ITEM 1. Business
ENSERCH Corporation ("ENSERCH" or the "Corporation") is an integrated company focused on natural gas. It is the successor to a company originally organized in 1909 for the purpose of providing natural-gas service to North Texas. The Corporation's operations include the following:
- Natural Gas Transmission and Distribution--Owning and operating interconnected natural-gas transmission pipelines, gathering lines, underground gas storage reservoirs, compressor stations, distribution systems and related properties; transporting, distributing and selling natural gas to residential, commercial, industrial, electric-generation, gas marketers, pipelines and other customers; and compressing natural gas for motor vehicle usage. (Lone Star Gas Company, a division of the Corporation, Enserch Gas Company and related operations.)
- Natural Gas and Oil Exploration and Production--Exploring for, developing, producing and marketing natural gas and oil. (Enserch Exploration, Inc. [more than 99% owned], Enserch International Exploration, Inc. and related operations.)
- Natural Gas Liquids Processing--Gathering natural gas, processing natural gas to produce liquids and marketing the products. (Enserch Processing Company, a division of the Corporation.)
- Power--Developing, operating and maintaining independent electric-generation power plants and cogeneration facilities; and furnishing energy services under long-term contracts to large building complexes, such as universities and medical centers. (Enserch Development Corporation and Lone Star Energy Company.)
In October 1994, the Corporation completed the divestiture of its former engineering and construction segment by the sale of Enserch Environmental Corporation, the subsidiary that had conducted the Corporation's environmental business. See "Financial Review" and Note 7 of the Notes to Consolidated Financial Statements included in Appendix A to this report.
Business Segments
Financial information required hereunder is set forth under "Summary of Business Segments" included in Appendix A to this report.
Natural Gas Transmission and Distribution
The Corporation's transmission and distribution business ("T&D") is composed of the regulated business of Lone Star Gas Company ("Lone Star") and the nonregulated gas marketing operations of Enserch Gas Company ("EGC").
Lone Star owns and operates interconnected natural-gas transmission lines, gathering lines, underground gas storage reservoirs, compressor stations, distribution systems and related properties. Through and by such facilities, it purchases, distributes and sells natural gas to about 1.28 million residential, commercial, industrial and electric-generation customers in approximately 550 cities and towns, including the 11- county Dallas/Fort Worth Metroplex. Lone Star also transports natural gas as market opportunities are available. About seven million people in Texas, representing over 40% of the total state population, reside in Lone Star's service area.
EGC purchases and sells natural gas to gas marketing companies, industrial and electric-generation customers and to unaffiliated pipeline and local distribution companies.
The Corporation holds a 50% interest in a partnership named Gulf Coast Natural Gas Company, which operates a transmission system in the Texas Gulf Coast area that transports and sells natural gas primarily to industrial and unaffiliated pipeline customers.
Operating data for the T&D segment are set forth under "Financial Review - Natural Gas Transmission and Distribution Operating Data" included in Appendix A to this report.
For the year ended December 31, 1994, residential and commercial customers accounted for 46% of T&D's total gas sales revenues and 23% of natural-gas volumes sold, industrial and electric-generation customers accounted for 19% and 22%, respectively, and sales to gas marketers, pipelines and other customers accounted for 35% and 55%, respectively. In 1994, 5% of T&D's gas sales volumes was sold to Texas Utilities Fuel Company, compared with 10% in 1993. See "Financial Review - Natural Gas Transmission and Distribution" included in Appendix A to this report for a discussion of Lone Star's gas sales margin.
Revenues from Lone Star's gas sales are affected by seasonal variations. The majority of Lone Star's residential and commercial gas customers use gas for heating. Revenues from these customers are affected by the mildness or severity of the heating season. Gas sales to electric-generation customers are affected by the mildness or severity of both cooling and heating seasons.
Competition. Natural gas continues to face varying degrees of competition from electricity, coal, natural gas liquids, oil and other refined products throughout Lone Star's service territory. Pipeline systems of other companies, both intrastate and interstate, extend into or through the areas in which Lone Star's markets are located, creating competition from other sellers of natural gas. Customer sensitivity to energy prices and the availability of competitively priced gas in the nonregulated markets continue to provide intense competition in the electric- generation and industrial user markets. Competitive pressure from other pipelines and alternative fuels has caused a decline in sales by Lone Star to industrial and electric-generation customers. Sales by the Corporation's nonregulated companies, along with transportation services provided by Lone Star, have served to offset much of the effects of this decline.
Competition to serve electric-generation customers was heightened in 1994, as it was the first full year of operation of a new nuclear-powered electric generating unit, which brought the number of operating units in Texas to four, versus one and one-half functioning units in 1993. These units displace about 1 billion cubic feet ("Bcf") of gas-fired generating capacity each day. Texas gas markets experienced the full impact of these units in 1994. This and other factors resulted in a 27% decline in volumes sold for electric generation from the prior year. However, most of the decline was in the lower margin sales by EGC, while margins from Lone Star's remaining long-term contracts that extend through the end of the decade remain intact.
The purchase and sale of gas in nonregulated markets is accomplished through the gas marketing activities of EGC, which actively pursues sales to customers that are tied to pipelines other than Lone Star's. Sales are accomplished by a trading group that sells gas to other marketers, as well as to end-users. As natural-gas markets continue to evolve following the implementation of the 1992 Order 636 of the Federal Energy Regulatory Commission ("FERC"), additional opportunities are created in the broader, more active trading markets and in serving off-system customers. Services to customers on off-system pipelines include term contracts with interruptible and firm deliveries, aggregation of supply, nominations, scheduling of deliveries and storage. Some sale opportunities allow for gas to move across Lone Star's system, thereby generating incremental transportation revenue. Trading activities with other marketing companies have become a significantly larger segment of the off-system business. With the advent of essentially instant price determination, margins are attainable only by taking positions in the monthly markets and selling as prices move from moment to moment. ENSERCH generally takes positions in transactions that will be concluded within a few months and generally no longer than twelve months. ENSERCH does not enter into multi-year, fixed-term contracts without having a corresponding supply or sale.
A portion of the sales made by EGC requires transportation on Lone Star's pipeline system. Additionally, Lone Star provides transportation services not related to EGC sales (nonaffiliated transportation). The movement of gas from the West Texas and New Mexico producing areas to the east provides a market for transportation across Lone Star's system. Intense competition exists within the transportation business, which has resulted in downward pressure on the average rate received for transportation services. Lone Star's transportation volumes were 389 Bcf in 1994, a 5% increase from 1993; however, transportation revenues for 1994 of $52 million were about the same as 1993.
In the current energy market, Lone Star's contracts for new gas reserves have been at prices below its current system-wide weighted average cost of gas and are expected to continue to be so in the foreseeable future.
Source and Availability of Raw Materials. Lone Star's gas supply is based on contracts for the purchase of dedicated specific reserves and contracts with other pipeline companies in the form of service agreements that are not related to specific reserves or fields. Management has calculated that the total contracted gas supply as of January 1, 1995 was 1.02 trillion cubic feet ("Tcf"), or approximately 6 times Lone Star's purchases during 1994. Of this total, 349 Bcf are dedicated reserves, 47 Bcf are gas in storage, 624 Bcf (including 284 Bcf under one agreement) are committed to Lone Star under service agreements. The January 1, 1995 total gas supply estimate is 48 Bcf greater than the January 1, 1994 estimate. The difference resulted from new supply additions of 202 Bcf and a net upward revision of 9 Bcf with respect to estimates for existing sources and service agreements, less 163 Bcf purchased from existing gas supply. New reserve additions consisted of 92 Bcf on new dedicated reserves under old contracts and 110 Bcf of reserves added under new service and peaking contracts.
In 1994, about 91% of Lone Star's gas requirement was purchased from some 270 independent producers and nonaffiliated pipeline companies, one of which supplied approximately 14.2% of total requirements. The remaining 9% of Lone Star's requirement was supplied by affiliates.
Lone Star estimates its peak-day availability from presently contracted sources, including withdrawals from underground storage, to be 1.7 Bcf. Short-term peaking contracts raise this level to meet anticipated sales needs.
During 1994, the average daily demand of Lone Star's residential and commercial customers was .3 Bcf. The estimated peak-day demand of such customers (based upon an arithmetic-mean outside temperature of 15 degrees F.) was 2.0 Bcf. Lone Star's greatest daily demand in 1994 was on February 10, when estimated actual deliveries to all customers reached 1.8 Bcf and there was an arithmetic-mean temperature of 30 degrees F. The estimated deliveries to residential and commercial customers on that day were 1.3 Bcf and another 1.3 Bcf were transported by Lone Star.
To meet peak-day gas demands during winter months, Lone Star utilizes its seven active underground storage fields, all of which are located in Texas. These fields have an extraneous gas capacity of 62 Bcf. At December 31, 1994, total extraneous gas in storage was approximately 50 Bcf. Gas withdrawn from storage on February 10, 1994, the date of Lone Star's greatest daily demand in 1994, was .6 Bcf, or approximately 30% of the total 2.0 Bcf of Lone Star's sales.
Lone Star has historically maintained a contractual right to curtail, which is designed to achieve the highest load factor possible in the use of its pipeline system while assuring continuous and uninterrupted service to its residential and commercial customers. Under the program, industrial customers select their own rates and relative priorities of service. Interruptible service contracts include the right to curtail gas deliveries up to 100% according to a strict priority plan. The last curtailment was in 1990 and lasted for only 30 hours.
Estimates of gas supplies and reserves are not necessarily indicative of Lone Star's ability to meet current or anticipated market demands or immediate delivery requirements because of factors such as the physical limitations of gathering and transmission systems, the duration and severity of cold weather, the availability of gas reserves from its suppliers, the ability to purchase additional supplies on a short-term basis and actions by federal and state regulatory authorities. Lone Star's curtailment rights provide flexibility to meet the human-needs requirements of its customers on a firm basis. Priority allocations and price limitations imposed by federal and state regulatory agencies, as well as other factors beyond the control of Lone Star, may affect its ability to meet the demands of its customers.
Lone Star pursues a program designed to place new supplies of gas under contract to its pipeline system. In addition to being heavily concentrated in the established gas-producing areas of central, northern and eastern Texas, Lone Star's intrastate pipeline system also extends into or near the major gas-producing areas of the Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. Nine basins located in Texas are estimated to contain a substantial portion of the nation's remaining onshore natural-gas reserves. Lone Star's pipeline system provides access to all of these basins.
In the past, Lone Star purchased gas under long-term, intrastate contracts in order to assure reliable supply to its distribution customers. Many of these contracts provided for minimum-purchase or payment ("take-or-pay") obligations to gas sellers. Lone Star had been unable to take delivery of all minimum gas volumes tendered by suppliers under these contracts. Based on Lone Star's estimated gas demand, which assumes normal weather conditions, requisite gas purchases are expected to substantially satisfy purchase obligations for the year 1995 and thereafter. See "Financial Review - Natural Gas Transmission and Distribution" and Note 1 to Consolidated Financial Statements included in Appendix A to this report.
