UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1998
-- OR--
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Transition Period From___________ to ___________
Exact Name of Registrant as Specified in
Commission its Charter; Address of Principal Executive I.R.S. Employer
File Number Offices; and Telephone Number Identification No.
1-12833 Texas Utilities Company 75-2669310
Energy Plaza, 1601 Bryan Street
Dallas, TX 75201-3411
(214) 812-4600
1-11668 Texas Utilities Electric Company 75-1837355
Energy Plaza, 1601 Bryan Street
Dallas, TX 75201-3411
(214) 812-4600
Securities registered pursuant to Section 12(b) of the Act:
Name of Each
Exchange on
Registrant Title of Each Class Which Registered
Texas Utilities Common Stock, without par
Company value New York Stock Exchange
The Chicago Stock Exchange
The Pacific Exchange
Growth Prides New York Stock Exchange
Income Prides New York Stock Exchange
TXU Capital I, a 7.25% Preferred Trust New York Stock Exchange
subsidiary of Securities
Texas Utilities
Company
Texas Utilities Depositary Shares, Series A, New York Stock Exchange
Electric Company each representing 1/4 of a
share of $7.50 Cumulative
Preferred Stock, without par
value
Texas Utilities Depositary Shares, Series B, New York Stock Exchange
Electric Company each representing 1/4 of a
share of $7.22 Cumulative
Preferred Stock, without par
value
TU Electric 8.25% Trust Originated New York Stock Exchange
Capital I, a Preferred Securities
subsidiary
of Texas Utilities
Electric Company
TU Electric 8.00% Quarterly Income New York Stock Exchange
Capital III, a Preferred Securities
subsidiary of
Texas Utilities
Electric Company
Securities registered pursuant to Section 12(g) of the Act: Preferred Stock
of Texas Utilities Electric Company, without par value
Indicate by check mark whether the registrants (1) have filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or for such shorter period that the
registrants were required to file such reports), and (2) have been subject
to such filing requirements for the past 90 days. Yes __X__ No ____
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
Aggregate market value of Texas Utilities Company Common Stock held by
non-affiliates, based on the last reported sale price on the composite tape on
March 19, 1999: $12,623,598,116.
Aggregate market value of Texas Utilities Electric Company Common Stock held
by non-affiliates: None
Common Stock outstanding at March 19, 1999:
Texas Utilities Company - 282,332,819 shares, without par value
Texas Utilities Electric Company - 118,714,200 shares, without par value
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement pursuant to Regulation 14A, which
will be filed with the Commission on or about April 5, 1999, are incorporated
by reference into Part III of this report.
This combined Form 10-K is filed separately by Texas Utilities Company and
Texas Utilities Electric Company. Information contained herein relating to an
individual registrant is filed by that registrant on its own behalf except
that the information with respect to Texas Utilities Electric Company, other
than the financial statements of Texas Utilities Electric Company, is filed by
each of Texas Utilities Company and Texas Utilities Electric Company. Each
registrant makes no representation as to information filed by the other
registrant.
TABLE OF CONTENTS
Page
____
PART I
Item 1. BUSINESS 1
LEGAL ENTITIES
Texas Utilities Company and Subsidiaries 1
Texas Utilities Electric Company and Subsidiaries 4
ENSERCH Corporation and Subsidiaries 4
TU International Holdings Limited and Subsidiaries 5
Texas Energy Industries, Inc. and Subsidiaries 6
COMPETITIVE STRATEGY 7
OPERATING SEGMENTS 7
US Electric 8
US Gas 20
US Energy Marketing 23
UK/Europe 24
Australia 31
Other Businesses 33
ENVIRONMENTAL MATTERS 34
Item 2. PROPERTIES 37
CAPITAL EXPENDITURES 39
Item 3. LEGAL PROCEEDINGS 40
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS 41
EXECUTIVE OFFICERS OF THE COMPANY 42
PART II
Item 5. MARKET FOR EACH REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS 43
Item 6. SELECTED FINANCIAL DATA 43
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS 44
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET
RISK 44
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA 44
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE 44
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF EACH REGISTRANT 45
Item 11. EXECUTIVE COMPENSATION 48
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND
MANAGEMENT 58
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS 59
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON
FORM 8-K 60
APPENDIX A - Financial Information of Texas Utilities Company and
Subsidiaries and Texas Utilities Electric Company
and Subsidiaries
i
PART I
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.
1
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.
Year Ended December 31,
--------------------------------------------------
1998 1997
----------------------- ------------------------
As Reported Pro forma As Reported Pro forma
----------- --------- ----------- ---------
Revenues $14,736 $17,319 $7,946 $14,794
Operating income 2,463 2,781 1,906 2,719
Net income 740 884 660 842
Average shares outstanding (millions) 265 282 231 286
Earnings per share of common stock
Basic $2.79 $3.13 $2.86 $2.95
Diluted $2.79 $3.13 $2.85 $2.94
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.
2
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:
Income
Statement
Balance Sheet (average for periods
(at December 31,) ended December 31,)
----------------- --------------------------
1998 1997 1998 1997 1996
------- ------- ------- ------- -------
UK pounds sterling $1.6554 - $1.6616 - -
Australian dollars $0.6123 $0.6503 $0.6313 $0.7443 $0.7738
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.
3
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.
4
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
5
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.
6
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.
7
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).
US Electric Consolidated Operating Statistics
Years Ended December 31
1998 1997 1996
------- ------- -------
ELECTRIC ENERGY GENERATED AND PURCHASED
(Gigawatt-hours - GWh)
Generated - net station output 97,574 91,298 88,130
Purchased and net interchange 12,205 11,980 13,029
------- ------- -------
Net generated and purchased 109,779 103,278 101,159
Company use, losses, and unaccounted for 6,637 6,255 5,905
------- ------- -------
Total electric energy sales 103,142 97,023 95,254
======= ======= =======
ELECTRIC ENERGY SALES (GWh)
Residential 37,299 33,967 33,469
Commercial 29,617 27,602 26,731
Industrial 25,313 24,785 24,375
Government and municipal 6,652 6,170 6,053
------- ------- -------
Total general business 98,881 92,524 90,628
Other electric utilities 4,261 4,499 4,626
------- ------- -------
Total electric energy sales 103,142 97,023 95,254
======= ======= =======
OPERATING REVENUES (millions of dollars)
Base rate revenues
Residential $2,192 $2,025 $2,028
Commercial 1,327 1,256 1,248
Industrial 593 593 600
Government and municipal 324 301 299
------- ------- -------
Total general business 4,436 4,175 4,175
Other electric utilities 125 139 146
------- ------- -------
Total base rate revenues 4,561 4,314 4,321
Fuel revenue (including over/under-recovered) 1,788 1,697 1,671
Transmission service revenues 126 114 --
Other operating revenues 66 51 85
------- ------- -------
Total operating revenues $6,541 $6,176 $6,077
======= ======= =======
ELECTRIC CUSTOMERS (end of year - in thousands) 2,544 2,490 2,432
Degree days (average for service area)
Percent of normal:
Cooling 130.3% 94.2 % 115.1%
Heating 89.2% 106.0 % 94.0%
8
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. Properties).
The Company and TU Electric
Electricity Peak Load and Generation Capability - The electricity peak
load and net generation capability for TU Electric is contained in the table
below. For SESCO, peak load was 258 MW on August 3, 1998. SESCO generates no
electric energy.
TU Electric
TU Electric's net capability, peak load and reserve, in MW, at the time
of peak were as follows during the years indicated:
Electricity
Peak Load(a)
Increase Firm
Net Over Peak
Year Capability Amount Prior Year Load Reserve(b)
- ---- ---------- ------ ---------- ------ ----------
1998 22,579 (c) 21,383 5.1% 20,351 2,228
1997 22,449 (d) 20,351 3.5% 19,229 3,220
1996 22,389 (e) 19,668 2.5% 18,930 3,459
<FN>
(a) The 1998 peak load occurred on August 3. TU Electric's peak load includes
interruptible load at the time of peak of 1,032 MW in 1998, 1,122 MW in 1997
and 738 MW in 1996.
(b) Amount of net capability in excess of firm peak load at the time of peak.
(c) Included in net capability is 1,499 MW of firm purchased capacity, of
which 1,164 MW is cogeneration and small power production, and 335 MW is
short-term firm summer capacity purchased in 1998 from three different
suppliers.
(d) Included in net capability is 1,224 MW of firm purchased capacity, of
which 1,164 MW is cogeneration and small power production, and 60 MW is
short-term firm summer capacity purchased in 1997 from a power marketer.
(e) Included in net capability is 1,164 MW of firm purchased capacity, all of
which is cogeneration and small power production.
</FN>
The peak load changes for 1998 as compared to 1997 resulted primarily
from customer growth and increased usage due to hotter-than-normal weather.
The peak load changes for 1997 and 1996, compared in each case to the prior
year, resulted primarily from customer growth and weather factors. TU
Electric expects to continue to purchase capacity in the future from various
sources. (See Fuel Supply and Purchased Power and Note 14 to Consolidated
Financial Statements included in Appendix A to this report.) Firm peak load
(including interruptible contracts) increases over the next five years are
expected to average approximately 2.2% annually, after consideration of load
management programs.
Resource Estimates - Changes in utility regulation and legislation at the
federal and state levels such as the Public Utility Regulatory Policy Act of
1978 (PURPA), the National Energy Policy Act of 1992 (Energy Policy Act) and
the 1995 amendments to the Public Utility Regulatory Act (PURA) in Texas have
significantly changed the way utilities plan for new resources. TU Electric
believes that competitive market forces will be a major factor in determining
future resource additions to serve customer loads. Thus, for planning
purposes, TU Electric can no longer readily identify the ownership and types
of resources to include in its integrated resource plan (IRP) before the
actual selection of those resources. TU Electric has reflected this
uncertainty through use of the term "Unspecified Resources." Except for known
contracts, all potential new resource needs are designated as "Unspecified
Resources."
9
A portion of TU Electric's near-term resource needs have been alleviated
with the extension of an existing purchased power contract through the year
2002. In addition, TU Electric has secured additional resources for the years
1999, 2000 and 2001 from various suppliers through short-term (two years or
less) purchased power contracts. (See Fuel Supply and Purchased Power.) Thus,
the immediate need to issue a solicitation for additional resources has been
deferred. TU Electric is continuing to review the need and timing for
purchasing additional resources.
TU Electric requested and received approval from the Public Utility
Commission of Texas (PUC) to expand its Power Cost Recovery tariff to provide
current recovery of acquisition costs for demand-side management resources
acquired in PUC-approved solicitations and for eight previously approved
demand-side management contracts entered into by TU Electric to the extent
such costs are not currently reflected in TU Electric's base rates.
The resource additions identified in TU Electric's 1999 IRP for the next
five years are as follows:
1999-2003
--------------------------
Firm
Capability
Resource Additions (MW) Percent
----------- --------
Load management (a) 81 2.4%
Renewable resources (b) 4 0.1
Long-term purchase (c) 25 0.8
Unspecified resources 3,261 96.7
------ -----
Total 3,371 100.0%
====== =====
<FN>
(a) TU Electric has negotiated and signed contracts with eight suppliers of
demand-side management services designed to displace a total of 72 MW by 2004.
(b) TU Electric has negotiated and signed one purchased power contract for
approximately 35 MW (4 MW firm) of wind-powered resources to be placed in
service during 1999.
(c) TU Electric has negotiated and signed a three-year extension to an existing
purchased power contract for an increase in contract capacity from 410 MW to
435 MW.
</FN>
The exact timing of when retail competition will occur in Texas is
unknown at this time. Some states in the US, for example, California and
Pennsylvania, already have retail competition. Many others, including Texas,
are considering it. The issue of retail competition is being discussed
extensively during the current session of the Texas legislature and some form
of legislation may be enacted. Because of this uncertainty and the potential
impact of retail competition on TU Electric's ability to retain customers
presently served, any forecasts of future resource needs beyond the near-term
(i.e., five years or less) would be speculative. Consequently, TU Electric is
providing only resource information for the next five years (1999-2003).
10
Fuel Supply And Purchased Power -- Net input for the US Electric segment
during 1998 totaled 109,779 GWh of which 97,574 GWh were generated by TU
Electric. Average fuel and purchased power cost (excluding capacity charges)
per kilowatt-hour (kWh) of net input for the US Electric segment (and TU
Electric) were 1.78 (1.77) cents for 1998, 1.85 (1.84) cents for 1997 and
1.79 (1.79) cents for 1996, respectively. A comparison of TU Electric's
resource mix for net kWh input and the unit cost per million British thermal
units (Btu) of fuel during the last three years is as follows:
Mix for Net Unit Cost
kWh Input kWh Input
----------------------- -------------------------
1998 1997 1996 1998 1997 1996
----- ----- ----- ----- ----- -----
Fuel for Electric Generation:
Gas/Oil (a) 36.7% 32.9% 33.0% $2.39 $2.80 $2.66
Lignite/Coal (b) 36.5 38.9 39.6 1.03 1.04 1.03
Nuclear 16.4 17.1 15.0 0.59 0.57 0.56
----- ----- -----
Total/Weighted Average Fuel Cost 89.6 88.9 87.6 $1.52 $1.62 $1.58
Purchased Power (c) 10.4 11.1 12.4
----- ----- -----
Total 100.0% 100.0% 100.0%
===== ===== =====
<FN>
(a) Fuel oil was an insignificant component of total fuel and purchased power
requirements.
(b) Lignite/coal cost per ton to TU Electric was $13.20 in 1998, $13.24 in 1997
and $13.22 in 1996.
(c) Excludes SESCO's power purchased from TU Electric: 1998 - 934 GWh; 1997 -
543 GWh; and 1996 - 616 GWh .
</FN>
In 1998, the US Electric segment purchased a net of 12,205 GWh or
approximately 11.1% of its energy requirements. TU Electric and SESCO had
available 1,757 MW of firm purchased capacity under contract, including 335 MW
of short-term capacity to meet the 1998 summer peak and a full requirements
contract to meet the needs of SESCO. TU Electric began receiving energy in
December 1998 under a purchased power contract for energy from wind turbines
equivalent to approximately 35 MW (4 MW of firm capacity at peak). Completion
of the facility is anticipated in 1999. This facility will include four of
the largest commercial wind turbines in the world, rated at 1.65 MW each. TU
Electric has executed or extended contracts with various suppliers to provide
an additional 970 MW, 1,660 MW and 2,160 MW to help meet the summer peaks of
1999, 2000 and 2001, respectively. TU Electric expects to acquire additional
amounts of purchased resources in the future to adequately and reliably
accommodate its customers' electrical needs. Such resources will be acquired
in accordance with the requirements of PURA and the PUC Substantive Rules.
For information concerning future resource requirements, see Electricity Peak
Load and Generation Capability.
TU Electric has signed a two-year contract to buy 500 MW in 2000 and
1,000 MW in 2001 from the 1,100 MW merchant plant being built by American
National Power, Inc. (ANP) in Midlothian, Texas (26 miles south of Dallas).
This is TU Electric's largest purchase contract so far from a merchant plant
and one of several contracts signed recently to meet projected demand. Also
for the first time, the transmission business is building facilities to
connect a merchant plant to TU Electric's power grid. Lone Star Pipeline's
transportation services are also participating in a contract with ANP to
deliver up to half of the plant's 180 million cubic feet (MMcf) natural gas
maximum daily requirement through its pipeline.
TU Electric and SESCO are unable to predict: (i) whether or not problems
may be encountered in the future in obtaining the fuel and purchased power
each will require, (ii) the effect upon operations of any difficulty either
of them may experience in protecting rights to fuel and purchased power now
under contract, or (iii) the cost of fuel and purchased power. The reasonable
costs of fuel and purchased power of TU Electric and SESCO are generally
recoverable subject to the rules of the PUC. (See Regulation and Rates for
information pertaining to the method of recovery of purchased power and fuel
costs.)
11
The Company and TU Electric
Gas/Oil -- Fuel gas for units at eighteen of the principal generating
stations of TU Electric, having an aggregate net gas/oil capability of 12,955
MW, was provided during 1998 by Fuel Company. Fuel Company supplied
approximately 12% of such fuel gas requirements under contracts with producers
at the wellhead and 88% under contracts with commercial suppliers.
Fuel oil can be stored at seventeen of the principally gas-fueled
generating stations. At December 31, 1998, TU Electric had fuel oil storage
capacity sufficient to accommodate approximately 6.1 million barrels of oil
and had approximately 2.3 million barrels of oil in inventory.
Fuel Company has acquired supplies of gas from producers at the wellhead
under contracts expiring at intervals through 2008. As gas production under
these contracts declines and contracts expire, new contracts are expected to
be negotiated to replenish or augment such supplies. Fuel Company has
negotiated gas purchase contracts, with terms ranging from one to ten years,
with a number of commercial suppliers. Additionally, Fuel Company has entered
into a number of short-term gas purchase contracts with other commercial
suppliers at spot market prices. In general, these spot gas purchase
contracts require both the buyer and seller to purchase and deliver the gas on
negotiated terms during the agreed-upon delivery period. In the past,
curtailments of gas deliveries have been experienced during periods of winter
peak gas demand; however, such curtailments have been of relatively short
duration, have had a minimal impact on operations and generally have required
utilization of fuel oil and gas storage inventories to replace the gas
curtailed. No curtailments were experienced during 1998.
Fuel Company owns and operates an intrastate natural gas pipeline system
that extends from the gas-producing area of the Permian Basin in West Texas to
the East Texas gas fields and southward to the Gulf Coast area. This system
includes a one-half undivided interest in a 36-inch pipeline that extends 395
miles from the Permian Basin area to a point of termination south of the
Dallas-Fort Worth area. Additionally, Fuel Company owns a 39% undivided
interest in another 36-inch pipeline connecting to this pipeline and extending
58 miles eastward to one of Fuel Company's underground gas storage
facilities. Fuel Company also owns and operates approximately 1,450 miles of
various smaller capacity lines that are used to gather and transport natural
gas from other gas-producing areas. The pipeline facilities of Fuel Company
form an integrated network through which fuel gas is gathered and transported
to certain TU Electric generating stations for use in the generation of
electric energy.
Fuel Company also owns and operates three underground gas storage
facilities with a usable capacity of 26.9 billion cubic feet, with
approximately 12.9 billion cubic feet of gas in inventory at December 31,
1998. Gas stored in these facilities currently can be withdrawn for use
during periods of peak demand to meet seasonal and other fluctuations or
curtailment of deliveries by gas suppliers. Under normal operating
conditions, up to 400 million cubic feet can be withdrawn each day for a
ten-day period, with withdrawals at lower rates thereafter. One of these gas
storage facilities, the Worsham-Steed facility located in Jack County, Texas
will be retired after withdrawal of the economically recoverable gas.
TU Electric
Lignite/Coal -- Lignite is used as the primary fuel in two units at the
Big Brown generating station (Big Brown), three units at the Monticello
generating station (Monticello), three units at the Martin Lake generating
station (Martin Lake), and one unit at the Sandow generating station (Sandow),
having an aggregate net capability of 5,825 MW. TU Electric's lignite units
have been constructed adjacent to surface minable lignite reserves. At the
present time, TU Electric owns in fee or has under lease an estimated 476
million tons of proven reserves dedicated to the Big Brown, Monticello and
Martin Lake generating stations. TU Electric also owns in fee or has under
lease in excess of 271 million tons of proven reserves not dedicated to
specific generating stations. Mining Company operates owned and/or leased
equipment to remove the overburden and recover the lignite. One of TU
Electric's lignite units, Sandow Unit 4, is fueled from lignite deposits owned
by Alcoa, which furnishes fuel at no cost to TU Electric for that portion of
energy generated from such unit that is equal to the amount of energy
12
delivered to Alcoa (see Texas Utilities Electric Company and Subsidiaries -
Consolidated Operating Statistics included in Appendix A to this report).
Lignite production operations at Big Brown, Monticello and Martin Lake
are accompanied by an extensive reclamation program that returns the land to
productive uses such as wildlife habitats, commercial timberland and pasture
land. For information concerning federal and state laws with respect to
surface mining, see Environmental Matters.
TU Electric supplements TU Electric-owned lignite fuel at Monticello
with western coal from the Powder River Basin (PRB) in Wyoming. The coal is
purchased from two suppliers under two-year contracts and is transported from
the PRB to TU Electric's generating plants by railcar under a three-year
contract scheduled to expire on December 31, 2001.
TU Electric currently plans to supplement its lignite fuel at Martin Lake
and Big Brown utilizing western coal to be delivered beginning in the year
2000. Construction of a 25-mile rail spur into Big Brown to facilitate the
delivery of the western coal began in July 1998 and is expected to be
completed by July 2000.
The Company
In the third quarter of 1998, the Company settled its advance royalty
obligations for certain coal reserves with a cash payment of approximately
$136 million and a transfer of rights to the coal reserves and related land.
The advance royalty obligations amounted to $16 million per year through 2017.
TU Electric
Nuclear -- TU Electric owns and operates two nuclear-fueled generating
units at the Comanche Peak nuclear powered electric generating station
(Comanche Peak), each of which is designed for a net capability of 1,150 MW.
The nuclear fuel cycle requires the mining and milling of uranium ore to
provide uranium oxide concentrate (U3O8), the conversion of U3O8 to uranium
hexafluoride (UF6), the enrichment of the UF6 and the fabrication of the
enriched uranium into fuel assemblies. TU Electric has on hand, or has
contracted for, the raw materials and services it expects to need for its
nuclear units through future years as follows: uranium (1999), conversion
(2003), enrichment (2014), and fabrication (2011). Although TU Electric
cannot predict the future availability of uranium and nuclear fuel services,
TU Electric does not currently expect to have difficulty obtaining U3O8 and
the services necessary for its conversion, enrichment and fabrication into
nuclear fuel for years later than those shown above.
The Energy Policy Act has provisions for the recovery of a portion of the
costs associated with the decommissioning and decontamination of the gaseous
diffusion plants used to enrich uranium for fuel. These costs are being
recovered in annual fees paid to the United States Department of Energy (DOE)
as determined by the Secretary of Energy. The total unescalated assessment
for all domestic utilities is capped at $150 million per federal fiscal year
assessable for fifteen years. TU Electric's assessment for the 1999 federal
fiscal year, as calculated by the DOE, is approximately $1 million.
The Nuclear Waste Policy Act of 1982, as amended (NWPA), provides for the
development by the DOE of interim storage and permanent disposal facilities
for spent nuclear fuel and/or high level radioactive waste materials. In
January 1998, the DOE did not meet its obligation to begin accepting spent
nuclear fuel. The DOE continues to maintain its position that no obligation
to begin acceptance of spent nuclear fuel exists despite a US Court of Appeals
decision affirming the Company's position that such an obligation does exist.
However, Secretary of Energy William Richardson recently testified that the
DOE is evaluating a proposal to take title to nuclear waste immediately and to
pay for storage of such waste at reactor sites until a permanent repository is
available. TU Electric is unable to predict what impact, if any, the DOE's
delay will have on the Company's future operations. Under provisions of the
NWPA, funding for the program is provided by a one-mill per kWh fee currently
levied on electricity generated and sold from nuclear reactors, including the
Comanche Peak units.
13
TU Electric's onsite spent nuclear fuel storage capability is sufficient
to accommodate the operation of Comanche Peak through the year 2017, while
fully maintaining the capability to off-load the core of one of the
nuclear-fueled generating units. Additional approval from the Nuclear
Regulatory Commission (NRC) will be required to utilize this full storage
capability. TU Electric is currently pursuing options for utilizing a larger
portion of the full storage capability, subject to approval by the NRC.
Transmission
In 1995, TU Electric became the first utility in Texas to functionally
unbundle, or separate, its transmission operations into a business unit. The
unit operates independently within the larger company and has the flexibility
to adapt to changing market and regulatory forces. It is now one of the key
components of the US Electric business segment. TU Electric and SESCO are
members of ERCOT, an intrastate network of investor-owned entities,
cooperatives, public entities, non-utility generators and power marketers.
ERCOT is the regional reliability coordinating organization for member
electric power systems in Texas, the Independent System Operator (ISO) of the
interconnected transmission system of those systems, and is responsible for
ensuring equal access to transmission service by all wholesale market
participants in the ERCOT region.
The function of the transmission business is to provide
non-discriminatory wholesale open access to TU Electric's transmission
facilities through business practices consistent with the standard of conduct
rules enacted by the PUC. The transmission system transverses almost 200,000
square miles of Texas and consists of over 13,000 circuit miles of
transmission line and over 900 substations.
The transmission business supports the operation of the ERCOT ISO and all
ERCOT members, as well as TU Electric's responsibilities and obligations to
its wholesale and retail customers. The transmission business unit has
planning, design, construction, operation, and maintenance responsibility for
the transmission grid and for the load serving substations.
Services are provided under tariffs approved by the PUC and the Federal
Energy Regulatory Commission (FERC). Transmission service offers the use of
the transmission system for delivery of power over facilities operating at
60,000 volts and above. Transformation service offers the use of substation
assets to transform voltage to below 60,000 volts.
Other services offered by the transmission business include: static and
dynamic scheduling and miscellaneous services such as system impact studies,
facilities studies, and maintenance of substations and transmission lines
owned by other parties.
The transmission business is participating with the ISO and other ERCOT
utilities to plan, design and obtain regulatory approval and construct new
transmission lines necessary to increase bulk power transfer capability and to
remove existing limitations on the ERCOT transmission grid.
The principal generating facilities of TU Electric and load centers of TU
Electric and SESCO are connected by 3,863 circuit miles of 345-kilovolt (kV)
transmission lines and 9,327 circuit miles of 138- and 69-kV transmission
lines. SESCO is connected to TU Electric by three 138-kV lines, ten 69-kV
lines and three lines at distribution voltage.
14
Distribution
The TU Electric distribution system supplies electricity to approximately
2.5 million customers (including approximately 2.2 million residential
customers and 300,000 commercial and industrial businesses). On average, TU
Electric has added approximately 45,000 customers to its system each year for
the last several years. The electric distribution business consists of the
ownership, management, construction, maintenance and operation of the
distribution network within TU Electric's certificated service area.
TU Electric's distribution network receives electricity from the
transmission grid through approximately 700 power distribution substations and
distributes electricity to end users and wholesale customers through
approximately 2,700 distribution feeders.
The TU Electric distribution network consists of approximately 51,000
miles of overhead and 9,600 miles of underground conductors. The majority of
the distribution system operates at 25 kV and 12.5 kV. Approximately 75% of
the system (in line-miles) is classified as rural, serving approximately 45%
of the system's customers.
REGULATION AND RATES
The Company and TU Electric
The Company is a holding company as defined in the Public Utility Holding
Company Act of 1935. However, the Company and all of its subsidiary companies
are exempt from the provisions of such Act, except Section 9(a)(2) which
relates to the acquisition of securities of public utility companies and
Section 33 which relates to the acquisition of foreign (non-US) utility
companies.
The Company is also subject to various other federal, state and local
regulations. (See discussion below and Environmental Matters.)
