Item 1.BUSINESS
BUSINESS -------- ENSERCH Corporation (ENSERCH or the Corporation) is an integrated company focused primarily on natural gas. Through its divisions and subsidiaries, the corporation is engaged in the gathering, processing, transmission and distribution of natural gas and the marketing of natural gas and electricity. ENSERCH is a wholly-owned subsidiary of Texas Utilities Company (TUC), a Texas corporation. TUC is a holding company whose principal United States (US) operations are conducted through Texas Utilities Electric Company (TU Electric), ENSERCH, and Texas Energy Industries, Inc. (TEI). TUC's principal international operations are conducted through TU International Holdings Limited (TU International Holdings). Through its subsidiaries, TUC engages in the generation, purchase, transmission, distribution and sale of electricity; the gathering, processing, transmission and distribution of natural gas; energy marketing; and telecommunications, retail energy services, international gas operations, power development and other businesses primarily in the US, the United Kingdom (UK) and Australia. Additional information concerning subsidiaries and divisions follows. ENSERCH and its subsidiaries possess all necessary franchises, licenses and certificates to enable them to conduct their respective businesses.
At December 31, 1998, ENSERCH and its direct and indirect wholly-owned subsidiaries had 1,423 full-time employees.
Merger with TUC
On August 5, 1997 (Merger Date or Acquisition Date), the merger transactions involving the former Texas Utilities Company, now known as TEI, and ENSERCH were completed. All of the common stock of ENSERCH was converted into common stock of TUC, and ENSERCH became a wholly-owned subsidiary of TUC. Immediately prior to ENSERCH's merger with TUC, Enserch Exploration, Inc. (EEX) and Lone Star Energy Plant Operations, Inc. (LSEPO), former subsidiaries of the Corporation, were merged to form a new company (New EEX), and ENSERCH distributed to its common shareholders its ownership interest in those businesses.
TUC accounted for its acquisition of ENSERCH as a purchase. Purchase accounting adjustments, including goodwill, have been pushed down and are reflected in the financial statements of ENSERCH and its subsidiaries for the period subsequent to August 5, 1997. The financial statements of ENSERCH for the periods ended before August 5, 1997 were prepared using ENSERCH's historical basis of accounting and are designated herein as "Predecessor". The comparability of the operating results for the Predecessor and the periods encompassing push down accounting are affected by the purchase accounting adjustments, including the amortization of goodwill over a period of forty years.
The fair value of the assets and liabilities of ENSERCH's rate-regulated natural gas utility business (conducted through its Lone Star Gas Company and Lone Star Pipeline Company divisions) is considered to be equivalent to the historical basis of accounting and, accordingly, no adjustment has been made to the carrying value. The process of determining the fair value of assets acquired, liabilities assumed and contingencies existing at the Merger Date was completed in 1998 and resulted in an increase in goodwill of approximately $60 million over the preliminary allocation, primarily due to refinement of estimates of preacquisition contingencies.
The Predecessor financial statements have been restated to reflect EEX and LSEPO as discontinued operations. The historical financial statements of ENSERCH reflect certain reclassifications made to conform to TUC's presentation style. On December 31, 1997, ENSERCH sold to another subsidiary of TUC, at net book value, the group of companies which had constituted the Corporation's power development and international gas distribution operations. For financial reporting purposes, the sale was deemed to have occurred on August 5, 1997.
Accordingly, operating results for periods following the Merger Date exclude those operations. Prior periods were not restated to reflect the sale.
Business of ENSERCH
ENSERCH conducts its major business operations through the following companies:
Lone Star Pipeline Company (Lone Star Pipeline), a partially rate-regulated division of ENSERCH, owns and operates interconnected natural-gas transmission lines, underground storage reservoirs, compressor stations and related properties, all within Texas. With a system consisting of approximately 7,600 miles of gathering and transmission pipelines in Texas, Lone Star Pipeline is one of the largest pipelines in the US. Through these facilities, it transports natural gas to distribution systems of Lone Star Gas Company (Lone Star Gas) and other customers. Rates for the services provided to Lone Star Gas are regulated by the Railroad Commission of Texas (RRC) while rates for services to other customers are generally established by competitively negotiated contracts.
Lone Star Gas, a partially rate-regulated division of ENSERCH, owns and operates natural gas distribution systems and related properties. One of the largest gas distribution companies in the US and the largest in Texas, Lone Star Gas provides service through over 24,000 miles of distribution mains. Through these facilities, it purchases, distributes and sells natural gas to over 1.37 million residential, commercial and industrial customers in approximately 550 cities and towns, including the 11-county Dallas-Fort Worth (DFW) Metroplex. Lone Star Gas also transports natural gas within its distribution system as market opportunities require. The distribution service rates that Lone Star Gas charges its residential and commercial customers are established by the municipal governments of the cities and towns served with the RRC having appellate jurisdiction. Lone Star Gas' gas sales revenues are influenced by seasonal temperature variations. The majority of Lone Star Gas' residential and commercial gas customers use gas for heating, and their needs are directly affected by the mildness or severity of the heating season, although some 70% of Lone Star Gas' residential and commercial volumes are subject to weather normalization adjustments. Sales to electric-generation customers are affected by the mildness or severity of both cooling and heating seasons.
Enserch Processing, Inc. (EPI), a wholly owned subsidiary of ENSERCH, gathers and processes natural gas to remove impurities and extract natural gas liquids (NGL) for sale and sells the natural gas remaining after processing. EPI uses cryogenic and mechanical refrigeration processes at its NGL extraction facilities. The mixed NGL stream, containing the heavier hydrocarbons ethane, propane, butane and natural gasoline, is pumped via pipeline to Mt. Belvieu, Texas. The remaining natural gas, primarily methane, leaves the NGL plants in gas transmission lines for transportation to end-use customers. About 85% of NGL product sales are under term contracts of one to three years, with prices established monthly. NGL prices are influenced by a number of factors, including supply, demand, inventory levels, the product composition of each barrel and the price of crude oil. Profitability is highly dependent on the relationship of NGL product prices to the cost of natural gas lost in the extraction process, which is commonly termed "shrinkage." To reduce the impact of shrinkage, EPI strives to replace "keep-whole" gas processing contracts with "net-proceeds" contracts. Keep-whole contracts are relatively more profitable during periods of high NGL prices and low gas costs because they provide the processor with ownership of the entire gas stream. However, as NGL prices decline relative to gas costs, these contracts become relatively less profitable because the processor must absorb all the shrinkage costs. Under net-proceeds contracts, the producer provides shrinkage volumes, while the processor contributes plant facilities and operational costs. Revenues from NGL sales are apportioned between the parties, and the processor is no longer impacted by natural-gas feedstock costs.
Enserch Energy Services, Inc. (EES), a wholly-owned subsidiary of ENSERCH, is a wholesale and retail marketer of natural gas and electricity in several areas of the US. Its primary natural gas markets, both retail and wholesale, are in Texas, the Northeast, the Midwest and the West Coast. EES' marketing activities typically consist of (i) contracting to purchase specific volumes of gas from producers, pipelines and other suppliers at various points
of receipt to be supplied to end users over a specific period of time, (ii) aggregating gas supplies and arranging for the transportation of these gas supplies, (iii) negotiating to sell specific volumes of gas over a specified period of time to end users and (iv) providing related risk-management services to its customers. EES makes physical sales of electricity in the wholesale market throughout the US excluding the area of the Electric Reliability Council of Texas (ERCOT).
ENSERCH operates in the liquified and compressed natural-gas vehicular fuel markets through its Alternative Fuel Division. This includes two affiliates, FleetStar of Texas, L.C. (Fleetstar), a fueling affiliate owned 50% by ENSERCH, and TranStar Technologies, L.C. (TranStar), a vehicle conversion affiliate owned 100% by ENSERCH. FinaStar, which is a partnership between FleetStar and Fina Oil and Chemical, is 25% owned by ENSERCH. These entities had 22 public and 9 private natural gas fueling stations in commercial operation at the end of 1998 and sold over 3.3 million equivalent gallons of natural gas during the year. TranStar provides turnkey natural gas vehicle conversions and other related services. ENSERCH also owns and operates one liquified natural gas fueling station at the American Airlines DFW Airport maintenance facility and one fueling station for the Dallas Area Rapid Transit Authority (DART). ENSERCH is completing the construction of a second station for DART.
COMPETITIVE STRATEGY --------------------
As legislative, regulatory, economic and technological changes occur, the energy and utility industries are faced with increasing pressure to become more competitive while adhering to regulatory requirements. A number of variables, including price, reliability of service, the cost of energy alternatives, new technologies and governmental regulations, affect the level of competition.
In order to remain competitive, ENSERCH aggressively manages its operating costs and capital expenditures through streamlined business processes and is developing and implementing strategies to address an increasingly competitive environment. These strategies include initiatives to improve return on assets and to maximize value through new marketing programs.
OPERATING SEGMENTS ------------------
Statement of Financial Accounting Standards (SFAS) No. 131, "Disclosures About Segments of an Enterprise and Related Information," became effective for reporting purposes at year-end 1998. In accordance with the provisions of that standard, the Corporation has two reportable operating segments:
(1) US Gas Pipeline and Distribution - operations engaged in the gathering, processing, transmission and distribution of natural gas and selling of natural gas liquids primarily within Texas (primarily Lone Star Gas, Lone Star Pipeline and EPI);
(2) US Energy Marketing - operations engaged in purchasing and selling natural gas and electricity and providing risk management services for the energy industry throughout the US (EES); and
Other - non-segment operations consist of liquified and compressed natural gas fuels (primarily the Alternative Fuel Division of ENSERCH).
Financial information required hereunder is set forth in Note 17 to Consolidated Financial Statements included in Appendix A to this report.
US GAS PIPELINE AND DISTRIBUTION SEGMENT
GENERAL
US Gas Pipeline and Distribution operations (primarily Lone Star Gas, Lone Star Pipeline and EPI) are engaged in the gathering, processing, transmission and distribution of natural gas and selling of related natural gas liquids primarily within Texas.
Gas Distribution Peaking -- Lone Star Gas estimates its peak-day availability from long-term contracts and withdrawals from underground storage to be 1.5 Bcf. Short-term peaking contracts and daily spot contracts raise this availability level to meet anticipated sales needs.
During 1998, the average daily demand of Lone Star Gas' residential and commercial customers was 0.3 Bcf. Lone Star Gas' greatest daily demand in 1998 was on December 22 when the arithmetic-mean temperature was 24 degrees F. and deliveries to all customers reached 2.1 Bcf, including estimated deliveries to residential and commercial customers of 2.0 Bcf.
Gas Supply -- Lone Star Gas' gas supply consists of contracts for the purchase of specific reserves, contracts not related to specific reserves or fields, and gas in storage. The total available gas supply as of January 1, 1999 was 299 Bcf, which is approximately two and a half times Lone Star Gas' purchases during 1998. Of this total, 89 Bcf are specific reserves and 34 Bcf are working gas in storage. A total of 176 Bcf are committed to Lone Star Gas under gas supply contracts not related to specific reserves or fields. In 1998, Lone Star Gas' gas requirement was purchased from some 268 independent producers, non-affiliated pipeline companies and other supplies.
To meet peak-day gas demands during winter months, Lone Star Gas utilizes the service of seven gas storage fields owned by Lone Star Pipeline, all of which are located in Texas. These fields have a working gas capacity of 47 Bcf and a storage withdrawal capacity of up to 1.2 Bcf per day.
Lone Star Gas has historically maintained a contractual right to curtail, which is designed to achieve the highest load factor possible in the use of the pipeline system while assuring continuous and uninterrupted service to the residential and commercial customers. Under the program, industrial customers select their own rates and relative priorities of service. Interruptible service contracts include the right to curtail gas deliveries up to 100% according to a strict priority plan. The last sales curtailment for Lone Star Gas occurred in 1990 and lasted for only 30 hours.
Estimates of gas supplies and reserves are not necessarily indicative of Lone Star Gas' 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. Curtailment rights provide Lone Star Gas 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 Gas, may affect its ability to meet the demands of its customers.
Lone Star Gas buys gas under long-term and short-term intrastate contracts in order to assure reliable supply to its customers. Many of these contracts require minimum purchases of gas. Presently, based on estimated gas demand which assumes normal weather conditions, requisite gas purchases are expected to substantially satisfy purchase obligations for the year 1999 and thereafter.
The Lone Star Gas supply program is designed to contract for new supplies of gas and to recontract targeted expiring sources. In addition to being heavily concentrated in the established gas-producing areas of central, northern and eastern Texas, Lone Star Pipeline's intrastate pipeline system also extends into or near the major producing areas of the Texas Gulf Coast and the Delaware and Val Verde Basins of West Texas. Nine basins located in Texas are estimated to contain a substantial portion of the nation's remaining onshore natural gas reserves. Lone Star Pipeline's pipeline system provides access to all of these basins. Lone Star Pipeline is well situated to receive large volumes into its system at the major hubs, such as Katy and Waha, as well as at the major third-party owned storage facilities where suppliers maintain instantaneous high delivery capabilities.
At December 31, 1998, Lone Star Pipeline operated approximately 7,600 miles of transmission and gathering lines and operated 22 compressor stations having a total rated horsepower of approximately 76,000. Lone Star Pipeline also owned seven active gas-storage fields, all located on its system in Texas, and three major gas-treatment plants to remove undesirable components from the gas stream.