Generally, EGC's gas supply is contracted for on a short-term basis at prevailing market prices for similar packages of gas. The availability of supply is dependent on many factors, including the overall demand for natural gas and a nonregulated market price high enough to warrant suppliers to sell.
Regulation. Lone Star Gas is wholly intrastate in character and performs utility operations in the state of Texas subject to regulation by the Railroad Commission of Texas ("RRC") and municipalities in Texas. Lone Star owns no certificated interstate transmission facilities subject to the jurisdiction of FERC under the Natural Gas Act, has no sales for resale under the rate jurisdiction of FERC and does not perform any transportation service that is subject to FERC jurisdiction under the Natural Gas Act.
In July 1988, Lone Star became an open-access transporter under Section 311 of the Natural Gas Policy Act of 1978 ("NGPA") on its intrastate transmission facilities. Such transportation is performed pursuant to Section 311(a)(2) of the NGPA and is subject to an exemption from the jurisdiction of the FERC under the Natural Gas Act, pursuant to Section 601 of the NGPA.
The RRC regulates the intracompany charge for gas delivered to Texas distribution systems for sale to residential and commercial consumers. The RRC has original jurisdiction over rates charged to residential and commercial customers for gas delivered outside incorporated cities and towns (environs rates). Rates within incorporated cities and towns in Texas are subject to the original jurisdiction of the local city council with appellate review by the RRC.
Lone Star employs a continuing program of rate review for all classes of customers in its regulatory jurisdictions. Rate relief amounting to $2.5 million in annualized revenue increases over and above changes in gas cost was achieved in Texas in 1994 through rate case filings, the operation of cost of service adjustment clauses, and the operation of plant investment cost adjustments. About 128 of the 550 cities and towns served by Lone Star had approved weather normalization adjustment clauses as part of their rate structure by year-end 1994, representing about 20% of Lone Star's residential and commercial sales volumes. These clauses allow rates to be adjusted monthly to reflect the impact of warmer- or colder-than-normal weather , minimizing the impact of variations in weather on Lone Star's earnings.
Lone Star's sales and transportation services to industrial and electric-generation customers is provided under competitively negotiated contracts. Regulatory authorities in Texas have jurisdiction to revise, review and regulate rates to industrial and electric-generation customers but, historically, have not exercised this jurisdiction because of the existing competitive market. Contracts with these customers permit automatic adjustment on a monthly basis for the full amount of increases or decreases in the cost of gas.
Natural Gas and Oil Exploration and Production
The Corporation's natural gas and oil exploration and production operations include geological and geophysical studies; acquisition of gas, oil and mineral leases; drilling of exploratory wells; development and operation of producing properties; acquisition of interests in developed or partially developed properties; and the marketing of natural gas, crude oil and condensate.
The Corporation's domestic operations are currently conducted through Enserch Exploration, Inc. ("Enserch Exploration" or "EEX"), a newly organized, publicly traded Texas corporation listed on the New York Stock Exchange under the symbol "EEX". During 1994, domestic gas and oil operations were primarily conducted through Enserch Exploration Partners, Ltd. ("EP"), a limited partnership in which a minority interest (less than 1%) was held by the public. At year-end 1994, pursuant to a plan for the reorganization of EP ("Reorganization"), EEX, through a series of transactions, acquired all of the operating properties of EP from EP's 99%-owned operating partnership, EP Operating Limited Partnership ("EPO"), in exchange for shares of EEX common stock. On December 30, 1994, the Reorganization was consummated, EP was dissolved, and the EEX common stock held by EP was distributed to EP's limited and general partners in accordance with their partnership interests. In this report, "Enserch Exploration" or "EEX" is used to refer to either EEX or EP, or both, when a distinction is not required.
In connection with the Reorganization, Enserch Exploration Holdings, Inc. ("EEH"), (named Enserch Exploration, Inc. and the Managing General Partner of EP prior to the Reorganization), received EP's interests in and assumed EP's obligations under certain equipment lease arrangements relative to the Garden Banks Block 388 project and the Mississippi Canyon Block 441 project, with the equipment being simultaneously subleased to EEX. ENSERCH affiliates also assumed approximately $395 million principal amount of EP's indebtedness, plus accrued interest. Upon the liquidation of EP and distribution of EEX common stock, public unitholders of EP received 805,914 shares of EEX common stock (.77%) and ENSERCH and its affiliates received 103,775,328 shares (99.23%) of EEX's 104,581,242 shares then outstanding.
Enserch Exploration is engaged in the exploration for and the development, production and marketing of natural gas and crude oil throughout Texas, offshore in the Gulf of Mexico, onshore in the Gulf Coast and Rocky Mountain areas and in various other areas in the United States. Subsidiaries of the Corporation currently have interests in three foreign countries.
Production offices are maintained in Dallas, Houston, Athens, Bridgeport, Longview and Midland, Texas. At December 31, 1994, Enserch Exploration had 373 employees, including 34 geologists, 20 geophysicists and 18 land representatives who investigate prospective areas, generate drilling prospects, review submitted prospects and acquire leasehold acreage in prospective areas. In addition, Enserch Exploration maintains a staff of 55 engineers and 45 technologists who plan and supervise the drilling and completion of wells, evaluate prospective gas and oil reservoirs, plan the development and management of fields and manage the daily production of gas and oil.
Variable-priced natural-gas sales, which include monthly and long-term sales contracts, covered about 75% of 1994 natural-gas sales. Enserch Exploration's natural-gas sales volumes for the year ended December 31, 1994 represented 11% of the Corporation's total natural-gas sales volumes. Approximately 80% of Enserch Exploration's natural-gas sales volumes (75% of gas revenues) for the year ended December 31, 1994 was sold to affiliated companies. Effective March 1, 1993, EGC began marketing gas for Enserch Exploration for all gas not covered under existing contracts. Affiliated purchasers do not have a preferential right to purchase natural gas produced by Enserch Exploration other than under existing contracts.
The statistics for this business segment, which are set forth in the table entitled "Financial Review - Natural Gas and Oil Exploration and Production Operating Data" in Appendix A to this report, reflect the fluctuations in product prices and volumes and certain unusual items that affected operating income.
Following is a summary of Enserch Exploration's exploration and development activity during 1994:
Gulf of Mexico. Exploration in the Gulf of Mexico is an important part of Enserch Exploration's exploratory program. A total of 14 leases (over 37,000 acres) were acquired in the Gulf of Mexico, primarily the result of the Central Gulf lease sale in April 1994. These leases were purchased based on prospects principally defined by three-dimensional ("3-D") seismic acquired before the lease sale. Typically, successful wells in the Gulf produce at high rates compared with onshore wells, which is important in increasing cash flow and improving the ratio of production to reserves. State-of-the-art technology, including specialized 3-D seismic processing and innovative production techniques, is being utilized to help achieve this objective.
Mississippi Canyon Block 441, the first development project in the Gulf of Mexico that Enserch Exploration has operated, is indicative of this approach. A 3-D seismic program, prior to field development, confirmed that the majority of the reservoir lies beneath a shipping fairway. A production program was developed that involved drilling highly deviated wells under the shipping fairway, subsea completing the deep-water wells and tying the wells back to a conventional shallow-water production platform using bundled flowlines. The high-angle wells required special gravel- pack completion techniques. After two years of production, the field has been essentially maintenance free. Production from the field, which declined from initial levels due to expected water encroachment, has stabilized and is expected to remain at current levels of some 35 million cubic feet ("MMcf") of natural gas and more than 150 barrels ("Bbls") of condensate per day for the foreseeable future. The 3-D seismic on Mississippi Canyon Block 441 is being reprocessed, using depth migration and other state-of-the-art techniques to aid in the identification of deeper exploratory targets, which, if successfully drilled, could add to the field reserves. Enserch Exploration has a 37.5% working interest in this project.
Throughout 1994, work progressed on the conversion of a semisubmersible rig to a floating production facility for the development of the Garden Banks Block 388 unit. The majority of the modification work on the major structural components has been completed. The 24-slot subsea template has been installed, and the two 12-inch gas and oil gathering lines have been installed and connected to the shallow-water production facility located 54 miles away. Completion operations on the two pre-drilled wells commenced in early 1995 and should enable these wells to be brought on-stream when the floating facility is moored on location and the production riser is installed. The initial well was completed in mid-March and tested at rates which indicate that the well will likely flow at an initial daily rate of 6,000 barrels. The second well should be completed in mid-1995, followed by additional development drilling, with one such well expected to be completed in late 1995. Initial daily oil production rates from the second pre-drilled well is anticipated to be between 2,500 and 6,000 barrels.
Under an agreement with Mobil Producing Texas and New Mexico Inc. ("Mobil"), an exploratory well was drilled in the third quarter of 1994 in Enserch Exploration's Garden Banks unit on Block 387, approximately four miles from the discovery on Block 388. The well, drilled in 2,200 feet of water to a depth of 11,893 feet, encountered a total of 150 feet of oil pay in the two reservoirs and added significant incremental reserve potential to the development project. A delineation well will be drilled on Block 386 or 387 in 1995. Subsea completions tied into the production facility on Block 388 will be utilized to produce these wells.
Mobil has an option to acquire a 40% interest in the entire Garden Banks unit consisting of six blocks and in the unit's production system. To obtain that option, Mobil drilled the exploratory well on Block 387 and has conducted a new 3-D seismic survey over the unit to further assess the deeper horizons correlative to nearby prolific reserves and, to extend the original option, Mobil has paid additional consideration. Enserch Exploration, which currently owns 100% of the project, will remain the operator.
Enserch Exploration has a 100% working interest in a successful exploratory sidetrack well on Green Canyon Block 254, which encountered more than 400 feet of net gas and oil pay below 12,000 feet. The well was an appraisal to a discovery well drilled in 1991 that encountered multiple sands with a combined thickness of more than 300 feet of net pay. Additional drilling is planned for the first half of 1995. Enserch Exploration had a 25% working interest in prior work on this project before assuming operations and a 100% working interest in the sidetrack well. Enserch Exploration also has a 25% working interest in three adjacent blocks. Efforts are underway to acquire additional interests in Block 254 and the adjacent blocks to raise Enserch Exploration's interest.
Onshore. In 1994, the majority of developmental drilling activity was focused in the Freestone, Boonsville and Fashing fields, all in Texas, where some reserves were added by establishing production in zones that had not produced in the past. In Freestone, 12 successful wells were drilled. Initial potential tests have ranged from 1.4 to 2.6 MMcf of gas per day. In the Boonsville area, 13 wells were drilled and completed in 1994. These include nine gas wells that had initial potentials averaging 0.8 MMcf of gas per day and four oil wells initially delivering an average of 76 barrels per day. In Fashing field, five wells were drilled in 1994, four of which have been completed, with initial deliveries averaging 1.7 MMcf of gas per day. Completion operations are in progress on the fifth well.
A large portion of the development drilling and recompletion activity during the past several years has been in six major gas fields in East Texas. To offset the decline rate of hundreds of older wells, reworks, recompletions and development drilling are required, all of which are sensitive to product prices. In East Texas, the goal is to accelerate production while preserving or increasing reserves and net present value of the fields. Enserch Exploration's East Texas proved reserves are currently estimated to be some 784 Bcf.