TU Electric and SESCO do not transmit electric energy in interstate
commerce or sell electric energy at wholesale in interstate commerce, or own
or operate facilities therefor, and their facilities are not connected
directly or indirectly to other systems that are involved in such interstate
activities, except during the continuance of emergencies permitting temporary
or permanent connections or under order of the FERC exempting TU Electric and
SESCO from jurisdiction under the Federal Power Act. TU Electric and SESCO
therefore believe that they are not public utilities as defined in the Federal
Power Act and have been advised by their counsel that they are not subject to
general regulation under such Act.
The PUC has original jurisdiction over electric rates and service in
unincorporated areas and those municipalities that have ceded original
jurisdiction to the PUC and has exclusive appellate jurisdiction to review the
rate and service orders and ordinances of municipalities. Generally, PURA
prohibits the collection of any rates or charges (including charges for fuel)
by a public utility that does not have the prior approval of the PUC.
TU Electric is subject to the jurisdiction of the NRC with respect to
nuclear power plants. NRC regulations govern the granting of licenses for the
construction and operation of nuclear power plants and subject such plants to
continuing review and regulation.
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
15
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 deficit of $12 million.
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.
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. Including deferred income
tax effects, the net effect was a $143 million reduction in net income for the
year ended December 31, 1998. In addition, for the year there was $183
million of depreciation expense reclassified from transmission and
distribution to nuclear production assets. 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
16
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 (Docket 20285) -- 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, 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
they have significantly improved the reliability of the supply of fuel to
Monticello and have, 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
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. A majority of the cities
involved have already approved such rates. 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.
COMPETITION
General -- The 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, PURA impacts the PUC
and its regulatory practices and encourages increased competition in the
wholesale electric utility industry in Texas. Although the Company is unable
to predict the ultimate impact of the Energy Policy Act, PURA and any related
regulations or legislation on the US Electric segment companies' operations,
it believes that such actions are consistent with the trend toward increased
competition in the energy industry.
As legislative, regulatory, economic and technological changes occur, the
energy and utility industries are faced with increasing pressure to become
more competitive while adhering to regulatory requirements. The level of
17
competition is affected by a number of variables, including price, reliability
of service, the cost of energy alternatives, new technologies and governmental
regulations.
As a result of the shift in emphasis toward greater competition, large
and small industry participants are offering energy services and
energy-related products that are both economically and environmentally
attractive to customers. 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.
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. These strategies include
initiatives to improve the return on corporate assets and to maximize
shareholder value through new marketing programs, creative rate design and new
business opportunities. Additional initiatives under consideration include
the potential disposition or alternative utilization of existing assets and
the restructuring of strategic business units.
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. 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). To the extent
stranded costs cannot be recovered from customers, it may be necessary for
such costs to be borne by shareholders. In response to these competitive
pressures, many utilities are implementing significant restructuring and
re-engineering initiatives designed to make them more competitive. Since the
implementation of an Operations Review and Cost Reduction program in April
1992, the US Electric segment companies have continued to take steps to reduce
costs by streamlining business processes and operating practices. (For
information pertaining to the effects of competition on the treatment of
certain regulatory assets and liabilities, see Management's Discussion and
Analysis of Financial Condition and Results of Operations and Note 2 to
Consolidated Financial Statements included in Appendix A to this report.)
Retail Competition -- At the federal level, 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.
PURA amendments require the PUC to report to the legislature during each
legislative session, on competition in electric markets. Accordingly, PUC
reports were submitted to the Texas legislature in January 1997 and 1999,
recommending that the legislature continue the process of expanding
competition in the Texas electricity markets, leading to expanded retail
competition, and authorize the PUC to take numerous steps toward that goal.
The PUC further recommended in 1997 that full competition not occur prior to
the year 2000 in order to provide an environment through which both retail
customers and utilities in Texas move more smoothly to achieve the perceived
benefits of competition. 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 date, thirteen states have enacted legislation that provides for
retail competition, and many other states are addressing the issue at this
time. Retail competition has not been implemented in Texas; however, this
issue is currently being addressed in the 76th Texas Legislature. The 1999
session of the Texas legislature is currently in process. Proposed
legislation has been introduced that would restructure the electric utility
industry to, among other matters, authorize competition in the retail market
for electricity, provide for the recovery of certain stranded costs and retain
regulation of the transmission and distribution businesses. While the Company
believes that such legislation could be enacted during the 1999 session, it
cannot predict the result of legislative efforts to restructure the electric
18
utility industry in Texas or how such result might affect the Company's
financial position, results of operations or cash flows.
The US Electric segment companies are experiencing competition for retail
load in areas that are multi-certificated with rural electric cooperatives or
municipal utilities. Except in areas where there is multi-certification by the
PUC, the US Electric segment companies currently have the exclusive right to
provide electric service to the public within their certificated service
areas. In addition, some energy consumers have the ability to produce their
own electricity or to use alternative forms of energy. Industrial customers
may also be able to relocate their facilities to lower-cost service areas. To
some degree, there is competition among utilities with defined service areas
to attract and retain large customers. The US Electric segment companies are
pursuing efforts to remain competitive through competitive pricing, economic
development and other initiatives. (See Regulation and Rates.)
The US Electric segment companies are not able to predict the extent of future
competitive developments in the retail market or what impact, if any, such
developments may have on operations.
Wholesale Competition -- Federal legislation such as the PURPA and, more
recently, the Energy Policy Act, as well as initiatives in various states,
encourage wholesale competition among electric utility and non-utility power
producers. Together with increasing customer demand for lower-priced
electricity and other energy services, these measures have accelerated the
industry's movement toward a more competitive pricing and cost structure.
Wholesale competition in the electric utility industry was addressed in the
1995 session of the Texas legislature when PURA was amended to encourage
greater wholesale competition and flexible retail pricing.
Amendments to PURA made during the 1995 session of the Texas legislature
also allow for wholesale pricing flexibility. While wholesale rates for
electric utilities are not deregulated, wholesale tariffs or contracts with
charges less than approved rates but greater than the utility's marginal cost
may be approved by the regulatory authority upon application by the utility.
In the wholesale power market, TU Electric competes with a variety of
utilities and other suppliers, some of which are willing and able to sell at
rates below TU Electric's standard wholesale power service rate as approved by
the PUC. As a result, TU Electric lost approximately 800 MW of wholesale
load in 1998. In 1998, wholesale revenues represented about 2.5% of TU
Electric's total consolidated operating revenues. TU Electric is unable to
predict the extent of future competitive developments in the wholesale market
or what impact, if any, such developments may have on its operations.
Open-Access Transmission -- At the federal level, the FERC issued Order
No. 888 in April 1996, which requires all FERC-jurisdictional electric public
utilities to offer third parties wholesale transmission services under an
open-access tariff. In May 1997, TU Electric filed with the FERC a
modification of its tariff governing service to, from and over certain High
Voltage Direct Current (HVDC) interconnections between ERCOT and the Southwest
Power Pool, which, in October 1997, was accepted by the FERC with minor
modifications.
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 August 1997, the PUC approved final tariffs for TU Electric's
open-access wholesale transmission service and implemented rates for other
transmission providers within ERCOT. (See Regulation and Rates.) In February
1999, the PUC approved modifications to its rules addressing open-access
wholesale transmission service to allow utilities to revise annually 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.
Customers -- There are no individually significant customers upon which
the segment's business or results of operations are highly dependent.
19
US GAS SEGMENT
GENERAL
US Gas operations (primarily Lone Star Gas, Lone Star Pipeline and EPI)
are engaged in the gathering, processing, transmission and distribution of
natural gas and selling of related natural gas liquids primarily within
Texas.
US Gas Consolidated Operating Statistics
Years Ended December 31
1998 1997*
----- ------
SALES VOLUMES
Gas distribution (billion cubic feet) (Bcf):
Residential 77 33
Commercial and industrial 53 24
---- ----
Total gas distribution 130 57
==== ====
Pipeline transportation (Bcf) 599 255
Gas liquids (million barrels) 6 3
OPERATING REVENUES (millions of dollars)
Gas distribution:
Residential $437 $206
Commercial and industrial 245 124
---- ----
Total gas distribution 682 330
Pipeline transportation 121 58
Gas liquids 64 36
Other 75 52
Less intra-segment revenues (78) (48)
---- ----
Total operating revenues $864 $428
==== ====
GAS DISTRIBUTION CUSTOMERS - (end of year - in thousands)
(end of period) 1,379 1,355
HEATING DEGREE DAYS ( % of normal) 89% 119%
<,fn>
*For the period from acquisition (August 5, 1997) to December 31, 1997.
</FN>
Gas Distribution Peaking -- Lone Star Gas estimates its peak-day
availability from long-term contracts and withdrawals from underground storage
to be 1.5 billion cubic feet (Bcf). Short-term peaking contracts and daily
spot contracts raise this availability level to meet anticipated sales needs.
During 1998, the average daily demand of Lone Star Gas' residential and
commercial customers was 0.3 Bcf. Lone Star Gas' greatest daily demand in
1998 was on December 22 when the arithmetic-mean temperature was 24 degrees F.
and deliveries to all customers reached 2.1 Bcf, including estimated
deliveries to residential and commercial customers of 2.0 Bcf.
20
Gas Supply-- Lone Star Gas' gas supply consists of contracts for the
purchase of specific reserves, contracts not related to specific reserves or
fields, and gas in storage. The total available gas supply as of January 1,
1999, was 299 Bcf, which is approximately two and a half times Lone Star Gas'
purchases during 1998. Of this total, 89 Bcf are specific reserves and 34 Bcf
are working gas in storage. Management has calculated that 176 Bcf are
committed to Lone Star Gas under gas supply contracts not related to specific
reserves or fields. In 1998, Lone Star Gas' gas requirement was purchased
from some 265 independent producers and non-affiliated pipeline companies.
To meet peak-day gas demands during winter months, Lone Star Gas utilizes
the service of seven gas storage fields owned by Lone Star Pipeline, all of
which are located in Texas. These fields have a working gas capacity of 47 Bcf
and a storage withdrawal capacity of up to 1.2 Bcf per day.
Lone Star Gas has historically maintained a contractual right to curtail,
which is designed to achieve the highest load factor possible in the use of
the pipeline system while assuring continuous and uninterrupted service to the
residential and commercial customers. Under the program, industrial customers
select their own rates and relative priorities of service. Interruptible
service contracts include the right to curtail gas deliveries up to 100%
according to a strict priority plan. The last sales curtailment for Lone Star
Gas occurred in 1990 and lasted for only 30 hours.
Estimates of gas supplies and reserves are not necessarily indicative of
Lone Star Gas' ability to meet current or anticipated market demands or
immediate delivery requirements because of factors such as the physical
limitations of gathering and transmission systems, the duration and severity
of cold weather, the availability of gas reserves from its suppliers, the
ability to purchase additional supplies on a short-term basis and actions by
federal and state regulatory authorities. Curtailment rights provide Lone Star
Gas flexibility to meet the human-needs requirements of its customers on a
firm basis. Priority allocations and price limitations imposed by federal and
state regulatory agencies, as well as other factors beyond the control of Lone
Star Gas, may affect its ability to meet the demands of its customers.
Lone Star Gas buys gas under long-term and short-term intrastate
contracts in order to assure reliable supply to its customers. Many of these
contracts require minimum purchases of gas. Presently, based on estimated gas
demand which assumes normal weather conditions, requisite gas purchases are
expected to substantially satisfy purchase obligations for the year 1999 and
thereafter.
The Lone Star Gas supply program is designed to contract for new supplies
of gas and to recontract targeted expiring sources. In addition to being
heavily concentrated in the established gas-producing areas of central,
northern and eastern Texas, Lone Star Pipeline's intrastate pipeline system
also extends into or near the major producing areas of the Texas Gulf Coast
and the Delaware and Val Verde Basins of West Texas. Nine basins located in
Texas are estimated to contain a substantial portion of the nation's remaining
onshore natural gas reserves. Lone Star Pipeline's pipeline system provides
access to all of these basins. Lone Star Pipeline is well situated to receive
large volumes into its system at the major hubs, such as Katy and Waha, as
well as at the major third-party owned storage facilities where suppliers
maintain instantaneous high delivery capabilities.
At December 31, 1998, Lone Star Pipeline operated approximately 7,600
miles of transmission and gathering lines and operated 22 compressor stations
having a total rated horsepower of approximately 76,000. Lone Star Pipeline
also 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.
21
REGULATION AND RATES
Lone Star Gas and Lone Star Pipeline are wholly intrastate in character
and perform distribution utility operations and transportation services in the
State of Texas subject to regulation by the RRC and municipalities in Texas.
The RRC regulates the charge for the transportation of gas by Lone Star
Pipeline to Lone Star Gas' distribution systems for sale to Lone Star Gas'
residential and commercial consumers. Lone Star Pipeline owns no certificate
interstate transmission facilities subject to the jurisdiction of the FERC
under the Natural Gas Act, has no sales for resale under the rate
jurisdiction of the FERC and does not perform any transportation service that
is subject to FERC jurisdiction under the Natural Gas Act.
The city gate rate for the cost of gas Lone Star Gas ultimately delivers
to residential and commercial customers is established by the RRC and provides
for full recovery of the actual cost of gas delivered, including out-of-period
costs such as gas purchase contract settlement costs. The distribution
service rates Lone Star Gas charges its residential and commercial customers
are established by the municipal governments of the cities and towns served,
with the RRC having appellate jurisdiction. Lone Star Gas has an ongoing
program of analyzing the sufficiency of rates in its various local
distribution systems and requesting rate increases where appropriate.
In August 1996, the RRC ordered a general inquiry into the rates and
services of Lone Star Gas, most notably a review of historic gas cost and gas
acquisition practices since the last rate setting. The inquiry docket was
separated into different phases, all of which are now resolved. Two of the
phases, conversion to the National Association of Regulatory Utility
Commissioners account numbering system and unbundling, have been dismissed by
the RRC, and one other phase, rate case expense, has been concluded. In the
phase dealing with historic gas cost and gas acquisition practices, the RRC
issued a final order on June 2, 1998 approving a stipulated settlement of the
docket. Lone Star Gas agreed to credit residential and commercial customers
$18 million to be spread over the next two heating seasons (November through
March). The earnings of Lone Star Gas were not affected by the settlement due
to previously established reserves. Lone Star Gas and the intervenors both
agreed to withdraw their appeals of the city gate rate case. The final order
approving the stipulation found that all gas costs flowed through Lone Star
Gas' monthly gas cost adjustment clause prior to October 31, 1997 were just,
reasonable and necessary.
COMPETITION
Customer sensitivity to energy prices and the availability of
competitively priced gas in the non-regulated markets continue to provide
intense competition in the electric-generation and industrial-user markets.
Natural gas faces varying degrees of competition from electricity, coal,
natural gas liquids, oil and other refined products throughout Lone Star Gas'
service territory. Pipeline systems of other companies, both intrastate and
interstate, extend into or through the areas in which Lone Star Gas' markets
are located, creating competition from other sellers of natural gas.
Competitive pressure from other pipelines and alternative fuels has caused a
decline in sales by Lone Star Gas to industrial and electric-generation
customers. As developments in the energy industry point to a continuation of
these competitive pressures, Lone Star Gas maintains its focus on customer
service and the creation of new services for its customers in order to remain
its customers' supplier of choice.
Lone Star Pipeline is the sole transporter of natural gas to Lone Star
Gas' distribution systems. Lone Star Pipeline competes with other pipelines in
Texas to transport natural gas to off-system markets. This business is highly
competitive and greatly influenced by the demand to move natural gas across
Texas to supply Northeast and upper Midwest US markets.
Natural gas liquids processing is highly competitive and includes
competition among producers, third-party owners and processors for
cost-sharing and interest-sharing arrangements.
Open Access -- Lone Star Pipeline has been an open access transporter
under Section 311 of the Natural Gas Policy Act of 1978 (NGPA) on its
intrastate transmission facilities since July 1988. Such transportation is
performed pursuant to Section 311(a)(2) of the NGPA and is subject to an
exemption from the jurisdiction of the FERC under the Natural Gas Act,
pursuant to Section 601 of the NGPA.
There are no individually significant customers upon which the segment's
business or results of operations are highly dependent.
22
US ENERGY MARKETING SEGMENT
GENERAL
US Energy Marketing (EES) operations are engaged in purchasing and
selling natural gas and electricity and providing risk management services for
the energy industry throughout the US, other than within ERCOT.
US Energy Marketing Operating Statistics
Years Ended December 31
1998 1997*
----- ----
SALES VOLUMES:
Gas (Bcf) 1,115 292
Electric (GWh) 16,268 -
OPERATING REVENUES (millions of dollars) $3,199 $859
<FN>
*For the period from acquisition (August 5, 1997) to December 31, 1997.
</FN>
Headquartered in Houston, Texas, EES serves the diversified energy
requirements of its clients from five regional centers and 17 local customer
service and support offices located across the US. EES' primary natural gas
markets, both retail and wholesale, are in Texas, the Northeast, the Midwest
and the West Coast. Other than within ERCOT, EES engages in the physical
purchase and sale of electricity in the wholesale markets throughout the US
and is also engaged in power retail marketing, primarily in the Northeast
region of the country.
In the course of providing comprehensive energy products and services to
its diversified client base, EES engages in energy price risk management
activities. In addition to the purchase and sale of 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. In order to manage
its exposure to the price risk associated with these instruments, EES has
established trading policies and limits and revalues its exposures daily
against these benchmarks. EES also periodically reviews these policies to
ensure they are responsive to changing market and business conditions.
EES' business is not specifically seasonal; however, the results of its
operations are greatly affected by price volatility in the underlying
commodity markets. Price volatility in both natural gas and electric power is
largely a result of supply and demand factors driven by weather conditions and
physical constraints in the deliverability of these commodities. Arbitrage
opportunities resulting from this price volatility are often greatest in the
late summer/early fall and winter months for natural gas and the summer months
for electricity.
COMPETITION
EES pursues opportunities to manage risks for companies outside the
Company's system. As natural-gas markets continue to evolve following the
implementation of the 1992 Order 636 of the FERC, additional opportunities are
created in the broader, more active trading markets and in serving
non-regulated customers. This highly competitive market demands that a wide
array of services be offered, including term contracts with interruptible and
firm deliveries, risk management, aggregation of supply, nominations,
scheduling of deliveries and storage.
Customers -- There are no individually significant customers upon which
the segment's business or results of operations are highly dependent.
23
UK/EUROPE SEGMENT
GENERAL
The UK/Europe operations are conducted primarily by Eastern Group. It's
energy business consists of three core activities: the generation of
electricity, the retailing of electricity and natural gas and production of
natural gas, and the distribution of electricity. This combination of
integrated activities within the electricity and gas industries provides
Eastern Group with opportunities to benefit throughout the electricity and gas
supply chains, from fuel sourcing to customer sales. The overall financial
efficiency of these activities is coordinated and optimized by EPETL. These
activities are carried out primarily in the UK but with interests increasingly
being developed throughout the rest of Europe.
UK/Europe Consolidated Operating Statistics
Year Ended December 31
1998*
SALES VOLUMES
Electric (GWh)
Industrial and commercial 15,459
Residential 7,826
------
Total electric 23,285
======
Units Distributed (GWh) 19,249
======
Gas (Bcf)
Industrial and commercial 51
Residential 21
------
Total gas 72
======
Wholesale Energy Sales
Electricity generated and sold to the Pool(GWh) 51,060
======
Gas (Bcf) 148
======
OPERATING REVENUES (millions of dollars)
Electric
Industrial and commercial $ 1,150
Residential 842
-------
Total electric operating revenues 1,992
Distribution 393
Gas
Industrial and commercial 125
Residential 136
-------
Total gas operating revenues 261
Wholesale energy sales 1,198
Other 98
Less intra-segment revenues (341)
-------
Total operating revenues $ 3,601
=======
CUSTOMERS (end of year - in thousands)
Electric 3,211
Gas 777
* For the period from acquisition (May 19, 1998) to December 31, 1998.
24
Generation
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 Generation is the fourth largest generator of electricity in the
UK with a share of approximately 9.4% of the total registered generating
capacity in the UK. It currently owns, operates or has an interest in eight
power stations in the UK with an aggregate net generating capability of 6,784
MW. It also has a controlling interest in Nedalo (UK) Limited (Nedalo), the
largest supplier of small (up to one MW) combined heat and power (CHP) plants
in the UK. Eastern Generation has recently acquired two additional CHP plants
with 46 MW of capacity. (See Item 2. Properties). It also has a controlling
interest in Teplarny Brno a.s. a district heating and generation company in
the Czech Republic.
Eastern Group's current portfolio of power stations, predominantly a mix
of combined cycle gas turbines (CCGT) and coal-fired stations, 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.
In June 1996, Eastern Group assumed operational and commercial control,
through a combination of lease and outright sale from National Power plc
(National Power), of all of the assets and a portion of the liabilities of the
West Burton, Rugeley B and Ironbridge power stations. Eastern Group holds a
99-year lease over the land, buildings and plant at each of those power
stations. Under the leases, Eastern Group was committed to make fixed
payments totaling $1,220 million, of which $558 million was paid at
commencement of the leases. The balance, together with interest, is payable
in 2001. Further payments of approximately $10 per megawatt-hour (MWh),
indexed to inflation, that are linked to output levels from these stations are
also payable to National Power through 2000.
Eastern Group has leased the land, buildings and plant at the Drakelow C
and High Marnham power stations from PowerGen plc (PowerGen) for a period of
99 years, pursuant to agreements entered into in July 1996. PowerGen is
responsible for decommissioning costs should Eastern Group decide to close
these stations during the term of the leases. Eastern Group is committed to
fixed payments totaling $381 million, subject to minor adjustments if
aggregate capacity falls below a certain level. The payments, together with
interest, are payable in installments over eight years beginning in 1996. As
with the National Power leases, further output-related payments of
approximately $10 per MWh, indexed to inflation, are payable to PowerGen for
the first five years of operation by Eastern Group. On November 25, 1998, the
UK Secretary of State for Trade and Industry (Secretary of State) confirmed
that, as a condition for allowing PowerGen to acquire East Midlands
Electricity plc, he would require that the output-related elements of these
lease arrangements be terminated 15 months early. The output -related
payments to PowerGen will now terminate in March 2000.
Electricity and Natural Gas Retailing
Eastern Group is integrating its electricity and gas retailing businesses
into a single operation.
The electricity retailing business involves the sale to customers of
electricity that is purchased from the Pool. Pool price risk is managed on
behalf of the retail business by EPETL. The retail business is charged a
regulated price by transmission and distribution companies, including Eastern
Electricity, for the physical delivery of electricity. Eastern Electricity
supplies electricity to customers in all sectors of the market and is one of
the largest retailers of electricity in England and Wales.
25
Ex-Franchise Market -- Eastern Electricity currently supplies electricity
to approximately 3.2 million customers (including approximately 2.9 million
domestic (residential) customers and 250,000 small businesses). The domestic
franchise market in the UK is being progressively opened to competition
beginning September 1998 and is expected to be open to full competition in
June 1999. Eastern Electricity's authorized area, which covers approximately
20,300 square kilometers in the east of England and parts of north London, was
one of four areas in the first group to be opened to competition.
Competitive (Industrial and Commercial) Market -- Eastern Group is an
active participant in the competitive UK electricity market. The competitive
market is made up of customers with over 100 KW of demand which typically
includes large commercial and industrial users. As of December 31, 1998, this
market consisted of over 51,000 sites. Eastern Group estimates that this
represents a market size of approximately $10 billion per year based upon
electricity prices at that date. In addition Eastern Group estimates that more
than 85% of these sites are outside its authorized area and that over 60% of
its electricity sales to the competitive market are to customers outside its
authorized area. At December 31, 1998, Eastern Group had a more than 13%
share of this market.
As a result of UK government action in recent years, the UK natural gas
market is open to competition by competing retailers. Eastern Group, through
Eastern Natural Gas and its subsidiaries, 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 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 also announced in November 1998 a gas retailing joint
venture in Holland with Energie NoordWest and an electricity trading and
retail joint venture with Lund Energi in Sweden.
Electricity Distribution
Eastern Group's electricity networks business consists of the ownership,
management and operation of the electricity distribution network within
Eastern Group's authorized area. Eastern Group receives electricity in
England and Wales from the transmission system for electricity (National
Grid) and distributes electricity to end users connected to Eastern Group's
power lines.
Almost all electricity customers in Eastern Group's authorized area,
whether franchise or competitive, are connected to and dependent upon Eastern
Group's distribution system. Eastern Group distributes approximately 32
terrawatt hours (Twh) of electricity annually to approximately 3.2 million
customers, representing more than seven million people. Most of the tangible
fixed assets owned by Eastern Group in the UK are currently employed in the
electricity distribution business. The distribution by Eastern Group of
electricity in its authorized area is regulated by its Public Electricity
Supply License (PES License) which, other than in exceptional circumstances,
is due to remain in effect until at least 2025.
Physical Distribution System -- Eastern Group receives electricity from
the National Grid at 21 supply points within its authorized area and three
points in the authorized areas of neighboring regional electricity companies
(RECs). The majority of this electricity is received at 132kV. It is then
distributed to customers through Eastern Group's system of approximately
35,300 kilometers of overhead lines, 53,900 kilometers of underground cable
and numerous transformers and switchgear, through a series of interconnected
networks operating at successively lower voltages. Eastern Group also
receives electricity directly from power stations located in its authorized
area and, from time to time, from customers' own generating plants and
connections with neighboring RECs.
Most of the revenue from use of the distribution system is from Eastern
Group electricity retail operations. The rest is derived from holders of
second tier supply licenses issued pursuant to the Electricity Act of 1989 of
Great Britain (Electricity Act) (Second Tier Supply Licenses) in respect of
the delivery of electricity to their customers located in Eastern Group's
authorized area.
26
Energy Trading Business
Typically, holders of PES Licenses issued pursuant to the Electricity Act
in connection with the supply and distribution within an authorized area in
Great Britain are exposed to risk, as they are obliged to supply electricity
to their customers at stable prices but have to purchase almost all the
electricity necessary to supply those customers from the Pool at prices which
are constantly changing. The ownership of generating assets provides a natural
hedge against these risks, as does the use of financial instruments such as
contracts for differences (CfDs).
A CfD is an agreement between two parties calling for payments between
the parties of amounts equal to the product of (a) the difference in each
settlement period between the Pool price and the price specified in the CfD
(strike price) and (b) the amount of electricity provided for in that
settlement period, which is usually expressed in MW of demand. Each
settlement period is one-half hour. CfDs effectively fix the prices a
supplier pays and a generator receives for electricity. In this way, CfDs
reduce the financial risk otherwise associated with the sale and purchase of
electricity through the Pool.
EPETL coordinates the Eastern Group's activities in managing risk. It
provides support to Eastern Group's electricity and natural gas retail
activities, taking into account its electricity and natural gas purchases and
sales and its contract portfolios, including Eastern Group's physical power
station assets and natural gas production interests. EPETL is responsible for
setting the level of bids into the Pool for the output of each of Eastern
Group's generating stations, other than the Barking and CHP plants. EPETL
uses this method to coordinate the operation of Eastern Group's generating
stations with Eastern Group's fuel contract position and its retail and
wholesale electricity and natural gas sales portfolios to Eastern Group's best
advantage. It also coordinates the operation of Eastern Group's power
stations taking into consideration the relative prices in gas and electricity
markets. EPETL also earns revenue by providing risk management services to
other retailers of electricity and gas to assist them in managing their
Pool/market price risk.
