Annual Report (Form 10-K), fiscal year 1993

ITEM 1. Business
ENSERCH Corporation ("ENSERCH" or the "Corporation") is an integrated company focused on natural gas. It is the successor to a company originally organized in 1909 for the purpose of providing natural-gas service to North Texas. The Corporation's operations include the following:
- Natural Gas Transmission and Distribution - Owning and operating interconnected natural-gas transmission pipelines, gathering lines, underground gas storage reservoirs, compressor stations, distribution systems and related properties; transporting, distributing and selling natural gas to residential, commercial, industrial, electric-generation, pipeline and other customers; and compressing natural gas for motor vehicle usage. (Lone Star Gas Company, a division of the Corporation, Enserch Gas Company, and related operations.)
- Natural Gas and Oil Exploration and Production - Exploring for, developing, producing and marketing natural gas and oil. (Enserch Exploration, Inc., Enserch Exploration Partners, Ltd. [more than 99% owned], Enserch International Exploration, Inc., and related operations.)
- Natural Gas Liquids Processing - Gathering natural gas, processing natural gas to produce liquids and marketing the products. (Enserch Processing Partners, Ltd.)
- Power and Other - Developing, operating and maintaining independent electric-generation power plants and cogeneration facilities; and furnishing energy services under long-term contracts to large building complexes, such as universities and medical centers (Enserch Development Corporation and Lone Star Energy Company). Providing environmental engineering and contracting services from initial site assessment and feasibility studies to designs, actions and remediation (Enserch Environmental Corporation).
On December 22, 1993, the Corporation completed the sale of the principal operating assets of its former engineering and construction subsidiary, Ebasco Services Incorporated, to a subsidiary of Raytheon Company. Also in December 1993, in a separate transaction, the Corporation completed the sale of its 49% interest in Dorsch Consult. See "Financial Review" and Note 11 of the Notes to Consolidated Financial Statements included in Appendix A to this report.
Business Segments
Financial information required hereunder is set forth under "Summary of Business Segments" included in Appendix A to this report.
Natural Gas Transmission and Distribution
The Corporation's transmission and distribution business ("T&D") is composed of the regulated business of Lone Star Gas Company ("Lone Star"), and the nonregulated gas marketing operations of Enserch Gas Company ("EGC").
Lone Star owns and operates interconnected natural-gas transmission lines, gathering lines, underground gas storage reservoirs, compressor stations, distribution systems and related properties. Through and by such facilities, it purchases, distributes and sells natural gas to about 1.25 million residential, commercial, industrial and electric-generation customers in approximately 550 cities and towns, including the 11-county Dallas/Fort Worth Metroplex. Lone Star also transports natural gas for unaffiliated pipeline and industrial customers as market opportunities are available. About seven million people
in Texas, representing more than 40% of the total state population, reside in Lone Star's service area.
EGC purchases and sells natural gas to industrial and electric-generation customers, local distribution companies and other pipeline and gas marketing companies.
The Corporation holds a 50% interest in a partnership named Gulf Coast Natural Gas Company that operates a transmission system in the Texas Gulf Coast area, which transports and sells natural gas to industrial and unaffiliated pipeline customers.
For the year ended December 31, 1993, residential and commercial customers accounted for 56% of T&D's total gas sales revenues and 34% of natural gas volumes sold; industrial customers accounted for 12% and 17%, respectively, and electric-generation customers accounted for 12% and 17%, respectively. Sales to other customers accounted for 20% of T&D's natural gas revenues and 32% of volumes sold. In 1993, 10% of T&D's gas sales volumes was sold to Texas Utilities Fuel Company, compared with 12% in 1992. See "Financial Review - Natural Gas Transmission and Distribution" included in Appendix A to this report for a discussion of Lone Star's gas sales margin.
Operating data for the T&D segment are set forth under "Financial Review - Natural Gas Transmission and Distribution Operating Data" included in Appendix A to this report.
Revenues from Lone Star's gas sales are affected by seasonal variations. The majority of Lone Star's residential and commercial gas customers uses gas for heating. Revenues from these customers are affected by the mildness or severity of the heating season. Gas sales to electric-generation customers are affected by the mildness or severity of the cooling and heating seasons.
Reengineering activities taking place within Lone Star's distribution operations have resulted in a number of process and system changes being made to improve customer service and provide operating efficiencies. As a part of these changes, the workforce will be reduced and many local offices will be closed. A related $12 million pretax charge was taken in 1993 primarily to reflect severance expenses.
Competition. Natural gas continues to face varying degrees of competition from electricity, coal, natural gas liquids, oil and other refined products throughout Lone Star's service territory. Pipeline systems of other companies, both intrastate and interstate, extend into or through the areas in which Lone Star's markets are located, setting up competitive situations with other sellers of natural gas for existing and potential customers. Customer sensitivity to energy prices and the availability of competitively priced gas in the nonregulated markets continue to provide intense competition in the electric- generation and industrial user markets. Competitive pressure from other pipelines and alternative fuels has caused a continuing decline in sales by Lone Star to industrial and electric-generation customers each year since 1981, most of which has been replaced by sales of the Corporation's nonregulated companies.
Lone Star initiated a program in 1992 that provides its industrial cus- tomers an opportunity to have transportation service for up to 50% of their natural-gas requirements transported by Lone Star. The gas to be trans- ported may be purchased by the industrial customers from third-party suppliers. This has resulted in lower overall gas costs to the industrial customers able to take advantage of this program, helping Lone Star maintain long-term gas load, with no detrimental effect on other customers.
In Lone Star's service area, the intensity of competition among natural gas, fuel oil, and coal is dependent upon relative prices of the products.
During most of 1993, natural gas was generally successful competing with fuel oil but was generally unable to compete effectively with coal in existing coal-fired units.
In response to highly competitive industrial and electric-generation markets, T&D continues to expand its businesses of arranging transportation and the purchase and sale of gas in the nonregulated markets. This is accomplished through the gas marketing activities of EGC. EGC sales in 1993 were 244 billion cubic feet ("Bcf"), which was 57 Bcf (including 42 Bcf purchased for resale from affiliates) greater than in 1992. EGC continues to actively pursue sales to customers not located on Lone Star's pipeline system. These "off-system" sales efforts have been enhanced by the ability to transport interstate gas under the Federal Energy Regulatory Commission ("FERC") open-access transportation plan. EGC continues to purchase and resell gas subject to the Natural Gas Policy Act of 1978 ("NGPA") without utility regulatory constraints, providing EGC more opportunities to obtain supplies and market gas throughout the United States.
With more normal weather conditions in 1993, overall volumes of natural gas sold or transported to industrial, electric-generation and pipeline markets by T&D increased slightly compared with 1992 despite intense competition for gas load and the commencement of commercial operation of a second nuclear power plant in Lone Star's service area. In addition, the former Gulf Coast operations of Enserch Gas Transmission Company ("EGT"), in which Lone Star now has only a 50% interest, are not included in statistics after 1991. Transportation volumes for the entire segment were 371 Bcf in 1993, up 64 Bcf compared with 1992.
In the current energy market, Lone Star's contracts for new gas reserves have been at prices below its current systemwide weighted average cost of gas and are expected to continue to be so in the foreseeable future.
Source and Availability of Raw Materials. Lone Star's gas supply is based on contracts for the purchase of dedicated specific reserves and contracts with other pipeline companies in the form of service agreements that are not related to specific reserves or fields. Management has calculated that the total contracted gas supply as of January 1, 1994, was 972 Bcf, or approximately six times Lone Star's purchases during 1993. Of this total, 342 Bcf are dedicated reserves, 52 BCF are gas in storage, and 578 Bcf, (including 372 Bcf under one agreement) are committed to Lone Star under service agreements. The January 1, 1994, total gas supply estimate is 198 Bcf lower than the January 1, 1993, estimate. The difference resulted from purchases of 175 Bcf from existing gas supply, new supply additions of 5 Bcf and a net downward revision of 28 Bcf with respect to estimates for existing sources and service agreements. New reserve additions consisted of 5 Bcf of new dedicated reserves under old contracts. The Corporation also has estimated the oil and natural gas liquids reserves of Lone Star, as of January 1, 1994, to be 64,664 barrels.
In 1993, about 97% of Lone Star's gas requirement was purchased from some 370 independent producers and nonaffiliated pipeline companies, one of which supplied approximately 12.8% of total requirements. The remainder of Lone Star's requirement (3.2%) was supplied by affiliates.
Lone Star estimates its peak-day availability from presently contracted sources to be 1.8 Bcf. Short-term peaking contracts and withdrawals from underground storage raise this level to meet anticipated sales needs.
During 1993, the average daily demand of Lone Star's residential and commercial customers was .4 Bcf. The estimated peak-day demand of such customers (based upon an arithmetic-mean outside temperature of 15 degrees F.) was 1.9 Bcf. Lone Star's greatest daily demand in 1993 was on January 10, when estimated actual deliveries to all customers reached 1.7 Bcf and there was an arithmetic-mean temperature of 33 degrees F. The estimated deliveries to
residential and commercial customers on that day were 1.2 Bcf and another .9 Bcf were transported by Lone Star.
To meet peak-day gas demands during winter months, Lone Star utilizes its eight active underground storage fields, all of which are located in Texas. These fields have an extraneous gas capacity of 74 Bcf. At December 31, 1993, total extraneous gas in storage was approximately 52 Bcf. Gas withdrawn from storage on January 10, 1993, the date of Lone Star's greatest daily demand in 1993, was .4 Bcf, or approximately 24% of the total 1.7 Bcf of Lone Star's sales.
Lone Star historically has maintained a curtailment program designed to achieve the highest load factor possible in the use of its pipeline system while assuring continuous and uninterrupted service to its residential and commercial customers. Under the program, industrial customers select their own rates and relative priorities of service. Interruptible service contracts give Lone Star the right to curtail gas deliveries up to 100% according to a strict priority plan.
Estimates of gas supplies and reserves are not necessarily indicative of Lone Star's ability to meet current or anticipated market demands or immediate delivery requirements, because of factors such as the physical limitations of gathering and transmission systems, the duration and severity of cold weather, the availability of gas reserves from its suppliers, the ability to purchase additional supplies on a short-term basis, and actions by federal and state regulatory authorities. Lone Star's curtailment rights provide flexibility to meet the human-needs requirements of its customers on a firm basis. Priority allocations and price limitations imposed by federal and state regulatory agencies, as well as other factors beyond the control of Lone Star, may affect its ability to meet the demands of its customers.
Lone Star follows a program to place new supplies of gas under contract to its pipeline system. In addition to being heavily concentrated in the established gas-producing areas of central, north and east Texas, Lone Star's intrastate pipeline system also extends into or near the major gas-producing areas of the Texas Gulf Coast, and the Delaware and Val Verde Basins of West Texas. Nine basins located in Texas are estimated to contain a substantial portion of the nation's remaining onshore natural-gas reserves. Lone Star's pipeline system provides access to all of these basins.
Lone Star's attractive service territory has been a primary factor in the continued addition of new customers. The number of Lone Star customers in Texas has steadily grown from 1986 to 1993. See "Financial Review - Natural Gas Transmission and Distribution Operating Data" included in Appendix A to this report.
Lone Star buys gas under long-term, intrastate contracts in order to assure reliable supply to its customers. To obtain this reliability, Lone Star, in the past, entered into many gas-purchase contracts that provided for minimum- purchase ("take-or-pay") obligations to gas sellers. In the past, Lone Star was unable to take delivery of all minimum gas volumes tendered by suppliers under these contracts. Assuming normal weather conditions, it is expected that normal gas purchases will substantially satisfy purchase obligations for the year 1994 and thereafter. For a discussion of these take-or-pay obligations and the Corporation's accounting policy with respect to gas-purchase contracts, see "Financial Review - Gas-Purchase Contracts" and Note 1 to the Consolidated Financial Statements included in Appendix A to this report.
Generally, EGC's gas supply is contracted for on a month-to-month basis at prevailing market prices. The availability of gas is dependent on many factors, including the overall demand for natural gas and market price.
Regulation. Lone Star is wholly intrastate in character. Its utility operations in the state of Texas are subject to regulation by the Railroad Commission of Texas ("RRC") and municipalities. Lone Star owns no certificated interstate transmission facilities subject to the jurisdiction of FERC under the Natural Gas Act, has no sales for resale under the rate jurisdiction of FERC, and does not perform any transportation service that is subject to FERC juris- diction under the Natural Gas Act.
In 1985, FERC issued Order 436, and later Order 500, which allow self- implementing, voluntary transportation of natural gas, as opposed to mandatory transportation for pipelines willing to assume FERC-imposed "open-access" conditions and certain other price/rate controls. The Order imposed "open- access" conditions that affect intrastate pipelines, such as Lone Star's intrastate facilities, if the intrastate pipeline "voluntarily" elects to transport gas for an interstate pipeline or local distribution company under Section 311 of the NGPA. Lone Star became an open-access transporter effective July 15, 1988, on its intrastate transmission facilities only. Transportation by each company is performed pursuant to Section 311(a)(2) of the NGPA and is subject to an exemption from the jurisdiction of the FERC under the Natural Gas Act, pursuant to Section 601 of the NGPA.
The RRC regulates the intracompany charge for gas delivered to Texas distribution systems for sale to residential and commercial consumers. The RRC has original jurisdiction over rates charged to residential and commercial customers for gas delivered outside incorporated cities and towns (environs rates). Rates within incorporated cities and towns in Texas are subject to the original jurisdiction of the municipal government, with appellate review by the RRC. Proposed rate changes within the jurisdiction of the incorporated cities and towns in Texas may be suspended for a period not to exceed 90 days beyond the proposed effective date. The RRC may extend the time during which it deliberates and decides a matter within its appellate jurisdiction to a maximum of 185 days, but it may suspend rates within its original jurisdiction for 150 days beyond the proposed effective date.