In 1994, Enserch Exploration and the Los Alamos National Laboratory joined in a first-time effort to use technology developed for energy and national defense in the field of natural- gas exploration. Joint goals are to employ more effective and efficient methods of recovery of resources, to increase reserves and to develop applied science that will be available to the entire natural-gas industry. The Enserch Exploration/Los Alamos team is testing the extent to which producing formations have been drained by hydraulic fracturing in the Opelika gas field located in East Texas. Los Alamos scientists are deploying instrumentation to verify the extent of hydraulic fracturing in the producing Travis Peak formation. It may then be determined where additional fracturing can be used to release trapped gas, thereby maximizing the recovery of domestic gas reserves. The data acquisition phase from the Opelika field has been completed, with significant microseismic activity detected in surrounding observation wells when the test well was hydraulically fractured. The computation phase of the project generated encouraging preliminary results regarding fracture orientation. Currently, Los Alamos' instrumentation is being modified to enhance the quality of acquired data to define fracture extent.
International. The Corporation's international activities, conducted through Enserch International Exploration, Inc. and its subsidiaries ("EIEI"), included participation in one exploration project during 1994. On the island of Java in Indonesia, delineation work continued in the Mudi field that was discovered in 1993. The discovery well was drilled to a total depth of 9,797 feet and encountered a gross oil column of approximately 600 feet and tested at a rate of 1,350 barrels of oil per day. Further appraisal of the structure was conducted in mid-1994 with the successful completion of a sidetrack well. This well encountered improved reservoir conditions and tested in excess of 2,000 barrels of oil per day. A third well, drilled to a depth of 8,793 feet, tested at slightly over 5,000 barrels of oil per day. The fourth well on the structure was spudded in early 1995 and will further assess the prospect. EIEI has a 25% working interest in this project, which is subject to the right of Pertimina, the national oil company of Indonesia, to assume one-half of the working interest after EIEI recovers its capital costs.
Competition. Competition in the natural gas and oil exploration and production business is intense and present from a large number of firms of varying sizes and financial resources, some of which are much larger than Enserch Exploration. Internationally, competition is from a number of both U.S. and non- U.S. firms, generally major national and international oil companies. Competition involves all aspects of marketing products (including terms, prices, volumes and length of contracts), terms relating to lease bonus and royalty arrangements, and the schedule of future development activity.
Regulation. Environmental Protection Agency ("EPA") rules, regulations and orders affect the operations of Enserch Exploration. EPA regulations promulgated under the Superfund Amendments and Reauthorization Act of 1986 require Enserch Exploration to report on locations and estimates of quantities of hazardous chemicals used in Enserch Exploration's operations. The EPA has determined that most gas and oil exploration and production wastes are exempt from the hazardous waste management requirements of the Resource Conservation Recovery Act. However, the EPA determined that certain exploration and production wastes resulting from the maintenance of production equipment and transportation are not exempt and must be managed and disposed of as hazardous waste. Also, regulations issued by the EPA under the Clean Water Act require a permit for "contaminated" stormwater discharges from exploration and production facilities.
Many states have issued new regulations under authority of the Clean Air Act Amendments of 1990, and such regulations are in the process of being implemented. These regulations may require certain gas and oil related installations to obtain federally enforceable operating permits and may require the monitoring of emissions; however, the impact of these regulations on Enserch Exploration is expected to be minor.
Several states have adopted regulations on the handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in gas and oil operations. Although applicable to certain Enserch Exploration facilities, it is not believed that such regulations will materially impact current or future operations.
The Oil Pollution Act of 1990 ("OPA 90") requires responsible parties to provide evidence of financial responsibility in the amount of $150 million to clean up oil spills into the navigable waters of the United States. The financial responsibility requirements apply to offshore facilities and possibly to onshore facilities in, on or under navigable waters. The Mineral Management Service ("MMS") is the agency charged with the administration and enforcement of OPA 90. The ultimate impact of the financial responsibility requirements cannot be determined until final regulations are issued by the MMS. Further Congressional action on these requirements is also possible, and the final MMS regulations could be challenged in court. The $150 million requirement will not become effective until regulations under OPA 90 are issued, probably in 1996. The insurance industry has indicated that insurance will not be available to evidence financial responsibility under OPA 90 as currently written. However, EEX has qualified as a self-insurer using the "identified assets" test under the current $35 million financial responsibility requirement using EEX's interest in Tri- Cities field as the identified assets. It is believed that EEX has sufficient assets to qualify as a self-insurer for $150 million under the identified assets test if the current self-insurance test is included in the OPA 90 regulations. It is unclear whether the new regulations will allow EEX to qualify as a self-insurer. Alternatively, EEX believes it could meet the current OPA 90 financial responsibility requirements by the purchase of a surety bond, although the cost of such bonds is generally much higher than insurance. The availability of surety bonds generally could also be affected by the requirements of the final MMS regulations.
In the aggregate, compliance with federal and state environmental rules and regulations is not expected to have a material adverse effect on Enserch Exploration's operations.
The RRC regulates the production of natural gas and oil by Enserch Exploration in Texas. Similar regulations are in effect in all states in which Enserch Exploration explores for and produces natural gas and oil. These regulations generally require permits for the drilling of gas and oil wells and regulate the spacing of the wells, the prevention of waste, the rate of production and the prevention and cleanup of pollution and other materials.
Natural Gas Liquids Processing
The Corporation's operations for the processing of natural gas for the recovery of natural gas liquids ("NGL") are currently being conducted by Enserch Processing Company ("EPC"), a division of the Corporation. In 1994, these operations were conducted by Enserch Processing Partners, Ltd., a limited partnership wholly owned by the Corporation.
EPC uses cryogenic and mechanical refrigeration processes at its NGL extraction facilities. During these processes, NGL are condensed at extremely low temperatures and are separated from natural gas. The mixed NGL stream, containing the heavier hydrocarbons, ethane, propane, butane and natural gasoline, is pumped via pipeline to Mt. Belvieu, Texas. The remaining natural gas, primarily methane, leaves the NGL plants in gas transmission lines for transportation to end-use customers. See "Properties."
About 60% of NGL product sales are under term contracts of one-to-three years, with prices established monthly. NGL prices are influenced by a number of factors, including supply, demand, inventory levels, the product composition of each barrel and the price of crude oil. Profitability is highly dependent on the relationship of NGL product prices to the cost of natural gas lost in the extraction process--"shrinkage."
To reduce the impact of shrinkage, EPC is increasingly emphasizing the replacement of keep-whole contracts with net- proceeds gas processing contracts. Keep-whole contracts are profitable during periods of high NGL prices and low gas costs because they provide the processor with ownership of the entire gas stream. As prices fluctuate, these contracts become less profitable because the processor must absorb all the shrinkage costs. Under net-proceeds contracts, the producer provides shrinkage volumes, while the processor contributes plant facilities and operational costs. Revenues from NGL sales are apportioned between the parties, and the processor is no longer impacted by natural-gas feedstock costs.
The NGL processing area is highly competitive, including competition regarding cost-sharing and interest-sharing arrangements among producers, third-party owners and processors.
Power
Enserch Development Corporation ("EDC") develops business opportunities primarily in the areas of independent power, including cogeneration. EDC evaluates the risk and rewards of these potential ventures; selects for development those ventures with the highest potential of success; implements and controls development of each venture; and brings together all the resources required to develop, finance, construct, operate and manage the selected ventures. EDC focuses on employing a strategy of maximizing the use of ENSERCH's resources and minimizing the Corporation's risk and investment. As of December 1994, EDC had several business opportunities in various phases of development throughout the United States and internationally.
The first project completed by EDC, operating since 1989, was a gas-fired, 255-megawatt ("MW") cogeneration plant located near Sweetwater, Texas. The electricity produced by the plant is purchased by Texas Utilities Electric Company, and thermal energy is sold to United Gypsum Company under a long-term agreement. EDC developed and arranged financing for the project and one of its subsidiaries is the managing general partner, Enserch Exploration and EGC provide gas to the plant, and Lone Star transports the gas. In 1992, the second plant developed by EDC was completed. The 62- MW natural gas-fired cogeneration facility in Buffalo, New York, supplies electricity to Niagara Mohawk Company and thermal energy to Outokumpu American Brass, Inc. EDC's third project, a 160-MW plant located in Bellingham, Washington, began commercial operation in July 1993. The electricity produced by the plant is sold under a long-term power sales agreement with Puget Sound Power & Light, and thermal energy in the form of steam and hot water is sold to Georgia-Pacific Corporation. Lone Star Energy Company ("LSEC") operates and maintains all three of the plants and has fixed-cost operating and maintenance agreements for providing labor and certain routine consumables at each plant. Each of the agreements contain escalation provisions. The agreements for the Buffalo and Bellingham plants also contain bonus or penalty provisions based upon plant availability.
In addition to operating and maintaining the above-mentioned cogeneration plants, LSEC owns and/or operates four central thermal energy plants providing heating and cooling to various institutional customers in Texas. The aggregate existing plant capacity is 40,500 tons of chilled water and 775 MMBtu's of steam or hot water per hour. From the three plants owned by LSEC, institutional customers receive thermal energy under long-term agreements that contain established rates for units of steam and chilled water and certain escalation provisions for increases in ad valorem taxes, utility and labor costs. When the agreements expire, the plants become the property of the customers. Expiration dates are in 1996 and 1997. LSEC is actively pursuing new contracts to operate the plants after the existing agreements expire. The expiration of the existing thermal-energy plant agreements is not expected to have a significant impact on the Corporation.
LSEC operates in the compressed natural-gas ("CNG") market through its CNG Division along with two natural-gas vehicle affiliates, Fleet Star of Texas, L.C. ("Fleet Star") and TRANSTAR Technologies, L.C. ("TRANSTAR"), each 50% owned by LSEC. Fleet Star and FinaStar, a partnership between Fleet Star and Fina Oil and Chemical, had ten public natural-gas fuel stations in commercial operation at December 31, 1994. TRANSTAR provides turnkey natural-gas vehicle conversion and other related services and performed over 500 vehicular natural-gas conversions in 1994, over a 100% increase in conversions from 1993.
The operations of the CNG Division and affiliates have been aligned under the Corporation's natural gas transmission and distribution business segment for financial reporting purposes.
Clean Air Act
The impact of the 1990 amendments to the Clean Air Act ("CAA") on the Corporation, its divisions, subsidiaries and affiliates, cannot be fully ascertained until all the regulations that implement the provisions of the Act have been promulgated. It is expected that a number of facilities or emission sources will require a federally enforceable operating permit, and certain emission sources may also be required to reduce emissions or to install enhanced monitoring equipment under proposed rules and regulations. Management currently believes, however, that if the rules and regulations implementing the CAA are adopted as proposed, the cost of obtaining permits, operating costs that will be incurred under the operating permit, new permit fee structures, capital expenditures associated with equipment modifications to reduce emissions, or any expenditures on enhanced monitoring equipment, in the aggregate, will not have a material adverse effect on the Corporation's results of operations.