At December 31, 1998, EPI had interests in 15 processing plants, 10 of which were wholly owned, and operated approximately 1,700 miles of gathering lines.
REGULATION AND RATES
Lone Star Gas and Lone Star Pipeline are wholly intrastate in character and perform distribution utility operations and transportation services in the State of Texas subject to regulation by the RRC and municipalities in Texas. The RRC regulates the charge for the transportation of gas by Lone Star Pipeline to Lone Star Gas' distribution systems for sale to Lone Star Gas' residential and commercial consumers. Lone Star Pipeline owns no certificated interstate transmission facilities subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act, has no sales for resale under the rate jurisdiction of the FERC and does not perform any transportation service that is subject to FERC jurisdiction under the Natural Gas Act.
The city gate rate for the cost of gas Lone Star Gas ultimately delivers to residential and commercial customers is established by the RRC and provides for full recovery of the actual cost of gas delivered, including out-of-period costs such as gas purchase contract settlement costs. The distribution service rates Lone Star Gas charges its residential and commercial customers are established by the municipal governments of the cities and towns served, with the RRC having appellate jurisdiction.
Lone Star Gas employs a continuing program of rate review for all classes of customers in its regulatory jurisdictions. Rate relief amounting to about $2.5 million in annualized revenue increases, exclusive of changes in gas costs, was achieved in 1998. Rate cases supporting an additional $5.9 million in annualized revenue increases were pending in a number of cities at the end of the year. Weather normalization adjustment clauses have been approved by almost 300 cities served by Lone Star Gas, representing 70% of Lone Star Gas' residential and commercial sales volumes. These clauses allow rates to be adjusted to reflect the impact of warmer or colder-than-normal weather during the winter months, minimizing the impact of variations in weather on Lone Star Gas' earnings.
Lone Star Gas' sales to industrial customers are provided under rates reflected in standard rate schedules and contracts. Transportation services to industrial and electric-generation customers are provided under competitively negotiated contracts. Industrial customers also have standard rate schedules for transportation services. Regulatory authorities in Texas have jurisdiction to revise, review and regulate rates to industrial and electric-generation customers but, historically, have not actively exercised this jurisdiction because of the existing competitive market. Sales contracts with these customers permit automatic adjustment on a monthly basis for the full amount of increases or decreases in the cost of gas.
In August 1996, the RRC ordered a general inquiry into the rates and services of Lone Star Gas, most notably a review of historic gas cost and gas acquisition practices since the last rate setting. The inquiry docket was separated into different phases, all of which are now resolved. Two of the phases, conversion to the National Association of Regulatory Utility Commissioners account numbering system and unbundling, have been dismissed by the RRC, and one other phase, rate case expense, has been concluded. In the phase dealing with historic gas cost and gas acquisition practices, the RRC issued a final order on June 2, 1998, approving a stipulated settlement of the docket. Lone Star Gas agreed to credit residential and commercial customers $18 million to be spread over the next two heating seasons (November through March). The earnings of Lone Star Gas were not affected by the settlement due to previously established reserves. Lone Star Gas and the intervenors both agreed to withdraw their appeals of the city gate rate case. The final order approving the stipulation found that all gas costs flowed through Lone Star Gas' monthly gas cost adjustment clause prior to October 31, 1997 were just, reasonable, and necessary. As a part of the final order, the RRC required an audit of an amount that Lone Star Gas credited to residential and commercial customers under a previous voluntary stipulation. The audit report indicated that an additional $7.3 million should be credited to residential and commercial customers. ENSERCH believes that the additional amount noted in the audit report was included in the $18 million settlement, but it is unable to predict the outcome of the audit.
COMPETITION
Customer sensitivity to energy prices and the availability of competitively priced gas in the non-regulated markets continue to provide intense competition in the electric-generation and industrial-user markets. Natural gas faces varying degrees of competition from electricity, coal, natural gas liquids, oil and other refined products throughout Lone Star Gas' service territory. Pipeline systems of other companies, both intrastate and interstate, extend into or through the areas in which Lone Star Gas' markets are located, creating competition from other sellers of natural gas. Competitive pressure from other pipelines and alternative fuels has caused a decline in sales by Lone Star Gas to industrial and electric-generation customers. As developments in the energy industry point to a continuation of these competitive pressures, Lone Star Gas maintains its focus on customer service and the creation of new services for its customers in order to remain its customers' supplier of choice.
Lone Star Pipeline is the sole transporter of natural gas to Lone Star Gas' distribution systems. Lone Star Pipeline competes with other pipelines in Texas to transport natural gas to off-system markets. This business is highly competitive and greatly influenced by the demand to move natural gas across Texas to supply Northeast and upper Midwest US markets.
Natural gas liquids processing is highly competitive and includes competition among producers, third-party owners and processors for cost-sharing and interest-sharing arrangements.
Open Access -- Lone Star Pipeline has been an open access transporter under Section 311 of the Natural Gas Policy Act of 1978 (NGPA) on its intrastate transmission facilities since July 1988. Such transportation is performed pursuant to Section 311(a)(2) of the NGPA and is subject to an exemption from the jurisdiction of the FERC under the Natural Gas Act, pursuant to Section 601 of the NGPA.
Customers --There are no individually significant customers upon which the segment's business or results of operations are highly dependent.
US ENERGY MARKETING SEGMENT
GENERAL
US Energy Marketing (EES) operations are engaged in purchasing and selling natural gas and electricity and providing risk management services for the energy industry throughout the US, other than within ERCOT.
US Energy Marketing Operating Statistics Years Ended December 31
Headquartered in Houston, Texas, EES serves the diversified energy requirements of its clients from five regional centers and 17 local customer service and support offices located across the US. EES' primary natural gas markets, both retail and wholesale, are in Texas, the Northeast, the Midwest and the West Coast. Other than within ERCOT, EES engages in the physical purchase and sale of electricity in the wholesale markets throughout the US and is also engaged in power retail marketing, primarily in the Northeast region of the country.
In the course of providing comprehensive energy products and services to its diversified client base, EES engages in energy price risk management activities. In addition to the purchase and sale of physical commodities, EES enters into futures contracts; swap agreements where settlement is based on the difference between a fixed and floating (index based) price for the underlying commodity; exchange traded options; over-the-counter options, which are settled in cash or in the physical delivery of the underlying commodity; exchange-of-futures for physical (EFP) transactions; energy exchange transactions; storage activities; and other contractual arrangements. EES may buy and sell certain of these instruments to manage its exposure to price risk from existing contractual commitments as well as other energy-related assets and liabilities. It may also enter into contracts to take advantage of arbitrage opportunities. In order to manage its exposure to the price risk associated with these instruments, EES has established trading policies and limits and revalues its exposures daily against these benchmarks. EES also periodically reviews these policies to ensure they are responsive to changing market and business conditions.
EES' business is not specifically seasonal; however, the results of its operations are greatly affected by price volatility in the underlying commodity markets. Price volatility in both natural gas and electric power is largely a result of supply and demand factors driven by weather conditions and physical constraints in the deliverability of these commodities. Arbitrage opportunities resulting from this price volatility are often greatest in the late summer/early fall and winter months for natural gas and the summer months for electricity.
COMPETITION
EES pursues opportunities to manage risks for non-affiliated companies. As natural-gas markets continue to evolve following the implementation of the 1992 Order 636 of the FERC, additional opportunities are created in the broader, more active trading markets and in serving non-regulated customers. This highly competitive market demands that a wide array of services be offered, including term contracts with interruptible and firm deliveries, risk management, aggregation of supply, nominations, scheduling of deliveries and storage.
Customers -- There are no individually significant customers upon which the segment's business or results of operations are highly dependent.
ENVIRONMENTAL MATTERS ---------------------
ENSERCH is subject to various federal, state and local regulations dealing with air and water quality and related environmental matters.
Air -- Under the Texas Clean Air Act, the Texas Natural Resource Conservation Commission (TNRCC) has jurisdiction over the permissible level of air contaminant emissions from facilities located within the State of Texas. In addition, the source performance standards of the Environmental Protection Agency (EPA) promulgated under the Federal Clean Air Act, as amended (Clean Air Act), which have also been adopted by the TNRCC, are also applicable. In 1997, the Clean Air Act required ENSERCH to submit Title V Operating Permit applications for certain of its facilities. ENSERCH has received the approval of all such permit applications.
Additional Clean Air Act regulations have been proposed and others are not yet finalized by the EPA. ENSERCH believes that the requirements necessary to be in compliance with additional regulatory provisions can be met as they are developed. Estimates for the capital requirements related to the Clean Air Act are included in the Corporation's estimated capital expenditures. Any additional capital expenditures, as well as any increased
operating costs associated with new requirements or compliance measures, are expected to be recoverable through rates, as similar costs have been recovered in the past. ENSERCH currently believes that if the rules and regulations under the Clean Air Act are adopted as proposed, operating costs that will be incurred under operating permits, new permit fee structures, capital expenditures associated with equipment modifications to reduce emission, or any expenditures on monitoring equipment, in the aggregate, will not have a materially adverse effect on the Corporation's financial position, results of operations or cash flow.
Water -- The TNRCC, the EPA and RRC have jurisdiction over water discharges (including storm water) from the Corporation's facilities. The Corporation's facilities are presently in compliance with applicable state and federal requirements relating to discharge of pollutants into the water. ENSERCH has obtained all required waste water discharge permits from the TNRCC, the EPA and the RRC for facilities in operation and has applied for or obtained necessary permits for facilities under construction. ENSERCH believes it can satisfy the requirements necessary to obtain any required permits or renewals.
Item 2.
Item 2. PROPERTIES
PROPERTIES ----------
At December 31, 1998, Lone Star Pipeline operated approximately 7,600 miles of transmission and gathering lines and operated 22 compressor stations having a total rated horsepower of approximately 76,000. Lone Star Pipeline also owned seven active gas-storage fields, all located on its system in Texas, and three major gas-treatment plants to remove undesirable components from the gas stream. At December 31, 1998, EPI had interests in 15 processing plants, 10 of which were wholly owned, and operated approximately 1,700 miles of gathering lines. At December 31, 1998, Lone Star Gas operated approximately 24,000 miles of distribution mains.
ENSERCH owns a five-building office complex in Dallas, containing approximately 453,000 square feet of space that is occupied by ENSERCH and other affiliates of TUC. In addition, ENSERCH owns a 21-story, 400,000 square-foot building in Houston. This building is leased, primarily to non-affiliated parties.
CAPITAL EXPENDITURES --------------------
The capital expenditures of the Corporation were $187 million in 1998 and are estimated at $117 million for 1999. Approximately 94% will be spent on US Gas Pipeline and Distribution operations and approximately 6% on US Energy Marketing and other operations.
Item 3.
Item 3. LEGAL PROCEEDINGS
LEGAL PROCEEDINGS -----------------
A lawsuit was filed on February 24, 1987, in the 112th Judicial District of Sutton County, Texas, against subsidiaries and affiliates of the Corporation and its utility division. The plaintiffs have claimed that defendants failed to make certain production and minimum-purchase payments under a gas-purchase contract. The plaintiffs initially alleged a conspiracy to violate purchase obligations, improper accounting of amounts due, fraud, misrepresentation, duress, failure to properly market gas and failure to act in good faith. Under amended pleadings filed in January 1997, plaintiffs have added allegations of negligence and gross negligence in connection with the measurement of gas and conversion. Plaintiffs seek actual damages in excess of $9 million and punitive damages in an amount equal to .5% of the consolidated gross revenues of the Corporation for the years 1982-1986
(approximately $85 million), interest, costs and attorneys' fees. On March 2, 1999, an agreement was reached to settle this matter at no material cost to the Corporation.
In August 1998, the Gracy Fund, L.P. (Gracy Fund) filed suit in the United States District Court for the Northern District of Texas against EEX Corporation, formerly Enserch Exploration, Inc. (EEX), TUC, David W. Biegler, Gary J. Junco, Erle Nye, Thomas Hamilton and J. Phillip McCormick. The Gracy Fund sought to represent a class comprised of all purchasers of the common stock of ENSERCH or EEX between January 26, 1996 and August 4, 1997, including former shareholders of ENSERCH who received shares of EEX and TUC pursuant to the merger agreement between ENSERCH and TUC dated April 13, 1996, all EEX shareholders solicited pursuant to a proxy statement/prospectus issued by EEX dated October 2, 1996 and all ENSERCH shareholders solicited by a joint proxy statement/prospectus issued by ENSERCH and TUC dated September 23, 1996. The Gracy Fund alleged that the defendants participated in a fraudulent scheme and course of business by disseminating materially false and misleading statements regarding EEX's and ENSERCH's business, which allegedly caused the plaintiffs and other members of the class to purchase EEX and ENSERCH stock at artificially inflated prices. In such connection, the plaintiffs alleged that the defendants violated various provisions of the Securities Act of 1933 (Securities Act) and the Securities Exchange Act of 1934 (Exchange Act).