Lone Star continuely reviews rates for all classes of customers in its regulatory jurisdictions. Rate relief amounting to $1.9 million in annualized revenue increases over and above changes in gas cost was achieved in Texas in 1993 through rate case filings, the operation of cost of service adjustment clauses, and the operation of plant investment cost adjustments. About 110 of the 550 cities and towns served by Lone Star had approved weather normalization adjustment clauses as part of their rate structure by yearend 1993, representing about 20% of Lone Star's residential and commercial sales volumes. These clauses allow rates to be adjusted monthly to reflect the impact of warmer- or colder-than-normal weather during the winter, minimizing the impact of variations in weather on Lone Star's earnings.
Sales and transportation services to industrial and electric-generation customers are provided under contract through contractual relations. Regulatory authorities in Texas have jurisdiction to revise, review and regulate rates to industrial and electric-generation customers but, historically, have not exercised this jurisdiction. Contracts with these customers permit automatic adjustment on a monthly basis for the full amount of increases or decreases in the cost of gas.
Natural Gas and Oil Exploration and Production
The Corporation's natural gas and oil exploration and production operations are collectively referred to herein as "Enserch Exploration." These operations and this business are conducted primarily through Enserch Exploration Partners Ltd. ("EP"), a limited partnership in which a minority interest (less than 1%) is held by the public and a group of subsidiary companies. Activities include geological and geophysical studies; acquisition of gas and oil leases; drilling
of exploratory wells; development and operation of producing properties; acquisition of interests in developed or partially developed properties; and the marketing of natural gas, crude oil and condensate.
In 1985, the Corporation formed EP to succeed to substantially all of the domestic gas and oil exploration and production business of the Corporation. The Corporation and an affiliate own more than 99% of the outstanding limited partnership units. The remaining units--slightly more than 800,000--are publicly held and traded on the New York Stock Exchange.
EP operates through EP Operating Limited Partnership ("EPO"), a Texas limited partnership, in which EP holds a 99% limited partner's interest and the general partners own a 1% interest. Enserch Exploration, Inc. is the managing general partner and the Corporation is the special general partner of EP and EPO.
Enserch Exploration is engaged in the exploration for and the development, production and marketing of natural gas and crude oil throughout Texas, offshore in the Gulf of Mexico, onshore in the Gulf Coast and Rocky Mountain areas and in various other areas in the United States. Subsidiaries currently have interests in three foreign countries.
Production offices are maintained in Dallas, Houston, Athens, Bridgeport, Longview and Midland, Texas. At December 31, 1993, Enserch Exploration employed 382 persons, including 36 geologists, 21 geophysicists and 19 land representatives who investigate prospective areas, generate drilling prospects, review submitted prospects and acquire leasehold acreage in prospective areas. In addition, Enserch Exploration maintains a staff of 56 engineers and 46 technologists who plan and supervise the drilling and completion of wells, evaluate prospective gas and oil reservoirs, plan the development and management of fields, and manage the daily production of gas and oil.
Enserch Exploration's natural-gas sales volumes for the year ended December 31, 1993, represented 16% of the Corporation's consolidated natural-gas sales volumes. Approximately 70% of Enserch Exploration's natural-gas sales volumes (75% of gas revenues) for the year ended December 31, 1993, was sold to affiliated customers. In 1993, affiliated revenues include gas sales under new contracts effective March 1, 1993 with Enserch Gas Company covering essentially all gas production not committed under existing contracts. Affiliated pur- chasers do not have a preferential right to purchase natural gas produced by Enserch Exploration other than under existing contracts.
The statistics for this business segment, which are set forth in the table entitled "Financial Review - Natural Gas and Oil Exploration and Production Operating Data" in Appendix A to this report, reflect the fluctuations in product prices and volumes and certain unusual items which affected operating income.
Following is a summary of Enserch Exploration's domestic exploration and development activity during 1993:
Gulf of Mexico. Offshore exploration provides the Corporation the opportunity to improve its ratio of production to reserve base by the addition of gas wells with relatively higher production rates. This is coupled with ongoing deep-water development projects, which are expected to provide long-term reserves. State-of-the-art technology, including 3-D seismic, specialized seismic processing, and innovative well completion and production techniques, are being used to help accomplish these objectives.
Mississippi Canyon Block 441, the first development project in the Gulf of Mexico that Enserch Exploration has operated, is indicative of this approach. A 3-D seismic program, prior to field development, confirmed that the majority of the reservoir lies beneath a shipping fairway. A production program was developed that involved drilling highly deviated wells under the shipping
fairway, subsea completing the deep-water wells, and tying the wells back to a conventional shallow-water production platform using bundled flowlines. The high-angle wells required special gravel-pack completion techniques. After a year of production, the field has been essentially maintenance free, producing some 70 million cubic feet ("MMcf") of natural gas and more than 500 barrels ("Bbls") of condensate per day from six wells.
The 3-D seismic on Mississippi Canyon Block 441 is being reprocessed, using depth migration and other state-of-the-art techniques to aid in the identification of deeper exploratory targets, which, if successfully drilled, could add to the field reserves. Enserch Exploration has a 37.5% working interest in this project.
The Garden Banks Block 388 oil development project remains on schedule, with initial production anticipated by mid-1995. Installation of the offshore facilities, which consist of a subsea template, gathering and sales pipelines, and shallow-water production facilities, will begin by mid-1994. After the rig and all facilities are in place, the three existing wells will be connected, with initial production from the first well expected to be approximately 5 thousand barrels ("MBbls") of oil and 5 MMcf of gas per day. Peak daily pro- duction from the project is anticipated to be 40 MBbls of oil and 60 MMcf of gas. Enserch Exploration is 100% owner and operator of the Garden Banks 388 project.
Another prospect delineated by seismic amplitude anomalies lies approximately four miles to the west of Garden Banks Block 388 on Garden Banks Blocks 386/387. If successfully drilled, this prospect could add production to the Block 388 development by incorporating some of the production technology that was utilized on Mississippi Canyon Block 441.
In 1994, an offset well to Enserch Exploration's discovery on Green Canyon Block 254 is scheduled to be drilled. The exploratory well, which was drilled in 1991, encountered 11 sands with a combined thickness of more than 360 feet of oil pay. Enserch Exploration has a 25% working interest in this block and a similar working interest in three adjacent blocks believed to be part of the same project.
Onshore. Enserch Exploration participated in 78 development wells (62 net) in 1993, with the majority completed as gas producers in East Texas. Thirty- nine wells were in progress at yearend. In East Texas, Enserch Exploration is positioned in a prolific gas-prone area which, despite its maturity, provides growth opportunities. Enserch Exploration is one of the oldest and most active operators in this basin in East Texas, which includes the Opelika, Tri-Cities, Whelan, Willow Springs, North Lansing and Freestone fields.
In early 1993, Enserch Exploration initiated a 26-well program in East Texas to accelerate the development of natural-gas reserves from the Travis Peak formation in the Opelika field. The program was targeted to test new techniques for shortening the average life of its reserve base. The project was completed in seven months, yielding initial daily per well production rates of up to 1.8 MMcf of gas and 48 Bbls of oil. Enserch Exploration has a 100% working interest in these wells.
Enserch Exploration performed additional development drilling in the Freestone field, where seven well completions flowed at daily rates ranging from 1.0 MMcf to 2.3 MMcf of gas per well. Enserch Exploration has 50% to 100% working interests in these wells.
In the Bralley field in West Texas, the combined daily oil production rate from six wells increased to 800 Bbls from 500 Bbls following production optimization work. Enserch Exploration owns a 50% working interest in each of these wells.
In South Texas, seven wells drilled and completed in the Fashing field flowed at daily rates of 1.2 MMcf to 2.6 MMcf of gas and 14 Bbls to 30 Bbls of oil per well. Twelve wells drilled and completed in the Boonsville field in north central Texas resulted in daily production of .4 MMcf to 1.5 MMcf of gas per well.
Onshore development activity planned for 1994 includes drilling approximately 35 wells outside East Texas. Some of the larger projects include wells in the Fashing, Rancho Viejo and Boonsville fields.
In the Fashing field, results of three wells and a field study indicate development potential for new wells, as well as recompletions that could result in reserve additions.
Competition. Competition in the natural gas and oil exploration and production business is intense. Domestically, competition is present from a large number of firms of varying sizes and financial resources, some of which are much larger than Enserch Exploration. Internationally, competition is from a number of both U.S. and non-U.S. firms, generally major national and international oil companies. Competition involves all aspects of marketing products (including terms, prices, volumes and length of contracts), terms relating to lease bonus and royalty arrangements, and the schedule of future development activity.
Regulation. Environmental Protection Agency ("EPA") rules, regulations and orders affect the operations of Enserch Exploration. EPA regulations promul- gated under the Superfund Amendments and Reauthorization Act of 1986 require Enserch Exploration to report on locations and estimates of quantities of hazardous chemicals used in Enserch Exploration's operations. The EPA has determined that most gas and oil exploration and production wastes are exempt from the hazardous waste management requirements of the Resource Conservation Recovery Act. However, the EPA determined that certain exploration and production wastes resulting from the maintenance of production equipment and transportation are not exempt, and these wastes must be managed and disposed of as hazardous waste. Also, regulations issued by the EPA under the Clean Water Act require a permit for "contaminated" stormwater discharges from exploration and production facilities.
Many states have issued new regulations under authority of the Clean Air Act Amendments of 1990, and such regulations are in the process of being imple- mented. These regulations may require certain gas and oil related installations to obtain federally enforceable operating permits and may require the monitoring of emissions; however, the impact of these regulations on Enserch Exploration is expected to be minor.
Several states have adopted regulations on handling, transportation, storage and disposal of naturally occurring radioactive materials that are found in gas and oil operations. Although applicable to certain Enserch Exploration facilities, it is not believed that such regulations will materially impact current or future operations.
In the aggregate, compliance with federal and state environmental rules and regulations is not expected to have a material effect on Enserch Exploration's operations.
The RRC regulates the production of natural gas and oil by Enserch Exploration in Texas. Similar regulations are in effect in all states in which Enserch Exploration explores for and produces natural gas and oil. These regulations generally require permits for the drilling of gas and oil wells and regulate the spacing of the wells, the prevention of waste, the rate of production, and the prevention and cleanup of pollution and other materials.
Natural Gas Liquids Processing
The Corporation's operations for the processing of natural gas for the recovery of natural gas liquids ("NGL") is conducted by Enserch Processing Partners, Ltd. ("Processing Partners"). Processing Partners is a limited partnership that is wholly owned by the Corporation.
Processing Partners, which is among the top 25 NGL producers in the U.S., uses cryogenic and mechanical refrigeration processes at its NGL extraction facilities. During these processes, NGL are condensed at extremely low temperatures and are separated from natural gas. The mixed NGL stream containing the heavier hydrocarbons ethane, propane, butane and natural gaso- line, is pumped via pipeline to Mt. Belvieu, Texas. The remaining natural gas, primarily methane, leaves the NGL plants in gas transmission lines for transport to end-use customers. (See "Properties".)
About 70% of NGL product sales are under term contracts of one-to-three years, with prices established monthly. NGL prices are influenced by a number of factors, including supply, demand, inventory levels, the product composition of each barrel, and the price of crude oil. Profitability is highly dependent on the relationship of NGL product prices to the cost of natural gas lost in the extraction process--"shrinkage."
The natural gas liquids processing area is highly competitive, including competition regarding cost-sharing and interest-sharing arrangements among producers, third-party owners and processors.
Power and Other
Energy Project Development. Enserch Development Corporation ("EDC") was organized in 1986 to develop business opportunities primarily in the areas of independent power, including cogeneration. EDC evaluates the risk and rewards of these potential ventures; selects for development those ventures with the highest potential of success; implements and controls development of each venture; and brings together all the resources required to develop, finance, construct, operate and manage the selected ventures. EDC focuses on employing a strategy of maximizing the use of ENSERCH resources and minimizing the Corporation's risk and investment. EDC, as of December 1993, had several business opportunities in various phases of development throughout the United States and internationally.
The first project completed by EDC, operating since 1989, was a gas-fired, 255-megawatt ("MW") cogeneration plant located near Sweetwater, Texas. The electricity produced by the plant is purchased by Texas Utilities Electric Company and thermal energy is sold to United Gypsum Company under a long-term agreement. EDC developed and arranged financing for the project and one of its subsidiaries is the managing general partner. Enserch Exploration and EGC provide gas to the plant; Lone Star transports the gas and Lone Star Energy Company ("LSEC") operates the plant.
In 1992, the second plant developed by EDC was completed. The 62-MW natural gas-fired cogeneration facility in Buffalo, New York, supplies elec- tricity to Niagara Mohawk Company and thermal energy to Outokumpu American Brass, Inc. LSEC operates the plant.
EDC's third project, a 160-MW plant located in Bellingham, Washington, began commercial operation July 1993. The electricity produced by the plant is sold under a long-term power sales agreement with Puget Sound Power & Light. Thermal energy in the form of steam and hot water is sold to Georgia-Pacific Corporation.
In addition to operating the above mentioned cogeneration plants, LSEC owns and/or operates four central thermal energy plants providing heating and cooling to various institutional customers in Texas. The aggregate existing plant capacity is nearly 50,000 tons of chilled water and 750 MMBtu's of steam or hot water per hour. From the three plants owned by LSEC, institutional customers receive thermal energy under long-term agreements that contain established rates for units of steam or chilled water and certain escalation provisions for increases in ad valorem taxes, utility and labor costs. When the agreements expire, the plants become the property of the customers. Expiration dates are in 1996 and 1997. LSEC is actively pursuing new contracts to operate the plants after the existing agreements expire. The expiration of the existing thermal- energy plant agreements is not expected to have a significant impact on the Corporation. LSEC also provides predictive maintenance services to outside plant owners through its Plant Analytical Services affiliate, which was formed in 1991.
