Item 1. BUSINESS
LEGAL ENTITIES
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
Texas Utilities Company (TUC or the Company), a Texas corporation, is a holding company whose principal United States (US) operations are conducted through Texas Utilities Electric Company (TU Electric), ENSERCH Corporation (ENSERCH), and Texas Energy Industries, Inc. (TEI). Its principal international operations are conducted through TU International Holdings Limited (TU International Holdings), whose principal operating subsidiaries include Eastern Group plc (a subsidiary of TXU Eastern Holdings Limited) (Eastern Group) in the United Kingdom (UK) and Eastern Energy Limited (Eastern Energy) in Australia. Through its subsidiaries, the Company 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, UK and Australia. Additional information concerning subsidiaries and divisions follows. The Company and its subsidiaries possess all necessary franchises, licenses and certificates to enable them to conduct their respective businesses.
For financial reporting and other purposes, the Company is treated herein as the successor to TEI, the holding company for the US businesses prior to the August 5, 1997 acquisition of ENSERCH. TEI was organized in 1945 and, prior to August 5, 1997, was known as Texas Utilities Company. Unless otherwise specified, all references to the Company which relate to a period prior to the ENSERCH acquisition shall be deemed to be references to TEI. In December 1998, TEI transferred ownership of TU Electric to the Company.
At December 31, 1998, the Company and its direct and indirect wholly-owned subsidiaries had 22,055 full-time employees.
Mergers and Acquisitions
Certain comparisons in this report have been affected by the May 1998 acquisition of The Energy Group PLC (TEG), the August 1997 acquisition of ENSERCH, and the November 1997 acquisition of Lufkin-Conroe Communications Co. (LCC) by the Company. In December 1995, the Company, through an indirect subsidiary, Texas Utilities Australia Pty. Ltd. (TU Australia), acquired Eastern Energy. Each of these acquisitions was accounted for as a purchase business combination. The results of operations of each acquired company are included in the consolidated financial statements of the Company only for the periods subsequent to their respective dates of acquisition.
In March 1998, the Company made an offer for all the ordinary shares of TEG. The Company's offer for TEG was declared unconditional on May 19, 1998, which was determined to be the date the Company acquired TEG. By the end of August 1998, the Company had acquired all of TEG's outstanding shares. The Company recorded its approximate 22% equity interest in the net income of TEG for the period March 1998 to May 19, 1998 and has accounted for TEG and Eastern Group as consolidated subsidiaries since May 19, 1998.
In October 1998, the Company completed a restructuring of its ownership of TEG, so that TU Acquisitions Limited (TU Acquisitions), an indirect subsidiary of the Company, owned Eastern Group through another wholly-owned subsidiary. In February 1999, that ownership was transferred to TU International Holdings, a newly formed holding company for TUC's UK/Europe and Australian companies. TEG has been re-registered as a private limited company incorporated in England and Wales and is now known as Energy Holdings (No. 3) Limited.
Immediately prior to being acquired by the Company, TEG completed the sale of its US and Australian coal business and US energy marketing operations (Peabody Sale). The TEG businesses acquired by TUC, which exclude those representing the Peabody Sale, are referred to as "TEG Businesses Acquired". The total purchase consideration for the TEG Businesses Acquired was approximately $7.4 billion, including cash paid of $5.8 billion and non-cash consideration of $1.6 billion, which consists primarily of the value assigned to the 37,316,884 shares of TUC common stock issued to those holders of TEG shares who elected to receive shares of TUC common stock in exchange for their TEG shares. At the date of the acquisition, TEG had assets of $10.4 billion, including cash of $3.3 billion, and liabilities of $8.4 billion including a provision for unfavorable contracts and leases and $5.1 billion in debt. The process of determining the fair value of assets acquired and liabilities assumed of TEG has not been completed; however, the excess of the purchase consideration plus acquisition costs over a preliminary estimate of net fair value of tangible and identifiable intangible assets acquired and liabilities assumed resulted in goodwill of $5.4 billion, which is being amortized over 40 years. This amount is subject to revision as additional information about the fair value of TEG's assets acquired, liabilities assumed and contingencies existing at the acquisition date becomes known. In particular, there is uncertainty over the valuation of the electricity distribution system including metering assets pending finalization of the current distribution price review and the intention that the metering business market becomes competitive in 2000. In addition, there is uncertainty over the final settlement price of the Peabody Sale and the outcome of certain proceedings concerning the pension scheme.
On August 5, 1997, the merger transactions involving the former Texas Utilities Company, now known as TEI, and ENSERCH were completed. On November 21, 1997, the Company acquired LCC. The assets and liabilities of each acquired company, at the respective acquisition date, were adjusted to their estimated fair values. For each company acquired, the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed was recorded as goodwill and is being amortized over 40 years. The process of determining the fair value of assets acquired, liabilities assumed and contingencies existing at the acquisition dates of ENSERCH and LCC 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.
The following summary of unaudited pro forma consolidated results of the Company's operations reflects the operations of the TEG Businesses Acquired, ENSERCH and LCC as though each acquisition had occurred at the beginning of each period presented. Expenses of the acquisitions incurred by the Company, the 22% equity in earnings of TEG and a one-time windfall tax imposed on TEG have been eliminated. Amounts are in millions of dollars, except per share amounts.
The above pro forma results are based on the most current estimate of the fair value of assets acquired, liabilities assumed and contingencies existing as of the acquisition dates of the TEG Businesses Acquired for the 1998 period and ENSERCH and LCC for the 1997 period. These results are not necessarily indicative of what the actual results would have been had the acquisitions occurred at the beginning of these periods. Further, the pro forma results are not intended to be a projection of the future results of the combined companies.
On February 24, 1999, TU Australia acquired from the Government of Victoria, Australia the gas retail business of Kinetik Energy, which has approximately 400,000 gas customers, and the gas distribution operations of Westar, which are of similar size. The purchase price was $1.0 billion which has been principally financed through banks by the Australian holding company for the Company's Australian operations. A portion of the financing was provided by a six-month subordinated credit facility guaranteed by the Company. The Company will pursue potential investment opportunities from time to time when it concludes that such investments are consistent with its business strategies and are likely to enhance the long-term return to its shareholders.
Throughout this document, references to TEG shall mean the consolidated UK entity acquired in May 1998, and Eastern Group or Eastern Electricity shall mean the Company's primary continuing operations in the UK and other parts of Europe subsequent to organizational restructuring of UK/Europe operations. References to Eastern Energy shall mean the Company's primary operations in Australia.
The following exchange rates have been used to convert foreign currency denominated amounts into US dollars:
Subsidiaries
The Company's most significant subsidiaries are as follows:
Texas Utilities Electric Company
ENSERCH Corporation Lone Star Pipeline Company, a division of ENSERCH Corporation Lone Star Gas Company, a division of ENSERCH Corporation Enserch Energy Services, Inc.
TU International Holdings Limited TXU Eastern Holdings Limited Eastern Group plc (UK)
Texas Utilities Australia Pty. Ltd. Eastern Energy Limited (Australia)
Texas Energy Industries, Inc.
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
TU Electric is an electric utility engaged in the generation, purchase, transmission, distribution and sale of electric energy wholly within the State of Texas. References herein to TU Electric include its financing subsidiaries (see Note 9 to Consolidated Financial Statements included in Appendix A to this report).
TU Electric's service area is located in the north central, eastern and western parts of Texas, with a population estimated at 6.1 million - about one-third of the population of Texas. Electric service is provided to over 2.5 million customers in 91 counties and 370 incorporated municipalities, including Dallas, Fort Worth, Arlington, Irving, Plano, Waco, Mesquite, Grand Prairie, Wichita Falls, Odessa, Midland, Carrollton, Tyler, Richardson and Killeen. The area is a diversified commercial and industrial center with substantial banking, insurance, communications, electronics, aerospace, petrochemical and specialized steel manufacturing, and automotive and aircraft assembly. The territory served includes major portions of the oil and gas fields in the Permian Basin and East Texas, as well as substantial farming and ranching sections of the State. The service territory also includes Dallas-Fort Worth International Airport and Alliance Airport. For energy sales and operating revenues contributed by each customer classification, see Texas Utilities Electric Company and Subsidiaries -- Consolidated Operating Statistics included in Appendix A to this report.
At December 31, 1998, TU Electric had 8,386 full-time employees. Some of these employees provide services to other subsidiaries of the Company, the cost of which is billed out to those subsidiaries.
ENSERCH CORPORATION AND SUBSIDIARIES
ENSERCH is an integrated company focused on natural gas. Its major business operations consist of the gathering, processing, transmission and distribution of natural gas and the marketing of natural gas and electricity through the following companies.
Lone Star Pipeline Company (Lone Star Pipeline), a division of ENSERCH, is a partially rate-regulated business that 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 gas pipeline companies 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 Metroplex. Lone Star Gas also transports natural gas within its distribution system as market opportunities require.
Enserch Processing, Inc. (EPI) gathers and processes natural gas to remove impurities and extract natural gas liquids for sale and sells the natural gas remaining after processing.
Enserch Energy Services, Inc. (EES) 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 makes physical sales of electricity in the wholesale market throughout the US excluding the area of the Electric Reliability Council of Texas (ERCOT). It also provides risk management services for the energy industry throughout the US.
References herein to ENSERCH include its financing subsidiary (See Note 9 to Consolidated Financial Statements included in Appendix A to this report.)
At December 31, 1998, ENSERCH and its direct and indirect wholly-owned subsidiaries had 1,423 full-time employees.
TU INTERNATIONAL HOLDINGS LIMITED AND SUBSIDIARIES
TU International Holdings, an indirect subsidiary of the Company, is a holding company whose subsidiaries are engaged in international energy generation, purchase, distribution and sales and international gas operations. Through its subsidiaries, TU International Holdings owns Eastern Group, one of the largest integrated electricity and gas groups in the UK and the principal operating entity in the UK/Europe business segment, and Eastern Energy, an electric utility which is the principal operating company in Australia, and the gas retail and distribution operations of Westar/Kinetik in Australia (acquired in February 1999).
TXU Eastern Holdings Limited's business operations (conducted primarily through Eastern Group) are divided into energy and networks businesses, as follows:
(i)The energy business comprising the generation of electricity, the retailing of electricity and natural gas and the production of natural gas. The overall financial efficiency of this portfolio of integrated activities is coordinated and optimized by the energy trading activity.
(ii)The networks business comprising the ownership, management and operation of electricity distribution networks.
These businesses are carried out primarily in the UK with interests increasingly being developed throughout the rest of Europe, including Scandinavia, Germany, the Czech Republic, The Netherlands, Poland and Spain.
Eastern Group's major business operations are conducted through the following subsidiaries:
Eastern Generation Limited (Eastern Generation), the fourth largest generator of electricity in the UK, currently owns, operates or has an interest in ten power stations, representing approximately 9.4% of the UK's total generating capacity of 72.4 gigawatts (GW) as of December 31, 1998.
Eastern Electricity plc (Eastern Electricity) is the largest supplier (retailer) and distributor of electricity in England and Wales, with approximately 3.2 million customers and an authorized area covering approximately 20,300 square kilometers in the east of England and parts of north London.
Eastern Natural Gas Limited (Eastern Natural Gas) is one of the largest suppliers of natural gas in the UK.
Eastern Power and Energy Trading Limited (EPETL) manages for Eastern Group: (i) the price and volume risks associated with electricity generation, and with electricity and gas retailing, (ii) the supply of fuels required for electricity generation, and (iii) the wholesaling and trading of electricity and natural gas. These exposures are managed by trading EPETL's contract portfolio and by bidding Eastern Generation's output into the wholesale trading market for electricity in England and Wales (the Pool). The rules and procedures for the Pool are currently contained in a Pooling and Settlement Agreement to which all licensed generators and suppliers are a party. EPETL also has equity interests in four natural gas producing fields in the North Sea.
At December 31, 1998, Eastern Group had approximately 7,000 full-time employees.
In February 1999, TU Australia was transferred from TEI to TU International Holdings. TU Australia owns all of the common stock of Eastern Energy, an Australian company engaged in the purchase, distribution, marketing and sale of electric energy to approximately 500,000 customers in a 31,000 square mile distribution service area extending from the outer eastern
suburbs of the Melbourne metropolitan area to the eastern coastal areas of the State of Victoria and north to the State of New South Wales border. References herein to TU Australia include its primary operating subsidiary, Eastern Energy.
In 1998, TU International Holdings acquired Lone Star Gas International, Inc. (LSGI) from TEI. LSGI is currently focused in the Mexico Federal District and in Santiago, Chile, and its operations consist primarily of ownership in gas distribution systems.
TEXAS ENERGY INDUSTRIES, INC. AND SUBSIDIARIES
TEI is a holding company for certain subsidiaries engaged in or supporting the purchase, transmission, distribution and sale of electric energy; telecommunications; retail energy services; power development; and other businesses.
Southwestern Electric Service Company (SESCO) is engaged in the purchase, transmission, distribution and sale of electric energy in ten counties in the eastern and central parts of Texas with a population estimated at 127,000.
Texas Utilities Fuel Company (Fuel Company) owns a natural gas pipeline system; acquires, stores and delivers fuel gas; and provides other fuel services, at cost, for the generation of electric energy by TU Electric.
Texas Utilities Mining Company (Mining Company) owns, leases and operates fuel production facilities for the surface mining and recovery of lignite, at cost, for the generation of electric energy by TU Electric.
LCC is the parent company of Lufkin-Conroe Telephone Exchange, Inc. (LCTX), Lufkin-Conroe Telecommunications Corporation and its subsidiaries (LCT) and LCT Long-Distance, Inc. (LCTLD). LCTX is an independent local exchange carrier providing regulated telephone services to its customers for 100 years and has over 105,000 access lines. It also provides access services to a number of interexchange carriers who provide long-distance services. LCT owns fiber optic cable systems that it leases to AT&T and provides Internet access, radio communication tower rentals, cellular mobile telephones and radio paging services and private branch exchange service to local customers. LCT is also a communications transport facility provider. LCTLD provides interexchange long-distance service, with a primary focus on business customers.
Texas Utilities Communications Inc. provides access to advanced telecommunications technology, primarily for the Company's expected expansion of the energy services business and currently holds a 20% ownership interest in Primeco Communications, Inc.'s Texas operations.
Texas Utilities Integrated Solutions Inc. is an unregulated company providing retail energy services. The company bundles energy-related products and services for selected target market segments.
Texas Utilities Services Inc. (TU Services) provides financial, accounting, information technology, environmental, customer, procurement and personnel services and other administrative services, at cost, to the Company and its other subsidiaries. TU Services acts as transfer agent, registrar and dividend paying agent with respect to the common stock of the Company, the preferred stock and preferred securities of TU Electric and ENSERCH and transfer agent and registrar for the preferred securities of the Company and as agent for participants under the Company's Direct Stock Purchase and Dividend Reinvestment Plan.
Texas Utilities Properties Inc. (TU Properties) owns, leases and manages real and personal properties, primarily the Company's corporate headquarters.
Basic Resources Inc. was organized for the purpose of developing natural resources, primarily energy sources, and other business opportunities.
Enserch Development Corporation (EDC) develops and finances independent electric power plant and cogeneration facilities.
COMPETITIVE STRATEGY
The Company has developed a strategy designed to achieve operations of significant scale in selected regions by integrating and leveraging its capabilities across multiple products and services. The Company plans to enhance its leading position in electric, gas, and related services in Texas, develop broad-based energy and related businesses in other US regions determined by the Company to be promising, achieve a substantial, broad-based position in selected international regions, and build on customer relationships through retail energy and related services.
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 Company has five reportable operating segments:
(1) US Electric - operations engaged in the generation, purchase, transmission, distribution and sale of electric energy primarily in the north central, eastern and western portions of Texas (primarily TU Electric, SESCO, Fuel Company and Mining Company operations);
(2) US Gas - 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);
(3) 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);
(4) UK/Europe - operations engaged in the generation, purchase, distribution and sale of electricity and the purchase and sale of natural gas primarily in the UK, with additional energy interests throughout the rest of Europe (primarily Eastern Group);
(5) Australia - operations engaged in the purchase, distribution and sale of electricity and natural gas and the provision of other energy-related services primarily in the State of Victoria, Australia (primarily Eastern Energy); and
Other - non-segment operations consist of telecommunications, retail energy services, international gas operations, power development and other energy development activities.
Financial information required hereunder is set forth in Note 17 to Consolidated Financial Statements included in Appendix A to this report.
TU Electric has only one reportable operating segment.
US ELECTRIC SEGMENT
GENERAL
US Electric operations are engaged in the generation, purchase, transmission, distribution and sale of electric energy primarily in the north central, eastern and western portions of Texas (primarily TU Electric, SESCO, Fuel Company and Mining Company operations).
Generation
TU Electric
Generating Units - At December 31, 1998, TU Electric owned or leased and operated 80 electric generating units with an aggregate net generating capability of 21,080 megawatts (MW) (See Item 2.
Item 2. PROPERTIES
PROPERTIES
The Company and TU Electric
GENERAL
The generating stations and other important units of property of TU Electric and SESCO are located on lands owned primarily in fee simple. The greater portion of the transmission and distribution lines of TU Electric and SESCO, the gas gathering and transmission lines of Fuel Company and the gas gathering, transmission and distribution lines of Lone Star Gas and Lone Star Pipeline, have been constructed over lands of others pursuant to easements or along public highways and streets as permitted by law. The gas gathering lines of EPI are not utility property and are primarily constructed over lands of others pursuant to private easements. The rights of the companies in the realty on which their properties are located are considered by them to be adequate for their use in the conduct of their business. Minor defects and irregularities customarily found in titles to properties of like size and character may exist, but any such defects and irregularities do not materially impair the use of the properties affected thereby. TU Electric, SESCO, Fuel Company, Eastern Energy, Lone Star Gas and Lone Star Pipeline have the right of eminent domain whereby they may, if necessary, perfect or secure titles or gain access to privately held land used or to be used in their operations. Utility plant of TU Electric and SESCO is generally subject to the liens of their respective mortgages. The Company does not directly own utility plant or real property.
US ELECTRIC
At December 31, 1998, TU Electric owned or leased and operated the following generating units:
The principal generating facilities of TU Electric and load centers of TU Electric and SESCO are connected by 3,863 circuit miles of 345kV transmission lines and 9,327 circuit miles of 138kV and 69kV transmission lines.
TU Electric is connected by six 345kV lines to Houston Lighting & Power Company; by three 345kV, eight 138kV and nine 69kV lines to West Texas Utilities Company; by two 345kV and eight 138kV lines to the Lower Colorado River Authority; by four 345kV and eight 138kV lines to the Texas Municipal Power Agency; by one asynchronous HVDC interconnection to Southwestern Electric Power Company; and at several points with smaller systems operating wholly within Texas. SESCO is connected to TU Electric by three 138kV lines, ten 69kV lines and three lines at distribution voltage. TU Electric and SESCO are members of ERCOT.