Also in August 1998, Stan C. Thorne (Thorne) filed suit in the United States District Court for the Southern District of Texas against EEX, ENSERCH, DeGolyer & MacNaughton, David W. Biegler, Gary J. Junco, Fredrick S. Addy and B. K. Irani. Thorne sought to represent a class comprised of all purchasers of the common stock of EEX during the period of August 3, 1995 through August 5, 1997. Thorne alleged that the defendants engaged in a course of conduct designed to mislead the plaintiff and investing public in order to maintain the price of EEX common stock at artificially high levels through false and misleading representations concerning the gas reserves of EEX in violation of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 thereunder. Thorne also alleged that the defendants were negligent in making such misrepresentations and that they constituted common law fraud against the defendants.
In December 1998, the United States District Court for the Northern District of Texas issued an Order in Cause No. 3-98-CV-1808-G consolidating the Gracy Fund and the Thorne suits (the Consolidated Action). On January 22, 1999, the Gracy Fund, et al. filed an amended class action complaint in the Consolidated Action against EEX, ENSERCH, David W. Biegler, Gary J. Junco, Thomas Hamilton, J. Philip McCormick, Fredrick S. Addy and B. K. Irani. TUC and Erle Nye were omitted as defendants pursuant to a tolling agreement. The individual-named defendants in the amended complaint are current or former officers and/or directors of EEX, and Mr. Biegler has been an officer and director of ENSERCH. The amended complaint alleges violations of provisions of the Securities Act and the Exchange Act. The state law claims alleged in the Thorne case have been omitted. The class period was amended to include those persons acquiring stock of ENSERCH and/or EEX between August 3, 1995 and August 5, 1997, inclusive. No amount of damages has been specified in the Consolidated Action. The Corporation is continuing to evaluate these claims and is unable at this time to predict the outcome of this proceeding, but it intends to vigorously defend this suit.
ENSERCH and its subsidiaries are party to other lawsuits arising in the ordinary course of its business. ENSERCH believes, based on its current knowledge and the advice of counsel, that all such lawsuits and resulting claims would not have a material adverse effect on its financial position, results of operations or cash flow.
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
Not applicable. All of ENSERCH's common stock is owned by TUC.
Item 6.
Item 6.SELECTED FINANCIAL DATA
The information required hereunder for the Corporation is set forth under Selected Financial Data included in Appendix A of this report.
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The information required hereunder for the Corporation is set forth under Management's Discussion and Analysis of Financial Condition and Results of Operations included in Appendix A of this report.
Item 7A.
Item 7A.QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required hereunder for the Corporation is set forth under Management's Discussion and Analysis of Financial Condition and Results of Operations included in Appendix A to this report.
Item 8.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder for the Corporation is set forth under Independent Auditors' Report, Statements of Consolidated Income, Statements of Consolidated Comprehensive Income, Statements of Consolidated Cash Flows, Consolidated Balance Sheets, Statements of Consolidated Common Stock Equity and Notes to Consolidated Financial Statements included in Appendix A of this report.
Item 9.
Item 9.CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT
Identification of Directors, business experience and other directorships:
Directors of ENSERCH receive no compensation in their capacity as Directors.
Identification of Executive Officers and business experience:
There is no family relationship between any of the above-named Directors and Executive Officers.
SECTION 16(a) BENEFICIAL OWNERSHIP REPORTING COMPLIANCE
All required reports relating to changes in beneficial ownership of shares of ENSERCH have been timely filed.
Item 11.
Item 11. EXECUTIVE COMPENSATION
ENSERCH and its affiliates have paid or awarded compensation during the last three calendar years to the following Executive Officers for services in all capacities:
As a part of the ENSERCH acquisition, options to purchase the common stock of ENSERCH which had been granted to various employees of ENSERCH were converted into options to acquire common shares of TUC. The table below shows, for each of the named officers, the information specified with respect to exercised, exercisable and unexercisable options under all existing stock option plans, converted into shares of TUC's common stock into which such options became exercisable at the time of the ENSERCH acquisition.
TUC and its subsidiaries maintain retirement plans (TU Retirement Plan) which are qualified under applicable provisions of the Internal Revenue Code of 1986, as amended (Code). Annual retirement benefits under the traditional defined benefit formula of the TU Retirement Plan, which applied to each of the named officers, are computed as follows: for each year of accredited service up to a total of 40 years, 1.3% of the first $7,800, plus
1.5% of the excess over $7,800, of the participant's average annual earnings during his or her three years of highest earnings. Amounts reported under Salary for the named officers in the Summary Compensation Table approximate earnings as defined by the TU Retirement Plan without regard to any limitations imposed by the Code. Benefits paid under the TU Retirement Plan are not subject to any reduction for Social Security payments but are limited by provisions of the Code. As of February 28, 1999, years of accredited service under the TU Retirement Plan for Messrs. Nye, Biegler, Gibbs, Hunter and Baker were 36, 1, 36, 1 and 28, respectively.
Before ENSERCH was acquired by TUC, Messrs. Biegler and Hunter earned retirement benefits under the Retirement and Death Benefit Program of 1969 of ENSERCH Corporation and Participating Subsidiary Companies (ENSERCH Retirement Plan) which was merged into, and became a part of, the TU Retirement Plan effective December 31, 1997. In connection with this plan merger, the TU Retirement Plan was amended to provide that the retirement benefit of employees who were employed by ENSERCH Corporation or one of its subsidiaries participating in the ENSERCH Retirement Plan on August 5, 1997, and as of the last full pay period of 1997, will equal the sum of (1) their accrued benefit under the ENSERCH Retirement Plan through the last pay period of 1997 and (2) their accrued benefit under the TU Retirement Plan beginning with the first pay period of 1998; provided that the aggregate retirement benefit earned under the traditional defined benefit plan formula of the plans can be no less than the retirement benefit which would have been earned had such employees remained under the ENSERCH Retirement Plan for their entire careers. Mr. Biegler, whose employment with TUC began August 5, 1997, is treated in a similar manner. Amounts reported for Messrs. Biegler and Hunter under Salary and Bonus in the Summary Compensation Table approximate earnings as defined by the ENSERCH Retirement Plan without regard to any limitations imposed by the Code. As of February 28, 1999, Messrs. Biegler and Hunter had 30 and 3 years, respectively, of accredited service under the ENSERCH Retirement Plan.
TUC's supplemental retirement plans (Supplemental Plan) provide for the payment of retirement benefits which would otherwise be limited by the Code or the definition of earnings in the TU Retirement Plan or the ENSERCH Retirement Plan, as applicable. Under the Supplemental Plan, retirement benefits are calculated in accordance with the same formula used under the applicable qualified plan, except that, with respect to calculating the portion of the Supplemental Plan benefit attributable to service under the TU Retirement Plan, earnings also include AIP awards (50% of the AIP award is reported under the Bonus for the named officers in the Summary Compensation Table). The tables set forth above illustrate the total annual benefit payable at retirement under the TU Retirement Plan and the ENSERCH Retirement Plan, respectively, inclusive of benefits payable under the Supplemental Plan, prior to any reduction for a contingent beneficiary option which may be selected by participants.
Change in Control Agreements
ENSERCH entered into change in control agreements with certain employees, including Messrs. Biegler and Hunter. As a result, if the employee is terminated or if, under certain circumstances, the employee resigns, within three years of a change in control, the employee will be entitled to a lump sum severance payment of up to three times the sum of the employee's base salary and target bonus (but not in excess of the aggregate base salary that could be earned up to the employee's normal retirement date), a prorated bonus in the year of termination, any unpaid balance and deferred compensation held in certain employee benefit plans, the value of any unexercised stock options, a three-year continuation of employee benefits, the equivalent of two years of service credit under the retirement program, and the reimbursement of certain legal fees, expenses and excise taxes. Shareholder approval of the merger in November 1996 constituted a change in control under these agreements.
The following report and performance graph are presented herein for information purposes only. This information is not required to be included herein and shall not be deemed to form a part of this report to be "filed" with the Securities and Exchange Commission. The report set forth hereinafter is the report of the Organization and Compensation Committee of the Board of Directors of TUC and is illustrative of the methodology utilized in establishing the compensation of executive officers of TUC and ENSERCH. References in the report to the "Company" are references to TUC.
ORGANIZATION AND COMPENSATION COMMITTEE REPORT ON EXECUTIVE COMPENSATION
The Organization and Compensation Committee of the Board of Directors (Committee) is responsible for reviewing and establishing the compensation of the executive officers of the Company. The Committee consists of all of the nonemployee directors of the Company and is chaired by James A. Middleton. The Committee has directed the preparation of this report and has approved its contents and submission to the shareholders.
As a matter of policy, the Committee believes that levels of executive compensation should be based upon an evaluation of the performance of the Company and its officers generally, as well as in comparison to persons with comparable responsibilities in similar business enterprises. Compensation plans should align executive compensation with returns to shareholders with due consideration accorded to balancing both long-term and short-term objectives. The overall compensation program should provide for an appropriate and competitive balance between base salaries and performance-based annual and long-term incentives. The Committee has determined that, as a matter of policy to be implemented over time, the base salaries of the officers will be established at the median, or 50th percentile, of the top ten electric utilities in the United States and that opportunities for total direct compensation (defined as the sum of base salaries, annual incentives and long-term incentives) to reach the 75th percentile, or above, of such utilities will be provided through performance-based compensation plans. Such compensation principles and practices have allowed, and should continue to allow, the Company to attract, retain and motivate its key executives.
In furtherance of these policies, a nationally recognized compensation consultant has been retained since 1994 to assist the Committee in its periodic reviews of compensation and benefits provided to officers. The consultant's evaluations include comparisons to the largest utilities as well as to general industry with respect both to the level and composition of officers' compensation. The consultant's recommendations including the Annual Incentive Plan, the Long-Term Incentive Compensation Plan and certain benefit changes have generally been implemented. The Annual Incentive Plan, which was approved by the shareholders in 1995, is generally referred to as the AIP and is described in this report as well as in footnote 5 to the Summary Compensation Table. The Long-Term Incentive Compensation Plan, referred to as the Long-Term Plan or LTICP, was approved by the shareholders in 1997 and is described in this report as well as in footnote 6 to the Summary Compensation Table.
In recent years, the compensation of the officers of the Company has consisted principally of base salaries, the opportunity to participate in the Deferred and Incentive Compensation Plan (referred to as the DICP and described in footnote 6 to the Summary Compensation Table), the opportunity to earn an incentive award under the AIP and, in certain instances, awards of performance-based restricted shares under the Long-Term Plan. Benefits provided under the DICP and the AIP have represented a substantial portion of officers' compensation, and the value of future payments under the DICP, as well as the value of the deferred portion of any award under the AIP, is directly related to the future performance of the Company's common stock. It is anticipated that performance-based incentive awards under the AIP and the Long-Term Plan, will, in future years, continue to constitute a substantial percentage of the officers' total compensation.
Certain of the Company's business units have developed separate annual and long-term incentive compensation plans. Generally those plans focus on the results achieved by those individual business units and the compensation opportunities provided by those plans are considered to be competitive in the markets in which those units compete. Officers may not participate in both the traditional incentive compensation plans as discussed herein and the business unit plans. None of the named officers participate in the individual business unit plans.
The AIP is administered by the Committee and provides an objective framework within which annual Company and individual performance can be evaluated by the Committee. Depending on the results of such performance evaluations, and the attainment of the per share net income goals established in advance, the Committee may provide annual incentive compensation awards to eligible officers. The evaluation of each individual participant's performance is based upon the attainment of individual and business unit objectives. The Company's performance is evaluated, compared to the ten largest electric utilities and/or the electric utility industry, based upon its total return to shareholders and return on invested capital, as well as other measures relating to competitiveness, service quality and employee safety. The combination of individual and Company performance results,
together with the Committee's evaluation of the competitive level of compensation which is appropriate for such results, determines the amount, if any, actually awarded.
The Long-Term Plan, which is also administered by the Committee, is a comprehensive stock-based incentive compensation plan under which all awards are made in, or based on the value of, the Company's common stock. The Long-Term Plan provides that, in the discretion of the Committee, awards may be in the form of stock options, stock appreciation rights, performance and/or restricted stock or stock units or in any other stock-based form. The purpose of the Long-Term Plan is to provide performance-related incentives linked to long-term performance goals. Such performance goals may be based on individual performance and/or may include criteria such as absolute or relative levels of total shareholder return, revenues, sales, net income or net worth of the Company, any of its subsidiaries, business units or other areas, all as the Committee may determine. Awards under the Long-Term Plan are expected to constitute the principal long-term component of officers' compensation.
In establishing levels of executive compensation at its May 1998 meeting, the Committee reviewed various performance and compensation data, including the performance measures under the AIP and the report of its compensation consultant. Information was also gathered from industry sources and other published and private materials which provided a basis for comparing the largest electric and gas utilities and other survey groups representing a large variety of business organizations. Included in the data considered were the comparative returns provided by the largest electric and gas utilities as represented by the returns of the Standard & Poor's Electric Utility Index which are reflected in the graph herein. In 1997, TU Electric, the Company's principal subsidiary, was the largest electric utility in the United States as measured by megawatt hour sales and, compared to other electric utilities in the United States, was fifth in electric revenues, fifth in total assets, fourth in net generating capability, sixth in number of customers and ninth in number of employees. Compensation amounts were established by the Committee based upon its consideration of the above comparative data and its subjective evaluation of Company and individual performance at levels consistent with the Committee's policy relating to total direct compensation.
