================================================================================
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
-----------------------------------
FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 1997
--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
Commission in its Charter; Address of Principal I.R.S. Employer
File Number Executive 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
0-11442 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 Company Common Stock, without par value New York Stock Exchange
The Chicago Stock Exchange
The Pacific Exchange
Texas Utilities Electric Company Depositary Shares, Series A, each representing New York Stock Exchange
1/4 of a share of $7.50 Cumulative
Preferred Stock, without par value
Texas Utilities Electric Depositary Shares, Series B, each representing New York Stock Exchange
Company 1/4 of a share of $7.22 Cumulative
Preferred Stock, without par value
TU Electric Capital I, a 8.25% Trust Originated Preferred Securities New York Stock Exchange
subsidiary of Texas Utilities
Electric Company
TU Electric Capital III, a 8.00% Quarterly Income Preferred Securities New York Stock Exchange
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. [X]
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
13, 1998: $9,863,560,270.
Aggregate market value of Texas Utilities Electric Company Common Stock held by
non-affiliates: None
Common Stock outstanding at March 13, 1998:
Texas Utilities Company - 245,237,688 shares, without par value
Texas Utilities Electric Company - 142,931,000 shares, without par value
----------------------------------------------------
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement pursuant to Regulation 14A, which was
filed with the Commission on March 19, 1998, 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
PART I
Page
----
Item 1. BUSINESS.................................................. 1
Texas Utilities Company and Subsidiaries................ 1
Texas Energy Industries, Inc. and Subsidiaries.......... 3
ENSERCH Corporation and Subsidiaries.................... 5
Texas Utilities Electric Company and Subsidiaries....... 5
Electricity Peak Load and Capability.................... 6
Gas Distribution Peaking................................ 8
Fuel Supply and Purchased Power......................... 8
Regulation and Rates.................................... 12
Competition............................................. 17
Environmental Matters................................... 21
Item 2. PROPERTIES................................................ 24
Capital Expenditures.................................... 25
Item 3. LEGAL PROCEEDINGS......................................... 26
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS....... 26
EXECUTIVE OFFICERS OF THE COMPANY.................................. 27
PART II
Item 5. MARKET FOR EACH REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS ...................................... 28
Item 6. SELECTED FINANCIAL DATA................................... 28
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS....................... 29
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK............................................... 29
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA............... 29
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON
ACCOUNTING AND FINANCIAL DISCLOSURE....................... 29
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF EACH REGISTRANT....... 30
Item 11. EXECUTIVE COMPENSATION.................................... 33
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
AND MANAGEMENT............................................ 40
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS............ 40
PART IV
Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND
REPORTS ON FORM 8-K....................................... 41
APPENDIX A - Financial Information of Texas Utilities Company and Subsidiaries
and Texas Utilities Electric Company and Subsidiaries
APPENDIX B - Financial Information of ENSERCH Corporation and Subsidiaries
i
PART I
ITEM 1. BUSINESS
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
Texas Utilities Company (Company), a Texas corporation organized in 1996,
which was named as TUC Holding Company, is a holding company for its predecessor
companies, Texas Energy Industries, Inc. (TEI), formerly known as Texas
Utilities Company, and ENSERCH Corporation (ENSERCH). Through subsidiaries and
divisions of TEI and ENSERCH, the Company engages in the generation,
transmission and distribution of electricity; the processing, transmission,
distribution and marketing of natural gas; and telecommunications, power
development and other businesses. Additional information concerning TEI and
ENSERCH and their respective subsidiaries and divisions follows. The Company
holds no franchises other than its corporate franchise.
At December 31, 1997, the Company and its direct and indirect wholly-owned
subsidiaries (System Companies) had 14,751 full-time employees.
MERGERS AND ACQUISITIONS
Certain comparisons in this Form 10-K have been affected by the August 1997
acquisition of ENSERCH and the November 1997 acquisition of Lufkin-Conroe
Communications Co. (LCC) by the Company and by the December 1995 acquisition of
Eastern Energy Limited (Eastern Energy) by Texas Utilities Australia Pty. Ltd.
(TU Australia), a wholly-owned subsidiary of the Company. The results of each
acquired company are included only for the periods subsequent to acquisition.
On August 5, 1997, the merger transactions (Merger) between the former
Texas Utilities Company, now known as TEI, and ENSERCH were completed. At the
effective time of the Merger: (i) the former Texas Utilities Company changed its
name to TEI, (ii) TEI and ENSERCH merged with wholly-owned subsidiaries of TUC
Holding Company, which, as a result, owned all the common stock of TEI and of
ENSERCH, (iii) TUC Holding Company changed its name to Texas Utilities Company
(now the Company), (iv) each share of TEI's common stock was automatically
converted into one share of common stock of the Company, and (v) each share of
common stock of ENSERCH was automatically converted into 0.225 share of common
stock of the Company, with cash issued in lieu of fractional shares. The share
conversions were tax-free transactions. In the Merger, approximately 15. 9
million shares of the Company's common stock were issued to former holders of
ENSERCH common stock. The value assigned to the Company shares issued and costs
incurred in connection with the acquisition of ENSERCH aggregated $579 million.
At the date of the Merger, ENSERCH had debt and preferred stock outstanding of
approximately $1.3 billion.
On November 21, 1997, the Company acquired LCC. Approximately 8.7 million
shares of the Company's common stock were issued to LCC stockholders in a
stock-for-stock exchange. The value assigned to the Company shares issued and
costs incurred in connection with the acquisition of LCC aggregated $319
million. At the date of the acquisition, LCC had debt outstanding of
approximately $31 million. Immediately following the acquisition, the Company
contributed its investment in LCC to TEI.
The acquisitions of ENSERCH, LCC and Eastern Energy were accounted for as
purchase business combinations. The assets and liabilities of the acquired
companies at the acquisition dates were adjusted to their estimated fair values.
The excess of the purchase price paid by the Company over the estimated fair
value of 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 and liabilities of ENSERCH and LCC as of the date of acquisition is
continuing, and the final results await primarily the resolution of income tax
and other contingencies and finalization of some preliminary estimates.
1
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 continues to seek 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.
In January 1998, the Company announced that it had approached The Energy Group
PLC (TEG), a diversified international energy group, in connection with its
possible interest in acquiring TEG. TEG is the holding company for Eastern
Electricity PLC, which is one of the largest regional electric companies in the
United Kingdom (U.K.), one of the largest U.K. generators of electricity and one
of the largest U.K. suppliers of natural gas. On March 2, 1998, the Company
announced through its wholly owned subsidiary, TU Acquisitions PLC (TU
Acquisitions), an offer to holders of TEG securities, to acquire 100% of TEG's
ordinary shares, including the ordinary shares evidenced by American Depository
Receipts, which was increased on March 3, 1998 to an offer of (Pounds)8.40 per
share. Alternatively, up to 20% of the TEG shares may be exchanged for Company
common stock with a value of approximately (Pounds)8.65 per TEG share. There is
currently a competing offer for TEG shares at (Pounds)8.20 per share. The offer
by the Company is subject to certain conditions and to certain regulatory
consents and confirmations which the Company anticipates will be satisfactorily
resolved within the normal timetable for an offer in the U.K. As of March 17,
1998, the Company had acquired 21.96% of TEG's shares in the U.K. market. The
TEG businesses to be acquired by the Company (which exclude TEG's Peabody Coal
and Citizens Power businesses, which are to be sold by TEG to an unaffiliated
party in connection with the Company's offer) had assets of approximately $10.3
billion at September 30, 1997 and $5.2 billion of revenues for the twelve months
ended on that date. Such businesses had debt outstanding at September 30, 1997
of approximately $3.8 billion. The estimated purchase price for the TEG shares
is approximately $7.3 billion. The Company estimates that the financing
necessary to purchase all outstanding TEG shares at the (Pounds)8.40 price and
to pay all associated expenses will be approximately (Pounds)4.6 billion ($7.6
billion). The Company and TU Acquisitions and other intermediate U.K. holding
companies have entered into credit facilities with banking institutions in the
United States (U.S.) and the U.K., respectively, which will provide committed
financing sufficient to purchase the outstanding TEG shares and pay related
expenses. The U.S. credit facilities, which will aggregate $5.0 billion, will
replace the Company's current Credit Facilities described in Note 3 to the
Consolidated Financial Statements. The timing, amount and funding of any other
new business investment opportunities are presently undetermined.
2
The Company's more significant subsidiaries are as follows:
TEXAS ENERGY INDUSTRIES, INC.
Texas Utilities Electric Company
TU Electric Capital I Trust
TU Electric Capital III Trust
TU Electric Capital IV Trust
TU Electric Capital V Trust
Southwestern Electric Service Company
Texas Utilities Australia Pty. Ltd.
Eastern Energy Limited
Texas Utilities Fuel Company
Texas Utilities Mining Company
Lufkin-Conroe Communications Co.
Lufkin-Conroe Telephone Exchange, Inc.
Lufkin-Conroe Telecommunications Corp.
LCT Long Distance, Inc.
East Texas Fiber Line, Inc. (67% owned)
Texas Utilities Integrated Solutions Inc.
Texas Utilities Services Inc.
Texas Utilities Properties Inc.
Texas Utilities Communications Inc.
Basic Resources Inc.
Chaco Energy Company
Enserch Development Corporation
Lone Star Gas International, Inc.
National Pipeline Company
Enserch International Services, Inc.
ENSERCH CORPORATION
Lone Star Gas Company, a Division of ENSERCH Corporation
Lone Star Pipeline Company, a Division of ENSERCH Corporation
Enserch Processing, Inc.
Enserch Energy Services, Inc.
TU FINANCE (NO. 1) LIMITED
TU Finance (No. 2) Limited (90% owned by TU Finance (No. 1) Limited and
10% owned by Texas Utilities Services Inc.)
TU Acquisitions PLC
TEXAS ENERGY INDUSTRIES, INC. AND SUBSIDIARIES
TEI is a holding company whose principal subsidiary, Texas Utilities
Electric Company (TU Electric), is an operating public utility company engaged
in the generation, purchase, transmission, distribution and sale of electric
energy in the north central, eastern and western portions of Texas. For
information concerning TU Electric, see TU Electric below. Two other
subsidiaries of TEI are also engaged directly or indirectly in electric utility
operations. 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
126,900. 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 489,000 customers in a 31,000 square mile
distribution service area extending from the outer eastern suburbs of the
Melbourne metropolitan area to the eastern coastal areas of the State of
Victoria and north to the State of New South Wales border. References herein to
TU Australia include its subsidiary, Eastern Energy.
3
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)
and Lufkin-Conroe Telecommunications Corporation (LCT) and its subsidiaries.
LCTX is an independent local exchange carrier which has provided telephone
services for almost 100 years, and as of December 1997, was the fourth largest
telephone company in Texas (28th largest in the U.S.). LCTX has sixteen
exchanges that serve approximately 100,000 access lines in the Alto, Conroe and
Lufkin areas of southeast Texas. It also provides access services to a number of
interexchange carriers, who provide long distance services. LCT and its
subsidiaries own fiber optic cable systems which they lease to interexchange
carriers, provide Internet access, radio communications tower rentals, cellular
mobile telephones and radio paging services and private branch exchange service
to local customers. LCT, through a subsidiary, also provides interexchange long
distance service, with a primary focus on business customers.
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 services, customer services, procurement,
personnel and other administrative services, at cost, to the System Companies.
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 as agent for participants under the Company's
Automatic Dividend Reinvestment and Common Stock Purchase Plan.
Texas Utilities Properties Inc. (TU Properties) owns, leases and manages
real and personal properties, primarily the Company's corporate headquarters.
Texas Utilities Communications Inc. was organized to provide access to
advanced telecommunications technology, primarily for the Company's expected
expansion of the energy services business.