EPETL manages Eastern Group's financial exposure to fluctuations in
electricity prices through its portfolio of CfDs, a small number of which are
long-term; bidding both price and volume for Eastern Group's generation
output (other than the Barking and CHP plants) into the Pool for each half
hour of the day; and by deciding with the electricity retailing division the
volume and pricing of sales in the competitive and franchise markets.
The overall electricity position for each half hour of the day is
monitored by EPETL with the goal of optimizing electricity purchases and sales
positions. The resulting net position is subject to risk exposure limits that
are monitored by a risk management team within Eastern Group. EPETL also
carries out credit checks on counterparties. Similar processes and procedures
apply to gas market activities, where Eastern Group has a substantial and
growing retail position, as well as its gas-fired power stations and a number
of long-term and short- term purchase contract positions. Eastern Group's
ability to manage such risk in the future will depend, in part, on the terms
of its supply contracts, its ability to manage an appropriate hedging
strategy, the continuation of an adequate market for hedging instruments and
the performance of its generating and upstream gas assets.
In order to help meet the expected needs of its natural gas wholesale and
retail customers (including its power stations), Eastern Group has entered
into a variety of gas purchase contracts. As of December 31, 1998, the
commitments under long-term purchase contracts amounted to an estimated $2.2
billion, covering periods of up to 16 years. Firm sales commitments,
including estimated power station usage, at the same date amounted to $5.0
billion, covering periods up to 18 years.
EPETL also purchases coal, oil and natural gas for the Eastern Group's UK
power stations and has equity interests in four natural gas producing fields
in the North Sea. In November 1998, Eastern announced a significant expansion
of its North Sea gas interests through an agreement to purchase all of BHP
Petroleum's assets in the southern North Sea for approximately $165 million.
These assets increased Eastern's interest in the Johnston field from
approximately 5% to 35%. In December 1998, Eastern also agreed to purchase
Monument Oil's 20% share of this field for almost $33 million. Both
acquisitions are subject to the approval of the UK Department of Trade and
Industry.
27
The energy trading business also trades on the Nord Pool, the electricity
trading market in Scandinavia, and has recently negotiated access to 183 MW of
hydro output in Norway for 55 years, in relation to which Eastern Group has
agreed to pay an up-front fee of up to $290 million.
REGULATION AND RATES
Eastern Group's operations are subject to extensive and changing
regulation in the UK.
The electricity industry in the UK is subject to regulation under, among
other things, the Electricity Act and certain UK and European Union (EU)
competition and environmental legislation. Eastern Group is also subject to
existing UK and EU legislation on competition and regulation in its gas
businesses. In addition, a portion of any profit received by Eastern Group on
its disposal of certain assets vested in it at the time of its privatization
is subject to recovery by the Secretary of State until March 31, 2000.
Eastern Group possesses all of the necessary franchises, licenses and
certificates required to enable it to conduct its businesses.
In March 1998, the Secretary of State published a green paper on utility
regulation, including price controls, for gas, electricity, water and
telecommunications. After a period of consultation, the UK government has
announced that the Office of Electricity Regulation covering England, Wales
and Scotland (OFFER) and the Office of Gas Supply (OFGAS) will be merged as
part of expected legislation. The UK government has consulted on the need for
greater separation of distribution, supply and metering activities and special
measures to protect disadvantaged customers. Eastern Group expects these
proposals to be part of legislation that will be introduced in 1999. The
implementation of such measures is uncertain, but could result in significant
changes to the existing regulatory regime. Similarly, in October 1998 the UK
government published a white paper proposing controls over the future
development of gas-fired power stations, and the Director General of
Electricity Supply in Great Britain (DGES) is reviewing the operations of the
Pool with a view to promoting alternative trading arrangements. There can be
no assurance regarding the potential impact of regulatory changes, if any, on
Eastern Group.
Unless covered by an exemption, all electricity generators operating a
power station in the UK are required to have generation licenses. The
conditions attached to such a license in the UK require the holder, among
other things, to be a member of the Pool and to submit the output of power
station generating units or turbines for central dispatch. Failure to comply
with any of the generation license conditions may subject the licensee to a
variety of sanctions, including enforcement orders by the DGES and license
revocation if an enforcement order is not complied with.
The Secretary of State has power under the Electricity Act to require
generators that operate power stations with a capacity of at least 50 MW to
maintain stocks of fuel and other materials at power stations. The Secretary
of State completed a review of the level of fuel stocks held by generators in
1997. No increase was required, but Pool rules were changed as of December
1997 to penalize gas power plants reducing output during times of insufficient
plant margins. Eastern Group does not anticipate that these changes will have
a material adverse effect on its results of operations.
In the UK, each PES License limits the amount of the generation capacity
in which each REC may hold an interest without the prior consent of the DGES.
These own-generation limits currently restrict the participation by a REC and
its affiliates in generation to a level of approximately 15% of the
simultaneous maximum electricity demand in that REC's authorized area at the
time of privatization. Eastern Group's limit is 1,000 MW. The DGES stated in
January 1996 that he would be prepared to consider a REC's request to increase
its own-generation capacity on the condition that it accept explicit
restrictions on the contracts it signs with its supply business. At a
minimum, a REC would be prohibited from passing additional own-generation
output into its franchise market. Following public consultation, the DGES set
out the basis on which consents for RECs to acquire new generation capacity
would be allowed. The specific consent of the DGES to the leasing by Eastern
Group of 6,000 MW of generating capacity from National Power and PowerGen was
subsequently confirmed by OFFER. Eastern Group's acquisition of additional
generation capacity at Shotton and Dowlais have also been approved in
principle.
28
Electricity Retailing -- Subject to certain exceptions, each retail
supplier of electricity in the franchise market in the UK is required to have
a PES License for its authorized area and is required under the Electricity
Act to provide a supply of electricity upon request to any premises in that
area, except in specified circumstances. Each PES License holder is subject
to various obligations under its PES License. These include prohibitions on
cross-subsidies among its various regulated businesses and on discrimination
in respect of the supply of customers. Each PES License holder is also
required to offer open access to its distribution network on
non-discriminatory terms. This obligation includes a requirement not to
discriminate between its own supply business and other users of its
distribution system. PES License holders are subject to separate controls on
the tariffs to franchise customers and in respect of distribution charges.
OFFER has begun a major review of the distribution and supply price
regulation. It is expected to lead to changes, possibly substantial, in the
year 2000. Eastern Group is not able to predict the outcome of this review or
the impact on its results of operations.
A supplier of electricity to the competitive market in the UK must,
subject to certain exemptions, have a Second Tier Supply License or a PES
License for the service area in which customers are supplied.
Electricity Supply Price Regulation -- Supply charges in the franchise
market are regulated by a maximum price control that applies to each tariff
in the residential and small business customer electricity market and
effectively provides customers with price guarantees. On April 1, 1998,
Eastern Group's tariffs were reduced by 8.9%, before adjustments for
inflation. Eastern Group's tariffs must be reduced by a further 3%, before
adjustments for inflation, beginning in April 1999.
As the franchise market is opened to competition, supply price restraints
are no longer expected to be applicable to current franchise market supply
customers. However, the DGES has indicated in his supply price restraint
proposals published in October 1997, that beginning April 1, 1998, price
regulation would be put in place for supply to all residential and small
business customers whose annual consumption is below 12,000 kWh within Eastern
Group's authorized area, and would remain in place until an adequate level of
competition is established, and, at least, until March 31, 2000.
Electricity Distribution Price Regulation -- A formula determines the
maximum average price per unit of electricity distributed (in pence per
kilowatt hour) that a 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 sterling for pound sterling increase in operating
profit for efficient operations and reduction of expenses within a review
period. The next Distribution Price Control Formula review is scheduled to be
implemented in April 2000. The 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.
Gas -- The natural gas supply activities of Eastern Natural Gas are
principally regulated by the Director General of Gas Supply under the UK Gas
Act 1986, as amended by the UK Gas Act 1995 (Gas Acts) and by the conditions
of Eastern Natural Gas' licenses. Eastern Natural Gas currently holds a
public gas transporter's license, a gas supplier's license and a gas shipper's
license. The natural gas supply business is not subject to price regulation.
Energy Trading -- EPETL is permitted by the Financial Services Authority
under the UK Financial Services Act 1986 to deal in CfDs, including futures
and options. A subsidiary of EPETL is a joint holder of production licenses
relating to its equity interest in four North Sea natural gas fields.
COMPETITION
Generation Business -- Eastern Generation was the fourth largest
generator of electricity in the UK as of December 31, 1998, with a share of
approximately 9.4% of total UK generation capacity registered at that date.
This compares to shares of approximately 22%, 20% and 10% for National Power,
PowerGen and British Energy plc, respectively. Eastern Generation'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. The generating market will be
29
affected by the outcome of the review of energy sources by the UK Government
and the regulatory review of electricity trading arrangements. Eastern
Generation cannot predict the impact of these reviews but believes it is
currently well positioned in the market.
Electricity Retailing -- Until September 1998, residential and small
business customers in all service areas could buy electricity only from the
REC authorized to supply service in the area where the customers were
located. In those areas where competition has been fully introduced, they now
are able to buy electricity from any appropriately licensed supplier, and this
will be the case for all customers once competition has been phased in
throughout the UK. This is expected to be completed by June 1999.
Second-tier suppliers who hold a Second Tier Supply License compete with one
another and with the local REC to supply customers in the competitive market.
Eastern Group competes in the competitive electricity market for
customers with over 100 kW of demand on the basis of the quality of its
customer service and by competitive pricing. In its fiscal year ended March
31, 1998, and at December 31, 1998, Eastern Group had a share of over 13% by
sales volume of this market, making it one of the leading competitive market
suppliers. The largest suppliers in this market over the same period were
PowerGen and National Power.
Eastern Group is currently the largest ex-franchise market supplier in
the UK. Competition for customers in all areas of the UK is being
progressively phased in. This process began in September 1998. The full
consequences of the phase in of competition are unpredictable, including the
extent to which new entrants who are not PES License holders will enter the
supply market, the impact of price competition, if any, and customers'
propensity to change suppliers. 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 traditional service
area.
There is no assurance whether or not competition among suppliers of
electricity will adversely affect Eastern Group.
Natural Gas Retailing -- The gas supply market is highly competitive,
with Eastern Group's main competitors being Centrica plc and the gas marketing
arms of certain major oil companies. Further competition is provided by a
number of other electricity companies and smaller gas suppliers which are
independent of the major oil companies and which each have a minor presence in
the market.
Eastern Group intends to maintain a significant share of this market
through high-quality customer service and competitive pricing.
Customers --There are no individually significant customers upon which
the segment's business or results of operations are highly dependent.
30
AUSTRALIA SEGMENT
GENERAL
Australian operations, primarily through Eastern Energy, are engaged in
the purchase, distribution, marketing and sale of electricity, primarily in
the State of Victoria, Australia. On February 24, 1999, the Company acquired
the gas retail and distribution operations of Kinetik Energy and Westar,
respectively.
Australian Operating Statistics
Years Ended December 31
1998 1997 1996
---- ---- ----
ELECTRIC ENERGY SALES (GWh)
Residential 2,468 2,410 2,386
Commercial 1,346 1,250 1,216
Industrial 1,347 1,468 1,380
Government and municipal 52 62 108
----- ----- -----
Total electric energy sales 5,213 5,190 5,090
===== ===== =====
OPERATING REVENUES (millions of dollars)
Electric
Residential $ 208 $ 223 $ 224
Commercial 88 112 109
Industrial 64 76 91
Government and municipal -- 19 23
Other 79 59 27
----- ----- -----
Total Operating Revenues $ 439 $ 489 $ 474
===== ===== =====
ELECTRIC CUSTOMERS (end of year - in thousands) 500 489 481
TU Australia, through its principal subsidiary, Eastern Energy,
purchases, distributes and retails electricity to approximately 500,000
customers in a 31,000 square mile network region primarily in the State of
Victoria, Australia. The distribution service area encompasses three of the
four fastest-growing suburban areas in Melbourne's region with almost 60
percent of customers living in suburban Melbourne, Australia's second-largest
city. TU Australia operates a number of other subsidiary companies, which
complement Eastern Energy. Enetech provides infrastructure construction and
maintenance capability, servicing electricity, water, telecommunications and
transport utilities. Global Customer Solutions provides call center, billing
and credit collection services to Eastern Energy and external customers,
including a number of local government districts. TU Australia has also
recently acquired the rights to construct and operate an underground gas
storage facility, Western Underground Storage, which will supply gas into
Melbourne and western Victoria. This will be the first underground gas storage
facility in Australia. The gas facility is expected to commence operations in
mid-1999.
Eastern Energy is the holder of an Electricity Distribution License,
which provides a right to distribute electricity within a defined geographical
area in accordance with a set of conditions that attach to the license.
Eastern Energy also holds a franchise to sell electricity to retail customers
with electricity loads of less than 160 MWh/year. This franchise is in
effect until January 1, 2001, at which time customers will be able to deal
with the retailer of their choice.
Energy demand is relatively stable throughout the year. Demand does
increase during the winter months of June through August, but the increase
averages only 10% above average monthly demand.
31
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 is of similar size. The purchase price was $1.0 billion which
was 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. Westar/Kinetik Energy revenues for the year ended June 30, 1998 were
$167 million.
Purchased Power -- In the eastern Australia electricity supply industry,
generators are required to offer all of their energy output for sale through
the wholesale market. The two major components of the wholesale market are
(i) the competitive energy market, centered around a trading pool, which
covers the sale of electricity by generators to retailers and large customers,
and (ii) contract trade, involving bilateral financial contracts between
buyers and sellers of electricity outside the Pool. Eastern Energy and other
distribution and retail companies in the State of Victoria, Australia purchase
their electric energy needs from the competitive power pool owned and operated
by the Victorian government. A full national market commenced in 1998 among
the participants in the States of New South Wales, Victoria, Queensland, South
Australia and the Australian Capital Territory, and is operated by a
corporation owned by the governments of those jurisdictions. Because the spot
price of electric energy from the pool can vary substantially from time to
time, Eastern Energy enters into hedging contracts with electric energy
generators and others to manage its exposure to such price fluctuations (see
Management's Discussion and Analysis of Financial Condition and Results of
Operations and Note 10 to Consolidated Financial Statements included in
Appendix A to this report).
REGULATION AND RATES
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 Eastern Energy 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.
COMPETITION
Retail Electric Market -- 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 completed 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 suppliers
and distribution companies to those customers having a right to choose their
supplier. Eastern Energy similarly can supply electric energy to such
customers in other territories by utilizing the distribution networks of the
distribution companies in those service territories. To date, this phase-in
has resulted in some loss of energy sales an reduced margins. Though Eastern
Energy expects significant competition in the fully contestable energy retail
market, it cannot predict the ultimate outcome of this process.
Eastern Energy is the holder of retail licenses to sell electricity in
Victoria and New South Wales. Under the terms of the licenses, Eastern Energy
is required to comply with a set of Pool Rules in each State established by
the Victorian Power Exchange (VPX)/National Electricity Market Management
Company (NEMMCO) and Transgrid respectively. The Pool Rules require Eastern
Energy to provide bank guarantees for amounts of $25 million and $0.6 million
to protect VPX/NEMMCO and Transgrid, respectively, from financial loss arising
from a default by Eastern Energy.
Customers -- There are no individually significant customers upon which
the segment's business or results of operations are highly dependent.
32
OTHER BUSINESSES
GENERAL
Other business operations consist of telecommunications, retail energy
services, international gas operations, power development and other energy
development activities. None of these operations is of significant magnitude
to constitute a segment. The telecommunication business operations are the
most significant business within this group.
REGULATION AND RATES
LCC is not subject to direct rate or service regulation. However, its
affiliates, LCTX and LCTLD, are regulated at both the state and federal
level. LCTX is a local exchange company providing a variety of local and
intrastate long-distance services. LCTX is regulated in Texas by the PUC.
This regulation applies to the geographical areas served, the intrastate
local and long-distance rates and tariffs and the intrastate access services
provided by LCTX. Because LCTX has elected to provide intrastate services
under an incentive rate regulation plan available under the PUC's enabling
statute, intrastate rates are subject to only limited regulation by the PUC.
LCTX is also regulated by the Federal Communications Commission (FCC) for
certain services. Regulation by the FCC is limited primarily to interstate
access rates and services. LCTLD provides long-distance service in the States
of Texas and Louisiana as well as interstate long-distance service. Interstate
long-distance service is regulated by the FCC. Intrastate, interexchange
service is regulated by the respective state commissions. In Texas,
regulation is limited to certification to do business and the filing of rate
sheets. The rates charged are not subject to direct regulation by the PUC.
In Louisiana, LCTLD is required to file rate tariffs, but rate regulation is
subject to maintaining rates for services within a "band" or range of rates
set by the Louisiana Public Service Commission. At the federal level, LCTLD's
interstate long-distance rates are filed in the form of rate sheets. The FCC
does not establish rates for interstate long-distance service, since such
services are subject to competition from a large number of interexchange
long-distance service providers.
COMPETITION
LCC's long-distance service at both the intrastate and interstate level
is subject to competition. Interexchange long-distance service has been
subject to competition for more than ten years. LCTLD competes with numerous
interexchange carriers ranging from small resellers to large, facilities-based
carriers such as AT&T and MCI WorldCom. While monitored by regulatory
authorities, rates for these long-distance services are largely market based
and essentially have been deregulated.
LCTX also provides intrastate intraLATA long-distance service. Upon
divestiture of the Bell System, the state was divided into long-distance
calling areas called Local Access Transport Areas (LATA's). Direct dialed
long-distance calls made within the boundaries of the LATA are reserved for
handling by the local exchange carrier at state-wide average rates. Customers
may use the carrier of their choice for intraLATA calls only by dialing a
special carrier access code before each call. Because intraLATA service was
not subject to equal access, the local exchange companies have dominated this
service sector.
LCTX is also subject to, but to date has not experienced significant
levels of, local competition. It is too early to predict whether significant
local competition will emerge in LCTX's service area.
33
ENVIRONMENTAL MATTERS
The Company and TU Electric
US SEGMENTS
The Company and its US subsidiaries are subject to various federal, state
and local regulations dealing with air and water quality and related
environmental matters. (See Item 2. Properties - Capital Expenditures and
Management's Discussion and Analysis of Financial Condition and Results of
Operation included in Appendix A to this report.)
Air -- Under the Texas Clean Air Act, the Texas Natural Resource
Conservation Commission (TNRCC) has jurisdiction over the permissible level of
air contaminant emissions from generating facilities located within the State
of Texas. In addition, the source performance standards of the Environmental
Protection Agency (EPA) promulgated under the Federal Clean Air Act, as
amended (Clean Air Act), which have also been adopted by the TNRCC, are
applicable to generating units, the construction of which commenced after
August 17, 1971. TU Electric's generating units have been built to operate in
compliance with current regulations and emission standards promulgated
pursuant to these Acts; however, due to variations in the quality of the
lignite fuel, operation of certain of the lignite-fueled generating units at
reduced loads is necessary from time to time in order for TU Electric to
maintain compliance with these standards at these units. With these occasional
reduced loads, TU Electric has achieved and continues to achieve material
compliance with the Clean Air Acts' emission standards.
The Clean Air Act includes provisions which, among other things, place
limits on the sulfur dioxide emissions produced by generating units. In
addition to the new source performance standards applicable to sulfur dioxide,
the Clean Air Act required that fossil-fueled plants meet certain sulfur
dioxide emission allowances by 1995 (Phase I), and requires more restrictions
on sulfur dioxide emission allowances by 2000 (Phase II). TU Electric's
generating units were not affected by the Phase I requirements. The
applicable Phase II requirements currently are met by 52 out of 56 of TU
Electric's generating units to which those requirements apply. Because the
sulfur dioxide emissions from the other four units are relatively low and
alternatives are available to enable these units to reduce sulfur dioxide
emissions or utilize compensatory reduction allowances achieved in other
units, material compliance with the applicable Phase II sulfur dioxide
requirements is not expected to have a significant impact on TU Electric.
To meet these sulfur dioxide requirements, the Clean Air Act provides for
the annual allocation of sulfur dioxide emission allowances to utilities.
Under the Clean Air Act, utilities are permitted to transfer allowances within
their own systems and to buy or sell allowances from or to other utilities.
The EPA grants a maximum number of allowances annually to TU Electric based on
the amount of emissions from units in operation during the period 1985 through
1987. TU Electric intends to utilize internal allocation of emission
allowances within its system and, if cost effective, may purchase additional
emission allowances to enable both existing and future electric generating
units to meet the requirements of the Clean Air Act. TU Electric may also
sell excess emission allowances. TU Electric is unable to predict the extent
to which it may generate excess allowances or will be able to acquire
allowances from others if needed but does not anticipate any significant
problems in keeping emissions within its allotted allowances.
TU Electric's generating units meet the nitrogen oxide (NOx) limits
currently required by the Clean Air Act. The TNRCC and the EPA have proposed
rules that will require NOx emission reductions at TU Electric's generating
units in the Dallas-Fort Worth area. Additionally, in 1996, TU Electric
elected for an early opt-in under Phase I related to NOx limits for its
coal-fired generating units. This election locks in NOx limits for these
generating units for a ten-year period. The Clean Air Act also requires
studies, which began in 1991, by the EPA to assess the potential for toxic
emissions from utility boilers. TU Electric is unable to predict either the
results of such studies or the effects of any subsequent regulations.
Recently, the EPA finalized more stringent standards for ambient levels of
34
ozone and fine particulates and issued proposed rules for regional haze. The
impact of these new standards or proposed regional haze rules, if adopted, is
unknown at this time.
In December 1997, the Conference of the Parties of the United Nations
Framework Convention on Climate Change adopted the Kyoto Protocol, which
specifies targets and timetables for certain countries to reduce greenhouse
gas emissions. The Company and TU Electric are unable to predict whether the
Kyoto Protocol will be ratified by the United States Senate and to what
extent, if any, such protocol might impact TU Electric, the Company and its
subsidiaries.
The 1997 session of the Texas legislature directed the TNRCC to develop a
voluntary post-construction state permitting program for older air emission
facilities, including many of TU Electric's generating facilities as well as
certain ENSERCH facilities. All of these facilities, including the so-called
"grandfathered units," are in compliance with state and federal regulations.
In October 1998, TU Electric committed to voluntary permitting of certain
facilities. It is likely that additional proposed legislation will be
introduced during the 1999 session of the Texas legislature that will more
specifically define elements of a voluntary permitting program for these
facilities. At this time, the Company is unable to predict the impact of this
voluntary permitting program on Company operations.
In 1997, the Clean Air Act required some companies to submit Title V
Operating Permit applications for many of their facilities, including TU
Electric's generating plants and certain Fuel Company and ENSERCH facilities.
These companies anticipate the approval of all such permit applications.
Additional Clean Air Act regulations have been proposed and others are
not yet finalized by the EPA. The Company believes that the requirements
necessary to be in compliance with additional regulatory provisions probably
can be met as they are developed. Estimates for the capital requirements
related to the Clean Air Act are included in the Company's and TU Electric's
estimated construction expenditures. Any additional capital expenditures, as
well as any increased operating costs associated with new requirements or
compliance measures, are expected to be recoverable through rates, as similar
costs have been recovered in the past. The Company and TU Electric currently
believe, however, that if the rules and regulations under the Clean Air Act
are adopted as proposed, operating costs that will be incurred under operating
permits, new permit fee structures, capital expenditures associated with
equipment modifications to reduce emissions, or any expenditures on monitoring
equipment, in the aggregate, will not have a materially adverse effect on the
Company and TU Electric's financial position, results of operation or cash
flows.
Water -- The TNRCC, the EPA and the RRC have jurisdiction over water
discharges (including storm water) from all domestic facilities. The
companies' facilities are presently in compliance with applicable state and
federal requirements relating to discharge of pollutants into the water. TU
Electric, ENSERCH, Fuel Company and Mining Company have obtained all required
waste water discharge permits from the TNRCC, the EPA and the RRC for
facilities in operation and have applied for or obtained necessary permits for
facilities under construction. TU Electric, ENSERCH, Fuel Company and Mining
Company believe they can probably satisfy the requirements necessary to obtain
any required permits or renewals.
Other -- Diversion, impoundment and withdrawal of water for cooling and
other purposes are subject to the jurisdiction of the TNRCC. US Electric
segment companies possess all necessary permits for these activities from the
TNRCC for their present operations.
Federal legislation regulating surface mining was enacted in August 1977,
and regulations implementing the law have been issued. Mining Company's
lignite mining operations are currently regulated at the state level by the
RRC,with oversight by the United States Department of the Interior's Office of
Surface Mining, Reclamation and Enforcement. Surface mining permits have
been issued for current Mining Company operations that provide fuel for Big
Brown, Monticello and Martin Lake.
Treatment, storage and disposal of solid and hazardous waste are
regulated at the state level under the Texas Solid Waste Disposal Act (Texas
Act) and at the federal level under the Resource Conservation and Recovery Act
35
of 1976, as amended (RCRA) and the Toxic Substances Control Act (TSCA). The
EPA has issued regulations under the RCRA and TSCA, and the TNRCC and the RRC
have issued regulations under the Texas Act applicable to companies'
facilities. The Company and certain subsidiaries have registered solid waste
disposal sites and have obtained or applied for such permits as are required
by such regulations.
Beginning in 1998, certain TU Electric and Mining Company facilities came
under the jurisdiction of the toxic release inventory requirements of the
Emergency Planning Community Right-To-Know Act (EPCRA) as finalized by the
EPA. Regulatory reporting of toxic releases under EPCRA begins in 1999.
TU Electric
Under the federal Low-Level Radioactive Waste Policy Act of 1980, as
amended, the State of Texas is required to provide, either on its own or
jointly with other states in a compact, for the disposal of all low-level
radioactive waste generated within the state. The State of Texas has agreed
to a compact with the States of Maine and Vermont for a disposal facility that
would be located in Texas. That compact was ratified by Congress and signed
by the President in 1998. The State of Texas has proposed to license a
disposal site in Hudspeth County, Texas, but in October 1998 the TNRCC denied
that license application. No appeal was taken from the denial of the license
application, and that denial is now final. The nature and extent of future
efforts by the State of Texas to provide for a disposal site are presently
uncertain. TU Electric will continue to ship low-level waste material
off-site for as long as an alternative disposal site is available. Should
existing off-site disposal become unavailable, the low-level waste material
will be stored on-site. TU Electric's on-site storage capacity is expected to
be adequate until other off-site facilities become available.
The Company
UK/EUROPE
Eastern Group's businesses are subject to numerous regulatory
requirements with respect to the protection of the environment. The
electricity generation industry in the UK is subject to a framework of
national and EU environmental laws which regulate the construction, operation
and decommissioning of power stations. Under these laws, each power station
operated by Eastern Group is required to have an authorization which regulates
its releases into the environment and seeks to minimize pollution of the
environment taken as a whole, having regard to the best available techniques
not entailing excessive cost. The principal laws that have environmental
implications for Eastern Group are the Electricity Act, the UK Environmental
Protection Act of 1990 and the UK Environment Act of 1995. Eastern Group is
in material compliance with such laws.