At its meeting in May 1998, the Committee provided awards of performance-based restricted stock under the Long-Term Plan to certain officers, including the Chief Executive. The future value of those awards will be determined by the Company's total return to shareholders over a three-year period compared to the total return for that period of the companies comprising the Standard & Poor's Electric Utility Index. Depending upon the Company's relative return for such period, the officers may earn from 0% to 200% of the original award and their compensation is, thereby, directly related to shareholder value. Awards granted in May 1998 contemplate that 200% of the original award will be provided if the Company's total return is in the 81st percentile or above of the returns of the companies comprising the Standard & Poor's Electric Utility Index and that such percentage of the original award will be reduced as the Company's return compared to the Index declines so that 0% of the original award will be provided if the Company's return is in the 40th percentile or below of returns provided by the companies comprising the Index. These awards, and any awards that may be made in the future, are based upon the Committee's evaluation of the appropriate level of long-term compensation consistent with its policy relating to total direct compensation.
In May 1998 the Committee increased Mr. Nye's base salary as Chief Executive to an annual rate of $850,000, representing a $75,000 or 9.7% increase over the amount established for Mr. Nye in May of 1997. Based upon the Committee's evaluation of individual and Company performance, as called for by the AIP, the Committee also provided Mr. Nye with an AIP award of $700,000 compared to the prior year's award of $650,000. The Committee also awarded 22,000 shares of performance-based restricted stock to Mr. Nye. Under the terms of the award, Mr. Nye can earn from 0% to 200% of the award depending on the Company's total return to shareholders over a three-year period (April 1, 1998 through March 31, 2001) compared to the total return provided by the companies comprising the Standard & Poor's Electric Utility Index. This level of compensation was established based upon the Committee's subjective evaluation of the information described in this report.
In discharging its responsibilities with respect to establishing executive compensation, the Committee normally considers such matters at its May meeting held in conjunction with the Annual Meeting of Shareholders. Although Company management may be present during Committee discussions of officers' compensation, Committee decisions with respect to the compensation of the Chairman of the Board and Chief Executive and the President are reached in private session without the presence of any member of Company management.
Section 162(m) of the Code limits the deductibility of compensation which a publicly traded corporation provides to its most highly compensated officers. As a general policy, the Company does not intend to provide compensation which is not deductible for federal income tax purposes. Awards under the AIP in 1996 and subsequent years as well as awards under the Long-Term Plan are expected to be fully deductible, and the DICP and the Salary Deferral Program have been amended to require the deferral of distributions of amounts earned in 1995 and subsequent years until the time when such amounts would be deductible. Awards provided under the AIP in 1995 and distributions under the DICP and the Salary Deferral Program which were earned in plan years prior to 1995, may not be fully deductible but such amounts are not expected to be material.
Shareholder comments to the Committee are welcomed and should be addressed to the Secretary of the Company at the Company's offices.
Organization and Compensation Committee
James A. Middleton, Chair Margaret N. Maxey Derek C. Bonham (since November 1998) J. E. Oesterreicher William M. Griffin Charles R. Perry Kerney Laday Herbert H. Richardson
PERFORMANCE GRAPH
The following graph compares the performance of TUC's common stock to the S&P 500 Index and S&P Electric Utility Index for the last five years. The graph assumes the investment of $100 at December 31, 1993 and that all dividends were reinvested. The amount of the investment at the end of each year is shown in the graph and in the table which follows.
Cumulative Total Returns for the Five Years Ended 12/31/98
[LINE GRAPH APPEARS HERE]
Item 12.
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
Security ownership of certain beneficial owners at February 28, 1999:
Security ownership of management at February 28, 1999:
The following lists the common stock of TUC owned by the Directors and Executive Officers of ENSERCH. The named individuals have sole voting and investment power for the shares of common stock reported. Ownership of such common stock by the Directors and Executive Officers, individually and as a group, constituted less than 1% of the outstanding shares at February 28, 1999. None of the named individuals own any of the preferred stock of ENSERCH or the preferred securities of any subsidiaries of ENSERCH.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, ENSERCH Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
ENSERCH CORPORATION
Date: March 31, 1999 By: /s/ ERLE NYE ---------------------------------- (Erle Nye, Chairman of the Board and Chief Executive)
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of ENSERCH Corporation and in the capacities and on the date indicated.
Appendix A
ENSERCH CORPORATION AND SUBSIDIARIES (A WHOLLY-OWNED SUBSIDIARY OF TEXAS UTILITIES COMPANY)
INDEX TO FINANCIAL INFORMATION December 31, 1998
Page
Selected Financial Data A-2 Management's Discussion and Analysis of Financial Condition and Results of Operations A-3 Independent Auditors' Report A-12 Statements of Consolidated Income A-13 Statements of Consolidated Comprehensive Income A-14 Statements of Consolidated Cash Flows A-15 Consolidated Balance Sheets A-16 Statements of Consolidated Common Stock Equity A-18 Notes to Consolidated Financial Statements A-19
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
FORWARD-LOOKING STATEMENTS
This report and other presentations made by ENSERCH Corporation (ENSERCH or the Corporation) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Although ENSERCH believes that in making any such statement its expectations are based on reasonable assumptions, any such statement involves uncertainties and is qualified in its entirety by reference to the following important factors, among others, that could cause the actual results of ENSERCH to differ materially from those projected in such forward-looking statements: (i) prevailing governmental policies and regulatory actions, including those of the Railroad Commission of Texas (RRC), acquisitions and disposal of assets and facilities, operation and construction of plant facilities, present or prospective wholesale and retail competition, changes in tax laws and policies and changes in and compliance with environmental and safety laws and policies, (ii) weather conditions and other natural phenomena, (iii) unanticipated population growth or decline, and changes in market demand and demographic patterns, (iv) competition for retail and wholesale customers, (v) pricing and transportation of natural gas and other commodities, (vi) unanticipated changes in interest rates or rates of inflation, (vii) unanticipated changes in operating expenses and capital expenditures, (viii) capital market conditions, (ix) competition for new energy development opportunities, (x) legal and administrative proceedings and settlements, (xi) inability of various counterparties to meet their obligations with respect to ENSERCH's financial instruments, (xii) changes in technology used and services offered by ENSERCH, (xiii) significant changes in ENSERCH's relationship with its employees and the potential adverse effects if labor disputes or grievances were to occur and (xiv) unanticipated problems related to the Corporation's internal Year 2000 (Y2K) initiative and potential adverse consequences related to Y2K non-compliance of third parties.
Any forward-looking statement speaks only as of the date on which such statement is made, and ENSERCH undertakes no obligation to update any forward-looking statement to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for ENSERCH to predict all of such factors, nor can it access the impact of each such factor or the extent to which any factor, or combination of factors, may cause results to differ materially from those contained in any forward-looking statement.
MERGERS AND ACQUISITIONS
On August 5, 1997 (Merger Date or Acquisition Date), the merger transactions involving the former Texas Utilities Company, now known as Texas Energy Industries, Inc., and ENSERCH were completed. (See Note 1 to Consolidated Financial Statements for additional information concerning the merger.)
All of the common stock of ENSERCH was converted into common stock of a new holding company, now known as Texas Utilities Company (TUC), and ENSERCH became a wholly-owned subsidiary of TUC. Immediately prior to ENSERCH's merger with TUC, Enserch Exploration, Inc. (EEX) and Lone Star Energy Plant Operations, Inc. (LSEPO), former subsidiaries of the Corporation, were merged to form a new company (New EEX), and ENSERCH distributed to its common shareholders its ownership interest in these businesses.
TUC accounted for its acquisition of ENSERCH as a purchase. Purchase accounting adjustments, including goodwill, have been pushed down and are reflected in the financial statements of ENSERCH and its subsidiaries for the period subsequent to August 5, 1997. The financial statements of ENSERCH for the periods ended before August 5, 1997 were prepared using ENSERCH's historical basis of accounting and are designated as "Predecessor". The comparability of the operating results for the Predecessor and the periods encompassing push down accounting are affected by the purchase accounting
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adjustments, including the amortization of goodwill over a period of forty years.
The fair value of the assets and liabilities of ENSERCH's rate-regulated natural gas utility business (conducted through its Lone Star Gas Company and Lone Star Pipeline Company divisions) is considered to be equivalent to the historical basis of accounting and accordingly, no adjustment has been made to the carrying value. The process of determining the fair value of assets acquired, liabilities assumed and contingencies existing at the Merger Date was completed in 1998 and resulted in an increase in goodwill of approximately $60 million over the preliminary allocation, primarily due to refinement of estimates of preacquisition contingencies.
The Predecessor financial statements reflect EEX and LSEPO as discontinued operations. The historical financial statements of ENSERCH reflect certain reclassifications made to conform to TUC's presentation style. On December 31, 1997, ENSERCH sold to another subsidiary of TUC, at net book value, the group of companies which had constituted the Corporation's power development and international gas distribution operations. For financial reporting purposes, the sale was deemed to have occurred on August 5, 1997. Accordingly, operating results for periods following the Merger Date exclude those operations. Prior periods were not restated to reflect the sale.
For purposes of the discussion of operating results provided herein, the financial information of the Predecessor for the 1997 periods prior to the Merger Date has been combined with the post-merger financial information. The continuing business operations of ENSERCH were not significantly changed as a result of the merger, and post-merger and pre-merger operating results, except as noted, are comparable.
FINANCIAL CONDITION
Liquidity and Capital Resources
Cash flows provided from operating activities for ENSERCH before changes in operating assets and liabilities for the year ended December 31, 1998 were $102 million compared with $57 million and $75 million for the comparable periods in 1997 and 1996, respectively. Changes in operating assets and liabilities for ENSERCH for the year ended December 31, 1998 used cash of $138 million compared with $69 million for the comparable period in 1997, but provided cash of $30 million for the same period of 1996.
Cash flows used in investing activities for the year ended December 31, 1998 totaled $194 million compared with $125 million for the same period of 1997 and $176 million for 1996. Construction expenditures were $187 million for the current period compared with $119 million and $125 million for the comparable periods in 1997 and 1996, respectively. Other investing activities for 1996 include cash required for investments in unconsolidated affiliates primarily related to international gas distribution operations that were sold to another subsidiary of TUC at the end of 1997.
Discontinued exploration and production operations used cash of $22 million in 1997 and provided cash of $20 million in 1996. The discontinued engineering and construction operations used cash of $3 million in 1998, $13 million in 1997 and $5 million in 1996.
Capital expenditures of the Corporation totaled $187 million in 1998, and expenditures of $117 million are estimated for 1999. Approximately 94% will be spent on US Gas Pipeline and Distribution operations and approximately 6% on US Energy Marketing and other operations.
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Total capitalization at December 31, 1998 was $1.9 billion, up slightly from year-end 1997. The capitalization ratios of the Corporation consisted of approximately 28% long-term debt, 22% advances from parent, 8% ENSERCH trust securities, 4% preferred stock, and 38% common stock equity.
During the year ended December 31, 1998, ENSERCH issued, redeemed, reacquired or made scheduled principal payments on long-term debt, preferred stock and trust securities for cash, as follows:
Early redemptions of preferred stock and long-term debt may occur from time to time in amounts presently undetermined. See Notes 4, 6 and 7 to Consolidated Financial Statements for further details concerning long-term debt, preferred stock and trust securities.
Shortly after the merger with TUC, ENSERCH's commercial paper program and bank lines in the form of a revolving credit agreement were discontinued. ENSERCH retired $204 million of commercial paper outstanding at the Merger Date and $260 million of long-term debt outstanding under the credit agreement, using advances from TUC to fund the retirements. In December 1997, TUC purchased 200,000 additional shares of ENSERCH common stock for $200 million. In February 1999, TUC purchased 250,000 additional shares of ENSERCH common stock for $250 million. These funds were used to reduce borrowings from TUC.
Interest rate swaps effectively fixed the rate on $100 million of the ENSERCH Capital I Trust Securities at 6.629% and at 6.444% on the remaining $50 million of the trust securities to July 1, 2003.
ENSERCH may issue additional debt and equity securities as needed, including the possible future sale of up to $100 million aggregate principal amount of securities that are currently registered with the Securities and Exchange Commission (SEC) for offering pursuant to Rule 415 under the Securities Act of 1933.
At December 31, 1998, TUC, TU Electric and ENSERCH had $3.5 billion of joint US dollar-denominated lines of credit under revolving credit facility agreements (US Credit Agreements) with a group of banking institutions. The US Credit Agreements have two facilities. Facility A provides for short-term borrowings aggregating up to $2.1 billion outstanding at any one time at variable interest rates and terminates February 25, 2000. Of this, $800 million can be used for working capital and other general corporate purposes. Facility B provides for borrowings aggregating up to $1.4 billion outstanding at any one time at variable interest rates and terminates March 2, 2003. Borrowings under this facility can be used for working capital and other general corporate purposes. The combined borrowings of TUC, TU Electric and ENSERCH under both facilities, excluding amounts restricted to finance the acquisition of a non-US subsidiary of TUC, are limited to an aggregate of $2.2 billion outstanding at any one time. ENSERCH's borrowings under both facilities are limited to an aggregate of $650 million outstanding at any one time. The facilities primarily support commercial paper borrowings.