Basic Resources Inc. was organized for the purpose of developing natural
resources, primarily energy sources, and other business opportunities.
Chaco Energy Company (Chaco) was organized to own and operate facilities
for the acquisition, production, sale and delivery of coal and other fuels and
currently leases extensive coal reserves.
In December 1997, TEI acquired from ENSERCH the companies which had
constituted its power development and international gas distribution
operations. Enserch Development Corporation (EDC) develops and finances
independent electric power plant and cogeneration facilities. EDC's efforts are
currently focused on international projects. International gas operations,
which are conducted through Lone Star Gas International, Inc., National Pipeline
Company and Enserch International Services, Inc., are currently focused in
Mexico and Central and South America and consist primarily of minority
ownership in gas distribution systems.
TU Electric, SESCO, TU Australia, LCTX and LCT possess all of the necessary
franchises, licenses and certificates required to enable them to conduct their
respective businesses (see Regulation and Rates).
At December 31, 1997, TEI and its direct and indirect wholly-owned
subsidiaries had 11,758 full-time employees.
4
ENSERCH CORPORATION AND SUBSIDIARIES
ENSERCH is an integrated company focused on natural gas. Its major business
operations consist of the gathering, processing, transmission, distribution and
marketing of natural gas through the following companies.
Enserch Processing, Inc. (EPI) gathers and processes natural gas to remove
impurities and extract natural gas liquids for sale.
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 pipelines in the United States. 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 to Lone
Star Gas are regulated by the Railroad Commission of Texas (RRC) while rates
for services to other customers are generally only subject to RRC jurisdiction
through complaint proceedings.
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 United States and the largest in
Texas, Lone Star Gas provides service through over 23,800 miles of distribution
mains. Through these facilities, it purchases, distributes and sells natural gas
to over 1.35 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 Energy Services, Inc. (EES) is a wholesale and retail marketer of
natural gas in several areas of the U.S. Its primary U.S. retail markets are in
Texas, the Northeast, the Midwest and the West Coast. In January 1998, the
Federal Energy Regulatory Commission approved an Order authorizing EES to make
physical sales of electricity in the wholesale market throughout the U.S. other
than within the area of the Electric Reliability Council of Texas (ERCOT).
ENSERCH possesses all of the necessary franchises and certificates required
to enable it to conduct its business (see Regulation and Rates). See Appendix B
to this report for additional information concerning the various operations of
ENSERCH.
At December 31, 1997, ENSERCH and its direct and indirect wholly-owned
subsidiaries had 2,987 full-time employees.
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. TU Electric possesses all of the necessary franchises and
certificates required to enable it to conduct its business (see Regulation and
Rates). TU Electric is the principal subsidiary of the Company. References
herein to TU Electric include its financing subsidiaries (see Note 7 to
Consolidated Financial Statements included in Appendix A to this report).
5
TU Electric's service area is located in the north central, eastern and
western parts of Texas, with a population estimated at 6,020,000 -- about one-
third of the population of Texas. Electric service is provided in 91 counties
and 372 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. Its service territory
also includes the Dallas-Forth Worth International Airport and the 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, 1997, TU Electric had 6,053 full-time employees.
ELECTRICITY PEAK LOAD AND CAPABILITY
THE COMPANY AND TU ELECTRIC
- ---------------------------
The electricity peak load and net capability for the System Companies
include those of TU Electric, contained in the chart below, SESCO and Eastern
Energy. For SESCO, peak load was 238 megawatts (MW) on July 29, 1997 and for
Eastern Energy was 1,042 MW on February 19, 1997. SESCO and Eastern Energy
generate no electric energy.
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)
---- ---------- ------- ---------- ------ ----------
1997...... 22,449(c) 20,351 3.5% 19,229 3,220
1996...... 22,389(d) 19,668 2.5 18,930 3,459
1995...... 22,469(e) 19,180 6.4 18,631 3,619
- --------------------
(a) The 1997 peak load occurred on August 20. TU Electric's peak load includes
interruptible load at the time of peak of 1,122 MW in 1997, 738 MW in 1996
and 744 MW in 1995.
(b) Amount of net capability in excess of firm peak load at the time of peak.
(c) 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.
(d) Included in net capability is 1,164 MW of firm purchased capacity, all of
which is cogeneration and small power production.
(e) Included in net capability is 1,244 MW of firm purchased capacity, of which
1,164 MW is cogeneration and small power production.
TU ELECTRIC
- -----------
The peak load changes for 1997 as compared to 1996 resulted primarily from
customer growth and increased customer usage. The peak load changes for 1996
and 1995, 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 15 to Consolidated Financial Statements included in
Appendix A to this report.) Firm peak load increases over the next ten years
are expected to average approximately 1.7% annually, after consideration of load
management programs (including interruptible contracts).
6
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 in which 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 plan 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."
In January 1996, in accordance with an order of the PUC, TU Electric filed
an updated ten-year Integrated Resource Plan (IRP) with the PUC for the period
1996 through 2005 along with a proposed plan for the solicitation of resources
through a competitive bidding process. The PUC issued its final order on TU
Electric's IRP in October 1996, and modified the order in December 1996 and
February 1997. The modified order approved a flexible solicitation plan that
will allow TU Electric to conduct up to three optional resource solicitations
for a total of 2,074 MW of demand-side and supply-side resources prior to the
filing of its next IRP in June 1999. A large 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. Thus, the immediate need to issue a short-
term solicitation for additional resources was deferred past 1997. TU Electric
is also evaluating the possible extension of its remaining purchased power
contracts and exploring opportunities in the short-term market. TU Electric is
continuing to review the need and timing for conducting the resource
solicitations.
In addition to its solicitation plan in the IRP docket, TU Electric
requested and received approval from the PUC to expand its Power Cost Recovery
tariff to provide current cost recovery of resource acquisition costs for
demand-side management resources acquired in the 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.
RESOURCE ESTIMATES
The resource additions identified in TU Electric's 1998 IRP for the next
five years are as follows:
1998-2002
-------------------------
FIRM
CAPABILITY
RESOURCE ADDITIONS (MW) PERCENT
------------------ ---------- --------
Load management (a)....................... 376 20.5%
Renewable resources (b)................... 4 0.2
Long-term purchase (c).................... 25 1.4
Unspecified resources .................... 1,427 77.9
----- -----
Total................................. 1,832 100.0%
===== =====
- ---------------------
(a) TU Electric has executed an agreement to purchase 75 MW during the summer
peak months of 1998 and 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.
The exact timing of when retail competition will occur in Texas is unknown
at this time. Some areas in the U.S. already have retail competition (e.g.,
California), many others are considering it, including Texas. During the next
session of the Texas legislature, which will be in 1999, the issue of retail
competition will likely be discussed, 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) are speculative and likely to be in error. Thus, TU Electric is providing
only resource information for the next five years (1998-2002).
7
GAS DISTRIBUTION PEAKING
THE COMPANY
- -----------
Lone Star Gas estimates its peak-day availability from long-term contracts
and withdrawals from underground storage to be 1.4 billion cubic feet (Bcf).
Short-term peaking contracts and daily spot contracts raise this availability
level to meet anticipated sales needs.
During 1997, the average daily demand of Lone Star Gas' residential and
commercial customers was .3 Bcf. Lone Star Gas' greatest daily demand in 1997
was on January 13 when the arithmetic-mean temperature was 22 degrees F. and
deliveries to all customers reached 2.3 Bcf, including estimated deliveries to
residential and commercial customers of 2.1 Bcf.
FUEL SUPPLY AND PURCHASED POWER
THE COMPANY AND TU ELECTRIC
- ---------------------------
Net input for the System Companies during 1997 totaled 108,468 million
kilowatt-hours (kWh) of which 91,298 million kWh were generated by TU Electric.
Average fuel and purchased power cost (excluding capacity charges) per kWh of
net input for the Company and TU Electric were 1.97 and 1.84 cents for 1997,
1.94 and 1.79 cents for 1996 and 1.64 and 1.62 cents for 1995, respectively. The
Company's increase for 1997 primarily reflects TU Electric's increased natural
gas costs. 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 PER MILLION BTU
--------------------- -------------------
1997 1996 1995 1997 1996 1995
---- ---- ---- ---- ---- ----
Fuel for Electric Generation:
Gas/Oil (a)...................... 32.9% 33.0% 33.4% $2.80 $2.66 $2.31
Lignite/Coal (b)................. 38.9 39.6 37.4 1.04 1.03 1.02
Nuclear.......................... 17.1 15.0 17.9 0.57 0.56 0.59
----- ----- ----- ----- ---- ----
Total/Weighted Average Fuel Cost.. 88.9 87.6 88.7 $1.62 $1.58 $1.43
Purchased Power (c)............... 11.1 12.4 11.3
----- ----- -----
Total............................. 100.0% 100.0% 100.0%
===== ===== =====
- ------------------
(a) Fuel oil was an insignificant component of total fuel and purchased power
requirements.
(b) Lignite cost per ton to TU Electric was $13.24 in 1997, $13.22 in 1996 and
$13.05 in 1995.
(c) Excludes SESCO's and Eastern Energy's purchased power: 1997 - 543 million
kWh and 5,190 million kWh, respectively; 1996 -616 million kWh and 5,090
million kWh, respectively; 1995 - 865 million kWh and 335 million kWh,
respectively.
TU Electric, SESCO and Eastern Energy 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 any 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.)
GAS/OIL
TU ELECTRIC
- -----------
Fuel gas for units at nineteen of the principal generating stations of TU
Electric, having an aggregate net gas/oil capability of 13,100 MW, was provided
during 1997 by Fuel Company. Fuel Company supplied
8
approximately 16% of such fuel gas requirements under contracts with producers
at the wellhead and 84% under contracts with commercial suppliers.
THE COMPANY
- -----------
Fuel Company -- 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 have generally required utilization of fuel oil
and gas storage inventories to replace the gas curtailed. During 1997, Fuel
Company experienced no curtailments.
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 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 and has a total estimated capacity of 885 million cubic feet per day with
existing compression facilities. 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 1,550 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 28.2 Bcf with approximately 14.8 Bcf of gas
in inventory at December 31, 1997. 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.
Fuel oil can be stored at eighteen of the principally gas-fueled generating
stations. At December 31, 1997, the System Companies had fuel oil storage
capacity sufficient to accommodate approximately 6.2 million barrels of oil,
with approximately 2.3 million barrels of oil in inventory.
Lone Star Gas -- 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 gas supply as of January 1, 1998, was 489
Bcf, which is approximately three times Lone Star Gas' purchases during 1997. Of
this total, 130 Bcf are specific reserves and 34 Bcf are working gas in storage.
Management has calculated that 325 Bcf, including 131 Bcf under one contract,
are committed to Lone Star Gas under gas supply contracts not related to
specific reserves or fields. In 1997, Lone Star Gas' gas requirement was
purchased from some 125 independent producers and non-affiliated pipeline
companies, one of which supplied approximately 28% of total requirements.
To meet peak-day gas demands during winter months, Lone Star Gas utilizes
the service of seven affiliated gas storage fields, all of which are located in
Texas. These fields have a working gas capacity of 47 Bcf and a day-one storage
withdrawal capacity of 1.3 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
9
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.
The Lone Star Gas supply program is designed to contract for new supplies
of gas (and to recontract targeted expiring sources) connected to Lone Star
Pipeline's pipeline system. 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.
Lone Star Gas buys gas under long-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 1998 and thereafter.
LIGNITE/COAL
TU ELECTRIC
- -----------
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 508 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 270 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 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 two-year contract scheduled to expire on December 31, 1998.
10
TU Electric currently plans to supplement its lignite fuel at Martin Lake
and Big Brown utilizing western coal to be delivered by the year 2000.
Construction of a 25 mile rail spur into Big Brown to facilitate the delivery of
the western coal will begin later this year.