The CAA has created new marketing opportunities for the sale of natural gas that may have a positive effect on the Corporation's results of operations. Natural gas has long been recognized as a clean and efficient fuel. Title II (Mobile Sources) requires lower emissions from light-duty vehicles and urban buses that should make alternative fuels such as natural gas more attractive and competitive. In addition, Clean Fuel Fleet programs under the CAA will require a certain percentage of fleet vehicles to utilize clean-burning alternative fuels such as natural gas in the near future. Further, because chloroflurocarbon compounds ("CFCs"), commonly used as refrigerants in large air-conditioning systems must be phased out of production by the year 2000, interest has increased in the use of natural gas-powered absorption cooling systems that do not use CFC's. In those areas that do not meet the CAA's National Ambient Air Quality Standards for ozone, natural gas may play an important role in reducing ozone formation and may be substituted for other fuels. Since Title IV (Acid Rain) requires major reductions in sulphur dioxide emissions, principally from coal-fired electric power plants, natural gas is expected to be considered as a cost-effective alternative for achieving reduced sulphur dioxide emissions.
Patents and Licenses
The Corporation, Lone Star and subsidiary companies have no material patents, licenses, franchises (excluding gas-distribution franchises) or concessions.
Employees
At December 31, 1994, the Corporation, its divisions and subsidiaries, had approximately 4,200 employees.
Executive Officers of Registrant
There are no family relationships between any of the above officers. All officers of the Corporation, its divisions and subsidiaries, are elected annually by their respective Board of Directors. Officers may be removed by their respective Board of Directors whenever, in their judgment, the best interest of the Corporation, its divisions or subsidiaries, as the case may be, will be served thereby.
ITEM 2.
ITEM 2. PROPERTIES
At December 31, 1994, Lone Star and certain subsidiaries of the Corporation operated approximately 32,000 miles of transmission and gathering lines and distribution mains and operated 35 compressor stations having a total rated horsepower of approximately 80,000. Lone Star owns seven active gas-storage fields, all located on Lone Star's system in Texas. Lone Star also owns three major gas-treatment plants to remove undesirable components from the gas stream. See "Business - Natural Gas Transmission and Distribution - Source and Availability of Raw Materials" for information concerning gas supply of Lone Star.
As of January 1, 1995, Enserch Exploration had net proved reserves of 1.04 Tcf of natural gas and 50.6 MMBbls of oil and condensate, as estimated by DeGolyer and MacNaughton, independent petroleum consultants. See Note 8 of the Notes to Consolidated Financial Statements included in Appendix A to this report for additional information on gas and oil reserves. All of these reserves, except 4.1 MMBbls of oil and condensate, are in the United States.
See "Financial Review - Liquidity and Financial Resources" included in Appendix A to this report for a discussion of the Corporation's 1995 capital spending budget by segment. In light of the recent lack of heating weather and lower gas prices, the Corporation is proceeding cautiously in implementing its total capital spending program until the amount of future cash flows can be better ascertained. Announced 1995 capital expenditures of $262 million could be reduced by up to $25 million for EEX and $10 million for Lone Star if cash flows fail to reach budgeted levels.
During 1994, Enserch Exploration filed Form EIA-23 with the Department of Energy reflecting reserve estimates for the year 1993. Such reserve estimates were not materially different from the 1993 reserve estimates reported in Note 8 of the Notes to Consolidated Financial Statements included in Appendix A to this report.
As of December 31, 1994, Enserch Exploration and EIEI owned leasehold interests or licenses in 17 states, offshore Texas and Louisiana, and three other countries as follows:
Enserch Exploration purchased about 191,000 net acres of leasehold interests in 1994, 37,000 of which were in the Gulf of Mexico. Enserch Exploration's Gulf of Mexico holdings totaled some 147,000 net acres, with an average working interest of 46% in 61 blocks and an overriding royalty interest in three other blocks. The company operates 28 offshore blocks. Enserch Exploration also canceled or allowed to expire 21 Gulf of Mexico leases during the year, which had been condemned following drilling on or near them or after geophysical and geological findings.
Enserch Exploration plans further drilling on undeveloped acreage but at this time cannot specify the extent of the drilling or predict how successful it will be in establishing the commercial reserves sufficient to justify retention of the acreage. The primary terms under which the undeveloped acreage in the United States can be retained by the payment of delay rentals without the establishment of gas and oil reserves expire as to 20% of undeveloped acreage in 1995, 36% in 1996, 21% in 1997, 5% in 1998, 11% in 1999, 2% in 2000 and 5% thereafter. A portion of the undeveloped acreage may be allowed to expire prior to the expiration of primary terms specified in this schedule by nonpayment of delay rentals. Aside from areas in Texas, the Gulf of Mexico, Malaysia and Indonesia, Enserch Exploration has no material concentration of undeveloped acreage in single areas at this time.
Undeveloped acreage in other countries, which can be retained without the establishment of gas or oil reserves, expires as follows: Indonesia - 50% in 1995, 30% in 1996 and 20% in 1998; United Kingdom - 100% in 2016; Malaysia - 100% in 1996.
EEX participated in 108 wells (74 net) during 1994. Of these wells, 58 wells (44 net) were successfully completed, resulting in a net success rate of 59%. Of the successful wells, 13 wells (10 net) were exploratory and 45 wells (34 net) were development. At December 31, 1994, EEX and EIEI were participating in 43 wells (24 net), which were either being drilled or in some stage of completion.
In the 1994 domestic drilling program, 5 wells (1.5 net) were offshore. Of these wells, 2 gas wells (.4 net) and 1 oil well (.4 net) were successfully completed. During 1993, 16 offshore wells (4.9 net) were drilled, of which 9 gas wells (2.6 net) and 1 oil well (.1 net) were successfully completed.
At December 31, 1994, Enserch Exploration owned interests in 1,314 gas wells (1,008 net) and 1,043 oil wells (286 net) in the United States and 3 oil wells (1 net) in Indonesia. Of these, 173 gas wells (141 net) and 37 oil wells (32 net) were dual completions in single boreholes.
Completed drilling activity during the three years ended December 31, 1994 is set forth below:
The number of wells drilled is not a significant measure or indicator of the relative success or value of a drilling program because the significance of the reserves and economic potential may vary widely for each project. It is also important to recognize that reported completions may not necessarily track capital expenditures, since Securities and Exchange Commission guidelines do not allow a well to be reported as complete until it is ready for production. In the case of offshore wells, this may be several years following initial drilling because of the timing of construction of platforms, pipelines and other necessary facilities.
Additional information relating to the gas and oil activities of Enserch Exploration is set forth in Note 8 of the Notes to Consolidated Financial Statements included in Appendix A to this report.
EPC has interests in 18 processing plants, 13 of which are wholly owned. The products, which in 1994 were produced at an average of about 16,800 barrels per day, are sold to customers primarily at the Mt. Belvieu fractionation and storage facility near Houston for use as chemical feedstock and other purposes. The processing plants are capable of producing an aggregate of about 27,000 barrels of NGL per day; daily production was up slightly from the previous year. Lone Star estimates that as of January 1, 1995, 28.5 MMBbls of NGL are attributable to contractual processing rights of EPC with respect to gas reserves owned by Enserch Exploration or third parties and dedicated to Lone Star under various gas-purchase contracts or are being transported by Lone Star under various gas transportation agreements. See "Business - Natural Gas Transmission and Distribution - Source and Availability of Raw Materials" for additional reserves held by Lone Star.
LSEC owns three central plants providing heating and cooling to institutional customers in Dallas, El Paso and Galveston Texas.
The Corporation owns a five-building office complex in Dallas, containing approximately 453,000 square feet of space that the Corporation, Lone Star and certain subsidiaries fully occupy. In addition, the Corporation leases a 21-story, 400,000 square-foot building in Houston under a two-year lease that is automatically extended each year unless terminated.
ITEM 3.
ITEM 3. Legal Proceedings
The utility division of the Corporation was named as a codefendant in a lawsuit filed on November 10, 1988 in the 200th Judicial District Court of Travis County, Texas. Plaintiffs were parties to gas-sale contracts that provided for direct and indirect sale of gas to the utility division. This case was dismissed on November 29, 1994 following a settlement of the claim at an amount that was not material to the financial position of the Corporation.
On June 25, 1993, a lawsuit was filed against the utility division of the Corporation in the 4th Judicial District Court of Rusk County, Texas. The plaintiff claimed that the utility division failed to make certain production and minimum-purchase payments under a gas-purchase contract, that it was fraudulently induced to enter into a gas-purchase contract, that it was fraudulently induced and coerced into releasing the utility division from its obligation to make minimum-purchase payments, and that the contract was breached. The plaintiff initially sought actual damages in excess of $100 million in addition to punitive damages. Following subsequent discovery proceedings of plaintiff's expert witnesses on the utility division's alleged minimum- purchase obligation, plaintiff's claim, under alternate damage theories, appeared to be in an asserted range of from $75 million to $235 million, plus an additional $68 million related to alleged secondary damages. Following a jury verdict in favor of the utility division, the court entered a judgement on December 14, 1994 and denied Plaintiff's motion for a new trial on February 16, 1995.
Additional information required hereunder is set forth in Note 4 of the Notes to Consolidated Financial Statements included in Appendix A to this report. In addition, the Corporation is a party to lawsuits arising in the ordinary course of its business. The Corporation believes, based on its current knowledge and the advice of counsel, that all lawsuits and claims would not have a material adverse effect on its financial condition.
ITEM 4.
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 10-13.
Pursuant to Instruction G(3) to Form 10-K, the information required in Items 10-13 (except for information set forth at the end of Part I under "Business - Executive Officers of Registrant") is incorporated by reference from the Corporation's definitive proxy statement which is being filed pursuant to Regulation 14A on or about March 24, 1995.
PART IV
ITEM 14.
ITEM 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a)-1 Financial Statements
The following items appear in Appendix A to this report:
(a)-2 Financial Statement Schedules
Consolidated financial statement schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the consolidated financial statements or notes thereto.
(a)-3 Exhibits. The following exhibits are filed herewith unless otherwise indicated:
3.1 Restated Articles of Incorporation of Registrant currently in effect.
3.2 Bylaws of Registrant currently in effect.
4.1* Shareholder Rights Plan - Filed as an Exhibit to Registrant's Form 8-A dated April 23, 1986.
Executive Compensation Plan and Arrangements (Exhibits 10.01 though 10.12):
10.1* Management Incentive Program - Unit Plan and Stock Option Plan, as amended, and currently in effect, filed as Exhibit 10.1 to Registrant's Form 10-K for the year ended December 31, 1991.
10.2 ENSERCH Corporation Deferred Compensation Plan for Directors.
10.3* Director's Deferred Compensation Trust Agreement, as amended, and currently in effect, filed as Exhibit 10.3 to Registrant's Form 10-K for the year ended December 31, 1991.
10.4* Forms of trust agreements relating to compensation and supplemental retirement income arrangements executed by certain executive officers of the Corporation, filed as Exhibit 10.5 to Registrant's Form 10-K for the year ended December 31, 1991.
10.5* ENSERCH Corporation 1981 Stock Option Plan, as amended, and currently in effect, as filed as Exhibit 10.6 to Registrant's Form 10-K for the year ended December 31, 1991.