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Quantitative and Qualitative Disclosure About Market Risk
The Corporation's market risk exposure is primarily a result of changes in interest rates and commodity price exposures. Derivative instruments, including options, swaps, futures and other contractual commitments, are used to reduce and manage a portion of those risks. With the exception of the marketing activities of its US Energy Marketing segment, principally Enserch Energy Services, Inc. (EES), the Corporation's participation in derivative transactions is designated for hedging purposes and is not held or issued for trading purposes.
CREDIT RISK -- Credit risk relates to the risk of loss that the Corporation would incur as a result of nonperformance by counterparties to their respective derivative instruments. The Corporation maintains credit policies with regard to its counterparties that management believes significantly minimize overall credit risk. The Corporation generally does not obtain collateral to support the agreements but establishes credit limits and monitors the financial viability of counterparties. In the event a counterparty's credit rating declines, the Corporation may apply certain remedies, if considered necessary. The Corporation believes the risk of nonperformance by counterparties is minimal.
INTEREST RATE RISK -- The table below provides information concerning the Corporation's financial instruments as of December 31, 1998 that are sensitive to changes in interest rates, which include debt obligations (by principal amount) and interest rate swaps. For debt obligations, the table presents principal cash flows and related weighted average interest rates by expected maturity dates. ENSERCH has entered into interest rate swaps under which it has agreed to exchange the difference between fixed-rate and variable-rate interest amounts calculated with reference to specified notional principal amounts. The contracts require settlement of net interest receivable or payable at specified intervals (primarily semi-annually) which generally coincide with the dates on which interest is payable on the underlying debt. For interest rate swaps, the table presents notional amounts and weighted average interest rates by expected (contractual) maturity dates. Weighted average variable rates are based on rates in effect at the reporting date.
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ENERGY MARKETING RISK -- In the course of providing comprehensive energy products and services to its diversified client base, EES engages in energy price risk management activities. In addition to the purchase and sale of these physical commodities, EES enters into futures contracts; swap agreements where settlement is based on the difference between a fixed and floating (index based) price for the underlying commodity; exchange traded options; over-the-counter options, which are settled in cash or the physical delivery of the underlying commodity; exchange-of-futures for physical (EFP) transactions; energy exchange transactions; storage activities; and other contractual arrangements. EES may buy and sell certain of these instruments to manage its exposure to price risk from existing contractual commitments as well as other energy-related assets and liabilities. It may also enter into contracts to take advantage of arbitrage opportunities.
These activities involve price commitments into the future and, therefore, give rise to market risk. EES uses the mark-to-market method of valuing and accounting for these activities.
In order to manage its exposure to the price risk associated with these instruments, EES has established trading policies and limits and revalues its exposures daily against these benchmarks. EES also periodically reviews these policies to ensure they are responsive to changing market and business conditions.
EES utilizes various techniques and methodologies that simulate forward price curves in the energy markets to estimate the size and probability of changes in market value resulting from price movements. These techniques include, but are not limited to, sensitivity analyses. The uses of these methodologies require a number of key assumptions including selection of confidence levels, the holding period of the positions, and the depth and applicability to future periods of historical price information.
The exposure of fixed price natural gas and electric power purchase and sale commitments, and derivative financial instruments, including options, swaps, futures and other contractual commitments, is based on a methodology that uses a five-day holding period and a 95% confidence level. The notional amounts and terms of the portfolio as of December 31, 1998 included financial instruments that provide for fixed price receipts of 2,643 trillion British thermal units equivalent (TBtue) and fixed price payments of 2,799 TBtue, with a maximum term of eight years. Additionally, sales and purchase commitments totaling 973 TBtue, with terms extending up to nine years, are included in the portfolio as of December 31, 1998. EES uses market-implied volatilities to determine its exposure to market risk. Market risk is estimated as the potential loss in fair value resulting from at least a 15% (two standard deviation) change in market factors, which may differ from actual results. Using a two standard deviation change, the most adverse change in fair value at December 31, 1998 and 1997, as a result of this analysis was a reduction of $2.1 million and $1.1 million, respectively.
Regulation and Rates
Under a settlement of the RRC rate inquiry approved in June 1998, Lone Star Gas Company (Lone Star Gas) agreed to credit residential and commercial customers $18 million to be spread over the next two heating seasons (November through March). Earnings were not affected by the settlement due to previously established reserves. The final order approving the stipulation found that all gas costs flowed through Lone Star Gas' monthly gas cost adjustment clause prior to October 31, 1997 were just, reasonable, and necessary. As a part of the final order, the RRC required an audit of an amount that Lone Star Gas credited to residential and commercial customers under a previous voluntary stipulation. The audit report indicated that an additional $7.3 million should be credited to residential and commercial customers. The Corporation believes that the additional amount noted in the audit report was included in the $18 million settlement, but it is unable to predict the outcome of the audit.
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RESULTS OF OPERATIONS
For the year ended December 31, 1998, ENSERCH had a loss from continuing operations of $22 million, compared with a loss of $24 million in 1997 and income of $10 million in 1996. The amortization of goodwill arising from the merger with TUC was $21 million for 1998 and $8 million for 1997. Results for 1998 were unfavorably impacted by milder winter weather in both the first and fourth quarters. The 1997 results were reduced by merger-related expenses of $25 million pretax ($21 million after-tax) and an $8.6 million pretax ($5.6 million after-tax) first quarter provision for a credit Lone Star Pipeline Company made voluntarily to its customers, but were improved by third quarter income of $12.5 million pretax ($8.1 million after-tax) from the sale of interests in cogeneration projects.
Consolidated revenues for 1998 were $4.0 billion compared with $2.6 billion for 1997 and $1.9 billion for 1996. The higher revenues reflect an increase of $1.7 billion in US energy marketing revenues. (The table of Selected Financial Data provides additional information on revenues.) Gas and electricity purchased for resale increased from $2.0 billion in 1997 to $3.5 billion in 1998, reflecting the increase in US energy marketing activities. Operating income was $46 million in 1998 compared with $67 million in 1997 and $105 million in 1996. Lone Star Pipeline operating income decreased $10 million in 1998 from 1997 but increased $10 million in 1997 from 1996. The lower results for 1998 were primarily due to milder winter weather in the first and fourth quarters of 1998. The higher results in 1997, which were after a voluntary refund of $8.6 million made prior to the merger to residential and commercial customers, were primarily attributable to lower operating and maintenance expenses and lower costs of gas lost in transmission. Lone Star Gas operating income decreased $31 million in 1998 from 1997 and $15 million in 1997 from 1996. The 1998 decline from 1997 was primarily due to milder winter weather, while the 1997 decline from 1996 was primarily due to higher operating and maintenance expenses. Natural gas liquids activities reported an increased operating loss of $18 million in 1998 from 1997 and $12 million in 1997 from 1996. Fluctuations in natural gas liquids (NGL) demand, price volatility for NGL products and natural-gas feedstock costs are the major factors that influence financial results in the NGL processing business. US energy marketing activities reported an increase in operating income of $49 million in 1998 from 1997 but a $32 million greater loss in 1997 than in 1996. The 1998 results reflect an increase in US energy marketing activity and margins, partly due to the beginning of electricity marketing in 1998, while the 1997 losses were the result of trading losses, inadequate system infrastructure and costs associated with new systems that were implemented around year-end 1997. Operating income for 1998 and 1997 was also after $21 million and $8 million, respectively, of amortization of goodwill resulting from the merger.
Other income (deductions) - net in 1998 included $3.9 million in investment activity for a non-qualified deferred compensation plan and proceeds from a life insurance policy, while 1997 included $25 million of merger-related expenses partially offset by gains of $2.4 million from the sale of cogeneration plants. Other amounts consisted principally of gains on disposals of assets, less losses from unconsolidated affiliates.
Interest charges for 1998 were $76 million compared with $77 million in both 1997 and 1996. Interest charges for 1998 and 1997 included $16 million and $11 million, respectively, related to advances from TUC.
The extraordinary loss in 1996 of $2.1 million represented a premium incurred in connection with the prepayment of ENSERCH's 9.06% Notes to facilitate the merger with TUC.
For the year ended December 31, 1997, there was a loss from discontinued operations of $225 million, which included a $236 million after-tax impact of a write-down of the carrying value of EEX's oil and gas properties due to the US cost center ceiling limitation at March 31, 1997 and a $10 million ($15 million pre-tax) provision for estimated costs and expenses to wind-up engineering and construction operations. For 1996, discontinued operations had income of $11 million. (See Note 13 to Consolidated Financial Statements).
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YEAR 2000 ISSUES
Year 2000 (Y2K) issues of ENSERCH are being addressed with those of its parent company, TUC. The following disclosure applicable to ENSERCH regarding Y2K issues of TUC's US businesses is excerpted from TUC's Form 10-K for the period ended December 31, 1998 with references in TUC's discussion to "the Company" changed to TUC.
Overview
Many existing computer programs use only the last two digits to identify a year in the date field. Thus, they would not recognize a year that begins with 20 instead of 19. If not corrected, many computer applications could fail or produce erroneous data on or about the year 2000.
TUC began its US efforts to address Y2K issues in 1996 by focusing on information technology mainframe-based application systems (IT Corporate Applications). In early 1997, an infrastructure project to address TUC's information technology related hardware, operating systems and desktop software was begun (IT Infrastructure). In late 1997, a project was begun to address Y2K issues throughout TUC related to embedded systems, such as process controls for energy production and delivery, and business unit owned applications (Non-IT Equipment and Applications).
Applications and equipment in each of these three major initiatives have been inventoried and categorized based on their criticality to TUC's business operations. Assessments of the potential impact due to Y2K issues are essentially complete. This process includes the solicitation of vendor feedback, comparing information with other energy companies, and in many cases internal verification by testing. The remediation and testing work on IT Corporate Applications currently stands at approximately sixty percent complete with the completion of mission critical items scheduled for the end of the first quarter of 1999. The IT Infrastructure project is currently at eighty percent completion. Remediation work on embedded systems is scheduled to be completed by September 1999. A number of tests on production equipment with embedded systems have been performed. TUC will continue to test this equipment throughout the first half of 1999.
Readiness
The IT Corporate Applications remediation and testing activities are approximately sixty percent complete with twenty-five percent of critical applications tested and determined as Y2K compliant. Completion of critical applications testing is scheduled for the end of the first quarter 1999 and remaining applications testing is scheduled for the third quarter.
The IT Infrastructure project involves assessing the compliance of standard computer hardware, network systems including gateways, hubs and routers, telecommunications equipment, operating systems and IT standard software products. Equipment is being individually tested using software products and applicable test procedures. Network system tests have been performed. Eighty percent of the IT Infrastructure is Y2K ready with the remainder scheduled to be ready by the end of the first quarter of 1999. Certain software vendors will not have Y2K ready versions of their products available until the first or second quarter of 1999. These software product upgrades will be tested and implemented during the second quarter of 1999.
Non-IT Equipment and Applications involve the hardware and software products that reside in individual business units. These items include the embedded systems that are used in energy production and delivery, and other processes of TUC. Inventories have been conducted to identify these embedded systems in individual business units. Assessments are substantially complete. Some remediation needs have been identified in various business units as a result of Y2K testing. In most cases, these concern software upgrades that are necessary to ensure that information produced by these
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systems can be efficiently used in TUC's business processes. The upgrades are not required for equipment functionality. These remediation activities are planned for completion by the end of the second quarter of 1999.
TUC is analyzing the potential impact of Y2K compliance efforts of third parties. Over 2,000 suppliers and service providers have been contacted to determine the status of their Y2K efforts. Approximately sixty percent of these vendors have responded. Their responses are being prioritized and the programs and status of the most significant among them are being analyzed in detail. This initial analysis is complete. The more significant interdependencies relate to telecommunications and gas suppliers.
Costs
The costs associated with TUC's Y2K efforts for its US energy businesses are currently estimated to be approximately $36 million (primarily for TU Electric). These costs reflect new, incremental costs and the reallocation of resources in pre-existing maintenance budgets. The costs related to the three major initiatives are estimated to be as follows: IT Corporate Applications - $14 million; IT Infrastructure - $7 million; and Non IT-Equipment and Applications - $15 million. These costs are being expensed as incurred over the period 1996 to 2000; and, a total of approximately $17 million had been expended through December 31, 1998. There can be no assurance that these estimated costs will not increase as TUC's Y2K program continues.
Strategic initiatives were begun in two areas prior to beginning work on the Y2K issue, and the costs for these initiatives are not included in the estimate above. The energy management system for TUC's transmission grid is being replaced. TUC's principal financial and accounting systems have been replaced. Each of these projects will eliminate potential Y2K deficiencies; however, that was not a significant consideration at the time replacement decisions were made.
Risk Issues
With respect to internal risks, TUC's current assessment of the most reasonably likely worst case scenario is that impacts on either service or financial performance will not be materially adverse. TUC believes, based on the results of testing that has already occurred on a large portion of its production equipment with embedded systems, that if any disruption to service occurs, it will be isolated and of short-term duration. TUC continues to collaborate with other major energy suppliers through the joint Electric Power Research Institute's embedded systems project.