THE COMPANY
- -----------
Chaco has a coal lease agreement for the rights to certain surface minable
coal reserves located in New Mexico. The agreement encompasses a minimum of 228
million tons of coal with provisions for advance royalty payments to be made
annually through 2017. The Company has entered into a surety agreement to assure
the performance by Chaco with respect to this agreement. Because of the present
ample availability of western coal at favorable prices from other mines, Chaco
has delayed plans to commence mining operations, and accordingly, is reassessing
its alternatives with respect to its coal properties including seeking
purchasers thereof. (See Item 2. Properties and Management's Discussion and
Analysis of Financial Condition and Results of Operation and Notes 14 and 15 to
Consolidated Financial Statements included in Appendix A to this report.)
NUCLEAR
TU ELECTRIC
- -----------
TU Electric owns and operates two nuclear-fueled generating units at the
Comanche Peak nuclear generating station (Comanche Peak), each of which is
designed for a net capability of 1,150 MW. (See Electricity Peak Load and
Capability.)
The nuclear fuel cycle requires the mining and milling of uranium ore to
provide uranium oxide concentrate (U\\3\\O\\8\\), the conversion of U\\3\\O\\8\\
to uranium hexafluoride (UF\\6\\), the enrichment of the UF\\6\\ 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 (2002). Although TU
Electric cannot predict the future availability of uranium and nuclear fuel
services, TU Electric does not currently expect to have difficulty obtaining
U\\3\\O\\8\\ 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 1998 federal fiscal year,
as calculated by the DOE, is $994,000.
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 December
1996, the DOE notified program participants that it did not expect to meet its
obligation to begin acceptance of spent nuclear fuel by 1998. The DOE continues
to maintain its position despite a U.S. Court of Appeals decision affirming the
Company's position that such an obligation exists. TU Electric is unable to
predict what impact, if any, the DOE delay will have on TU Electric'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.
Currently, TU Electric's onsite storage capability for spent nuclear fuel
is sufficient to accommodate the operation of Comanche Peak through the year
2000, while fully maintaining the capability to off-load one of the nuclear-
fueled generating unit's core. TU Electric is currently pursuing options for
increasing its storage capability, subject to approval by the Nuclear Regulatory
Commission (NRC).
11
PURCHASED POWER
THE COMPANY AND TU ELECTRIC
- ---------------------------
In 1997, System Companies purchased a net of 17,170 million kWh or
approximately 16% of their energy requirements. TU Electric and SESCO had
available 1,292 MW of firm purchased capacity under contract, including 60 MW of
short-term firm capacity to meet the 1997 summer peak. During 1997, TU Electric
extended, from 1999 to 2002, an existing contract which increased the purchase
of capacity from 410 MW to 435 MW. In July 1998, SESCO will begin receiving
power under a full requirements contract with another supplier and will no
longer receive power from TU Electric. Beginning in 1999, TU Electric expects to
receive energy under a contract with a developer for the purchase of energy
produced from wind turbines equivalent to approximately 35 MW (or approximately
4 MW of firm capacity at peak). The proposed facility will include four of the
largest commercial wind turbines in the world, rated at 1.65 MW each. 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 resources
requirements, see the Electricity Peak Load and Capability section.)
Eastern Energy and other distribution and retail companies in the State of
Victoria, Australia purchase their electric energy needs from a competitive
power pool owned and operated by the Victorian government. A full national
market will commence in 1998 among the participants in the States of New South
Wales, Victoria, Queensland, South Australia and the Australian Capital
Territory, and will be operated by a corporation owned by the governments of
those jurisdictions. While the spot price of electric energy from the pool can
vary substantially, 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
Operation and Note 9 to Consolidated Financial Statements included in Appendix A
to this report).
REGULATION AND RATES
GENERAL
THE COMPANY
- -----------
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.
The System Companies are also subject to various other federal, state and
local regulations. (See discussion below and Environmental Matters.)
THE COMPANY AND TU ELECTRIC
- ---------------------------
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 which are involved in such interstate activities,
except during the continuance of emergencies permitting temporary or permanent
connections or under order of the Federal Energy Regulatory Commission (FERC)
exempting TU Electric and SESCO from jurisdiction under the Federal Power Act.
In view thereof, TU Electric and SESCO 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.
12
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.
LCC is not subject to direct rate or service regulation. However, its
affiliates, LCTX and LCT Long Distance, Inc. (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 their rates are
subject to competition from a large number of interexchange long distance
service providers.
Lone Star Gas and Lone Star Pipeline are wholly intrastate in character and
perform distribution utility operations and transportation services in the State
of Texas subject to regulation by the RRC and municipalities in Texas. The RRC
regulates the charge for the transportation of gas by Lone Star Pipeline to Lone
Star Gas' distribution systems for sale to Lone Star Gas' residential and
commercial consumers. Lone Star Pipeline owns no certificated interstate
transmission facilities subject to the jurisdiction of FERC under the Natural
Gas Act, has no sales for resale under the rate jurisdiction of FERC and does
not perform any transportation service that is subject to FERC jurisdiction
under the Natural Gas Act.
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 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
jursidication.
In October 1996, Lone Star Pipeline filed a request with the RRC to
increase the rate it charges Lone Star Gas to store and transport gas ultimately
destined for residential and commercial customers in the 550 Texas cities and
towns served by Lone Star Gas. Lone Star Gas also requested that the RRC
separately set rates for costs to aggregate gas supply for these cities. Rates
previously in effect were set by the RRC in 1982. In September 1997, the RRC
issued an order reducing the charges by Lone Star Pipeline to Lone Star Gas for
storage and transportation services. In that order, the RRC did authorize
separate charges for the Lone Star Pipeline storage and transportation services,
a separate charge by Lone Star Gas for the cost of aggregating gas supplies, and
a continuation of the 100% flow through of purchased gas expense. The RRC also
imposed some new criteria for affiliate gas purchases and a new reconciliation
procedure that will require a review of purchased gas expenses every three
years. The RRC order has become final, but is being appealed by several parties
including Lone Star Pipeline and Lone Star Gas. The rates authorized by the
order became effective on December 1, 1997, and will result in an annual margin
reduction of approximately $8.2 million.
On August 20, 1996, the RRC ordered a general inquiry into the rates and
services of Lone Star Gas, most notably a review of Lone Star Gas' historic gas
cost and gas acquisition practices since the last rate setting. The inquiry
docket has been separated into different phases. Two of the phases, conversion
to the NARUC account numbering system and unbundling, have been dismissed by the
RRC, and one other phase, rate case expense, is pending RRC action on the basis
of a stipulation of all parties. In the phase dealing with historic gas cost and
gas
13
acquisition practices, Lone Star Gas and Lone Star Pipeline have filed a motion
for summary disposition stating that any retroactive rate action would be
inappropriate and unlawful. Settlement discussions with intervenor cities are
ongoing. If the motion for summary disposition is denied, a hearing has been
scheduled to begin in August 1998. A number of management and transportation
related issues have been placed in a separate phase which still has an undefined
scope and is being held in abeyance pending the resolution of the phase dealing
with gas costs. Management believes that gas costs were prudently incurred and
were properly accounted for and recovered through the gas cost recovery
mechanism previously approved by the RRC. At this time, management is unable to
determine the ultimate outcome of the inquiry.
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 see if it
will be effective for the period commencing after December 31, 2000.
TU ELECTRIC
- -----------
DOCKET 9300
The PUC's final order (Order) in connection with TU Electric's January 1990
rate increase request (Docket 9300) was reviewed by the 250th Judicial District
Court of Travis County, Texas (District Court) and thereafter was appealed to
the Court of Appeals for the Third District of Texas and to the Supreme Court of
Texas (Supreme Court). As a result of such review and appeals, 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 would also be 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 January 1997, the Supreme
Court denied a motion for rehearing on the Comanche Peak minority owners issue
filed by the original complainants. TU Electric cannot predict the outcome of
the reconsideration of the Order on remand by the PUC.
In its decision, the Supreme Court also affirmed the previous $472 million
prudence disallowance related to Comanche Peak. Since the Company and TU
Electric each has previously recorded a charge to earnings for this prudence
disallowance, the Supreme Court's decision did not have an effect on the
Company's or TU Electric's current financial position, results of operation or
cash flows.
DOCKET 11735
In July 1994, TU Electric filed a petition in the 200th Judicial District
Court of Travis County, Texas to seek judicial review of the final order of the
PUC granting a $449 million, or 9.0%, rate increase in connection with TU
Electric's January 1993 rate increase request of $760 million, or 15.3% (Docket
11735). Other parties to the PUC proceedings also filed appeals with respect to
various portions of the order.
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 adopted in February 1996. These tariffs also
provide for generation-related ancillary services necessary to support wholesale
transactions. 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 will 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. As such, the
current maximum impact on TU Electric for 1998 is an $8.52 million deficit,
which, in the
14
opinion of TU Electric, is not expected to have a material effect on its
financial position, results of operation or cash flows.
TU Electric joined a lawsuit in state district court challenging the
validity of the cost-shifting aspects of the PUC wholesale open-access rules. In
December 1997, the District Court judge issued a decision upholding the validity
of the PUC pricing rules.
DOCKET 17250
In late 1996, as part of its regular earnings monitoring process, the PUC
staff advised the PUC, after reviewing the 1995 Electric Investor-Owned
Utilities Earnings Report of TU Electric, that it believed TU Electric was
earning in excess of a reasonable rate of return, and the PUC and TU Electric
subsequently began discussions concerning possible remedies. It was decided to
limit negotiations to a resolution of issues concerning TU Electric's earnings
through 1997, and discussion of a longer-term resolution was deferred. In July
1997, the PUC issued its final written order approving TU Electric's proposal to
make a one-time $80 million refund to its customers (Rate Settlement) and to
leave rates unchanged during the remainder of 1997. TU Electric recorded the
charge to revenues in July 1997 and included the refunds in August 1997
billings. The proposal was the result of a joint stipulation in which TU
Electric was joined by the PUC General Counsel, on behalf of the PUC Staff and
the public interest, the Office of Public Utility Counsel, the state agency
charged with representing the interests of residential and small commercial
customers, and the Coalition of Cities served by TU Electric.
DOCKET 18490
On December 17, 1997, TU Electric, together with the PUC General Counsel,
the Office of Public Utility Counsel and various other parties interested in TU
Electric's rates and services, filed with the PUC a stipulation and joint
application which, if granted, would among other things: (i) result in permanent
retail 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, (ii) result in additional permanent retail base rate credits
beginning January 1, 1999, of 1.4% for residential customers, (iii) impose a
11.35% cap on TU Electric's rate of return on equity during 1998 and 1999, with
any sums earned above that cap being applied as additional nuclear production
depreciation, (iv) allow TU Electric to record depreciation applicable to
transmission and distribution assets in 1998 and 1999 as additional depreciation
of nuclear production assets, (v) establish an updated cost of service study
that includes interruptible customers as customer classes, (vi) result in the
permanent dismissal of pending appeals of prior PUC orders including Docket No.
11735, if all other parties that have filed appeals of those dockets also
dismiss their appeals, (vii) result in the stay of any proceedings in the remand
of Docket 9300 prior to January 1, 2000, and (viii) result in all gains from
off-system sales of electricity in excess of the amount included in base rates
being flowed to customers through the fuel factor.
The PUC has until March 31, 1998 to approve or reject the stipulation and
joint application. Otherwise, TU Electric may terminate the base rate
reductions and all other aspects of the proposal upon giving two weeks notice to
the PUC.