10.6* Form of Change of Control Agreement executed by certain executive officers of the Corporation filed as Exhibit 10.9 to Registrant's Form 10-K for the year ended December 31, 1988.
10.7 ENSERCH Corporation Performance Incentive Plan - Calendar Year 1995.
10.8* ENSERCH Corporation 1991 Stock Incentive Plan, filed as Exhibit 10.12 to Registrant's Form 10-K for the Year Ended December 31, 1990.
10.9 ENSERCH Corporation Deferred Compensation Plan and Amendment No. 1 thereto dated March 28, 1995.
10.10 ENSERCH Corporation Deferred Compensation Trust.
10.11 ENSERCH Corporation Retirement Income Restoration Plan and Amendment No. 1 thereto dated September 30, 1994.
10.12 ENSERCH Corporation Retirement Income Restoration Trust.
21 Subsidiaries of the Registrant.
23.1 Deloitte & Touche LLP consent to incorporation by reference in Registration Statements No. 2-59259, No. 2-7572, No. 33-15623, No. 33-40589, No. 33-47911 and No. 33-52525.
23.2 DeGolyer and MacNaughton consent letter including consent to incorporation by reference in Registration Statements No. 2-59259, No. 2-77572, No. 33-15623, No. 33-40589, No. 33-47911 and No. 33-52525.
24 Powers of Attorney.
27 Financial Data Schedule.
99* Proxy Statement dated at or about March 24, 1995 being filed with the Securities and Exchange Commission on or about March 24, 1995.
Long-term debt is described in Note 2 of the Notes to Consolidated Financial Statements included in Appendix A to this report. The Corporation agrees to provide the Commission, upon request, copies of instruments defining the rights of holders of such long-term debt, which instruments are not filed herewith pursuant to Paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K. ___________________
*Incorporated herein by reference and made a part hereof.
(b) Reports on Form 8-K
Current Report on Form 8-K dated December 9, 1994, was filed on December 12, 1994 (Reorganization of Enserch Exploration Partners, Ltd. into a new corporation, Enserch Exploration, Inc.).
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENSERCH Corporation
March 30 , 1995 By: /s/ D. W. Biegler ----- -------------------------- D. W. Biegler, Chairman and President, Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant in the capacities and on the date indicated.
Signature Title Date --------- ----- ----
* Chairman and President, March 30 1995 ---------------------- Chief Executive Officer, ----, D. W. Biegler and Director
* Director March 30 1995 ---------------------- ----, Frederick S. Addy
* Director March 30 1995 ---------------------- ----, William B. Boyd
* Director March 30 1995 ---------------------- ----, B. A. Bridgewater, Jr.
Director ---------------------- Odie C. Donald
* Director March 30 1995 ---------------------- ----, Lawrence E. Fouraker
* Director March 30 1995 ---------------------- ----, Preston M. Geren, Jr.
* Director March 30 1995 ---------------------- ----, Marvin J. Girouard
* Director March 30 1995 ---------------------- ----, Joseph M. Haggar
Director ---------------------- Thomas W. Luce, III
* Director March 30 1995 ---------------------- ----, W. C. McCord
* Director March 30 1995 ---------------------- ----, Diana S. Natalicio
* Director March 30 1995 ---------------------- ----, W. Ray Wallace
* Senior Vice President, March 30 1995 ---------------------- Finance and Corporate ----, S. R. Singer Development, Chief Financial Officer
* Vice President and March 30 1995 ---------------------- Controller, Chief ----, J. W. Pinkerton Accounting Officer
*By: /s/ D. W. Biegler ---------------------- D. W. Biegler, Individually and as Attorney-in-Fact
APPENDIX A
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
INDEX TO FINANCIAL INFORMATION DECEMBER 31, 1994
Page ----
Selected Financial Data............................... A-2
Financial Review...................................... A-3
Independent Auditors' Report.......................... A-9
Management Report on Responsibility for Financial Reporting................................. A-10
Financial Statements: Statements of Consolidated Income................... A-11
Statements of Consolidated Cash Flows............... A-12
Consolidated Balance Sheets......................... A-13
Statements of Consolidated Common Shareholders' Equity.............................. A-14
Notes to Consolidated Financial Statements............ A-15
Summary of Business Segments.......................... A-26
Quarterly Results..................................... A-27
Common Stock Market Prices and Dividend Information... A-28
ENSERCH CORPORATION FINANCIAL REVIEW
Earnings applicable to common stock for the year 1994 were $91 million ($1.36 per share), compared with 1993 earnings of $47 million ($.70 per share) and a loss applicable to common stock for 1992 of $41 million ($.62 per share).
CONTINUING OPERATIONS - Results from continuing operations, after provision for preferred dividends, were income of $70 million ($1.05 per share) in 1994, a loss of $29 million ($.43 per share) in 1993, and a loss of $12 million ($.18 per share) in 1992. The 1994 results from continuing operations included a $70 million reduction of deferred income taxes associated with the conversion of Enserch Exploration Partners, Ltd. and other partnerships to corporate form and the resulting change in tax status (see Note 6). The 1994 results also included a $4.9 million after-tax ($7.6 million pretax) gain from the sale of an inactive offshore pipeline. Results for 1993 were impacted by an $8 million after-tax ($12 million pretax) charge principally for severance expenses associated with the re-engineering of Lone Star Gas Company's distribution operations, an $11 million charge from the 1% increase in the statutory federal income-tax rate on corporations, a $9 million after-tax ($13 million pretax) write-off of non-U.S. gas and oil assets and a $27 million after-tax ($41 million pretax) charge as a result of an adverse judgment in litigation. The 1992 results included an $11 million after-tax ($17 million pretax) write-down of an inactive offshore pipeline and facilities and a $10 million after-tax ($15 million pretax) provision for litigation.
Operating income for 1994 was $87 million, compared with $67 million in 1993 and $105 million in 1992. Excluding the effects of the unusual items mentioned above, operating income was $80 million for 1994, $134 million for 1993 and $122 million for 1992. Variations in operating income by business segment are discussed below.
NATURAL GAS TRANSMISSION AND DISTRIBUTION - The table of Operating Data reflects the effects of variable weather patterns and increasing activity in non-utility markets. Operating income for 1994 was $63 million, compared with $101 million in 1993 and $102 million in 1992. From 1993 to 1994, there was a decline of $39 million in margin on gas sales, and operating expenses for 1994 increased some $6 million (2%) because transitional costs for the re- engineering of the distribution operations exceeded savings that began to be realized.
Lone Star's residential and commercial sales volumes of 126 billion cubic feet (Bcf) in 1994 were 10% below the 1993 volumes of 139 Bcf. The 1993 volumes were 16% above 1992. The fluctuations are mostly attributable to differences in winter weather. In 1994, total heating degree days were 91% of the average for the 30-year period ended in 1990, compared with 104% in 1993 and 82% in 1992.
The margin decline on sales by Lone Star included approximately $8 million attributable to year-to-year differences in heating weather and $17 million due to higher unrecovered gas-purchase costs. Gas-purchase expense includes the cost of gas delivered, which is directly flowed-through to customers, plus the cost of the excess of purchased volumes over delivered volumes. The latter costs fluctuate from year to year due to various factors, including temperature extremes, metering variances and billing estimates.
Sales by Enserch Gas Company (EGC), the ENSERCH gas marketing affiliate, accounted for 72% of total gas sales volumes in 1994, 59% in 1993 and 53% in 1992. EGC's 1994 margin declined $14 million compared with 1993. Gas prices were strong in early 1994 due to record cold weather in the Northeast and remained somewhat stable until midyear, but prices declined rapidly later in the year as industry storage facilities were generally full and normally expected colder fourth-quarter weather failed to materialize throughout most of the country. Additionally, gas demand for electric generation was lower than expected during the summer months as a result of fewer days of above- 100-degree temperatures and an increase in nuclear generating capacity in Texas. The combination of these market pressures eroded much of the margin on EGC's gas sales. From time to time, EGC enters into contracts to purchase gas for physical delivery up to one year later. The 1994 margin decline for EGC also includes a $4 million charge recorded on forward purchase contracts to reflect lower year-end market prices.
In the past, Lone Star was unable to take delivery of all gas tendered by suppliers under contract minimum-purchase requirements, resulting in sizable advance payments for gas and settlement payments. At December 31, 1994, there was an unrecovered balance of gas-purchase contract settlements of $61 million. The unrecovered balance has declined substantially each year from $208 million at year-end 1991. The balances include take-or-pay settle- ments, amounts relating to pricing and amounts related to the settlement of other contractual matters. Of the $61 million, $31 million represented prepayments expected to be recouped under contracts covering future gas purchases, and $30 million represented amounts to be recovered from customers under the existing gas-cost recovery provisions. Based on Lone Star's estimated gas demand, which assumes normal weather conditions, requisite gas purchases are expected to substantially satisfy purchase obligations for the year 1995 and thereafter. Outstanding supplier claims approximated $10 million as of December 31, 1994. A previously reported claim asserting damages ranging from $75 million to $235 million was decided in Lone Star's favor by a jury in the fourth quarter of 1994; the decision is subject to plaintiff's motion for new trial and later appeal to a higher court. Lone Star expects to recoup or recover the remaining balances of gas settlement payments made to date, as well as any future payments made in settlement of remaining claims.
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION - Operating income closely follows fluctuations in product prices and volumes, as shown in the table of Operating Data. Excluding effects of the previously discussed unusual items, operating income was $18 million for 1994, $17 million for 1993 and $10 million for 1992.
Revenues for 1994 of $179 million were 6% lower than 1993, which was 11% above 1992. In 1994, natural-gas revenues decreased slightly to $145 million, with
the average natural-gas price per thousand cubic feet of $2.15 up from $2.09 in 1993 and $1.82 in 1992. Natural-gas sales volumes were 67 Bcf in 1994, 70 Bcf in 1993 and 65 Bcf in 1992. The decrease in volumes in 1994 was principally due to reduced production from several high-volume fields in South Texas and offshore Louisiana. The increase in volumes from 1992 to 1993 was principally due to accelerated natural-gas development drilling in East Texas and offshore production from Mississippi Canyon Block 441 in the Gulf of Mexico, which went on-stream in the second quarter of 1993. Oil revenues declined $6 million to $31 million in 1994 due to a 6% production decline and an 11% decrease in the average sales price to $15.38 per barrel. Oil revenues decreased to $37 million in 1993 from $45 million in 1992, as production declined 9% and the average sales price dropped 10%. The lower volumes were primarily the result of declining production from several North Texas reservoirs.
Throughout 1994, work progressed on the conversion of a semisubmersible rig to a floating production facility for the development of the Garden Banks Block 388 unit. The majority of the modification work on the major structural components has been completed. The 24-slot subsea template has been installed, and the two 12-inch oil and gas gathering lines have been installed and connected to the shallow-water production facility located 54 miles away.
Completion operations on two pre-drilled wells commenced in early 1995 and should enable these wells to be brought on-stream when the floating facility is moored on location and the production riser is installed. These activities should be completed in mid-1995, followed by additional development drilling, with one such well expected to be completed in late 1995. Initial daily oil production rates from the pre-drilled wells are anticipated to be between 2,500 and 5,000 barrels of oil per well.