The Company
US GAS
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 owns seven active gas-storage fields, all located on its system in Texas, and three major gas- treatment plants to remove undesirable components from the gas stream. 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 over 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 the Company. In addition, ENSERCH owns a 21-story, 400,000 square-foot building in Houston. This building is leased, primarily to non-affiliated parties.
UK/EUROPE
Eastern Generation is the fourth largest generator of electricity in the UK. Its share of total UK generating capacity is approximately 9.4%. It currently owns, operates or has an interest in eight power stations in the UK. It also has a controlling interest in Nedalo, the largest supplier of less than one MW (electrical) CHP plants in the UK, and has recently acquired two additional CHP plants. It also has a controlling interest in Teplarny Brno a.s., a heating and generation company in the Czech Republic.
Further information on Eastern Group's interests in power stations in the UK is set out in the following table and discussed further below:
Eastern Group's current portfolio of power stations is predominantly a mix of CCGT and coal-fired stations. It represents both base load plants, which run throughout most of the year, and mid-merit plants, which run in high demand periods. Eastern Group's portfolio of power stations provides flexibility in managing the price and volume risks of its sales portfolios and has enabled Eastern Group to diversify its fuel supply risk.
As of March 31, 1998 (the latest available date), Eastern Group's electricity distribution system network, excluding service connections to consumers, included overhead lines and underground cables at the operating voltage levels indicated: 132kV - 2,561 kilometers (km); 33kV - 6,320 km, 11kV - - 35,864 km; and other voltages - 44,558 km.
AUSTRALIA
Eastern Energy's distribution network is comprised primarily of subtransmission and distribution assets. It owns no generating or transmission facilities. Eastern Energy's distribution system is interconnected with an intrastate power network, comprised of the operator of the transmission system, and each of the other distribution companies within Victoria. Eastern Energy has entered into distribution system agreements with each of the distribution businesses which share the boundaries of its distribution area to provide for wheeling of electricity on behalf of those distribution businesses and for the reciprocal provision of other distribution services.
OTHER
TU Properties currently leases a 48-story office building in Dallas containing approximately 1,027,000 square feet of space (Energy Plaza) from a bank leasing company. TU Properties entered into a tenant agreement with TU Services on behalf of the other subsidiary companies that allows them to occupy certain office space in Energy Plaza at market rates in effect when the agreements were entered into.
LCC and its affiliates provide a full range of telecommunications services over a variety of state of the art facilities. As of December 31, 1998, LCC's local exchange affiliate, LCTX, provided service to over 105,000 access lines and almost 91,000 customers in 16 exchanges. All calls are switched by state of the art digital switches. LCTLD has a separate digital switch for providing long-distance services.
LCC's affiliate, LCT, owns 63% of East Texas Fiber Line, Inc. (ETFL). ETFL provides voice and data capacity to interexchange carriers over its fiber optic lines. LCT owns an additional two hundred route miles of fiber optic lines and markets that capacity to interexchange carriers including LCTLD. LCT also has cellular interests in the Houston Metropolitan Serving Area as well as interests in three rural service areas.
CAPITAL EXPENDITURES
The capital expenditures of the Company were $1.2 billion in 1998 and are estimated at $1.3 billion for 1999. Approximately 50% will be spent on US electric and gas operations, approximately 35% on operations in the UK and continental Europe, and approximately 15% on operations in Australia, communications and other activities.
The re-evaluation of growth expectations, the effects of inflation, additional regulatory requirements and the availability of fuel, labor, materials and capital may result in changes in estimated construction costs and dates of completion. Commitments in connection with the construction program are generally revocable subject to reimbursement to manufacturers for expenditures incurred or other cancellation penalties. (See Item 1. Business - - US Electric Segment-Electricity Peak Load and Generation Capability.)
The Company will pursue potential investment opportunities from time to time when it concludes that such investments are consistent with its business strategies and are likely to enhance the long-term return to its shareholders.
For information regarding the financing of capital expenditures, see Management's Discussion and Analysis of Financial Condition and Results of Operation included in Appendix A to this report.
Item 3.
Item 3. LEGAL PROCEEDINGS
The Company
The Company and its subsidiaries are party to lawsuits arising in the ordinary course of their business. The Company 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 operation or cash flows.
UK -- In February 1997, the official government representative of pensioners in the UK (Pensions Ombudsman) made final determinations against National Grid and its group trustees with respect to complaints by two pensioners in National Grid's section of the Electricity Supply Pension Scheme (ESPS) relating to the use of the pension fund surplus resulting from the March 31, 1992 actuarial valuation of the National Grid section to meet certain costs arising from the payment of pensions on early retirement upon reorganization or downsizing. These determinations were set aside by the High Court on June 10, 1997, and the arrangements made by National Grid and its group trustees in dealing with the surplus were confirmed. The two pensioners appealed this decision, and judgment has now been received although a final order is awaited. The appeal endorsed the Pensions Ombudsman's determination that the corporation was not entitled to unilaterally deal with any surplus. If a similar action were to be made against Eastern Group in relation to its use of actuarial surplus in its section of the ESPS, it would vigorously defend the action, ultimately through the courts. However, if a determination were finally to be made against it and upheld in the courts, Eastern Group could have a potential liability to repay to its section of the ESPS an amount estimated by Eastern Group to be up to $165 million (exclusive of any applicable interest charges).
On January 25, 1999, the Hindusthan Development Corporation issued proceedings in the Arbitral Tribunal in Delhi against TEG claiming damages for breach of contract following the termination of a Joint Development Agreement dated March 20, 1997 relating to the construction, development and operation of a lignite based thermal power plant at Barsingsar, Rajasthan. TEG's successor is vigorously defending this claim.
In November 1998, five suits were filed against subsidiaries of Eastern Group by five of their former sales agencies. The agencies claim a total 104 million pounds ($172 million) and arise from the summary termination for the claimed fundamental breach of their respective contracts in April 1998. The five agencies are claiming damages for failure to give reasonable notice and for compensation under the UK Commercial Agents Regulations 1994. These actions are all being defended strenuously, and counterclaims are being prepared. The Company cannot predict the outcome of these claims and counter claims.
US -- 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), the Company, 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 the Company pursuant to the merger agreement between ENSERCH and the Company 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 the Company 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 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.
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. The Company 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 Company 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.
Item 4.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company and TU Electric None.
There is no family relationship between any of the above-named Executive Officers.
PART II
Item 5.
Item 5. MARKET FOR EACH REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
The Company The Company's common stock is listed on the New York, Chicago and Pacific stock exchanges (symbol: TXU).
The price range of the common stock of the Company on the composite tape, as reported by The Wall Street Journal and the dividends paid for each of the calendar quarters of 1998 and 1997 were as follows:
The Company, or its predecessor TEI, have declared common stock dividends payable in cash in each year since TEI's incorporation in 1945. The Board of Directors of the Company, at its February 1999 meeting, declared a quarterly dividend of $0.575 a share, payable April 1, 1999 to shareholders of record on March 5, 1999. For information concerning the Company's dividend policy, see Management's Discussion and Analysis of Financial Condition and Results of Operations included in Appendix A to this report. Future dividends may vary depending upon the Company's profit levels and capital requirements as well as financial and other conditions existing at the time. Reference is made to Note 6 to Consolidated Financial Statements included in Appendix A to this report regarding limitations upon payment of dividends on common stock of TU Electric and Eastern Group.
The number of record holders of the common stock of the Company as of March 19, 1999 was 87,524.
TU Electric All of TU Electric's common stock is owned by the Company. Reference is made to Note 6 to Consolidated Financial Statements included in Appendix A to this report regarding limitations upon payment of dividends on common stock of TU Electric.
Item 6.
Item 6. SELECTED FINANCIAL DATA
The Company and TU Electric
The information required hereunder for the Company and TU Electric is set forth under Selected Financial Data included in Appendix A to this report.
Item 7.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The Company and TU Electric
The information required hereunder for the Company and TU Electric is set forth under Management's Discussion and Analysis of Financial Condition and Results of Operations included in Appendix A to this report.
Item 7A.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Company and TU Electric
The information required hereunder for the Company and TU Electric is set forth in 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 Company and TU Electric
The information required hereunder for the Company and TU Electric is set forth under Statements of Responsibility, Independent Auditors' Reports, 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 as included for each company in Appendix A to this report.
Item 9.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
The Company and TU Electric
None.
PART III
Item 10.
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF EACH REGISTRANT
For financial reporting and other purposes, the Company is being treated herein as the successor to TEI. Unless otherwise specified, all references to the Company which relate to a period prior to August 5, 1997, shall be deemed to be references to TEI.
The Company
Information with respect to this item is found under the heading Election of Directors in the definitive proxy statement to be filed by the Company with the Commission on or about April 5, 1999. Additional information with respect to Executive Officers of the Company is found at the end of Part I.
TU Electric
Identification of Directors, business experience and other directorships:
Directors of TU Electric receive no compensation in their capacity as Directors of TU Electric.
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 TU Electric have been timely filed.
Item 11.
Item 11. EXECUTIVE COMPENSATION
The Company
Information with respect to this item is found under the heading Executive Compensation in the definitive proxy statement to be filed by the Company with the Commission on or about April 5, 1999.
TU Electric
TU Electric and its affiliates have paid or awarded compensation during the last three calendar years to the following Executive Officers for services in all capacities:
(1) Amounts reported in the table for Mr. Nye consist entirely of compensation paid by the Company.
(2) Mr. Biegler was elected to his current position with TU Electric effective January 1, 1998; compensation amounts represent compensation paid by the Company.
(3) Amounts reported as Bonus in the Summary Compensation Table are attributable to the named officer's participation in the Annual Incentive Plan (AIP). Elected corporate officers of the Company and its participating subsidiaries with a title of Vice President or above are eligible to participate in the AIP. Under the terms of the AIP, target incentive awards ranging from 35% to 50% of base salary, and a maximum award of 100% of base salary, are established. The percentage of the target or the maximum actually
awarded, if any, is dependent upon the attainment of per share net income goals established in advance by the Organization and Compensation Committee (Committee) as well as the Committee's evaluation of the participant's and the Company's performance. One-half of each such award is paid in cash and is reflected as Bonus in the Summary Compensation Table. Payment of the remainder of the award is deferred under the Deferred and Incentive Compensation Plan (DICP) discussed hereinafter in footnote (4).
(4) Amounts reported as Long-Term Compensation in the Summary Compensation Table are attributable to the named officer's participation in the DICP. Elected corporate officers of the Company and its participating subsidiaries with the title of Vice President or above are eligible to participate in the DICP. Participants in the DICP may defer a percentage of their base salary not to exceed a maximum percentage determined by the Committee for each Plan year and in any event not to exceed 15% of the participant's base salary. Salary deferred under the DICP is included in amounts reported as salary in the Summary Compensation Table. The Company makes a matching award (Matching Award) equal to 150% of the participant's deferred salary. In addition, one-half of any AIP award (Incentive Award) is deferred and invested under the DICP. The Matching Awards and Incentive Awards are subject to forfeiture under certain circumstances. Under the DICP, a trustee purchases Company common stock with an amount of cash equal to each participant's deferred salary, Matching Award and Incentive Award, and accounts are established for each participant containing performance units (Units) equal to such number of common shares. DICP investments, including reinvested dividends, are restricted to Company common stock. On the expiration of the applicable maturity period (three years for the Incentive Awards and five years for deferred salary and Matching Awards), the value of the participant's accounts are paid in cash based upon the then current value of the Units; provided, however, that in no event will a participant's account be deemed to have a cash value which is less than the sum of such participant's deferred salary together with a 6% per annum (compounded annually) interest equivalent thereon. The maturity period is waived if the participant dies or becomes totally and permanently disabled and may be extended under certain circumstances.
Incentive Awards and Matching Awards that have been made under the DICP are included under Restricted Stock Awards in the Summary Compensation Table for each of the last three years. As a result of these awards, undistributed Incentive Awards and Matching Awards made under the DICP in prior years, and dividends reinvested thereon, the number and market value of such Units at December 31, 1998 (each of which is equal to one share of common stock) held in the DICP accounts for Messrs. Nye, Biegler, Taylor, Baker and Greene were 46,827 ($2,186,236), 5,895 ($275,223), 16,724 ($780,802), 14,357 ($670,292) and 11,161 ($521,079), respectively.
The Long-Term Incentive Compensation Plan (LTICP) is a comprehensive, stock-based incentive compensation plan providing for discretionary grants of common stock-based awards, including restricted stock. Outstanding awards to named executive officers vest over a three year period and such executive officers may earn from 0% to 200% of the number of shares awarded based on the Company's total return to shareholders over such three year period compared to the total return provided by the companies comprising the Standard & Poor's Electric Utility Index. Dividends are paid and reinvested on such restricted stock awards at the same rate as dividends on the Company's common stock. As a result of restricted stock awards under the LTICP, and dividends reinvested thereon, the number of shares of restricted stock and the value of such shares at December 31, 1998 held for Messrs. Nye, Biegler, Taylor, Baker and Greene were 46,441 ($2,168,214), 7,177 ($335,076), 8,443 ($394,183), 9,529 ($444,885), and -0- ($-0-), respectively.
Salary deferred under the DICP is included in amounts reported as Salary in the Summary Compensation Table. Amounts shown in the table below represent the number of shares purchased under the DICP with such deferred salaries for 1998 and the number of shares awarded under the LTICP:
The amounts reported under LTIP Payouts in the Summary Compensation Table represent payouts maturing during such years of earnings on deferred salary under the DICP in prior years.
(5) Amounts reported as All Other Compensation in the Summary Compensation Table are attributable to the named officer=s participation in certain plans and as otherwise described hereinafter in this footnote.
Under the Employees' Thrift Plan of the Texas Utilities Company System (Thrift Plan) all employees of the Company or any of its participating subsidiaries may invest up to 16% of their regular salary or wages in common stock of the Company, or in a variety of selected mutual funds. Under the Thrift Plan, the Company matches a portion of an employee's contributions in an amount equal to 40%, 50% or 60% (depending on the employee's length of service) of the first 6% of such employee's contributions. All matching amounts are invested in common stock of the Company. The amounts reported under All Other Compensation in the Summary Compensation Table include these matching amounts which, for Messrs. Nye, Biegler, Taylor, Baker and Greene amounted to $5,760, $3,840, $5,760, $5,760 and $5,760, respectively, during 1998.
The Company has a Salary Deferral Program (Program) under which each employee of the Company and its participating subsidiaries whose annual salary is equal to or greater than an amount established under the Program ($96,370 for the Program Year beginning April 1, 1998) may elect to defer a percentage of annual base salary, or any bonus or other special cash compensation for a period of seven years, for a period ending with the retirement of such employee, or for a combination thereof. Effective with the Program Year beginning April 1, 1998, such deferrals may be up to a maximum of 50% of the employee's annual salary and/or 100% of the employee's bonus or other special cash compensation. The Company makes a matching award, subject to forfeiture under certain circumstances, equal to 100% of up to the first 8% of salary deferred under the Program. Prior to April 1, 1998, deferrals under the Program were limited to up to 10% of the employee's salary and the Company made a matching award equal to 100% of the employee's salary deferral. Salary and bonuses deferred under the Program are included in amounts reported under Salary and Bonus, respectively, in the Summary Compensation Table. Deferrals made after April 1, 1998, are credited with earnings or losses based on the performance of investment alternatives selected by each participant. Deferrals made prior to April 1, 1998, are, at the end of the applicable maturity period, credited with the greater of the actual earnings of the Program assets, or the average yield during the applicable maturity period of U.S. Treasury Notes having a maturity of ten years. At the end of the applicable maturity period, the trustee for the Program distributes the deferrals and the applicable earnings in cash. The distribution is in a lump sum if the applicable maturity period is seven years. If the retirement
option is elected, the distribution is made in twenty annual installments. Individuals who were participating in the Program on March 31, 1998, were given a one time opportunity to elect (1) to continue to have the provisions of the Program relating to permitted deferrals, matching awards, investments and calculation of earnings in effect prior to April 1, 1998, apply to their future Program participation; or (2) to have the Program provisions relating to investments and calculation of earnings apply to their entire Program account, including deferrals and matching contributions which had been made prior to April 1, 1998. The Company is financing the retirement portion of the Program through the purchase of corporate-owned life insurance on the lives of the participants. The proceeds from such insurance are expected to allow the Company to fully recover the cost of the retirement option. During 1998, matching awards, which are included under All Other Compensation in the Summary Compensation Table, were made for Messrs. Nye, Biegler, Taylor, Baker and Greene in the amounts of $69,375, $37,400, $30,590, $27,372 and $24,583, respectively.
Under the Company's Split-Dollar Life Insurance Program (Insurance Program), split-dollar life insurance policies are purchased for elected corporate officers of the Company and its participating subsidiaries with a title of Vice President or above, with a death benefit equal to four times their annual Insurance Program compensation. New participants vest in the policies issued under the Insurance Program over a six year period. The Company pays the premiums for these policies and has received a collateral assignment of the policies equal in value to the sum of all of its insurance premium payments. Although the Insurance Program is terminable at any time, it is designed so that if it is continued, the Company will fully recover all of the insurance premium payments it has made either upon the death of the participant or, if the assumptions made as to policy yield are realized, upon the later of fifteen years of participation or the participant's attainment of age sixty-five. During 1998, the economic benefit derived by Messrs. Nye, Biegler, Taylor, Baker and Greene from the term insurance coverage provided and the interest foregone on the remainder of the insurance premiums paid by the Company amounted to $81,771, $7,968, $27,071, $28,879 and $15,532, respectively.
In connection with the acquisition of ENSERCH, the Company entered into an employment agreement with Mr. Biegler which provides for a minimum annual salary of $600,000, minimum annual cash incentive compensation for 1997 of $330,000 and certain severance benefits. In accordance with the agreement, a supplemental incentive compensation payment of $125,000 was made to Mr. Biegler and is included under All Other Compensation in the Summary Compensation Table. The agreement terminates in August 1999.
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 the Company. 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 the Company's common stock into which such options became exercisable at the time of the ENSERCH acquisition.
The Company 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, Taylor, Baker and Greene were 36, 1, 31, 28 and 28, respectively.
Before the ENSERCH acquisition, Mr. Biegler 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 they remained under the ENSERCH Retirement Plan for their entire careers. Mr. Biegler, whose employment with the Company began August 5, 1997, is treated in a similar manner. Amounts reported for Mr. Biegler 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, Mr. Biegler had 30 years of accredited service under the ENSERCH Retirement Plan.