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, as defined by the PUC, cumulative under- or
over-recovery of fuel costs. If the cumulative difference of the under- or over-
recovery, plus interest, is in excess of 4% of the annual estimated fuel costs
most recently approved by the PUC, it will be deemed to be material. In
accordance with PUC approvals, TU Electric has, since the inception of the rule
in 1986, made thirteen refunds of over-collected fuel costs and two surcharges
of under-collected fuel costs. The most recent refund was made pursuant to a
petition filed by TU Electric in July 1997 to refund approximately $67 million,
including interest, in over-collected fuel costs for the period October 1995
through May 1997 (Fuel Refund). Such
15
over-collection was primarily due to TU Electric's ability to use less expensive
nuclear fuel and purchased power to offset a higher-priced natural gas market
during the period. Customer refunds were included in August 1997 billings. A
final order confirming the Fuel Refund was entered by the PUC in October 1997.
The two surcharges (one in the amount of $147.3 million and the other in the
amount of $93 million) have been appealed by certain intervenors to district
courts of Travis County, Texas. In those appeals, those parties are contending
that the PUC is without authority to allow a fuel cost surcharge without a
hearing and resultant findings that the costs are reasonable and necessary and
that the prices charged to TU Electric by supplying affiliates are no higher
than the prices charged by those affiliates to others for the same item or class
of items. TU Electric is unable to predict their outcome.
The fuel cost recovery rule also contains a procedure for an expedited
change in the fixed fuel factor in the event of an emergency. 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 like SESCO, 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
In July 1997, the PUC ruled on TU Electric's petition seeking final
reconciliation of all eligible fuel and purchased power expenses incurred during
the reconciliation period of July 1, 1992 through June 30, 1995 (approximately
$4.7 billion). In the ruling, the PUC disallowed approximately $81 million of
eligible fuel related costs (including interest of $12 million) incurred during
the reconciliation period (Fuel Disallowance). The majority of the Fuel
Disallowance (approximately $67 million) is related to replacement fuel costs as
a result of the November 1993 collapse of the emissions chimney serving Unit 3
of the Monticello lignite-fueled generating station. In addition, the PUC ruled
that approximately $10 million from the gain on sale of sulfur dioxide
allowances should be deferred and reconsidered at a future date. TU Electric
received a final written order from the PUC and recorded the charge to revenues
in August 1997. TU Electric strongly disagrees with the Fuel Disallowance and
continues to vigorously defend its position. TU Electric has appealed the PUC's
order to the District Court of Travis County, Texas.
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 existing 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
existing 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.
16
COMPETITION
THE COMPANY AND TU ELECTRIC
- ---------------------------
GENERAL
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 competition
is affected by a number of variables, including price, reliability of service,
the cost of energy alternatives, new technologies and governmental regulations.
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 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. Although the Company is
unable to predict the ultimate impact of the Energy Policy Act, PURA and any
related regulations or legislation on the System Companies' operations, it
believes that such actions are consistent with the trend toward increased
competition in the energy industry.
In order to remain competitive, the System 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 their 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.
While TU Electric has experienced competitive pressures in the wholesale
market resulting in a small loss of load since the beginning of 1993, wholesale
sales represented a relatively low percentage of TU Electric's consolidated
operating revenues in 1997. TU Electric is unable to predict the extent of
future competitive developments in either the wholesale or retail markets or
what impact, if any, such developments may have on its operations.
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. Competition in the electric utility
industry was also addressed in the 1995 session of the Texas legislature. PURA
was amended to encourage greater wholesale competition and flexible retail
pricing. PURA amendments also 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, 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 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 (i.e., costs of assets that may
not be recoverable from customers as a result of competitive pricing). 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 $7.7
billion to a projected excess of market value over net book value of $2.1
billion. Legislation that would have authorized retail competition was not
enacted by the 1997 Texas legislature.
17
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
who are not subject to the traditional governmental regulation experienced by
the energy and utility industries 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 and the
cost of certain of its assets becoming stranded costs. To the extent stranded
costs cannot be recovered from customers, it may be necessary for such costs to
be borne partially or entirely 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 System Companies continue 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 Operation and Note 2 to Consolidated Financial Statements included in
Appendix A to this report.)
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. While monitored by regulatory authorities, rates for these
long distance services are largely market based and have been essentially
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 to be handled 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.
Recent changes in federal and state law have applied equal access principles to
this service sector and it is anticipated that competition will likely become
more intense beginning in mid-1998.
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.
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. Sales by ENSERCH's non-
regulated companies, along with transportation services provided by Lone Star
Pipeline, have served to offset much of the effects of this decline. 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 U.S. markets.
18
Natural gas liquids processing is highly competitive and includes
competition among producers, third-party owners and processors for cost-sharing
and interest-sharing arrangements.
EES pursues markets connected to pipelines other than Lone Star Pipeline's.
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.
RETAIL ELECTRIC MARKET
TU Electric and SESCO 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, TU
Electric and SESCO currently have the exclusive right to provide electric
service to the public within their 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. TU Electric and SESCO are pursuing efforts
to remain competitive through competitive pricing, economic development and
other initiatives. (See Regulation and Rates.)
Congress, as well as legislatures and regulatory commissions in several
states, have begun to examine the possibility of mandated "retail wheeling," 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,
subject to the practical constraints of long distance transmission. To date,
retail wheeling has not been implemented in Texas; however, this issue is likely
to be pursued again during the 1999 session of the Texas legislature and in the
106th Congress.
While the Company and TU Electric anticipate legislation being enacted
during the 1999 session of the Texas legislature to authorize competition in the
retail market, 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
operation or cash flows.
The energy supply franchise portion of Eastern Energy's business is
gradually being exposed to competition through a phase-in of customers' right 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 suppliers and distribution companies to those customers
having a right to choose their supplier, and Eastern Energy can similarly supply
electric energy to such customers in other service territories by utilizing the
distribution networks of the distribution companies in those service
territories. A national electricity market continues to develop in Australia,
with full contestabilty for all customers to be phased in progressively through
2001. Eastern Energy currently has a license to provide retail electricity in
New South Wales and may pursue retail licences in other states.
TU Electric, SESCO and Eastern Energy are not able to predict the extent of
future competitive developments or what impact, if any, such developments may
have on their operations.
19
TU ELECTRIC
- -----------
WHOLESALE MARKET
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 has received notifications of termination of
approximately 700 MW of wholesale load through 1999. In 1997, wholesale
revenues represented about 3% of TU Electric's total consolidated operating
revenues.
Amendments to PURA made during the 1995 session of the Texas legislature
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.
OPEN-ACCESS TRANSMISSION
In February 1996, pursuant to the 1995 amendments to PURA, 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
consisting of an ERCOT system-wide component and a distance-sensitive component.
The ERCOT system-wide component provides that each load-serving entity in ERCOT
will pay a share of the ERCOT-wide transmission cost of service based on the
entity's load. The distance-sensitive component provides that a distance-
sensitive rate will be paid to utilities that own transmission facilities, based
on the impact of transmitting power and energy to loads. The rates charged for
using the transmission system are designed to ensure that all market
participants pay on a comparable basis to use the system. While all users of
the transmission grid pay rates that are comparably designed, the impact on
individual users will differ.
In May 1996, TU Electric filed with the PUC, under Docket 15638, its
transmission cost information and tariffs for open-access wholesale transmission
service. These tariffs also provide for generation-related ancillary services
necessary to support wholesale transactions. Company-specific proceedings to
determine transmission rates for each transmission provider within ERCOT were
concluded in 1996. In August 1997, the PUC approved final tariffs for TU
Electric and implemented rates for other transmission providers within ERCOT.
(See Regulation and Rates.)
As a result of the PUC rules, the organization and structure of ERCOT has
been changed to provide for equal governance among all wholesale electricity
market participants. These changes were made in order to facilitate wholesale
competition while ensuring continued reliability within ERCOT.
At the federal level, the Energy Policy Act empowers the FERC to require
utilities to provide transmission service for the delivery of wholesale power
from other power producers to qualified resellers, such as municipalities,
cooperatives and other utilities. In April 1996, the FERC issued Order No. 888
which requires all FERC-jurisdictional electric utilities to offer third parties
wholesale transmission services under an open-access tariff and provides a
framework for recovery of "legitimate, prudent and verifiable stranded costs"
resulting from the implementation of open-access wholesale transmission service.
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 (TFO Tariff) between ERCOT and the Southwest Power Pool. This
modification conformed TU Electric's TFO Tariff to the rates, terms and
conditions governing open-access wholesale transmission service within ERCOT
previously approved by the PUC. In October 1997, the FERC accepted TU Electric's
TFO Tariff with minor modifications.
20
THE COMPANY
- -----------
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.
ENVIRONMENTAL MATTERS
THE COMPANY AND TU ELECTRIC
- ---------------------------
GENERAL
The System Companies 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 new 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 constructed 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 required from
time to time in order to maintain compliance with these 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 will require 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 the 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, compliance with the applicable
Phase II sulfur dioxide requirements is not expected to have a significant
impact on TU Electric. In January 1993, the EPA issued its "core" regulations to
implement the sulfur dioxide reduction program. TU Electric is preparing
compliance plans in accordance with these regulations and expects these plans to
be implemented by January 1, 2000.
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.
21
TU Electric's generating units meet the nitrogen oxide (NOx) limits
currently required by the Clean Air Act. The TNRCC and the EPA have determined
that the requirements of the Clean Air Act for ozone nonattainment areas will
not require NOx emission reductions at TU Electric's generating units in the
Dallas-Fort Worth area; however, the TNRCC is re-evaluating its position since
the Dallas-Fort Worth area did not achieve attainment of the ozone standard in
1996 as required by Clean Air Act regulations. 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 ozone and of 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 is unable to predict whether the Kyoto Protocol will be
ratified by the United States Congress and to what extent, if any, such protocol
might impact the Company.
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. 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 System 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 System 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 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. (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.) 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. For ENSERCH facilities, certain emission sources may
be required to reduce emissions or to install monitoring equipment under
proposed rules and regulations. The Company currently believes, 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'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 System Companies' domestic facilities. The
System Companies' domestic 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 satisfy the requirements necessary to obtain
any required permits or renewals.
22
OTHER
Diversion, impoundment and withdrawal of water for cooling and other
purposes are subject to the jurisdiction of the TNRCC. System Companies,
including TU Electric, 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 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 System Companies' domestic
facilities. The Company has registered its solid waste disposal sites and has
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 will begin in 1999.
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 is taking steps to site,
construct and operate a low-level radioactive waste disposal site by 1999 and
submitted a license application in March 1992 for such a facility. The license
application has been finalized and a contested Administrative Hearing on the
adequacy of the application began in January 1998. The State of Texas has agreed
to a compact with the States of Maine and Vermont, which is subject to
ratification by Congress, for such a facility. Low-level waste material will
continue to be shipped off-site as long as an alternate disposal site is
available. Otherwise the low-level waste material will be stored on-site. TU
Electric's on-site storage capacity is expected to be adequate until other
facilities are available.
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.
23
ITEM 2. PROPERTIES
THE COMPANY AND TU ELECTRIC
- ---------------------------
The Company does not directly own utility plant or real property. At
December 31, 1997, TU Electric owned or leased and operated the following
generating units:
ELECTRIC NET
GENERATING CAPABILITY
UNITS FUEL SOURCE (MW) %
- ---------- ----------- ---------- ----
46 Natural Gas (a).............. 12,105 57.0%
9 Lignite/Coal................. 5,825 27.5
2 Nuclear...................... 2,300 10.8
15 Combustion Turbines (b)...... 975 4.6
10 Diesel....................... 20 0.1
------ ----
Total 21,225 100.0%
====== =====
- ------------------------
(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.
The principal generating facilities of TU Electric and load centers of TU
Electric and SESCO are connected by 3,863 circuit miles of 345,000 volt
transmission lines and 9,327 circuit miles of 138,000 and 69,000 volt
transmission lines.