Mobil Producing Texas and New Mexico Inc. (Mobil) has an option to acquire, for consideration, a 40% interest in the entire Garden Banks unit consisting of six blocks and in the unit's production system. If Mobil exercises its option, Enserch Exploration, which currently owns 100% of the project, will remain the operator.
Operating results for 1995 are expected to be negatively impacted by the midyear commencement of production from the two pre-drilled wells on Garden Banks Block 388. Revenues from the early levels of production are not expected to be sufficient to cover operating costs, amortization and the equipment lease costs on the floating production platform and related facilities. Some operating costs and amortization vary with production; however, other costs and the equipment lease costs are essentially fixed. Results are expected to improve significantly for 1996 as production begins from several development wells and equipment lease and other fixed costs are spread over significantly more production.
ENSERCH has budgeted $160 million for exploration and production activities in 1995, compared with expenditures of $133 million in 1994 and $120 million in 1993.
ENSERCH's natural-gas reserves at January 1, 1995, were 1.04 trillion cubic feet (Tcf), compared with 1.09 Tcf the year earlier, as estimated by DeGolyer and MacNaughton, independent petroleum consultants. Oil and condensate
reserves, including natural gas liquids attributable to leasehold interests, were 51 million barrels (MMBbls), compared with the year-earlier level of 39 MMBbls. The increase is associated with Garden Banks Block 388 and the Mudi project in Indonesia.
The Corporation follows the full-cost method of accounting for gas and oil properties. The overall rate of amortization for U.S. properties was $1.04 per million British thermal units produced for 1994, compared with $.98 for both 1993 and 1992. The Mississippi Canyon capital lease and higher onshore exploratory costs largely account for the increase in 1994. Product prices are subject to seasonal and other fluctuations. A decline in prices from year-end 1994 or other factors, without mitigating circumstances, would cause a future write-down of capitalized costs that could be significant and a noncash charge against earnings.
ENSERCH uses gas and oil swaps, collars and futures agreements to hedge volatile product prices for a portion (normally 30 to 70 percent) of anticipated future gas and oil production. Hedges resulted in a net increase in gas revenues of $5.0 million in 1994, compared with a decrease of $4.1 million in 1993. Hedges reduced oil revenues $.7 million in 1994 but added $.4 million in 1993. At December 31, 1994, ENSERCH had outstanding swaps, collars and futures agreements extending through December 1995 to exchange payments on some 17.8 Bcf of gas and 1.2 MMBbls of oil on which ENSERCH had $4.1 million of net unrealized gains. At December 31, 1994, realized gains on hedging activities of $.9 million were deferred.
On December 30, 1994, through a series of transactions, Enserch Exploration, Inc. (EEX), a newly organized Texas corporation, acquired all of the operating properties of Enserch Exploration Partners, Ltd. (EP), and EP received common stock of EEX. EP was then liquidated, and its partners received one share of EEX common stock for each limited and general partnership interest held. The ENSERCH companies also received EP's interests in and assumed EP's obligations under certain equipment lease arrangements (the equipment was simultaneously subleased to EEX) and assumed approximately $395 million principal amount of EP's indebtedness, plus accrued interest. Upon the liquidation of EP and distribution of EEX common stock, public unitholders of EP received 805,914 shares of EEX common stock (.77%) and the ENSERCH companies received 103,775,328 shares (99.23%) of EEX's 104,581,242 shares outstanding.
NATURAL GAS LIQUIDS PROCESSING - Fluctuations in natural gas liquids (NGL) demand caused by overall economic conditions, price volatility for NGL products and natural-gas feedstock costs are the major factors that influence financial results in the NGL processing business, as shown in the table of Operating Data. Operating income was $1 million for 1994, $5 million for 1993 and $13 million for 1992. Small operating losses were incurred during the first three quarters of 1994. However, in the last quarter, NGL prices improved and feedstock costs declined, and the restored margins were sufficient to more than offset the losses incurred earlier in 1994.
POWER - ENSERCH's power activities, comprised of Enserch Development Corporation (EDC) and Lone Star Energy Company (LSE), had 1994 operating income of $5.8 million, compared with $9.8 million for 1993 and $13.4 million for 1992. In the second quarter of 1994, EDC and LSE began earning management and incentive fees from operating a 160-megawatt cogeneration plant in Bellingham, Washington, developed by EDC, which should provide a steady stream
of future income. EDC's 1994 operating income was $1.7 million, compared with $5.9 million for 1993 and $9.8 million for 1992. Results for 1993 included a $15 million gain from the sale of a position in a power project that had been scheduled for development, and 1992 results included a $15 million fee from development of the Bellingham project. LSE's operating income was $4.1 million for 1994, $3.9 million for 1993 and $3.6 million for 1992.
OTHER - Other income/expense consists principally of gains on disposal of assets, interest income and discounts on sales of receivables. In addition, 1993 includes a $5.6 million provision for interest awarded in the judgment described earlier, and 1992 includes a $15 million provision for litigation.
Interest expense for 1994 was $68 million, compared with $77 million for 1993, which included $8 million not related to borrowings, and $94 million for 1992. The reduction from 1992 reflects the results of a program to refinance long- term debt at lower rates. Over the three-year period, short-term interest rates were at their lowest level in 1993.
DISCONTINUED OPERATIONS - The 1994 income from discontinued operations of $21 million ($.31 per share) arose from the sale of Enserch Environmental Corporation, partially offset by a $10 million ($17.5 million pretax) loss provision to recognize that costs and expenses incurred for the wind-up of other discontinued businesses would be greater than previously estimated. The 1993 results of $75 million ($1.13 per share) primarily arose from the sale of the principal operating assets of Ebasco Services Incorporated. The $14 million ($.21 per share) loss in 1992 primarily related to the sale of Humphreys and Glasgow International and provisions for real estate formerly utilized by discontinued operations. With the sale of Enserch Environmental, the Corporation has now completed the divestiture of its engineering and construction business. Remaining assets, including receivables, and obligations are expected to be substantially settled by year-end 1996 (see Note 7).
LIQUIDITY AND FINANCIAL RESOURCES - Net cash flows from operating activities of continuing operations reflect the previously described variances in operating income and related changes in current operating assets and liabilities and for 1994 totaled $94 million, compared with $197 million in 1993 and $213 million in 1992. The amount provided in 1994 is after the $62 million payment relating to the adverse judgment in litigation described earlier. Net recoveries of gas-purchase contract settlements were some $50 million in both 1994 and 1993, twice the 1992 amount.
Discontinued operations required cash of $.9 million in 1994, after the net proceeds from the sale of Enserch Environmental of $98 million. Enserch Environmental operations required cash for working capital of $32 million, which was recovered in the sale. Also included is the remittance of $22 million for December 1993 collections of sold receivables plus the payment of accrued expenses, taxes and other retained obligations relating to the sale of Ebasco. Cash provided by discontinued operations in 1993 included net proceeds from the sale of the principal operating assets of Ebasco and $100 million from the limited recourse sale of Ebasco receivables.
Planned property, plant and equipment additions for 1995 total $262 million and include $96 million designated for Transmission and Distribution, $160 million for Exploration and Production and $6 million for other
requirements. The planned expenditures are expected to be funded from internal cash flow and external financings as required and exclude costs of the floating production platform and related facilities of the Garden Banks project, which is financed by an operating lease arrangement aggregating $235 million. The cost of these facilities is expected to be $330 million, which includes design modifications and other costs for Block 388 facilities and for the recent discovery on Block 387. Financing options for the additional costs currently are being evaluated, including an addition to the current operating lease arrangement.
In the first quarter of 1994, $150 million of 6 3/8% Notes due 2004 were issued in a public offering, and $74 million of sinking fund debentures and $75 million of Series D Adjustable Rate Preferred Stock were redeemed. In April 1994, $75 million of Series F Adjustable Rate Preferred Stock was sold, which has a substantially lower dividend rate than the Series D. Net proceeds were used to repay $29 million of maturing senior long-term debt and to reduce commercial paper borrowings. In November 1994, $150 million of privately placed variable-rate long-term debt due in 1998 was issued. The proceeds were used to retire $100 million of maturing 9.11% debt and to reduce short-term borrowings.
Total capitalization at December 31, 1994 was $1.7 billion, an increase of $165 million from year-end 1993, reflecting $86 million more senior long-term debt and $79 million growth in shareholders' equity. As a percentage of total capitalization, common shareholders' equity increased slightly to 42.3% at December 31, 1994. At December 31, 1994, $423 million of shareholders' equity was free of any restrictions for payment of dividends or acquisition of capital stock.
The current ratio at December 31, 1994 was .75 versus .72 at year-end 1993 and 1.0 at year-end 1992, with the decline from 1992 substantially attributable to the sale of Ebasco and Enserch Environmental.
ENSERCH uses the commercial paper market and commercial banking facilities for short-term needs. Bank lines in the form of a three-year revolving agreement totaled $600 million, all unused at year-end 1994.
Inflation during recent years has had little effect on capital costs and results of operations.
FOURTH-QUARTER RESULTS - Earnings applicable to common stock for the fourth quarter of 1994 were $89 million ($1.33 per share), compared with $36 million ($.53 per share) for the fourth quarter of 1993. Income from continuing operations after provision for preferred dividends for the fourth quarter of 1994 was $70 million ($1.05 per share) versus a loss of $35 million ($.52 per share) for the year-ago period. Results for the 1994 and 1993 fourth quarters included all of the unusual items noted for the full year, except in 1993 the $11 million charge for the increase in the statutory federal income-tax rate and $2.0 million of the after-tax write-offs of non-U.S. gas and oil assets occurred earlier. Fourth-quarter income from discontinued operations was $19 million ($.28 per share), compared with $70 million ($1.05 per share) for the 1993 period. Excluding effects of unusual items, operating income for the 1994 fourth quarter was $14 million, compared with $27 million for the year- earlier quarter, with the decline primarily due to lower results for the Transmission and Distribution business segment.
INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of ENSERCH Corporation:
We have audited the accompanying consolidated balance sheets of ENSERCH Corporation and subsidiary companies as of December 31, 1994 and 1993, and the related statements of consolidated income, cash flows and common shareholders' equity for each of the three years in the period ended December 31, 1994. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits. We have previously audited the consolidated balance sheets of ENSERCH Corporation and subsidiary companies as of December 31, 1992, 1991, 1990 and 1989 and the related statements of consolidated income, cash flows and common shareholders' equity for the years ended December 31, 1991, 1990, and 1989 (not presented herewith), and have expressed unqualified opinions thereon.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of ENSERCH Corporation and subsidiary companies at December 31, 1994 and 1993, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles. Also, in our opinion, the information set forth in the accompanying table of selected financial data for the years 1989 through 1994 is fairly stated in all material respects in relation to the consolidated financial statements from which such information has been derived.
DELOITTE & TOUCHE LLP
Dallas, Texas February 10, 1995
MANAGEMENT REPORT ON RESPONSIBILITY FOR FINANCIAL REPORTING
The management of ENSERCH Corporation is responsible for the preparation, presentation and integrity of the financial statements and other information contained in this report. The financial statements have been prepared in conformity with accounting principles generally accepted in the United States and include amounts that represent management's best estimates and judgments. Management has established practices and procedures designed to support the reliability of the estimates and minimize the possibility of a material misstatement.