AUSTRALIA
Eastern Energy is subject to various Australian federal and Victorian
state environmental regulations, the most significant of which is the
Victorian Environmental Protection Act of 1970 (VEPA). VEPA regulates, in
particular, the discharge of waste into air, land and water, site
contamination, the emission of noise and the storage, recycling and disposal
of solid and industrial waste. VEPA establishes the Environmental Protection
Authority (Authority) and grants the Authority a wide range of powers to
control and prevent environmental pollution. These powers include issuing
approvals for construction of works which may cause noise or emissions to air,
water or land, waste discharge licenses and pollution abatement notices. No
licenses or works approvals from the Authority are currently required for
activities undertaken by Eastern Energy.
TU Australia has carried forward provisions totaling $3.9 million in the
1998 financial statements to cover estimated environmental liabilities. These
liabilities were identified during an independent audit. Liabilities include
the management of hazardous materials and waste, noise and visual pollution
and soil contamination present within the distribution network.
36
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:
Net
Electric Generating
Generating Capability
Units Fuel Source (MW) Percent
----- ---------------------- -------- -------
54 Natural Gas/Oil (a) 11,980 56.9
9 Lignite/Coal 5,825 27.6
2 Nuclear 2,300 10.9
15 Combustion Turbines (b) 975 4.6
------ -----
Total 21,080 100.0
====== =====
<FN>
(a) Twenty-four natural gas units are capable of operating on fuel oil for
short periods when gas supplies are interrupted or curtailed. In addition,
five natural gas units are capable of operating on fuel oil for extended
periods.
(b) Natural gas units leased and operated by TU Electric. Such units are
capable of operating on fuel oil for extended periods.
</FN>
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.
37
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:
Net
Electric Generating
Generating Capability
Plants Fuel Source (MW)(a) Percent
------ ---------------------------------- ------- -------
5 Coal - fired 5,949 87.1
3 Combined cycle gas turbines (CCGT)(b) 835 12.2
2 Combined heat and power plant (CHP) 46 .7
----- -----
Total 6,830 100.0
===== =====
<FN>
(a) In all cases, installed generating capacity is equal to registered
generating capacity except for two units, which have registered generating
capacities of 405 MW and 380 MW, respectively, but installed generating
capacities of 360 MW and 340 MW, respectively..
(b) Includes Eastern Group's approximately 13.5% interest (135 MW)
in a 1,000 MW plant.
</FN>
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.
38
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.
39
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
40
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. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
The Company and TU Electric
None.
41
EXECUTIVE OFFICERS OF THE COMPANY
Positions and Offices Date First Elected to
Presently Held Present Offices
(Current Term Expires (Current Term Expires Business Experience
Name of Officer Age May 8, 1999) May 14, 1999) (Preceding Five Years)
- --------------- --- ---------------------- --------------------- --------------------------
Erle Nye 61 Chairman of the Board May 23, 1997 Chairman ofthe Board and
Chief Executive Chief Executive of the
and Director Company, TU Electric and
ENSERCH; prior thereto,
President and Chief Executive
ofthe Company and Chairman
ofthe Board and Chief
Executive of TU Electric.
David W. Biegler 52 President and Chief August 5, 1997 President and Chief Operating
Operating Officer Officer of the Company, TU
Electric and ENSERCH;
prior thereto, Chairman,
President and Chief
Executive Officer of
ENSERCH.
H. Jarrell Gibbs 61 Vice Chairman of August 5, 1997 Vice Chairman of the Board of
the Board Company and ENSERCH; prior
thereto, President of TU Electric,
prior thereto, Vice President and
and Principal Financial Officer
of the Company.
Michael J. McNally 44 Executive Vice President May 23, 1997 Executive Vice President and Chief
and Chief Financial Officer Financial Officer of the
Company; prior thereto, President,
Transmission Division of TU Electric,
prior thereto, Executive Vice
President of TU Electric,
prior thereto, Principal of
Enron Development Corporation: prior
thereto, Managing Director of
Industrial Services (Enron
Capital and Trade Resources) and
President of Houston Pipe Line Company
and Enron Gas Liquids, Inc.
There is no family relationship between any of the above-named Executive
Officers.
42
PART II
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:
Price Range Dividends Paid
-------------------------------------------- ---------------
Quarter Ended 1998 1997 1998 1997
- ------------- -------------------- -------------------- ------ ------
High Low High Low
-------- -------- -------- --------
March 31 $42.6250 $38.8125 $42.0000 $33.7500 $0.55 $0.525
June 30 42.1250 38.3750 37.0000 31.5000 0.55 0.525
September 30 47.1250 38.4375 36.1875 33.5000 0.55 0.525
December 31 48.0625 43.0000 41.8125 34.1875 0.55 0.525
----- ------
$2.20 $2.100
===== ======
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. 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.
43
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. 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. 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. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
The Company and TU Electric
None.
44
PART III
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:
Other Positions and
Offices Presently Held Date First Elected as Present Principal Occupation or
With TU Electric Director Employment and Principal
(Current Term Expires (Current Term Expires Business (Preceding Five Years),
Name of Director Age in May, 1999) in May, 1999) Other Directorships
- ---------------- ---- ----------------------- --------------------- --------------------------------------
T. L. Baker 53 President, Electric February 20, 1987 President, Electric Service Division of
Service Division TU Electric, Lone Star Gas and
Southwestern Electric Service Company;
prior thereto,
Executive Vice President of TU
Electric; prior thereto, Senior
Vice President of TU Electric.
David W. Biegler 52 President and Chief August 29, 1997 President and Chief Operating Officer
Operating Officer of the Company, TU Electric
and ENSERCH; prior thereto,
Chairman, President and Chief
Executive Officer of
ENSERCH; other directorships:
ENSERCH, Chase Bank of
Texas N.A. and Trinity
Industries, Inc. (railcars,
construction materials and industrial
equipment)
Barbara B. Curry 44 None August 29, 1997 Executive Vice President of TU
Services; prior thereto, Vice
President of TU Services and,
prior thereto, Assistant to the
Chairman of the Company;
other directorship: ENSERCH.
M. S. Greene 53 President, Transmission May 27, 1997 President, Transmission Division of TU
Division Electric; prior thereto,
Executive Vice President of
Fuel Company and Mining
Company.
45
Other Positions and
Offices Presently Held Date First Elected as Present Principal Occupation or
With TU Electric Director Employment and Principal
(Current Term Expires (Current Term Expires Business (Preceding Five Years),
Name of Director Age in May, 1999) in May, 1999) Other Directorships
- ---------------- ---- ----------------------- --------------------- -------------------------------------
Michael J. McNally 44 None February 16, 1996 Executive Vice President and Chief
Financial Officer of the
Company; prior thereto
President, Transmission
Division of TU Electric; prior
thereto Executive Vice
President of TU Electric; prior
thereto, Principal of Enron
Development Corporation;
prior thereto, Managing
Director of Industrial Services
(Enron Capital and Trade
Resources) and President of
Houston Pipe Line Company
and Enron Gas Liquids, Inc.;
other directorship: ENSERCH.
Erle Nye 61 Chairman of the Board September 17, 1982 Chairman of the Board and Chief
and Chief Executive Executive of the Company, TU
Electric and ENSERCH; prior
thereto, President and Chief
Executive of the Company and
Chairman of the Board and
Chief Executive of TU Electric;
other directorships: the
Company and ENSERCH.
W. M. Taylor 56 President, Generation May 20, 1986 President, Generation Division of TU
Division Electric and Executive Vice
President of Mining Company;
prior thereto, Executive Vice
President of TU Electric.
Directors of TU Electric receive no compensation in their capacity as
Directors of TU Electric.
46
Identification of Executive Officers and business experience:
Positions and Offices Date First Elected to
Presently Held Present Office
(Current Term Expires (Current Term Expires Business Experience
Name of Officer Age in May, 1999) in May, 1999) (Preceding Five Years)
- ---------------- ---- ----------------------- --------------------- --------------------------------------
Erle Nye 61 Chairman of the Board February 20, 1987 Chairman of the Board and Chief
and Chief Executive Executive of the Company, TU
Electric and ENSERCH; prior
thereto, President and Chief
Executive of the Company and
Chairman of the Board and
Chief Executive of TU Electric.
David W. Biegler 52 President and Chief January 1, 1998 President and Chief Operating Officer
Operating Officer of the Company, TU Electric
and ENSERCH; prior thereto
Chairman, President and Chief
Executive Officer of
ENSERCH.
T. L. Baker 53 President, Electric February 16, 1996 President, Electric Service Division of
Service Division TU Electric, Lone Star Gas and
Southwestern Electric Service
Company; prior thereto,
Executive Vice President of TU
Electric; prior thereto, Senior
Vice President of TU Electric.
M. S. Greene 53 President, Transmission May 27, 1997 President, Transmission Division of TU
Division Electric; prior thereto,
Executive Vice President of
Fuel Company and Mining
Company.
W. M. Taylor 56 President, Generation February 16, 1996 President, Generation Division of TU
Division Electric and Executive Vice
President of Mining Company;
prior thereto, Executive Vice
President of TU Electric.
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.
47
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:
SUMMARY COMPENSATION TABLE
Long-Term Compensation (4)
-----------------------------------
Annual Compensation Awards Payouts
--------------------------------- ------------------------ --------
Other Restricted Securities All Othe
Annual Stock Underlying LTIP Compen-
Name and Salary Bonus Compen- Awards Options/ Payouts sation
Principal Position Year ($) ($) (3) sation ($) ($) SARs (#) ($) ($) (5)
------------------------- ----- -------- -------- ---------- -------- ---------- -------- ----------
Erle Nye, 1998 818,750 350,000 - 541,250 - 19,674 156,906
Chairman of the Board 1997 760,417 325,000 - 499,375 - 23,928 143,963
and Chief Executive of 1996 723,333 185,000 - 351,500 - 0 117,908
the Company and
TU Electric (1)
David W. Biegler, 1998 617,500 102,500 - 244,250 - 0 174,208
President and Chief 1997 245,833 0 - 0 - 0 0
Operating Officer of 1996 0 0 - 0 - 0 0
the Company and
TU Electric (2)
W. M. Taylor, 1998 360,500 75,000 - 157,800 - 7,733 63,421
President, Generation 1997 339,583 83,000 - 161,750 - 9,343 59,948
Division - TU Electric 1996 312,500 83,500 - 156,625 - 0 49,530
T. L. Baker, 1998 323,083 60,000 - 135,600 - 8,212 62,011
President, Electric 1997 294,583 71,000 - 139,625 - 10,619 56,603
Service Division - 1996 275,833 60,500 - 123,500 - 0 46,319
TU Electric
M. S. Greene, 1998 245,833 50,000 - 106,250 - 5,645 45,875
President, Transmission 1997 233,750 53,000 - 107,000 - 6,609 40,668
Division - TU Electric 1996 220,833 45,000 - 95,625 - 0 34,750
(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
48
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:
49
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
Deferred and Incentive
Compensation Plan Long-Term Incentive Compensation Plan
------------------------------ -----------------------------------------------------------
Number of Performance or Performance or
Shares, Other Period Number of Other Period Estimated Future Payouts
Units or Until Shares, Units Until ------------------------
Other Rights Maturation or Other Maturation or Minimum Maximum
Name (#) or Payout Rights (#) Payout (#) (#)
- ------------------ ------------ ------------- ------------- ------------- -------- ---------
Erle Nye 3,041 5 Years 22,000 3 Years 0 44,000
David W. Biegler 2,254 5 Years 7,000 3 Years 0 14,000
W. M. Taylor 1,316 5 Years 4,000 3 Years 0 8,000
T. L. Baker 1,202 5 Years 4,000 3 Years 0 8,000
M. S. Greene 894 5 Years 0 - 0 0
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
50
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 $125,000 was made to Mr.
Biegler and is included under All Other Compensation in the Summary
Compensation Table. The agreement terminates in August 1999.
As a part of the ENSERCH acquisition, options to purchase the common
stock of ENSERCH which had been granted to various employees of ENSERCH were
converted into options to acquire common shares of the Company. The table
below shows, for each of the named officers, the information specified with
respect to exercised, exercisable and unexercisable options under all existing
stock option plans, converted into shares of the Company's common stock into
which such options became exercisable at the time of the ENSERCH
acquisition.
51
AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES
Number of Securities Value of Unexercised
Underlying Unexercised In-the-Money
Shares Options at Options at
Acquired on Value December 31, 1998 December 31, 1998
Exercise Realized (#) ($)
--------------------------- ----------------------------
Name (#) ($) Exercisable Unexercisable Exercisable Unexercisable
- ---------------- ------------ -------- ----------- ------------- ------------ -------------
Erle Nye 0 0 0 0 0 0
David W. Biegler 26,555 314,033 129,778 0 2,907,112 0
W. M. Taylor 0 0 0 0 0 0
T. L. Baker 0 0 0 0 0 0
M. S. Greene 0 0 0 0 0 0
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.
TEXAS UTILITIES PENSION PLAN TABLE
Years of Service
--------------------------------------------------------------------------
Remuneration 20 25 30 35 40
- ------------- --------- --------- --------- --------- ---------
$ 50,000 $ 14,688 $ 18,360 $ 22,032 $ 25,704 $ 29,376
100,000 29,688 37,110 44,532 51,954 59,376
200,000 59,688 74,610 89,532 104,454 119,376
400,000 119,688 149,610 179,532 209,454 239,376
800,000 239,688 299,610 359,532 419,454 479,376
1,000,000 299,688 374,610 449,532 524,454 599,376
1,400,000 419,688 524,610 629,532 734,454 839,376
1,800,000 539,688 674,610 809,532 944,454 1,079,376
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
52
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.
ENSERCH PENSION PLAN TABLE
Years of Service
-----------------------------------------------------------------------------------------
Remuneration 20 25 30 35 40 45
- ------------- --------- --------- --------- --------- --------- ---------
$ 50,000 $ 12,831 $ 16,039 $ 19,246 $ 22,454 $ 23,704 $ 24,954
100,000 30,331 37,914 45,496 53,079 55,579 58,079
200,000 65,331 81,664 97,996 114,329 119,329 124,329
400,000 135,331 169,164 202,996 236,829 246,829 256,829
800,000 275,331 344,164 412,996 481,829 501,829 521,829
1,000,000 345,331 431,164 517,996 604,329 629,329 654,329
1,400,000 485,331 606,164 727,996 849,329 884,329 919,329
1,800,000 625,331 781,164 937,996 1,094,329 1,139,329 1,184,329
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.
53
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
54
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
55
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
56
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]
1993 1994 1995 1996 1997 1998
----- ----- ----- ----- ----- -----
Texas Utilities 100 81 112 117 126 150
S&P 500 Index 100 101 139 171 228 293
S&P Electric Utility Index 100 86 113 113 143 166
57
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:
Amount and Nature
Name and Address of Beneficial
Title of Class of Beneficial Owner Ownership Percent of Class
- ------------------- ----------------------- ------------------- ----------------
Common stock, Texas Utilities Company 118,714,200 shares 100.0%
without par value, Energy Plaza sole voting and
of TU Electric 1601 Bryan Street investment power
Dallas, Texas 75201
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.
Number of Shares
Name Beneficially Owned Deferred Plan(2) Total
- ----------------- ------------------ ---------------- ---------
T. L. Baker 13,321 20,700 34,021
David W. Biegler 152,867(1) 8,277 161,144
Barbara B. Curry 2,608 6,095 8,703
M. S. Greene 1,332 16,118 17,450
Michael J. McNally 33,138 17,041 50,179
Erle Nye 76,055 63,306 139,361
W. M. Taylor 20,158 23,789 43,947
------- ------- -------
All Directors and Executive
Officers as a group (7) 299,479 155,326 454,805
======= ======= =======
(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.
58
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company
None.
TU Electric
None.
59
PART IV
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.
60
(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:
The Company and TU Electric
Previously Filed*
------------------------
With
File As
Exhibits Number Exhibit
- --------- -------- --------
2(a) 333-12391 2(a) - Amended and Restated Agreement and Plan
of Merger, dated as of April 13, 1996, among
the Company, ENSERCH Corporation and TUC Holding
Company.
3(a) 333-12391 4(a) - Restated Articles of Incorporation of
the Company.
3(b) 333-45657 4(b) - Bylaws, as amended, of the Company.
3(c) 0-11442 4(a) - Restated Articles of Incorporation of
Form 10-Q TU Electric.
(Quarter ended
June 30, 1997)
3(d) 33-64694 4(c) - Bylaws of TU Electric, as amended.
3(e) 1-12833 1 - Rights Agreement, dated as of February 19, 1999,
Form 8-A between the Company and The Bank of New York,
(filed February which includes as Exhibit A thereto the form of
26, 1999) Statement of Resolution Establishing the
Series A Preference Stock, Exhibit B thereto
the form of a Right Certificate and Exhibit C
thereto the Summary of Rights to
Purchase Series A Preference Stock.
4(a) 2-90185 4(a) - Mortgage and Deed of Trust, dated as of
December 1, 1983, between TU Electric and Irving
Trust Company (now The Bank of New York),
Trustee.
4(a)(1) - Supplemental Indentures to Mortgage and Deed of
Trust:
Number Dated
------ -----------
2-90185 4(b) First April 1, 1984
2-92738 4(a)-1 Second September 1, 1984
2-97185 4(a)-1 Third April 1, 1985
2-99940 4(a)-1 Fourth August 1, 1985
2-99940 4(a)-2 Fifth September 1, 1985
33-01774 4(a)-2 Sixth December 1, 1985
33-9583 4(a)-1 Seventh March 1, 1986
61
Previously Filed*
-------------------
With
File As
Exhibits Number Exhibit Number Dated
- --------- -------- -------- -------- --------------
33-9583 4(a)-2 Eighth May 1, 1986
33-11376 4(a)-1 Ninth October 1, 1986
33-11376 4(a)-2 Tenth December 1, 1986
33-11376 4(a)-3 Eleventh December 1, 1986
33-14584 4(a)-1 Twelfth February 1, 1987
33-14584 4(a)-2 Thirteenth March 1, 1987
33-14584 4(a)-3 Fourteenth April 1, 1987
33-24089 4(a)-1 Fifteenth July 1, 1987
33-24089 4(a)-2 Sixteenth September 1, 1987
33-24089 4(a)-3 Seventeenth October 1, 1987
33-24089 4(a)-4 Eighteenth March 1, 1988
33-24089 4(a)-5 Nineteenth May 1, 1988
33-30141 4(a)-1 Twentieth September 1, 1988
33-30141 4(a)-2 Twenty-first November 1, 1988
33-30141 4(a)-3 Twenty-second January 1, 1989
33-35614 4(a)-1 Twenty-third August 1, 1989
33-35614 4(a)-2 Twenty-fourth November 1, 1989
33-35614 4(a)-3 Twenty-fifth December 1, 1989
33-35614 4(a)-4 Twenty-six February 1, 1990
33-39493 4(a)-1 Twenty-seventh September 1, 1990
33-39493 4(a)-2 Twenty-eighth October 1, 1990
33-39493 4(a)-3 Twenty-ninth October 1, 1990
33-39493 4(a)-4 Thirtieth March 1, 1991
33-45104 4(a)-1 Thirty-first May 1, 1991
33-45104 4(a)-2 Thirty-second July 1, 1991
33-46293 4(a)-1 Thirty-third February 1, 1992
33-49710 4(a)-1 Thirty-fourth April 1, 1992
33-49710 4(a)-2 Thirty-fifth April 1, 1992
33-49710 4(a)-3 Thirty-sixth June 1, 1992
33-49710 4(a)-4 Thirty-seventh June 1, 1992
33-57576 4(a)-1 Thirty-eighth August 1, 1992
33-57576 4(a)-2 Thirty-ninth October 1, 1992
33-57576 4(a)-3 Fortieth November 1, 1992
33-57576 4(a)-4 Forty-first December 1, 1992
33-60528 4(a)-1 Forty-second March 1, 1993
33-64692 4(a)-1 Forty-third April 1, 1993
33-64692 4(a)-2 Forty-fourth April 1, 1993
33-64692 4(a)-3 Forty-fifth May 1, 1993
33-68100 4(a)-1 Forty-sixth July 1, 1993
33-68100 4(a)-3 Forty-seventh October 1, 1993
33-68100 4(a)-4 Forty-eighth November 1, 1993
33-68100 4(a)-5 Forty-ninth May 1, 1994
33-68100 4(a)-6 Fiftieth May 1, 1994
33-68100 4(a)-7 Fifty-first August 1, 1994
0-11442 99 Fifty-second April 1, 1995
Form 10-Q
(Quarter ended
March 31, 1995)
62
Previously Filed*
--------------------------
With
File As
Exhibits Number Exhibit Number Dated
- --------- -------- -------- -------- --------------
0-11442 99 Fifty-third June 1, 1995
Form 10-Q
(Quarter ended
June 30, 1995)
0-11442 4 Fifty-fourth October 1, 1995
Form 8-K (Dated
September 26,
1995)
0-11442 4(a) Fifty-fifth March 1, 1996
Form 10-Q
(Quarter ended
March 31, 1996)
0-11442 4(a) Fifty-sixth September 1, 1996
Form 10-Q
(Quarter ended
September 30,
1996)
33-83976 4(g) Fifty-seventh February 1, 1997
0-11442 4(b) Fifty-eighth July 1, 1997
Form 10-Q
(Quarter ended
June 30, 1997)
4(b)(1) - Agreement to furnish certain debt
instruments (the Company).
4(b)(2) - Agreement to furnish certain debt
instruments (TU Electric).
4(c) 33-68104 4(b)-17 - Deposit Agreement between TU
Electric and Chemical Bank,
dated as of August 4, 1993.
4(d) 0-11442 4(e) - Deposit Agreement between TU Electric
Form 10-K and Chemical Bank,
(1993) dated as of October 14, 1993.
4(e) 0-11442 4(f) - Indenture (For Unsecured Subordinated
Form 10-K Debt Securities relating to Trust
(1995) Securities), dated as of December 1, 1995,
between TU Electric and The Bank of New
York, as Trustee.
4(f) 0-11442 4(g) - Amended and Restated Trust Agreement,
Form 10-K dated as of December 12, 1995 between
(1995) TU Electric, as Depositor, and The
Bank of New York, The Bank of New York
(Delaware) and the Administrative
Trustees thereunder as trustees for TU
Electric Capital I.
4(g) 0-11442 4(h) - Guarantee Agreement with respect to
Form 10-K TU Electric Capital I, dated as of
(1995) December 12, 1995, between TU Electric,
as Guarantor, and The Bank of New York,
as Trustee.
4(h) 0-11442 4(i) - Agreement as to Expenses and Liabilities,
Form 10-K dated as of December 12, 1995, between
(1995) TU Electric and TU Electric Capital I.
4(i) 0-11442 4(j) - Officer's Certificate, dated as of December 12,
Form 10-K 1995, establishing the terms of the
(1996) Junior Subordinated Debentures issued in
connection with the preferred securities
of TU Electric Capital I.
4(j) 0-11442 4(m) - Amended and Restated Trust Agreement,
Form 10-K dated as of December 13, 1995, between
(1995) TU Electric, as Depositor, and The Bank
of New York, The Bank of New York
(Delaware), and the Administrative
Trustees thereunder, as Trustees for
TU Electric Capital III.
63
Previously Filed*
--------------------------
With
File As
Exhibits Number Exhibit
- --------- -------- --------
4(k) 0-11442 4(n) - Guarantee Agreement with respect to TU
Form 10-K Electric Capital III, dated as of
(1995) as of December 13, 1995, between TU
Electric, as Guarantor, and The Bank of
New York, as Trustee.
4(l) 0-11442 4(o) - Agreement as to Expenses and Liabilities,
Form 10-K dated as of December 13, 1995, between
(1995) TU Electric and TU Electric Capital III.
4(m) 0-11442 4(r) - Officer's Certificate, dated as of
Form 10-K December 13, 1995, establishing the terms
(1996) of the Junior subordinated Debentures
issued in connection with the preferred
securities of TU Electric Capital III.
4(n) 0-11442 4(s) - Amended and Restated Trust Agreement,
Form 10-K dated as of January 30, 1997, between
(1996) TU Electric, as Depositor, and The Bank
of New York (Delaware), and the
Administrative Trustee as thereunder,
as Trustees for TU Electric Capital IV.
4(o) 0-11442 4(t) - Guarantee Agreement with respect to
Form 10-K TU Electric Capital IV, dated as of
(1996) January 30, 1997, between TU Electric,
as Guarantor and The Bank of New York,
as Trustee.
4(p) 0-11442 4(u) - Agreement as to Expenses and Liabilities,
Form 10-K dated as of January 30, 1997, between
(1996) TU Electric and TU Electric Capital IV.
4(q) 0-11442 4(v) - Officer's Certificate, dated as of
Form 10-K January 30, 1997, establishing the terms
(1996) of the Junior Subordinated Debentures
issued in connection with the preferred
securities of TU Electric Capital IV.
4(r) 0-11442 4(w) - Amended and Restated Trust Agreement,
Form 10-K dated as of January 30, 1997, between
(1996) TU Electric, as Depositor, and The Bank of
of New York (Delaware), and the
Administrative Trustee thereunder, as
Trustees for TU Electric Capital V.
4(s) 0-11442 4(x) - Guarantee Agreement with respect to
Form 10-K TU Electric Capital V, dated as of
(1996) January 30, 1997, between TU Electric,
as Guarantor, and the Bank of New York, as Trustee.
4(t) 0-11442 4(y) - Agreement as to Expenses and Liabilities,
Form 10-K dated as of January 30, 1997, between
(1996) TU Electric and TU Electric Capital V.
4(u) 0-11442 4(z) - Officer's Certificate, dated as of
Form 10-K January 30, 1997, establishing the
(1996) terms of the Junior Subordinated Debentures
issued in connection with the preferred
securities of TU Electric Capital V.
4(v) 333-45999 4(a) - Indenture, dated October 1, 1997,
relating to the Company's 6.20% Series A
Senior Notes and 6.20% Series A Exchange
Notes (together, Series A Notes).
4(w) 333-45999 4(e) - Officers' Certificate establishing
Series A Notes.
4(x) 333-45999 4(b) - Indenture, dated October 1, 1997,
relating to the Company's 6.375% Series B
Senior Notes and 6.375% Series B Exchange
Notes (together, Series B Notes).
4(y) 333-45999 4(f) - Officer's Certificate establishing
Series B Notes.
4(z) 0-12833 4(ff) - Indenture, dated January 1, 1998,
Form 10-K relating to the Company's 6.375% Series
(1997) C Senior Notes and 6.375% Series C
Exchange Notes (together, Series C Notes).
64
Previously Filed*
----------------------
With
File As
Exhibits Number Exhibit
- -------- ----- -------
4(aa) 0-12833 4(hh) - Officers' Certificate establishing
Form 10-K Series C Notes.