TU Electric is connected by six 345,000 volt lines to Houston Lighting &
Power Company; by three 345,000 volt, eight 138,000 volt and nine 69,000 volt
lines to West Texas Utilities Company; by two 345,000 volt and eight 138,000
volt lines to the Lower Colorado River Authority; by four 345,000 volt and eight
138,000 volt 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 138,000 volt lines, ten 69,000 volt lines and three lines at
distribution voltage. 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 and is responsible for
ensuring equal access to transmission service by all wholesale market
participants in the ERCOT region.
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 System 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.
24
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.
LCC and its affiliates provide a full range of telecommunications services
over a variety of state of the art facilities. As of December 31, 1997, LCC's
local exchange affiliate, LCTX, provided service to 97,959 access lines and
74,287 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 the three rural service areas.
At December 31, 1997, 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 76,455. 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, 1997, EPI had interests in 15 processing plants, 10 of which
were wholly owned, and operated approximately 1,714 miles of gathering lines. At
December 31, 1997, Lone Star Gas operated approximately 23,800 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 some
of its affiliates. In addition, ENSERCH leases a 21-story, 400,000 square-foot
building in Houston under a two-year lease that is automatically extended each
year unless terminated. This building is sub-leased, primarily to non-affiliated
parties.
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, and expects to generate revenue by offering competitively
priced business office space to interested parties. TU Properties has entered
into a tenant agreement with TU Services on behalf of the System Companies that
allows the System Companies to occupy certain office space in Energy Plaza at a
market price.
CAPITAL EXPENDITURES
THE COMPANY AND TU ELECTRIC
- ---------------------------
The Company has taken steps to aggressively manage its construction
expenditures. Such construction expenditures for utility related activities,
excluding allowance for funds used during construction, (see Note 15 to
Consolidated Financial Statements included in Appendix A to this report) are
presently estimated at $886 million, $799 million and $852 million for the
Company and $449 million, $439 million and $441 million for TU Electric for each
of the years 1998, 1999, and 2000, respectively. The System Companies are
subject to federal, state and local regulations dealing with environmental
protection. (See Item 1. Business - Environmental Matters.) Such expenditures
for construction to meet the requirements of environmental regulations at
existing generating units are estimated to be $27 million for 1998 (included in
the 1998 construction estimates noted above) and were approximately $33 million
in 1997, $14 million in 1996 and $64 million in 1995. Expenditures for nuclear
fuel are presently estimated to be $104 million, $81 million and $92 million for
the Company and TU Electric for each of the years 1998, 1999 and 2000,
respectively.
25
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 -Electricity
Peak Load and Capability.)
The Company and TU Electric continue to seek 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. In January 1998, the Company announced that it had
approached The Energy Group PLC (TEG), a diversified international energy group,
in connection with its possible interest in acquiring TEG. (See Item 1.
Business - Texas Utilities Company and Subsidiaries - Mergers and Acquisitions.)
The estimated purchase price for the TEG shares is approximately $7.3 billion.
The Company estimates that the financing necessary to purchase all outstanding
TEG shares and to pay all associated expenses will be approximately (Pounds)4.6
billion ($7.6 billion). The Company and TU Acquisitions and other intermediate
U.K. holding companies have entered into credit facilities with banking
institutions in the U.S. and the U.K., respectively, which will provide
committed financing sufficient to purchase the outstanding TEG shares and pay
related expenses. The U.S. credit facilities, which will aggregate $5.0
billion, will replace the Company's current Credit Facilities described in Note
3 to the Consolidated Financial Statements. The timing, amount and funding of
any other new business investment opportunities are presently undetermined.
For information regarding the financing of capital expenditures, see
Management's Discussion and Analysis of Financial Condition and Results of
Operation included in Appendix A to this report.
ITEM 3. LEGAL PROCEEDINGS
THE COMPANY AND TU ELECTRIC
- ---------------------------
The Company and its subsidiaries are party to lawsuits arising in the
ordinary course of its 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
THE COMPANY AND TU ELECTRIC
- ---------------------------
None.
26
---------------------------------------------
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, 1998) MAY 8, 1998) (PRECEDING FIVE YEARS)
- --------------- --- ----------------------- ---------------------- -----------------------------------------
Erle Nye 60 Chairman of the Board May 23, 1997 Chairman of the Board and Chief Executive
Chief Executive of and Director the Company,
TU Electric and ENSERCH
Corporation; prior thereto,
President and Chief
Executive of the Company and
Chairman of the Board and Chief
Executive of TU Electric.
David W. Biegler 51 President and Chief August 5, 1997 President and Chief Operating Officer of
Operating Officer the Company, TU Electric and
ENSERCH Corporation; prior
thereto, Chairman, President and
Chief Executive Officer of
ENSERCH Corporation.
H. Jarrell Gibbs 60 Vice Chairman of August 5, 1997 Vice Chairman of the Board; prior thereto,
the Board President of TU Electric; prior
thereto, Vice President and
Principal Financial Officer of
the Company.
Michael J. McNally 43 Executive Vice President May 23, 1997 Executive Vice President and Chief
and Chief Financial Financial Officer; prior
Officer 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.
27
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 1997 and 1996 were as follows:
Price Range Dividends Paid
------------------------------------ --------------
Quarter Ended 1997 1996 1997 1996
- ------------- ----------------- ----------------- ------ ------
High Low High Low
-------- ------- --------- ------
March 31....... $42.0000 $33.7500 $42.8750 $38.8750 $0.525 $0.50
June 30........ 37.0000 31.5000 42.7500 38.5000 0.525 0.50
September 30... 36.1875 33.5000 43.7500 39.3750 0.525 0.50
December 31.... 41.8125 34.1875 42.1250 38.7500 0.525 0.50
------ -----
$2.100 $2.00
====== =====
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 1998 meeting, declared a quarterly
dividend of $0.55 a share, payable April 1, 1998 to shareholders of record on
March 6, 1998. For information concerning the Company's dividend policy, see
Management's Discussion and Analysis of Financial Condition and Results of
Operation 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 5
to Consolidated Financial Statements included in Appendix A to this report
regarding limitations upon payment of dividends on common stock of TU Electric
and SESCO.
The number of record holders of the common stock of the Company as of March
13, 1998 was 88,868.
TU ELECTRIC
- -----------
All of TU Electric's common stock is owned by the Company. Reference is
made to Note 5 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.
28
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATION
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 Operation 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 Operation 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 Cash Flows,
Consolidated Balance Sheets, Statements of Consolidated Common Stock Equity, and
Notes to Consolidated Financial Statements included 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.
29
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 filed by the Company with the
Commission on March 19, 1998. 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 Present Principal Occupation or
With TU Electric as Director Employment and Principal
(Current Term Expires (Current Term Expires Business (Preceding Five Years),
Name of Director Age May 8, 1998) May 8, 1998) Other Directorships
- ---------------- --- --------------------- --------------------- --------------------------------
T. L. Baker 52 President, Electric February 20, 1987 President, Electric Service Division of TU
Service Division Electric and President of Lone Star Gas
prior thereto, Executive Vice President of TU
Electric; prior thereto, Senior Vice President
of TU Electric.
David W. Biegler 51 President and Chief August 29, 1997 President and Chief Operating Officer of the
Operating Officer Company, TU Electric and ENSERCH; prior
thereto, Chairman, President and Chief
Executive Officer of ENSERCH; other
directorships: ENSERCH and Trinity Industries,
Inc.
Barbara B. Curry 43 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 52 President, Transmission May 27, 1997 President, Transmission Division of TU Electric;
Division prior thereto, Executive Vice President of
Fuel Company and Mining Company.
30
Other Positions and
Offices Presently Held Date First Elected Present Principal Occupation or
With TU Electric as Director Employment and Principal
(Current Term Expires (Current Term Expires Business (Preceding Five Years),
Name of Director Age May 8, 1998) May 8, 1998) Other Directorships
- ---------------- --- --------------------- --------------------- --------------------------------
Michael J. McNally 43 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 60 Chairman of the Board and September 17, 1982 Chairman of the Board and Chief Executive of the
Chief Executive 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 55 President, Generation May 20, 1986 President, Generation Division of TU Electric;
Division prior thereto, Executive Vice President of TU
Electric.
Directors of TU Electric receive no compensation in their capacity as Directors
of TU Electric.
31
Identification of Executive Officers and business experience:
Positions and
Offices Presently Held Date First Elected
With TU Electric as Director
(Current Term Expires (Current Term Expires Business Experience
Name of Director Age May 8, 1998) May 8, 1998) (Preceding Five Years)
- ---------------- --- --------------------- --------------------- ----------------------
Erle Nye 60 Chairman of the Board February 20, 1987 Chairman of the Board and Chief Executive of the
and Chief Executive 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 51 President and Chief January 1, 1998 President and Chief Operating Officer of the
Operating Officer Company, TU Electric and ENSERCH; prior
thereto, Chairman, President and Chief
Executive Officer of ENSERCH.
T. L. Baker 52 President, Electric February 16, 1996 President, Electric Service Division of TU
Service Division Electric and President of Lone Star Gas
prior thereto, Executive Vice President of TU
Electric; prior thereto, Senior Vice President
of TU Electric.
M. S. Greene 52 President, Transmission May 27, 1997 President, Transmission Division of TU Electric;
Division prior thereto, Executive Vice President of
Fuel Company and Mining Company.
W. M. Taylor 55 President, Generation February 16, 1996 President, Generation Division of TU Electric;
Division 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 have been
timely filed.
32
Item 11. EXECUTIVE COMPENSATION
The Company
- -----------
Information with respect to this item is found under the heading Executive
Compensation in the definitive proxy statement filed by the Company with the
Commission on March 19, 1998.
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
Annual Compensation Long-Term Compensation (5)
------------------------------- ----------------------------------
Awards Payouts
----------------------- -------
Other
Annual Restricted Securities
Compen- Stock Underlying LTIP All Other
Name and Salary Bonus sation Awards Options/ Payouts Compensation
Principal Position Year ($) ($)(4) ($) ($) SARs (#) ($) ($)(6)
- --------------------------- ---- ------- ------- -------- ---------- ----------- -------- -------
Erle Nye, 1997 760,417 325,000 - 499,375 - 23,928 143,963
Chairman of the Board 1996 723,333 185,000 - 351,500 - 0 117,908
and Chief Executive of the 1995 679,167 140,000 - 266,000 - 25,602 87,810
Company and TU Electric (1)
H. Jarrell Gibbs, 1997 354,583 103,000 - 185,125 - 8,432 66,226
Vice Chairman of the Board 1996 321,250 113,000 - 189,500 - 0 53,203
of the Company (2) 1995 282,917 67,200 - 120,300 - 9,102 38,702
W. M. Taylor, 1997 339,583 83,000 - 161,750 - 9,343 59,948
President, Generation 1996 312,500 83,500 - 156,625 - 0 49,530
Division - TU Electric 1995 282,917 64,700 - 117,800 - 10,809 38,278
Michael J. McNally, 1997 279,167 105,000 - 172,500 - 0 103,630
Executive Vice President 1996 229,166 75,000 - 131,250 - 0 97,949
and Chief Financial 1995 170,833 0 - 0 - 0 0
Officer of the Company (3)
T. L. Baker, 1997 294,583 71,000 - 139,625 - 10,619 56,603
President, Electric 1996 275,833 60,500 - 123,500 - 0 46,319
Service Division - TU 1995 261,667 44,900 - 93,500 - 11,947 34,465
Electric
M. S. Greene, 1997 233,750 53,000 - 107,000 - 6,609 40,668
President, Transmission 1996 220,833 45,000 - 95,625 - 0 34,750
Division - TU Electric 1995 206,667 25,800 - 64,500 - 6,599 28,619
- ---------------------------------
(1) Amounts reported in the table for Mr. Nye consist entirely of compensation
paid by the Company.