As TUC's Y2K program proceeds, TUC will continue to assess its internal and external risks, not all of which are within its control; and it will continue to consider the most reasonably likely worst case scenario. There can be no assurance that all material Y2K risks within TUC's control will have been adequately identified and corrected before the end of 1999. In addition, TUC can make no assurances regarding the Y2K readiness of systems and parties outside its control, or the effect on TUC if those parties are not Y2K compliant.
Contingency Plans
TUC has in place detailed emergency response and disaster recovery plans to ensure high reliability of service to customers. These plans are utilized routinely for abnormal service conditions. These plans have been reviewed to identify required actions specific to the Y2K issue. Draft contingency plans have been developed and were filed with the Public Utility Commission of Texas (PUC) on December 31, 1998. These Y2K contingency plans address both TUC's activities and actions necessary to mitigate the impact of third party disruptions. These contingency plans have been coordinated with those of the Electric Reliability Council of Texas (ERCOT), the regional independent system operator in Texas, and the North American Electric Reliability Council (NERC). Final contingency plans are scheduled to be completed by June 1999.
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CHANGES IN ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) 133, "Accounting for Derivative Instruments and Hedging Activities," is effective for fiscal years beginning after June 15, 1999. This standard requires that all derivative financial instruments be recognized as either assets or liabilities on the balance sheet at their fair values and that accounting for the changes in their fair values is dependent upon the intended use of the derivatives and their resulting designations. The new standard will supersede or amend existing standards which deal with hedge accounting and derivatives. The Corporation has not yet determined the effect adopting this standard will have on its financial statements.
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INDEPENDENT AUDITORS' REPORT
ENSERCH Corporation:
We have audited the accompanying consolidated balance sheets of ENSERCH Corporation and subsidiaries (the Corporation) as of December 31, 1998 and 1997, and the related statements of consolidated income, comprehensive income, cash flows and common stock equity for the year ended December 31, 1998, and the period from August 5, 1997 (acquisition date) to December 31, 1997, and for the Predecessor Company Operations, the period from January 1, 1997 to the acquisition date and for the year ended December 31, 1996. These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We 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, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of ENSERCH Corporation and subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for the above stated periods in conformity with generally accepted accounting principles.
Deloitte & Touche LLP Dallas, Texas March 5, 1999
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ENSERCH CORPORATION AND SUBSIDIARIES (A WHOLLY-OWNED SUBSIDIARY OF TEXAS UTILITIES COMPANY) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BUSINESS, MERGERS AND DISPOSITIONS
ENSERCH Corporation (ENSERCH or the Corporation) is an integrated company focused on natural gas. Substantially all of its business operations consist of the gathering, processing, transmission and distribution of natural gas and the marketing of natural gas and electricity. Businesses and subsidiaries of ENSERCH include Lone Star Gas Company (Lone Star Gas), a gas distribution company in Texas, serving over 1.37 million customers and providing service through over 24,000 miles of distribution mains; Lone Star Pipeline Company (Lone Star Pipeline), which has approximately 7,600 miles of gathering and transmission pipeline in Texas; and subsidiaries engaged in natural gas processing (Enserch Processing, Inc.) and US energy marketing (Enserch Energy Services, Inc.).
On August 5, 1997 (Merger Date or Acquisition Date), the merger transactions involving the former Texas Utilities Company, now known as Texas Energy Industries, Inc., and ENSERCH were completed. All of the common stock of ENSERCH was converted into common stock of a new holding company now known as Texas Utilities Company (TUC), and ENSERCH became a wholly-owned subsidiary of TUC. Immediately prior to ENSERCH's merger with TUC, Enserch Exploration, Inc. (EEX) and Lone Star Energy Plant Operations, Inc. (LSEPO), former subsidiaries of ENSERCH, were merged to form a new company (New EEX), and ENSERCH distributed to its common shareholders its ownership interest in these businesses.
The value of the TUC shares issued and costs incurred by TUC in connection with the acquisition of ENSERCH aggregated $579 million. TUC accounted for its acquisition of ENSERCH as a purchase, and purchase accounting adjustments, including goodwill, have been pushed down and are reflected in the financial statements of ENSERCH and its subsidiaries for the period subsequent to August 5, 1997. The financial statements of ENSERCH for the periods ended before August 5, 1997 were prepared using ENSERCH's historical basis of accounting and are designated as "Predecessor". The comparability of the operating results for the Predecessor and the periods encompassing push down accounting are affected by the purchase accounting adjustments, including the amortization of goodwill over a period of forty years.
The fair value of the assets and liabilities of ENSERCH's rate-regulated natural gas utility business (conducted through its Lone Star Gas Company and Lone Star Pipeline Company divisions) is considered to be equivalent to the historical basis of accounting and accordingly, no adjustment has been made to the carrying value.
The following is a summary of unaudited pro forma results of operations assuming the distribution to shareholders and the Merger with TUC had occurred at the beginning of the periods presented.
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The Predecessor financial statements reflect EEX and LSEPO as discontinued operations. The historical financial statements of ENSERCH reflect certain reclassifications made to conform to TUC's presentation style. Effective August 5, 1997, ENSERCH sold, at net book value to another subsidiary of TUC, the group of companies which had constituted the Corporation's power development and international gas distribution operations. Accordingly, operating results for periods following the Merger Date exclude those operations. Prior periods were not restated to reflect the sale.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER INFORMATION
Consolidation -- The consolidated financial statements include the accounts of the Corporation and its majority owned subsidiaries, including its subsidiary business trust.
All significant intercompany items and transactions have been eliminated in consolidation. Investments in significant unconsolidated affiliates are accounted for by the equity method.
All dollar amounts in the financial statements and notes to consolidated financial statements, except per share amounts, are stated in millions of US dollars unless otherwise indicated.
Use of Estimates -- The preparation of the Corporation's consolidated financial statements requires management to make estimates and assumptions about future events that affect the reporting and disclosure of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense during the periods. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments, other than those disclosed elsewhere herein, were made to previous estimates during the current year.
System of Accounts and Other Policies -- Lone Star Gas and Lone Star Pipeline, are subject to the accounting requirements prescribed by the National Association of Regulatory Utility Commissioners (NARUC). The Corporation applies the principles of Statement of Financial Accounting Standards (SFAS) 71, "Accounting for the Effects of Certain Types of Regulation" to its cost-based regulated operations.
Property, Plant and Equipment -- Gas utility plant is stated at original cost. The cost of property additions to gas utility plant includes labor and materials, applicable overhead and payroll-related costs. Other property is stated at cost.
Depreciation of Property, Plant and Equipment -- The pipeline and distribution systems are depreciated by the straight line method over the estimated useful life of the asset, approximately 30 to 40 years from original acquisition, respectively.
Amortization of Goodwill -- Goodwill represents the excess of the purchase price paid by TUC over the fair value of the ENSERCH assets acquired and liabilities assumed and is being amortized over 40 years. The processes of determining the fair value of assets acquired, liabilities assumed and contingencies existing at the acquisition date of ENSERCH was completed in 1998 and resulted in an overall increase in goodwill of approximately $60 million over the preliminary allocations primarily due to refinement of estimates of preacquisition contingencies.
Revenue Recognition -- Revenues are recognized when services are provided to customers. Lone Star Gas records revenues on the basis of cycle meter readings throughout the month and accrues revenues for gas delivered from the meter reading dates to the end of the month. Revenues include billings under approved rates and adjustments under various mechanisms to recover or refund the cost of fuel purchased that is above or below the level included in base rates. (See Note 15 for discussion of Regulations and Rates.)
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Derivative Instruments -- The Corporation does not enter into or trade derivative financial instruments for speculative purposes, other than for trading purposes in US energy marketing activities. The Corporation enters into interest rate swaps to reduce exposure to interest rate fluctuations. Amounts paid or received under interest rate swap agreements are accrued as interest rates change and are recognized over the life of the agreements as adjustments to interest expense.
Income Taxes -- The Corporation is included in the consolidated federal income tax return of TUC and subsidiary companies, and federal income taxes are allocated to all subsidiary companies based upon their respective taxable income or loss. Investment tax credits are being amortized to income over the estimated service lives of the properties. Deferred federal income taxes are provided for temporary differences between the book and tax basis of assets and liabilities.
Energy Marketing Activities --The Corporation, through its energy marketing subsidiary, Enserch Energy Services, Inc. (EES), enters into a variety of transactions in the US, including forward contracts involving physical delivery of natural gas or electrical power commodities, as well as swaps, futures, options and other derivative contractual arrangements. As part of these business activities, EES offers price risk management services to the energy sector. These transactions are primarily conducted with retail end users, established energy companies and major financial institutions. EES uses the mark-to-market method of valuing and accounting for these activities. Under this method, the current market value of EES' energy portfolio, net of future servicing costs, is reflected within the Corporation's consolidated balance sheets as "Energy Marketing Risk Management Assets" or "Energy Marketing Risk Management Liabilities". Resulting unrealized gains and losses are reflected in the Corporation's consolidated statements of income. The actual timing of cash receipts and payments, however, may vary as contracts may be settled at intervals other than their scheduled maturities. (See Note 8.)
Consolidated Cash Flows -- For purposes of reporting cash and cash equivalents, temporary cash investments purchased with a remaining maturity of three months or less are considered to be cash equivalents.
The schedule below details the Corporation's cash payments and non-cash investing and financing activities:
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3. AFFILIATES
Transactions between ENSERCH, TUC and affiliates of TUC for the year ended December 31, 1998 and the period from Acquisition Date through December 31, 1997 included $16 million and $11 million, respectively, in interest expense related to ENSERCH borrowings from TUC. Texas Utilities Services Inc. billed ENSERCH $55 million and $8 million for the year ended December 31, 1998 and the period from Acquisition Date through December 31, 1997, respectively for financial, accounting, information technology, environmental, customer, procurement and personnel services and other administrative services at costs. ENSERCH was also billed $107 million for the year ended December 31, 1998 from Texas Utilities Electric Company primarily for employee services and expenses at cost. In addition, ENSERCH had revenues of $18 million and $9 million from the sale and transportation of gas to other TUC subsidiaries during the respective periods. The outstanding net amount payable to TUC and related affiliates (including advances) was $447 million at December 31, 1998.
4. BORROWINGS AND LINES OF CREDIT
ENSERCH's commercial paper program was discontinued following the merger with TUC, and the borrowings outstanding at the Merger Date, which totaled $204 million were paid off at maturity with funds advanced to ENSERCH by TUC. In addition, ENSERCH redeemed long-term debt of $260 million outstanding under a revolving credit agreement with funds advanced by TUC. At December 31, 1998, advances from TUC totaled $420 million. Interest on the advances accrues at a rate equal to the weighted average commercial paper rate, 5.96% at December 31, 1998.
At December 31, 1998, TUC, TU Electric and ENSERCH had $3,500 million of joint US dollar-denominated lines of credit under revolving credit facility agreements (US Credit Agreements) with a group of banking institutions. The US Credit Agreements have two facilities. Facility A provides for short-term borrowings aggregating up to $2,100 million outstanding at any one time at variable interest rates and terminates February 25, 2000. Of this, $800 million can be used for working capital and other general corporate purposes. Facility B provides for borrowings aggregating up to $1,400 million outstanding at any one time at variable interest rates and terminates March 2, 2003. Borrowings under this facility can be used for working capital and other general corporate purposes. The combined borrowings of TUC, TU Electric and ENSERCH under both facilities, excluding amounts restricted to finance the acquisition of a non-US subsidiary by TUC, are limited to an aggregate of $2,200 million outstanding at any one time. ENSERCH's borrowings under both facilities are limited to an aggregate of $650 million outstanding at any one time. The facilities primarily support commercial paper borrowings. At December 31, 1998, ENSERCH had no borrowings outstanding under these facilities.
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The carrying value of ENSERCH debt was adjusted to reflect fair value as of the Merger date.
In July 1998, the interest rate on the Remarketed Reset Notes was reset to a fixed rate of 6.56% payable until July 1, 2005.
ENSERCH may issue additional debt and equity securities as needed, including the possible future sale of up to $100 million aggregate principal amount of securities that are currently registered with the Securities and Exchange Commission (SEC) for offering pursuant to Rule 415 under the Securities Act of 1933.
In September 1996, the Corporation paid off the outstanding balance of the 9.06% Notes due through 1999, including a prepayment premium of $3.2 million ($2.1 million after-tax) which has been accounted for as an extraordinary loss on early extinguishment of debt.
5.COMMON STOCK EQUITY
Common Stock -- On August 5, 1997, ENSERCH became a wholly owned subsidiary of TUC. At the effective time of the merger, each of the 1,000 outstanding shares of common stock of ENSERCH Merger Corp. (a transitory corporation organized to facilitate the merger) was converted to one share of ENSERCH Corporation Common Stock (ENSERCH common stock). All of the shares of ENSERCH common stock outstanding prior to the effective time of the merger were converted to shares of TUC and, upon conversion, were canceled and ceased to exist. Accordingly, at August 5, 1997, the outstanding common stock of ENSERCH consisted of 1,000 shares, par value $0.01 per share, all of which were owned by TUC.
In December 1997, TUC purchased an additional 200,000 shares for $200 million. In February 1999, TUC purchased 250,000 shares for $250 million, and ENSERCH used the proceeds to repay intercompany advances from TUC.