(1997)
4(bb) 0-11442 4(a) - Indenture (For Unsecured Debt
Form 10-Q Securities), dated as of August 1, 1997
(Quarter ended between TU Electric and The Bank of
Sept. 30, 1997) New York.
4(cc) 0-11442 4(b) - Officer's Certificate establishing
Form 10-Q the TU Electric 7.17% Debentures
(Quarter ended due August 1, 2007.
Sept. 30, 1997)
4(dd) 0-11422 99(a) - Officer's certificate establishing
Form 10-Q TU Electric's Floating Rate debentures
(Quarter ended due April 24, 2000.
March 31, 1998)
4(ee) 0-12833 4(kk) - Indenture (For Unsecured Debt Securities),
Form 10-K dated as of January 1, 1998,
(1997) between ENSERCH and The Bank of
New York.
4(ff) 0-12833 4(ll) - Officer's Certificate establishing the
Form 10-K ENSERCH 6 1/4 % Series A Notes due
(1997) January 1, 2003.
4(gg) 0-12833 4(mm) - Officer's Certificate establishing the
Form 10-K ENSERCH Remarketed Reset Notes
(1997) due January 1, 2008.
4(hh) 33-45688 4.2 - Indenture, dated February 15, 1992,
between ENSERCH and The First
National Bank of Chicago.
4(ii) 0-12833 4(oo) - ENSERCH 7% Note due 1999,
Form 10-K dated August 18, 1992.
(1997)
4(jj) 0-12833 4(qq) - ENSERCH 6-3/8% Note due 2004,
Form 10-K dated February 1, 1994.
(1997)
4(kk) 0-12833 4(rr) - ENSERCH 7-1/8% Note due 2005,
Form 10-K dated June 6, 1995.
(1997)
4(ll) 1-12833 4(a) - Remarketing Agreement, dated as of
Form 8-K January 30, 1998 and form of
(filed August 28, Remarketing Agreement Supplement with
1998) respect to ENSERCH Remarketed Reset Notes.
4(mm) 1-12833 4(b) - Indenture, (For Unsecured Subordinated
Form 8-K Debt Securities), dated as of June 1,
(filed August 28, 1998, between ENSERCH and The Bank
1998) of New York, as Trustee.
4(nn) 1-12833 4(c) - Officer's Certificate, dated as of July 2,
Form 8-K 1998, establishing the terms of the
(filed August 28, ENSERCH Floating Rate Junior Subordinated
1998) Debentures, issued in connection with the
preferred securities ENSERCH Capital I.
4(oo) 1-12833 4(d) - Amended and Restated Trust Agreement, dated
Form 8-K as of July 2, 1998 between ENSERCH, as
(filed August 28, Depositor, and The Bank of New York, The
1998) Bank of New York (Delaware), and the
Administrative trustees thereunder, as
Trustee.
65
Previously Filed*
-----------------------
With
File As
Exhibits Number Exhibit
- -------- ------ -------
4(pp) 1-12833 4(e) - Guarantee Agreement with respect to
Form 8-K ENSERCH Capital I, dated as of July 2,
(filed August 28, 1998, between ENSERCH, as Guarantor,
1998) and The Bank of New York, as Trustee.
4(qq) 1-12833 4(f) - Agreement as to Expenses and Liabilities,
Form 8-K dated as of July 1, 1998, between ENSERCH
(filed August 28, and ENSERCH Capital I.
1998)
4(rr) 1-12833 4(g) - Indenture (For Unsecured Debt Securities
Form 8-K Series D and Series E), dated as of
(filed August 28, July 1, 1998, between Company and the Bank
1998) New York.
4(ss) 1-12833 4(h) - Officers' Certificate, dated July 22, 1998
Form 8-K establishing the terms of the 6.37% Series
(filed August 28, D Senior Notes and the 6.50% Series E
1998) Senior Notes.
4(tt) 1-12833 4(i) - Purchase Contract Agreement, dated as of
Form 8-K July 1, 1998, between the Company and
(filed August 28, The Bank of New York with respect to the
1998) Company's issuance of Feline PRIDES.
4(uu) 1-12833 4(j) - Pledge Agreement, dated as of July 1,
Form 8-K 1998, among the Company and
(filed August 28, The Chase Manhattan Bank and
1998) The Bank of New York with respect to the
Feline PRIDES.
4(vv) 1-12833 4(a) - Indenture, (For Unsecured Subordinated Debt
Form 8-K Securities), dated as of December 1, 1998,
(filed January 19, between the Company and The Bank of
1999) of New York, as Trustee.
4(ww) 1-12833 4(b) - Officer's Certificate, dated as of
Form 8-K December 30, 1998, establishing the terms
(filed January 19, of the Company's 7-1/4% Junior Subordinated
1999) Debentures, Series A issued in connection
with the preferred securities of TXU
Capital I.
4(xx) 1-12833 4(c) - Amended and Restated Trust Agreement,
Form 8-K dated as of December 30, 1998,
(filed January 19, between the Company, as Depositor, and
1999) The Bank of New York, The Bank of New
York (Delaware), and the Administrative
Trustees thereunder, as Trustees.
66
Previously Filed*
----------------------
With
File As
Exhibits Number Exhibit
- -------- ----- -------
4(yy) 1-12833 4(d) - Guarantee Agreement with respect to TXU
Form 8-K Capital I, dated as of December 30, 1998,
(filed January 19, between the Company, as Guarantor,
1999) and The Bank of New York, as Trustee.
4(zz) 1-12833 4(e) - Agreement as to Expenses and Liabilities,
Form 8-K dated as of December 30, 1998,
(filed January 19, between the Company and TXU Capital I.
1999)
4(aaa) 1-12833 4(a) - Indenture, (For Unsecured Debt Securities
Form 10-Q Series F), dated as October 1, 1998,
(Quarter ended between the Company and The Bank of
September 30, 1998) New York.
4(bbb) 1-12833 4(b) - Officer's Certificate establishing the
Form 10-Q terms of the Company's Mandatory Putable/
(Quarter ended Remarketable Securities (Series F Notes).
September 30, 1998)
4(ccc) 1-12833 4(c) - Remarketing Agreement relating to the
Form 10-Q Series F Notes.
(Quarter ended
September 30, 1998)
4(ddd) 1-12833 4(d) - Indenture (For Unsecured Debt Securities
Form 10-Q Series G), dated as of October 1, 1998,
(Quarter ended between the Company and The Bank of
September 30, 1998) New York.
4(eee) 1-12833 4(e) - Officer's Certificate establishing the
Form 10-Q terms of the Company's Floating Rate
(Quarter ended Senior Notes.
September 30, 1998)
4(fff) 333-8008 and 4.1 - Indenture, dated as of October 16, 1997,
333-8008-1 among Energy Group Overseas B.V. (EGO),
The Energy Group PLC and The Bank of
New York, as Trustee.
4(ggg) 333-8008 and 4.2 - Form of 7.375% Series B Guaranteed note
333-8008-1 of EGO Due 2017.
4(hhh) 333-8008 and 4.3 - Form of 7.500% Series B Guaranteed note
333-8008-1 of EGO Due 2027.
10(a)** 1-3591 10(a) - Deferred and Incentive Compensation Plan
Form 10-Q of the Texas Utilities Company System,
(Quarter ended as amended February 20, 1998.
June 30, 1995)
10(b)** 1-3591 10(f) - Salary Deferral Program of the Texas
Form 10-Q Utilities Company System as amended
(Quarter ended February 20, 1998.
June 30, 1995)
67
Previously Filed*
--------------------------
With
File As
Exhibits Number Exhibit
10(c)** 1-3591 10(c) - Restated Supplemental Retirement Plan
Form 10-Q for Employees of the Texas Utilities
(Quarter ended Company System, as restated effective
June 30, 1995) January 1, 1995.
10(d)** 1-3591 10(b) - Deferred Compensation Plan for Outside
Form 10-Q Directors of the Company, effective
(Quarter ended as of July 1, 1995.
June 30, 1995)
10(e)** 1-3591 10(d) - Long-Term Incentive Plan of the
Form 10-Q Texas Utilities Company System, dated as
(Quarter ended of May 19, 1995.
June 30, 1995)
10(f)** 1-3591 10(e) - Management Transition Agreement, dated
Form 10-Q as of May 19, 1995 between the Company
(Quarter ended and J.S. Farrington.
June 30, 1995)
10(g)** - Description of Compensatory Arrangement
with Derek Bonham.
10(h) - 364 Day Amended and Restated Competitive
Advance and Revolving Credit Facility
Agreement, dated as of May 28, 1998 as
amended and restated as of February 26,
1999, among Texas Utilities Company,
Texas Utilities Electric Company,
ENSERCH Corporation, Chase Bank of Texas,
National Association, as Administrative
Agent and certain banks listed therein
and The Chase Manhattan Bank, as
Competitive Advance Facility Agent
(US Facility A).
10(i) l-2833 (b)(2) - 5-Year Competitive Advance and Revolving
Schedule 14D-1 Credit Facility Agreement dated as of
(filed March 10. March 2, 1998 among Texas Utilities
1998) Company, Texas Utilities Electric Company,
ENSERCH Corporation, The Chase Manhattan
Bank, as Competitive Advance Facility Agent
and Chase Bank of Texas, National
Association, as Administrative Agent and
certain banks listed therein (US Facility
B).
10(j) l-12833 (b)(3) - Amendment No. 1, dated March 3, 1998, to
Schedule 14D-1 US Facility A and US Facility B.
(filed March 10,
1998)
10(k) 1-12833 10(a) - Facilities Agreement for Credit Facilities
Form 10-Q dated March 2, 1998, as amended through
(Quarter ended July 16, 1998, among TU Finance (No. 1)
September 30, Limited, TU Finance (No. 2) Limited,
1998) TU Acquisitions PLC and Chase Manhattan plc,
Lehman Brothers International and Merrill
Lyncy Capital Corporation as Joint Lead
Arrangers, and The Chase Manhattan Bank,
Lehman Commercial Paper Inc. and Merrill
Lynch Capital Corporation as Underwriters.
10(l) 1-12833 10(b) - Guarantee and Debenture, dated May 19,
Form 10-Q 1998, among TU Finance (No. 1) Limited and
(Quarter ended certain of its subsidiaries (as Charging
September 30, Companies) and Chase Manhattan International
1998) Limited (as Security Agent).
68
Previously Filed*
---------------------
With
File As
Exhibits Number Exhibit
- -------- ------ -------
10(m) 1-1283310 10(c) - Share Charge, dated May 19, 1998, between
Form 10-Q TU Finance (No. 2) Holdings, Inc. (as
(Quarter ended Chargor) and Chase Manhattan International
September 30, 1998) Limited (as Security Agent).
12(a) - Computation of Ratio of Earnings to Fixed
Charges and to Fixed Charges and Preferred
Dividends for the Company.
12(b) - Computation of Ratio of Earnings to Fixed
Charges and to Fixed Charges and Preferred
Dividends for TU Electric.
21 - Subsidiaries of the Company.
23(a) - Consent of Counsel to the Company.
23(b) - Consent of Counsel to TU Electric.
23(c) - Consent of Deloitte & Touche, Independent
Auditors' for the Company.
23(d) - Consent of Deloitte & Touche Independent
Auditors' for TU Electric.
23(e) - Consent of PricewaterhouseCoopers,
Independent Auditors for Eastern Group.
27(a) - Financial Data Schedule for the Company.
27(b) - Financial Data Schedule for TU Electric.
99(a) 1-3591 28(b) - Agreement, dated as of February 12, 1988,
Form 10-K between TU Electric and Texas Municipal
(1987) Power Agency.
99(b) 33-55408 99(a) - Agreement, dated as of July 5, 1988,
between TU Electric and Electric and
Tex-La Electric Cooperative of Texas, Inc.
99(c) 33-23532 4(c)(I) - Trust Indenture, Security Agreement and
Mortgage, dated as of December 1, 1987, as
supplemented by Supplement No. 1 thereto
dated as of May 1, 1988 among the Lessor,
TU Electric and the Trustee.
99(d) 33-24089 4(c)-1 - Supplement No. 2 to Trust Indenture,
Security Agreement and Mortgage, dated
as of August 1, 1988.
99(e) 33-24089 4(e)-1 - Supplement No. 3 to Trust Indenture,
Security Agreement and Mortgage, dated
as of August 1, 1988.
99(f) 0-11442 99(c) - Supplement No. 4 to Trust Indenture,
Form 10-Q Security Agreement and Mortgage, including
(Quarter ended) form of Secured Facility Bond, 1993 Series.
June 30, 1993)
99(g) 33-23532 4(d) - Lease Agreement, dated as of December 1,
1987 between the Lessor and TU Electric
as supplemented by Supplement No. 1
thereto dated as of May 20, 1988 between
the Lessor and TU Electric.
99(h) 33-24089 4(f) - Lease Agreement Supplement No. 2, dated
as of August 18, 1988.
99(i) 33-24089 4(f)-1 - Lease Agreement Supplement No. 3, dated
as of August 25, 1988.
99(j) 33-63434 4(d)(iv) - Lease Agreement Supplement No. 4, dated
as of December 1, 1988.
99(k) 33-63434 4(d)(v) - Lease Agreement Supplement No. 5, dated
as of June 1, 1989.
69
Previously Filed*
---------------------
With
File As
Exhibits Number Exhibit
- -------- ------- -------
99(l) 0-11442 99(d) - Lease Agreement Supplement No. 6, dated
Form 10-Q as of July 1, 1993.
(Quarter ended
June 30, 1993)
99(m) 33-23532 4(e) - Participation Agreement dated as of
December 1, 1987, as amended by a
Consent to Amendment of the Participation
Agreement, dated as of May 20, 1988, each
among the Lessor, the Trustee, the Owner
Participant, certain banking institutions,
Capcorp, Inc. and TU Electric.
99(n) 33-24089 4(g) - Consent to Amendment of the Participation
Agreement, dated as of August 18, 1988.
99(o) 33-24089 4(g)-1 - Supplement No. 1 to the Participation
Agreement, dated as of August 18, 1988.
99(p) 33-24089 4(g)-2 - Supplement No. 2 to the Participation
Agreement, dated as of August 18, 1988.
99(q) 33-63434 4(e)(v) - Supplement No. 3 to the Participation
Agreement, dated as of December 1, 1988.
99(r) 0-11442 99(e) - Supplement No. 4 to the Participation
Form 10-Q Agreement, dated as of June 17, 1993.
(Quarter ended
June 30, 1993)
99(s) 0-11442 4(b) - Supplement No. 1, dated October 25, 1995,
Form 10-Q to Trust Indenture, Security Agreement and
(Quarter ended and Mortgage, dated as of December 1, 1989,
March 31, 1996) among the Owner Trustee, TU Electric and
the Indenture Trustee.
99(t) 0-11442 4(c) - Supplement No. 1, dated October 19, 1995,
Form 10-Q to Amended and Restated Participation
(Quarter ended Agreement, dated as of November 28, 1989,
March 31, 1996) among the Owner Trustee, The First National
Bank of Chicago, As Original Indenture
Trustee, the Indenture Trustee, the Owner
Participant, Mesquite Power Corporation and
TU Electric.
99(aa) 1-12833 99(a) - Facility Agreement for pound 250,000,000
Form 10-Q Revolving Credit Facility, dated May 21,
(Quarter ended 1998, among Eastern Electricity plc, and
September 30, 1998) and Chase Manhattan plc, Lehman Brothers
International and Merrill Lynch Capital
Corporation as Joint Lead Arrangers,
and The Chase Manhattan Bank, Lehman
Commercial Paper Inc. and Merrill Lynch
Capital Corporation as Underwriters.
99(bb) - Syndicated Facilities Agreement, dated
February 24, 1999, among TU Australia
Holdings (Partnership) Limited Partnership
(the Partnership), certain of its Australia
affiliates (Borrowers) and The Bank of
America National Trust and Savings
Association, Deutsche Australia Limited,
National Australia Bank Limited, Toronto
Dominion Australia Limited and the other
Banks named therein (Banks).
99(cc) - Security Trust Deed, dated February 24,
1999, among the Partnership, the Borrowers,
the Company and the Banks.
99(dd) 1-14576 3.10 - Deed of Assignment of Rents, dated as of
Form 20-F October 28, 1996,
dated January 27, among Eastern Merchant Properties Limited
1997 (EMPL), Eastern Group Finance Limited,
Barclays Bank PLC (as agent) and the banks
listed therein.
70
Previously Filed*
---------------------
With
File As
Exhibits Number Exhibit
- -------- ----- -------
99(ee) 1-14576 3.11 - Standby Credit Facility Agreement, dated
Form 20-F, as of October 28, 1996, among EMPL and
dated January Eastern Merchant Generation Limited (EMGL)
27, 1997 (as borrowers), Eastern Group plc (Eastern)
and Eastern Generation Limited (EGL)
(as guarantors), Eastern Electricity plc (EE),
The Industrial Bank of Japan, Limited
(as arranger and agent), The Bank of Nova
Scotia, the Dai-ichi Kangyo Bank, Limited,
The Royal Bank of Scotland plc and Societe
Generale (as co-arrangers), and the
financial institutions listed therein.
99(ff) 1-14576 3.12 - Guarantee and Indemnity Deed, dated
Form 20-F, as of October 28, 1996, among Eastern,
dated January 27, EGL, EE, Barclays Bank PLC, Barclays
1997 De Zoete Wedd Limited, and the other
banks listed therein.
99(gg) 1-14576 3.13 - Deferred Premium Settlement Deed, dated
Form 20-F, as of October 28, 1996 among EPML, EMGL,
dated January 27, EE, The Industrial Bank of Japan, Limited
1997 (as arranger and agent) and the banks and
the participants listed therein.
<FN>
- ------------------------
* Incorporated herein by reference.
** Management contract or compensation plan or arrangement required to be
filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.
</FN>
71
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.
Signature Title Date
--------- ----- ----
/s/ ERLE NYE Principal Executive
- --------------------------------- Officer and Director
(Erle Nye, Chairman of the
Board and Chief Executive)
/s/ MICHAEL J. McNALLY Principal Financial Officer
- ---------------------------------
(Michael J. McNally, Executive
Vice President and Chief Financial
Officer)
/s/ JERRY W. PINKERTON Principal Accounting Officer
- ---------------------------------
(Jerry W. Pinkerton, Controller)
/s/ D. C. BONHAM Director
- ---------------------------------
(D. C. Bonham)
/s/ J. S. FARRINGTON Director
- ---------------------------------
(J. S. Farrington)
/s/ WILLIAM M. GRIFFIN Director March 22, 1999
- ---------------------------------
(William M. Griffin)
/s/ KERNEY LADAY Director
- ---------------------------------
(Kerney Laday)
/s/ MARGARET N. MAXEY Director
- ---------------------------------
(Margaret N. Maxey)
/s/ JAMES A. MIDDLETON Director
- ---------------------------------
(James A. Middleton)
/s/ J. E. OESTERREICHER Director
- ---------------------------------
(J. E. Oesterreicher)
/s/ CHARLES R. PERRY Director
- ---------------------------------
(Charles R. Perry)
/s/ HERBERT H. RICHARDSON Director
- ---------------------------------
(Herbert H. Richardson)
72
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.
Signature Title Date
--------- ----- ----
/s/ ERLE NYE Principal Executive
- --------------------------------- Officer
(Erle Nye, Chairman of the
Board and Chief Executive)
/s/ KIRK R. OLIVER Principal Financial Officer
- ---------------------------------
(Kirk R. Oliver, Treasurer and
Assisitant Secretary)
/s/ JERRY W. PINKERTON Principal Accounting Officer
- ---------------------------------
(Jerry W. Pinkerton, Controller)
/s/ T. L. BAKER Director
- ---------------------------------
(T. L. Baker)
/s/ DAVID BIEGLER Director
- ---------------------------------
(David Biegler)
/s/ BARBARA B. CURRY Director March 22, 1999
- ---------------------------------
(Barbara B. Curry)
/s/ M. S. GREENE Director
- ---------------------------------
(M. S. Greene)
/s/ MICHAEL J. McNALLY Director
- ---------------------------------
(Michael J. McNally)
/s/ W. M. TAYLOR Director
- ---------------------------------
(W. M. Taylor)
73
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
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
SELECTED FINANCIAL DATA
CONSOLIDATED FINANCIAL STATISTICS
Year Ended December 31,
---------------------------------------------------
1998 1997 1996 1995 1994
---- ---- ---- ---- ----
(Millions of Dollars, except ratios and per share amounts)
Total assets - end of year. . . . . . . . . . . . . . . . . . . . . . . . $39,514 $24,864 $21,376 $21,536 $20,893
Property, plant & equipment - gross - end of year . . . . . . . . . . . . $31,946 $26,578 $24,931 $24,912 $24,206
Accumulated depreciation and amortization - end of year . . . . . . 8,243 7,171 6,497 5,858 5,228
Reserve for regulatory disallowances - end of year. . . . . . . . . 836 836 836 1,308 1,308
Construction expenditures (including allowance for
funds used during construction). . . . . . . . . . . . . . . . 1,173 586 434 434 444
Capitalization - end of year
Long-term debt, less amounts due currently. . . . . . . . . . . . . $15,133 $8,759 $ 8,668 $ 9,175 $ 7,888
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) . . . . . . . . . . . . 1,193 875 381 381 -
Preferred stock of subsidiaries:
Not subject to mandatory redemption. . . . . . . . . . . . . . . 190 304 465 490 870
Subject to mandatory redemption. . . . . . . . . . . . . . . . . 21 21 238 263 388
Common stock equity . . . . . . . . . . . . . . . . . . . . . . . . 8,246 6,843 6,033 5,732 6,490
------- ------- ------- ------- -------
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . $24,783 $16,802 $15,785 $16,041 $15,636
======= ======= ======= ======= =======
Capitalization ratios - end of year (a)
Long-term debt, less amounts due currently. . . . . . . . . . . . . 61.1% 52.1% 54.9% 57.2% 50.5%
Trust securities. . . . . . . . . . . . . . . . . . . . . . . . . . 4.8 5.2 2.4 2.4 -
Preferred stock of subsidiaries . . . . . . . . . . . . . . . . . . .8 2.0 4.5 4.7 8.0
Common stock equity . . . . . . . . . . . . . . . . . . . . . . . . 33.3 40.7 38.2 35.7 41.5
------- ------- ------- ------- -------
Total. . . . . . . . . . . . . . . . . . . . . . . . . 100.0% 100.0% 100.0% 100.0% 100.0%
======= ======= ======= ======= =======
Embedded interest cost on long-term debt - end of year. . . . . . . . . . 7.7% 7.9% 8.1% 8.4% 8.7%
Embedded distribution cost on trust securities - end of year. . . . . . . 8.0% 8.3% 8.7% 8.6% -%
Embedded dividend cost on preferred stock of subsidiaries - end
of year (b). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9.4% 9.2% 7.5% 7.4% 7.5%
Net income (loss) . . . . . . . . . . . . . . . . . . . . . . . . . . . . $740 $660 $754 $(139) $543
Dividends declared on common stock. . . . . . . . . . . . . . . . . . . . $597 $496 $456 $635 $696
Common stock data
Shares outstanding - average (in millions). . . . . . . . . . . . . 265 231 225 226 226
Shares outstanding - end of year (in millions). . . . . . . . . . . 282 245 225 226 226
Basic earnings (loss) per share . . . . . . . . . . . . . . . . . . $2.79 $2.86 $3.35 $(0.61) $2.40
Diluted earnings (loss) per share . . . . . . . . . . . . . . . . . $2.79 $2.85 $3.35 $(0.61) $2.40
Dividends declared per share. . . . . . . . . . . . . . . . . . . . $2.225 $2.125 $2.025 $2.81 $3.08
Book value per share - end of year. . . . . . . . . . . . . . . . . $29.21 $27.90 $26.86 $25.38 $28.74
Return on average common stock equity . . . . . . . . . . . . . . . 9.8% 10.3% 12.8% (2.3)% 8.3%
Ratio of earnings to fixed charges. . . . . . . . . . . . . . . . . . . . 1.84 2.14 2.18 0.72 1.88
<FN>
(a) Including the effect of restricted cash pledged against future lease
obligations that is included in other investments (See Note 15 to Consolidated
Financial Statements), the capitalization ratio consisted at December 31, 1998
of 59.1% long-term debt, 34.9% common stock equity, 5.1% trust securities and
0.9% preferred stock.
(b) Includes the unamortized balance of the loss on reacquired preferred stock
and associated amortization. The embedded dividend cost excluding the
effects of the loss on reacquired preferred stock is 5.9% for 1998, 6.6% for
1997, 6.8% for 1996, and 6.9% for 1995.
</FN>
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.
A-2
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
CONSOLIDATED OPERATING STATISTICS
Year Ended December 31,
-------------------------------------------------------
1998 1997 1996 1995 1994
------- ------- ------- ------- -------
SALES VOLUMES
Electric energy sales (gigawatt hours - GWh)
Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . 47,593 36,377 35,855 31,284 30,460
Commercial and industrial. . . . . . . . . . . . . . . . . . . . . 79,786 61,337 59,863 55,239 53,847
Other electric utilities . . . . . . . . . . . . . . . . . . . . . 4,261 4,499 4,626 3,580 4,319
------- ------- ------- ------ ------
Total electric energy sales . . . . . . . . . . . . . . . . . 131,640 102,213 100,344 90,103 88,626
======= ======= ======= ====== ======
Gas distribution (billion cubic feet - Bcf)
Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . 98 33 - - -
Commercial and industrial. . . . . . . . . . . . . . . . . . . . . 104 24 - - -
------- ------- ------- ------ ------
Total gas distribution. . . . . . . . . . . . . . . . . . . . 202 57 - - -
------- ------- ------- ------ ------
Pipeline transportation (Bcf) . . . . . . . . . . . . . . . . . . . . 599 255 - - -
Gas liquids (million barrels) . . . . . . . . . . . . . . . . . . . . 6 3 - - -
US energy marketing
Gas (Bcf). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,115 292 - - -
Electric (GWh) . . . . . . . . . . . . . . . . . . . . . . . . . . 16,268 - - - -
UK wholesale energy sales
Gas (Bcf). . . . . . . . . . . . . . . . . . . . . . . . . . . . . 148 - - - -
Electric (GWh) . . . . . . . . . . . . . . . . . . . . . . . . . . 51,060 - - - -
OPERATING REVENUES (millions)
Electric
Residential. . . . . . . . . . . . . . . . . . . . . . . . . . . . $3,242 $2,248 $2,252 $1,920 $1,862
Commercial and industrial. . . . . . . . . . . . . . . . . . . . . 3,546 2,357 2,370 2,110 2,063
Other electric utilities . . . . . . . . . . . . . . . . . . . . . 125 139 146 118 156
Fuel revenue (including over/under-recovered). . . . . . . . . . . . . 1,788 1,696 1,671 1,418 1,514
Transmission service revenues. . . . . . . . . . . . . . . . . . . . . 126 114 - - -
Other operating revenues . . . . . . . . . . . . . . . . . . . . . . . 538 108 112 73 69
------- ------- ------- ------ ------
Total electric operating revenues. . . . . . . . . . . . . 9,365 6,662 6,551 5,639 5,664
Gas distribution
Residential . . . . . . . . . . . . . . . . . . . . . . . . . . . 573 206 - - -
Commercial and industrial . . . . . . . . . . . . . . . . . . . . 370 124 - - -
Pipeline transportation. . . . . . . . . . . . . . . . . . . . . . . . 121 57 - - -
Gas liquids. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 64 37 - - -
US energy marketing. . . . . . . . . . . . . . . . . . . . . . . . . . 3,198 859 - - -
UK wholesale energy sales. . . . . . . . . . . . . . . . . . . . . . . 1,198 - - - -
Telecommunications . . . . . . . . . . . . . . . . . . . . . . . . . . 114 12 - - -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 191 44 - - -
Less intercompany revenues . . . . . . . . . . . . . . . . . . . . . . (458) (55) - - -
------- ------- ------- ------ ------
Total operating revenues . . . . . . . . . . . . . . . . . $ 14,736 $ 7,946 6,551 5,639 $ 5,664
======= ======= ======= ====== ======
CUSTOMERS (end of year - in thousands)
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,255 2,972 2,913 2,852 2,330
Gas. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,156 1,355 - - -
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.