The Company'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 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.
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 the Company and is illustrative of the methodology utilized in establishing the compensation of executive officers of the Company and TU Electric.
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 3 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 4 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 4 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 the Company'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
The Company
Information with respect to this item is found under the headings Beneficial Ownership of Common Stock of the Company in the definitive proxy statement filed by the Company with the Commission on or about April 5, 1999. Additional information with respect to Executive Officers of the Company is found at the end of Part I.
TU Electric
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 the Company owned by the Directors and Executive Officers of TU Electric. 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 TU Electric or the preferred securities of any subsidiaries of TU Electric.
(1) Total shares include 129,778 shares subject to stock options exercisable within sixty days of the date of this report.
(2) Share units held in deferred compensation accounts under the Deferred and Incentive Compensation Plan. Although this plan allows such units to be paid only in the form of cash, investments in such units create essentially the same investment stake in the performance of the Company's common stock as do investments in actual shares of common stock.
Item 13.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The Company
None.
TU Electric
None.
PART IV
Item 14.
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Page ---- (a) Documents filed as part of this Report:
The Company and TU Electric
Financial Statements (included in Appendix A to this report):
The Company and TU Electric: Selected Financial Data - Consolidated Financial and Operating Statistics A-2 Management's Discussion and Analysis of Financial Condition and Results of Operations A-6 Statements of Responsibility A-23 Independent Auditors' Reports A-25
The Company: Statements of Consolidated Income for each of the three years in the period ended December 31, 1998 A-28 Statements of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 1998 A-29 Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 1998 A-30 Consolidated Balance Sheets, December 31, 1998 and 1997 A-31 Statements of Consolidated Common Stock Equity for each of the three years in the period ended December 31, 1998 A-33
TU Electric: Statements of Consolidated Income for each of the three years in the period ended December 31, 1998 A-34 Statements of Consolidated Comprehensive Income for each of the three years in the period ended December 31, 1998 A-34 Statements of Consolidated Cash Flows for each of the three years in the period ended December 31, 1998 A-35 Consolidated Balance Sheets, December 31, 1998 and 1997 A-36 Statements of Consolidated Common Stock Equity for each of the three years in the period ended December 31, 1998 A-38
The Company and TU Electric: Notes to Consolidated Financial Statements A-39
The consolidated financial statement schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the consolidated financial statements or notes thereto.
(b) Reports on Form 8-K:
Reports on Form 8-K filed since September 30, 1998, are as follows:
The Company
Date of Report Item Reported ----------------- -------------------- December 10, 1998 Item 5. OTHER EVENTS The following financial information of The Energy Group was filed: The Audited Financial Statements as of March 31, 1998 and 1997 and for the year ended March 31, 1998, the six months ended March 31, 1997 and the two years in the period ended September 30, 1996.
January 19, 1999 Item 5. OTHER EVENTS
TU Electric
Date of Report Item Reported ----------------- -------------------- March 17, 1999 Item 5. OTHER EVENTS
(c) Exhibits:
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Texas Utilities Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TEXAS UTILITIES COMPANY
Date: March 22, 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 Texas Utilities Company and in the capacities and on the date indicated.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, Texas Utilities Electric Company has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
TEXAS UTILITIES ELECTRIC COMPANY
Date: March 22, 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 Texas Utilities Electric Company and in the capacities and on the date indicated.
Appendix A
TEXAS UTILITIES COMPANY AND SUBSIDIARIES AND TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
INDEX TO FINANCIAL INFORMATION December 31, 1998
Page
Texas Utilities Company and Subsidiaries and Texas Utilities Electric Company and Subsidiaries:
Selected Financial Data - Consolidated Financial and Operating Statistics A-2 Management's Discussion and Analysis of Financial Condition and Results of Operations A-6 Statements of Responsibility A-23 Independent Auditors' Reports A-25
Financial Statements:
Texas Utilities Company and Subsidiaries:
Statements of Consolidated Income A-28 Statements of Consolidated Comprehensive Income A-29 Statements of Consolidated Cash Flows A-30 Consolidated Balance Sheets A-31 Statements of Consolidated Common Stock Equity A-33
Texas Utilities Electric Company and Subsidiaries:
Statements of Consolidated Income and Comprehensive Income A-34 Statements of Consolidated Cash Flows A-35 Consolidated Balance Sheets A-36 Statements of Consolidated Common Stock Equity A-38
Notes to Consolidated Financial Statements A-39
A-1
Certain financial statistics were affected by the May 1998 acquisition of The Energy Group (TEG), the August 1997 acquisition of ENSERCH and the November 1997 acquisition of LCC, the December 1995 acquisition of Eastern Energy; and for the year 1995, were affected by recording of the impairment of certain assets. Shares outstanding (in millions) assuming dilution for 1998 and 1997 were 266 and 232, respectively. There were no additional diluted shares for any of the prior periods presented.
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Certain previously reported operating statistics have been reclassified to conform to current classifications. The operating statistics include the operations of Eastern Group, ENSERCH and Eastern Energy from their respective dates of acquisition, May 1998, August 1997 and December 1995.
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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 Texas Utilities Company and its subsidiaries (the Company or TUC) or Texas Utilities Electric Company and its subsidiaries (TU Electric) contain forward-looking statements within the meaning of Section 21E of the Securities Exchange Act of 1934, as amended. Although the Company and TU Electric each believe 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 the Company or TU Electric to differ materially from those projected in such forward-looking statements: (i) prevailing governmental policies and regulatory actions, including those of the Federal Energy Regulatory Commission (FERC), the Public Utility Commission of Texas (PUC), the Railroad Commission of Texas (RRC), the Nuclear Regulatory Commission (NRC), and, in the case of the Company, the Office of the Regulator General of Victoria, Australia, and the Office of Electricity Regulation covering England, Wales and Scotland (OFFER) in the United Kingdom (UK) with respect to allowed rates of return, industry and rate structure, purchased power and investment recovery, operations of nuclear generating facilities, acquisitions and disposal of assets and facilities, operation and construction of plant facilities, decommissioning costs, 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 crude oil, natural gas and other commodities, (vi) unanticipated changes in interest rates, rates of inflation or foreign exchange rates, (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 the various counterparties to meet their obligations with respect to the Company's and TU Electric's financial instruments, (xii) changes in technology used and services offered by the Company and TU Electric, (xiii) significant changes in the Company's and TU Electric's relationship with their employees and the potential adverse effects if labor disputes or grievances were to occur and (xiv) unanticipated problems related to the Company'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 neither the Company nor TU Electric undertakes any 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 the Company or TU Electric to predict all of such factors, nor can they assess 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
Certain comparisons in this report have been affected by the acquisitions of the Company (accounted for as purchase business combinations) of The Energy Group PLC (TEG) in May 1998, ENSERCH Corporation (ENSERCH) in August 1997, and Lufkin-Conroe Communications Co. (LCC) in November 1997. (See Note 17 to Consolidated Financial Statements for information concerning reportable segments.)
On February 24, 1999, TU Australia Pty. Ltd. (TU Australia) acquired from the Government of Victoria, Australia the gas retail business of Kinetik Energy, which has approximately 400,000 gas customers, and the gas distribution operations of Westar, which is of similar size. The purchase price was $1.0 billion which has been principally financed through banks by the Australian holding company for the Company's Australian operations. A portion of the financing was provided by a six-month subordinated credit facility guaranteed by the Company. The Company will pursue potential investment opportunities from time to time when it concludes that such
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investments are consistent with its business strategies and are likely to enhance the long-term return to its shareholders.
Throughout this document, references to TEG shall mean the consolidated UK entity acquired in May 1998, and Eastern Group or Eastern Electricity shall mean the Company's primary continuing operations in the UK and other parts of Europe subsequent to organizational restructuring of UK/Europe operations. References to Eastern Energy shall mean the company's primary operations in Australia.
FINANCIAL CONDITION
Liquidity and Capital Resources For 1998, the Company generated cash from operations sufficient to meet operating needs and service debt requirements, pay dividends on capital stock, pay distributions on preferred securities of trusts and finance capital expenditures. Factors affecting the continued ability of TU Electric to fund its capital requirements from operations include regulation that permits allowing recovery of capital investment through depreciation, recovery of fuel and purchased power costs and the competitive rates of return on capital markets securities.
Cash flows provided from operating activities for the Company before changes in operating assets and liabilities for the year ended December 31, 1998 were $2.3 billion compared with $1.6 billion and $1.7 billion for the comparable periods in 1997 and 1996, respectively, ($1.8 billion versus $1.6 billion and $1.7 billion for TU Electric). Increased net income and higher depreciation and amortization expense (primarily resulting from TU Electric's earnings in excess of the return cap as discussed below) were contributing factors. Changes in operating assets and liabilities for the Company for the year ended December 31, 1998 used $338 million versus $15 million and $43 million provided for the comparable periods in 1997 and 1996. Changes in operating assets and liabilities for TU Electric for the year 1998 provided $2 million, compared with $74 million and $33 million provided in 1997 and 1996, respectively.
Cash flows used for investing activities for the Company for the year ended December 31, 1998 totaled $4.3 billion, including $2.5 billion used for the acquisition of TEG, compared with $708 million for the same period of 1997 and $576 million for 1996. Construction expenditures were $1.2 billion for the current period, compared with $586 million and $434 million for the comparable periods in 1997 and 1996, respectively, primarily resulting from higher expenditures for TU Electric and the inclusion of expenditures for Eastern Group, ENSERCH and LCC. Cash flows used for investing activities for TU Electric for the year 1998 totaled $580 million versus $526 million for the same period of 1997 and $481 million for 1996. Construction expenditures for TU Electric were $501 million, $446 million and $377 million for 1998, 1997 and 1996, respectively.
In 1998, the Company acquired TEG for $7.4 billion, including $1.4 billion assigned to common stock issued. In 1997, the Company acquired ENSERCH for $579 million and LCC for $319 million primarily through the issuance of common stock.
The capital expenditures of the Company were $1.2 billion in 1998 and are estimated at $1.3 billion for 1999 ($501 million in 1998 and $508 million estimated for 1999 for TU Electric). Approximately 50% will be spent on US electric and gas operations, approximately 35% on operations in the UK and continental Europe, and approximately 15% on operations in Australia, communications and other activities.
External funds of a permanent or long-term nature are obtained through the issuance of common and preferred stock, trust securities and long-term debt by the Company. The capitalization ratios of the Company at December 31, 1998, consisted of approximately 61% long-term debt (including equity-linked securities), 5% Company or subsidiary obligated, mandatorily redeemable, preferred securities of Company or subsidiary trusts, each holding solely junior subordinated debentures of the Company or related subsidiary (trust securities), 1% preferred stock and 33% common stock equity. Restricted cash pledged against lease obligations is included in other investments (See Note 15 to Consolidated Financial Statements). Offsetting the cash pledge against
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lease obligations, the capitalization ratios consisted of 59% long-term debt, 5% trust securities, 1% preferred stock and 35% common stock equity.
The capitalization ratios of TU Electric at December 31, 1998 consisted of approximately 41% long-term debt, 7% TU Electric obligated, mandatorily redeemable, preferred securities of subsidiary trusts holding solely junior subordinated debentures of TU Electric, 1% preferred stock and 51% common stock equity.
During the year ended December 31, 1998, the Company (including TU Electric) 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 5, 9 and 16 to Consolidated Financial Statements for further details concerning long-term debt, trust securities and preferred stock of subsidiaries.
The Company, TU Electric, ENSERCH and or other subsidiaries of the Company may issue additional debt and equity securities as needed, including the possible future sale: (i) by TU Electric of up to $499 million principal amount of debt securities, (ii) by TU Electric of up to $25 million of its Cumulative Preferred Stock, and (iii) by ENSERCH of up to $100 million aggregate principal amount of securities, all of which are currently
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registered with the Securities and Exchange Commission (SEC) for offering pursuant to Rule 415 under the Securities Act of 1933. In addition, the Company may issue up to $170 million of debt securities and, together or separately, up to $170 million of (i) debt securities, (ii) shares of its common stock, (iii) contracts to purchase shares of common stock and (iv) units pledged to secure the holder's obligation to purchase common stock under stock purchase contracts similarly registered with the SEC.
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 TEG, are limited to an aggregate of $2.2 billion outstanding at any one time. TU Electric's and ENSERCH's borrowings under both facilities are limited to an aggregate of $1.25 billion and $650 million outstanding at any one time, respectively. The facilities primarily support commercial paper borrowings.
The Company intends to refinance $874 million of its current short-term borrowings beyond one-year of December 31, 1998; such amount has been reclassified as long-term debt.
At December 31, 1998, TXU Eastern Holdings Limited (TXU Eastern), formerly TU Finance (No. 1) Limited, TU Finance (No. 2) Limited, TU Acquisitions and Eastern Group, had a joint sterling-denominated line of credit with a group of banking institutions under a credit facility agreement (Sterling Credit Agreement). Originally, the Sterling Credit Agreement provided for borrowings of up to 3.4 billion pounds and was comprised of three facilities: the Acquisition, Interim, and Revolving Credit facilities. During 1998, the Interim facility was repaid and has been cancelled. The aggregate borrowing limit of the remaining facilities, which mature March 2, 2003, has been reduced to 1.3 billion pounds ($2.1 billion) at December 31, 1998. At December 31, 1998, the Acquisition facility had a balance of 750 million pounds ($1.2 billion) outstanding, and no additional borrowings are permitted. The Revolving Credit facility had a balance of 51 million pounds ($84 million) outstanding at December 31, 1998. In addition, a separate Eastern Electricity Revolving Credit Facility provides for short term borrowings for general corporate purposes of up to 250 million pounds ($414 million) outstanding at any one time and terminates March 2, 2003. Under this facility, 180 million pounds ($298 million) was outstanding at year-end 1998.
As of December 31, 1998, TXU Eastern had entered into various interest rate swaps as required by the Sterling Credit Agreements. The aggregate notional amount of the interest rate swaps entered into was 800 million pounds ($1.3 billion). The swaps have an average maturity of six years and an average fixed rate of 6.58%.
In addition, certain non-US subsidiaries have revolving credit agreements (denominated in both foreign currencies and US dollars) aggregating approximately $106 million, of which $83 million was outstanding at December 31, 1998. These revolving credit agreements expire at various dates through 2001.
Quantitative and Qualitative Disclosure About Market Risk
The Company's and TU Electric's operations involve managing market risks related to changes in interest rates and, for the Company, foreign exchange and commodity price exposures. Derivative instruments, including swaps, options and forward contracts, are used to reduce and manage a portion of those risks. With the exception of the energy marketing activities of a subsidiary, Enserch Energy Services, Inc. (EES), the Company's and TU Electric's participation in derivative transactions are designated for hedging purposes and are not held or issued for trading purposes.
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CREDIT RISK -- Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties to their respective derivative instruments. The Company maintains credit policies with regard to its counterparties that management believes significantly minimize overall credit risk. The Company 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 Company may apply certain remedies, if considered necessary. The Company believes the risk of nonperformance by counterparties is minimal.
ELECTRICITY PRICE RISK
UK -- Almost all electricity generated in England and Wales must be sold to the electricity trading market in England and Wales (Pool), and electricity suppliers must likewise generally buy electricity from the Pool for resale to their customers. In the electricity retail business, Eastern Group contracts to supply customers at fixed prices and buys output from the electricity Pool to meet the demand of these customers. Since the price of electricity purchased from the Pool can be volatile, Eastern Group is exposed to the risk arising from the differences between the fixed price at which it sells electricity to customers and the variable prices at which it buys electricity from the Pool. Eastern Group's generation business provides a physical hedge to this risk as it is exposed to Pool price fluctuations from selling electricity into the Pool. Eastern Group's overall exposure to such risks is managed by its energy trading business, Eastern Power and Energy Trading Limited (EPETL), which also enters into derivatives to hedge the portfolio and maintain energy price exposure to within a limit set by Eastern Group's Board of Directors. The derivatives used are contracts for differences (CFDs) and electricity forward agreements (EFAs). CFDs are bilaterally negotiated contracts which fix the price of electricity for an agreed quantity and duration by reference to an agreed strike price. EFAs are similar in principle to CFDs but are on standard terms and tend to be for smaller quantities and shorter durations. The hypothetical loss in fair value of Eastern Group's CFDs and EFAs in existence at December 31, 1998 arising from a 10% adverse movement in future electricity prices is estimated at $134 million. This loss is calculated by modeling the contracts against an internal forecast of Pool prices using discounted cash flow techniques.
Australia -- Eastern Energy also maintains a strategy of seeking hedging contracts with individual generators to cover a portion of forecasted contestable loads. These contracts fix the price of energy within a certain range for the purpose of hedging or protecting against fluctuations in the spot market price. At December 31, 1998, Eastern Energy's contracts related to its forecasted contestable and franchise load cover a notional volume of approximately 8.3 million MWh's for the period from January 1999 through 2001. Further hedge contracts may be required in that period to service forecasted sales. Under these contracts, payments are made between Eastern Energy and the generators representing the difference between the wholesale electricity market price and the contract price. The net payable or receivable is recognized in earnings as adjustments to purchased power expense in the period the related transactions are completed.
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INTEREST RATE RISK -- The table below provides information concerning the Company's and TU Electric'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. The Company and TU Electric have entered into interest rate swaps under which they have 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. When differences exist between the swap settlement dates and the dates on which interest is payable on the underlying debt, the gap exposure, or basis risk, is managed by means of forward rate agreements. These forward rate agreements are not expected to have a material effect on the Company's and TU Electric's financial position, results of operations or cash flows. 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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US 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 for 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.
GAS PRICE RISK -- In the gas retail business, Eastern Group sells fixed price contracts to customers and supplies the customer through a portfolio of gas purchase contracts and other wholesale contracts. The overall net exposure of Eastern Group to the gas spot market is also managed by its subsidiary, EPETL, within a limit set by the Board of Directors of Eastern Group, using natural gas futures and swaps, as appropriate, to hedge the exposures. The hypothetical loss in fair value at December 31, 1998 of Eastern Group's natural gas commodity futures arising from a 10% adverse movement in future gas prices is estimated at $3.3 million.
FOREIGN CURRENCY RISK -- The Company has entered into short-term foreign currency exchange contracts in connection with the acquisition of TEG to hedge a portion of the Company's exposure to changes in the dollar to pound exchange rate. The Company has contracted to deliver £675 million and will receive $1.1 billion. The fair value of this contract was a negative $28 million at December 31, 1998.