(2) Mr. Gibbs served as President of TU Electric until December 31, 1997 and was
also elected to his current position with the Company effective August 5,
1997; a portion of the 1997 compensation represents compensation paid by the
Company.
(3) Mr. McNally served as President of the Transmission Division of TU Electric
through May 23, 1997; compensation after that date represents compensation
paid by the Company.
(4) 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
33
awards ranging from 35% to 50% of base salary, and a maximum award of 100%
of base salary, are established. The percentage of the target or the maximum
actually awarded, if any, is dependent upon the attainment of per share net
income goals established in advance by the Organization and Compensation
Committee (Committee) as well as the Committee's evaluation of the
participant's and the Company's performance. One-half of each such award is
paid in cash and is reflected as Bonus in the Summary Compensation Table.
Payment of the remainder of the award is deferred under the Deferred and
Incentive Compensation Plan (DICP) discussed hereinafter in footnote (5).
(5) Amounts reported as Long-Term Compensation 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. 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 values 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, 1997 (each of which is equal to one share of common stock) held
in the DICP accounts for Messrs. Nye, Gibbs, Taylor, McNally, Baker and
Greene were 39,725 ($1,648,588), 17,134 ($711,061), 15,597 ($647,276), 8,299
($344,409), 13,278 ($551,037) and 9,887 ($410,310), 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, 1997 held for Messrs.
Nye, Gibbs, Taylor, McNally, Baker and Greene were 22,666 ($940,639), 5,151
($213,767), 4,121 ($171,022), 11,333 ($470,320), 5,151 ($213,767), and -0-
($-0-), respectively.
34
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 1997 and the number of shares awarded under the LTICP:
Long-Term Incentive Plans - Awards in Last Fiscal Year
Deferred and Incentive
Compensation Plan Long-Term Incentive Compensation Plan
----------------------------- ------------------------------------------------------------
Number of Performance Number of Performance
Shares, or Other Shares, or Other
Units or Period Until Units or Period Until Estimated Future Payouts
Other Maturation Other Maturation or -----------------------------
Name Rights (#) or Payout Rights (#) Payout Minimum (#) Maximum (#)
---- ---------- ------------ ----------- -------------- ----------- -----------
Erle Nye 3,305 5 Years 22,000 3 Years 0 44,000
H. Jarrell Gibbs 1,556 5 Years 5,000 3 Years 0 10,000
W. M. Taylor 1,492 5 Years 4,000 3 Years 0 8,000
Michael J. McNally 1,279 5 Years 11,000 3 Years 0 22,000
T. L. Baker 1,300 5 Years 5,000 3 Years 0 10,000
M. S. Greene 1,023 5 years 0 - 0 0
Amounts reported as LTIP Payouts in the Summary Compensation Table represent
payouts maturing during such years of earnings on salary deferred under the
DICP in prior years.
(6) Amounts reported as All Other Compensation 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 with at least six months of eligible service
with 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 savings 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 savings. 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,
Gibbs, Taylor, McNally, Baker and Greene amounted to $5,760, $4,800, $5,760,
$3,840, $5,760 and $5,760, respectively, during 1997.
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
($94,760 for the Program Year beginning April 1997) may elect to defer a
percentage of annual salary for a period of seven years, a period ending
with the retirement of such employee, or for a combination thereof. Such
deferrals may not exceed in the aggregate 10% of the employee's annual
salary. Salary deferred under the Program is included in amounts reported
under Salary in the Summary Compensation Table. The Company makes a matching
award, subject to forfeiture under certain circumstances, equal to 100% of
the salary deferred under the Program. The trustee for the Program
distributes, at the end of the applicable maturity period, cash equal to the
greater of the actual earnings of Program assets, or the average yield
during the applicable maturity period of U. S. Treasury Notes with a
maturity of ten years. The distribution of the amounts due under the Program
is in a lump sum if the maturity period is seven years or, if the retirement
option is elected, in twenty annual installments. 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 1997, matching awards, which are included
under All Other Compensation in the Summary Compensation Table, were made
for Messrs. Nye, Gibbs, Taylor, McNally, Baker and Greene in the amounts of
$76,042, $35,458, $33,958, $27,917, $29,458 and $23,375, respectively.
Under the Split-Dollar Life Insurance Program of the Texas Utilities Company
System (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
35
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 1997, the economic
benefit derived by Messrs. Nye, Gibbs, Taylor, McNally, 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 $62,161,
$25,968, $20,230, $5,582, $21,385 and $11,533, respectively.
The amount of $66,291 included in the All Other Compensation column of the
Summary Compensation Table for Mr. McNally for 1997 represents additional
compensation that the Company agreed to pay Mr. McNally incident to his
employment with the Company in lieu of payments he would have received from
a prior employer.
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
The Company and its subsidiaries maintain retirement plans (Plans) which are
qualified under applicable provisions of the Internal Revenue Code of 1986, as
amended (Code). Annual retirement benefits are computed as follows: for each
year of accredited service up to a total of 40 years of service, 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 Plans and the Supplemental Retirement
Plan (Supplemental Plan). Benefits paid under the Plans are not subject to any
reduction for Social Security payments but are limited by provisions of the
Code. The Supplemental Plan provides for the payment of retirement benefits
which would otherwise be limited by the Code or by the definition of earnings in
the Plans. Under the Supplemental Plan, retirement benefits are calculated in
accordance with the same formula used under the Plans, except that earnings also
include AIP awards (50% of the AIP award is reported under Bonus for the named
officers in the Summary Compensation Table). As of February 28, 1998, years of
accredited service under the plans for Messrs. Nye, Gibbs, Taylor, McNally,
Baker and Greene were 35, 35, 30, 1, 27 and 27, respectively. The table
illustrates the total annual benefit payable at retirement under the Plans and
Supplemental Plan prior to any reduction for a contingent beneficiary option
which may be selected by the participant.
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 or 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.
36
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 4 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 5 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 5 to the Summary Compensation Table) and the opportunity to earn an
incentive award under the AIP. 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, constitute
an increasing percentage of the officers' total compensation.
The AIP is administered by the Committee and provides an objective framework
within which annual Company and individual performance can be evaluated by the
Committee. Depending on the results of such performance evaluations, and the
attainment of the per share net income goals established in advance, the
Committee may provide annual incentive compensation awards to eligible officers.
The evaluation of each individual participant's performance is based upon the
attainment of individual and business unit objectives. The Company's performance
is evaluated, compared to the ten largest electric utilities and/or the electric
utility industry, based upon its total return to shareholders and return on
invested capital, as well as other measures relating to competitiveness, service
quality and employee safety. The combination of individual and Company
performance results, together with the Committee's evaluation of the competitive
level of compensation which is appropriate for such results, determines the
amount, if any, actually awarded.
The Long-Term Plan, which is also administered by the Committee, is a
comprehensive stock-based incentive compensation plan under which all awards are
made in, or based on the value of, the Company's common stock. The Long-Term
Plan provides that, in the discretion of the Committee, awards may be in the
form of stock options, stock appreciation rights, performance and/or restricted
stock or stock units or in any other stock-based form. The purpose of the Long-
Term Plan is to provide performance-related incentives linked to long-term
performance goals. Such performance goals may be based on individual performance
and/or may include criteria such as absolute or relative levels of total
shareholder return, revenues, sales, net income or net worth of the Company, any
of its subsidiaries, business units or other areas, all as the Committee may
determine. Awards under the Long-Term Plan are expected to constitute the
principal long-term component of officers' compensation. At its meeting in May
1997, the Committee provided awards of performance-based restricted stock 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. 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.
37
In establishing levels of executive compensation at its May 1997 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 was that the
Company's total return to shareholders in 1996 was 4.4%, which was the third
highest total return amongst the ten largest utilities. The comparative returns
provided by the largest electric and gas utilities are represented by the
returns of the Standard & Poor's Electric Utility Index and are reflected in the
graph herein. The graph also reflects the returns provided by the Moody's 24
Utilities, and that disclosure will be discontinued after this year in light of
the greater comparability of the Company to the companies comprising such S&P
index. In 1996, 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, sixth in total assets, fourth in net generating capability, eighth in
number of customers and twelfth 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.
In May 1997 the Committee increased Mr. Nye's base salary as Chief Executive
to an annual rate of $775,000 representing a $35,000 or 4.7% increase over the
amount established for Mr. Nye in May 1996. 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 $650,000 compared to the
prior year's award of $370,000. 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, 1997 through March 31,
2000) compared to the total return provided by the companies comprising the
Standard & Poor's Electric Utility Index. This level of compensation was
established based upon the Committee's subjective evaluation of the information
described in this report.
In discharging its responsibilities with respect to establishing executive
compensation, the Committee normally considers such matters at its May meeting
held in conjunction with the Annual Meeting of Shareholders. Although Company
management may be present during Committee discussions of officers'
compensation, Committee decisions with respect to the compensation of the
Chairman of the Board and Chief Executive and the President are reached in
private session without the presence of any member of Company management.
Section 162(m) of the Code limits the deductibility of compensation which a
publicly traded corporation provides to its most highly compensated officers. As
a general policy, the Company does not intend to provide compensation which is
not deductible for federal income tax purposes. Awards under the AIP in 1996 and
subsequent years as well as awards under the Long-Term Plan are expected to be
fully deductible, and the DICP and the Salary Deferral Program have been amended
to require the deferral of distributions of amounts earned in 1995 and
subsequent years until the time when such amounts would be deductible. Awards
provided under the AIP in 1995 and distributions under the DICP and the Salary
Deferral Program which were earned in plan years prior to 1995, may not be fully
deductible but such amounts are not expected to be material.
Shareholder comments to the Committee are welcomed and should be addressed
to the Secretary of the Company at the Company's offices.
Organization and Compensation Committee
James A. Middleton, Chair Margaret N. Maxey
Bayard H. Friedman J. E. Oesterreicher
William M. Griffin Charles R. Perry
Kerney Laday Herbert H. Richardson
38
PERFORMANCE GRAPH
The following graph compares the performance of the Company's common stock to
the S&P 500 Index, the Moody's 24 Utilities and the S&P Electric Utility Index
for the last five years. The graph assumes the investment of $100 at December
31, 1992 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.
[LINE GRAPH APPEARS HERE]
Cumulative Total Returns
for the Five Years Ended 12/31/97
1992 1993 1994 1995 1996 1997
- ----------------------------------------------------------------------------
Texas Utilities 100 109 88 123 128 138
- ----------------------------------------------------------------------------
S&P 500 Index 100 110 111 153 188 251
- ----------------------------------------------------------------------------
Moody's 24 Utilities 100 110 94 123 125 152
- ----------------------------------------------------------------------------
S&P Electric Utility Index 100 113 98 128 128 162
- ----------------------------------------------------------------------------
39
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 March 19, 1998. 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, 1998:
Amount and
Name and Address Nature
of Beneficial of Beneficial Percent of
Title of Class Owner Ownership Class
-------------- ----------------- ---------------- -------------
Common stock, Texas Energy 142,931,000 100.0%
without par value, Industries, Inc. shares
of TU Electric Energy Plaza, sole voting and
1601 Bryan Street investment power
Dallas, Texas
75201
Security ownership of management at February 28, 1998:
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, 1998.