A-3
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
SELECTED FINANCIAL DATA
CONSOLIDATED FINANCIAL STATISTICS
Year Ended December 31,
-------------------------------------------------------
1998 1997 1996 1995 1994
------- ------ ------ ------ -------
(Millions of Dollars, except ratios)
Total assets - end of year . . . . . . . . . . . . . . . . . . . . . . $18,405 $18,824 $18,795 $19,003 $19,447
Electric plant - gross - end of year . . . . . . . . . . . . . . . . . $23,583 $23,132 $22,664 $22,748 $23,063
Accumulated depreciation and amortization - end of year. . . . . . 7,338 6,576 5,963 5,371 4,765
Reserve for regulatory disallowances - end of year . . . . . . . . 836 836 836 1,308 1,308
Construction expenditures (including allowance for
funds used during construction). . . . . . . . . . . . . . . . 501 446 377 407 415
Capitalization - end of year
Long-term debt, less amounts due currently . . . . . . . . . . . . $ 5,208 $5,476 $ 6,311 $ 7,212 $ 7,221
TU Electric obligated, mandatorily redeemable, preferred
securities of subsidiary trusts holding solely junior
subordinated debentures of TU Electric (trust securities) . . . 823 875 381 381 -
Preferred stock:
Not subject to mandatory redemption . . . . . . . . . . . . . . 115 129 465 490 870
Subject to mandatory redemption . . . . . . . . . . . . . . . . 21 21 238 263 388
Common stock equity. . . . . . . . . . . . . . . . . . . . . . . . 6,495 6,298 6,106 5,800 6,114
------- ------- ------- ------- -------
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $12,662 $12,799 $13,501 $14,146 $14,593
======= ======= ======= ======= =======
Embedded interest cost on long-term debt - end of year . . . . . . . . 8.3% 8.3% 8.3% 8.4% 8.7%
Embedded distribution cost on trust securities - end of year . . . . . 8.4% 8.3% 8.7% 8.6% -%
Embedded dividend cost on preferred stock - end of year* . . . . . . . 13.5% 14.1% 7.5% 7.4% 7.5%
Net income available for common stock. . . . . . . . . . . . . . . . . $785 $745 $809 $368 $556
Dividends declared on common stock . . . . . . . . . . . . . . . . . . - $137 $503 $682 $716
Ratio of earnings to fixed charges . . . . . . . . . . . . . . . . . . 3.2 2.9 3.0 2.0 2.5
Ratio of earnings to combined fixed charges and preferred
dividends. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 2.7 2.6 1.7 2.0
Return on average common stock equity. . . . . . . . . . . . . . . . . 12.3% 12.0% 13.6% 6.2% 9.2%
<FN>
* Includes the unamortized balance of the loss on reacquired preferred stock
and associated amortization. The embedded dividend cost excluding the
effects of the loss on reacquired preferred stock is 6.7% for 1998, 6.9% for
1997, 6.8% for 1996 and 6.9% for 1995.
</FN>
A-4
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED OPERATING STATISTICS
Year Ended December 31,
1998 1997 1996 1995 1994
------ ------ ------ ------ ------
ELECTRIC ENERGY GENERATED AND
PURCHASED (GWh)
Generated - net station output. . . . . . . . . . . . . . . 97,574 91,298 88,130 83,876 81,321
Purchased and net interchange . . . . . . . . . . . . . . . 11,271 11,443 12,418 10,684 11,663
------- ------- ------- ------ ------
Total generated and purchased. . . . . . . . . . . . . . . 108,845 102,741 100,548 94,560 92,984
Company use, losses and unaccounted for . . . . . . . . . . . 6,484 6,161 5,805 5,532 5,131
------- ------- ------- ------ ------
Total electric energy sales. . . . . . . . . . . . . . . . 102,361 96,580 94,743 89,028 87,853
======= ======= ======= ====== ======
ELECTRIC ENERGY SALES (GWh)
Residential . . . . . . . . . . . . . . . . . . . . . . . . . 36,830 33,530 33,039 30,716 30,066
Commercial. . . . . . . . . . . . . . . . . . . . . . . . . . 29,332 27,323 26,456 25,553 24,816
Industrial. . . . . . . . . . . . . . . . . . . . . . . . . . 25,125 24,609 24,215 23,302 22,984
Government and municipal. . . . . . . . . . . . . . . . . . . 6,525 6,039 5,929 5,616 5,505
------- ------- ------- ------ ------
Total general business . . . . . . . . . . . . . . . . . . 97,812 91,501 89,639 85,187 83,371
Other electric utilities. . . . . . . . . . . . . . . . . . . 4,549 5,079 5,104 3,841 4,482
------- ------- ------- ------ ------
Total electric energy sales. . . . . . . . . . . . . . . . 102,361 96,580 94,743 89,028 87,853
======= ======= ======= ====== ======
OPERATING REVENUES (millions)
Base rate revenues
Residential. . . . . . . . . . . . . . . . . . . . . . . . $2,157 $1,991 $1,994 $1,875 $1,833
Commercial . . . . . . . . . . . . . . . . . . . . . . . . 1,307 1,235 1,227 1,194 1,165
Industrial . . . . . . . . . . . . . . . . . . . . . . . . 583 582 590 586 586
Government and municipal . . . . . . . . . . . . . . . . . 317 293 291 280 277
------- ------- ------- ------ ------
Total general business. . . . . . . . . . . . . . . . 4,364 4,101 4,102 3,935 3,861
Other electric utilities . . . . . . . . . . . . . . . . . 138 164 166 133 163
------- ------- ------- ------ ------
Total base rate revenues. . . . . . . . . . . . . . . 4,502 4,265 4,268 4,068 4,024
Fuel revenue (including over/under-recovered). . . . . . . . 1,798 1,707 1,679 1,422 1,521
Transmission service revenues. . . . . . . . . . . . . . . . 126 114 - - -
Other operating revenues . . . . . . . . . . . . . . . . . . 62 49 83 70 68
------- ------- ------- ------ ------
Total operating revenues . . . . . . . . . . . . $6,488 $6,135 $6,030 $5,560 $5,613
======= ======= ======= ====== ======
ELECTRIC CUSTOMERS (end of year - in thousands)
Residential. . . . . . . . . . . . . . . . . . . . . . . . . 2,206 2,152 2,110 2,061 2,019
Commercial . . . . . . . . . . . . . . . . . . . . . . . . . 244 237 230 225 220
Industrial . . . . . . . . . . . . . . . . . . . . . . . . . 21 21 21 21 21
Government and municipal . . . . . . . . . . . . . . . . . . 31 31 30 30 29
------- ------- ------- ------ ------
Total electric customers . . . . . . . . . . . . . . . . . 2,502 2,441 2,391 2,337 2,289
======= ======= ======= ====== ======
RESIDENTIAL STATISTICS (excludes master-metered
customers, kilowatt hour ( kWh) sales, and revenues)
Average annual kWh per customer . . . . . . . . . . . . . . . 16,170 15,026 15,100 14,336 14,236
Average revenue per kWh (in cents). . . . . . . . . . . . . . 7.83 7.85 7.91 8.08 8.26
Industrial classification includes service to Alcoa-Sandow:
Electric energy sales (GWh) . . . . . . . . . . . . . . . . . 3,779 3,820 3,842 3,765 3,886
Operating revenues (millions) . . . . . . . . . . . . . . . . $40 $47 $47 $48 $55
<FN>
Certain previously reported operating statistics have been reclassified to
conform to current classifications.
</FN>
A-5
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
A-6
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
A-7
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:
Issuances Retirements
--------- -----------
The Company:
TXU Capital I 7.25% Trust Securities. . . . . . . . . . . . $ 230 $ -
Floating rate senior notes. . . . . . . . . . . . . . . . . 125 -
6.375% Senior Notes . . . . . . . . . . . . . . . . . . . . 200 -
Equity-linked securities (6.37% to 6.50%) . . . . . . . . . 700 -
5.94% mandatory putable/remarketable securities . . . . . . 375 -
TU Electric:
$8.20 Series Preferred Stock. . . . . . . . . . . . . . . - 14
Capital II 9.00% Series Trust Securities. . . . . . . . . - 47
Long-term Debt:
Brazos River Authority Pollution Control Bonds . . . . 79 79
First Mortgage Bonds . . . . . . . . . . . . . . . . . - 842
Floating Rate Debentures. . . . . . . . . . . . . . . . . 350 -
Other. . . . . . . . . . . . . . . . . . . . . . . . . . - 3
ENSERCH:
Capital I Trust Securities. . . . . . . . . . . . . . . . 150 -
Series E Preferred Stock. . . . . . . . . . . . . . . . . - 100
6.375% Convertible Debentures * . . . . . . . . . . . . . - 88
8.875% Senior Notes . . . . . . . . . . . . . . . . . . . - 100
6.25% Series A Notes. . . . . . . . . . . . . . . . . . . 125 -
Remarketable Reset Notes. . . . . . . . . . . . . . . . . 125 -
Eastern Group:
Acquisition and Interim Facilities. . . . . . . . . . . . 3,429 2,183
Other . . . . . . . . . . . . . . . . . . . . . . . . . . 113 306
All Other Subsidiaries - Long-term Debt. . . . . . . . . . . 118 86
------- -------
Total. . . . . . . . . . . . . . . . . . . . . . $ 6,119 $ 3,848
======= =======
<FN>
*In March 1998, holders of $3 million principal amount of ENSERCH Convertible
Debentures converted such debentures into shares of TUC common stock, and
the remaining $88 million principal amount was redeemed by ENSERCH at par for
cash.
</FN>
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
A-8
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.
A-9
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.
A-10
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.
Expected Maturity Date
---------------------------------------------------------------
1998 1997
There- Fair Fair
1999 2000 2001 2002 2003 after Total Value Value
------ ------ ------ ------ ------- ------ -------- ------- ------
The Company
Long-term Debt
(including current maturities)
Fixed Rate . . . . . . . . . . . . . . . $1,052 $1,353 $ 544 $ 503 $ 922 $6,944 $11,318 $11,912 $7,932
Average interest rate . . . . . . . . 7.86% 6.66% 7.43% 7.73% 6.64% 7.36% 7.29% - -
Variable Rate . . . . . . . . . . . . . $ 121 $ 816 $ 296 $ 40 $1,325 $ 905 $ 3,503 $ 3,503 $2,000
Average interest rate . . . . . . . . 5.16% 5.96% 5.42% 8.59% 6.46% 5.01% 5.86% - -
Interest Rate Swaps
(notional amounts)
Variable to Fixed. . . . . . . . . . . . $ 9 $ 220 $ 86 $ 196 $ 851 $ 912 $ 2,274 $ (132) $ (57)
Average pay rate. . . . . . . . . . . 8.45% 5.75% 6.77% 8.45% 6.60% 6.54% 6.67% - -
Average receive rate . . . . . . . . . 5.20% 5.49% 5.01% 5.20% 5.44% 5.65% 5.49% - -
Fixed to Variable . . . . . . . . . . . - - - - $ 350 $ 165 $ 515 $ 46 $ 6
Average pay rate. . . . . . . . . . . - - - - 5.70% 4.72% 5.39% - -
Average receive rate. . . . . . . . . - - - - 6.89% 8.38% 7.37% - -
TU Electric
Long-term Debt
(including current maturities)
Fixed Rate . . . . . . . . . . . . . . . $ 533 $ 509 $ 226 $ 374 $ 318 $3,032 $ 4,992 $ 5,296 $ 5,563
Average interest rate . . . . . . . . 8.44% 5.83% 7.49% 8.22% 6.91% 7.44% 7.41% - -
Variable Rate. . . . . . . . . . . . . . - - - - - $ 749 $ 749 $ 749 $ 1,010
Average interest rate . . . . . . . . - - - - - 4.88% 4.88% - -
Interest Rate Swaps
(notional amounts)
Variable to Fixed. . . . . . . . . . . . - - - - - $100.0 $ 100.0 $ (4) $ (1)
Average pay rate. . . . . . . . . . . - - - - - 7.18% 7.18% - -
Average receive rate. . . . . . . . . - - - - - 6.19% 6.19% - -
A-11
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.
A-13
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.
A-14
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
A-15
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
A-16
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.
A-17
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.
A-18
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
A-19
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
A-20
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.
A-21
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.
A-22
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
A-23
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
A-24
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
A-25
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
A-26
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
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31,
---------------------------------
1998 1997 1996
---- ---- ----
Millions of Dollars, Except per Share Amounts
OPERATING REVENUES. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $14,736 $7,946 $6,551
------- ------ ------
OPERATING EXPENSES
Fuel and purchased power. . . . . . . . . . . . . . . . . . . . . . . . . . . 3,799 2,213 2,136
Gas and electricity purchased for resale. . . . . . . . . . . . . . . . . . . 4,115 1,063 -
Operation and maintenance . . . . . . . . . . . . . . . . . . . . . . . . . . 2,570 1,539 1,256
Depreciation and amortization . . . . . . . . . . . . . . . . . . . . . . . . 1,147 666 621
Taxes other than income . . . . . . . . . . . . . . . . . . . . . . . . . . . 642 559 535
------- ------ ------
Total operating expenses. . . . . . . . . . . . . . . . . . . . . . . . . . 12,273 6,040 4,548
------- ------ ------
OPERATING INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,463 1,906 2,003
OTHER INCOME (DEDUCTIONS) - NET . . . . . . . . . . . . . . . . . . . . . . . . 45 (49) (29)
------- ------ ------
INCOME BEFORE INTEREST, OTHER CHARGES
AND INCOME TAXES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,508 1,857 1,974
------- ------ ------
INTEREST INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 139 32 28
INTEREST EXPENSE AND OTHER CHARGES
Interest. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,300 763 798
Distributions on 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 . . . . 74 70 33
Preferred stock dividends of subsidiaries . . . . . . . . . . . . . . . . . . 16 28 53
Allowance for borrowed funds used during construction . . . . . . . . . . . . (9) (9) (11)
------- ------ ------
Total interest and other charges . . . . . . . . . . . . . . . . . . . . . 1,381 852 873
------- ------ ------
INCOME BEFORE INCOME TAXES. . . . . . . . . . . . . . . . . . . . . . . . . . . 1,266 1,037 1,129
INCOME TAX EXPENSE . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 526 377 375
------- ------ ------
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 740 $ 660 $ 754
======= ====== ======
Average shares of common stock outstanding (millions) . . . . . . . . . . . . . 265 231 225
Per share of common stock:
Basic earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2.79 $2.86 $3.35
Diluted earnings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2.79 $2.85 $3.35
Dividends declared . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $2.225 $2.125 $2.025
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-28
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Year Ended December 31,
--------------------------------
1998 1997 1996
---- ---- ----
Millions of Dollars
NET INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 740 $ 660 $ 754
------ ------ ------
OTHER COMPREHENSIVE INCOME (LOSS) - net change during period:
Foreign currency translation adjustments . . . . . . . . . . . . . . . (39) (127) 43
Unrealized holding losses on investments . . . . . . . . . . . . . . . (13) - -
Minimum pension liability adjustments. . . . . . . . . . . . . . . . . (6) - -
------ ------ ------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (58) (127) 43
------ ------ ------
Deferred income tax effects. . . . . . . . . . . . . . . . . . . . . . (28) 28 -
------ ------ ------
COMPREHENSIVE INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . $ 654 $ 561 $ 797
====== ====== ======
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-29
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
---------------------------
1998 1997 1996
---- ---- ----
Millions of Dollars
CASH FLOWS - OPERATING ACTIVITIES
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 740 $ 660 $ 754
Adjustments to reconcile net income to cash provided by operating activities:
Depreciation and amortization (including amounts charged to fuel) . . . . . . . . . . . 1,340 839 774
Deferred income taxes - net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 288 168 185
Investment tax credits - net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (23) (23) (33)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2) (5) (2)
Changes in operating assets and liabilities:
Accounts receivable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (167) (442) (3)
Inventories. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (29) (14) 6
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 317 334 33
Interest and taxes accrued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (24) 40 (33)
Other working capital. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (261) 90 10
Over/(under) - recovered fuel revenue - net of deferred taxes. . . . . . . . . . . . 26 (21) (47)
Energy marketing risk management assets and liabilities. . . . . . . . . . . . . . . (11) (13) -
Other - net. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (189) 41 77
------- ------ ------
Cash provided by operating activities. . . . . . . . . . . . . . . . . . . . . . . 2,005 1,654 1,721
------- ------ ------
CASH FLOWS - FINANCING ACTIVITIES
Issuances of securities:
Acquisition and interim debt facilities. . . . . . . . . . . . . . . . . . . . . . . . . 3,429 - -
Other long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,310 823 1,444
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 . . . . . . . . . . . . . 380 493 -
Common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8 - -
Retirements of securities:
Acquisition and interim debt facilities. . . . . . . . . . . . . . . . . . . . . . . . . (2,183) - -
Other long-term debt . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,504) (1,573) (1,831)
Preferred stock of subsidiaries. . . . . . . . . . . . . . . . . . . . . . . . . . . . . (114) (553) (50)
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. . . . . . . . . . . . . (47) - -
Common stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (25) (149) (52)
Change in notes payable:
Commercial paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,311 1,102 (32)
Banks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 242 (543) (140)
Common stock dividends paid. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (573) (479) (451)
Debt premium, discount, financing and reacquisition expenses . . . . . . . . . . . . . . . . (215) (41) (44)
------- ------ ------
Cash provided by (used in) financing activities . . . . . . . . . . . . . . . . . . 3,019 (920) (1,156)
------- ------ ------
CASH FLOWS - INVESTING ACTIVITIES
Acquisition of The Energy Group (net of cash acquired of $3,265) . . . . . . . . . . . . . . (2,534) - -
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1,173) (586) (434)
Nuclear fuel (excluding allowance for equity funds used
during construction) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (51) (74) (59)
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (582) (48) (83)
------- ------ ------
Cash used in investing activities . . . . . . . . . . . . . . . . . . . . . . . . . (4,340) (708) (576)
------- ------ ------
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH
EQUIVALENTS. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 68 2 2
------- ------ ------
NET CHANGE IN CASH AND CASH EQUIVALENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 752 28 (9)
CASH AND CASH EQUIVALENTS - BEGINNING BALANCE . . . . . . . . . . . . . . . . . . . . . . . . . 44 16 25
------- ------ ------
CASH AND CASH EQUIVALENTS - ENDING BALANCE. . . . . . . . . . . . . . . . . . . . . . . . . . . $ 796 $ 44 $ 16
======= ====== ======
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-30
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
-----------------------
1998 1997
---- ----
Millions of Dollars
PROPERTY, PLANT AND EQUIPMENT
United States (US):
Electric . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $23,130 $22,780
Gas distribution and pipeline. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,212 1,069
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 844 673
------- -------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25,186 24,522
Less accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 7,426 6,652
------- -------
Net of accumulated depreciation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,760 17,870
Construction work in progress. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 346 308
Nuclear fuel (net of accumulated amortization: 1998 - $549; 1997 - $456) . . . . . . . . . . . . 202 242
Held for future use. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 24
Less reserve for regulatory disallowances. . . . . . . . . . . . . . . . . . . . . . . . . . . . 836 836
------- -------
Net US property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . 17,496 17,608
UK/Europe - Electric and Other (net of accumulated depreciation of $147) . . . . . . . . . . . . . 4,428 -
Australia - Electric (net of accumulated depreciation: 1998 - $121; 1997 - $63). . . . . . . . . . 943 963
------- -------
Net property, plant and equipment . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,867 18,571
------- -------
INVESTMENTS
Goodwill (net of accumulated amortization: 1998 - $154; 1997 - $33). . . . . . . . . . . . . . . . 6,830 1,424
Other investments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,482 851
-------- -------
Total investments.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 9,312 2,275
------- -------
CURRENT ASSETS
Cash and cash equivalents. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 796 44
Accounts receivable (net of allowance for uncollectible accounts: 1998 - $50; 1997 - $11). . . . . 1,887 981
Inventories - at average cost:
Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 267 210
Fuel stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 276 81
Gas stored underground . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133 157
Energy marketing risk management assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 832 366
Deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 88 76
Other current assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 308 80
------- -------
Total current assets .. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4,587 1,995
------- -------
DEFERRED DEBITS
Unamortized regulatory assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,805 1,866
Long-term prepayments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 527 -
Other deferred debits. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 416 157
------- -------
Total deferred debits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,748 2,023
------- -------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $39,514 $24,864
======= =======
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-31
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
------------------
1998 1997
---- -----
Millions of Dollars
CAPITALIZATION
Common stock without par value - net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 6,940 $ 5,587
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,448 1,312
Accumulated other comprehensive income (loss):
Foreign currency translation adjustments . . . . . . . . . . . . . . . . . . . . . . . . . . . . (123) (56)
Unrealized holding losses on investments . . . . . . . . . . . . . . . . . . . . . . . . . . . . (13) -
Minimum pension liability adjustments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (6) -
------- -------
Total common stock equity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,246 6,843
Preferred stock of subsidiaries:
Not subject to mandatory redemption . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 190 304
Subject to mandatory redemption. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 21
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 . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,193 875
Long-term debt, less amounts due currently . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,133 8,759
------- -------
Total capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24,783 16,802
------- -------
CURRENT LIABILITIES
Notes payable:
Commercial paper . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,055 570
Banks. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 896 44
Long-term debt due currently . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,071 772
Accounts payable . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,747 880
Energy marketing risk management liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . 838 357
Dividends declared . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 164 140
Taxes accrued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 490 183
Interest accrued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 310 193
Other current liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 705 383
------ -------
Total current liabilities. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 8,276 3,522
------ -------
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES
Accumulated deferred income taxes. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,718 2,989
Unamortized investment tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 548 571
Other deferred credits and noncurrent liabilities. . . . . . . . . . . . . . . . . . . . . . . . . 2,189 980
------ -------
Total deferred credits and other noncurrent liabilities. . . . . . . . . . . . . . . . . . . . 6,455 4,540
------ -------
COMMITMENTS AND CONTINGENCIES (Note 14)
------- -------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $39,514 $24,864
======= =======
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-32
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
Year Ended December 31,
---------------------------
1998 1997 1996
---- ---- ----
Millions of Dollars
COMMON STOCK without par value- authorized shares - 500,000,000:
Balance at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $5,587 $4,787 $4,807
Issued for acquisitions:
The Energy Group (37,316,884 shares). . . . . . . . . . . . . . . . . . . . . . . . 1,449 - -
ENSERCH Corporation (15,861,272 shares) . . . . . . . . . . . . . . . . . . . . . . - 565 -
Lufkin-Conroe Communications Co. (8,727,730 shares) . . . . . . . . . . . . . . . . - 317 -
Direct Stock Purchase and Dividend Reinvestment Plan (198,184 shares) . . . . . . . . 8 - -
Issued for conversion of Convertible Debentures (77,963 shares) . . . . . . . . . . . 3 - -
Issued for Long-Term Incentive Compensation Plan (68,000 shares in
1998 and 61,000 shares in 1997) . . . . . . . . . . . . . . . . . . . . . . . . . . 4 3 -
Common stock repurchased and retired (1998 - 565,771 shares,
1997 - 4,015,000 shares and 1996 - 1,238,480 shares). . . . . . . . . . . . . . . . (14) (91) (28)
Treasury Stock - Long-Term Incentive Plan Trusts . . . . . . . . . . . . . . . . . . (26) - -
Equity-linked securities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (76) - -
Special allocation to Thrift Plan by trustee . . . . . . . . . . . . . . . . . . . . 8 8 8
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (3) (2) -
------ ------ ------
Balance at end of year (1998 - 282,332,819 shares;
1997 - 245,237,559 shares; and 1996 - 224,602,557 shares). . . . . . . . . . . 6,940 5,587 4,787
------ ------ ------
RETAINED EARNINGS:
Balance at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,312 1,203 925
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 740 660 754
Dividends declared on common stock . . . . . . . . . . . . . . . . . . . . . . . . . (597) (496) (456)
Common stock repurchased and retired . . . . . . . . . . . . . . . . . . . . . . . . (11) (59) (24)
LESOP dividend deduction tax benefit and other . . . . . . . . . . . . . . . . . . . 4 4 4
------ ------ ------
Balance at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,448 1,312 1,203
------ ------ ------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (56) 43 -
Change during the year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (86) (99) 43
------ ------ ------
Balance at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (142) (56) 43
------ ------ ------
COMMON STOCK EQUITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $8,246 $6,843 $6,033
====== ====== ======
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-33
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31,
----------------------------
1998 1997 1996
---- ---- ----
Millions of Dollars
OPERATING REVENUES . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $6,488 $6,135 $6,030
------ ------ ------
OPERATING EXPENSES
Fuel and purchased power . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,102 2,063 1,966
Operation and maintenance. . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,281 1,226 1,112
Depreciation and amortization. . . . . . . . . . . . . . . . . . . . . . . . . . 749 572 562
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 490 420 421
Taxes other than income. . . . . . . . . . . . . . . . . . . . . . . . . . . . . 533 507 506
------ ------ ------
Total operating expenses . . . . . . . . . . . . . . . . . . . . . . . . . . 5,155 4,788 4,567
------ ------ ------
OPERATING INCOME.. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,333 1,347 1,463
------ ------ ------
OTHER INCOME (DEDUCTIONS)
Allowance for equity funds used during construction . . . . . . . . . . . . . . 6 5 1
Other income (deductions) - net . . . . . . . . . . . . . . . . . . . . . . . . (12) (8) (3)
Income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4 10 15
------ ------ ------
Total other income (deductions) . . . . . . . . . . . . . . . . . . . . . . . (2) 7 13
------ ------ ------
INCOME BEFORE INTEREST AND OTHER CHARGES . . . . . . . . . . . . . . . . . . . . . 1,331 1,354 1,476
------ ------ ------
INTEREST INCOME . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 7 4
INTEREST EXPENSE AND OTHER CHARGES
Interest . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 476 527 595
Distributions on TU Electric obligated, mandatorily redeemable,
preferred securities of subsidiary trusts holding solely junior
subordinated debentures of TU Electric. . . . . . . . . . . . . . . . . . . . 68 70 33
Allowance for borrowed funds used during construction . . . . . . . . . . . . . (8) (8) (11)
------ ------ ------
Total interest expense and other charges . . . . . . . . . . . . . . . . . . 536 589 617
------ ------ ------
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 798 772 863
PREFERRED STOCK DIVIDENDS . . . . . . . . . . . . . . . . . . . . . . . . . . . . 13 27 54
------ ------ ------
NET INCOME AVAILABLE FOR