At the special shareholders meeting held on November 15, 1996, shareholders of the Corporation approved a change in the par value of ENSERCH common stock from $4.45 per share to $.01 per share to facilitate the distribution of the Corporation's interest in EEX. The reduction in par value was recorded by the transfer of $312 million to the paid-in-capital account.
Effective with the merger, outstanding options for ENSERCH common stock were exchanged for options for 532,913 shares of TUC common stock exercisable at prices ranging from $7.03 to $37.71 per share. The estimated fair value of these options of $3.2 million was accounted for as a part of the cost of the acquisition. At December 31, 1998, 260,151 of these options remained outstanding and exercisable. Prior to the Merger, the Corporation had three fixed option plans. Stock options had been awarded to key employees and were outstanding under all three plans. Options generally expire ten years after the date of the grant.
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6. PREFERRED STOCK
In January 1998, the Corporation redeemed all of the outstanding shares of its Adjustable Rate Preferred Stock, Series E, at $1,000 per share, plus accrued and unpaid dividends of $14.777 per share.
The Series F stock is redeemable at stated value after May 1, 1999. Holders of the preferred stock are entitled to its stated value upon involuntary liquidation.
Dividend rates for the Series F Stock are determined quarterly, in advance, based on 87% of the "Applicable Rate" (highest of the three-month US Treasury bill rate, the US Treasury ten-year constant maturity rate and either the US Treasury twenty-year or thirty-year constant maturity rate, as defined) with a minimum rate of 4.50% and a maximum rate of 10.50%.
Dividends Declared:
7. ENSERCH OBLIGATED, MANDATORILY REDEEMABLE, PREFERRED SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF ENSERCH (TRUST SECURITIES)
In July 1998, a wholly-owned statutory business trust, ENSERCH Capital I, established as a financing subsidiary of ENSERCH for the purpose of issuing trust securities and holding Junior Subordinated Debentures of ENSERCH, issued $150 million of floating rate trust securities which have a liquidation preference of $1,000 per unit. Distributions on these trust securities are payable quarterly based on an annual floating rate determined quarterly with reference to a three-month LIBOR plus a margin. The only assets held by the trust are $154.6 million principal amount of Floating Rate Junior Subordinated Debentures Series A (Series A Debentures) of ENSERCH. The interest on the Series A Debentures matches the distributions on the Trust Securities. The Series A Debentures will mature on July 1, 2028 and ENSERCH has the right to redeem the Series A Debentures and the Trust Securities in whole or in part on or after July 1, 2003. ENSERCH owns the securities issued by its subsidiary trust and has effectively issued a full and unconditional guarantee of the trust's securities.
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In 1998, interest rate swaps were entered into which effectively fixed the rate on $100 million notional amount of the Trust Securities at 6.629% and at 6.444% on the remaining $50 million of the Trust Securities to July 1, 2003.
8. DERIVATIVE INSTRUMENTS
The Corporation does not enter into or trade derivative financial instruments for speculative purposes, other than for trading purposes in US energy marketing activities. The Corporation enters into interest rate swaps to reduce exposure to interest rate fluctuations. Amounts paid or received under interest rate swap agreements are accrued as interest rates change and are recognized over the life of the agreements as adjustments to interest expense.
Interest Rate Risk Management -- At December 31, 1998, ENSERCH had two interest rate swap agreements with respect to floating rate trust securities of ENSERCH Capital I, with notional principal amounts of $100 million and $50 million, respectively, that effectively fixed the rate at 6.629% and 6.444%, respectively, per annum to July 1, 2003.
US Energy Marketing Activities -- In the course of providing comprehensive energy products and services to its diversified client base, EES engages in energy price risk management activities. In addition to the purchase and sale of these physical commodities, EES enters into futures contracts; forward commitments; swap agreements where settlement is based on the difference between a fixed and floating (index-based) price for the underlying commodity; exchange traded options; over-the-counter options, which are settled in cash or the physical delivery of the underlying commodity; exchange-of-futures for physical transactions; energy exchange transactions; storage activities; and other contractual arrangements. EES may buy and sell certain of these instruments to manage its exposure to price and basis risk from existing contractual commitments as well as other energy-related assets and liabilities. It may also enter into contracts to take advantage of arbitrage opportunities.
EES utilizes various techniques and methodologies that simulate forward price curves in the energy markets to estimate the size and probability of changes in market value resulting from price movements. These techniques include, but are not limited to, sensitivity analyses. The uses of these methodologies require a number of key assumptions including selection of confidence levels, the holding period of the positions, and the depth and applicability to future periods of historical price information.
EES has a number of risks and costs associated with the future contractual commitments included in its energy portfolio, including price risk, credit risks associated with the financial condition of counterparties, product location (basis) differentials, market liquidity and other risks that management policies dictate. EES continuously monitors the valuation of identified risk and adjusts the portfolio valuation based on present market conditions. Reserves are established in recognition that certain risks exist until delivery of energy has occurred, counterparties have fulfilled their financial commitments and related financial instruments mature or are closed out.
In order to manage its exposure to the price risk associated with these instruments, EES has established trading policies and limits and revalues its exposures daily against these benchmarks. These policies are periodically reviewed to ensure they are responsive to changing market and business conditions.
EES' energy portfolio is comprised of forward commitments, futures, swaps, options and other derivative instruments related to natural gas and electricity marketing activities. The notional amounts and terms of the portfolio as of December 31, 1998 included financial instruments that provide for fixed price receipts of 2,643 trillion British thermal units equivalent (TBtue) and fixed price payments of 2,799 TBtue, with a maximum term of eight years. Additionally, sales and purchase commitments totaling 973 TBtue, with terms extending up to nine years, are included in the portfolio as of December 31, 1998.
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Notional amounts reflect the volume of transactions but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, the notional amounts represented above do not necessarily measure EES' exposure to market or credit risks. Additionally, the maximum term in years is not indicative of likely future cash flows as these positions may be offset in the markets at any time in response to EES' risk management needs.
The following table displays the mark-to-market values of EES's energy marketing risk management assets and liabilities at December 31, 1998 and 1997 and the average value for the year ended December 31, 1998 and the period from August 5, 1997 through December 31, 1997:
EES recorded net trading gains (losses) of $46 million and $(0.3) million from energy marketing activities for the year ended December 31, 1998 and for the period from August 5, 1997 through December 31, 1997, respectively.
Credit Risk -- Credit risk relates to the risk of loss that the Corporation would incur as a result of nonperformance by counterparties to their respective derivative instruments. The Corporation maintains credit policies with regard to its counterparties that management believes significantly minimize overall credit risk. The Corporation generally does not obtain collateral to support the agreements but establishes credit limits and monitors the financial viability of counterparties. In the event a counterparty's credit rating declines, the Corporation may apply, certain remedies if considered necessary. The Corporation believes the risk of nonperformance by counterparties is minimal.
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9. INCOME TAXES
Income Tax Expense (Benefit) of Continuing Operations:
Reconciliation of Income Taxes (Benefit) Computed at the Federal Statutory Rate to Income Tax Expense (Benefit) of Continuing Operations:
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Deferred income taxes provided by the liability method for significant temporary differences based on tax laws and statutory rates in effect at the December 31, 1998 and 1997 balance sheet dates are as follows:
At December 31, 1998, domestic net operating-loss (NOL) carryforwards totaled $420 million, which begin to expire in 2003, and alternative minimum tax-credit carryforwards totaled $9 million. The tax benefits of these carryforwards of $156 million, as shown above, are available to offset future tax payments. A deferred tax asset valuation allowance of $10 million has been recorded at December 31, 1998 for the NOL carryforwards. At December 31, 1998, ENSERCH also had $17 million of general business credit carryforwards which begin to expire in 1999. As a result of limitations on the timing of use arising from the Merger, ENSERCH does not expect to fully utilize such tax credit carryforwards prior to their expiration date; therefore, such credits were written off as a purchase accounting adjustment in 1997.
Separately, the ENSERCH consolidated income tax returns have been audited and settled with the Internal Revenue service (IRS) through the year 1992. The IRS is currently auditing the years 1993 through 1997. To the extent that adjustments to income tax accounts for periods prior to the Merger are required as a result of an IRS audit, the adjustment will be added to or deducted from goodwill.
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10. EMPLOYEE BENEFIT PLANS
Pension Plan -- At the date of the merger, ENSERCH had a defined benefit pension plan providing retirement income benefits for substantially all of its employees. Effective January 1, 1998, the ENSERCH qualified retirement plan was merged into another retirement plan of TUC which covers TUC employees and certain other subsidiaries. Accrued retirement costs are funded to the extent such amounts are deductible for federal income tax purposes. Plan assets consist primarily of equity investments, government bonds and corporate bonds. Benefits are based on years of credited service and average compensation and were not affected by the plan merger.
In connection with the merger, certain employees of ENSERCH were offered and accepted an early retirement option.
The following tables provide information for the Corporation's participation in TUC's plan, using actuarial allocations for 1998.
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The following table provides information for the TUC defined benefit pension plan in which the Corporation and certain other subsidiaries of TUC participate:
Year Ended December 31, ----------- Components of Net Pension Costs: Service cost . . . . . . . . . . . . . . . . . . . . . . . . $ 15 Interest cost. . . . . . . . . . . . . . . . . . . . . . . . 44 Expected return on assets. . . . . . . . . . . . . . . . . . (46) Amortization of unrecognized net transition asset. . . . . . (1) ------- Net periodic pension cost. . . . . . . . . . . . . . . . $ 12 =======
Change in Pension Obligation: Pension obligation at beginning of period. . . . . . . . . . $ 640 Service cost . . . . . . . . . . . . . . . . . . . . . . 15 Interest cost . . . . . . . . . . . . . . . . . . . . . . 44 Plan amendments . . . . . . . . . . . . . . . . . . . . . (1) Actuarial loss. . . . . . . . . . . . . . . . . . . . . . 7 Benefits paid . . . . . . . . . . . . . . . . . . . . . . (27) ------- Pension obligation at end of period. . . . . . . . . . . . . $ 678 ======= Change in Plan Assets: Fair value of assets at beginning of period. . . . . . . . . $ 569 Actual return on assets . . . . . . . . . . . . . . . . . 69 Employer contributions. . . . . . . . . . . . . . . . . . 49 Benefits paid . . . . . . . . . . . . . . . . . . . . . . (28) ------- Fair value of assets at end of period. . . . . . . . . . . . $ 659 ======= Funded Status: Pension obligation . . . . . . . . . . . . . . . . . . . . . $ (678) Fair value of assets . . . . . . . . . . . . . . . . . . . . 659 Unrecognized net transition asset. . . . . . . . . . . . . . (2) Unrecognized prior service costs . . . . . . . . . . . . . . (2) Unrecognized net loss. . . . . . . . . . . . . . . . . . . . (32) ------- Accrued pension costs. . . . . . . . . . . . . . . . . . . . $ (55) ======= Weighted-average assumptions: Discount rate. . . . . . . . . . . . . . . . . . . . . . . . 7.0% Expected return on plan assets . . . . . . . . . . . . . . . 9.0% Rate of compensation increase. . . . . . . . . . . . . . . . 4.3%
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Postretirement Benefits Other than Pensions -- In addition to the retirement plan, ENSERCH offers certain health care and life insurance benefits to substantially all employees and their eligible dependents at retirement. In connection with the merger, the plan was amended to provide coverage to those employees hired after July 1, 1989 not previously eligible for postretirement medical benefits. In addition, the health care benefits provided to retirees under the plan were enhanced to reflect the same level of benefits as offered by other such plans of TUC companies. The unrecognized prior service cost at December 31, 1997 arose from these two changes which occurred after the Merger Date. Effective January 1, 1998, the ENSERCH postretirement benefit plan was merged into the postretirement benefit plan of TUC. Obligations have not been prefunded. Benefits received vary in level depending on years of service and retirement dates. The following tables provide information for the Corporation's participation in TUC's plan, using actuarial allocations for 1998.
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The expected increase in costs of future benefits covered by the postretirement benefit plan is projected using a health care cost trend rate of 5% in 1999 and thereafter. A one percentage point increase in the assumed health care cost trend rate in each future year would increase the accumulated postretirement benefit obligation at December 31, 1998 by approximately $12.3 million and other postretirement benefits cost for 1998 by approximately $1.8 million.