As previously noted, LSEC operates the 255-MW Sweetwater cogeneration plant in West Texas. Labor for operating and maintaining this facility is provided under a fixed-cost contract with annual escalation provisions for increases in labor costs. All other costs are borne by the facility owners. LSEC also operates the 62-MW cogeneration plant in Buffalo, NY, and the 160-MW cogen- eration facility in Bellingham, Washington. At both the Buffalo and Bellingham plants, LSEC has fixed-cost operating and maintenance agreements with escalation provisions. The contracts also include bonus or penalty provisions based upon plant availability.
LSEC operates in the compressed natural gas ("CNG") market through its CNG Division along with two natural gas vehicle affiliates, Fleet Star of Texas, L.C. ("Fleet Star") and TRANSTAR Technologies, L.C., ("TRANSTAR"), each 50% owned by LSEC. Fleet Star and FinaStar, a partnership between Fleet Star and Fina Oil and Chemical, had six public stations in commercial operation at December 31, 1993, and four additional stations were under construction. The CNG Division and affiliates sold more than 1 million gallons of CNG into the emerging transportation fuels market during 1993. TRANSTAR Technologies, L.C., provides turnkey natural gas vehicle conversion and other related services. TRANSTAR was involved in the conversion of more than 300 vehicles to natural gas during its first full year of operation in 1993 and enters 1994 with a backlog of 120 units under contract to be converted.
The operations of the CNG Division and affiliates and the Plant Analytical Services have been aligned under the Corporation's natural gas transmission and distribution system for financial reporting purposes.
Enserch Environmental Corporation. The Corporation retained and will continue to operate the former environmental division of Ebasco Services Incorporated ("Ebasco"). This business is now operated through Enserch Environmental Corporation ("Enserch Environmental"), a lower-tier subsidiary of the Corporation. Enserch Environmental employs about 1,200 people and is headquartered in New Jersey. Enserch Environmental had 1993 revenues of $169 million, operating income of $5.7 million and its backlog at the end of 1993 was $600 million.
The Corporation's environmental business began in the 1960's as an out- growth of Ebasco's licensing of plant sites in connection with the company's power plant design and construction work. Enserch Environmental has extensive experience in all aspects of the environmental market, from initial site assess- ment and feasibility studies to remedial design, action and clean up. Over the last five years, Enserch Environmental has completed projects valued in excess of $1 billion in all areas of environmental and hazardous waste management ser- vices for more than 300 clients. Enserch Environmental has completed hundreds of environmental impact statements, licensing studies and baseline environmental investigations.
With business, government and the public showing an increasing concern about the environment, management believes that the environmental market will grow and that Enserch Environmental will be a strong participant in it.
Clean Air Act
The impact of the 1990 amendments to the Clean Air Act ("CAA") on the Corporation, its division, subsidiaries and affiliates, cannot be fully ascertained until all the regulations that implement the provisions of the Act have been promulgated. It is expected that a number of facilities or emission sources will require a federally enforceable operating permit, and certain emission sources may also be required to reduce emissions or to install enhanced monitoring equipment under proposed rules and regulations. Management currently believes, however, that if the rules and regulations implementing the CAA are adopted as proposed, the cost of obtaining permits, operating costs that will be incurred under the operating permit, new permit fee structures, capital expenditures associated with equipment modifications to reduce emissions, or any expenditures on enhanced monitoring equipment, in the aggregate, will not have a material adverse effect on the Corporation's results of operations.
The CAA has created new marketing opportunities for the sale of natural gas that may have a positive effect on the Corporation's results of operations. Natural gas has long been recognized as a clean and efficient fuel. Title II (Mobile Sources) requires lower emissions from light-duty vehicles and urban buses that should make alternative fuels such as natural gas more attractive and competitive. In addition, Clean Fuel Fleet programs under the CAA will require a certain percentage of fleet vehicles to utilize clean-burning alternative fuels such as natural gas in the near future. Further, because chlorofluoro- carbon compounds ("CFCs"), commonly used as refrigerants in large air- conditioning systems must be phased out of production by the year 2000, interest has increased in the use of natural gas-powered absorption cooling systems that do not use CFCs. In those areas that do not meet the CAA's National Ambient Air Quality Standards for ozone, natural gas may play an important role in reduc- ing ozone formation, and may be substituted for other fuels. Since Title IV (Acid Rain) requires major reductions in sulphur dioxide emissions, princi- pally from coal-fired electric power plants, natural gas is expected to be considered as a cost-effective alternative for achieving reduced sulphur dioxide emissions.
The CAA also is expected to create new marketing opportunities for Enserch Environmental, which has considerable experience and expertise in the engineer- ing and construction implications of environmental matters. Enserch Environ- mental's comprehensive services extend into the areas regulated by the CAA, including: Title III (Air Toxins) where regulated air toxins will ultimately grow from 8 to more than 200 contaminants, and private industrial clients, par- ticularly in the petroleum, petrochemical, chemical and pharmaceutical sectors, will require air-quality assessment, monitoring, engineering and facility upgrades; Title IV (Acid Rain) where electric-utility clients will require conceptual engineering studies, air-quality studies and monitoring; Title II (Mobile Sources) where increased emphasis is expected on environmental con- sulting related to transportation systems--both the construction of new types of infrastructure projects and the development of more sophisticated transporta- tion systems; and Title V (Permits) where industrial facilities will be required to obtain operating permits involving emission inventories, performing com- pliance analysis and operational studies, and designing and installation of emission monitors and/or enhanced monitoring systems.
The ultimate effect of these opportunities on the Corporation's business cannot be quantified at this time as it will depend on the extent to which natural gas is selected as an alternative fuel source and the services of Enserch Environmental Corporation are utilized in these newly regulated areas.
Patent and Licenses
The Corporation, Lone Star and subsidiary companies have no material patents, licenses, franchises (excluding gas-distribution franchises) or concession.
Employees
At December 31, 1993, the Corporation, its division and subsidiaries, employed approximately 5,600 persons.
Executive Officers of Registrant
There are no family relationships between any of the above officers. All officers of the Corporation, its division and subsidiaries are elected annually by their respective Boards of Directors. Officers may be removed by their respective Boards of Directors whenever, in their judgment, the best interest of
the Corporation, its division or subsidiaries, as the case may be, will be served thereby.
ITEM 2.



ITEM 2. Properties
At December 31, 1993, Lone Star and certain subsidiaries of the Corporation operated approximately 32,000 miles of transmission and gathering lines and distribution mains, and operated 37 compressor stations having a total rated horsepower of approximately 81,000. Lone Star owns eight active gas-storage fields, all located on Lone Star's system in Texas. Lone Star also owns three major gas-treatment plants to remove undesirable components from the gas stream. See "Business - Natural Gas Transmission and Distribution - Source and Availability of Raw Materials" for information concerning gas supply of Lone Star.
As estimated by DeGolyer and MacNaughton, Enserch Exploration has net proved reserves, as of January 1, 1994, of 1.09 trillion cubic feet ("Tcf") of natural gas and 39.3 million barrels ("MMBbls") of oil and condensate, including NGL attributable to leasehold interests. (See Note 13 of the Notes to Consolidated Financial Statements included in Appendix A to this report for additional information on gas and oil reserves.) All of these reserves are in the United States.
Enserch Exploration's 1994 capital spending budget has been set at $116 million, a 3% decrease from 1993 actual capital expenditures. More than half of the 1994 capital expenditures is earmarked for domestic onshore drilling. The exploration program includes a balance mix of projects with regard to reserve potential and risk, focusing on as many core area oppor- tunities as possible. See "Financial Review - Natural Gas and Oil Exploration and Production" included in Appendix A to this report.
During 1993, Enserch Exploration filed Form EIA-23 with the Department of Energy reflecting reserve estimates for the year 1992. Such reserve estimates were not materially different from the 1992 reserve estimates reported in Note 13 of the Notes to Consolidated Financial Statements included in Appendix A to this report.
Operating data relating to Enserch Exploration are set forth under "Financial Review - Natural Gas and Oil Exploration and Production Operating Data" included in Appendix A to this report.
Enserch Exploration and subsidiary companies owned leasehold interests or licenses in 17 states, offshore Texas and Louisiana, and three other countries as of December 31, 1993, as follows:
Enserch Exploration purchased about 220,000 net acres of leasehold interests in 1993, 26,000 of which were in the Gulf of Mexico. Enserch Explora- tion's Gulf of Mexico holdings totaled some 123,000 net acres, with an average working interest of 36% in 64 leases covering 65 blocks with an overriding royalty interest in six other leases. The company operates 23 leases cover- ing 24 offshore blocks. Enserch Exploration also canceled, or allowed to expire, eight Gulf of Mexico leases during the year. These leases had been con- demned following drilling on or near them or after geophysical and geological findings.
Enserch Exploration plans further drilling on undeveloped acreage but at this time cannot specify the extent of the drilling or predict how successful it will be in establishing the commercial reserves sufficient to justify retention of the acreage. The primary terms under which the undeveloped acreage in the United States can be retained by the payment of delay rentals without the establishment of gas and oil reserves expire 30% in 1994, 17% in 1995, 25% in 1996, 13% in 1997, 4% in 1998, 1% in 1999 and 10% thereafter. A portion of the undeveloped acreage may be allowed to expire prior to the expiration of primary terms specified in this schedule by nonpayment of delay rentals. Aside from
Texas, the Gulf of Mexico, Malaysia and Indonesia, Enserch Exploration has no material concentration of undeveloped acreage in single areas at this time.
Undeveloped acreage in other countries, which can be retained without the establishment of gas or oil reserves, expires as follows: Indonesia - 25% in 1994, 30% in 1996, 20% in 1998 and 25% in 2000; United Kingdom - 100% in 2016; Malaysia - 100% in 1996.
Enserch Exploration participated in 111 wells (79 net) during the year. Of these wells, 83 (64 net) were completed successfully, resulting in a net success rate of 81%. Of the successful wells, 7 wells (4 net) were exploratory and 76 wells (60 net) were development. At December 31, 1993, Enserch Exploration was participating in 39 wells (21 net), which were either being drilled or in some state of completion.
In the 1993 domestic drilling program, 16 wells (4.9 net) were offshore. Of these wells, 9 (2.6 net) gas wells and 1 (.1 net) oil well were successfully completed. During 1992, 4 (1.6 net) offshore wells were drilled, of which 2 (.8 net) gas wells were successfully completed.
At December 31, 1993, Enserch Exploration owned working interests in 1,303 (980 net) gas wells and 1,121 (277 net) oil wells in the United States. Of these, 173 (141 net) gas wells and 37 (32 net) oil wells were dual completions in single boreholes.
Drilling activity by Enserch Exploration during the three years ended December 31, 1993, is set forth below:
The number of wells drilled is not a significant measure or indicator of the relative success or value of a drilling program because the significance of the reserves and economic potential may vary widely for each project. It is also important to recognize that reported completions may not necessarily track capital expenditures, since Securities and Exchange Commission guidelines do not allow a well to be reported as complete until it is ready for production. In the case of offshore wells, this may be several years following initial drilling because of construction of platforms, pipelines and other necessary facilities.
Additional information relating to the gas and oil activities of Enserch Exploration is set forth in Note 13 of the Notes to Consolidated Financial Statements included in Appendix A to this report.
Processing Partners has interest in 18 processing plants, 13 of which are wholly owned. The products, which in 1993 were produced at an average of about 16,500 barrels per day, are sold to customers primarily at the Mt. Belvieu fractionation and storage facility near Houston for use as chemical feedstock and other purposes. The processing plants are capable of producing an aggre- gate of about 27,000 barrels of NGL per day; daily production was up slightly from the previous year. Lone Star estimates that as of January 1, 1994, 27.2 MMBbls of NGLs are attributable to contractual processing rights of Pro- cessing Partners with respect to gas reserves owned by EP or third parties and dedicated to Lone Star under various gas-purchase contracts or are being trans- ported by Lone Star under various gas transportation agreements. See "Business - - Natural Gas Transmission and Distribution - Source and Availability of Raw Materials" for additional reserves held by Lone Star.
LSEC owns and operates three central plants providing heating and cooling to institutional customers in Dallas, El Paso and Galveston, Texas. LSEC also operates a similar plant in San Antonio, Texas.
The Corporation owns a five-building office complex in Dallas, containing approximately 453,000 square feet of space that the Corporation, Lone Star and certain subsidiaries fully occupy. In addition, the Corporation leases a 21- story, 400,000-square-foot building in Houston under a two-year lease that is automatically extended each year unless terminated.
ITEM 3.

ITEM 3. Legal Proceedings
The utility division of the Corporation was named as a codefendant in a lawsuit filed on November 10, 1988, in the 200th Judicial District Court of Travis County, Texas. Plaintiffs were parties to gas-sale contracts that provided for direct and indirect sale of gas to the utility division. Plain- tiffs allege that defendants implemented a series of unilateral price decreases, thereby improperly fixing prices paid for gas in three Texas counties in violation of state antitrust laws and the Texas State Natural Resources Code. Plaintiffs also allege breach of contract and fiduciary duties, fraud, interference of contracts, conspiracy, economic duress, failure to reasonably market the plaintiffs' gas, and perform the contracts in good faith and discrimination by a common purchaser. Plaintiffs seek actual damages of approximately $35 million and $20 million in punitive damages. Management believes the allegations are without merit and that liability, if any, will not have any material effect on the financial position of the Corporation.
Additional information required hereunder is set forth in Note 6 and Note 10 to Consolidated Financial Statements included in Appendix A hereto.
ITEM 4.

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" and "Summary of Business Segments" 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 30, 1994.
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
The following items are included in Appendix B to this report:
Consolidated financial statement schedules, other than those listed above, are omitted because of the absence of the conditions under which they are required or because the required information is included in the consolidated financial statements or notes thereto.