COMMON STOCK . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 785 $ 745 $ 809
====== ====== ======
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Year Ended December 31,
-----------------------------
1998 1997 1996
---- ---- ----
Millions of Dollars
NET INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 798 $ 772 $ 863
------ ------ ------
OTHER COMPREHENSIVE INCOME (LOSS) - net change during period in
minimum pension liability adjustment. . . . . . . . . . . . . . . . . . . . . . (1) - -
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (1) - -
------ ------- ------
COMPREHENSIVE INCOME. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 797 $ 772 $ 863
====== ======= ======
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-34
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
----------------------------
1998 1997 1996
---- ---- ----
Millions of Dollars
CASH FLOWS - OPERATING ACTIVITIES
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 798 $ 772 $ 863
Adjustments to reconcile net income to cash provided by
operating activities:
Depreciation and amortization (including amounts charged to fuel) . . . . . . 905 710 685
Deferred income taxes - net . . . . . . . . . . . . . . . . . . . . . . . . . 127 134 150
Investment tax credits - net. . . . . . . . . . . . . . . . . . . . . . . . . (21) (21) (32)
Allowance for equity funds used during construction . . . . . . . . . . . . . (6) (5) (1)
Changes in operating assets and liabilities:
Accounts receivable . . . . . . . . . . . . . . . . . . . . . . . . . . . . 153 (124) 9
Inventories . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (2) (4) 3
Accounts payable. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (169) 44 52
Interest and taxes accrued. . . . . . . . . . . . . . . . . . . . . . . . . (6) 42 (19)
Other working capital . . . . . . . . . . . . . . . . . . . . . . . . . . . (25) 83 (1)
Over/(under) - recovered fuel revenue - net of deferred taxes . . . . . . . 26 (21) (47)
Other - net . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 25 54 36
------ ------ ------
Cash provided by operating activities. . . . . . . . . . . . . . . . . . 1,805 1,664 1,698
------ ------ ------
CASH FLOWS - FINANCING ACTIVITIES
Issuances of securities:
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 429 513 244
TU Electric obligated, mandatorily redeemable, preferred securities
of subsidiary trusts holding solely junior subordinated debentures
of TU Electric. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 493 -
Retirements/repurchases of securities:
Long-term debt. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (924) (942) (859)
Preferred stock . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (14) (553) (50)
TU Electric obligated, mandatorily redeemable, preferred securities
of subsidiary trusts holding solely junior subordinated debentures
of TU Electric. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (47) - -
Common stock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (578) (280) -
Change in notes receivable/payable:
Parent. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (20) 219 (33)
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - (253) (69)
Preferred stock dividends paid. . . . . . . . . . . . . . . . . . . . . . . . . (14) (36) (55)
Common stock dividends paid . . . . . . . . . . . . . . . . . . . . . . . . . . - (273) (367)
Debt premium, discount, financing and reacquisition expenses. . . . . . . . . . (64) (27) (38)
------ ------ ------
Cash used in financing activities. . . . . . . . . . . . . . . . . . . . (1,232) (1,139) (1,227)
------ ------ ------
CASH FLOWS - INVESTING ACTIVITIES
Construction expenditures. . . . . . . . . . . . . . . . . . . . . . . . . . . (501) (446) (377)
Allowance for equity funds used during construction (excluding
amount for nuclear fuel) . . . . . . . . . . . . . . . . . . . . . . . . . . 5 3 1
Nuclear fuel (excluding allowance for equity funds used
during construction) . . . . . . . . . . . . . . . . . . . . . . . . . . . . (51) (74) (59)
Other investments. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . (33) (9) (46)
------ ------ ------
Cash used in investing activities. . . . . . . . . . . . . . . . . . . . (580) (526) (481)
------ ------ ------
NET CHANGE IN CASH AND CASH EQUIVALENTS . . . . . . . . . . . . . . . . . . . . (7) (1) (10)
CASH AND CASH EQUIVALENTS - BEGINNING BALANCE . . . . . . . . . . . . . . . . . 12 13 23
------ ------ ------
CASH AND CASH EQUIVALENTS - ENDING BALANCE . . . . . . . . . . . . . . . . . . . $ 5 $ 12 $ 13
====== ====== ======
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-35
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
---------------------
1998 1997
---- ----
Millions of Dollars
ELECTRIC PLANT
In service:
Production . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $15,469 $15,370
Transmission . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,621 1,669
Distribution . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5,046 4,745
General. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 447 436
------- -------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 22,583 22,220
Less accumulated depreciation. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,789 6,120
------- -------
Electric plant in service, less accumulated depreciation. . . . . . . . . . . . . . . . . . . 15,794 16,100
Construction work in progress. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 226 190
Nuclear fuel (net of accumulated amortization: 1998 - $549, 1997 - $456) . . . . . . . . . . . . 201 242
Held for future use. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 24 24
------- -------
Electric plant, less accumulated depreciation and amortization . . . . . . . . . . . . . . . . . . 16,245 16,556
Less reserve for regulatory disallowances. . . . . . . . . . . . . . . . . . . . . . . . . . . . 836 836
------- -------
Net electric plant. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 15,409 15,720
------- -------
INVESTMENTS . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 588 534
------- -------
CURRENT ASSETS
Cash and cash equivalents . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5 12
Accounts receivable (net of allowance for uncollectible accounts: 1998 - $7; 1997 - $6) . . . . . 205 358
Inventories - at average cost:
Materials and supplies . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 181 181
Fuel stock. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 84 82
Deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 73 49
Prepayments and other current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 36 33
------- -------
Total current assets. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 584 715
------- -------
DEFERRED DEBITS
Unamortized regulatory assets . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,750 1,787
Other deferred debits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 74 68
------- -------
Total deferred debits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,824 1,855
------- -------
Total . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $18,405 $18,824
======= =======
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-36
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
-------------------
1998 1997
---- ----
Millions of Dollars
CAPITALIZATION
Common stock without par value . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $ 3,729 $ 4,316
Retained earnings. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,767 1,982
Accumulated other comprehensive income (loss) - minimum pension liability adjustment . . . . . (1) -
------- -------
Total common stock equity. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6,495 6,298
Preferred stock:
Not subject to mandatory redemption . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115 129
Subject to mandatory redemption. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 21 21
TU Electric obligated, mandatorily redeemable, preferred securities of subsidiary trusts
holding solely junior subordinated debentures of TU Electric . . . . . . . . . . . . . . . . 823 875
Long-term debt, less amounts due currently . . . . . . . . . . . . . . . . . . . . . . . . . . 5,208 5,476
------- -------
Total capitalization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 12,662 12,799
------- -------
CURRENT LIABILITIES
Notes payable - affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 163 183
Long-term debt due currently . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 533 753
Accounts payable:
Affiliates . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 115 289
Other. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 157 152
Customers' deposits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 76 74
Taxes accrued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 169 167
Interest accrued . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 133 141
Over-recovered fuel revenue . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 52 12
Other current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 113 137
------- -------
Total current liabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,511 1,908
------- -------
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES
Accumulated deferred income taxes . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3,307 3,217
Unamortized investment tax credits . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 536 557
Other deferred credits and noncurrent liabilities. . . . . . . . . . . . . . . . . . . . . . . 389 343
------- -------
Total deferred credits and other noncurrent liabilities. . . . . . . . . . . . . . . . . . 4,232 4,117
------- -------
COMMITMENTS AND CONTINGENCIES (Note 14)
------- -------
Total. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $18,405 $18,824
======= =======
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-37
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
Year Ended December 31,
----------------------------
1998 1997 1996
---- ---- ----
Millions of Dollars
COMMON STOCK without par value- authorized shares - 180,000,000:
Balance at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . $4,316 $4,732 $4,732
Common stock repurchased and retired (1998 - 19,270,300 shares,
1997 - 13,869,000 shares). . . . . . . . . . . . . . . . . . . . . . . . (578) (416) -
Long-term incentive plan trust . . . . . . . . . . . . . . . . . . . . . . (9) - -
------ ------ ------
Balance at end of year (1998 - 123,660,700 shares;
1997 - 142,931,000 shares; and 1996 - 156,800,000 shares) . . . . . . . . 3,729 4,316 4,732
------ ------ ------
RETAINED EARNINGS:
Balance at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . 1,982 1,374 1,068
Net income . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 798 772 863
Dividends declared on common stock . . . . . . . . . . . . . . . . . . . . - (137) (503)
Dividends declared on preferred stock. . . . . . . . . . . . . . . . . . . (13) (27) (54)
------ ------ ------
Balance at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . 2,767 1,982 1,374
------ ------ ------
ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS):
Balance at beginning of year . . . . . . . . . . . . . . . . . . . . . . . . - - -
Change during the year . . . . . . . . . . . . . . . . . . . . . . . . . . (1) - -
------ ------ ------
Balance at end of year . . . . . . . . . . . . . . . . . . . . . . . . . . . (1) - -
------ ------ ------
COMMON STOCK EQUITY . . . . . . . . . . . . . . . . . . . . . . . . . . . . . $6,495 $6,298 $6,106
====== ====== ======
<FN>
See Notes to Consolidated Financial Statements.
</FN>
A-38
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.
Year Ended December 31,
---------------------------------------------------
1998 1997
----------------------- ------------------------
As Reported Pro forma As Reported Pro forma
----------- --------- ----------- ----------
Revenues. . . . . . . . . . . . . . . . . . $14,736 $17,319 $7,946 $14,794
Operating income. . . . . . . . . . . . . . 2,463 2,781 1,906 2,719
Net income. . . . . . . . . . . . . . . . . 740 884 660 842
Average shares outstanding (millions) . . . 265 282 231 286
Earnings per share of common stock
Basic . . . . . . . . . . . . . . . . . $2.79 $3.13 $2.86 $2.95
Diluted . . . . . . . . . . . . . . . . $2.79 $3.13 $2.85 $2.94
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.
A-40
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
A-42
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:
Year Ended December 31,
-----------------------------------
1998 1997 1996
------ ------- ------
The Company
CASH PAYMENTS
Interest (net of amounts capitalized) . . . . . . . . . . $ 1,206 $ 700 $ 790
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 357 175 247
NON-CASH INVESTING AND FINANCING ACTIVITIES
Acquisition of TEG (1998), ENSERCH and LCC (1997):
Fair value of assets acquired. . . . . . . . . . . . $10,414 $ 2,033 $ -
Goodwill . . . . . . . . . . . . . . . . . . . . . . 5,412 1,005 -
Common stock issued, net of capitalized expenses . . (1,449) (892) 10
Loan notes payable . . . . . . . . . . . . . . . . . (141) - -
Liabilities assumed. . . . . . . . . . . . . . . . . (8,437) (2,125) -
------- ------- -------
Cash used . . . . . . . . . . . . . . . . . . . 5,799 21 10
Cash acquired. . . . . . . . . . . . . . . . . . . . (3,265) (26) -
------- ------- -------
Net cash used (provided). . . . . . . . . . . . $ 2,534 $ (5) $ 10
======= ======= =======
TU Electric
CASH PAYMENTS
Interest (net of amounts capitalized) . . . . . . . . . . $ 508 $ 537 $ 591
Income taxes. . . . . . . . . . . . . . . . . . . . . . . 374 232 303
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:
The Company TU Electric
December 31, December 31,
----------------- -----------------
1998 1997 1998 1997
------ ------ ------ ------
Securities reacquisition costs . . . . . . . . . . $ 434 $ 398 $ 432 $ 397
Rate case costs. . . . . . . . . . . . . . . . . . 54 57 54 57
Litigation and settlement costs. . . . . . . . . . 73 73 73 73
Voluntary retirement/severance program . . . . . . 105 128 90 108
Recoverable deferred income taxes - net. . . . . . 1,204 1,249 1,209 1,255
Other regulatory assets (liabilities). . . . . . . 8 34 (35) (30)
Reserve for regulatory disallowances . . . . . . . (73) (73) (73) (73)
------ ------ ------ ------
Unamortized regulatory assets . . . . . . . . . 1,805 1,866 1,750 1,787
Unamortized investment tax credits . . . . . . . . (548) (571) (536) (557)
------ ------ ------ ------
Unamortized regulatory assets - net. . . . . . $1,257 $1,295 $1,214 $1,230
====== ====== ====== ======
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:
Year Ended December 31,
--------------------------
1998 1997 1996
------ ----- ----
Billings from:
TU Services. . . . . . . . . . . . . $ 248 $271 $264
Fuel Company . . . . . . . . . . . . 1,019 996 922
Mining Company . . . . . . . . . . . 360 355 369
Billings to:
SESCO. . . . . . . . . . . . . . . . $ 23 $ 35 $ 29
Fuel Company . . . . . . . . . . . . - 1 2
ENSERCH. . . . . . . . . . . . . . . 107 - -
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.
A-47
5. LONG-TERM DEBT, less amounts due currently
The Company TU Electric
December 31, December 31,
--------------------- --------------------
1998 1997 1998 1997
------- ------- ------- -------
First mortgage bonds (6 1/4% to 10.44% due 1999 to 2025). . . . . . . . $ 2,276 $ 2,867 $ 2,276 $ 2,867
Pollution control series:
Brazos River Authority:
Fixed rate (4.15% to 8 1/4% due 2019 to 2033) . . . . . . . . . 902 641 902 641
Taxable series (5.27% to 5.28% due 2021 to 2023) (a). . . . . . 116 141 116 141
Variable rate (3.10% to 5.30% due 2022 to 2032) (b)(c). . . . . 400 637 400 637
Sabine River Authority of Texas:
Fixed rate (5.55% to 8 1/4% due 2020 to 2022) . . . . . . . . . 199 199 199 199
Variable rate (4.00% to 5.30% due 2022 to 2030) (c). . . . . . 182 182 182 182
Trinity River Authority of Texas-
Flexible rate (4.10% to 5.38% due 2022 to 2032) (c) . . . . . . 51 51 51 51
Secured medium-term notes . . . . . . . . . . . . . . . . . . . . . 315 345 315 345
Debt assumed for purchase of utility plant (d). . . . . . . . . . . . . 151 154 151 154
TU Electric Floating Rate Debentures due 2000 (e) . . . . . . . . . . . 350 - 350 -
TU Electric 7.17% Senior Debentures due 2007. . . . . . . . . . . . . . 300 300 300 300
Eastern Group:
Bonds (7.375% to 8.75% due 2004 to 2027) (f). . . . . . . . . . . . 1,872 - - -
Rent factoring agreement. . . . . . . . . . . . . . . . . . . . . . 708 - - -
Capital leases (See note 14). . . . . . . . . . . . . . . . . . . . 871 - - -
Other long-term debt. . . . . . . . . . . . . . . . . . . . . . . . 726 - - -
Senior notes:
TUC (5.248% to 6.375% due through 2008) . . . . . . . . . . . . . . 625 300 - -
Various subsidiaries (6.5% to 10.5% due 2003 to 2016) . . . . . . . 1,248 1,436 - -
ENSERCH Remarketed Reset Notes due 2008 (g) . . . . . . . . . . . . . . 125 - - -
6.375% Convertible subordinated debentures due 2002 . . . . . . . . . . - 91 - -
TUC - Equity-linked securities (6.37% to 6.50% due 2003 and 2004) . . . 700 - -
TUC - 5.94% mandatory putable/remarketable securities . . . . . . . . . 375 - - -
Credit facilities:
Eastern Energy (h). . . . . . . . . . . . . . . . . . . . . . . . . 448 427 - -
Eastern Group . . . . . . . . . . . . . . . . . . . . . . . . . . . 1,324 - - -
TUC . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 816 990 - -
Other . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 82 34 - -
Unamortized premium and discount and fair value adjustments . . . . . . (29) (36) (34) (41)
------- ------- ------- -------
Total long-term debt, less amounts due currently. . . . . . $15,133 $ 8,759 $ 5,208 $ 5,476
======= ======= ======= =======
<FN>
(a) Interest rates in effect at December 31, 1998 are presented. Taxable
pollution control series are in a flexible rate mode. Series 1991D bonds due
2021 were remarketed on June 1, 1995 for rate periods up to 180 days and are
secured by an irrevocable letter of credit with maturities in excess of one
year. Series 1993 bonds due 2023 will be remarketed for periods of less than
270 days and are secured by an irrevocable letter of credit with maturities in
excess of one year.
(b) Interest rates in effect at December 31, 1998 are presented. These series
are in a flexible mode with varying interest rates and, while in such mode,
will be remarketed for periods of less than 270 days and are secured by an
irrevocable letter of credit with maturities in excess of one year.
(c) Interest rates in effect at December 31, 1998 are presented. These series
are in a daily or multiannual mode with varying interest rates and are
supported by either municipal bond insurance policies and standby bond
purchase agreements or are secured by irrevocable letters of credit with
maturities in excess of one year.
(d) In 1990, TU Electric purchased the ownership interest in Comanche Peak of
Tex-La Electric Cooperative of Texas, Inc. (Tex-La) and assumed debt of Tex-La
payable over approximately 32 years. The assumption is secured by a mortgage
on the acquired interest. The Company has guaranteed these payments.
(e) Interest will be set quarterly based on three-month LIBOR plus a margin.
The rate at December 31, 1998 was 5.47%.
(f) Eastern Group has an interest swap that converts 100 million pounds
($165.4 million) of the 8.375% bonds due 2004 to a floating rate, which was
5.42% at December 31, 1998.
(g) In July 1998, the interest rate was reset to a fixed rate of 6.56% payable
until July 1, 2005.
(h) Also includes Eastern Energy's $296 million Multi Option Credit
Facility due 2001 with a floating interest rate of 5.42% on December 31, 1998
and Eastern Energy's $124 million reclassified short-term debt (all of which
is included under interest rate swap agreements with notional principal
amounts of $577 million expiring at various dates through 2006 with fixed
interest rates ranging from 5.765 to 8.45% per annum and forward contracts
with notional principal amounts of $58 million maturing in early 1999 with an
average rate of 4.99%).
</FN>
A-48
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:
Year The Company TU Electric
---- ----------- -----------
1999 . . . . . . . . . . . . . $1,194 $536
2000 . . . . . . . . . . . . . 2,186 159
2001 . . . . . . . . . . . . . 1,519 226
2002 . . . . . . . . . . . . . 562 374
2003 . . . . . . . . . . . . . 2,266 4
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.
A-50
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.
A-51
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:
December 31, 1998 December 31, 1997
---------------------- -------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
-------- -------- ------- -------
The Company
On balance sheet assets (liabilities):
Long-term debt (including current maturities)* . . . . . . . . . . . . $(15,332) $(15,926) $(9,531) $(9,932)
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 . . . . . . . . . . . . . . . . . . . . . . . (1,193) (1,236) (875) (913)
Preferred stock of subsidiary subject to mandatory
redemption . . . . . . . . . . . . . . . . . . . . . . . . . . . . (21) (21) (21) (22)
Other investments. . . . . . . . . . . . . . . . . . . . . . . . . . . 2,581 2,597 242 249
LESOP note receivable. . . . . . . . . . . . . . . . . . . . . . . . . 250 302 250 281
Off-balance sheet assets (liabilities):
Financial guarantees . . . . . . . . . . . . . . . . . . . . . . . . . - (432) - (149)
Interest rate swaps. . . . . . . . . . . . . . . . . . . . . . . . . . - (86) - (50)
Currency swaps and forwards. . . . . . . . . . . . . . . . . . . . . . - (4) - 76
Gas swaps. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . - (3) - -
CfDs and EFAs. . . . . . . . . . . . . . . . . . . . . . . . . . . . . - 101 - -
TU Electric
On balance sheet assets (liabilities):
Long-term debt (including current maturities). . . . . . . . . . . . . $ (5,741) $ (6,045) $(6,229) $(6,574)
TU Electric obligated, mandatorily redeemable, preferred
securities of subsidiary trusts holding solely junior
subordinated debentures of TU Electric. . . . . . . . . . . . . . . (823) (862) (875) (913)
Preferred stock subject to mandatory redemption. . . . . . . . . . . . (21) (21) (21) (22)
Other investments. . . . . . . . . . . . . . . . . . . . . . . . . . . 588 599 205 209
Off balance sheet assets (liabilities):
Financial guarantees . . . . . . . . . . . . . . . . . . . . . . . . - (96) - (103)
Interest rate swap . . . . . . . . . . . . . . . . . . . . . . . . . - (4) - (1)
<FN>
*Excludes capital leases.
</FN>
A-52
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.
A-53
At December 31, 1998 and 1997, the statutory business trust subsidiaries
of the Company, TU Electric and ENSERCH had trust securities outstanding, as
follows:
Trust Securities Outstanding Trust Assets
------------------------------------- -----------------
Units (000's) Amount Amount Maturity
December 31, December 31, December 31,
-------------- ----------------- ----------------- --------
1998 1997 1998 1997 1998 1997
----- ----- ------- ----- ------- ------
The Company
TXU Capital I (7.25% Series). . . . . . . . 9,200 - $ 223 $ - $ 237 $ - 2029
TU Electric
TU Electric Capital I (8.25% Series). . . . 5,871 5,871 141 141 155 155 2030
TU Electric Capital II (9.00% Series) . . . - 1,991 - 47 - 52 -
TU Electric Capital III (8.00% Series). . . 8,000 8,000 194 194 206 206 2035
TU Electric Capital IV (Floating Rate
Trust Securities)(a). . . . . . . . . 100 100 96 98 103 103 2037
TU Electric Capital V (8.175% Trust
Securities). . . . . . . . . . . . . . 400 400 392 395 412 412 2037
------ ------ ------ ----- ----- -----
Total TU Electric. . . . . . . . . 14,371 16,362 823 875 876 928
------ ------ ------ ----- ----- -----
ENSERCH
ENSERCH Capital I (Floating Rate Trust
Securities)(b) . . . . . . . . . . . . 150 - 147 - 155 - 2028
------ ------ ------ ----- ----- -----
Total. . . . . . . . . . . . . . . 23,721 16,362 $1,193 $ 875 $1,268 $ 928
====== ====== ====== ===== ====== =====
<FN>
(a) Floating rate is determined quarterly based on LIBOR. A related interest
rate swap, expiring 2002, effectively fixes the rate on the TU Electric
Capital IV securities at 7.183%.
(b) Interest rate swaps effectively fix the rate on $100 million of the
ENSERCH Floating Rate Trust Securities at 6.629% and at 6.444% on the
remaining $50 million of the Trust Securities to July 1, 2003.
</FN>
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.
A-54
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:
Income Statement
Balance Sheet (average for periods
(at December 31,) ended December 31,)
----------------------------------------------------
Period Amount Annual Rate Fair Value
- ------ -------- ----------- ---------
millions millions
Annually to 2017 $ 14.8 $ 1.61 $ (9.2)
Annually to 2027 $ 22.5 $ 1.62 $ (20.7)
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
A-55
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.
A-56
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:
1998 1997
---------------------------- ----------------------------
Assets Liabilities Net Assets Liabilities Net
------ ----------- ----- ------ ----------- -----
Fair Value:
Current . . . . . . . . . . . . $832 $838 $ (6) $366 $357 $ 9
Noncurrent. . . . . . . . . . . 128 93 35 41 31 10
---- ---- ---- ---- ---- ----
Total . . . . . . . . . . $960 $931 29 $407 $388 19
Less reserves . . . . . . . . . ==== ==== 6 ==== ==== 9
---- ----
Net of reserves . . . . . $ 23 $ 10
==== ====
Average Value:
Total . . . . . . . . . . . . . $656 $617 $ 39 $292 $279 $ 13
Less reserves . . . . . . . . . ==== ==== 7 ==== ==== 8
---- ----
Net of reserves . . . . . $ 32 $ 5
==== ====
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
A-57
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.
The Company TU Electric
------------ ---------------
1998 1997 1998 1997
---- ---- ---- ----
Weighted-average assumptions:
Discount rate . . . . . . . . . . . . . . 7.00% 7.25% 7.00% 7.25%
Expected return on plan assets. . . . . . 9.00% 9.00% 9.00% 9.00%
Rate of compensation increase . . . . . . 4.30% 4.30% 4.30% 4.30%
Year Ended December 31, Year Ended December 31,
-------------------------- ----------------------
1998 1997 1996 1998 1997 1996
------ ----- ---- ---- ---- ----
Components of Net Pension Costs:
Service cost. . . . . . . . . . . . . . . . . . . . $ 53 $ 37 $ 37 $ 22 $ 21 $ 22
Interest cost . . . . . . . . . . . . . . . . . . . 163 94 77 60 61 56
Expected return on assets . . . . . . . . . . . . . (205) (137) (88) (77) (99) (66)
Amortization of unrecognized net transition asset . (1) (1) (1) - - -
Amortization of unrecognized prior service cost . . 4 4 3 4 3 3
Amortization of net (gain) loss . . . . . . . . . . (5) (5) 1 (5) (5) -
Recognized termination benefits loss. . . . . . . . - 34 - - 24 -
------ ------ ---- ----- ----- -----
Net periodic pension cost . . . . . . . . . . . $ 9 $ 26 $ 29 $ 4 $ 5 $ 15
====== ====== ==== ===== ===== =====
A-58
The Company TU Electric
----------------------- -----------------------
Year Ended December 31, Year Ended December 31,
----------------------- -----------------------
1998 1997 1998 1997
------ ------ ------ ------
Change in Pension Obligation:
Pension obligation at beginning of year . . . . . . . $ 1,576 $ 1,082 $ 845 $ 802
Service cost. . . . . . . . . . . . . . . . . . . 53 37 22 21
Interest cost . . . . . . . . . . . . . . . . . . 163 94 60 61
Participant contributions . . . . . . . . . . . . 10 1 - -
Plan amendments . . . . . . . . . . . . . . . . . 12 - - -
Actuarial loss. . . . . . . . . . . . . . . . . . 193 85 45 38
Acquisitions. . . . . . . . . . . . . . . . . . . 1,429 395 - -
Benefits paid . . . . . . . . . . . . . . . . . . (133) (64) (45) (47)
Curtailments. . . . . . . . . . . . . . . . . . . - 1 - 2
Settlements . . . . . . . . . . . . . . . . . . . - (76) - (56)
Special termination benefits . . . . . . . . . . - 33 - 24
Currency exchange rate changes . . . . . . . . . 25 (12) - -
Other . . . . . . . . . . . . . . . . . . . . . . 3 - - -
------- ------- ------ ------
Pension obligation at end of year . . . . . . . . . . $ 3,331 $ 1,576 $ 927 $ 845
======= ======= ====== ======
Change in Plan Assets:
Fair value of assets at beginning of year . . . . . . $ 1,794 $ 1,299 $1,125 $ 994
Actual return on assets. . . . . . . . . . . . . 188 301 146 231
Acquisitions . . . . . . . . . . . . . . . . . . 1,832 316 - -
Employer contributions . . . . . . . . . . . . . 57 22 - -
Participant contributions. . . . . . . . . . . . 10 1 - -
Benefits paid . . . . . . . . . . . . . . . . . . (133) (61) (45) (47)
Settlements . . . . . . . . . . . . . . . . . . . - (72) - (53)
Currency exchange rate changes. . . . . . . . . . 34 (12) - -
------- ------- ------ ------
Fair value of assets at end of year . . . . . . . . . $ 3,782 $ 1,794 $1,226 $1,125
======= ======= ====== ======
Funded Status:
Pension obligation. . . . . . . . . . . . . . . . . . $(3,331) $(1,576) $ (927) $ (845)
Fair value of assets. . . . . . . . . . . . . . . . . 3,782 1,794 1,226 1,125
Unrecognized net transition asset . . . . . . . . . . (4) (5) (2) (2)
Unrecognized prior service cost . . . . . . . . . . . 42 34 33 36
Unrecognized net gain . . . . . . . . . . . . . . . . (199) (417) (417) (397)
------- ------- ------ -----
(Accrued)/prepaid pension cost .. . . . . . . . . . . $ 290 $ (170) $ (87) $ (83)
======= ======= ====== ======
Amounts Recognized in the Statement of
Financial Position Consist of:
Prepaid pension cost. . . . . . . . . . . . . . $ 433 $ 7 $ - $ -
Accrued benefit liability . . . . . . . . . . . (151) (177) (89) (83)
Intangible asset. . . . . . . . . . . . . . . . 2 - 1 -
Accumulated other comprehensive income (loss) . 6 - 1 -
------- ------- ------ -----
Net amount recognized. . . . . . . . . . . $ 290 $ (170) $ (87) $ (83)
======= ======= ====== ======
A-59
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.