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
-----------------------------------
Beneficially Deferred
Name Owned Plan * Total
----- ------------ -------- -------
T. L. Baker 8,575 18,752 27,327
David W. Biegler 15,272 0 15,272
Barbara B. Curry 2,444 3,612 6,056
H. Jarrell Gibbs 14,323 23,494 37,817
M. S. Greene 745 14,130 14,875
Michael J. McNally 20,551 10,688 31,239
Erle Nye 49,466 54,462 103,928
W. M. Taylor 14,847 21,850 36,697
All Directors and Executive ------- ------- -------
Officers as a group (8)
126,223 146,988 273,211
======= ======= =======
- -----------
* Share units held in deferred compensation accounts under the Deferred and
Incentive Compensation Plan. Although this plan allows such units to be
paid only in the form of cash, investments in such units create
essentially the same investment stake in the performance of the Company's
common stock as do investments in actual shares of common stock.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The Company
- -----------
Information with respect to this item is found under the heading Beneficial
Ownership of Common Stock of the Company in the definitive proxy statement filed
by the Company with the Commission on March 19, 1998. Additional information
with respect to Executive Officers of the Company is found at the end of Part I.
TU Electric
- -----------
None.
40
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 Operation........................................................... A-7
Statements of Responsibility........................................................... A-19
Independent Auditors' Reports.......................................................... A-21
The Company:
Statements of Consolidated Income for each of the three years in the
period ended December 31, 1997..................................................... A-23
Statements of Consolidated Cash Flows for each of the three years in
the period ended December 31, 1997................................................. A-24
Consolidated Balance Sheets, December 31, 1997 and 1996................................ A-25
Statements of Consolidated Common Stock Equity for each of the three years in
the period ended December 31, 1997................................................. A-27
TU Electric:
Statements of Consolidated Income and Retained Earnings for each of the three years
in the period ended December 31, 1997.............................................. A-28
Statements of Consolidated Cash Flows for each of the three years in
the period ended December 31, 1997................................................. A-29
Consolidated Balance Sheets, December 31, 1997 and 1996................................ A-30
The Company and TU Electric:
Notes to Consolidated Financial Statements............................................. A-32
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.
Other financial information included :
Page
----
Financial Statements (included in Appendix B to this report):
ENSERCH Corporation:
Selected Financial Data................................................................ B-2
Management's Discussion and Analysis of Financial Condition and
Results of Operation........................................................... B-3
Independent Auditors' Report........................................................... B-9
Statements of Consolidated Income for each of the three years in the
period ended December 31, 1997..................................................... B-10
Statements of Consolidated Cash Flows for each of the three years in
the period ended December 31, 1997................................................. B-11
Consolidated Balance Sheets, December 31, 1997 and 1996................................ B-12
Statements of Consolidated Common Stock Equity for each of the three years in
the period ended December 31, 1997................................................. B-13
Notes to Consolidated Financial Statements............................................. B-14
41
(b) Reports on Form 8-K:
Reports on Form 8-K filed since September 30, 1997, are as follows:
The Company
- -----------
Date of Report Item Reported
-------------- -------------
November 21, 1997 Item 5. OTHER EVENTS
December 17, 1997 Item 5. OTHER EVENTS
February 26, 1998 Item 5. OTHER EVENTS
March 13, 1998 Item 5. OTHER EVENTS
TU Electric
- -----------
Date of Report Item Reported
-------------- -------------
December 17, 1997 Item 5. OTHER EVENTS
(c) Exhibits:
The Company and TU Electric
- ---------------------------
Previously Filed*
---------------------------
With
File As
Exhibits Number Exhibit Number Dated
- -------- ------ ------- ------ -----
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 TU Electric.
Form 10-Q
(Quarter ended
June 30, 1997)
3(d) 33-64694 4(c) - Bylaws of TU Electric, as amended.
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:
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
33-9583 4(a)-2 Eighth May 1, 1986
42
Previously Filed*
---------------------------
With
File As
Exhibits Number Exhibit Number Dated
- -------- ------ ------- ------ -----
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)
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
43
Previously Filed*
---------------------------
With
File As
Exhibits Number Exhibit Number 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 and Chemical Bank, dated
Form 10-K as of October 14, 1993.
(1993)
4(e) 0-11442 4(f) - Indenture (For Unsecured Subordinated Debt Securities relating to
Form 10-K Trust Securities), dated as of December 1, 1995, between TU
(1995) Electric and The Bank of New York, as Trustee.
4(f) 0-11442 4(g) - Amended and Restated Trust Agreement, dated as of December 12,
Form 10-K 1995, between TU Electric, as Depositor, and The Bank of New
(1995) 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 TU Electric Capital I, dated
Form 10-K as of December 12, 1995, between TU Electric, as Guarantor, and
(1995) The Bank of New York, as Trustee.
4(h) 0-11442 4(i) - Agreement as to Expenses and Liabilities, dated as of December
Form 10-K 12, 1995, between TU Electric and TU Electric Capital I.
(1995)
4(i) 0-11442 4(j) - Officer's Certificate, dated as of December 12, 1995, establishing
Form 10-K the terms of the Junior Subordinated Debentures issued in
(1996) connection with the preferred securities of TU Electric Capital I.
4(j) 0-11442 4(j) - Amended and Restated Trust Agreement, dated as of December 12,
Form 10-K 1995, between TU Electric, as Depositor, and The Bank of New
(1995) York, The Bank of New York (Delaware) and the Administrative
Trustees thereunder, as Trustees for TU Electric Capital II.
4(k) 0-11442 4(k) - Guarantee Agreement with respect to TU Electric Capital II, dated
Form 10-K as of December 12, 1995, between TU Electric, as Guarantor, and
(1995) The Bank of New York, as Trustee.
4(l) 0-11442 4(l) - Agreement as to Expenses and Liabilities, dated as of December
Form 10-K 12, 1995, between TU Electric and TU Electric Capital II.
(1995)
44
Previously Filed*
---------------------------
With
File As
Exhibits Number Exhibit Number Dated
- -------- ------ ------- ------ -----
4(m) 0-11442 4(n) - Officer's Certificate, dated as of December 12, 1995, establishing
Form 10-K the terms of the Junior Subordinated Debentures issued in
(1996) connection with the preferred securities of TU Electric Capital II.
4(n) 0-11442 4(m) - Amended and Restated Trust Agreement, dated as of December 13,
Form 10-K 1995, between TU Electric, as Depositor, and The Bank of New
(1995) York, The Bank of New York (Delaware), and the Administrative
Trustees thereunder, as Trustees for TU Electric Capital III.
4(o) 0-11442 4(n) - Guarantee Agreement with respect to TU Electric Capital III, dated
Form 10-K as of December 13, 1995, between TU Electric, as Guarantor, and
(1995) The Bank of New York, as Trustee.
4(p) 0-11442 4(o) - Agreement as to Expenses and Liabilities, dated as of December
Form 10-K 13, 1995, between TU Electric and TU Electric Capital III.
(1995)
4(q) 0-11442 4(r) - Officer's Certificate, dated as of December 13, 1995, establishing
Form 10-K the terms of the Junior Subordinated Debentures issued in
(1996) connection with the preferred securities of TU Electric Capital III.
4(r) 0-11442 4(s) - Amended and Restated Trust Agreement, dated as of January 30,
Form 10-K 1997, between TU Electric, as Depositor, and The Bank of New
(1996) York (Delaware), and the Administrative Trustee thereunder, as Trustees for TU
Electric Capital IV.
4(s) 0-11442 4(t) - Guarantee Agreement with respect to TU Electric Capital IV, dated
Form 10-K as of January 30, 1997, between TU Electric, as Guarantor, and The
(1996) Bank of New York, as Trustee.
4(t) 0-11442 4(u) - Agreement as to Expenses and Liabilities, dated as of January 30,
Form 10-K 1997, between TU Electric and TU Electric Capital IV.
(1996)
4(u) 0-11442 4(v) - Officer's Certificate, dated as of January 30, 1997, establishing the
Form 10-K terms of the Junior Subordinated Debentures issued in connection
(1996) with the preferred securities of TU Electric Capital IV.
4(v) 0-11442 4(w) - Amended and Restated Trust Agreement, dated as of January 30,
Form 10-K 1997, between TU Electric, as Depositor, and The Bank of New
(1996) York (Delaware), and the Administrative Trustee thereunder, as Trustees for TU
Electric Capital V.
4(w) 0-11442 4(x) - Guarantee Agreement with respect to TU Electric Capital V, dated
Form 10-K as of January 30, 1997, between TU Electric, as Guarantor, and The
(1996) Bank of New York, as Trustee.
4(x) 0-11442 4(y) - Agreement as to Expenses and Liabilities, dated as of January 30,
Form 10-K 1997, between TU Electric and TU Electric Capital V.
(1996)
4(y) 0-11442 4(z) - Officer's Certificate, dated as of January 30, 1997, establishing the
Form 10-K terms of the Junior Subordinated Debentures issued in connection
(1996) with the preferred securities of TU Electric Capital V.
4(z) 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(aa) 333-45999 4(c) - Registration Rights Agreement with respect to Series A Notes.
4(bb) 333-45999 4(e) - Officers' Certificate establishing Series A Notes.
4(cc) 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).
45
Previously Filed*
---------------------------
With
File As
Exhibits Number Exhibit Number Dated
- -------- ------ ------- ------ -----
4(dd) 333-45999 4(d) - Registration Rights Agreement with respect to Series B Notes.
4(ee) 333-45999 4(f) - Officer's Certificate establishing Series B Notes.
4(ff) - Indenture, dated January 1, 1998, relating to the Company's
6.375% Series C Senior Notes and 6.375% Series C Exchange
Notes (together, Series C Notes).
4(gg) - Registration Rights Agreement with respect to Series C Notes.
4(hh) - Officers' Certificate establishing Series C Notes.
4(ii) 0-11442 - Indenture (For Unsecured Debt Securities), dated as of August 1,
Form 10-Q 1997, between TU Electric and The Bank of New York.
(Quarter ended
Sept. 30, 1997)
4(jj) 0-11442 - Officer's Certificate establishing the TU Electric 7.17% Debentures
Form 10-Q due August 1, 2007.
(Quarter ended
Sept. 30, 1997)
4(kk) - Indenture (For Unsecured Debt Securities), dated as of January 1, 1998, between
ENSERCH Corporation and The Bank of New York.
4(ll) - Officer's Certificate establishing the ENSERCH 6 1/4% Series A
Notes due January 1, 2003.
4(mm) - Officer's Certificate establishing the ENSERCH Remarketed Reset
Notes due January 1, 2008.
4(nn) 33-45688 4.2 - Indenture, dated February 15, 1992, between ENSERCH Corporation
and The First National Bank of Chicago.
4(oo) - ENSERCH Corporation 7% Note due 1999, dated August 18, 1992.
4(pp) - ENSERCH Corporation 8 7/8% Note due 2001, dated March 17, 1992.
4(qq) - ENSERCH Corporation 6 3/8% Note due 2004, dated February 1, 1994.
4(rr) - ENSERCH Corporation 7 1/8% Note due 2005, dated June 6, 1995.
10(a)** 1-3591 10(a) - Deferred and Incentive Compensation Plan of the Texas Utilities
Form 10-Q Company System, as amended February 20, 1998.
(Quarter ended
June 30, 1995)
10(b)** 1-3591 10(f) - Salary Deferral Program of the Texas Utilities Company System
Form 10-Q as amended February 20, 1998.
(Quarter ended
June 30, 1995)
10(c)** 1-3591 10(c) - Restated Supplemental Retirement Plan for Employees of the
Form 10-Q Texas Utilities Company System, as restated effective January 1, 1995.
(Quarter ended
June 30, 1995)
10(d)** 1-3591 10(b) - Deferred Compensation Plan for Outside Directors of the Company,
Form 10-Q effective as of July 1, 1995.
(Quarter ended
June 30, 1995)
10(e)** 1-3591 10(d) - Long-Term Incentive Plan of the Texas Utilities Company System,
Form 10-Q dated as of May 19, 1995.
(Quarter ended
June 30, 1995)
10(f)** 333-45657 - Deferred Compensation Plan for Directors of Subsidiaries of Texas
Utilities Company dated as of February 5, 1998.