(a)-3 Exhibits. The following exhibits are filed herewith unless otherwise indicated:
Long-term debt is described in Notes 3 and 4 of the Notes to Consolidated Financial Statements included in Appendix A to this report. The Corporation agrees to provide the Commission, upon request, copies of instruments defining the rights of holders of such long-term debt, which instruments are not filed herewith pursuant to Paragraph (b)(4)(iii)(A) of Item 601 of Regulation S-K. ___________________
*Incorporated herein by reference and made a part hereof.
(b) Reports on Form 8-K
Current Report on Form 8-K dated October 18, 1993, was filed on October 22, 1993 (judgment entered in Exchange Offer suit).
Current Report on Form 8-K dated November 17, 1993, was filed on November 29, 1993 (ENSERCH signs agreement to sell principal operating assets of Ebasco Services Incorporated to Raytheon Engineers & Constructors).
Current Report on Form 8-K dated December 22, 1993, was filed on January 6, 1994 (ENSERCH closes Ebasco sale; sells 49% interest in Dorsch Consult).
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENSERCH Corporation
March 30, 1994 By: /s/ D. W. Biegler D. W. Biegler, Chairman and President, Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant in the capacities and on the date indicated.
Signature and Title Date
D. W. Biegler, Chairman and President, Chief Executive Officer, and Director; William B. Boyd, Director; B. A. Bridgewater, Jr., Director; Lawrence E. Fouraker, Director; Preston M. Geren, Jr., Director; Marvin J. Girouard, Director; March 30, 1994 Joseph M. Haggar, Jr., Director; W. C. McCord, Director; Diana S. Natalicio, Director; W. Ray Wallace, Director; S. R. Singer, Senior Vice President, Finance and Corporate Development, Chief Financial Officer; Jerry W. Pinkerton, Vice President and Controller, Chief Accounting Officer
By: /s/ D. W. Biegler D. W. Biegler As Attorney-in-Fact
APPENDIX A
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
INDEX TO FINANCIAL INFORMATION
DECEMBER 31, 1993
Page ----
Selected Financial Data............................... A-2
Financial Review...................................... A-4
Independent Auditors' Report.......................... A-18
Management Report on Responsibility for Financial Reporting................................. A-19
Financial Statements: Statements of Consolidated Income................... A-21
Statements of Consolidated Cash Flows............... A-22
Consolidated Balance Sheets......................... A-23
Statements of Consolidated Common Shareholders' Equity.............................. A-24
Notes to Consolidated Financial Statements............ A-25
Summary of Business Segments.......................... A-54
Common Stock Market Prices and Dividend Information... A-55
A-3
ENSERCH CORPORATION FINANCIAL REVIEW
RESULTS OF OPERATIONS
Earnings applicable to common stock for the year 1993 were $47 million ($.70 per share), compared with a loss applicable to common stock for 1992 of $41 million ($.62 per share) and 1991 earnings of $5 million ($.07 per share).
Results from continuing operations, after provision for preferred dividends, were a loss of $27 million ($.41 per share) in 1993, a loss of $9 million ($.14 per share) in 1992 and income of $23 million ($.36 per share) in 1991. Results from continuing operations for 1993 were impacted by the following items:
- An $8 million after-tax ($12 million pretax) charge for efficiency enhancements and severance expenses accrued for staff reductions in Natural Gas Transmission and Distribution operations;
- An $11 million charge to deferred federal income taxes resulting from the 1% increase in the statutory federal income-tax rate on corpora- tions;
- A $9 million after-tax ($13 million pretax) write-off of non-U.S. gas and oil assets; and
- A $27 million after-tax ($41 million pretax) charge as a result of an adverse judgment in litigation that required additional payment in a limited partnership exchange offer made in 1989 beyond the amount that the Corporation believes represented fair value. In addition, there was a $4 million after-tax ($6 million pretax) charge for additional interest awarded.
The 1992 results from continuing operations included an $11 million after-tax ($17 million pretax) write-off of abandoned offshore facilities and a $10 million after-tax ($15 million pretax) provision for litigation. Results from continuing operations in 1991 included after-tax gains totaling $10 mil- lion from the sale of properties.
Revenues for 1993 were $1.9 billion, compared with $1.7 billion in both 1992 and 1991. Operating income for 1993 was $73 million, compared with $112 million in 1992 and $137 million in 1991. Excluding the effects on operating income of the unusual charges mentioned above, 1993 operating income was $140 million versus $129 million for 1992 and $137 million for 1991. Variations in operating income by business segment are discussed below.
The 1993 results include income from discontinued operations of $74 million ($1.11 per share), representing after-tax gains totaling $68 mil- lion ($1.03 per share) from the sale of the principal operating assets of Ebasco Services Incorporated and the Corporation's 49% interest in Dorsch Consult, and income from operations before the sale of $6 million. There was a $16 million ($.25 per share) loss from discontinued operations in 1992, primarily related to the sale of Humphreys and Glasgow International and provisions for real estate formerly utilized by discontinued operations. In 1991, there was a loss of $19 million ($.29 per share). With these sales, the Corporation has concluded its involvement in the engineering and construction business and now reflects these results as discontinued operations.
A-4
Results for the year 1992 also included a $15 million ($.23 per share) after-tax extraordinary loss from the extinguishment of high interest-rate debt and the termination of an interest-rate hedge.
NATURAL GAS TRANSMISSION AND DISTRIBUTION
The six-year statistics for Transmission and Distribution operations (See table of Operating Data) reflect the effects of variable weather patterns and increasing significance of nonregulated markets.
Operating income for Transmission and Distribution operations for 1993 was $113 million before the $12 million charge relating to the ongoing reengineering of this business ($101 million after the charge), compared with $102 million for 1992 and $111 million for 1991. Normal winter weather, combined with aggressive marketing of services and increased capacity, contributed to higher sales and transportation volumes in 1993.
Volumes handled during the year were 645 billion cubic feet (Bcf), a 22% increase from both 1992 and 1991. Gas throughput on Lone Star's pipeline system reached 554 Bcf in 1993, its highest level since 1981. The volume of gas sold by Lone Star Gas Company and Enserch Gas Company (EGC) in 1993 totaled 414 Bcf, 18% above the 1992 level and 14% greater than 1991. Sales by EGC accounted for 59% of total gas sales volumes in 1993 versus 53% in 1992 and 51% in 1991.
Residential and commercial (R&C) sales volumes were 139 Bcf in 1993, up 16% from the 1992 volumes of 121 Bcf and 8% higher than in 1991, primarily due to colder winter weather. Heating degree days for 1993 rose 27% over the prior year and were slightly above normal for the first year since 1989. Industrial and electric-generation sales volumes of 138 Bcf were 6% greater than in 1992 but 15% less than 1991. Volumes sold to pipelines and others in 1993 totaled 136 Bcf, a 37% improvement from the 1992 level of 99 Bcf, which was improved 40% from the 1991 level of 71 Bcf.
The overall gas sales margin (revenue less cost of gas purchased and off-system transportation expense) for 1993 improved 7% from the prior year. The overall gross margin per thousand cubic feet (Mcf) on Lone Star's sales was $2.09 in 1993, $2.06 in 1992 and $1.96 in 1991. Lone Star has an ongoing rate program to monitor returns from cities and towns served by its distribution system, as well as the transmission system that supplies them. In the aggregate, rate increases provided $1.9 million in annual base-rate relief in 1993. The gross margin per Mcf on gas sold by EGC was $.11 in 1993, down from $.13 in both 1992 and 1991.
The total gas transportation volume in 1993 was 371 Bcf, a 21% improvement from 1992 volumes of 307 Bcf, which were slightly above the 1991 level. The gas transportation rate per Mcf averaged $.14 in 1993, compared with $.15 in 1992 and $.16 in 1991. The margins on incremental volumes generally are at lower rates and thereby reduce the average margin.
Lone Star's gas purchase contracts are discussed below.
A-5
NATURAL GAS AND OIL EXPLORATION AND PRODUCTION
Operating income for Exploration and Production operations closely follows fluctuations in product prices and volumes that are shown in the table of Operating Data.
Before the previously noted litigation charge and write-offs of non-U.S. gas and oil properties, operating income for Exploration and Production operations was $17 million for 1993, compared with $10 million for 1992 and $11 million for 1991. This improvement resulted from significantly increased natural-gas prices and higher sales volumes.
Revenues for Exploration and Production operations for 1993 of $190 mil- lion were 11% higher than 1992 and 3% above 1991. In 1993, natural-gas revenues increased 23% to $146 million, with the average natural-gas price per Mcf of $2.09 up 15% from the price in 1992 of $1.82. Natural-gas sales volumes totaled 70 Bcf, a 7% increase from the year-ago period and virtually the same as 1991. The increase in volumes for 1993 was principally due to accelerated natural-gas development drilling in East Texas and offshore production from Mississippi Canyon Block 441 in the Gulf of Mexico, which went on stream in the second quarter of 1993. Oil revenues declined $8 million to $37 million in 1993 due to a 9% production decline and a 10% decrease in the average sales price to $17.24 per barrel. The lower volumes in 1993 were primarily the result of declining production from several North Texas reservoirs.
Spot-market sales, which include monthly and short-term industrial sales, covered about 70% of 1993 gas sales, compared with 80% in 1992 and 75% in 1991. During 1994, the percentage of gas sold in the spot market is expected to be in the range of 75% to 85%.
Drilling activity during the first half of 1993 increased to levels last experienced by the Corporation in 1987, primarily because of development work in East Texas. ENSERCH participated in more than 100 wells (79 net) in 1993, with the majority completed as gas producers in East Texas. Thirty-nine wells were in progress at yearend. Recompletions and production optimization measures played a major role in the 1993 production enhancement program.
Results for 1994 will include a full year of production from the Mississippi Canyon Block 441 deep-water project in the Gulf of Mexico, which began production in early 1993. The field is producing some 70 million cubic feet (MMcf) of natural gas and more than 500 barrels of condensate per day from six wells. ENSERCH is the operator, with a 37.5% working interest in the project.
The Garden Banks Block 388 oil development project, also in the Gulf, remains on schedule and on budget, with initial production anticipated by mid- 1995. The final major contract for the conversion of a semi-submersible drilling rig to a floating production facility was finalized in early 1994. Installation of the offshore facilities, consisting of the subsea template, gathering and sales pipelines and shallow-water operations, will begin by mid- year. Three previously drilled oil wells will be connected to the subsea template. Initial daily production from three predrilled wells is expected to total 15 thousand barrels (MBbls) of oil and 12 to 15 MMcf of gas by late 1995, with peak daily production from the Garden Banks project anticipated in late 1996 at 40 MBbls of oil and 60 MMcf of gas. Gross proven reserves are presently estimated to be equivalent to 28 million barrels (MMBbls) of oil by DeGolyer and MacNaughton, an independent consulting firm. ENSERCH is 100% interest owner and operator of the Garden Banks project.
A-6
ENSERCH has budgeted $116 million for exploration and production activities in 1994, compared with expenditures of $120 million in 1993. In 1992, ENSERCH sharply curtailed its capital spending to $66 million in response to poor prices for both natural gas and oil. If the early 1994 weakness in oil prices persists throughout 1994, appropriate cutbacks in spending may be undertaken. More than half of ENSERCH's 1994 capital expenditures is earmarked for domestic onshore drilling.
The Corporation follows the full-cost method of accounting for the acquisition, exploration and development costs of gas and oil properties. The overall rate of amortization for U.S. properties was $.98 per million British thermal units produced for both 1993 and 1992, compared with $.90 in 1991. Costs of additional offshore projects and increased development costs associated with older East Texas fields largely account for the increase from 1991.
During 1993, the Corporation wrote off some $13 million representing all remaining capitalized costs associated with its non-U.S. gas and oil proper- ties.
ENSERCH's natural-gas reserves at January 1, 1994, were 1.09 trillion cubic feet (Tcf), compared with 1.10 Tcf the year earlier, as estimated by DeGolyer and MacNaughton. Oil and condensate reserves, including natural gas liquids attributable to leasehold interests, were 39 MMBbls, virtually the same as the year-ago level.
At January 1, 1994, estimated future pretax net cash flows from ENSERCH's owned proved gas and oil reserves, based on average prices and contracts in effect in December 1993, were $2.0 billion, about the same as the year earlier. The net present value of such cash flows, discounted at the Securities and Exchange Commission (SEC)-prescribed 10%, was $1.1 billion, virtually the same as the prior year. These discounted cash flow amounts are the basis for the SEC-prescribed cost-center ceiling for the full-cost accounting method. The margin between the cost-center ceiling and the unamortized capitalized costs of U.S. gas and oil properties was approximately $75 million at December 31, 1993. Product prices are subject to seasonal and other fluctuations. A significant decline in prices from yearend 1993 or other factors, without mitigating circumstances, could cause a future write-down of capitalized costs and a noncash charge against earnings.
In November 1993, an adverse judgment in litigation required additional payment for a limited partnership exchange offer made in 1989. The award included $41 million for the units and $21 million of prejudgment and post-judgment interest ($15 million was charged against an existing reserve for litigation). The $41 million additional payment was charged against income in the fourth quarter. The Corporation had believed that any additional consideration for the units should be capitalized; however, after further review at the time of the judgment, the expensing of the final court-ordered payment was prudent and necessary because it did not bring additional value.
NATURAL GAS LIQUIDS PROCESSING
Operating income for Natural Gas Liquids (NGL) Processing operations for 1993 was $5 million, compared with $13 million for 1992 and $21 million for 1991. Higher prices for natural gas, the feedstock used in NGL production, and continued lower NGL sales prices caused margins to decline. The average NGL
A-7
sales price per barrel in 1993 of $12.34 was down 8% from 1992 and was 11% below 1991, while NGL sales volumes of 6.0 MMBbls were virtually the same as 1992 and 1991.