Management has established and maintains internal accounting controls that provide reasonable assurance as to the integrity and reliability of the financial statements, the protection of assets from unauthorized use or disposition, and the prevention and detection of fraudulent financial reporting. The system of internal control is supported by written policies and procedures, and the control environment is regularly evaluated by both Deloitte & Touche LLP,the independent auditors, and the Corporation's internal auditors. The Board of Directors maintains an Audit Committee composed of Directors who are not employees. The Audit Committee meets periodically with management, the independent auditors and the internal auditors to discuss significant accounting, auditing, internal accounting control and financial reporting matters. The independent auditors and the internal auditors have free access to the Audit Committee.
Management believes that, as of December 31, 1994, the overall system of internal accounting controls is sufficient to accomplish the objectives discussed herein.
/s/ D. W. Biegler /s/ S. R. Singer /s/ J. W. Pinkerton _______________________ ______________________ ______________________ D. W. Biegler S. R. Singer J. W. Pinkerton Chairman, President and Senior Vice President, Vice President and Chief Executive Officer Finance and Corporate Controller, Development, Chief Chief Accounting Officer Financial Officer
February 10, 1995
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ENSERCH Corporation and Subsidiary Companies
All dollar amounts, except per share amounts, in the notes to the consolidated financial statements are stated in thousands unless otherwise indicated.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER INFORMATION
The consolidated financial statements include the accounts of ENSERCH Corporation (ENSERCH or the Corporation) and its majority owned subsidiaries. The statements of consolidated income and cash flows for 1993 and 1992 have been restated to reflect the environmental business sold in 1994 as a discontinued operation.
Earnings per share applicable to common stock are based on the weighted average number of common shares outstanding during the year, including common equivalent shares when dilutive. Fully diluted earnings per share are not presented since the assumed exercise of stock options and conversion of debentures would not be dilutive.
All highly liquid investments in the United States with a maturity of three months or less are considered to be cash equivalents.
Information by business segments is presented after the notes and is an integral part of these financial statements. Non-U.S. operations provided less than 10% of consolidated revenues and employed less than 10% of consolidated assets for all periods presented. No customer provided more than 10% of consolidated revenues.
Natural Gas Transmission and Distribution - The Lone Star Gas Company (Lone Star) division is subject to the accounting requirements prescribed by the National Association of Regulatory Utility Commissioners. Rates are established by the Railroad Commission of Texas and by municipal governments.
Lone Star records revenues on the basis of cycle meter readings throughout the month and accrues revenues for gas delivered from the meter reading dates to the end of the month. The transmission and distribution system is depreciated by the straight-line method over approximately 40 years. Gas stored underground is valued at average cost.
Lone Star has made accruals for payments that may be required for settlement of gas-purchase contract claims asserted or that are probable of assertion. Lone Star's rates provide for the recovery of the actual cost of gas, including out-of-period costs such as gas-purchase contract settlement costs. Lone Star continually evaluates its position relative to asserted and unasserted take-or-pay claims, above-market prices or future commitments. Management believes that the Corporation has not incurred losses for which reserves should be provided at December 31, 1994.
Natural Gas and Oil Exploration and Production - The full-cost accounting method prescribed by the Securities and Exchange Commission is followed for gas and oil properties. Costs directly associated with the acquisition and evaluation of unproved gas and oil properties are excluded from the amortization base until the related properties are evaluated. Such unproved properties are assessed periodically and a provision for impairment is made to the full-cost amortization base when appropriate. Amortization of evaluated gas and oil properties is computed on the unit-of-production method using estimated proved gas and oil reserves quantified on the basis of their
equivalent energy content. Amortization of gas and oil properties was approximately 5.8% in 1994, 6.0% in 1993 and 5.7% in 1992. At December 31, 1994, estimates of future site restoration, dismantlement and abandonment costs, as assessed on an overall cost center basis, were less than estimates of future salvage values. Therefore, no accruals were required.
Gas and oil swaps, collars and futures agreements are used to hedge volatile product prices for a portion (normally 30 to 70 percent) of anticipated future gas and oil production. The purpose of these hedging activities is to fix the prices to be received. Under these agreements, payments are received or made based on the differential between a fixed and a variable product price. These agreements are settled in cash at or prior to expiration or exchanged for physical delivery contracts. Realized gains and losses on hedging activities are deferred and included in income during the month that the related physical sale occurs. In the event of nonperformance by counterparties, ENSERCH would be exposed to price risk. ENSERCH does not obtain collateral to support the agreements but monitors the financial viability of counterparties. ENSERCH has no off-balance sheet risk of accounting loss.
ENSERCH's 99.2% ownership of Enserch Exploration Partners, Ltd. (EP) was held primarily through Enserch Processing Partners Limited (EPPL). On December 30, 1994, Enserch Exploration, Inc. (EEX), a newly organized Texas corporation, acquired all of the partnership interests of EP Operating Limited Partnership (EPO), the operating partnership of EP in which EP owned a 99% interest and other ENSERCH companies owned a 1% interest. EPO was then merged into EEX and thereafter, EP was liquidated. Following the liquidation of EP, EPPL redeemed ENSERCH's interest in EPPL in exchange for EEX stock and EPPL's operating assets. ENSERCH's natural gas and oil exploration and production and natural gas liquids processing operations are now conducted in corporate form.
2. BORROWINGS AND LINES OF CREDIT
The Convertible Subordinated Debentures have an interest rate of 6 3/8%, are due 2002 and are convertible into common stock at $26.88 per share (equal to 37.20 shares per $1 thousand principal amount). The Debentures may be redeemed at 103.19% of the principal amount, plus accrued interest, through March 31, 1995 and at declining premiums thereafter.
Commercial paper totaled $151 million at December 31, 1994 and $32 million at year-end 1993. The average year-end interest rate on commercial paper borrowings was 6.3% in 1994 versus 3.5% in 1993.
Lines of credit are maintained that provide for short- and interim-term borrowings and also support commercial paper borrowings. The aggregate lines of credit totaled $600 million at December 31, 1994 and expire in 1997. All lines are on a fee basis and none require compensating balances or restrict the use of cash. All lines provide for borrowing at prevailing market rates.
The 1992 extraordinary loss included a $10.4 million ($15.8 million pretax) charge for the estimated cost to terminate an interest-rate swap agreement and charges totaling $5.0 million ($7.3 million pretax) for call premiums and other expenses associated with the early extinguishment of high interest-rate debt. The swap, which expired in January 1995, hedged the interest rate on $100 million of variable-rate debt.
The fair value of other financial instruments consisting primarily of cash and equivalents, accounts receivable, investments, commercial paper and other short-term borrowings, accounts payable and other accrued liabilities and accrued interest approximates carrying value. The estimated fair value of senior long-term debt does not reflect prepayment penalties, which would be incurred upon early extinguishment.
3. SHAREHOLDERS' EQUITY
As of December 31, 1994, 8,071,367 shares of unissued common stock were reserved for issuance under stock plans and conversion of convertible subordinated debentures. The Corporation is authorized to issue up to 2,000,000 shares of preferred stock and 2,000,000 shares of voting preference stock.
The Series F stock was sold in April 1994 for net proceeds of $73 million and is represented by three million depositary shares (stated value $25 per share). The Series E stock is represented by one million depositary shares (stated value $100 per share).
The Series F stock is redeemable at $25 per depositary share beginning after May 1, 1999, and the Series E stock is redeemable at the option of the Corporation at $100 per depositary share at any time. Holders of the preferred stock are entitled to its stated value upon involuntary liquidation.
Dividend rates are determined quarterly, in advance, based on the "Applicable Rate" (highest of the three-month Treasury bill rate, the Treasury ten-year constant maturity rate and either the Treasury twenty-year or thirty-year constant maturity rate, as defined), as set forth below:
Dividends - Restrictions on the payment of dividends on common stock (other than stock dividends) or acquisitions of capital stock are contained in a loan agreement relating to senior long-term debt and in the Restated Articles of Incorporation. At December 31, 1994, the amount of dividends on common stock that could be paid under the most restrictive of these agreements was $423 million.
Shareholder Rights Plan - The outstanding shares of common stock include one voting preference stock contingent purchase right, which is exercisable only under specific conditions. Under those conditions, each right could be exercised to purchase one two-hundredth share of a new series of voting preference stock at an exercise price of $60 or will entitle its holder to purchase, at a specified exercise price, shares of the Corporation's common stock (or, in certain circumstances as determined by the Board of Directors, other consideration) having a value of twice the right's exercise price. The rights have no voting privileges, expire on May 5, 1996 and are generally redeemable at $.05 per right until the 15th day following public announcement that a 20% position has been acquired.
Stock Options - Stock options have been awarded to key employees and are outstanding under three plans. Options for 9,055 shares granted under a former plan have an exercise option price equal to par value ($4.45). Options granted under the other plans have an exercise price of not less than the fair market value of the common stock on its grant date. At December 31, 1994, there were 126 participants in the stock option plans. Options become exercisable over four years and generally expire ten years after the date of the grant.
The current stock option plan was amended in February 1994 to include provisions for granting restricted stock. At December 31, 1994, a total of 74,700 shares of performance-based restricted stock had been issued to certain executive officers and were outstanding. Performance criteria for lifting the restrictions is related to three-year total shareholder return compared with the weighted average of a peer group of companies.
4. COMMITMENTS AND CONTINGENT LIABILITIES
Legal Proceedings - A lawsuit was filed on February 24, 1987, in the 112th Judicial District of Sutton County, Texas, against subsidiaries and affiliates of the Corporation and its utility division. The plaintiffs have claimed that defendants failed to make certain production and minimum-purchase payments under a gas-purchase contract. The plaintiffs have alleged a conspiracy to violate purchase obligations, improper accounting of amounts due, fraud, misrepresentation, duress, failure to properly market gas and failure to act in good faith. Plaintiffs seek actual damages in excess of $5 million and punitive damages in an amount equal to 0.5% of the consolidated gross revenues
of the Corporation for the years 1982-1986 (approximately $85 million), interest, costs and attorneys' fees.
Management of the Corporation believes it has meritorious defenses to the claims made in this and other actions brought in the ordinary course of business. In the opinion of management, the Corporation will incur no liability from this and all other pending claims and suits that is material for financial reporting purposes.
Environmental Matters - The Corporation is subject to federal, state and local environmental laws and regulations that regulate the discharge of materials into the environment. Environmental expenditures are expensed or capitalized depending on their future economic benefit. The level of future expenditures for environmental matters, including costs of obtaining operating permits, enhanced equipment monitoring and modifications under the Clean Air Act and cleanup obligations, cannot be fully ascertained until the regulations that implement the applicable laws have been approved and adopted. However, the capital expenditures required to achieve compliances with the Clean Air Act regulations, in their current form, have been estimated to range from $5 to $20 million, with expenditures to be made over a two-to three-year period. It is management's opinion that all such costs, when finally determined, will not have a material adverse effect on the consolidated financial position or results of operations of the Corporation.
