GAS
AND OIL NATURAL GAS
EXPLORATION PIPELINE, POWER GENERAL
AND PROCESSING NATURAL GAS AND AND
PRODUCTION & MARKETING DISTRIBUTION OTHER OTHER CONSOLIDATED
----------- ----------- ------------ ------- ------- ------------
Revenues from
Nonaffiliates
1996................... $ 245,075 $ 965,707 $894,035 $37,808 $ $2,142,625
1995................... 133,876 864,872 892,675 39,817 1,931,240
1994................... 69,140 1,100,916 879,953 45,499 2,095,508
Intersegment Revenues
from Affiliates
(eliminated in
consolidation)
1996................... 86,129 160,743 1,189 248,061
1995................... 87,002 131,552 1,174 219,728
1994................... 110,191 134,656 1,383 246,230
Operating Income (Loss)
1996................... 32,224 63,444 68,157 (8,239) (9,266) 146,320
1995................... (12,023) 60,153 54,634 3,478 (8,513) 97,729
1994................... 25,420 27,245 38,334 5,761 (8,114) 88,646
Depreciation and
Amortization
1996................... 151,026 24,390 27,208 1,516 705 204,845
1995................... 119,976 21,158 24,906 1,563 659 168,262
1994................... 79,982 22,500 22,475 1,403 619 126,979
Identifiable Assets
1996................... 1,876,723 938,514 712,400 84,865 132,075(a) 3,744,577
1995................... 1,720,349 723,023 744,981 38,630 154,111(a) 3,381,094
1994................... 1,298,130 694,506 698,341 41,794 155,766(a) 2,888,537
Gross Additions to
Property, Plant and
Equipment
1996................... 204,363 50,949 80,380 53 894 336,639
1995................... 190,168(b) 44,617 61,286 312 643 297,026
1994................... 133,254 47,503 78,186 622 493 260,058
- --------
(a)Includes $46,035 in 1996, $74,051 in 1995 and $62,622 in 1994 related to
discontinued operations.
(b)Excludes property acquired in the purchase of a gas and oil exploration and
production company.
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. 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.
A-39
QUARTERLY RESULTS (UNAUDITED)
The results of operations by quarters are summarized below. In the opinion of
the Corporation's management, all adjustments (consisting only of normal
recurring accruals) necessary for a fair presentation have been made.
QUARTER ENDED
-------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
-------- -------- ------------ -----------
1996:
Revenues.......................... $678,643 $415,155 $385,515 $663,312
Operating Income.................. 70,392 15,075 4,696 56,157
Income (Loss) From Continuing
Operations....................... 29,777 (6,701) (15,281) 14,903
Loss From Discontinued
Operations....................... -- -- -- (1,560)
Extraordinary Loss on
Extinguishment of Debt........... -- -- (2,096) --
Net Income (Loss)................. 29,777 (6,701) (17,377) 13,343
Earnings (Loss) Applicable to
Common Stock..................... 27,018 (9,518) (20,263) 10,466
Per Share of Common Stock:
Income (loss) from continuing
operations...................... $ .39 $ (.14) $ (.26) $ .17
Discontinued operations.......... -- -- -- (.02)
Extraordinary loss............... -- -- (.03) --
-------- -------- -------- --------
Earnings (loss) applicable to
common stock.................... $ .39 $ (.14) $ (.29) $ .15
1995:
Revenues.......................... $612,641 $396,160 $414,547 $507,892
Operating Income (Loss)........... 67,532 (3,938) 4,114 30,021
Net Income (Loss)................. 30,816 (14,632) (13,771) 10,640
Earnings (Loss) Applicable to
Common Stock..................... 27,780 (17,613) (16,637) 7,833
Per Share of Common Stock--
Earnings (loss) applicable to
common stock..................... $ .41 $ (.26) $ (.24) $ .11
A-40
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.
1996 1995 1994
--------------- --------------- ---------------
HIGH LOW HIGH LOW HIGH LOW
------- ------- ------- ------- ------- -------
First Quarter................... $16 3/4 $14 1/8 $15 1/8 $12 5/8 $19 1/8 $12 7/8
Second Quarter.................. 22 1/8 15 7/8 18 3/8 14 5/8 15 1/4 12 5/8
Third Quarter................... 22 3/4 19 1/4 18 5/8 15 7/8 16 1/2 13 1/8
Fourth Quarter.................. 23 3/4 20 5/8 16 7/8 14 1/4 15 12 1/8
1993 1992 1991
--------------- --------------- ---------------
HIGH LOW HIGH LOW HIGH LOW
------- ------- ------- ------- ------- -------
First Quarter................... $19 1/8 $14 1/8 $14 3/8 $10 3/8 $20 1/2 $16 7/8
Second Quarter.................. 19 5/8 16 7/8 16 3/8 12 1/8 21 3/8 17 1/8
Third Quarter................... 22 5/8 17 1/2 16 1/8 14 18 3/4 15 5/8
Fourth Quarter.................. 21 1/4 15 1/2 16 1/2 13 3/4 17 1/2 12 3/4
COMMON STOCK DATA AT YEAR-END
1996 1995 1994 1993 1992 1991
------ ------ ------ ------ ------ ------
Shareholders of Record............... 16,973 19,247 19,614 20,406 22,832 23,979
------ ------ ------ ------ ------ ------
Shares Outstanding (000's)........... 70,280 68,516 68,158 67,860 67,238 66,506
------ ------ ------ ------ ------ ------
DIVIDENDS PER SHARE OF COMMON STOCK
As of December 31, 1996, the Corporation had paid 210 consecutive quarterly
cash dividends on its common stock. At December 31, 1996, $569 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 1997, a quarterly cash dividend of $.05
per share was declared, payable March 3, 1997, to shareholders of record on
February 21, 1997. Quarterly cash dividends on common stock were $.05 per
share (annual rate of $.20 per share) in 1996 through 1993 and $.20 per share
(annual rate of $.80 per share) for the two preceding years.
A-41