POWER AND OTHER
ENSERCH's power and other activities, comprised of Enserch Development Corporation, Lone Star Energy Company and Enserch Environmental Corporation, had 1993 operating income of $15 million, compared with $20 million for 1992 and $9 million for 1991. Enserch Development Corporation's 1993 operating income was $5.9 million, compared with $9.8 million for 1992 and $2.1 million for 1991. Current year results included a $15 million pretax gain from the sale of a position in a power project that had been scheduled for development, while 1992 and 1991 results included development fees from cogeneration projects of $15 million and $5 million, respectively. Lone Star Energy Company's 1993 operating income was $3.9 million, some 8% higher than 1992 but slightly below 1991.
Enserch Environmental Corporation, which was retained when Ebasco's principal operating assets were sold in December 1993, had operating income for 1993 of $5.7 million, compared with $6.8 million for 1992 and $2.9 million for 1991. Backlog was $600 million at December 31, 1993.
OTHER INCOME AND EXPENSE ITEMS
Other income/(expense) for 1993 includes pretax gains totaling $7 million from the sale of a gas storage facility and the Corporation's minority investment in an insurance entity. Partially offsetting was a $5.6 million provision for the interest awarded in the judgment described earlier, while the 1992 amount principally reflected a $15 million provision for litigation. The sale of Oklahoma utility properties and non-U.S. gas and oil properties in 1991 resulted in pretax gains of $15 million. Details of other income/(expense) are included in Note 12.
Interest expense for 1993 was $80 million, including $8 million not related to borrowings, compared with $97 million for 1992 and $96 million for 1991. The reduction is the result of ongoing restructuring of long-term debt at lower rates and lower short-term interest rates. Interest capitalized in 1993 was $4.5 million, compared with $5.4 million in 1992 and $7.5 million in 1991.
Income-tax expense for 1993 includes an $11 million charge to deferred federal income taxes resulting from the 1% increase in the statutory federal income-tax rate on corporations. Excluding this charge, the income-tax benefit on the loss from continuing operations equaled 46% of the pretax loss. At December 31, 1993, the Corporation had domestic net operating-loss carryfor- wards and suspended losses of $161 million and tax-credit carryforwards of $37 million. The tax benefits of these carryforwards and suspended losses, which total some $93 million, are available to reduce future income-tax payments. Note 9 provides additional information on income taxes.
A-8
LIQUIDITY AND FINANCIAL RESOURCES
Net cash flows from operating activities of continuing operations for 1993 were $192 million, compared with $211 million in 1992 and $184 million in 1991. Net cash flows from continuing operations, before cash flow effects of gas- purchase contract settlements and changes in current operating assets and liabilities, were $155 million versus $150 million in 1992 and $184 million in 1991. Cash flows associated with gas-purchase contract settlements improved substantially over the three-year period. Recoveries, net of payments, provided $51 million in 1993 and $26 million in 1992, while there were net payments of $7 million in 1991. (These payments are discussed in detail under "Gas-Purchase Contracts.") In 1993, there was a cash requirement of $14 mil- lion for the increase in current operating assets and liabilities, compared with decreases that provided $36 million in 1992 and $7 million in 1991.
Cash of $118 million was provided by investing activities in 1993, compared with cash requirements of $105 million and $127 million in 1992 and 1991, respectively. These amounts include cash provided by discontinued operations of $320 million in 1993, $14 million in 1992 and $37 million in 1991. Cash provided by discontinued operations in 1993 includes net proceeds of $198 mil- lion from the sale of the principal operating assets of Ebasco and the 49% interest in Dorsch and proceeds of $100 million from the limited recourse sale of retained Ebasco receivables, while 1992 includes net proceeds of $41 million from the sale of Humphreys and Glasgow International.
There was a net cash requirement for capital spending and other investing activities of $203 million in 1993, compared with $119 million in 1992 and $164 million in 1991. The increase in 1993 is primarily due to a higher level of capital spending for natural-gas and oil exploration and development programs.
Property, plant and equipment additions by business segments for the past three years and planned for 1994 are as follows:
The planned expenditures for 1994 are expected to be funded from internal cash flow and external financings as required.
In 1993, net cash flows from operating and investing activities totaled $309 million. In addition, $11 million was provided by the sale of common stock to employee stock plans and there was a $29 million net decrease in cash and cash equivalents. After the payment of cash dividends of $26 million, net cash of $324 million was available to reduce outstanding borrowings, with long- term debt reduced $200 million and commercial paper and other short-term borrowings decreased $121 million. In 1992, there was $51 million available to reduce borrowings or for temporary investment.
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In June 1993, the Corporation borrowed $200 million under its interim-term (13-month) bank lines, with the interest rate based on the London Interbank Offering Rate plus a fixed percentage. The proceeds were used in refinancing maturing debt consisting of $76 million net due on a Swiss Franc Note that had an effective interest rate of 8.9% and $100 million of 11 5/8% Notes that matured in May 1993, with the remainder used to reduce commercial paper borrowings. The $200 million interim-term borrowing was repaid in December 1993 in connection with the sale of Ebasco assets and Dorsch.
In February 1993, the Corporation announced a reduction in the quarterly cash dividend on common stock to $.05 per share from $.20 per share, resulting in a change in annual cash requirements of about $40 million.
In 1992, Enserch Exploration Partners Ltd. (EP) entered into operating lease arrangements to provide financing for its portion of the offshore platforms and related facilities for the Mississippi Canyon Block 441 (37.5% owned) and Garden Banks Block 388 (100% owned) projects. A total of $34 mil- lion was required for the Mississippi Canyon Block 441 project, which was com- pleted in early 1993. The lease arrangement to fund the construction costs for the Garden Banks facility is estimated to total $235 million when completed in 1995. (See Note 6.)
Total capitalization was $1.6 billion at December 31, 1993, a decrease of $184 million from yearend 1992. The decrease reflects a $226 million reduction in senior long-term debt and a $42 million increase in common shareholders' equity. Common shareholders' equity, as a percentage of total capitalization, increased to 41.7% at December 31, 1993 from 34.8% at the end of 1992. At December 31, 1993, $350 million of shareholders' equity was free of any restrictions for payment of dividends or acquisition of capital stock.
The current ratio at December 31, 1993 was .72, compared with 1.0 at yearend 1992 and .95 at yearend 1991. The decline in 1993 was partially attributable to the sale of $34 million of Ebasco's working capital and the classification of a $62 million payment relating to the judgment described above as a current liability. This payment was made in January 1994.
ENSERCH uses the commercial paper market and commercial banking facilities for short-term needs. Commercial paper and other short-term borrowings, net of temporary cash investments, totaled $32 million at December 31, 1993, compared with $121 million at yearend 1992 and $156 million at the end of 1991. Bank lines for either short- or interim-term borrowings totaled $650 million at yearend 1993. Presently, all of these lines are unused.
In February 1994, the Corporation issued $150 million of 10-year term notes at a coupon rate of 6.375%. The proceeds were used in March to fully redeem the $75 million of Series D Adjustable Rate Preferred Stock at par value and to retire all outstanding sinking fund debentures, which had a combined principal balance of $74 million. The premium for early retirement was $1.4 million. The preferred stock had a minimum dividend rate of 7.5%, equivalent to 11.54% on a tax-adjusted basis. The sinking fund debentures had a weighted average interest rate of 8.5%.
In March 1994 the Corporation filed a shelf registration statement with the Securities and Exchange Commission for the sale from time to time of up to $450 million in the aggregate of securities, which can be its senior or subordinated debt securities, or its equity securities or the securities of a special purpose subsidiary. Proceeds received from any sale will be used to repay obligations of the Corporation, unless otherwise set
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forth in a prospectus supplement. The type and terms of any security to be offered will be determined at the time of each offering.
Even though inflation has abated considerably from the levels of the early 1980s, and was only about 2.5% in 1993, it continues to have some influence on the Corporation's operations. Most notable is that allowances for depreciation and amortization based on the historical cost of fixed assets may be insuffi- cient to cover the replacement of some long-lived fixed assets.
GAS-PURCHASE CONTRACTS
Lone Star is a fully integrated intrastate natural-gas utility from well- head to end use and owns its own gathering, transmission and distribution facilities. Lone Star buys gas under long-term, intrastate contracts in order to assure reliable supply to its customers. To obtain this relia- bility, Lone Star entered into many gas-purchase contracts that provide for minimum-purchase ("take-or-pay") obligations to gas sellers. In the past, Lone Star was unable to take delivery of all minimum gas volumes tendered by suppliers under these contracts. This situation principally resulted from general economic conditions, the restructuring of regulations in the natural- gas industry, customers having the availability of lower-priced natural gas from competitive sources, certain capacity limitations, Railroad Commission of Texas (RRC) rules regulating takes of gas, and warmer-than-normal winter temperatures that reduced sales demand. During past years, numerous claims have been made by gas suppliers asserting Lone Star's failure to meet its minimum purchase obligations, and other claims such as disputing prices paid for gas purchased under contracts. Lone Star has substantially reduced the potential assertions resulting from such claims through negotiations and contractual and statutory provisions. Producer settlement obligations in Lone Star's contracts have been reduced substantially in recent years. Claims asserted for events during 1992 and anticipated claims for 1993 are negligible.
Take-or-pay contract provisions generally allow for payments to be recouped by taking gas in future periods without payment in accordance with the terms of the contract. When the gas is taken, the previous advance payment becomes a part of gas cost that is charged to customers. Alternatively, Lone Star, in many cases, has negotiated "nonrecoupable" payments that generally are much less in amount than comparable recoupable payments but provide no rights to recoup gas in future periods. Nonrecoupable settlement payments are included in gas costs recovered through customer billings as described below.
Obligations to purchase gas in the future are estimated to be as follows (in millions): 1994, $150; 1995, $120; 1996, $95; 1997, $90; 1998, $80; and thereafter, not more than $70, with the final contracts expiring in 2003. Based on Lone Star's estimated gas demand of about 170 Bcf annually, which assumes normal weather conditions, it is expected that normal gas purchases will substantially satisfy purchase obligations for the year 1994 and thereafter; however, any payments that may be required to be made for obligations not met are recoupable under contract provisions or are recoverable from customers as gas purchase costs. Therefore, a provision for loss is not required.
Lone Star's regulated rates for residential and commercial customers and its contractual rates for industrial and electric-generation customers include gas costs recorded each month (including out-of-period costs), an allowance for other costs and expenses, and a return on investment. Its residential and commercial distribution rates are set at the cost of service within each city
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by the local municipal governments. The RRC has appellate jurisdiction over the city distribution rates and original jurisdiction over the rates outside city limits. The RRC regulates the intracompany city gate rate or charge for the transmission service outside city limits that is included as a cost for distribution service to residential and commercial customers within city limits. The RRC provides a gas cost recovery mechanism in the city gate rate that is designed to match gas costs with revenues on a timely basis to prevent margin erosion or excesses by allowing both positive and negative gas cost changes to flow through to the customers. The Texas city gate gas cost recovery mechanism limits the amount of out-of-period gas costs, of which producer settlements are a part, that can be charged to customers in a particular month. The existing recovery mechanism does, however, allow for ultimate recovery of gas costs, including such out-of-period payments. Similarly, contractual provisions provide for recovery of the allocated share of these costs from industrial and electric-generation customers. Therefore, a provision for loss is not required.
At December 31, 1993, the approximate amount of unsettled gas-purchase contract claims asserted by suppliers, as well as estimated claims that are probable of assertion, was $80 million. Of this total, approximately $70 million relates to a claim filed in 1993 primarily related to asserted obligations for purchases for early through mid-1980s. (See Note 6.) In some cases, the claimed amount includes other asserted damages in addition to the take-or-pay claim. The possibility exists that additional gas-purchase contract claims might be asserted by other claimants. Lone Star expects to resolve the foregoing claims at substantially less than the claimed amounts. Due to the different forms of settlement, as discussed above, the ultimate liability to a supplier, if any, generally cannot be reasonably estimated prior to settlement; however, a liability is recorded in the financial statements for those claims when a settlement is probable and an amount can be reasonably estimated. A provision for loss is not required since settlement payments are recoupable under contracts or recoverable through billings to customers, as previously discussed.
At December 31, 1993, there was an unrecovered balance of gas-purchase contract settlements of $111 million, down from $173 million at December 31, 1992. The balances include take-or-pay settlements, amounts relating to pricing and amounts related to the settlement of other contractual matters. Of the $111 million, $63 million represented prepayments for gas expected to be recouped under contracts covering future gas purchases. The remaining $48 million represented amounts expected to be recovered from customers under the existing gas cost recovery provisions. Lone Star expects to recoup or recover the remaining balances of gas settlement payments made to date, as well as future payments to be made in settlement of remaining claims. The period of recovery is dependent on the overall demand for gas by Lone Star's customers, which is influenced by weather conditions.
A summary of transactions related to unrecovered gas settlement payments during the two years ended December 31, 1993, is as follows:
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FOURTH-QUARTER RESULTS
Earnings applicable to common stock for the fourth quarter of 1993 were $36 million ($.53 per share), compared with a loss of $33 million ($.49 per share) for the fourth quarter of 1992. Fourth quarter income from discontinued operations was $70 million ($1.04 per share), compared with a loss of $16 million ($.25 per share) for the same period a year earlier. Results for the fourth quarter of 1992 also included a $10 million after-tax extraordinary loss from debt extinguishment. There was a loss from continuing operations after provision for preferred dividends for the fourth quarter of 1993 of $34 million ($.51 per share) versus a loss of $6 million ($.08 per share) for the year-ago period. Results for the 1993 and 1992 fourth quarters included all of the unusual items noted for the full year, except for after-tax charges of $10.8 million for the increase in the statutory federal income tax rate, $3.6 million for litigation and $2.0 million for write-offs of non-U.S. gas and oil properties that occurred earlier in 1993. Before unusual items, operating income for the 1993 fourth quarter was $28 million, compared with $52 million for the year-earlier quarter. In addition to the unusual items noted, fourth quarter 1993 operating income was reduced by some $10 million of other year-end provisions. Results for the fourth quarter of 1992 were enhanced by develop- ment fees of $15 million from a cogeneration project. Fundamental results were about the same in both quarters.