Eastern Group has limited exposure to foreign currency movements. The policy with regard to any such exposures is to match assets owned in foreign countries with borrowings in that same currency. Where there are known commitments to purchase goods in foreign currency then forward contracts or options are used to fix the exchange rate. A-12
Eastern Energy maintains cross currency swaps for its US dollar denominated debts. These cross currency swaps mature in December 2006 and December 2016 for $250 million and $100 million, respectively. The maturity of these swaps coincides with the maturity of the US dollar denominated debt.
NUCLEAR DECOMMISSIONING AND DISPOSAL OF SPENT FUEL TRUST -- TU Electric has established an external trust to provide for nuclear decommissioning and disposal of spent fuel. The trust is invested in marketable fixed income debt and equity securities. At December 31, 1998, the current market value of the debt and equity securities was $81 million and $130 million, respectively. A hypothetical 10% increase in interest rates and 10% decrease in equity prices would result in a $16 million reduction in the fair value of the trust assets. However, adjustments to market value result in a corresponding adjustment to related liability accounts based on current regulatory treatment.
Regulation and Rates
Under the current regulatory environment, certain US subsidiaries of the Company are subject to the provisions of Statement of Financial Accounting Standards (SFAS) No. 71, "Accounting for the Effects of Certain Types of Regulation". This statement applies to utilities that have cost-based rates established by a regulator and charged to and collected from customers. In accordance with this statement, these companies may defer the recognition of certain costs (regulatory assets) and certain obligations (regulatory liabilities) that, as a result of the ratemaking process, have probable corresponding increases or decreases in future revenues. Future significant changes in regulation or competition could affect these companies' ability to meet the criteria for continued application of SFAS 71 and may affect these companies' ability to recover such regulatory assets from, or refund such regulatory liabilities to, customers. These regulatory assets and liabilities are being amortized over various periods (5 to 40 years). The amortization is currently, or is expected to be, included in rates. In the event all or a portion of these companies' operations fail to meet the criteria for application of SFAS 71, these companies would be required to write-off all or a portion of their regulatory assets and liabilities. Should significant changes in regulation or competition occur, the affected subsidiaries would be required to assess the recoverability of plant and regulatory assets. (See Note 2 to Consolidated Financial Statements.)
Although neither the Company nor TU Electric can predict future regulatory or legislative actions or any changes in economic and securities market conditions, no changes are expected in trends or commitments, other than those discussed in this Form 10-K, which might significantly alter its basic financial position, results of operations or cash flows. (See Note 14 to Consolidated Financial Statements.)
The Company and TU Electric have several rate requests pending or on appeal. (See Note 13 to Consolidated Financial Statements for a detailed discussion of the status of these items.) (See "Docket 18490" in Note 13 to Consolidated Financial Statements for a discussion of the impact of a rate settlement.) With regard to Eastern Group, the regulation of distribution and supply charges is currently subject to review by OFFER, with the outcome due to impact results from April 1, 2000.
Electricity and gas operations in Australia are subject to the requirements of the applicable regulatory governments or agencies and are currently in various stages of implementing deregulation.
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Competition
US -- As legislative, regulatory, economic and technological changes occur, the US energy and utility industries are faced with increasing pressure to become more competitive while adhering to regulatory requirements. The National Energy Policy Act of 1992 (Energy Policy Act) addresses a wide range of energy issues and is intended to increase competition in electric generation and broaden access to electric transmission systems. In addition, the Texas Public Utility Regulatory Act of 1995, as amended (PURA), impacts the PUC and its regulatory practices and encourages increased competition in some aspects of the electric utility industry in Texas. The 106th Congress has begun to examine the possibility of mandated "retail competition," the required delivery by an electric utility over its transmission and distribution facilities of energy produced by another entity to retail customers in such utility's service territory. If implemented, such access could allow a retail customer to purchase electric service from any other electric service provider. Retail competition has not been implemented in Texas; however, this issue is currently being addressed in the 76th Texas Legislature.
In Texas, aggressive marketing of competitive prices by rural electric cooperatives, municipally-owned electric systems, and other energy providers not subject to the traditional governmental regulation experienced by the utility industry has intensified competition within the state's wholesale markets and, in multi-certificated areas, retail customer markets. Furthermore, there is increasing pressure on utilities to reduce costs, including the cost of power, and to tailor energy services to the specific needs of customers. Such competitive pressures among electric utility and non-utility power producers could result in the loss by TU Electric of customers. In order to remain competitive, the US Electric segment companies are aggressively managing their operating costs and capital expenditures through streamlined business processes and are developing and implementing strategies to address an increasingly competitive environment. In a competitive retail environment, amounts invested by TU Electric in certain of its assets could become stranded costs (i.e., investments and commitments that may not be recoverable from customers as a result of competitive pricing). As such, the PUC is seeking guidance from the legislature and authority to address the issue of recovery of stranded costs. The PUC's latest available estimate for TU Electric's potentially stranded retail costs ranged from a projected excess of net book value over market value of $5.8 billion to a projected excess of market value over net book value of $3.8 billion. To the extent stranded costs cannot be recovered from customers, it may be necessary for such costs to be borne by shareholders.
While the Company and the US Electric segment companies anticipate legislation being enacted during the 1999 session of the Texas legislature to authorize retail competition, they cannot predict the ultimate outcome of the ongoing efforts that are taking place to restructure the electric utility industry or whether such outcome will have a material effect on their financial position, results of operations or cash flows.
The Company
UK -- Unless covered by an exemption, all electricity generators operating a power station in the UK are required to be a member of the Pool and to submit the output of power station generating units or turbines for central dispatch. Eastern Group's mix of generating plants enables it to operate in the mid-merit and base load sectors of the market and to spread its fuel risk. Almost all electricity customers in Eastern Group's authorized area, whether franchise (i.e. regulated) or competitive, are connected to and dependent upon Eastern Group's distribution system. Competition for electric retail customers in all areas of the UK is being progressively phased in, beginning in September 1998. The domestic franchise market in the UK is expected to be open to full competition in June 1999. These customers typically include residential and small commercial customers. Until September 1998, customers in all service areas could buy electricity only from the regional electricity company (REC) authorized to supply service in the area where the customers were located. Eastern Group competes on the basis of the quality of its customer service and by competitive pricing. Eastern Group intends to continue to compete nationally for residential and small business customers and, by December 1998, had contracts with 200,000 of such customers outside its franchise area. There is no assurance whether or not competition among suppliers of electricity will adversely affect Eastern Group. Because of UK government action in recent years, the UK natural gas market is open to competition by competing retailers. The gas market is highly competitive.
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Eastern Group is one of the largest suppliers of natural gas in the UK. As of December 31, 1998, Eastern Group's market share by volume was estimated at approximately 12% of gas delivered to the competitive industrial and commercial market. At December 31, 1998, it was supplying approximately 780,000 customers in the UK, ranging from residential households to large commercial companies. Eastern Group intends to maintain a significant share of this market through high quality customer service and competitive pricing.
Australia -- The energy supply franchise portion of Eastern Energy's business is gradually being exposed to competition through a phase-in of rules permitting customers to choose their energy supplier. This phase-in is by customer class and is expected to be complete by December 31, 2000, at which time all energy customers in Victoria will have the right to choose their energy supplier. Eastern Energy is required to offer distribution of electric energy in its service territory on behalf of other electric retail companies to those customers having a right to choose their supplier. Eastern Energy can similarly supply electric energy to such customers in other service territories by utilizing the distribution networks of the retail companies in those service territories. While Eastern Energy expects significant competition in the fully contestable energy retail marketplace, it cannot predict the ultimate outcome of this process.
RESULTS OF OPERATIONS
TU Electric
Net income of $798 million for 1998 increased approximately 3% from 1997. Results for 1997 were reduced by the recognition of an $81 million Fuel Disallowance (including interest) and a $10 million charge related to the sale of sulfur dioxide allowances, which reduced 1997 net income by $55 million. Excluding the effect of these items, 1998 net income decreased approximately 4% from 1997, and 1997 net income was approximately 4% less than 1996. Results for 1998 were impacted by the rate reduction settlement approved by the PUC in April 1998 that became effective January 1, 1998; increased nuclear depreciation and depreciation expense reclassified from transmission and distribution to nuclear production assets that reduced 1998 income by $143 million. These effects were partially offset by continued strong sales growth and the effect of hotter-than-normal summer weather.
Operating revenues increased approximately 6% and 2% for the years ended December 31, 1998 and 1997, respectively, over the prior-year period. The 1998 increase primarily results from the increase in base rate electricity revenues due to the exceptionally high summer temperatures and customer growth, partially offset by the effect of the rate reduction settlement on base rate revenues. The increase in 1997 operating revenues reflects transmission service revenues from implementation of the PUC's Open Access Transmission Rule (OAT Rule) effective January 1, 1997, with revenue increases due to customer growth essentially offsetting the impact of a rate settlement refund, the Fuel Disallowance and the charge related to the sulphur dioxide allowances.
Electric energy sales in gigawatt-hours (GWh) (including unbilled sales) increased approximately 6% and 2% for 1998 and 1997, respectively. Fuel revenue increased in 1998 and 1997 primarily due to increases in fuel costs driven by increased energy sales, with 1997 also affected by increased spot market gas prices, partially offset by the Fuel Disallowance.
Fuel and purchased power expense increased approximately 2% and 5% for 1998 and 1997, respectively. The increases were primarily due to increased energy sales in both periods with increased gas usage partially offset by decreased gas prices in 1998.
Total operating expenses, excluding fuel and purchased power, increased approximately 12% for 1998 and 5% for 1997. Operation and maintenance expense increased in 1998 largely as a result of higher marketing incentives, increased provision for uncollectible accounts and increased reactive maintenance expenses, partially offset by decreased employee related costs. The 1997 increase was a result of recording third party transmission expenses in accordance with the PUC's OAT Rule, partially offset by decreased employee benefit expenses. TU Electric's rate reduction settlement resulted in increased depreciation on its Comanche Peak nuclear power plant by $353 million in 1998, bringing total nuclear depreciation for the year to approximately $640 million. Of the $353 million, $183 million is the result of the transfer of transmission and distribution depreciation and $170 million
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is the result of TU Electric's earnings in excess of its rate cap. The change in the effective income tax rate was due to the impact of amortization of prior period flow-through amounts, which increased due to the accelerated depreciation on nuclear production assets in conjunction with the rate reduction agreement. Taxes, other than income taxes, increased in 1998 primarily due to higher state and local gross receipt taxes.
Total interest charges, excluding AFUDC and distributions on trust securities, decreased approximately 10% in 1998 and 11% in 1997 compared with the prior-year period. The capital restructuring and debt reduction programs have favorably affected the year-to-year comparisons. Distributions on trust securities and preferred stock dividends have decreased from 1997 reflecting the redemption in January 1998 of trust securities and the repurchases of a portion of TU Electric's preferred stock in the last two years.
The Company
Net income of $740 million for 1998 increased approximately 12% from 1997, reflecting continued strong US electric sales growth, the effect of hotter-than-normal summer weather on US electric sales and capital cost reductions in US electric operations. The results also reflect the addition of Eastern Group - especially Eastern Group's strong fourth quarter results - and LCC, significant improvement in the Company's US energy marketing operations and continued strong results from Australian operations. Partially offsetting was the impact of the rate reduction settlement at TU Electric; increased nuclear depreciation and depreciation expense reclassified from transmission and distribution to nuclear production assets that reduced 1998 income by $143 million. Results from US natural gas operations were unfavorably impacted by mild winter weather in both the first and fourth quarters of 1998.
Results for 1998 include a non-recurring gain from Eastern Group's renegotiations of a long-term gas contract and non-recurring costs associated with the acquisition of TEG, which offset to add $7 million to net income. Results for 1997 were reduced by the Fuel Disallowance and the charge related to the sale of sulfur dioxide allowances, which reduced 1997 net income by $55 million. Excluding these non-recurring items, 1998 net income was $733 million ($2.76 per share), compared with $715 million ($3.10 per share) for 1997 and $754 million ($3.35 per share) for 1996.
UK/Europe operations contributed approximately $140 million to 1998 income, which was partially offset by approximately $82 million of acquisition costs recorded by the Company, resulting in net income for these operations of $58 million for the period.
Operating revenues of the Company increased approximately 86% to $14.7 billion for the year ended December 31, 1998 compared with $7.9 billion in 1997 and $6.6 billion in 1996. In 1998, the increase in operating revenues was due primarily to the inclusion of the Eastern Group revenues for the period following the acquisition, ENSERCH revenues for the entire period, increased revenues from the US Electric segment and increased volumes from US energy marketing. The 1997 increase reflected ENSERCH revenues for the period following the merger and TU Electric's transmission service revenues from implementing the PUC's OAT Rule effective January 1, 1997.
Base rate electric revenues for the U S (including unbilled sales) increased 6% in 1998 primarily as a result of the hotter-than-normal summer weather and customer sales growth, partially offset by the TU Electric rate reduction settlement. Base rate revenues for 1997 decreased slightly from 1996 as a result of the rate settlement refund in 1997, while electric energy sales (including unbilled sales) increased approximately 2%. Fuel revenue increased in 1998 and 1997 due primarily to increases in fuel costs driven by increased energy sales, partially offset, in 1998 by lower gas prices and in 1997, by the Fuel Disallowance.
Fuel and purchased power expense increased approximately 72% and 4% for 1998 and 1997, respectively. The 1998 increase is primarily due to the inclusion of the Eastern Group for the period following acquisition, an increase in energy sales and gas usage for TU Electric, partially offset by a reduction in gas spot market prices and a reduction of energy purchase prices in TU Australia. The increase in 1997 was primarily due to increased energy
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sales and increased spot market gas prices. (See Consolidated Operating Statistics.) Gas and electricity purchased for resale increased as a result of the inclusion of ENSERCH for the entire year in 1998, as compared to the period following acquisition in 1997, along with the addition of the Eastern Group in 1998.
Total operating expenses, excluding fuel and purchased power and gas and electricity purchased for resale, increased approximately 58% for 1998 and 15% for 1997, with approximately 55% in 1998 attributable to the acquisition of the Eastern Group, and 13% in 1998 and 9% in 1997 attributable to ENSERCH companies since the merger. Other 1998 increases were mostly due to higher marketing incentives, increased provision for uncollectible accounts and increased reactive maintenance expenses, more than offset by decreased employee related and other costs. The 1997 increase was due to recording third party transmission expenses in accordance with the PUC's OAT Rule, partially offset by decreased employee benefit expenses. Taxes other than income increased in 1998 and 1997 due primarily to the effect of ENSERCH amounts for a full year in 1998 and for the period subsequent to acquisition in 1997, and an increase in revenue related taxes for 1998.
The increase in other income (deductions) - net in 1998 results primarily from the non-utility operations of Eastern Group since acquisition date and gains on the disposition of certain properties, while the 1997 decrease was primarily due to losses from an interest in a telecommunications partnership. Interest income increased as a result of the inclusion of Eastern Group since acquisition date.
Interest expense and distributions on trust securities and preferred stock of subsidiaries totaled approximately $1.4 billion in 1998, $861 million in 1997 and $884 million in 1996. The Company's capital restructuring and debt reduction programs have favorably affected the comparisons. Year-to-year comparisons were also affected by the debt incurred or recorded in connection with the 1998 acquisition of TEG and the 1997 acquisitions of ENSERCH and LCC. Interest expense in 1997 also included a charge related to the settlement of over-recovered fuel revenues.
The increase in the Company's overall effective income tax rate from 1997 to 1998 was due primarily to the effects of Eastern Group since acquisition along with the impact of TU Electric's amortization of prior period flow-through amounts, related to additional depreciation on nuclear production assets in conjunction with the rate reduction agreement. (See Note 12 to Consolidated Financial Statements for a reconciliation of income taxes computed at the statutory rate to provision for income taxes.
On a pro forma basis, as if TEG had been acquired at January 1, 1998, consolidated revenues for the year ended December 31, 1998 would have been $17 billion, consolidated net income would have been $884 million and basic earnings per share would have been $3.13. A substantial portion of Eastern Group's earnings occur during the first and fourth quarters of the year which are the periods of peak electricity usage in the UK.
EUROPEAN MONETARY UNION (EMU)
Most of Eastern Group's income and expenditures are denominated in pounds sterling or in the currencies of other countries which either are not eligible or have indicated that they are not intending to join the first stage of EMU. Eastern Group therefore does not expect the introduction of the Euro, the new currency of countries participating in EMU, to have a material impact on those operations for as long as the UK continues to remain outside EMU. Eastern Group has prepared its accounting systems to be able to deal with the receipt of payments in Euros effective from January 1, 1999.
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YEAR 2000 ISSUES
The Company and TU Electric
US -- 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.
The Company began its US efforts to address Year 2000 (Y2K) issues in 1996 by focusing on information technology mainframe-based application systems (IT Corporate Applications). In early 1997, an infrastructure project to address the Company'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 the Company 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 the Company'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. The Company 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 product 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 the Company. Inventories have been conducted to identify these embedded systems in individual business units. Assessments are substantially complete. Twenty-five of fifty-two fossil steam generating units were Y2K ready at the end of 1998. Validation testing is scheduled throughout the first half of 1999 on the remaining twenty-seven fossil generating units. 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 systems can be efficiently used in the Company'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.
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The Company has implemented a specific Y2K program at its Comanche Peak nuclear fueled electric generating station. Inventories were completed by mid 1998 and detailed assessments were made by December 1998. Remediation projects on Units 2 and 1 are scheduled for completion by May 1999 and September 1999, respectively.
The Company 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 the Company'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 the Company'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 the Company's transmission grid is being replaced. The Company'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.
LCC continues to work on its Y2K project. IT applications affected by Y2K issues are being replaced by systems with dramatically increased functionality. The cost of this effort is estimated to be $4 million, which is being expended through 1999. As of December 31, 1998, estimated costs expended were approximately $2.2 million.
Risk Issues
With respect to internal risks, the Company'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. The Company 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. The Company continues to collaborate with other major energy suppliers through the joint Electric Power Research Institute's embedded systems project.
The North American Electric Reliability Council (NERC) is continuing to evaluate the status of the electric infrastructure throughout North America. The Company is a participant in this process. The second NERC status report, issued on January 11, 1999, indicates that the transition through critical Y2K dates is expected to have minimal impact on electrical systems in North America and that, with continued work and coordinated contingency planning, operating risks can be effectively mitigated. Results from the Company's testing program compare favorably with the results on which the NERC conclusions have been based. NERC will perform scenario analyses of potential risks to the electric infrastructure. Joint industry testing between the electric industry and the telecommunications industry are also being planned. Until this work is complete, the Company cannot assess a worst case scenario relating to external interdependencies.
As the Company's Y2K program proceeds, the Company 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 the Company's control will have been adequately identified and corrected
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before the end of 1999. In addition, the Company can make no assurances regarding the Y2K readiness of systems and parties outside its control, or the effect on the Company if those parties are not Y2K compliant.
