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.
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.
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
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
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.
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
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
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.
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
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).
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.
ITEM 2.
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:
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:
- -------- (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.
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:
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:
- -------- 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.
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.
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Not applicable.
PART II
ITEM 5.
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.
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.
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.
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.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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.
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
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.
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.
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
- -------- (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.
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
- -------- (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.
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
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
- -------- (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.
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
- -------- (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
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
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
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
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]
- -------- (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.
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.
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.
- -------- (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.
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:
- -------- * 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.
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.
PART IV
ITEM 14.
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:
(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:
- -------- * 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).
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
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
INDEX TO FINANCIAL INFORMATION
DECEMBER 31, 1996
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ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
SELECTED FINANCIAL DATA
See Notes on page A-3.
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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.
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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.
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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:
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.
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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.
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NATURAL GAS AND OIL EXPLORATION AND PRODUCTION OPERATING DATA (A)
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NATURAL GAS PIPELINE, PROCESSING & MARKETING OPERATING DATA (A)
- -------- (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.
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NATURAL GAS DISTRIBUTION OPERATING DATA (A)
- -------- (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.
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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
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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
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ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED INCOME
See Notes to Consolidated Financial Statements.
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ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Information on noncash investing and financing activities is presented in Note 8.
See Notes to Consolidated Financial Statements.
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ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
See Notes to Consolidated Financial Statements.
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ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
STATEMENTS OF CONSOLIDATED COMMON SHAREHOLDERS' EQUITY
See Notes to Consolidated Financial Statements.
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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
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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.
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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
-------- * 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.
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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.
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.
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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.
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:
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.
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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.
- -------- (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:
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
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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:
-------- * 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
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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.
- -------- 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
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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.
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Commitments--Future minimum commitments are as follows (in millions):
-------- (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.
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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.
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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):
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.
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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):
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.
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10. INCOME TAXES
Provision (Benefit) for Income Taxes on Continuing Operations:
Reconciliation of Income Taxes Computed at the Federal Statutory Rate to Provision for Income Taxes (Benefit) of Continuing Operations:
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.
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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:
- -------- (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.
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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:
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.
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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.
- -------- (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):
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.
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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.
- -------- (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.
- -------- (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.
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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.
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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.
- -------- (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.
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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.
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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.
COMMON STOCK DATA AT YEAR-END
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.
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