NEW ACCOUNTING STANDARDS
SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other Than Pensions," which mandates the accounting for medical and life insurance and other nonpension benefits provided to retired employees, was adopted by the Corporation effective January 1, 1993. (See Note 8.)
SFAS No. 112, "Employer's Accounting for Postemployment Benefits," will become effective for the Corporation in 1994. This standard covers the accounting for estimated costs of benefits provided to former or inactive employees before their retirement. The Corporation currently accrues costs of benefits to former or inactive employees by varying methods. The new standard is not expected to have a significant effect on results of operations or financial condition.
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INDEPENDENT AUDITORS' REPORT
To the Shareholders and Board of Directors of ENSERCH Corporation:
We have audited the accompanying consolidated balance sheets of ENSERCH Corporation and subsidiary companies as of December 31, 1993 and 1992, and the related statements of consolidated income, cash flows and common shareholders' equity for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits. We have previously audited the consolidated balance sheets of ENSERCH Corporation and subsidiary companies as of December 31, 1991, 1990, 1989 and 1988 and the related statements of consolidated income, cash flows and common shareholders' equity for the years ended December 31, 1990, 1989, and 1988 (not presented herewith), and have expressed unqualified opinions thereon.
We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of ENSERCH Corporation and subsidiary companies at December 31, 1993 and 1992, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. Also, in our opinion, the information set forth in the accompanying table of selected financial data for the years 1988 through 1993 is fairly stated in all material respects in relation to the consolidated financial statements from which such information has been derived.
DELOITTE & TOUCHE
Dallas, Texas February 7, 1994
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MANAGEMENT REPORT ON RESPONSIBILITY FOR FINANCIAL REPORTING
The management of ENSERCH Corporation is responsible for the preparation, presentation and integrity of the financial statements contained in this report. These statements have been prepared in conformity with accounting principles generally accepted in the United States and include amounts that represent management's best estimates and judgments. Management has estab- lished practices and procedures designed to support the reliability of the estimates and minimize the possibility of a material misstatement. Management also is responsible for the accuracy of the other information presented in the annual report and for its consistency with the financial statements.
Management has established and maintains internal accounting controls that provide reasonable assurance as to the integrity and reliability of the financial statements, the protection of assets from unauthorized use or disposition, and the prevention and detection of fraudulent financial reporting. The system of internal control provides for appropriate division of responsibility and is documented by written policies and procedures that are communicated to employees with significant roles in the financial reporting process and updated as necessary. Management continually monitors compliance with the system of internal accounting controls. The Corporation maintains a strong internal audit function that evaluates the adequacy of the system of internal accounting controls. As part of the annual audit of the financial statements, Deloitte & Touche also performs a study and evaluation of the system of internal accounting controls as necessary to determine the nature, timing, and extent of their auditing procedures. The Board of Directors maintains an Audit Committee composed of Directors who are not employees. The Audit Committee meets periodically with management, the independent auditors and the internal auditors to discuss significant accounting, auditing, internal accounting control and financial reporting matters. A procedure exists whereby either the independent or the internal auditors through the independent auditors may request, directly to the Audit Committee, a meeting with the Committee.
Management has given proper consideration to the independent and internal auditors' recommendations concerning the system of internal accounting controls and has taken corrective action believed appropriate in the circumstances. Management further believes that, as of December 31, 1993, the overall system of internal accounting controls is sufficient to accomplish the objectives discussed herein.
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Management recognizes its responsibility for establishing and maintaining a strong ethical climate so that the Corporation's affairs are conducted according to the highest standards as defined in the Corporation's Statement of Policies. The Statement of Policies is publicized throughout the Corpora- tion and addresses, among other issues, open communication within the Corporation; the disclosure of potential conflicts of interest; compliance with the laws, including those relating to financial disclosure; and the confidenti- ality of proprietary information.
s/D. W. Biegler - ------------------------------ D. W. Biegler Chairman and President, Chief Executive Officer
s/S. R. Singer - ------------------------------ S. R. Singer Senior Vice President, Finance and Corporate Development, Chief Financial Officer
s/J. W. Pinkerton - ------------------------------ J. W. Pinkerton Vice President and Controller, Chief Accounting Officer
February 7, 1994
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS ENSERCH Corporation and Subsidiary Companies
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
All dollar amounts, except per share amounts, in the notes to the consoli- dated financial statements are stated in thousands unless otherwise indicated.
Basis of Financial Statements - The consolidated financial statements include all subsidiaries during the period of ownership and control. The equity method of accounting is used for investments in affiliates in which ENSERCH Corporation (ENSERCH or the Corporation) does not have voting control.
Lone Star Gas Company (Lone Star), the gas utility division of ENSERCH Corporation and principal company in the natural gas transmission and distribu- tion business operations, is subject to the accounting requirements prescribed by the National Association of Regulatory Utility Commissioners. Lone Star's rates are established by the Railroad Commission of Texas and by municipal governments.
The statements of consolidated income and cash flows previously reported for 1992 and 1991 have been restated to reflect the engineering and construction segment as a discontinued operation. Current year reported results reflect the realignment of the segments of business for financial reporting purposes. All prior year amounts have been reclassified to reflect the new alignments.
Revenue Recognition - Lone Star records revenues on the basis of cycle meter readings throughout the month and accrues revenues for gas delivered but not billed to customers from the meter reading dates to the end of the month.
The environmental business of the Corporation follows the generally accepted accounting practice of reporting revenues and income from long-term contracts on the percentage of completion basis using estimates of total contract revenue and costs at completion. These estimates are updated throughout the terms of the contracts and adjustments are made as appro- priate. All known or anticipated losses on these contracts are charged to earnings when identified.
Gas and Oil Properties - The full-cost method, as prescribed by the Securi- ties and Exchange Commission (SEC), is used whereby the costs of proved and unproved gas and oil properties, together with successful and unsuccessful exploration and development costs, are capitalized by cost centers on a country-by-country basis. The carrying value for each cost center is limited to the present value of estimated future net revenues of proved reserves, the cost of excluded properties and the lower of cost or market value of unproved properties being amortized. Dry-hole costs resulting from exploration activities are classified as evaluated costs and are included in the amortiza- tion base. Costs directly associated with the acquisition and evaluation of unproved properties are excluded from the amortization base until the related properties are evaluated. Such unproved properties are assessed periodically and a provision for impairment is made to the full-cost amortization base when appropriate. Sales of gas and oil properties are credited to capitalized costs unless the sale would have a significant impact on the amortization rate.
Gas Purchase Contracts - The Corporation has made accruals for payments to producers that may be required for settlement of gas purchase contract claims asserted or that are probable of assertion. Lone Star's rates billed to customers provide for the recovery of the actual cost of gas (including out-of- period costs such as gas purchase contract settlement costs). The Corporation
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continually evaluates its position relative to asserted and unasserted take-or- pay claims, above-market prices or future commitments. Based on this evaluation and its experience to date, management believes that the Corporation has not incurred losses for which reserves should be provided at December 31, 1993.
Depreciation and Amortization - Depreciation is provided principally by the straight-line method over the estimated service lives of the related assets. Amortization of evaluated gas and oil properties is computed on the unit-of- production method by cost center using estimated proved gas and oil reserves quantified on the basis of their equivalent energy content.
Lone Star's plants are depreciated over approximately 40 years; amortiza- tion of gas and oil properties was approximately 6.0% in 1993 and 5.7% in both 1992 and 1991.
Earnings Per Share of Common Stock - Earnings per share applicable to com- mon stock are based on the weighted average number of common shares, including common equivalent shares when dilutive, outstanding during the year. Common equivalent shares consist of those shares issuable upon the assumed conversion of the 10% Convertible Subordinated Debentures during the periods in which they were outstanding (which were not dilutive in 1992 and 1991) and exercise of stock options under the treasury stock method. The 6 3/8% Convertible Subordinated Debentures were not common stock equivalents. Fully diluted earnings per share are not presented since the assumed exercise of stock options and conversion of debentures would not be dilutive.
Gas Stored Underground - Gas stored underground is valued at average cost. The volume of gas that is available for sale within 24 months is classified as a current asset. The remainder is included in property, plant and equipment.
Fair Value of Financial Instruments - The Corporation has estimated the fair values of its financial instruments using available market information and other valuation methodologies in accordance with SFAS No. 107, "Disclosures About Fair Value of Financial Instruments". Accordingly, the estimates presented are not necessarily indicative of the amounts that the Corporation could realize in a current market exchange. Determinations of fair value are based on subjective data and significant judgment relating to timing of payments and collections and the amounts to be realized. Different market assumptions and/or estimation methodologies might have a material effect on the estimated fair value amounts.
The estimated fair value amounts for specific groups of financial instruments are presented within the footnotes applicable to such items. When available, values were based on market quotes from a securities exchange or a broker-dealer. When such quotes were not available, fair value estimates were made using a discounted cash flow approach based on the interest rates currently available for debt with similar terms and maturities.
The fair value of financial instruments for which estimated fair value amounts have not been specifically presented is estimated to approximate the related book value.
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2. LINES OF CREDIT AND BORROWINGS
The Corporation maintains domestic and foreign lines of credit that provide for short- and interim-term (13-month) borrowings and also support commercial paper borrowings in the U.S. and Europe. Foreign lines provide for borrowings in either U.S. dollars or in local foreign currencies, with maturities of not more than 13 months. At December 31, 1993, the aggregate lines of credit were:
The domestic lines are subject to renegotiation annually by May 1 and the foreign lines by November 1. All lines are on a fee basis and do not require compensating balances or restrictions on the use of cash. All lines provide for borrowing at the prime rate or at rates related to the London Interbank Offering Rate (LIBOR), the banks' certificate of deposit rate, or a money market based rate.
As of December 31, 1993, $15 million was used to support a letter of credit issued in connection with the appeal of a lawsuit. This letter of credit was canceled in January 1994, following satisfaction of amounts awarded under the lawsuit.
The Corporation has an interest-rate swap agreement, expiring in 1995, whereby the Corporation pays interest at the rate of 12.26% per annum on a notional amount of $100 million and receives interest at a floating rate based on LIBOR. Through November 1992, the notional amount of the swap was matched to variable interest-rate debt, including commercial paper, and was accounted for as an interest-rate hedge. In December 1992, the Corporation repaid all variable rate debt, and the swap arrangement could no longer be accounted for as an interest-rate hedge. A charge of $10.4 million (net of income-tax benefit of $5.4 million) was recorded for the estimated cost to terminate the hedge. (See Notes 3 and 4 for other debt extinguishments.)
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3. SENIOR LONG-TERM DEBT
Senior long-term debt as of December 31 is summarized below:
In February 1994, the Corporation issued $150 million of 6 3/8% Notes due 2004 in a public offering. Part of the net proceeds of this issue will be used in March 1994 for early redemption, including call premiums of $1.4 million, of all the $73.7 million principal amount of the sinking fund debentures outstanding at December 31, 1993. The remainder of the net proceeds will be used to redeem in March 1994, all of the $75 million Adjustable Rate Preferred Stock, Series D. (See Note 5).
In June 1993, the Corporation borrowed $200 million under its interim-term (13-month) bank lines, with the interest rate based on LIBOR plus a fixed percentage. The proceeds were used in refinancing maturing debt consisting of $76 million net due on a Swiss Franc Note that had an effective interest rate of 8.9% and $100 million of 11 5/8% Notes that matured in May 1993, with the remainder used to reduce commercial paper borrowings. The $200 million interim-term borrowing was repaid in December 1993 in connection with the sale of Ebasco assets and Dorsch.
In March 1992, the Corporation issued $100 million of 8% Notes due 1997 and $100 million of 8 7/8% Notes due 2001 and in August 1992, issued $150 million of 7% Notes due 1999, all in public offerings. The net proceeds were used for early redemption of higher interest-rate debt and convertible subordinated debentures (see Note 4). The Corporation recognized an extraordinary loss of
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$2.4 million (net of income taxes of $1.2 million) representing the call premiums, unamortized costs and other expenses associated with the early extinguishment.
The Corporation has a borrowing of $100 million from a foreign bank under a variable interest-rate note agreement due November 11, 1994, which provides for interest at a rate based on LIBOR plus a fixed percentage. The Corporation entered into a separate $100 million interest-rate swap that fixes interest payments at an average rate of 9.11% per annum.
The 9.06% Note provides for varying increasing levels of semi-annual principal payments, including an aggregate of $10.6 million for 1994, with the last payment due December 28, 1999.
Excluding the sinking fund debentures that have been called for redemption in March 1994, maturities of senior long-term debt for the following five years are: 1994, $139.9 million; 1995, $10.6 million; 1996, $13.4 million; 1997, $117.4 million; and 1998, $17.4 million. The 1994 amount includes $100 million for the 9.11% Note and $29.3 million for the 8.7% Note which will be refinanced on a long-term basis. The Corporation is not required to maintain compensating balances for any of its senior long-term debt.
The estimated fair value of the Corporation's senior long-term debt, including related interest-rate swaps, was $669 million at December 31, 1993, and $888 million at December 31, 1992. Such amounts do not include prepayment penalties which would be incurred upon the early extinguishment of certain debt issues.
4. CONVERTIBLE SUBORDINATED DEBENTURES
As of December 31, 1993 and 1992, $90,750 of 6 3/8% Convertible Subordinated Debentures Due 2002 were outstanding and convertible into shares of the Corporation's common stock at $26.88 per share (equal to 37.20 shares per $1 thousand principal amount). The Corporation, at its option, may redeem the 6 3/8% Debentures at 103.82% of the principal amount, plus accrued interest, through March 31, 1994, and at declining premiums there- after. The estimated fair value of the Corporation's convertible subordinated debentures was $92 million and $83 million at December 31, 1993 and 1992, respectively.