Commitments - Future minimum commitments are as follows (in millions):
Lease Commitments - In 1992, the Corporation entered into operating lease arrangements to provide financing for its portion of the offshore platforms and related facilities for the Mississippi Canyon Block 441 (MC 441)(37.5% owned) and Garden Banks Block 388 (GB 388) (100% owned) projects. The leases contain fixed-priced purchase options and, if terminated, require a guaranteed residual payment.
A total of $34 million was required for the MC 441 project. The lease was modified in the second quarter of 1994 with terms that resulted in capital lease accounting treatment, a noncash investing and financing transaction. The noncurrent portion of the lease obligation of $28 million is included in other noncurrent liabilities.
Under the GB 388 lease arrangement, the lessor will fund the construction cost of the facilities quarterly, up to a maximum of $235 million, all of which had been advanced under the lease at December 31, 1994. The facilities will be leased for an initial period through March 31, 1997. The lease may be extended for up to three successive two-year periods on such terms as the Corporation and lessor may agree. The Corporation is constructing the leased property and has guaranteed completion of construction. The Corporation has the option to purchase the facilities throughout the lease period and has guaranteed an estimated residual value for the facilities of approximately $188 million should the lease terminate. Lease payments are deferred during construction and will be amortized when production begins.
The cost of the Garden Banks facilities is expected to be $330 million, which includes design modifications and other costs for Block 388 facilities and for the recent discovery on Block 387. Financing options for the additional costs currently are being evaluated, including an addition to the current operating lease arrangement.
The Corporation had a number of other noncancelable long-term operating leases at December 31, 1994, principally for office space and machinery and equipment. Rental expenses incurred under all operating leases aggregated $7.9 million in 1994, $10.8 million in 1993 and $14.2 million in 1992. Rental income received for subleased office space was $3.6 million in 1994, $3.4 million in 1993 and $4.7 million in 1992. Future minimum rental income to be received for subleased office space is $7.7 million over the next five years.
Gas-Purchase Contracts - Lone Star buys gas under long-term, intrastate contracts in order to assure reliable supply to its customers. Many of these contracts require minimum purchases ("take-or-pay") of gas. Based on Lone Star's estimated gas demand, which assumes normal weather conditions, requisite gas purchases are expected to substantially satisfy purchase obligations for the year 1995 and thereafter.
Gas Marketing - Enserch Gas Company (EGC) enters into contracts to purchase and sell natural gas for physical delivery in the future. At December 31, 1994, EGC had a net commitment to purchase natural gas through January 1996, for which a $4 million charge was recorded to reflect lower year-end market prices.
Sales of Receivables - The Corporation has an agreement until 1996 with a commercial bank for the limited recourse sale of up to $100 million of Lone Star's receivables. Additional receivables are continually sold to replace those collected. In a separate agreement, a limited recourse sale of receivables retained from the sale of Ebasco occurred. As of December 31, 1994 and 1993, the uncollected balances of receivables sold were $133 million and $200 million, respectively.
Guarantees - The Corporation and/or its subsidiaries are the guarantor on various commitments and obligations of others aggregating some $111 million at December 31, 1994. The Corporation is exposed to loss in the event of nonperformance by other parties. However, the Corporation does not anticipate nonperformance by the counterparties.
Concentrations of Credit Risk - Natural Gas Transmission and Distribution operations have trade receivables from a few large industrial customers in North Central Texas arising from the sale of natural gas. A change in economic conditions may affect the ability of customers to meet their contractual obligations. At December 31, 1994 and 1993, the allowance for possible losses deducted from accounts receivable was $4,686 and $4,753, respectively. The Corporation believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.
5. EMPLOYEE BENEFIT PLANS
Pension Plan - A defined benefit pension plan provides retirement income benefits for substantially all employees. Accrued retirement costs are funded to the extent such amounts are deductible for federal income tax purposes. Plan assets include equity and fixed-income securities and cash. Benefits are based on years of credited service and average compensation.
ENSERCH retained the pension obligations to former Ebasco and Enserch Environmental employees, and no further benefits will accrue, thus the decline in service cost in 1994. Plan curtailment gains of $2.2 million in 1994 and $6.9 million in 1993 were recognized in discontinued operations. During 1994, the Ebasco pension plan was merged with the ENSERCH plan.
Investment Plan - A voluntary contributory investment plan is available to substantially all employees. The Corporation matches a portion of employees' contributions with ENSERCH common stock. Costs under the plans were $1.9 million, $3.5 million and $3.5 million in 1994, 1993 and 1992, respectively.
Postretirement Benefits Other than Pensions - Some retirees, including those of Ebasco, and their dependents receive postretirement medical benefits that vary in level based on their years of service and retirement date. Employees hired after July 1, 1989 are not eligible for medical benefits when they retire. Obligations are not prefunded.
The assumed health care cost trend rate is 12.0% for 1994, declining gradually to 6.0% in 2003, and remaining at that level thereafter. If the health care cost trend rate were increased by 1%, the accumulated postretirement benefit obligation as of December 31, 1994 would be increased by $4.8 million and the net periodic postretirement benefit cost for 1994 by $.4 million.
Prior to 1993, benefit costs were expensed as paid and amounted to $7.5 million for 1992.
6. INCOME TAXES
At the completion of the conversion of EP and EPPL to corporate form, the tax basis of certain properties of ENSERCH and subsidiary companies receiving EEX stock in the conversion exceeded the financial basis of such properties. Also, the financial basis of ENSERCH and subsidiary companies in EEX exceeds their tax basis in the EEX stock. ENSERCH expects to ultimately recover the excess financial basis tax free. As a result of the conversion and related change in tax status, deferred income taxes applicable to the difference between the financial and tax basis of ENSERCH and subsidiary companies' investment in the partnerships were reduced by $70 million.
Deferred income taxes provided by the liability method for significant temporary differences based on tax laws and statutory rates in effect at the December 31, 1994 and 1993 balance sheet dates are as follows:
At December 31, 1994, domestic net operating-loss carryforwards total $205 million, which begin to expire in 2003, and tax-credit carryforwards total $27 million, which begin to expire in 1999. The tax benefits of these carryforwards of $99 million, as shown above, are available to reduce future income-tax payments.
7. DISCONTINUED OPERATIONS
In October 1994, the Corporation sold Enserch Environmental Corporation, which conducted the former environmental businesses of Ebasco, for $98 million. The principal operating assets of Ebasco were sold in December 1993 for net proceeds of $191 million. Also in December 1993, Dorsch Consult was sold for $9.3 million, including the assumption of debt. In 1992, the business of H&G Engineering was sold. Discontinued operations are summarized as follows:
The tax effect of the 1993 gain on sale differs from tax at the statutory rate because of permanent differences in financial and tax basis of the assets sold. The determination of the gain on the sale of the principal operating assets of Ebasco in 1993 involved significant estimates, including the final purchase price, realization of the estimated value of retained assets and related income-tax matters. In 1994, a loss provision of $17.5 million pretax ($10.0 million after-tax) was recorded in recognition that costs and expenses incurred for the wind-up of discontinued businesses would be greater than previously estimated. At December 31, 1994, the retained assets of discontinued businesses consisted principally of billed and unbilled accounts receivable and retainages (net of valuation allowances) of $36 million and liabilities of $48 million.
8. SUPPLEMENTARY GAS AND OIL INFORMATION
Gas and Oil Producing Activities - The following tables set forth information relating to gas and oil producing activities. Reserve data for natural gas liquids attributable to leasehold interests owned by the Corporation are included in oil and condensate.
Costs excluded from the amortizable base as of December 31, 1994(in millions):
Approximately 41% of the excluded costs relates to offshore activities in the Gulf of Mexico, about 57% is domestic onshore exploration activities and the remainder is non-U.S. The anticipated timing of the inclusion of these costs in the amortization computation will be determined by the rate at which exploratory and development activities continue, which are expected to be accomplished within ten years.
The following information is required and defined by the Financial Accounting Standards Board. The disclosure does not represent the results of operations based on historical financial statements. In addition to requiring different determinations of revenues and costs, the disclosure excludes the impact of interest expense and corporate overheads.
Hedging Activities - At December 31, 1994, ENSERCH had outstanding swaps, collars and futures agreements extending through December 31, 1995 to exchange payments on 17.8 Bcf of natural gas and 1.2 MMBbls of oil on which ENSERCH had $4.1 million of net unrealized gains based on the difference between the strike price and the NYMEX futures price for the applicable trading month. At December 31, 1994, realized gains on hedging activities of $.9 million were deferred. The weighted average strike price and market price per Mcf of natural gas was $2.06 and $1.84, respectively, and the weighted average strike price and market price per barrel of oil was $17.98 and $17.82, respectively.
Gas and Oil Reserves (Unaudited) - The following table of estimated proved and proved developed reserves of gas and oil has been prepared utilizing estimates of year-end reserve quantities provided by DeGolyer and MacNaughton, independent petroleum consultants. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing gas and oil properties. Accordingly, the reserve estimates are expected to change as additional performance data become available.
In 1994, foreign (non-U.S.) extensions, discoveries and additions resulted in 4,105 MBbl of oil at December 31, 1994.
Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserve Quantities (Unaudited) - has been prepared using estimated future production rates and associated production and development costs. Continuation of economic conditions existing at the balance sheet date was assumed. Accordingly, estimated future net cash flows were computed by applying contracts and prices in effect in December to estimated future production of proved gas and oil reserves, estimating future expenditures to develop proved reserves and estimating costs to produce the proved reserves based on average costs for the year. Average prices used in the computations were: Gas (per Mcf) $2.29 in 1994, $2.38 in 1993 and $2.20 in 1992; Oil (per barrel) $14.07 in 1994, $11.73 in 1993 and $16.89 in 1992.
Because reserve estimates are imprecise and changes in the other variables are unpredictable, the standardized measure should be interpreted as indicative of the order of magnitude only and not as precise amounts.
Quarterly Results (Unaudited) - The results of operations by quarters are summarized below and have been restated for the discontinuance of the environmental business. In the opinion of the Corporation, after the restatement, all adjustments (consisting only of normal recurring accruals) necessary for a fair presentation have been made.
Reconciliation of Previously Reported Quarterly Information
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.
DIVIDENDS PER SHARE OF COMMON STOCK
As of December 31, 1994, the Corporation had paid 202 consecutive quarterly cash dividends on its common stock. At December 31, 1994, $423 million of common shareholders' equity was free of restrictions as to the payment of dividends and redemption of capital stock. The declaration of future dividends will be dependent upon business conditions, earnings, cash requirements and other relevant factors. In February 1995, a quarterly cash dividend of $.05 per share was declared, payable March 6, 1995, to shareholders of record on February 24, 1995. Quarterly cash dividends on common stock were $.05 per share (annual rate of $.20 per share) in both 1994 and 1993 and $.20 per share (annual rate of $.80 per share) for the four preceeding years.
In November 1990, two million shares of PESC common stock obtained in connection with the sale of Pool Company were distributed to ENSERCH shareholders, which had a value equivalent to $.33 per share of ENSERCH common stock.