Contingency Plans
The Company has in place detailed emergency response and disaster recovery plans designed 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 PUC on December 31, 1998. These Y2K contingency plans address both Company 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 NERC. Final contingency plans are scheduled to be completed by June 1999.
The Company
International Operations -- Y2K Programs
UK/EUROPE -- Overview
In the UK, Eastern Group established a program of projects in August 1996 designed to ensure that all its systems are Y2K compliant. Each project has six phases: inventory, risk assessment, analysis, remediation, testing and contingency planning.
Readiness
The inventory, risk assessment and analysis of the mainframe systems were completed in June 1997. All COBOL code was fixed by November 1998. The plan, which is on schedule, is to complete the mainframe remediation work by April 1999 and testing work by July 1999.
Inventories of all other IT systems and of embedded systems (controls, monitoring, and protection systems, including electricity meters and customer premises and systems used in Eastern Group's offices) were completed in February 1998. Risk assessments were completed in August 1998. Many of the older IT systems have already been replaced by systems which are Y2K compliant, and approximately 25% of these were tested for Y2K compliance by August 1998 as part of the latest phase of electricity deregulation. Since October 1996, requirements have been included in Eastern Group's standard purchasing terms and conditions requiring Y2K readiness. Acceptance tests for any significant new or upgraded system include testing for Y2K readiness.
The IT infrastructure is currently based on a mixture of hardware and operating systems connected by local and wide area networks (LAN/WAN). The system will be remediated in March 1999 and tested and verified compliant by April 1999. Additional upgrade of the LAN/WAN is planned for 1999. The infrastructure PABX systems are being upgraded to be compliant by the end of February 1999.
Remediation products for three of the eight power station turbine control systems were not available from all suppliers in time for the planned summer shutdowns of 1998. Completion of this work has therefore been delayed until August 1999. All the electricity distribution systems have been checked, and testing was completed on all but one of the systems by December 31, 1998. Testing of the outstanding system for control room operation was completed in February 1999.
Costs
The costs of addressing the Y2K issue are estimated to be approximately $33 million. These costs include all Y2K related activities. They do not include the cost of addressing IT systems installed to achieve the
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liberalization of the domestic electricity market, systems installed to meet other business needs, or the cost of providing contingency plans for the trading business. These costs are being expensed as incurred. Amounts expended through December 1998 totaled $4.6 million. Cost expenditures for 1999 are estimated at $22.4 million and an additional $4 million for 2000.
Risk and Contingency Plans
With respect to internal risks, Eastern Group'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. Eastern Group believes, based on the results of testing that has already occurred on a large portion of production equipment with embedded systems, that if any disruption to service occurs, it will be isolated and of short-term duration.
Eastern Group has contingency plans for all business critical operations, except plans for the trading business which are currently under development. These plans cover realistic failure scenarios and are regularly tested. The Y2K Program process includes a review of all the existing contingency plans and the proposed contingency plans for the trading business to cover all realistic scenarios involving failures resulting from Y2K issues. The work is planned for January to June 1999, and will result in revisions to the existing contingency plans.
Eastern Group is working with its equipment and service suppliers to ensure their products and services are Y2K compliant. Reviews were completed by December 1998.
AUSTRALIA -- Overview
TU Australia initiated a Y2K Program in the third quarter of 1997 with the compilation of a Y2K inventory of supported IT assets and systems. An IT Project Manager was appointed and a consultant engaged to develop a Y2K remediation plan for items in the inventory assessed as having Y2K risk. A consulting firm was engaged in early 1998 to provide a methodology for addressing the Y2K risks of all other assets and systems. The consulting firm was subsequently retained to establish a Y2K Program Office and complete a non-IT inventory. A Y2K structure was also established in 1998 and a full time Program Director appointed to bring all activities together into a single TU Australia Y2K Program. The inventory contains over 800 different asset types divided approximately equally between IT and non-IT items. The program consists of sixty separate projects with individual project plans and project managers.
Readiness
Thirty-four of the sixty Y2K projects have been completed. Two projects track the progress of Y2K preparedness associated with telecommunications and electricity wholesale trading partners. Some vendor supplied program products will be available during the first quarter of 1999. The remaining projects are due for completion by July 1999 and are associated with the implementation of new applications for customer information and system control and data acquisition.
Costs
As a result of lower than anticipated requirements, the estimated costs associated with the Y2K program have been reduced to $2.3 million. Costs are expensed as incurred. Some additional costs included in capital budgets for new IT systems are not reflected in these Y2K costs. Approximately 50% of the Y2K costs were incurred during 1998 with the remainder to be incurred in the first quarter of 1999. There can be no assurance that these estimates will not increase as a result of the discovery of unexpected additional remediation work identified during Y2K testing.
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Risk Issues
With respect to internal risks, TU Australia'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. TU Australia believes, based on the results of testing that has already occurred on a large portion of production equipment with embedded systems, that if any disruption to service occurs, it will be isolated and of short-term duration.
Contingency Plans
TU Australia's Y2K contingency planning is being developed on three levels; asset level, project level and program level. In addition, Y2K contingency planning associated with assets that are assessed as having the capacity to interrupt electricity supply will be developed jointly with the rest of the Victorian Electricity Supply Industry. Y2K contingency plans at the asset level have been completed and several project level plans have also been prepared. The completion of the remainder of contingency plans represents the majority of Y2K activities planned in 1999. Y2K contingency plans will be incorporated into existing disaster plans and business continuity plans where appropriate.
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 that deal with hedge accounting and derivatives. The Company and TU Electric have not yet determined the effect adopting this standard will have on their financial statements.
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TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENT OF RESPONSIBILITY
The management of Texas Utilities Company is responsible for the preparation, integrity and objectivity of the consolidated financial statements of the Company and its subsidiaries and other information included in this report. The consolidated financial statements have been prepared in conformity with generally accepted accounting principles. As appropriate, the statements include amounts based on informed estimates and judgments of management.
The management of the Company has established and maintains a system of internal control designed to provide reasonable assurance, on a cost-effective basis, that assets are safeguarded, transactions are executed in accordance with management's authorization and financial records are reliable for preparing consolidated financial statements. Management believes that the system of control provides reasonable assurance that errors or irregularities that could be material to the consolidated financial statements are prevented or would be detected within a timely period. Key elements in this system include the effective communication of established written policies and procedures, selection and training of qualified personnel and organizational arrangements that provide an appropriate division of responsibility. This system of control is augmented by an ongoing internal audit program designed to evaluate its adequacy and effectiveness. Management considers the recommendations of the internal auditors and independent certified public accountants concerning the Company's system of internal control and takes appropriate actions which are cost-effective in the circumstances. Management believes that, as of December 31, 1998, the Company's system of internal control was adequate to accomplish the objectives discussed herein.
The Board of Directors of the Company addresses its oversight responsibility for the consolidated financial statements through its Audit Committee, which is composed of directors who are not employees of the Company. The Audit Committee meets regularly with the Company's management, internal auditors and independent certified public accountants to review matters relating to financial reporting, auditing and internal control. To ensure auditor independence, both the internal auditors and independent certified public accountants have full and free access to the Audit Committee.
The independent certified public accounting firm of Deloitte & Touche LLP is engaged to audit, in accordance with generally accepted auditing standards, the consolidated financial statements of the Company and its subsidiaries and to issue their report thereon.
/s/ ERLE NYE ------------------------------- Erle Nye, Chairman of the Board and Chief Executive
/s/ D. W. BIEGLER ------------------------------- D. W. Biegler, President and Chief Operating Officer
/s/ MICHAEL J. McNALLY ------------------------------- Michael J. McNally, Executive Vice President and Chief Financial Officer
/s/ JERRY W. PINKERTON
---------------------------------- Jerry W. Pinkerton, Controller and Principal Accounting Officer
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TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES STATEMENT OF RESPONSIBILITY
The management of Texas Utilities Electric Company is responsible for the preparation, integrity and objectivity of the financial statements of TU Electric and its subsidiaries and other information included in this report. The financial statements have been prepared in conformity with generally accepted accounting principles. As appropriate, the statements include amounts based on informed estimates and judgments of management.
The management of TU Electric has established and maintains a system of internal control designed to provide reasonable assurance, on a cost-effective basis, that assets are safeguarded, transactions are executed in accordance with management's authorization and financial records are reliable for preparing financial statements. Management believes that the system of control provides reasonable assurance that errors or irregularities that could be material to the financial statements are prevented or would be detected within a timely period. Key elements in this system include the effective communication of established written policies and procedures, selection and training of qualified personnel and organizational arrangements that provide an appropriate division of responsibility. This system of control is augmented by an ongoing internal audit program designed to evaluate its adequacy and effectiveness. Management considers the recommendations of the internal auditors and independent certified public accountants concerning TU Electric's system of internal control and takes appropriate actions which are cost-effective in the circumstances. Management believes that, as of December 31, 1998, TU Electric's system of internal control was adequate to accomplish the objectives discussed herein.
The independent certified public accounting firm of Deloitte & Touche LLP is engaged to audit, in accordance with generally accepted auditing standards, the financial statements of TU Electric and to issue their report thereon.
/s/ ERLE NYE ---------------------------------- Erle Nye, Chairman of the Board and Chief Executive
/s/ D. W. BIEGLER ---------------------------------- D. W. Biegler, President and Chief Operating Officer
/s/ KIRK OLIVER ---------------------------------- Kirk Oliver, Treasurer and Assistant Secretary and Principal Financial Officer
/s/ Jerry W. PINKERTON ---------------------------------- Jerry W. Pinkerton, Controller and Principal Accounting Officer
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INDEPENDENT AUDITORS' REPORT
Texas Utilities Company:
We have audited the accompanying consolidated balance sheets of Texas Utilities Company and subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of income, comprehensive income, cash flows and common stock equity for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We did not audit the consolidated financial statements of TXU Eastern Holdings Limited (a consolidated subsidiary), which statements reflect total assets constituting 36% of consolidated total assets at December 31, 1998, and total revenues constituting 24% of consolidated total revenues for the year ended December 31, 1998. Those statements were audited by other auditors whose report has been furnished to us, and our opinion, insofar as it relates to the amounts included for TXU Eastern Holdings Limited, is based solely on the report of such other auditors. 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 and the report of the other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the report of the other auditors, such consolidated financial statements present fairly, in all material respects, the financial position of Texas Utilities Company and subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Dallas, Texas March 5, 1999
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REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors and Shareholder of TXU Eastern Holdings Limited:
In our opinion, the consolidated balance sheet and the related statements of consolidated income, comprehensive income, common stock equity and cash flows present fairly, in all material respects, the financial position of TXU Eastern Holdings Limited and its subsidiaries at December 31, 1998, and the results of their operations and their cash flows for the period from formation (February 5, 1998) to December 31, 1998 in conformity with accounting principles generally accepted in the United States. These financial statements are the responsibility of the Company's management; our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit of these statements in accordance with generally accepted auditing standards in the United Kingdom which do not differ significantly with those in the United States and which 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, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for the opinion expressed above.
PricewaterhouseCoopers London, England 3 March 1999
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INDEPENDENT AUDITORS' REPORT
Texas Utilities Electric Company:
We have audited the accompanying consolidated balance sheets of Texas Utilities Electric Company (TU Electric) and subsidiaries as of December 31, 1998 and 1997, and the related consolidated statements of income, comprehensive income, common stock equity and cash flows for each of the three years in the period ended December 31, 1998. These financial statements are the responsibility of TU Electric 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, such consolidated financial statements present fairly, in all material respects, the financial position of Texas Utilities Electric Company and subsidiaries at December 31, 1998 and 1997, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 1998, in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Dallas, Texas March 5, 1999 A-27
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TEXAS UTILITIES COMPANY AND SUBSIDIARIES TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BUSINESS, MERGERS AND ACQUISITIONS
The Company
Texas Utilities Company (TUC or the Company), a Texas corporation, is a holding company whose principal United States (US) operations are conducted through Texas Utilities Electric Company (TU Electric), ENSERCH Corporation (ENSERCH), and Texas Energy Industries, Inc. (TEI). Its principal international operations are conducted through TU International Holdings Limited (TU International Holdings), whose principal operating subsidiaries include Eastern Group plc (a subsidiary of TXU Eastern Holdings Limited) (Eastern Group) in the United Kingdom (UK) and Eastern Energy Limited (Eastern Energy) in Australia. Through its subsidiaries, the Company 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, UK and Australia.
In March 1998, the Company made an offer for all the ordinary shares of The Energy Group PLC (TEG). The Company's offer for TEG was declared unconditional on May 19, 1998, which was determined to be the date the Company acquired TEG. By the end of August 1998, the Company had acquired all of TEG's outstanding shares. The Company recorded its approximate 22% equity interest in the net income of TEG for the period March 1998 to May 19, 1998 and has accounted for TEG and Eastern Group as consolidated subsidiaries since May 19, 1998.
Immediately prior to being acquired by the Company, TEG completed the sale of its US and Australian coal business and US energy marketing operations (Peabody Sale). The TEG businesses acquired by TUC, which exclude those representing the Peabody Sale, are referred to as "TEG Businesses Acquired". The total purchase consideration for the TEG Businesses Acquired was approximately $7.4 billion, including cash paid of $5.8 billion and non-cash consideration of $1.6 billion, which consists primarily of the value assigned to the 37,316,884 shares of TUC common stock issued to those holders of TEG shares who elected to receive shares of TUC common stock in exchange for their TEG shares. At the date of the acquisition, TEG had assets of $10.4 billion, including cash of $3.3 billion, and liabilities of $8.4 billion including a provision for unfavorable contracts and leases and $5.1 billion in debt. The process of determining the fair value of assets acquired and liabilities assumed of TEG has not been completed; however, the excess of the purchase consideration plus acquisition costs over a preliminary estimate of net fair value of tangible and identifiable intangible assets acquired and liabilities assumed resulted in goodwill of $5.4 billion, which is being amortized over 40 years. This amount is subject to revision as additional information about the fair value of TEG's assets acquired, liabilities assumed and contingencies existing at the acquisition date becomes known. In particular, there is uncertainty over the valuation of the electricity distribution system including metering assets pending finalization of the current distribution price review and the intention that the metering business market becomes competitive in 2000. In addition, there is uncertainty over the final settlement price of the Peabody Sale and the outcome of certain proceedings concerning the pension scheme.
On August 5, 1997, the merger transactions (Merger) involving the former Texas Utilities Company, now known as TEI, and ENSERCH were completed. The value assigned to the TUC shares issued and costs incurred in connection with the acquisition of ENSERCH aggregated $579 million. On November 21, 1997, the Company acquired Lufkin-Conroe Communications Co. (LCC). The value assigned to the TUC shares issued and costs incurred in connection with the acquisition of LCC aggregated $319 million. The acquisitions of ENSERCH and LCC were accounted for as purchase business combinations. A-39
The following summary of unaudited pro forma consolidated results of the Company's operations reflects the operations of the TEG Businesses Acquired, ENSERCH and LCC as though each acquisition had occurred at the beginning of each period presented. Expenses of the acquisitions incurred by the Company, the 22% equity in earnings of TEG and a one-time windfall tax imposed on TEG have been eliminated. Amounts are in millions of dollars, except per share amounts.
The above pro forma results are based on the most current estimate of the fair value of assets acquired, liabilities assumed and contingencies existing as of the acquisition dates of the TEG Businesses Acquired for the 1998 period and ENSERCH and LCC for the 1997 period. These results are not necessarily indicative of what the actual results would have been had the acquisitions occurred at the beginning of these periods. Further, the pro forma results are not intended to be a projection of the future results of the combined companies.
On February 24, 1999, TU Australia acquired from the Government of Victoria, Australia the gas retail business of Kinetik Energy, which has approximately 400,000 gas customers, and the gas distribution operations of Westar, which are of similar size. The purchase price was $1.0 billion for Westar/Kinetik Energy assets.
2. SIGNIFICANT ACCOUNTING POLICIES
The Company and TU Electric
Consolidation -- The consolidated financial statements include the accounts of the Company and all of its majority owned subsidiaries. The consolidated financial statements of TU Electric include all of its business trusts.
All significant intercompany items and transactions have been eliminated in consolidation. Investments in significant unconsolidated affiliates are accounted for by the equity method. Certain previously reported amounts have been reclassified to conform to current classifications.
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 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.
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System of Accounts -- The accounting records of TU Electric are maintained in accordance with the Federal Energy Regulatory Commission's (FERC) Uniform System of Accounts as adopted by the Public Utility Commission of Texas (PUC). Lone Star Gas Company (Lone Star Gas) and Lone Star Pipeline Company (Lone Star Pipeline), divisions of ENSERCH, are subject to the accounting requirements prescribed by the National Association of Regulatory Utility Commissioners (NARUC). Eastern Group separately prepares regulatory accounts under accounting requirements specified by the Office of Electricity Regulation (OFFER).
Property, Plant and Equipment -- US electric and gas utility plant is stated at original cost less certain regulatory disallowances. The cost of property additions to US electric and gas utility plant includes labor and materials, applicable overhead and payroll-related costs and an allowance for funds used during construction (AFUDC). Other property, including non-US property, is stated at cost.
Allowance For Funds Used During Construction -- AFUDC is a cost accounting procedure whereby amounts based upon interest charges on borrowed funds and a return on equity capital used to finance construction are added to US utility plant.
TU Electric and other regulated US subsidiaries capitalize AFUDC on expenditures for ongoing construction work in progress and nuclear fuel in process not otherwise allowed in rate base by regulatory authorities. For 1998, 1997 and 1996, TU Electric used rates of 8.0%, 7.9% and 7.4%, respectively.
Depreciation of Property, Plant and Equipment -- Depreciation of the Company's US electric and gas utility plant is generally based upon an amortization of the original cost of depreciable properties (net of regulatory disallowances) on a straight-line basis over the estimated service lives of the properties. Depreciation also includes an amount for decommissioning costs for TU Electric's nuclear powered electric generating station (Comanche Peak) which is being accrued over the lives of the units. Depreciation of all other plant and equipment generally is determined by the straight-line method over the estimated useful life of the asset. Consolidated depreciation as a percent of average depreciable property for the Company approximated 3.0% for 1998, 2.6% for 1997 and 2.7% for 1996. The fair value of the acquired UK power stations under capital lease is amortized to expense ratably over the remaining estimated economic life of the power stations which extend to 2018. The UK government is entitled to claim a portion of any gain realized by Eastern Group on certain subsidiary property disposals made up to March 31, 2000. Provisions for such claims are made to the extent that such liabilities are probable, including when an actual or deemed disposal occurs. The successful efforts method is used to account for UK natural gas fields. Depletion is charged on a unit-of-production basis.