An extraordinary loss of $2.5 million (net of income-tax benefit of $1.3 million) was recorded for the call premiums and other expenses associated with the early extinguishment of the 10% Debentures in 1992.
5. SHAREHOLDERS' EQUITY
As of December 31, 1993, 8,368,968 shares of unissued common stock were reserved for issuance for stock plans and conversion of convertible subordinat- ed debentures. The Corporation is authorized to issue up to 2,000,000 shares of preferred stock and 2,000,000 shares of voting preference stock.
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Adjustable Rate Preferred Stock - Information concerning issued and out- standing shares of adjustable rate preferred stock at December 31, 1993 and 1992, is summarized below:
The Corporation has called for redemption at par in March 1994, all outstanding shares of the Series D preferred stock at $50 per share, plus accrued dividends. The Series E stock is deposited with a bank under a depositary agreement and is represented by 1,000,000 Depositary Shares. The Series E preferred stock is redeemable at the option of the Corporation at $103.00 per depositary share through April 30, 1994, thereafter at $100 per depositary share. Holders of the preferred stock are entitled to its stated value upon involuntary liquidation.
Dividend rates are determined quarterly, in advance, based on the "Applicable Rate" (such rate being the highest of the three-month U.S. Treasury bill rate, the U.S. Treasury ten-year constant maturity rate and the U.S. Treasury twenty-year constant maturity rate, as defined), as set forth below:
Shareholder Rights Plan - The outstanding shares of common stock include one voting preference stock contingent purchase right. The rights are exercisable only if a person or group acquires beneficial ownership of 20% or more, or commences a tender or exchange offer upon consummation of which such person or group would beneficially own 30% or more of the Corporation's com- mon stock. Under those conditions, each right could be exercised to purchase one two-hundredth share of a new series of voting preference stock at an exercise price of $60.
If any person becomes the beneficial owner of 30% or more of the Corpora- tion's common stock, or if a 20%-or-more shareholder engages in certain self- dealing transactions, or if in a merger transaction with the Corporation in which the Corporation is the surviving corporation and its common stock is not changed or converted, then each right not owned by such person or related parties will entitle its holder to purchase, at the right's then-current exercise price, shares of the Corporation's common stock (or, in certain circumstances as determined by the Board of Directors, other consideration) having a value of twice the right's exercise price. In addition, if the
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Corporation is involved in a merger or other business combination transaction with another person in which its common stock is changed or converted, or sells 50% or more of its assets or earning power to another person, each right will entitle its holder to purchase, at the right's then-current exercise price, common stock of such other person having a value of twice the right's exercise price.
The rights, which have no voting privileges, expire on May 5, 1996. The Corporation will generally be entitled to redeem the rights at $.05 per right at any time until the 15th day following public announcement that a 20% position has been acquired.
Management Incentive Program - As of December 31, 1993, the Corporation's Management Incentive Program consisted of two separate plans, the Unit Plan and the Non-Qualified Performance - Stock Option Plan. Key employees participating in the Unit Plan and Stock Option Plan totaled 62 and 8, respectively.
Under the Unit Plan, a maximum of 900,000 units outstanding at one time could be awarded from time to time to key employees by the Board of Directors. Benefits are payable in cash. At December 31, 1993 and 1992, 316,500 and 347,750 units, respectively, were outstanding. The Unit Plan was terminated by the Board of Directors in February 1994.
Under the Non-Qualified Performance - Stock Option Plan, options were granted to key employees to purchase shares of common stock at an exercise option price equal to par value ($4.45). Outstanding options at December 31, 1993, covered 13,277 shares.
1981 Stock Option Plan - Incentive Stock Options and Non-Qualified Stock Options were granted to key employees to purchase shares of the Corporation's common stock at an option price of not less than the fair market value of the common stock on the date of grant. This plan terminated on September 17, 1991, and no additional grants of stock options will be made. Options exercised in 1993 were at prices ranging from $16.375 to $21.00 per share. No options were exercised in 1992 and options exercised in 1991 were at a price of $17.00 per share. Option prices of grants outstanding at December 31, 1993, ranged from $16.375 to $25.625 per share. As of December 31, 1993, options to purchase 1,307,568 shares were outstanding under such plan. The number of key employees participating in the plan was 108 as of December 31, 1993.
1991 Stock Option Plan - Non-Qualified Stock Options may be granted to key employees for the purchase of not more than 2,000,000 shares of the Corpora- tion's common stock at an option price of not less than the fair market value of the common stock on the date of grant. In February 1994, the Board of Directors amended the 1991 Stock Option Plan, subject to shareholder approval, to include provisions for Restricted Stock. A total of 88,500 shares of performance-based Restricted Stock have been authorized for issuance to certain executive officers, subject to shareholder approval of the plan amendments. Performance criteria for lifting the restrictions is related to three-year total shareholder return compared to the weighted average of a peer group of companies. Options exercised in 1993 were at prices ranging from $12.50 to $19.00 per share. No options were exercised in 1992 or 1991. Option prices of grants outstanding at December 31, 1993, ranged from $12.50 to $19.00 per share. As of December 31, 1993, options to purchase 1,068,125 shares had been
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granted and were outstanding under such plan. The number of key employees participating in the plan was 122 as of December 31, 1993.
A summary of all stock option transactions follows:
Dividends - Restrictions on the payment of dividends on common stock (other than stock dividends) or acquisitions of the Corporation's capital stock are contained in the Corporation's several trust indentures and other agreements relating to senior long-term debt and in the Restated Articles of Incorporation of the Corporation. At December 31, 1993, the amount of dividends on common stock that could be paid under the most restrictive of these agreements exceeded the combined total of the retained earnings and paid in capital of the Corporation which was $350,099 and represented the effective limitation on common stock dividends. Following the redemption of all of the outstanding sinking fund debentures and the Adjustable Rate Preferred Stock, Series D, all of which have been called for redemption in March 1994, $342,139 of the Corporation's common shareholders' equity as of December 31, 1993, would have been free of such restrictions.
Dividends declared are summarized below:
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6. COMMITMENTS AND CONTINGENT LIABILITIES
Legal Proceedings - On June 25, 1993, a lawsuit was filed against the utility division of the Corporation in the 4th Judicial District Court of Rusk County, Texas. The plaintiff claims that the utility division failed to make certain production and minimum purchase payments under a gas- purchase contract. The plaintiff contends that it was fraudulently induced to enter into a gas-purchase contract which the utility division never intended to perform; that the plaintiff was fraudulently induced and coerced into releasing the utility division from its obligation to make minimum purchase payments; and that the contract was breached. The plaintiff seeks actual damages in excess of $100 million in addition to punitive damages equal to the savings produced from a gas price reduction program implemented by the utility in 1982 or equal to the value of gas supply in excess of its needs which were added pursuant to a program established in 1978 to increase gas supply.
A lawsuit was filed on February 24, 1987, in the 112th Judicial District of Sutton County, Texas, against subsidiaries and affiliates of the Corporation as well as its utility division. The plaintiffs have claimed that defendants failed to make certain production and minimum purchase payments under a gas- purchase contract. In this connection, the plaintiffs have alleged a conspiracy to violate purchase obligations, improper accounting of amounts due, fraud, misrepresentation, duress, failure to properly market gas and failure to act in good faith. In this case, plaintiffs seek actual damages in excess of $5 million and punitive damages in an amount equal to 0.5% of the consoli- dated gross revenues of the Corporation for the years 1982-1986 (approximately $85 million), interest, costs and attorneys' fees.
Management of the Corporation believes that the named defendants have meritorious defenses to the claims made in these and other actions. In the opinion of management, the Corporation will incur no liability from these and all other pending claims and suits that would be considered material for financial reporting purposes.
Long-term Contracts - The Corporation's environmental business enters into contracts which have provisions for significant financial penalties should certain terms of performance not be achieved. Such contract provisions have not and are not expected to have a material effect on the Corporation's operations.
Gas-Purchase Contracts - See "Financial Review - Gas-Purchase Contracts" for a discussion of commitments and contingencies relating to gas-purchase contracts.
Environmental Matters - The Corporation is subject to federal, state, and local environmental laws and regulations. These laws and regulations, which are constantly changing, regulate the discharge of materials into the environment. Environmental expenditures are expensed or capitalized depending on their future economic benefit. The level of future expenditures for environmental matters, including costs of obtaining operating permits, enhanced equipment monitoring and modifications under the Clean Air Act and cleanup obligations, cannot be fully ascertained at this time. However, it is management's opinion that such costs, when finally determined, will not have
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a material adverse effect on the consolidated financial position of the Corporation.
Lease Commitments - In May 1992, EP entered into an operating lease arrangement to provide financing for its portion of the offshore platform and related facilities for the 37 1/2% owned Mississippi Canyon Block 441 project. A total of $34 million was required for the Mississippi Canyon project, which was completed in early 1993. EP leased the facilities for an initial period through May 20, 1994, with an option to renew the lease, with the consent of the lessor, for up to 10 successive six-month periods. The lease has been renewed through November 20, 1994 and the Corporation expects to renew the lease for all renewal periods. EP has the option to purchase the facilities throughout the lease periods and as of December 31, 1993, has guaranteed an estimated residual value for the facilities of approximately $27 million should the lease not be renewed. Expenses incurred under the lease in 1993 were $2.1 million. The estimated future minimum net rentals for the Mississippi Canyon operating lease is $6.3 million for 1994.
In September 1992, EP entered into an operating lease arrangement to pro- vide financing for the offshore platform and related facilities of its 100% owned Garden Banks Block 388 project. The lessor will fund the construction cost of the facilities quarterly, up to a maximum of $235 million. As of December 31, 1993, a total of $60 million had been advanced to EP under the lease as agent for the lessor, $31 million of which was unexpended and reflected as a current liability. EP will lease the facilities for an initial period through March 31, 1997, with the option to renew the lease, with the consent of the lessor, for up to three successive two-year periods. EP, as agent for the lessors, will acquire, construct and operate the units of leased property and has guaranteed completion of construction of the facilities. EP has the option to purchase the facilities throughout the lease periods and has guaranteed an estimated residual value for the facil- ities of approximately $188 million, assuming the full lease amounts are advanced and expended, should the lease not be renewed. The estimated future minimum net rentals for the Garden Banks operating lease are as follows: $4.8 million for 1994; $9.1 million for 1995; $9.1 million for 1996; and $2.3 million for 1997. Lease payments are being deferred during the con- struction period and will be amortized when production begins.
In addition, the Corporation had a number of other noncancelable long-term operating leases at December 31, 1993, principally for office space and machinery and equipment. Future minimum net rentals under these noncancelable long-term operating leases aggregate $9.7 million for 1994; $8.9 million for 1995; $6.6 million for 1996; $6.5 million for 1997; $4.7 million for 1998; and $51.9 million thereafter. Future minimum rental income to be received for subleased office space is $9.3 million over the next five years. Rental expenses incurred under operating leases aggregated $14.3 million in 1993; $19.4 million in 1992; and $20.3 million in 1991. Rental income received for subleased office space was $3.4 million in 1993; $4.7 million in 1992; and $4.7 million in 1991.
Sales of Receivables - The Corporation has an agreement, which has been extended to 1996, with a commercial bank for the limited recourse sale of up to $100 million of Lone Star's receivables. Additional receivables are continually sold to replace those collected. The agreement the Corporation had
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for the limited recourse sale of up to $75 million of Ebasco accounts receivable was assumed by the purchaser as part of the sale of Ebasco. In December 1993, the Corporation entered into an agreement with a bank for the limited recourse sale of $100 million of receivables retained from the sale of Ebasco. This program is self-liquidating as new receivables will not be sold to replace those collected. As of December 31, 1993 and 1992, the uncollected balances of receivables sold under all existing agreements were $200 million and $175 million, respectively.
Contingent Support Agreement - In connection with the sale of its oil field services segment to Pool Energy Services Co. (PESC) in 1990, ENSERCH entered into a Contingent Support Agreement (Agreement) by which ENSERCH is providing PESC with limited financial support. PESC is obligated to repay ENSERCH for any amounts paid out under guarantees and contingent obligations, together with interest accrued thereon.
Support provided under the Agreement at January 1, 1994, consists of (i) the guarantee supporting the financing of PESC's Saudi Arabian affiliate, Pool Arabia, Ltd., totaling $3.1 million until July 31, 1996, and (ii) the $31 million guarantee outstanding in connection with a facility lease that is reduced periodically until fully released in March 2003. The stock of Pool International, Inc. has been pledged to ENSERCH as collateral for the Agreement. ENSERCH's lien on this collateral will remain so long as the guarantee of the Pool Arabia loan is outstanding.
Guarantees - In addition to guarantees mentioned above, the Corporation and/or its subsidiaries are the guarantor on various commitments and obliga- tions of others aggregating some $60 million at December 31, 1993. The Corporation is exposed to loss in the event of nonperformance by other parties. However, the Corporation does not anticipate nonperformance by the counterpart- ies.
Financial Instruments With Concentrations of Credit Risk - The transmission and distribution operations have trade receivables from a few large industrial customers in the north central area of Texas arising from the sale of natural gas. The environmental operations have several large receivables from projects that are subject to governmental funding approvals.
A change in economic conditions in a particular region or industry or change in local taxing authority may affect the ability of customers to meet their contractual obligations. The Corporation believes that its provision for possible losses on uncollectible accounts receivable of continuing operations is adequate for its credit loss exposure. At December 31, 1993 and 1992, the allowance for possible losses deducted from accounts receivable on the balance sheet was $4,105 and $6,590, respectively.