The Company TU Electric
------------- ----------------
1998 1997 1998 1997
---- ----- ---- -----
Weighted-average assumptions:
Discount rate . . . . . . . . . . . . . . . . . 7.00% 7.25% 7.00% 7.25%
Expected return on plan assets. . . . . . . . . 8.13% 7.50% 8.13% 7.50%
Year Ended December 31, Year Ended December31,
------------------------ -----------------------
1998 1997 1996 1998 1997 1996
---- ----- ----- ---- ----- -----
Components of Net Periodic Postretirement
Benefit Costs:
Service cost. . . . . . . . . . . . . . . . . . $ 19 $ 12 $ 14 $ 10 $ 7 $ 8
Interest cost . . . . . . . . . . . . . . . . . 42 43 41 26 31 31
Expected return on assets . . . . . . . . . . . (10) (8) (5) (8) (6) (3)
Amortization of unrecognized net transition
obligation. . . . . . . . . . . . . . . . . 16 17 17 14 14 14
Amortization of unrecognized prior service cost 2 - - - - -
Amortization of net loss. . . . . . . . . . . . 2 2 6 1 1 4
Recognized curtailment loss . . . . . . . . . . - 10 - - 4 -
----- ----- ----- ----- ----- -----
Net postretirement benefit cost . . . . . . $ 71 $ 76 $ 73 $ 43 $ 51 $ 54
===== ===== ===== ===== ===== -----
Change in Postretirement Benefit Obligation:
Benefit obligation at beginning of year . . . . $ 591 $ 531 $ 367 $ 407
Service cost. . . . . . . . . . . . . . . . 19 12 10 7
Interest cost . . . . . . . . . . . . . . . 42 43 26 31
Participant contributions . . . . . . . . . 6 4 5 3
Plan amendments . . . . . . . . . . . . . . - (92) - (30)
Actuarial (gain)/loss . . . . . . . . . . . 83 36 76 (23)
Acquisitions. . . . . . . . . . . . . . . . - 96 - -
Benefits paid . . . . . . . . . . . . . . . (39) (32) (30) (24)
Curtailments. . . . . . . . . . . . . . . . - (7) - (4)
------ ----- ----- -----
Benefit obligation at end of year .. . . . . . $ 702 $ 591 $ 454 $ 367
====== ===== ===== =====
Change in Plan Assets:
Fair value of assets at beginning of year . . . $ 112 $ 82 $ 82 $ 61
Actual return on assets . . . . . . . . . . 18 13 14 10
Employer contributions. . . . . . . . . . . 42 41 31 30
Participant contributions . . . . . . . . . 3 2 2 2
Benefits paid . . . . . . . . . . . . . . . (30) (26) (25) (21)
------ ------ ---- ----
Fair value of assets at end of year . . . . . . $ 145 $ 112 $104 $ 82
====== ====== ==== ====
Funded Status:
Benefit obligation. . . . . . . . . . . . . . . $ (702) $(591) $(454) $(367)
Fair value of assets. . . . . . . . . . . . . . 145 112 104 82
Unrecognized transition obligation. . . . . . . 146 162 128 142
Unrecognized prior service cost . . . . . . . . 17 19 - -
Unrecognized net loss . . . . . . . . . . . . . 139 67 114 45
------- ------ ----- ----
Accrued postretirement benefit cost . . . . . . $ (255) $(231) $(108) $ (98)
======= ====== ===== =====
A-60
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:
Year Ended December 31,
----------------------------
1998 1997 1996
---- ----- -----
The Company
Current:
US Federal. . . . . . . . . . . . . . . . . . . . . $ 174 $ 182 $ 198
State . . . . . . . . . . . . . . . . . . . . . . 29 40 -
Non-US. . . . . . . . . . . . . . . . . . . . . . . 72 - -
----- ----- -----
Total . . . . . . . . . . . . . . . . . . . . . 275 222 198
----- ----- -----
Deferred
US Federal. . . . . . . . . . . . . . . . . . . . . 208 175 197
State . . . . . . . . . . . . . . . . . . . . . . . 1 (17) -
Non-US. . . . . . . . . . . . . . . . . . . . . . . 65 20 13
----- ----- -----
Total . . . . . . . . . . . . . . . . . . . . . 274 178 210
----- ----- -----
Investment tax credits. . . . . . . . . . . . . . . . (23) (23) (33)
----- ----- -----
Total . . . . . . . . . . . . . . . . . . $ 526 $ 377 $ 375
===== ===== =====
TU Electric
Charged (credited) to operating expenses:
Current:
US Federal. . . . . . . . . . . . . . . . . $ 404 $ 283 $ 292
State . . . . . . . . . . . . . . . . . . . 29 44 -
----- ----- -----
Total . . . . . . . . . . . . . . . . 433 327 292
----- ----- -----
Deferred:
Depreciation differences and capitalized
construction costs . . . . . . . . . . 109 147 151
Over/under-recovered fuel revenue . . . . . (14) 10 26
Alternative minimum tax . . . . . . . . . . (1) 1 15
Other . . . . . . . . . . . . . . . . . . . (16) (44) (32)
----- ----- -----
Total . . . . . . . . . . . . . . . . 78 114 160
----- ----- -----
Investment tax credits. . . . . . . . . . . . . (21) (21) (31)
----- ----- -----
Total to operating expenses . . . . . 490 420 421
----- ----- -----
Charged (credited) to other income:
Current:
US Federal. . . . . . . . . . . . . . . . . (37) (36) (30)
State . . . . . . . . . . . . . . . . . . . (2) (5) -
----- ----- -----
Total . . . . . . . . . . . . . . . (39) (41) (30)
----- ----- -----
Deferred:
US Federal:
Regulatory disallowance . . . . . . . . . . 32 34 14
Other . . . . . . . . . . . . . . . . . . . 3 14 2
----- ----- -----
Total . . . . . . . . . . . . . . . 35 48 16
----- ----- -----
State . . . . . . . . . . . . . . . . . . . - (17) -
Investment tax credits. . . . . . . . . . . . . - - (1)
----- ----- -----
Total to other income . . . . . . . (4) (10) (15)
----- ----- -----
Total . . . . . . . . . . . . $ 486 $ 410 $ 406
===== ===== =====
A-61
Reconciliation of income taxes computed at the federal statutory
rate to provision for income taxes.
The Company Year Ended December 31,
-----------------------------------
1998 1997 1996
----- ------ ------
Income before income taxes:
Domestic. . . . . . . . . . . . . . . . . . . . . . $ 951 $1,002 $1,108
Non-US. . . . . . . . . . . . . . . . . . . . . . . 315 35 21
------ ------ ------
Total . . . . . . . . . . . . . . . . . . . . 1,266 1,037 1,129
Preferred stock dividends of subsidiaries. . . . . 16 28 53
------ ------ ------
Income before preferred stock dividends
of subsidiaries. . . . . . . . . . . . . . . . . $1,282 $1,065 $1,182
====== ====== ======
Income taxes at the US federal statutory
rate of 35% . . . . . . . . . . . . . . . . . . . . $ 449 $ 373 $ 414
Allowance for funds used during construction. . . (2) (2) (1)
Depletion allowance . . . . . . . . . . . . . . . (24) (22) (26)
Amortization of investment tax credits. . . . . . (23) (23) (23)
Amortization of tax rate differences. . . . . . . (5) (7) (9)
Amortization of prior flow-through amounts. . . . 66 37 35
State income taxes, net of federal tax benefit. . 19 15 -
Prior year adjustments. . . . . . . . . . . . . . (1) (8) (25)
Amortization of goodwill. . . . . . . . . . . . . 43 7 5
Other . . . . . . . . . . . . . . . . . . . . . . 4 7 5
------ ------ ------
Provision for income taxes. . . . . . . . . . . . . . . $ 526 $ 377 $ 375
====== ====== ======
Effective tax rate (on income before preferred
stock dividends of subsidiaries). . . . . . . . . . 41% 35% 32%
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.
TU Electric Year Ended December 31,
1998 1997 1996
------ ------ -------
Income before income taxes . . . . . . . . . . . . . . . . . $1,284 $1,182 $1,269
====== ====== ======
Income taxes at the US federal statutory rate of 35% $ 449 $ 413 $ 444
Allowance for funds used during construction. . . . . . (2) (2) -
Depletion allowance . . . . . . . . . . . . . . . . . . (24) (22) (26)
Amortization of investment tax credits. . . . . . . . . (21) (21) (21)
Amortization of tax rate differences. . . . . . . . . . (4) (6) (9)
Amortization of prior flow-through amounts. . . . . . . 66 36 35
State income taxes, net of federal tax benefit. . . . . 18 14 -
Prior year adjustments. . . . . . . . . . . . . . . . . (1) (7) (22)
Other . . . . . . . . . . . . . . . . . . . . . . . . . 5 5 5
----- ----- ------
Provision for income taxes. . . . . . . . . . . . . . . . . . $ 486 $ 410 $ 406
===== ===== ======
Effective tax rate. . . . . . . . . . . . . . . . . . . . . . 38% 35% 32%
A-62
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:
December 31,
---------------------------------------------------------------------
The Company 1998 1997
---------------------------------- ------------------------------
Total Current Noncurrent Total Current Noncurrent
------- --------- ----------- ------- -------- ----------
Deferred Tax Assets:
Unbilled revenues . . . . . . . . . . . . . . . . $ 30 $ 30 $ - $ 29 $ 29 $ -
Over-recovered fuel revenue . . . . . . . . . . . 18 18 - 5 5 -
Unamortized investment tax credits. . . . . . . . 293 - 293 301 - 301
Impairment of assets. . . . . . . . . . . . . . . 76 - 76 142 - 142
Regulatory disallowance . . . . . . . . . . . . . 152 - 152 184 - 184
Alternative minimum tax . . . . . . . . . . . . . 594 - 594 590 - 590
Tax rate differences. . . . . . . . . . . . . . . 62 - 62 78 - 78
Employee benefits . . . . . . . . . . . . . . . . 158 4 154 166 3 163
Net operating loss carryforwards. . . . . . . . . 147 - 147 156 - 156
Foreign tax loss carryforwards. . . . . . . . . . 83 - 83 61 - 61
Deferred benefits of state income tax . . . . . . 184 11 173 156 5 151
Unrealized currency translation adjustments . . . - - - 28 - 28
Leased assets . . . . . . . . . . . . . . . . . . 584 - 584 - - -
Valuation allowance . . . . . . . . . . . . . . . (238) - (238) - - -
Other . . . . . . . . . . . . . . . . . . . . . . 338 25 313 48 37 11
Deferred state income taxes . . . . . . . . . . . 61 5 56 53 3 50
------- ------ ----- ----- ----- -----
Total deferred tax assets. . . . . . . . . 2,542 93 2,449 1,997 82 1,915
------- ------ ----- ----- ----- -----
Deferred Tax Liabilities:
Depreciation differences and capitalized
construction costs. . . . . . . . . . . . . . 4,818 - 4,818 4,328 - 4,328
Redemption of long-term debt. . . . . . . . . . . 134 - 134 124 - 124
Deferred charges for state income tax . . . . . . 22 - 22 24 - 24
Unbilled income . . . . . . . . . . . . . . . . . 17 17 - 13 13 -
Lease assets. . . . . . . . . . . . . . . . . . . 553 - 553 - - -
Other . . . . . . . . . . . . . . . . . . . . . . 301 - 301 134 1 133
Deferred state income taxes . . . . . . . . . . . 339 - 339 295 - 295
------- ------ ------- ------ ----- ------
Total deferred tax liabilities 6,184 17 6,167 4,918 14 4,904
------- ------ ------- ------ ----- ------
Net deferred tax liability (asset). . . . . $ 3,642 $ (76) $ 3,718 $2,921 $ (68) $2,989
======= ====== ======= ====== ===== ======
December 31,
----------------------------------------------------------------------------
1998 1997
----------------------------------- ---------------------------------
Net Net Net Net Net Net
Current Current Noncurrent Current Current Noncurrent
Asset Liability Liability Asset Liability Liability
-------- --------- ---------- -------- --------- ----------
Summary of Deferred Income Taxes
US Federal. . . . . . . . . . . . . . . . . . . . $ 83 $ - $2,876 $ 73 $ - $2,734
State . . . . . . . . . . . . . . . . . . . . . . 5 - 283 3 - 245
United Kingdom. . . . . . . . . . . . . . . . . . - - 531 - - -
Australia . . . . . . . . . . . . . . . . . . . . - 12 28 - 8 10
-------- ------- ------ ------- ----- ------
Total . . . . . . . . . . . . . . . . . . . . $ 88 $ 12 $3,718 $ 76 $ 8 $2,989
======== ======= ====== ======= ===== ======
A-63
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.
December 31,
--------------------------------------------------------------------------
TU Electric 1998 1997
--------------------------------- ------------------------------------
Total Current Noncurrent Total Current Noncurrent
----- ------- ---------- ------ ------- ----------
Deferred Tax Assets:
Unbilled revenues . . . . . . . . . . . . . $ 30 $ 30 $ - $ 28 $ 28 $ -
Over-recovered fuel revenue . . . . . . . . 18 18 - 5 5 -
Unamortized investment tax credits. . . . . 289 - 289 296 - 296
Impairment of assets. . . . . . . . . . . . 72 - 72 71 - 71
Regulatory disallowance . . . . . . . . . . 152 - 152 184 - 184
Alternative minimum tax . . . . . . . . . . 424 - 424 423 - 423
Tax rate differences. . . . . . . . . . . . 59 - 59 77 - 77
Employee benefits . . . . . . . . . . . . . 94 - 94 90 - 90
Deferred benefits of state income tax . . . 178 9 169 152 5 147
Other . . . . . . . . . . . . . . . . . . . 33 11 22 21 8 13
Deferred state income taxes. . . . . . . . 53 5 48 47 3 44
----- ------ ------- ------ ----- -----
Total deferred tax assets. . . . . . . 1,402 73 1,329 1,394 49 1,345
----- ------ ------- ------ ----- -----
Deferred Tax Liabilities:
Depreciation differences and capitalized
construction costs . . . . . . . . . . . 4,042 - 4,042 4,027 - 4,027
Redemption of long-term debt. . . . . . . . 134 - 134 123 - 123
Deferred charges for state income tax . . . 18 - 18 22 - 22
Other . . . . . . . . . . . . . . . . . . . 125 - 125 116 - 116
Deferred state income taxes . . . . . . . . 317 - 317 274 - 274
----- ------ ------- ------ ----- -----
Total deferred tax liability. . . . . . 4,636 - 4,636 4,562 - 4,562
----- ------ ------- ------ ----- -----
Net deferred tax liability (asset). . $ 3,234 $ (73) $ 3,307 $3,168 $ (49) $3,217
======= ====== ======= ====== ===== ======
A-64
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.
A-65
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
A-66
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.
A-67
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:
Year The Company TU Electric
- ---- ----------- -----------
1999. . . . . . . . . . . . . . . . . . . . . $ 246 $ 238
2000. . . . . . . . . . . . . . . . . . . . . 214 207
2001. . . . . . . . . . . . . . . . . . . . . 217 210
2002. . . . . . . . . . . . . . . . . . . . . 112 105
2003. . . . . . . . . . . . . . . . . . . . . 83 76
Thereafter. . . . . . . . . . . . . . . . . . 91 91
------- -------
Total capacity payments . . . . . . . . . $ 963 $ 927
======= =======
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
A-68
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:
The Company TU Electric
------------------------ ----------
Capital Operating Operating
Year Leases Leases Leases
---- ------- -------- ---------
1999. . . . . . . . . . . . . . . . . . . . . . . $ 80 $ 190 $ 32
2000. . . . . . . . . . . . . . . . . . . . . . . 82 118 33
2001. . . . . . . . . . . . . . . . . . . . . . . 749 122 44
2002. . . . . . . . . . . . . . . . . . . . . . . 28 103 38
2003. . . . . . . . . . . . . . . . . . . . . . . 27 88 31
Thereafter. . . . . . . . . . . . . . . . . . . . 137 530 434
------- ------ ------
Total future minimum lease payments. . . . . 1,103 $1,151 $ 612
Less amounts representing interest. . . . . . . . (232) ====== ======
-------
Present value of future minimum lease payments. . $ 871
=======
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.
A-69
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.
A-70
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
A-71
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.
A-72
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.
The Company
Basic
Earnings
Consolidated Per Share of
Operating Revenues Operating Income Net Income Common Stock*
------------------ ------------------ --------------- ---------------
Quarter Ended 1998 1997 1998 1997 1998 1997 1998 1997
- -------------- ---- ---- ---- ---- ---- ---- ---- ----
March 31. . . . . . . . . $ 2,499 $1,494 $ 426 $ 382 $ 127 $ 115 $0.52 $0.51
June 30 . . . . . . . . . 3,236 1,588 474 460 83 161 0.33 0.72
September 30. . . . . . . 4,380 2,265 783 684 294 290 1.04 1.24
December 31 . . . . . . . 4,621 2,599 780 380 236 94 0.89 0.39
------- ------ ------- ------ ----- -----
$14,736 $7,946 $ 2,463 $1,906 $ 740 $ 660
======= ====== ======= ====== ===== =====
<FN>
* The sum of the quarters may not equal annual earnings per share due to
rounding. Diluted earnings per share for the quarter ended March 31,
1998 was $0.51. All other quarters were not different from basic earnings per
share.
</FN>
TU Electric
Consolidated
Operating Revenues Operating Income Net Income
------------------ ------------------ ---------------
Quarter Ended 1998 1997 1998 1997 1998 1997
- -------------- ---- ---- ---- ---- ---- ----
March 31. . . . . . . . . $ 1,332 $1,365 $ 270 $ 272 $ 137 $ 143
June 30 . . . . . . . . . 1,666 1,452 344 330 205 183
September 30. . . . . . . 2,123 1,851 498 477 365 322
December 31 . . . . . . . 1,367 1,467 221 268 91 124
------- ------ ------- ------ ----- -----
$ 6,488 $6,135 $ 1,333 $1,347 $ 798 $ 772
======= ====== ======= ====== ===== =====
A-73
16. PREFERRED STOCK OF TU ELECTRIC AND OTHER SUBSIDIARIES OF THE COMPANY
Redemption Price Per Share
(Before Adding
Shares Outstanding Amount Accumulated Dividends)
Dividend Rate December 31, December 31, December 31, 1998
- -------------- --------------- ---------------- --------------------------
1998 1997 1998 1997
---- ---- ---- ----
Thousands of Shares
Not Subject to Mandatory Redemption:
TU Electric (cumulative, without par value, entitled upon liquidation to $100 a share; authorized 17,000,000 shares)
$ 4.50 series . . . . . . . . . . . . . . . . . . . 22 22 $ 2 $ 2 $110.00
4.00 series (Dallas Power) . . . . . . . . . . . . 21 21 2 2 103.56
4.56 series (Texas Power). . . . . . . . . . . . . 53 53 5 5 112.00
4.00 series (Texas Electric) . . . . . . . . . . . 69 69 7 7 102.00
4.56 series (Texas Electric) . . . . . . . . . . . 22 22 2 2 112.00
4.24 series . . . . . . . . . . . . . . . . . . . 18 18 2 2 103.50
4.64 series. . . . . . . . . . . . . . . . . . . . 25 25 3 3 103.25
4.84 series. . . . . . . . . . . . . . . . . . . . 16 16 2 2 101.79
4.00 series (Texas Power). . . . . . . . . . . . . 27 27 3 3 102.00
4.76 series. . . . . . . . . . . . . . . . . . . . 23 23 2 2 102.00
5.08 series. . . . . . . . . . . . . . . . . . . . 28 28 3 3 103.60
4.80 series. . . . . . . . . . . . . . . . . . . . 21 21 2 2 102.79
4.44 series. . . . . . . . . . . . . . . . . . . . 34 34 3 3 102.61
8.20 series (a) (c). . . . . . . . . . . . . . . . - 147 - 14 -
7.98 series. . . . . . . . . . . . . . . . . . . . 261 261 26 26 (b)
7.50 series (a). . . . . . . . . . . . . . . . . . 308 308 30 30 (b)
7.22 series (a). . . . . . . . . . . . . . . . . . 221 221 21 21 (b)
----- ----- ----- -----
Total . . . . . . . . . . . . . . . . . . . . 1,169 1,316 115 129
----- ----- ----- -----
ENSERCH (entitled upon liquidation to stated value per share; authorized 2,000,000 shares)
Adjustable Rate Preferred Stock:
Series E (c) (d) . . . . . . . . . . . . . . . . - 100 - 100 -
Series F (d) . . . . . . . . . . . . . . . . . . 75 75 75 75 (b)
----- ----- ----- -----
Total . . . . . . . . . . . . . . . . . . . 75 175 75 175
----- ----- ----- -----
Total. . . . . . . . . . . . . . . . . 1,244 1,491 $ 190 $ 304
===== ===== ===== =====
TU Electric - Subject to Mandatory Redemption (e)
$ 6.98 series. . . . . . . . . . . . . . . . . . 107 107 $ 11 $ 11 (b)
6.375 series . . . . . . . . . . . . . . . . . 100 100 10 10 (b)
----- ----- ----- -----
Total. . . . . . . . . . . . . . . . . 207 207 $ 21 $ 21
===== ===== ===== =====
<FN>
(a) The preferred stock series is the underlying preferred stock for depositary
shares that were issued to the public. Each depositary share represents one
quarter of a share of underlying preferred stock.
(b) Preferred stock series is not redeemable at December 31, 1998.
(c) Preferred stock series redeemed in January 1998.
(d) Stated value $1,000 per share. The preferred stock series is the
underlying preferred stock for depositary shares that were issued to the
public. Each depositary share represents one-fortieth of a share for Series F
($25 per share). Dividend rates are determined quarterly, in advance, based
on certain US Treasury rates. At December 31, 1998, the Series F bears a
dividend rate of 4.5%.
(e) TU Electric is required to redeem at a price of $100 per share plus
accumulated dividends a specified minimum number of shares annually or
semi-annually on the initial/next dates shown below. These redeemable shares
may be called, purchased or otherwise acquired. Certain issues may not be
redeemed at the option of TU Electric prior to 2003. TU Electric may annually
call for redemption, at its option, an aggregate of up to twice the number of
shares shown below for each series at a price of $100 per share plus
accumulated dividends.
Minimum Redeemable Initial/Next Date of
Series Shares Mandatory Redemption
------- ------------------ ---------------------
$ 6.98 50,000 annually July 1, 2003
6.375 50,000 annually October 1, 2003
</FN>
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.
A-74
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.
A-75
US
US US Energy UK/ All
Electric Gas Marketing Europe Australia Other Eliminations Consolidated
-------- ------- --------- ------- --------- ----- ------------ ------------
Million of Dollars
Trade Revenues-
1998. . . . . . . . . $6,541 $822 $3,198 $3,601 $439 $135 $ - $14,736
1997. . . . . . . . . 6,176 409 859 - 489 13 - 7,946
1996. . . . . . . . . 6,077 - - - 474 - - 6,551
Affiliated Revenues-
1998. . . . . . . . . - 42 1 - - 337 (380) -
1997. . . . . . . . . - 19 - - - - (19) -
1996. . . . . . . . . - - - - - - - -
Depreciation and Amortization -
1998 . . . . . . . . 759 75 1 240 43 29 - 1,147
1997 . . . . . . . . 580 29 1 - 48 8 - 666
1996 . . . . . . . . 570 - - - 48 3 - 621
Equity in Earnings of Unconsolidated
Subsidiaries -
1998. . . . . . . . - - - 4 - (23) - (19)
1997. . . . . . . . - - - - - (27) - (27)
1996. . . . . . . . - - - - - (15) - (15)
Interest Income -
1998 . . . . . . . . 3 1 - 106 - 114 (85) 139
1997 . . . . . . . . 6 - - - - 26 - 32
1996 . . . . . . . . 2 - - - - 26 - 28
Interest Expense and Other Charges -
1998 . . . . . . . . 580 78 2 447 59 300 (85) 1,381
1997 . . . . . . . . 648 35 2 - 73 119 (25) 852
1996 . . . . . . . . 705 - - - 87 81 - 873
Income Tax Expense -
1998 . . . . . . . . 486 (6) 3 119 25 (101) - 526
1997 . . . . . . . . 408 5 (6) - 20 (50) - 377
1996 . . . . . . . . 405 - - - 13 (43) - 375
Net Income -
1998. . . . . . . . . 788 (32) 6 140 31 (193) - 740
1997. . . . . . . . . 748 (2) (12) - 17 (91) - 660
1996. . . . . . . . . 812 - - - 8 (66) - 754
Investment in Equity Investees -
1998. . . . . . . . . - - - - - 18 - 18
1997. . . . . . . . . - 6 - - - 145 - 151
1996. . . . . . . . . - - - - - 65 - 65
Total Assets -
1998 . . . . . . . . 19,028 4,133 1,369 14,332 1,432 13,479 (14,259) 39,514
1997 . . . . . . . . 19,544 2,533 577 - 1,436 9,242 (8,468) 24,864
1996 . . . . . . . . 19,534 - - - 1,728 7,263 (7,149) 21,376
Capital Expenditures -
1998. . . . . . . . . 506 185 2 341 63 76 - 1,173
1997. . . . . . . . . 453 56 1 - 49 27 - 586
1996. . . . . . . . . 384 - - - 35 15 - 434
A-76