The following table provides information for the TUC postretirement benefit plan in which the Corporation and certain other subsidiaries of TUC participate:
Year Ended December 31, -----------
Components of Net Periodic Postretirement Benefit Costs: Service cost . . . . . . . . . . . . . . . . . . . . . . . . . . $ 8 Interest cost. . . . . . . . . . . . . . . . . . . . . . . . . . 15 Expected return on assets. . . . . . . . . . . . . . . . . . . . (2) Amortization of unrecognized net transition obligation . . . . . 3 Amortization of unrecognized prior service costs . . . . . . . . 2 Amortization of net loss . . . . . . . . . . . . . . . . . . . . 1 ------- Net periodic postretirement benefit cost . . . . . . . . . . $ 27 ======= Change in Postretirement Benefit Obligation: Benefit obligation at beginning of period. . . . . . . . . . . . $ 214 Service cost . . . . . . . . . . . . . . . . . . . . . . . . 8 Interest cost . . . . . . . . . . . . . . . . . . . . . . . . 15 Participant contributions . . . . . . . . . . . . . . . . . . 2 Actuarial loss. . . . . . . . . . . . . . . . . . . . . . . . 7 Benefits paid . . . . . . . . . . . . . . . . . . . . . . . . (9) ------- Benefit obligation at end of period. . . . . . . . . . . . . . . $ 237 ======= Change in Plan Assets: Fair value of assets at beginning of period. . . . . . . . . . . $ 30 Actual return on plan assets. . . . . . . . . . . . . . . 5 Employer contributions. . . . . . . . . . . . . . . . . . 12 Benefits paid . . . . . . . . . . . . . . . . . . . . . . (6) ------- Fair value of assets at end of period. . . . . . . . . . . . . . $ 41 ======= Funded Status: Benefit obligation . . . . . . . . . . . . . . . . . . . . . . . $ (237) Fair value of assets . . . . . . . . . . . . . . . . . . . . . . 41 Unrecognized transition obligation . . . . . . . . . . . . . . . 18 Unrecognized prior service costs . . . . . . . . . . . . . . . . 17 Unrecognized net loss. . . . . . . . . . . . . . . . . . . . . . 25 ------- Accrued postretirement benefit costs . . . . . . . . . . . . . . $ (136) ======= Weighted-average assumptions: Discount rate. . . . . . . . . . . . . . . . . . . . . . . . . . 7.00% Expected return on plan assets . . . . . . . . . . . . . . . . . 8.13%
11. COMMITMENTS AND CONTINGENCIES
Legal Proceedings -- On October 30, 1995, a lawsuit was filed in the Supreme Court of Western Australia by Woodside Petroleum Ltd. and its joint venture partners against the Corporation, a former subsidiary of the Corporation and others. Plaintiffs seek damages of approximately $18 million from the Corporation based on an indemnity arrangement and approximately $208 million from the other defendants for alleged breaches of contract and
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breaches of a trade practice act, all in connection with the construction of an offshore gas and condensate drilling production platform. The Corporation has agreed to indemnify the current owner of the former subsidiary pursuant to the provisions in the prior sales agreement. Following a preliminary hearing, the Court, on December 4, 1997, delivered an opinion in favor of the Corporation, the former subsidiary and the other defendants finding that the defendants are other assureds under certain insurance policies owned by the plaintiffs and that the plaintiffs and their insurers are precluded from bringing a subrogated claim against the defendants. On April 29, 1998, the court entered a final judgment. The plaintiff's lawsuit was dismissed as well as the counterclaims of the defendants. The plaintiffs served their notice of appeal on May 19, 1998. The appeal was heard by the Full Court of the Supreme Court of Western Australia beginning February 1, 1999. In March 1999, the Full Court of the Supreme Court entered a judgment dismissing the plaintiffs' appeal. The plaintiff are expected to seek special leave to perfect a further appeal to the High Court of Australia.
In August 1998, the Gracy Fund, L.P. (Gracy Fund) filed suit in the United States District Court for the Northern District of Texas against EEX Corporation, formerly Enserch Exploration, Inc. (EEX), TUC, David W. Biegler, Gary J. Junco, Erle Nye, Thomas Hamilton and J. Phillip McCormick. The Gracy Fund sought to represent a class comprised of all purchasers of the common stock of ENSERCH or EEX between January 26, 1996 and August 4, 1997, including former shareholders of ENSERCH who received shares of EEX and TUC pursuant to the merger agreement between ENSERCH and TUC dated April 13, 1996, all EEX shareholders solicited pursuant to a proxy statement/prospectus issued by EEX dated October 2, 1996 and all ENSERCH shareholders solicited by a joint proxy statement/prospectus issued by ENSERCH and TUC dated September 23, 1996. The Gracy Fund alleged that the defendants participated in a fraudulent scheme and course of business by disseminating materially false and misleading statements regarding EEX's and ENSERCH's business, which allegedly caused the plaintiffs and other members of the class to purchase EEX and ENSERCH stock at artificially inflated prices. In such connection, the plaintiffs alleged that the defendants violated various provisions of the Securities Act of 1933 and the Securities and Exchange Act of 1934 (Exchange Act).
Also in August, 1998, Stan C. Thorne (Thorne) filed suit in the United States District Court for the Southern District of Texas against EEX, ENSERCH, DeGolyer & MacNaughton, David W. Biegler, Gary J. Junco, Fredrick S. Addy and B. K. Irani. Thorne sought to represent a class comprised of all purchasers of the common stock of EEX during the period of August 3, 1995 through August 5, 1997. Thorne alleged that the defendants engaged in a course of conduct designed to mislead the plaintiff and investing public in order to maintain the price of EEX common stock at artificially high levels through false and misleading representations concerning the gas reserves of EEX in violation of Sections 10(b) and 20(a) of the Exchange Act and Rule 10b-5 thereunder. Thorne also alleged that the defendants were negligent in making such misrepresentations and that they constituted common law fraud against the defendants.
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In December 1998, the United States District Court for the Northern District of Texas issued an Order in Cause No. 3-98-CV-1808-G consolidating the Gracy Fund and the Thorne suits (the Consolidated Action). On January 22, 1999, the Gracy fund, et al filed an amended class action complaint in the Consolidated Action against EEX, ENSERCH, David W. Biegler, Gary J. Junco, Thomas Hamilton, J. Phillip McCormick, Fredrick S. Addy and B. K. Irani. TUC and Erle Nye were omitted as defendants pursuant to the tolling agreement. The individual named defendants in the amended complaint are current or former officers and/or directors of EEX and Mr. Biegler has been an officer and director of ENSERCH. The amended complaint alleges violations of provisions of the Securities Act of 1933 and the Exchange Act. The state law claims alleged in Thorne have been omitted. The class period was amended to include those persons acquiring stock of ENSERCH and/or EEX between August 3, 1995 and August 5, 1997, inclusive. No amount of damages has been specified in the Consolidation Action. ENSERCH is continuing to evaluate these claims and is unable at this time to predict the outcome of this proceeding, but it intends to vigorously defend this suit.
Management of the Corporation believes it has meritorious defenses to the claims made in these and other actions brought in the ordinary course of business. In the opinion of management, the Corporation will incur no liability from these and all other pending claims and suits that is material for financial reporting purposes.
Environmental Matters -- The Corporation is subject to federal, state and local environmental laws and regulations that regulate the discharge of materials into the environment. Environmental expenditures are expensed or capitalized depending on their future economic benefit. The level of future expenditures for environmental matters, including costs of obtaining operating permits, equipment monitoring and modifications under the Federal Clean Air Act, as amended and cleanup obligations, cannot be fully ascertained until the regulations that implement the applicable laws have been approved and adopted. It is management's opinion that all such costs, when finally determined, will not have a material adverse effect on the consolidated financial position, results of operations or cash flows of the Corporation.
Leases -- Rental expenses for continuing operations incurred under all operating leases aggregated $5 million in 1998, $3 million for the pre-and post-merger periods of 1997, and $4 million in 1996. Rental income received for subleased office space was $5 million in 1998, $2 million in 1997 and $3 million in 1996. After 1998, the Corporation has no significant commitments under operating leases.
Gas-Purchase Contracts -- Lone Star Gas buys gas under long-term and short-term, intrastate contracts in order to assure a reliable supply to its customers. Many of these contracts require minimum purchases of gas. Lone Star Gas has made accruals for payments that may be required for settlement of gas-purchase contract claims asserted or that are probable of assertion. Lone Star Gas continually evaluates its position relative to asserted and unasserted claims, above-market prices or future commitments. Management believes that Lone Star Gas has not incurred losses for which reserves should be provided at December 31, 1998. Based on estimated gas demand, which assumes normal weather conditions, requisite gas purchases are expected to substantially satisfy purchase obligations for the year 1999 and thereafter.
Sales of Accounts Receivable -- ENSERCH has facilities with financial institutions whereby it is entitled to sell and such financial institutions may purchase, on an ongoing basis, undivided interests in customer accounts receivables representing up to an aggregate of $100 million. Additional receivables are continually sold to replace those collected. At December 31, 1998, accounts receivable of ENSERCH companies were reduced by $100 million to reflect the sales of such receivables under such agreements.
Guarantees -- The Corporation and/or its subsidiaries are the guarantor on various commitments and obligations of others aggregating some $30 million at December 31, 1998. The Corporation is exposed to loss in the event of nonperformance by other parties. However, the Corporation does not anticipate nonperformance by the counterparties.
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Concentrations of Credit Risk -- Lone Star Gas operations have trade receivables from a few large industrial customers in north central Texas arising from the sale of natural gas. A change in economic conditions may affect the ability of customers to meet their contractual obligations. The Corporation believes that its provision for possible losses on uncollectible accounts receivable is adequate for its credit loss exposure.
12.FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and related estimated fair values of the Corporation's significant financial instruments at December 31, 1998 and 1997 were as follows:
The fair values of other financial instruments for which carrying amounts and fair values have not been presented are not materially different than their related carrying amounts.
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13. DISCONTINUED OPERATIONS
In connection with the merger of ENSERCH with TUC, EEX and LSEPO were merged to form New EEX, and ENSERCH distributed to its common shareholders its ownership interest in New EEX, which was represented by approximately 105 million shares of New EEX common stock with a carrying value of $583 million. In the distribution, which was tax free to the recipients, ENSERCH shareholders of record on August 4, 1997 received approximately 1.5 shares of New EEX common stock for each share of ENSERCH common stock owned. ENSERCH's financial statements for all periods presented have been restated to reflect EEX and LSEPO as discontinued operations. ENSERCH's discontinued operations also include its engineering and construction and environmental businesses, the principal assets of which were sold in prior years. The results of operations of ENSERCH's discontinued businesses were as follows:
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Loss provisions of $9.7 million in 1997 and $1.6 million in 1996 after-tax were recorded in recognition that certain claims and accounts receivable were settled at amounts less than previously estimated and costs and expenses incurred for the windup of discontinued engineering and construction businesses would be greater than previously estimated.
At December 31, 1998, discontinued engineering and construction businesses had assets of $51 million, consisting principally of retained claims and accounts receivable of the Ebasco and Enserch Environmental business units, and current and other liabilities and reserves of $30 million. The Corporation has filed suit against certain parties to recover amounts outstanding. Management believes that adequate provision for uncollectible claims and accounts receivable, income-tax matters and expenses for windup of discontinued engineering and construction operations has been made.
14.CHANGES IN ACCOUNTING STANDARDS
SFAS 133, "Accounting for Derivative Instruments and Hedging Activities," is effective for fiscal years beginning after June 15, 1999. This standard requires that all derivative financial instruments be recognized as either assets or liabilities on the balance sheet at their fair values and that accounting for the changes in their fair values is dependent upon the intended use of the derivatives and their resulting designations. The new standard will supersede or amend existing standards which deal with hedge accounting and derivatives. The Corporation has not yet determined the effect adopting this standard will have on its financial statements.
15.REGULATIONS AND RATES
The city gate rate for the cost of gas Lone Star Gas ultimately delivers to residential and commercial customers is established by the Railroad Commission of Texas (RRC) and provides for full recovery of the actual cost of gas delivered, including out-of-period costs such as gas purchase contract settlement costs. The rates Lone Star Gas charges its residential and commercial customers are established by the municipal governments of the cities and towns served, with the RRC having appellate jurisdiction. The rate Lone Star Pipeline charges to Lone Star Gas for transportation and storage of gas ultimately consumed by residential and commercial customers is established by the RRC.
Under a settlement of the RRC rate inquiry approved in June 1998, Lone Star Gas Company (Lone Star Gas) agreed to credit residential and commercial customers $18 million to be spread over the next two heating seasons (November through March). Earnings were not affected by the settlement due to previously established reserves. The final order approving the stipulation found that all gas costs flowed through Lone Star Gas' monthly gas cost adjustment clause prior to October 31, 1997 were just, reasonable, and necessary. As a part of the final order, the RRC required an audit of an amount that Lone Star Gas credited to residential and commercial customers under a previous voluntary stipulation. The audit report indicated that an additional $7.3 million should be credited to residential and commercial customers. The Corporation believes that the additional amount noted in the audit report was included in the $18 million settlement, but it is unable to predict the outcome of the audit.
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16.SUPPLEMENTARY FINANCIAL INFORMATION
QUARTERLY RESULTS (UNAUDITED) -- The results of operations by quarters are summarized below. In the opinion of the Corporation's management, all adjustments (consisting only of normal recurring accruals) necessary for a fair presentation have been made.
17. SEGMENT INFORMATION
The Corporation's reportable segments are strategic business units that offer different products and services or are geographically integrated. They are managed separately because each business requires different marketing strategies or is in a different geographic area.
The Corporation has two reportable operating segments:
(1) US Gas Pipeline and Distribution - operations engaged in the gathering, processing, transmission, and distribution of natural gas and selling of natural gas liquids primarily within Texas (principally Lone Star Gas, Lone Star Pipeline and Enserch Processing, Inc.);
(2) US Energy Marketing - operations engaged in the purchasing and selling of natural gas and electricity and providing risk management services for the energy industry throughout the US (EES); and
Other - non-segment operations consist of liquified and compressed natural gas fuels (primarily the Alternative Fuel Division of ENSERCH).
The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Corporation evaluates performance based on net income or loss. The Corporation accounts for intersegment sales and transfers as if the sales or transfers were to third parties, that is, at current market prices.
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