7. RETIREMENT PLANS
The Corporation has retirement plans covering substantially all its employees and employees of its subsidiaries. Upon the sale of the principal operating assets of Ebasco in 1993, the Corporation retained the obligations related to the Ebasco pension plan, including the obligation for benefits due Ebasco employees hired by the purchaser to date of sale and Ebasco employees
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terminated as a result of the sale. The employees hired by the purchaser are considered fully vested with full rights in the plan but frozen benefits. The terminated employees are due the benefits for which they were eligible at the date of their termination. Since no further benefits will accrue to these two groups of former Ebasco employees, the Corporation recognized a plan curtail- ment gain in 1993 of $6.9 million, which was included as a part of the gain on the sale. The following table sets forth the funded status of all plans as of September 30, 1993 (adjusted to reflect the effects of the sale of Ebasco) and 1992, and the amounts recognized in the consolidated balance sheet at December 31:
The accumulated benefit obligations represent the actuarial present value of benefits based on employees' history of service and compensation up to the measurement dates (September 30, 1993 and 1992). The projected benefit obliga- tions include additional assumptions about future compensation levels. The accumulated benefit obligations and the projected benefit obligations for 1993 and 1992 were determined using an assumed discount rate of 7.25% and 8.5%, respectively, and an assumed rate of compensation increase of 4% for both 1993 and 1992. The assumed long-term rate of return on plan assets was 9.5% for 1993 and 10% for 1992. The benefit obligations fluctuate with the assumed discount rate. When the rate declines, as it did in 1993 from the broad reduction in interest rates, the actuarial present value of benefit obligations increases. Some $68 million of the increase in the benefit obligations was primarily due to the reduction in the assumed discount rate in 1993 and is reflected in the unrecognized net actuarial gain (loss).
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The Corporation and its subsidiaries make annual contributions to the plans in such amounts as are necessary, on an actuarial basis, to satisfy minimum funding requirements of ERISA. Accrued pension cost represents the amount of pension cost recognized in excess of contributions paid.
Benefits vary by plan and generally are determined by the participant's years of credited service and average compensation during the highest five years prior to retirement or during each participant's career. Plan assets consist primarily of preferred and common stocks, corporate bonds and U.S. government securities.
The components of pension cost were as follows:
8. POSTRETIREMENT BENEFITS OTHER THAN PENSIONS
SFAS No. 106, "Employer's Accounting for Postretirement Benefits Other Than Pensions," became effective in January 1993 and mandates the accounting for medical and life insurance and other nonpension benefits provided to retired employees. The new standard requires accrual of these benefits over the working life of the employee, similar in manner to the requirement for pension benefits, rather than charging to expense on a cash basis.
The Corporation and its subsidiaries provide varying postretirement medical benefits to its retirees and employees based on their hiring date, years of service and retirement date. Except for Ebasco employees, retirees and their dependents who retired on or before December 31, 1990, and employees age 62 or older on that date who subsequently retire, are entitled to full medical coverage. Employees hired before July 1, 1989 who retire with a minimum of five years of service are provided with an annual subsidy, based on years of service, with which to purchase medical coverage. Employees hired after July 1, 1989, are not eligible for medical benefits when they retire.
Ebasco provided limited postretirement medical benefits to certain of its employees who retired prior to January 1, 1993. Upon the sale of the principal operating assets of Ebasco in 1993, the Corporation retained the obligations to retirees of Ebasco under this plan.
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The Corporation does not prefund its obligations under the plan. The following table sets forth the funded status of all plans as of September 30, 1993, and the amounts recognized in the consolidated balance sheet at December 31, 1993 (in millions):
The accumulated postretirement benefit obligation represents the actuarial present value of employee medical and life insurance benefits based on employees' history of service up to the measurement date (September 30, 1993.) It was determined using an assumed discount rate of 7.25% and an assumed medical cost trend rate of 12% for 1994 declining to a rate of 6% after the year 2002. If the medical cost trend rate was increased by 1%, the December 31, 1993 accumulated postretirement benefit obligation would have increased by $7.0 million and the 1993 net periodic benefit cost would have increased by $.9 million.
The accumulated postretirement benefit obligation as of January 1, 1993, was $70 million assuming an 8 1/2% discount rate. This transition obligation is being amortized over allowable periods up to 20 years. In 1993, the reduction in the discount rate to 7.25% was the primary cause of the increase in the benefit obligation, which is reflected in the net actuarial loss.
The components of postretirement benefit cost for 1993 were as follows (in millions):
Accrued postretirement benefit cost represents the amount of benefit cost recognized in excess of benefits paid. Cash payments totaled $8.1 million in 1993, $7.5 million in 1992 and $6.9 million in 1991.
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Of the amounts noted above, about $34 million of the unrecognized transi- tion obligation and $4.7 million of the 1993 expense are attributable to Lone Star's rate-regulated activities. Lone Star's related cash payments in 1993 were $2.7 million. Cash basis is the method of recovery currently followed in the rate-making process. Lone Star has deferred approximately $.5 million of the $2.0 million difference in the 1993 net periodic expense and cash pay- ments, although the full amount is subject to future recovery through rates.
9. INCOME TAXES
The provision (benefit) for income taxes on continuing operations is summarized below:
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A reconciliation between income taxes (benefit) computed at the federal statutory rate and income-tax expense (benefit) of continuing operations is shown below:
Deferred income taxes are provided for all significant temporary differences by the liability method, whereby deferred tax assets and liabil- ities are determined by the tax laws and statutory rates in effect at the balance sheet date. Temporary differences which give rise to significant deferred tax assets and liabilities at December 31, 1993 are as follows:
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At December 31, 1993, the Corporation had domestic net operating-loss carryforwards and suspended losses from partnerships of $161 million which begin to expire in 2003, and tax-credit carryforwards of $37 million, which begin to expire in 1999. The tax benefits of these carryforwards and suspended losses, which total some $93 million as shown above, are available to reduce future income-tax payments.
The Corporation made payments (received refunds) for income taxes as follows:
The tax effect of the gain on sale differs from tax at the statutory rate because of permanent differences in book and tax basis of the assets sold. The determination of the gain on sale involved significant estimates including the final purchase price, realization of the estimated value of retained assets, and related income-tax matters. In management's opinion, adequate provision has been made for these matters.
12. SUPPLEMENTAL FINANCIAL INFORMATION
Quarterly Results (Unaudited) - The results of operations by quarters are summarized below and have been restated for the discontinuance of the engineering and construction business segment and the realignment of operations for segment of business reporting that became effective in the first quarter of 1993. Consolidated operating income and net income were not affected by the realignment. In the opinion of the Corporation, after the restatement, all adjustments (consisting only of normal recurring accruals) necessary for a fair presentation have been made.
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Reconciliation of Previously Reported Quarterly Information
Quarterly amounts previously reported for the year 1992 and the first three quarters of 1993 have been restated in the above tables to give effect to the discontinued engineering and construction operations referred to in Note 11. The restatement affected the various components of the quarterly results as follows:
Disposal of Significant Assets
In 1993, the Corporation sold a gas storage facility and a minority- investment in an insurance entity and realized a pretax gain of $7.0 million.
Effective January 1, 1992, the Corporation transferred the assets and business of Enserch Gas Transmission Company to a new partnership, Gulf Coast Natural Gas Company, for $19 million and a 50% ownership of the new partner- ship. No gain or loss resulted from the transfer. The Corporation uses the equity method to account for its interest in the new partnership.
In December 1991, the Corporation completed the sale of Enserch Nether- lands, Inc., for $32.1 million and recorded a pretax gain on the sale of $6.0 million. In June 1991, the Corporation completed the sale of its Oklahoma utility properties, for approximately $31 million, and recorded a pretax gain on the sale of $9.1 million.
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Cash Flows - The Corporation considers all highly liquid investments in the United States with a maturity of three months or less to be cash equivalents. The decrease (increase) in current operating assets and liabilities for con- tinuing operations is summarized below.
Supplemental disclosure of noncash financing and investing activities
The $15.8 million pretax charge in 1992 for termination of an interest-rate hedge described in Note 2 was a noncash transaction.
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Environmental business long-term contracts
The following tabulation indicates accounts receivable and the components of unbilled costs, estimated earnings and retainages relating to uncompleted contracts as of December 31, 1993:
In accordance with industry practice, unbilled costs and fees relating to contracts having a duration of longer than one year are classified as current assets. Costs and fees on long-term contracts that have been billed to clients, but that have not yet been paid, are included in accounts receivable. Unbilled costs and fees on uncompleted contracts are generally includable in the following month's billings, or become billable on a progress basis, pursuant to the terms of the contract billing schedule. The balances billable pursuant to retainage provisions in contracts will be due upon substantial completion of the contract and acceptance by the client.
Assignment of Future Gas Purchase Credits - At December 31, 1993 and 1992, assignments of future gas purchase credits from advances and prepayments for gas were $38,191 and $54,114, respectively (of which $26,028 and $18,214, respectively, were current). The credits are reduced by an amount equal to the reduction in the related asset, advances and prepayments for gas, which are based upon amounts of gas purchased by the Corporation under related gas purchase contracts. The assignment of future gas purchase credits provided for an average annual finance charge of 3.6% during December 1993.
Restructuring Charges - In December 1993, the Corporation recognized a $12 million charge for efficiency enhancements and severance expenses accrued for staff reductions in Natural Gas Transmission and Distribution operations.
Business Segments - Information by business segments presented elsewhere herein is an integral part of these financial statements.
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13. SUPPLEMENTARY GAS AND OIL INFORMATION
Gas and Oil Producing Activities - The following tables set forth informa- tion relating to gas and oil producing activities. Reserve data for natural gas liquids attributable to leasehold interests owned by the Corporation are included in oil and condensate.
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Excluded Costs - The following table sets forth the composition of capitalized costs excluded from the amortizable base as of December 31, 1993:
Approximately 43% of the excluded costs relates to offshore activities in the Gulf of Mexico and the remainder is domestic onshore exploration activi- ties. The anticipated timing of the inclusion of these costs in the amortiza- tion computation will be determined by the rate at which exploratory and development activities continue, which are expected to be accomplished within ten years.
Gas and Oil Reserves (Unaudited) - The following table of estimated proved and proved developed reserves of gas and oil has been prepared by the Corporation utilizing estimates of yearend reserve quantities provided by DeGolyer and MacNaughton, independent petroleum consultants. Reserve estimates are inherently imprecise and estimates of new discoveries are more imprecise than those of producing gas and oil properties. Accordingly, the reserve estimates are expected to change as additional performance data becomes available. Oil reserves (which include condensate and natural gas liquids attributable to leasehold interests) are stated in thousands of barrels (MBbl). Gas reserves are stated in million cubic feet (MMcf).
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Included in the U.S.-Oil reserve estimates are natural gas liquids for leasehold interest of 1,019 MBbl for 1991; and 985 MBbl for 1992; and 1,117 MBbl for 1993.
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Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Gas and Oil Reserve Quantities (Unaudited) - has been prepared by the Corporation using estimated future production rates and associated production and development costs. Continuation of economic con- ditions existing at the balance sheet date was assumed. Accordingly, estimated future net cash flows were computed by: applying contracts and prices in effect in December to estimated future production of proved gas and oil reserves; estimating future expenditures to develop proved reserves; and estimating costs to produce the proved reserves based on average costs for the year. Average prices used in the computations were:
Because of the imprecise nature of reserve estimates and the unpredictable nature of the other variables used, the standardized measure should be interpreted as indicative of the order of magnitude only and not as precise amounts.
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The following table sets forth an analysis of changes in the standardized measure of discounted future net cash flows from proved gas and oil reserves:
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COMMON STOCK MARKET PRICES AND DIVIDEND INFORMATION
MARKET PRICES - ENSERCH COMMON STOCK
The Corporation's common stock is principally traded on the New York Stock Exchange. The following table shows the high and low sales prices per share of the common stock of the Corporation reported in the New York Stock Exchange - - Composite Transactions report for the periods shown as quoted in The Wall Street Journal (WSJ).
DIVIDENDS PER SHARE OF COMMON STOCK
As of December 31, 1993, the Corporation had paid 198 consecutive quarterly cash dividends on its common stock. At December 31, 1993, $350 million of the consolidated common shareholders' equity of the Corporation was free of restrictions as to the payment of dividends and redemption of capital stock. The declaration of future dividends will be dependent upon business conditions, earnings, the cash requirements of the Corporation and other relevant factors. In February 1994, the Corporation declared a quarterly cash dividend of 5 cents per share payable March 7, 1994, to share- holders of record on February 18, 1994.
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Two million shares of PESC common stock, obtained in connection with the sale of Pool Company and set aside as a special dividend to ENSERCH sharehold- ers, were distributed in November 1990. The common stock was distributed at the rate of one share of PESC for every 32.368 shares of ENSERCH common stock, equivalent to $.33 per share.
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APPENDIX B
ENSERCH CORPORATION AND SUBSIDIARY COMPANIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENT SCHEDULES
DECEMBER 31, 1993
Page ----
Independent Auditors' Report................................. B-2
Consolidated Financial Statement Schedules for the Three Years Ended December 31, 1993:
V - Property, Plant and Equipment..................... B-3
VI - Accumulated Depreciation and Amortization of Property, Plant and Equipment................ B-6
IX - Short-Term Borrowings............................. B-9
X - Supplementary Income Statement Information........ B-10
B-1
INDEPENDENT AUDITORS' REPORT
ENSERCH CORPORATION:
We have audited the consolidated financial statements of ENSERCH Corporation and subsidiary companies as of December 31, 1993 and 1992, and for each of the three years in the period ended December 31, 1993, and have issued our report thereon dated February 7, 1994; (included elsewhere in this Form 10-K). Our audits also included the consolidated financial statement schedules of ENSERCH Corporation listed in Item 14. These consolidated financial statement schedules are the responsibility of the Corporation's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE
Dallas, Texas February 7, 1994
B-2
B-3
B-4
B-5