Amortization of Goodwill -- Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed for each company acquired and is being amortized over 40 years. The process of determining the fair value of assets acquired, liabilities assumed and contingencies existing at the acquisition date of ENSERCH and LCC 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.
Amortization of Nuclear Fuel and Refueling Outage Costs -- The amortization of nuclear fuel in the reactors (net of regulatory disallowances) is calculated on the units-of-production method and is included in nuclear fuel expense. TU Electric accrues a provision for costs anticipated to be incurred during the next scheduled refueling outage for Comanche Peak.
Foreign Currency Translation -- The assets and liabilities of non-US operations denominated in local currencies are translated at rates in effect at year end. Revenues and expenses are translated at average rates for the applicable periods. Generally, local currencies are considered to be the functional currency, and adjustments resulting from such translation are A-41
included in other comprehensive income, a separate component of common stock equity.
Derivative Instruments -- The Company and its subsidiaries do not enter into or trade derivative financial instruments for speculative purposes, other than for trading purposes in US energy marketing activities. The Company 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. Swaps, options and forward contracts are used to hedge foreign currency exposure in the Company's UK and Australian operations. The Company also enters into derivative contracts or other contractual agreements in connection with the wholesale purchases of electric energy by Eastern Group in the UK and Eastern Energy in Australia and defers the impact of changes in the market value of the derivative instruments, which serve as hedges, until the related transaction is completed. (See Note 10.) Eastern Group evaluates its net open energy trading position, including derivative financial instruments entered into as a part of energy trading activities, and provides for any anticipated future losses.
Energy Marketing Activities --The Company, 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 Company'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 Company'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 10.)
Revenues -- Electric and gas sales revenues are recognized when services are provided to customers on the basis of periodic cycle meter readings and include an estimated accrual for the value of electricity and gas provided from the meter reading date to the end of the period. US electric and gas revenues include billings under approved rates and adjustments under various mechanisms to recover or refund the cost of fuel and purchased power costs that are above or below the level included in base rates. (See Note 13 for a discussion of Regulations and Rates.)
Income Taxes --The Company and its US subsidiaries file a consolidated federal income tax return, and federal income taxes are allocated to subsidiaries based upon their respective taxable income or loss. Investment tax credits are normally amortized to income over the estimated service lives of the properties. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Certain provisions of Statement of Financial Accounting Standards (SFAS) No. 109 provide that regulated enterprises are permitted to recognize such adjustments as regulatory tax assets or tax liabilities if it is probable that such amounts will be recovered from, or returned to, customers in future rates.
Income Taxes on Undistributed Earnings of Foreign Subsidiaries -- The Company intends to reinvest the earnings of its foreign subsidiaries into those businesses. Accordingly, no provision has been made for taxes which would be payable if such earnings were to be repatriated.
Earnings Per Share -- Basic earnings per share applicable to common stock are based on the weighted average number of common shares outstanding during the year. Diluted earnings per share include the effect of potential common shares resulting from the assumed conversion of the convertible subordinated debentures of ENSERCH for the period outstanding and the exercise of all outstanding stock options. For the year ended December 31, 1998 and for the period from the date of the Merger to December 31, 1997, 677,269 and 999,492
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shares, respectively, were added to the average shares outstanding and $.9 million and $1.5 million, respectively, of after-tax interest expense was added to earnings applicable to common stock for the purpose of calculating diluted earnings per share.
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 Company's and TU Electric's cash payments and non-cash investing and financing activities:
Regulatory Assets and Liabilities -- SFAS 71 applies to utilities which have cost-based rates established by a regulator and charged to and collected from customers. The Company's US regulated subsidiaries defer the recognition of certain costs (regulatory assets) and certain obligations (regulatory liabilities) that, as a result of the rate making process, have probable corresponding increases or decreases in future revenues. These regulatory assets and liabilities are being amortized over various periods of 5 to 40 years and are currently included in rates, or are expected to be included in future rates.
Significant net regulatory assets are as follows:
TN#34 Future significant changes in regulation or competition could affect the US regulated subsidiaries' ability to meet the criteria for continued application of SFAS 71 and may affect their ability to recover these A-43
regulatory assets from, or refund these regulatory liabilities to, customers. If the affected subsidiaries were to discontinue the application of SFAS 71, they would be required to assess the recoverability of US plant and regulatory assets. The Company and TU Electric cannot predict the ultimate outcome of the ongoing efforts that are taking place to restructure the electric utility industry or whether the outcome of such efforts will have a material effect on its financial position, results of operations or cash flows.
TU Electric
Affiliates -- The Company provides common stock capital and a part of short-term financing requirements to TU Electric and other subsidiaries. The Company has other subsidiaries which perform specialized services for TU Electric and other subsidiaries; Texas Utilities Services Inc. (TU Services) which provides financial, accounting, information technology, environmental, customer, procurement, personnel, shareholder and other administrative services at cost; Texas Utilities Fuel Company (Fuel Company), which owns a natural gas pipeline system, acquires, stores and delivers fuel gas and provides other fuel services at cost for the generation of electric energy by TU Electric; and Texas Utilities Mining Company (Mining Company), which owns, leases and operates fuel production facilities for the surface mining and recovery of lignite at cost for use at TU Electric's generating stations. TU Electric provides services such as energy sales, wheeling and scheduling to Southwestern Electric Service Company (SESCO), an electric utility subsidiary of the Company operating in the eastern and central part of Texas.
TU Electric has entered into agreements with Fuel Company for the procurement of certain fuels and related services and with Mining Company for the procurement and production of lignite. Payments are at cost for the services received and are required by the agreements to be "at least equivalent in the aggregate to the annual charge to income on the books" of Fuel Company and of Mining Company. TU Electric is, in effect, obligated for the principal, $325 million at December 31, 1998, and interest on long-term notes of Mining Company through payments described above. Such notes mature at various dates through 2005 and have interest rates ranging from 6.5% to 7.0%.
The schedule below details TU Electric's significant billings to and from affiliates for services rendered and interest on short-term financings:
3. SHORT-TERM FINANCING
The Company The Company had outstanding short-term borrowings of $2,951 million consisting of commercial paper of $2,055 million and bank borrowings of $896 million at December 31, 1998. The weighted average interest rates on such borrowings was 6.46% at December 31, 1998. During the years 1998, 1997 and 1996, the Company's average amounts outstanding for short-term borrowings, including amounts classified as long-term, were $3,131 million, $1,222 million and $594 million, respectively. Weighted average interest rates for short-term borrowings during such periods were 5.84%, 5.86%, and 5.94%, respectively. A-44
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 TEG, are limited to an aggregate of $2,200 million outstanding at any one time. TU Electric's and ENSERCH's borrowings under both facilities are limited to an aggregate of $1,250 million and $650 million outstanding at any one time, respectively. The facilities primarily support commercial paper borrowings.
In addition, a separate Eastern Electricity Revolving Credit Facility provides for short term borrowings for general corporate purposes of up to 250 million pounds ($414 million) outstanding at any one time and terminates March 2, 2003. Under this facility, 180 million pounds ($298 million) was outstanding at year-end 1998.
The Company intends to refinance $874 million of its current short-term borrowings beyond one-year of December 31, 1998; such amount has been reclassified as long-term debt.
In addition, certain non-US subsidiaries have revolving credit agreements (denominated in both foreign currencies and US dollars) aggregating approximately $106 million, of which $83 million was outstanding at December 31, 1998. These revolving credit agreements expire at various dates through 2001.
TU Electric
TU Electric had no borrowings from banks in 1998, 1997 or 1996 and no commercial paper outstanding in 1998. TU Electric's average commercial paper outstanding was $37 million and $254 million, for 1997 and 1996, respectively. During such periods, weighted average interest rates to holders of commercial paper were 5.61% and 5.53%, respectively. Average borrowings outstanding from other affiliates were $206 million, $158 million and $10 million during 1998, 1997, and 1996, respectively, and the respective weighted average interest rates for such borrowings were 5.84%, 5.88% and 5.91%.
4. COMMON STOCK
The Company The Company has a Direct Stock Purchase and Dividend Reinvestment Plan (DRIP), an Employees' Thrift Plan of the Texas Utilities Company System (Thrift Plan) and an Employee Stock Purchase and Savings Plan of ENSERCH (EN$AVE). During the last three years, most of the requirements under the DRIP, Thrift Plan and EN$AVE plans have been met through open market purchases of the Company's common stock. In 1998, approximately $8 million in common stock of the Company was issued to the plans.
At December 31, 1998, the Thrift Plan had an initial obligation of $250 million outstanding in the form of a note, which the Company purchased from the original third-party lender and recorded as a reduction to common equity. At December 31, 1998, the Thrift Plan trustee held 5,141,529 shares of common stock (LESOP Shares) of the Company under the leveraged employee stock ownership provision of the Thrift Plan. LESOP Shares are held by the trustee until allocated to Thrift Plan participants when required to meet the Company's obligations under terms of the Thrift Plan. The Thrift Plan uses dividends on the LESOP Shares held and contributions from the Company, if required, to repay interest and principal on the note. Common stock equity increases at such time as LESOP Shares are allocated to participants' accounts although shares of common stock outstanding include unallocated LESOP Shares A-45
held by the trustee. Allocations to participants' accounts in each of the years 1998, 1997 and 1996 increased common stock equity by $8 million each year.
The Long-Term Incentive Compensation Plan is a comprehensive, stock-based incentive compensation plan, providing for discretionary awards (Awards) of incentive stock options, nonqualified stock options, stock appreciation rights, restricted stock, restricted stock units, performance shares, performance units, bonus stock and other stock-based awards. The maximum number of shares of common stock for which Awards may be granted under the plan is 2,500,000. During 1998 and 1997, the Board of Directors authorized the award of 68,000 and 61,000 shares, respectively, of restricted common stock, which were issued subject to performance and vesting requirements over a three to five year period. No stock options were granted.
Effective with the Merger, under terms specified in the Merger agreement, outstanding options for ENSERCH common stock were exchanged for options for 532,913 shares of the Company's common stock exercisable at prices ranging from $7.03 to $37.71 per share, and ENSERCH was precluded from awarding further options. 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.
At December 31, 1998, 25,225,357 shares of the authorized but unissued common stock of the Company were reserved for issuance and sale pursuant to the above plans, for equity-linked securities and for other purposes.
In November 1997, the Company's Board of Directors increased the common stock repurchase limit to $350 million of which $227 million had been used as of December 31, 1998 to purchase and retire a total of 5,819,251 shares of the Company's issued and outstanding common stock during the three years then ended. The cost of the repurchased shares, to the extent it exceeded the estimated amount received upon their original issuance, has been charged to retained earnings.
The Company has 50 million authorized shares of serial preference stock having a par value of $25 per share, none of which has been issued.
Shareholders Rights Plan -- On February 19, 1999, the Board of Directors adopted a shareholder rights plan pursuant to which shareholders were granted rights to purchase one one-hundreth of a share of Series A Preference Stock (Rights) for each share of the Company's common stock held.
In the event that any person acquires more than 15% of the Company's outstanding Common Stock, the Right becomes exercisable, entitling each holder (other than the acquiring person or group) to purchase that number of shares of securities or other property of the Company having a market value equal to two times the exercise price of the Right. If the Company were acquired in a merger or other business combination, each Right would entitle its holder to purchase a number of the acquiring company's common shares having a market value of two times the exercise price of the Right. In either case, the Company's Board of Directors may choose to redeem the Rights before they become exercisable.
The Company's Board declared a dividend of one Right for each outstanding share of Common Stock. Rights were distributed to shareholders of record on March 1, 1999. A-46
TU Electric
During the years ended December 31, 1998 and 1997, TU Electric purchased and retired a total of 19,270,300 and 13,869,000 shares of its issued and outstanding common stock at a total cost of approximately $587 million and $416 million, respectively. TU Electric had no common stock transactions in 1996. In February 1999, TU Electric purchased 4,946,500 shares of its issued and outstanding common stock at a total cost of approximately $148 million.
No shares of TU Electric's common stock are held by or for its own account, nor are any shares of such capital stock reserved for its officers and employees or for options, warrants, conversions and other rights in connection therewith.
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5. LONG-TERM DEBT, less amounts due currently
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The Company
At December 31, 1998, TXU Eastern Holdings Limited (TXU Eastern), formerly TU Finance (No. 1) Limited, TU Finance (No. 2) Limited, TU Acquisitions and Eastern Group, had a joint sterling-denominated line of credit with a group of banking institutions under a credit facility agreement (Sterling Credit Agreement). Originally, the Sterling Credit Agreement provided for borrowings of up to 3,375 million pounds and was comprised of three facilities: the Acquisition, Interim, and Revolving Credit facilities. During 1998, the Interim facility was repaid and has been cancelled. The aggregate borrowing limit of the remaining facilities, which mature March 2, 2003, has been reduced to 1,275 million pounds ($2,109 million) at December 31, 1998. At December 31, 1998, the Acquisition facility had a balance of 750 million pounds ($1,241 million) outstanding, and no additional borrowings are permitted. The Revolving Credit facility had a balance of 51 million pounds ($84 million) outstanding at December 31, 1998.
As of December 31, 1998, TXU Eastern had entered into various interest rate swaps as required by the Sterling Credit Agreements. The aggregate notional amount of the interest rate swaps entered into was 800 million pounds ($1,324 million). The swaps have an average maturity of six years and an average fixed rate of 6.58%.
The Company recorded the liabilities of TEG upon acquisition, including an agreement with commercial banks whereby future intra-group rental payments receivable were assigned to the banks in return for a capital sum of 1,097 million pounds. These obligations are disclosed net of deferred finance charges. A portion of the proceeds have been deposited as collateral for obligations in respect of the funding of capital leases of certain power stations. (See Note 14.)
In July and August of 1998, the Company issued a total of 14 million equity-linked securities consisting of 12,700,000 units of income equity-linked securities with a stated amount per security of $50 and 1,300,000 units of growth equity-linked securities with a stated amount per security of $50. The Company also issued $32.5 million aggregate principal amount of 6.37% Series D Senior Notes due August 16, 2003 (Series D Notes) and $32.5 million aggregate principal amount of 6.50% Series E Senior Notes due August 16, 2004 (Series E Notes).
Each income equity-linked security initially consists of a unit comprised of (i) a purchase contract (Purchase Contract) under which the holder will purchase from the Company by not later than August 16, 2001 (first settlement date) for $25 cash a specified number of shares of the Company's common stock (based on a formula using the market price of the Company's common stock) and will purchase from the Company by not later than August 16, 2002 (second settlement date) for $25 cash a specified number of shares of the Company's common stock (based on a formula using the market price of the Company's common stock), (ii) until the first settlement date, a Series D Note having a principal amount of $25, and (iii) until the second settlement date, a Series E Note having a principal amount of $25. Initially, $317.5 million aggregate principal amount of Series D Notes and $317.5 million aggregate principal amount of Series E Notes were issued to be held as a component of the equity-linked securities. The holder of an income equity-linked security is entitled to receive from the Company quarterly payments, in arrears, at 9.25% per annum of the stated amount of such security ($50) prior to the first settlement date and 9.25% per annum of the remaining stated amount ($25) from that date to the second settlement date, consisting of contract adjustment payments of 2.815% per annum of the stated amount and interest on the Series D Note and the Series E Note through the first settlement date and 2.75% per annum of the remaining stated amount and interest on the Series E Note through the second settlement date.
Each growth equity-linked security initially consists of a unit comprised of (i) a Purchase Contract, (ii) until the first settlement date, beneficial ownership interest in a 1/40th undivided interest in a 3-year Treasury security having a principal amount at maturity equal to $1,000, and (iii) until the second settlement date, a 1/40th undivided interest in a 4-year Treasury security having a principal amount at maturity equal to $1,000. The holder of a growth equity-linked security will receive from the Company, quarterly in arrears, contract adjustment payments of 3.315% per annum of the A-49
stated amount of such security ($50) to the first settlement date and 3.25% per annum of the remaining stated amount ($25) from the first to the second settlement date.
Under the terms of the Purchase Contracts, the Company will issue between 7,115,267 and 8,395,802 shares of common stock by the first settlement date and between 7,115,267 and 8,395,802 additional shares by the second settlement date.
The Company recorded as a reduction of common stock equity, the present value of the contract adjustment payments and a portion of the costs in connection with the issuance of the equity-linked securities aggregating approximately $76 million. A liability was recorded for the contract adjustment payments and will be reduced as the contract adjustment payments are made. The Company has the right to defer the contract adjustment payments, but any such election will subject the Company to restrictions on the payment of dividends on and redemption of outstanding shares of its common stock.
In October 1998, the Company issued $375 million aggregate principal amount of 5.94% Mandatory Putable/Remarketable Securities. On October 15, 2001, the notes will be subject to mandatory tender to a remarketing dealer, if the remarketing dealer chooses to remarket the notes. If the remarketing dealer does not purchase the notes, they must be repurchased by the Company. If the remarketing dealer chooses to remarket, the Company may elect to have the notes remarketed on October 15, 2001, for an interim period of up to 26 weeks at an interest rate to be reset weekly. On October 15, 2001 or, if applicable, at the end of the interim period, the notes will be remarketed at a reset interest rate to maturity or repurchased by the Company. The notes are scheduled to mature on October 15, 2011, but that maturity date will be extended by the length of any interim period.
Also in October 1998, the Company issued $125 million aggregate principal amount of its Floating Rate Senior Notes due April 20, 2000. Interest on the notes will be set quarterly based on LIBOR for three month deposits plus a margin. In October 1998, the interest rate on the Floating Rate Senior Notes was effectively fixed through an interest rate swap at a rate of 5.248% through maturity.
Sinking fund and maturity requirements for the years 1999 through 2003 under long-term debt instruments in effect at December 31, 1998, were as follows:
TU Electric's first mortgage bonds are secured by a mortgage and deed of trust with a major financial institution. Electric plant of TU Electric is generally subject to the lien of its mortgage.
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6. DIVIDEND RESTRICTIONS OF TU ELECTRIC AND OTHER SUBSIDIARIES OF THE COMPANY
The articles of incorporation and/or the mortgage, as supplemented, and certain other debt instruments of TU Electric contain provisions which, under certain conditions, restrict distributions on or acquisitions of common stock. At December 31, 1998, $13 million of retained earnings of TU Electric, were thus restricted as a result of such provisions. Certain debt instruments of Eastern Group contain provisions that, under certain conditions, may restrict distributions on or acquisitions of common stock. At December 31, 1998, none of Eastern Group's retained earnings was restricted as a result of such provisions.
7.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 that deal with hedge accounting and derivatives. The Company and TU Electric have not yet determined the effect adopting this standard will have on their financial statements.
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8. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and related estimated fair values of the Company's and TU Electric's significant financial instruments at December 31, 1998 and 1997, are as follows:
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The fair values of long-term debt and preferred stock subject to mandatory redemption are estimated at the lesser of either the call price or the market value as determined by quoted market prices, where available, or, where not available, at the present value of future cash flows discounted at rates consistent with comparable maturities with similar credit risk. The fair values of trust securities and preferred stock of subsidiaries are based on quoted market prices. The carrying amounts for financial assets classified as current assets and the carrying amounts for financial liabilities classified as current liabilities approximate fair value due to the short maturity of such instruments.
Other investments include deposits in an external trust fund for nuclear decommissioning of Comanche Peak and restricted cash held as collateral for certain leases. The trust fund is invested primarily in fixed income debt and equity securities, which are considered as available-for-sale. Any unrealized gains or losses are treated as regulatory assets or regulatory liabilities, respectively.
Common stock - net has been reduced by the note receivable from the trustee of the leveraged employee stock ownership provision of the Thrift Plan. The fair value of such note is estimated at the lesser of the Company's call price or the present value of future cash flows discounted at rates consistent with comparable maturities adjusted for credit risk.
The fair value of the financial guarantees is based on the present value of the instruments' approximate cash flows discounted at the year-end risk free rate for issues of comparable maturities adjusted for credit risk.
Fair values for off-balance sheet instruments (interest rate and currency swaps) are based either on quotes or the cost to terminate the agreements.
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.
9. COMPANY OR SUBSIDIARY OBLIGATED, MANDATORILY REDEEMABLE, PREFERRED SECURITIES OF COMPANY OR SUBSIDIARY TRUSTS, EACH HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF THE COMPANY OR RELATED SUBSIDIARY (TRUST SECURITIES)
Statutory business trusts have been established as wholly-owned financing subsidiaries (trusts) of the Company, TU Electric and ENSERCH (parent companies) for the purposes, in each case, of issuing trust securities and holding Junior Subordinated Debentures issued by the trust's parent company (Debentures). TXU Capital I and TU Electric Capital I and III trust securities have a liquidation preference of $25 per unit, and TU Electric Capital IV and V and ENSERCH Capital I trust securities have a liquidation preference of $1,000 per unit. The only assets of each trust are Debentures of its parent company having a principal amount set forth under "Trust Assets" in the table below. The interest on trust assets matches the distributions on the trust securities. Each trust will use interest payments received on the Debentures it holds to make cash distributions on the trust securities it has issued.
The trust securities are subject to mandatory redemption upon payment of the Debentures at maturity or upon redemption. The Debentures are subject to redemption, in whole or in part at the option of the parent company, at 100% of their principal amount plus accrued interest, after an initial period during which they may not be redeemed and at any time upon the occurrence of certain events. The carrying value of the trust securities is being increased periodically to equal the redemption amounts at the mandatory redemption dates with a corresponding increase in trust securities distributions.
In December 1998, a statutory business trust, TXU Capital I, was established as a financing subsidiary for the Company for the purpose of issuing to investors $230 million of 7.25% Trust Securities.
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At December 31, 1998 and 1997, the statutory business trust subsidiaries of the Company, TU Electric and ENSERCH had trust securities outstanding, as follows:
Each parent company owns securities issued by its subsidiary trust and has effectively issued a full and unconditional guarantee of such trust's securities.
10. DERIVATIVE INSTRUMENTS The Company enters into derivative instruments, including options, swaps, futures and other contractual commitments to manage market risks related to changes in interest rates, foreign currency exchange rates and commodity price exposures. The Company's participation in derivative transactions, except for its energy marketing activities conducted by EES, have been designated for hedging purposes and are not held or issued for trading purposes. (For a discussion of accounting policies relating to derivative instruments, see Note 2.)
Interest Rate Risk Management -- At December 31, 1998, TU Electric had an interest rate swap agreement with respect to trust securities of TU Electric Capital IV, with a notional principal amount of $100 million that effectively fixed the rate at 7.183% per annum through 2002. 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 that effectively fixed the rate at 6.629% and 6.444%, respectively per annum through 2003. At December 31, 1998, TUC had an interest rate swap agreement with respect to Floating Rate Senior Notes, with a notional principal amount of $125 million expiring 2000 that effectively fixed the rate at 5.248% per annum.
At December 31, 1998, Eastern Energy had interest rate swaps and forward rate agreements outstanding, denominated in Australian dollars and/or US dollars, with an aggregate notional amount of $1,218 million. These agreements establish a mix of fixed and variable interest rates on outstanding debt and have remaining terms up to 18 years.
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At December 31, 1998, TXU Eastern had various interest rate swaps as required by the Sterling Credit Agreement. The Sterling Credit Agreement requires that one-half of the borrowings under these facilities be swapped from a floating to a fixed interest rate with a maturity of at least two years from July 28, 1998. The aggregate notional amount of the interest rate swaps entered into is 800 million pounds ($1,323 million) with an average maturity of six years and an average fixed rate of 6.58%. Eastern Group had interest rate swaps outstanding with an aggregate notional amount of $165 million that convert fixed interest rates to floating rates expiring in 2004 and forward rate agreements totaling $878 million for a maximum duration of one year to swap floating rate deposits into fixed rates.
At December 31, 1998, there were $86 million of net unrealized deferred hedging losses on interest rate swaps.
Foreign Currency Risk Management -- The Company has entered into short-term foreign currency exchange contracts in connection with the acquisition of TEG to hedge a portion of the Company's exposure to changes in the US dollar to pound sterling exchange rate. The Company has contracted to deliver 675 million pounds and will receive $1,093 million. The fair value of these contracts was a negative $28 million at December 31, 1998.
Eastern Group manages its exposure to foreign currency rates principally by matching foreign currency denominated assets with borrowings in the same currency. Currency swaps and options are also used where appropriate to hedge any residual exposures. In addition, certain imports of capital equipment and fuel are denominated in foreign currencies, and the pound sterling cost of these is fixed by means of forward contracts as soon as Eastern Group's contractual commitment is firm. The principal foreign currency hedges outstanding at December 31, 1998 were as follows:
US $/Pound sterling options at put rates of $1.57, and call rates of $1.60, each totaling $10 million and maturing in the year ending December 31, 1999. The fair value of these options is $1.5 million.
US $/Pound sterling swaps in respect of the semi-annual interest payments on the $500 million bonds to swap from US$ to pound sterling as follows:
Eastern Energy maintains cross currency swaps for its US dollar denominated debts. These cross currency swaps mature in December 2006 and December 2016 for $250 million and $100 million, respectively. The maturity of these swaps coincides with the maturity of the US dollar denominated debt.
Energy Price Risk Management -- UK/Europe -- Almost all electricity generated in England and Wales must be sold to the electricity trading market in England and Wales (the Pool), and electricity suppliers must likewise generally buy electricity from the Pool for resale to their customers. The Pool is operated under a Pooling and Settlement Agreement to which all licensed generators and suppliers of electricity in the UK are party. These trading arrangements are currently under review by the UK government. Eastern Group enters into derivative contracts to assist in the management of its exposure to fluctuations in electricity pool prices. The contracts bought and sold are contracts for differences (CfDs) and electricity forward agreements (EFAs) which fix the price of electricity for an agreed quantity and duration by reference to an agreed strike price. EFAs are similar in nature to CfDs, except that they tend to last for shorter time periods and are based on standard industry terms rather than being individually negotiated. Long-term CfDs are in place to hedge a portion of the electricity to be purchased by Eastern Group through 2009. From 1998, such CfDs represent an annual commitment of approximately five terawatt hours (TWh), declining on a linear
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basis to approximately two TWh by 2005 and finally expiring in 2010. There are no similar long-term commitments under EFAs. The impact of changes in the market value of these contracts, which serve as hedges, is deferred until the related transaction is completed. At December 31, 1998, there were net unrealized deferred hedging gains of $101 million on the CfDs and EFAs.
In its gas retail business, Eastern Group sells fixed price contracts to customers and supplies the customers through a portfolio of gas purchase contracts and other wholesale contracts. The overall exposure of Eastern Group to the gas spot market is also managed by EPETL using gas swaps and futures. At December 31, 1998, there was one such swap outstanding maturing March 31, 1999 with a negative fair value of $3.3 million.
Australia -- Eastern Energy and the other distribution companies in the state of Victoria, Australia purchase their power from a competitive power pool operated by a statutory, independent corporation. Eastern Energy purchases about 95% of its energy from this pool, the cost of which is based on spot market prices. Eastern Energy and other distribution companies were required to enter into wholesale market contracts to cover most of their forecasted franchise load through the end of 2000. Eastern Energy also maintains a strategy of seeking hedging contracts with individual generators to cover a portion of forecasted contestable loads. These contracts fix the price of energy within a certain range for the purpose of hedging or protecting against fluctuations in the spot market price. At December 31, 1998, Eastern Energy's contracts related to its forecasted contestable and franchise load cover a notional volume of approximately 8.3 million MWh for the period from January 1999 through 2001. Further hedge contracts may be required in that period to service forecasted sales. Under these contracts, payments are made between Eastern Energy and the generators representing the difference between the wholesale electricity market price and the contract price. The net payable or receivable is recognized in earnings as adjustments to purchased power expense in the period the related transactions are completed.
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.
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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.
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 are 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 $45.6 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 Company would incur as a result of nonperformance by counterparties to their respective derivative instruments. The Company maintains credit policies with regard to its counterparties that management believes significantly minimize overall credit risk. The Company 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 Company may apply certain remedies, if considered necessary. The Company believes the risk of nonperformance by counterparties is minimal.
11. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS
Most US employees are covered by defined benefit pension plans which provide benefits based on years of service and average earnings. At the date of their acquisition by the Company, both ENSERCH and LCC had defined benefit pension plans covering most of their employees and providing benefits similar to those provided to employees of other US subsidiaries.
Eastern Group participates in several defined benefit pension plans in the UK which cover the majority of its employees. The benefits under these plans are primarily based on years of credited service and final average compensation levels as defined under the respective plan provisions. In the
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UK, the majority of Eastern Group employees are members of the Electricity Supply Pension Scheme (ESPS) which provides pensions of a defined benefit nature for employees throughout the electricity supply industry. The ESPS operates on the basis that there is no cross-subsidy between employers, and the financing of Eastern's pension liabilities is, therefore, independent of the experience of other participating employers. The assets of the ESPS are held in a separate trustee-administered fund and consists principally of UK and European equities, UK property holdings and cash. The pension cost relating to the Eastern Group part of the ESPS is assessed in accordance with the advice of independent qualified actuaries using the projected unit method.
As a part of the purchase accounting for TEG, the accrued pension liabilities were adjusted to recognize all previously unrecognized gains or losses arising from past experience.
Eastern Group and Eastern Energy plans use economic assumptions similar to the other subsidiaries plans and are included in the tabular information below. The information in the tables below conforms to the requirements of SFAS 132, which became effective in 1998.
In 1998, the Company made contributions to the Thrift Plan and EN$AVE aggregating approximately $15 million.
The projected benefit obligations and fair value of plan assets for the pension plans with projected benefit obligations in excess of plan assets were $744 million and $718 million, respectively, as of December 31, 1998 and $705 million and $628 million, respectively, as of December 31, 1997.
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In addition to the retirement plans, the US subsidiaries offer certain health care and life insurance benefits to substantially all of their employees and their eligible dependents at retirement. Benefits received vary in level depending on years of service and retirement dates.
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The expected increase in costs of future benefits covered by the postretirement benefit plans 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 $93 million for the Company and $52 million for TU Electric, and other postretirement benefits cost for 1998 by approximately $11 million for the Company and $5.6 million for TU Electric.
12. INCOME TAXES
The components of the Company's and TU Electric's provisions for income taxes are as follows:
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Reconciliation of income taxes computed at the federal statutory rate to provision for income taxes.
The Company had net tax benefits from LESOP dividend deductions of $3.7 million, $3.9 million and $4.0 million in 1998, 1997 and 1996, respectively, which were credited directly to retained earnings.
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Deferred income taxes provided by the liability method for significant temporary differences based on tax laws in effect at the December 31, 1998 and 1997 balance sheet dates are as follows:
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At December 31, 1998, the Company had approximately $594 million of alternative minimum tax credit carryforwards available to offset future tax payments. At December 31, 1998, ENSERCH had $420 million of pre-merger net operating loss (NOL) carryforwards which begin to expire in 2003. Such NOL's can be used only to offset future taxable income generated by ENSERCH and its subsidiaries. A deferred tax asset valuation allowance of $10 million has been recorded for the ENSERCH NOL's at December 31, 1998. At December 31, 1998, TU Australia had $191 million and Eastern Group had $50 million of tax loss carryforwards that can be used to offset future taxable income in the respective jurisdictions. Such tax loss carryforwards do not have expiration dates. Eastern Group has recorded a valuation allowance of $228 million against the deferred tax assets related to leased assets.
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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13. REGULATION AND RATES
The rates charged by TU Electric for electric sales to consumers are generally set by the PUC. Rates for the cost of natural gas delivered to US residential and commercial customers are established by the Railroad Commission of Texas (RRC). The rates Lone Star Gas charges such customers are established by the cities and towns served. Rates charged by Eastern Group for electric sales to consumers are determined by the competitive market, subject to a tariff revenue cap, which is set by the OFFER in relation to customers with annual demands below 12,000 KWh. Rates charged for distribution of electricity are also regulated by OFFER. The rates charged by Eastern Group for gas sales to customers are determined by the competitive market.
Docket 9300 -- The PUC's final order (Order) in connection with TU Electric's January 1990 rate increase request (Docket 9300) was ultimately reviewed by the Supreme Court of Texas (Supreme Court). As a result, an aggregate of $909 million of disallowances with respect to TU Electric's reacquisitions of minority owners' interests in Comanche Peak, which had previously been recorded as a charge to the Company's and TU Electric's earnings, has been remanded to the District Court with instructions that it be remanded to the PUC for reconsideration on the basis of a prudent investment standard. On remand, the PUC also was required to reevaluate the appropriate level of TU Electric's construction work in progress included in rate base in light of its financial condition at the time of the initial hearing. In connection with the settlement of Docket 18490, proceedings in the remand of Docket 9300 have been stayed prior to January 1, 2000. The Company and TU Electric cannot predict the outcome of the reconsideration of the Order on remand by the PUC.
Dockets 15638 and 15840 -- In May 1996, TU Electric filed with the PUC its transmission cost information and tariffs for open-access wholesale transmission service (Docket 15638) in accordance with PUC rules. In August 1997, the PUC approved final tariffs for TU Electric and implemented rates for other transmission providers within ERCOT (Docket 15840). Under rates implemented by the PUC, TU Electric's payments for transmission service exceed its revenues for providing transmission service. The PUC has adopted a rate-moderation plan that will minimize the impact of the new pricing mechanism for the first three years the rules are in effect. The current maximum impact on TU Electric for 1999 is a $12 million deficit.
Docket 18490 -- The PUC approved the non-unanimous stipulation filed on December 17, 1997. The stipulation, modified to incorporate changes made by the PUC, resulted in base rate credits beginning January 1, 1998 of 4% for residential customers, 2% for general service secondary customers and 1% for all other retail customers and additional base rate credits for residential customers of 1.4% beginning January 1, 1999. Other provisions of the stipulation (i) impose an annual earnings cap on TU Electric's rate of return on rate base during 1998 and 1999, based in part on an 11.35% return on average common equity and a cap on operations and maintenance expense at a specified level, with any sums earned above the earnings cap being applied as additional nuclear production depreciation, (ii) allow TU Electric to record depreciation applicable to transmission and distribution assets in 1998 and 1999 as additional depreciation of nuclear production assets, (iii) establish an updated cost of service study that includes interruptible customers as customer classes, (iv) result in the permanent dismissal of pending appeals of prior PUC orders, if all other parties that have filed appeals of those dockets also dismiss their appeals, (v) result in the stay of any proceedings in the remand of Docket 9300 prior to January 1, 2000, and (vi) flow all gains from off-system sales of electricity in excess of the amount included in base rates to customers through the fuel factor. Modifications that were also approved by the PUC include: (i) imputing $16 million of revenues from discounted rates in the calculation of the return cap, (ii) limiting the recovery of interest on any new debt issued prior to December 31, 1999 to the interest rate available to TU Electric at its bond rating as of January 1, 1998 in the calculation of the return cap, (iii) limiting the amount of annual capital additions to production plant to 1.5% of TU Electric's net plant in service on December 31, 1996 in the calculation of the return cap, and (iv) permitting TU Electric, at its discretion, to apply earnings as additional depreciation of nuclear production assets, after the determinations have been made under the return cap. Certain parties that did not sign the stipulation have appealed the PUC's approval by filing suit in state district court. The Company and TU Electric cannot predict the outcome of these appeals.
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For the year ended December 31, 1998, TU Electric recorded $170 million as additional depreciation of nuclear production assets, representing 1998 earnings in excess of the stipulated return cap. In addition, for the year there was $183 million of depreciation expense reclassified from transmission and distribution to nuclear production assets. Including deferred income tax effects, the net effect was a $143 million reduction in net income for the year ended December 31, 1998. TU Electric will file with the PUC its first report, concerning the earnings cap calculation for 1998, by March 31, 1999. Interested parties are allowed to challenge the calculation and the reasonableness of the underlying costs. The Company and TU Electric are unable to predict whether any such challenge will be filed or the outcome of any such challenge.
Fuel Cost Recovery Rule -- Pursuant to a PUC rule, the recovery of TU Electric's eligible fuel costs is provided through fixed fuel factors. The rule allows a utility's fuel factor to be revised upward or downward every six months, according to a specified schedule. A utility is required to petition to make either surcharges or refunds to ratepayers, together with interest based on a twelve-month average of prime commercial rates, for any material cumulative under- or over-recovery of fuel costs. If the cumulative difference of the under- or over-recovery, plus interest, exceeds 4% of the annual estimated fuel costs most recently approved by the PUC, it will be deemed to be material.
Final reconciliation of fuel costs must be made either in a reconciliation proceeding, which may cover no more than three years and no less than one year, or in a general rate case. In a final reconciliation, a utility has the burden of proving that fuel costs under review were reasonable and necessary to provide reliable electric service, that it has properly accounted for its fuel-related revenues, and that fuel prices charged to the utility by an affiliate were reasonable and necessary and not higher than prices charged for similar items by such affiliate to other affiliates or nonaffiliates. In addition, for generating utilities like TU Electric, the rule provides for recovery of purchased power capacity costs through a power cost recovery factor (PCRF) with respect to purchases from qualifying facilities, to the extent such costs are not otherwise included in base rates. The energy-related costs of such purchases are included in the fixed fuel factor. For non-generating utilities, the rule provides for the recovery of all costs of power purchased at wholesale chargeable under rate schedules approved by a federal or state regulatory authority and all amounts paid to qualifying facilities for the purchase of capacity and/or energy, to the extent such costs are not otherwise included in base rates. Penalties of up to 10% will be imposed in the event an emergency increase has been granted when there was no emergency or when collections under the PCRF exceed PCRF costs by 10% in any month or 5% in the most recent twelve months.
Fuel Reconciliation Proceeding -- On December 30, 1998, in accordance with PUC rules, TU Electric filed a petition with the PUC seeking final reconciliation of all eligible fuel and purchased power expenses incurred during the reconciliation period of July 1, 1995 through June 30, 1998, amounting to a total of $5.04 billion. The Company and TU Electric are unable to predict the outcome of such proceeding.
In addition, and as permitted by the PUC rules, TU Electric is also seeking an accounting order from the PUC that will allow certain costs incurred to facilitate the use of coal as a supplemental fuel at its Monticello plant to be treated as eligible fuel costs and billed pursuant to TU Electric's fuel cost factor. By incurring these expenses, the Company and TU Electric believe it has significantly improved the reliability of the supply of fuel to Monticello and has, at the same time, lowered the fuel expense that would be incurred in the absence of these investments.
Flexible Rate Initiatives -- TU Electric continues to offer flexible rates in over 160 cities with original regulatory jurisdiction within its service territory (including the cities of Dallas and Fort Worth) to non-residential retail and wholesale customers that have viable alternative sources of supply and would otherwise leave the system. TU Electric also continues to offer in those cities an economic development rider to attract
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new businesses and to encourage customers to expand their facilities as well as an environmental technology rider to encourage qualifying customers to convert to technologies that conserve energy or improve the environment. TU Electric will continue to pursue the expanded use of flexible rates when such rates are necessary to be price-competitive.
TU Electric also offers optional time-of-use rates to residential, commercial, and industrial customers under rates approved on an interim basis by the PUC in October 1997, in areas where the PUC retains sole regulatory jurisdiction. These time-of-use rate options allow participating customers to plan and manage their electrical energy usage to shift their loads from the TU Electric on-peak periods to off-peak periods. This reduces TU Electric's requirements for capacity resources to meet the peak electrical load of all of its customers. A ruling from the PUC approving these rates is expected by the second quarter of 1999. On January 15, 1999, the Company applied for approval of these rates with municipal regulatory authorities in 173 cities, in the form that it expects the PUC ultimately to approve. The Company and TU Electric estimate that any decrease in revenue resulting from the implementation of these rates will be offset by the reduced costs associated with the peak load reductions achieved.
Open Access Transmission -- In February 1996, the PUC adopted rules requiring each electric utility in ERCOT to provide wholesale transmission and related services to other utilities and non-utility power suppliers at rates, terms and conditions that are comparable to those applicable to such utility's use of its own transmission facilities. Under the rules, the PUC established a transmission pricing mechanism that is designed to ensure that all market participants pay on a comparable basis to use the system.
In February 1999, the PUC approved modifications to its rules addressing open-access wholesale transmission service to allow utilities to annually revise their transmission rates to reflect rate base additions and updated billing units. In addition, the rules now clarify the cost responsibility for entities connecting new resources to the ERCOT transmission grid. These revisions to the rules were enacted primarily to enhance wholesale competition and provide for the timely recovery by utilities of their transmission investment. It is anticipated that the adoption of these rules will have a minimal impact on open-access transmission rates.
The Company
Lone Star Gas and Lone Star Pipeline Rates -- In August 1996, the RRC ordered a general inquiry into the rates and services of Lone Star Gas. The inquiry docket was separated into different phases, all of which are now resolved. 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. 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.
UK -- A formula determines the maximum average price per unit of electricity distributed (in pence per kilowatt hour) which a regional electrical company (REC) is entitled to charge. The formula permits RECs to retain part of their additional revenue due to increased distribution of units and allows for a pound for pound increase in operating profit for efficient operations and reduction of expenses within a review period. In relation to the next Distribution Price Control Formula review scheduled to be implemented in April 2000, the Director General of Electricity Supply in Great Britain (DGES) may reduce any such increase in operating profit to the extent it determines it not to be a function of efficiency savings and/or, if genuine efficiency savings have been made, it determines that customers should benefit through lower prices in the future.
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Australia -- Eastern Energy is subject to regulation by the Office of the Regulator General (ORG). The ORG has the power to issue licenses for the supply, distribution and sale of electricity within Victoria and regulates tariffs for the use of the transmission system, distribution system, and other ancillary services. The existing tariff under which Eastern Energy operates is in effect through December 31, 2000. The ORG will review the existing tariff to determine if it will be effective for the period commencing January 1, 2001. Rates charged to non-franchise customers by the Company and the other distribution companies are subject to competitive forces and are not directly regulated by the ORG, although certain network tariff components of such rates are subject to regulation.
14. COMMITMENTS AND CONTINGENCIES
Capital Expenditures -- The capital expenditures of the Company were $1,173 million in 1998 and are estimated at $1,300 million for 1999. Approximately 50% will be spent on US electric and gas operations, approximately 35% on operations in the UK and continental Europe, and approximately 15% on operations in Australia, communications and other activities.
TU Electric
Clean Air Act -- The Federal Clean Air Act, as amended (Clean Air Act) includes provisions which, among other things, place limits on the sulfur dioxide emissions produced by generating units. Although TU Electric's capital requirements have not been significantly affected by the requirements of the Clean Air Act, any additional capital expenditures, as well as any increased operating costs, associated with the requirements are expected to be recoverable through rates, as similar costs have been recovered in the past.
The Company and TU Electric
Purchased Power Contracts --The US electric companies have entered into purchased power contracts to purchase power from utilities and non-utilities through the year 2005. These contracts provide for capacity payments subject to performance standards and energy payments based on the actual power taken under contract. The payments made under these contracts are expected to be recovered through a combination of base rates, power cost and fuel recovery factors applied to customer billings. Capacity payments under these contracts for the years ended December 31, 1998, 1997 and 1996 were $247 million, $240 million and $233 million, respectively, for the Company, and $243 million, $237 million and $228 million, respectively, for TU Electric.
Assuming operating standards are achieved, future capacity payments under the agreements are estimated as follows:
The Company
Gas Purchase Contracts -- Texas Utilities Fuel Company (Fuel Company) and Lone Star Gas buy gas under long-term and short-term intrastate contracts in order to assure reliable supply to their customers. Many of these contracts require minimum purchases ("take-or-pay") 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
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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.
Eastern Group has various types of contracts for the purchase of gas. Almost all include take-or-pay obligations. In order to help meet the expected needs of its wholesale and retail customers, Eastern Group has entered into a range of gas purchase contracts.
Based on estimated gas demand, which assumes normal weather conditions, requisite gas purchases of Fuel Company, Lone Star Gas and Eastern Group are expected to substantially satisfy their purchase obligations for the year 1999 and thereafter.
Leases -- Subsidiaries have entered into operating leases covering various facilities and properties including generating plants, combustion turbines, transportation, mining equipment, data processing equipment and office space. Certain of these leases contain renewal and purchase options and residual value guarantees. Lease costs charged to operating expense for the years ended December 31, 1998, 1997 and 1996 were $243 million, $157 million and $145 million, respectively, for the Company, and $68 million, $66 million and $56 million, respectively, for TU Electric.
At December 31, 1998, future minimum lease payments for assets under capital lease, together with the present value of such minimum lease payments, and future minimum lease commitments under operating leases that have initial or remaining noncancellable lease terms in excess of one year as of December 31, 1998, were as follows:
Financial Guarantees -- TU Electric has entered into contracts with public agencies to purchase cooling water for use in the generation of electric energy and has agreed, in effect, to guarantee the principal, $27 million at December 31, 1998, and interest on bonds issued to finance the reservoirs from which the water is supplied. The bonds mature at various dates through 2011 and have interest rates ranging from 5-1/2% to 7%. TU Electric is required to make periodic payments equal to such principal and interest, including amounts assumed by a third party and reimbursed to TU Electric, of $4 million annually for the years 1999 through 2003. Annual payments made by TU Electric, net of amounts assumed by a third party under such contracts, for 1998, 1997 and 1996 were $4 million. In addition, TU Electric is obligated to pay certain variable costs of operating and maintaining the reservoirs. TU Electric has assigned to a municipality all contract rights and obligations of TU Electric in connection with $64 million remaining principal amount of bonds at December 31, 1998, issued for similar purposes which had previously been guaranteed by TU Electric. TU Electric is, however, contingently liable in the unlikely event of default by the municipality. In addition, the Company and/or its subsidiaries are the guarantor on various commitments and obligations of others aggregating some $30 million at December 31, 1998.
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The Company
The Company has guaranteed up to $110 million of certain liabilities which may be incurred and payable by the purchasers of its Peabody Coal and Citizens Power businesses with respect to the various retirement plans of the sold businesses, subject to certain specified conditions.
Eastern Group is the guarantor or the indemnifying party, as the case may be, under power purchase agreements and note purchase agreements in connection with certain former subsidiary's energy restructuring projects as well as various indemnity agreements in connection with such projects. In connection with the acquisition, letters of credit were issued under the Sterling Credit Facility in the amount of approximately £118 million ($195 million) to support certain debt financing associated with these restructuring projects.
Chaco Coal Properties --In the third quarter of 1998, the Company settled its advance royalty obligations for Chaco Energy Company coal reserves with a cash payment of approximately $136 million and a transfer of rights to the coal reserves and related land, recognizing a pretax gain of $16 million ($11 million after-tax).
TU Electric
Nuclear Insurance -- With regard to liability coverage, the Price-Anderson Act (Act) provides financial protection for the public in the event of a significant nuclear power plant incident. The Act sets the statutory limit of public liability for a single nuclear incident currently at $9.7 billion and requires nuclear power plant operators to provide financial protection for this amount. As required, TU Electric provides this financial protection for a nuclear incident at Comanche Peak resulting in public bodily injury and property damage through a combination of private insurance and industry-wide retrospective payment plans. As the first layer of financial protection, TU Electric has purchased $200 million of liability insurance from American Nuclear Insurers (ANI), which provides such insurance on behalf of a major stock insurance company pool, Nuclear Energy Liability Insurance Association. The second layer of financial protection is provided under an industry-wide retrospective payment program called Secondary Financial Protection (SFP).
Under the SFP, each operating licensed reactor in the United States is subject to an assessment of up to $88 million, subject to increases for inflation every five years, in the event of a nuclear incident at any nuclear plant in the United States. Assessments are limited to $10 million per operating licensed reactor per year per incident. All assessments under the SFP are subject to a 3% insurance premium tax which is not included in the amounts above.
With respect to nuclear decontamination and property damage insurance, Nuclear Regulatory Commission (NRC) regulations require that nuclear plant license-holders maintain not less than $1.1 billion of such insurance and require the proceeds thereof to be used to place a plant in a safe and stable condition, to decontaminate it pursuant to a plan submitted to and approved by the NRC before the proceeds can be used for plant repair or restoration or to provide for premature decommissioning. TU Electric maintains nuclear decontamination and property damage insurance for Comanche Peak in the amount of $4.3 billion, above which TU Electric is self-insured. The primary layer of coverage of $500 million is provided by Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry mutual insurance company. The remaining coverage includes premature decommissioning coverage and is provided by ANI and Mutual Atomic Energy Liability Underwriters (MAELU) in the amount of $1.3 billion and additional insurance from NEIL in the amount of $2.5 billion. TU Electric is subject to a maximum annual assessment from NEIL of $17 million in the event NEIL's losses under this type of insurance for major incidents at nuclear plants participating in these programs exceed the mutual's accumulated funds and reinsurance.
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TU Electric maintains Extra Expense Insurance through NEIL to cover the additional costs of obtaining replacement power from another source if one or both of the units at Comanche Peak are out of service for more than seventeen weeks as a result of covered direct physical damage. The coverage provides for weekly payments of $3.5 million for the first fifty-eight weeks and $2.8 million for the next 104 weeks for each outage, respectively, after the initial seventeen week period. The total maximum coverage is $494 million per unit. The coverage amounts applicable to each unit will be reduced to 80% if both units are out of service at the same time as a result of the same accident. Under this coverage, TU Electric is subject to a maximum annual assessment of $6 million per year.
Nuclear Decommissioning and Disposal of Spent Fuel -- TU Electric has established a reserve, charged to depreciation expense and included in accumulated depreciation, for the decommissioning of Comanche Peak, whereby decommissioning costs are being recovered from customers over the life of the plant and deposited in external trust funds (included in other investments). At December 31, 1998, such reserve totaled $146 million which includes an accrual of $18 million for the year ended December 31, 1998. As of December 31, 1998, the market value of deposits in the external trust for decommissioning of Comanche Peak was $211 million. Any difference between the market value of the external trust fund and the decommissioning reserve, that represents unrealized gains or losses of the trust fund, is treated as a regulatory asset or a regulatory liability. Realized earnings on funds deposited in the external trust are recognized in the reserve. Based on a site-specific study completed during 1997 using the prompt dismantlement method and 1997 dollars, decommissioning costs for Comanche Peak Unit 1 and for Unit 2 and common facilities were estimated to be $271 million and $404 million, respectively.
Decommissioning activities are projected to begin in 2030 for Comanche Peak Unit 1 and 2033 for Unit 2 and common facilities. TU Electric is recovering decommissioning costs based upon a 1992 site-specific study through rates placed in effect under its January 1993 rate increase request. Actual decommissioning costs are expected to differ from estimates due to changes in the assumed dates of decommissioning activities, regulatory requirements, technology and costs of labor, materials and equipment. In addition, the marketable fixed income debt and equity securities in which assets of the external trust are invested are subject to interest rate and equity price sensitivity.
TU Electric has a contract with the United States Department of Energy (DOE) for the future disposal of spent nuclear fuel. In December 1996, the DOE notified TU Electric that it did not expect to meet its obligation to begin acceptance of spent nuclear fuel by 1998. TU Electric is unable to predict what impact, if any, the DOE delay will have on TU Electric's future operations. The disposal fee is at a cost to TU Electric of one mill per kilowatt-hour of Comanche Peak net generation and is included in nuclear fuel expense.
The Company
Legal Proceedings -- In February 1997, the official government representative of pensioners in the UK (Pensions Ombudsman) made final determinations against The National Grid Company plc (National Grid) and its group trustees with respect to complaints by two pensioners in National Grid's section of the ESPS relating to the use of the pension fund surplus resulting from the March 31, 1992 actuarial valuation of the National Grid section to meet certain costs arising from the payment of pensions on early retirement upon reorganization or downsizing. These determinations were set aside by the High Court on June 10, 1997, and the arrangements made by National Grid and its group trustees in dealing with the surplus were confirmed. The two pensioners have now appealed against this decision, and judgment has now been received although a final order is awaited. The appeal endorsed the Pension Ombudsman's determination that the corporation was not entitled to unilaterally deal with any surplus. If a similar action were to be made against Eastern Group in relation to its use of actuarial surplus in its section of the ESPS, it would vigorously defend the action, ultimately through the courts. However, if a determination were finally to be made against it
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and upheld in the courts, Eastern Group could have a potential liability to repay to its section of the ESPS an amount estimated by the Company to be up to $165 million (exclusive of any applicable interest charges).
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), the Company, 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 the Company pursuant to the merger agreement between ENSERCH and the Company 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 the Company 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.
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. The Company 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 of 1933 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 Company 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.
General -- In addition to the above, the Company and other subsidiaries, including TU Electric, are involved in various other legal and administrative proceedings which, in the opinion of each, should not have a material effect upon their financial position, results of operation or cash flows.
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15. SUPPLEMENTARY FINANCIAL INFORMATION
Sale of Receivables and Other Receivable Financing -- TU Electric 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 receivable representing up to an aggregate of $450 million. ENSERCH has a similar facility for $100 million. Additional receivables are continually sold to replace those collected. At December 31, 1998 and 1997, accounts receivable of TU Electric was reduced by $450 million and $300 million, respectively, and accounts receivable of ENSERCH companies were reduced by $100 million to reflect the sales of such receivables to financial institutions under such agreements. Eastern Group has facilities with financial institutions whereby it may borrow funds using trade accounts receivable as collateral. At December 31, 1998, Eastern Group had borrowed $496 million under these facilities.
Restricted Cash -- At December 31, 1998, $675 million of the deposits classified with investments has been used to cash-collateralize existing future obligations of Eastern Group to certain banks in respect of the funding of the leases of three power stations, and $511 million is matched to lease obligations arising from a leasing arrangement on two other power stations.
Contracts -- A provision for unfavorable long-term gas and electricity contracts of Eastern Group was established at acquisition for contracts that expire in 2009 and 2011 and is reflected in other liabilities.
Quarterly Information (unaudited) -- In the opinion of the Company and TU Electric, respectively, the information below includes all adjustments (constituting only normal recurring accruals) necessary to a fair statement of such amounts. Quarterly results are not necessarily indicative of expectations for a full year's operations because of seasonal and other factors, including rate changes, variations in maintenance and other operating expense patterns, and the charges for regulatory disallowances. Certain quarterly information has been reclassified to conform to the current year presentation.
TU Electric
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16. PREFERRED STOCK OF TU ELECTRIC AND OTHER SUBSIDIARIES OF THE COMPANY
The carrying value of preferred stock subject to mandatory redemption is being increased periodically to equal the redemption amounts at the mandatory redemption dates with a corresponding increase in preferred stock dividends.
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17. SEGMENT INFORMATION
The Company'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 Company has five reportable operating segments:
(1) US Electric - operations engaged in the generation, purchase, transmission, distribution and sale of electric energy primarily in the north central, eastern and western portions of Texas (primarily TU Electric, Southwestern Electric Service Company, Fuel Company and Mining Company operations);
(2) US Gas - 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 Enserch Processing, Inc.);
(3) 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);
(4) UK/Europe - operations engaged in the generation, purchase, distribution and sale of electricity and the purchase and sale of natural gas primarily in the UK, with additional energy interests throughout the rest of Europe (primarily Eastern Group);
(5) Australia - operations engaged in the purchase, distribution and sale of electricity and natural gas and the provision of other energy-related services primarily in the State of Victoria, Australia (primarily Eastern Energy); and
(6) Other - non-segment operations consist of telecommunications, retail energy services, international gas operations, power development and other energy development activities.
The accounting policies of the segments are the same as those described in the summary of significant accounting policies. The Company evaluates performance based on net income or loss. The Company 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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