46
Previously Filed*
---------------------------
With
File As
Exhibits Number Exhibit Number Dated
- -------- ------ ------- ------ -----
10(g)** 1-3591 10(e) - Management Transition Agreement, dated as of May 19, 1995
Form 10-Q between the Company and J.S. Farrington.
(Quarter ended
June 30, 1995)
10(h) 1-12833 (b)(1) - 364 Day Competitive Advance and Revolving Credit Facility
Schedule 14D-1 Agreement, dated as of March 2, 1998 among Texas Utilities
(filed March 10, Company, Texas Utilities Electric Company, ENSERCH
1998) 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 A).
10(i) l-12833 (b)(2) - 5-Year Competitive Advance and Revolving Credit Facility
Schedule 14D-1 Agreement dated as of March 2, 1998 among Texas Utilities
(filed March 10, Company, Texas Utilities Electric Company, ENSERCH Corporation,
1998) 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 US Facility A and US
Schedule 14D-1 Facility B.
(filed March 10,
1998)
10(k) l-12833 (b)(4) - Facilities Agreement for (Pounds)3,625,000,000 Credit Facilities for TU
Schedule 14D-1 Finance (No. 1) Limited, TU Finance (No. 2) Limited, TU
(filed March 10, Acquisitions PLC, Chase Manhattan plc, Lehman Brothers
1998) International and Merrill Lynch Capital Corporation as Joint Lead
Arrangers, the Chase Manhattan Bank, Lehman Commercial Paper
Inc. and Merrill Lynch Capital Corporation as Underwriters (UK
Facility).
10(l) l-12833 (b)(5) - Amendment No. 1, dated March 3, 1998 to UK Facility.
Schedule 14D-1
(filed March 10,
1998)
10(m) l-12833 (b)(6) - 364-Day Competitive Advance and Revolving Credit Facility
Schedule 14D-1 Agreement "Interim Facility", dated as of March 6, 1998 among
(filed March 10, Texas Utilities Company, Chase Bank of Texas, National
1998) Association, as Administrative Agent and The Chase Manhattan
Bank, as Competitive Advance Facility Agent, Initial Underwriters,
The Chase Manhattan Bank, Lehman Commercial Paper Inc., Merrill
Lynch Capital Corporation, Chase Securities Inc., Lehman Brothers
Inc. and Merrill Lynch & Co. as Joint Lead Arrangers and certain
banks listed therein (Interim Facility).
10(n) - Amendment No. 1, dated March 23, 1998 to the Interim Facility.
12(a) - Computation of Ratio of Earnings to Fixed Charges 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) - Independent Auditors' Consent for the Company.
23(d) - Independent Auditors' Consent for TU Electric.
47
Previously Filed*
---------------------------
With
File As
Exhibits Number Exhibit Number Dated
- -------- ------ ------- ------ -----
23(e) - Independent Auditors' Consent for ENSERCH.
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, between TU Electric
Form 10-K and Texas Municipal Power Agency.
(1987)
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, Security Agreement and
Form 10-Q Mortgage, including form of Secured Facility Bond, 1993 Series.
(Quarter ended
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.
99(l) 0-11442 99(d) - Lease Agreement Supplement No. 6, dated as of July 1, 1993.
Form 10-Q
(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.
48
Previously Filed*
---------------------------
With
File As
Exhibits Number Exhibit Number Dated
- -------- ------ ------- ------ -----
99(r) 0-11442 99(e) - Supplement No. 4 to the Participation Agreement, dated as of
Form 10-Q June 17, 1993.
(Quarter ended
June 30, 1993)
99(s) 0-11442 4(b) - Supplement No. 1, dated October 25, 1995, to Trust Indenture,
Form 10-Q Security Agreement and Mortgage, dated as of December 1, 1989,
(Quarter ended among the Owner Trustee, TU Electric and the Indenture Trustee.
March 31, 1996)
99(t) 0-11442 4(c) - Supplement No. 1, dated October 19, 1995, to Amended and
Form 10-Q Restated Participation Agreement, dated as of November 28, 1989,
(Quarter ended among the Owner Trustee, The First National Bank of Chicago,
March 31, 1996) As Original Indenture Trustee, the Indenture Trustee, the Owner
Participant, Mesquite Power Corporation and TU Electric.
99(u) 0-11442 99(a) - Amended and Restated 364 Day Competitive Advance and
Form 10-Q Revolving Credit Facility Agreement, "Facility A", dated as of
(Quarter ended April 24, 1997, among the Company, TEI, TU Electric, ENSERCH,
March 31, 1997 certain banks, Chemical Bank and Texas Commerce Bank National
Association, as Agents.
99(v) 0-11442 99(a) - Amendment, dated as of September 4, 1997, to Facility A.
Form 10-Q
(Quarter ended
June 30, 1997)
99(w) 0-11442 99(w) - Second Amendment, dated as of November 10, 1997, to Facility
Form 10-Q A.
(Quarter ended
September 30, 1997)
99(x) 0-11442 99(u) - Amended and Restated Five Year Competitive Advance and
Form 10-Q Revolving Credit Facility Agreement, "Facility B", dated as of
(Quarter ended April 24, 1997, among the Company, TEI, TU Electric, ENSERCH,
March 31, 1997 certain banks, Chemical Bank and Texas Commerce Bank National
Association, as Agents.
99(y) 0-11442 99(v) - Amendment, dated as of September 4, 1997, to Facility B.
Form 10-Q
(Quarter ended
June 30, 1997)
99(z) 0-11442 99(z) - Second Amendment, dated as of November 10, 1997, to Facility
Form 10-Q B.
(Quarter ended
September 30, 1997)
- -----------------------
* 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.
49
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 26, 1998 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/ J. W. PINKERTON Principal Accounting Officer
- ------------------------------------
(J. W. Pinkerton, Controller)
/s/ J. S. FARRINGTON Director
- ------------------------------------
(J. S. Farrington)
/s/ BAYARD H. FRIEDMAN Director
- ------------------------------------
(Bayard H. Friedman)
/s/ WILLIAM M. GRIFFIN Director March 26, 1998
- ------------------------------------
(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)
50
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 26, 1998 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 and Director
(Erle Nye, Chairman of the Board and
Chief Executive)
/s/ ROBERT S. SHAPARD Principal Financial Officer
- ------------------------------------
(Robert S. Shapard, Treasurer and
Assistant Secretary)
/s/ J. W. PINKERTON Principal Accounting Officer
- ------------------------------------
(J. W. Pinkerton, Controller)
/s/ T. L. BAKER Director
- ------------------------------------
(T. L. Baker)
/s/ D. W. Biegler Director
- ------------------------------------
(D. W. Biegler)
/s/ BARBARA B. CURRY Director March 26, 1998
- ------------------------------------
(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)
51
Appendix A
TEXAS UTILITIES COMPANY AND SUBSIDIARIES AND
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
INDEX TO FINANCIAL INFORMATION
December 31, 1997
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 Operation .......................................................................................... A-7
Statements of Responsibility ........................................................................... A-19
Independent Auditors' Reports .......................................................................... A-21
Financial Statements:
Texas Utilities Company and Subsidiaries:
Statements of Consolidated Income ...................................................................... A-23
Statements of Consolidated Cash Flows .................................................................. A-24
Consolidated Balance Sheets ............................................................................ A-25
Statements of Consolidated Common Stock Equity ......................................................... A-27
Texas Utilities Electric Company and Subsidiaries:
Statements of Consolidated Income and Retained Earnings ................................................ A-28
Statements of Consolidated Cash Flows .................................................................. A-29
Consolidated Balance Sheets ............................................................................ A-30
Notes to Consolidated Financial Statements ............................................................. A-32
A-1
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
SELECTED FINANCIAL DATA
CONSOLIDATED FINANCIAL STATISTICS
Year Ended December 31,
-----------------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
(Dollars in Thousands, except ratios and per share amounts)
Total assets -- end of year .............................. $24,874,129 $21,397,655 $21,535,851 $20,893,408 $21,518,128
- -----------------------------------------------------------------------------------------------------------------------------------
Property, plant & equipment - gross -- end of year ....... $26,579,187 $24,931,239 $24,911,787 $24,206,351 $23,836,729
Accumulated depreciation and amortization -- end of
year................................................... 7,172,152 6,496,724 5,857,580 5,228,423 4,710,398
Reserve for regulatory disallowances -- end of year .... 836,005 836,005 1,308,460 1,308,460 1,308,460
Construction expenditures (including allowance for
funds used during construction) ....................... 586,097 434,139 434,338 444,245 871,450
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalization -- end of year
Long-term debt, less amounts due currently ............. $ 8,759,379 $ 8,668,111 $ 9,174,575 $ 7,888,413 $ 8,379,826
TU Electric obligated, mandatorily redeemable, preferred
securities of subsidiary trusts holding solely
debentures of TU Electric ............................ 875,146 381,311 381,476 -- --
Preferred stock of subsidiaries:
Not subject to mandatory redemption ................... 304,194 464,427 489,695 870,190 1,083,008
Subject to mandatory redemption ....................... 20,600 238,391 263,196 387,482 396,917
Common stock equity .................................... 6,843,062 6,032,913 5,731,753 6,490,047 6,570,993
----------- ----------- ----------- ----------- -----------
Total ............................................. $16,802,381 $15,785,153 $16,040,695 $15,636,132 $16,430,744
=========== =========== =========== =========== ===========
Capitalization ratios -- end of year
Long-term debt, less amounts due currently ............. 52.1% 54.9% 57.2% 50.5% 51.0%
TU Electric obligated, mandatorily redeemable, preferred
securities of subsidiary trusts holding solely
debentures of TU Electric ............................. 5.2 2.4 2.4 -- --
Preferred stock of subsidiaries ........................ 2.0 4.5 4.7 8.0 9.0
Common stock equity .................................... 40.7 38.2 35.7 41.5 40.0
----- ----- ----- ----- -----
Total ............................................. 100.0% 100.0% 100.0% 100.0% 100.0%
===== ===== ===== ===== =====
- -----------------------------------------------------------------------------------------------------------------------------------
Embedded interest cost on long-term debt -- end of
year ................................................. 7.9% 8.1% 8.4% 8.7% 8.7%
Embedded distribution cost on TU Electric obligated,
mandatorily redeemable, preferred securities of
subsidiary trusts holding solely debentures of TU
Electric -- end of year .............................. 8.3% 8.7% 8.6% --% --%
Embedded dividend cost on preferred stock of subsidiaries
-- end of year* ...................................... 9.2% 7.5% 7.4% 7.5% 7.6%
- -----------------------------------------------------------------------------------------------------------------------------------
Net income (loss) ........................................ $660,454 $753,606 $(138,645) $542,799 $368,660
Dividends declared on common stock ....................... $496,244 $456,059 $ 634,613 $695,590 $682,438
- -----------------------------------------------------------------------------------------------------------------------------------
Common stock data
Shares outstanding -- average .......................... 230,957,999 225,159,846 225,841,037 225,833,659 221,555,218
Shares outstanding -- end of year ...................... 245,237,559 224,602,557 225,841,037 225,841,037 224,345,422
Basic Earnings (loss) per share ........................ $2.86 $3.35 $(0.61) $2.40 $1.66
Diluted Earnings (loss) per share ...................... $2.85 $3.35 $(0.61) $2.40 $1.66
Dividends declared per share ........................... $2.125 $2.025 $2.81 $3.08 $3.08
Book value per share -- end of year .................... $27.90 $26.86 $25.38 $28.74 $29.29
Return on average common stock equity .................. 10.3% 12.8% (2.3)% 8.3% 5.6%
Ratio of earnings to fixed charges:
Pre-tax ................................................ 2.3 2.4 0.8 2.3 1.9
After-tax .............................................. 1.8 2.0 0.9 1.9 1.6
Allowance for funds used during construction as
percent of net income ................................. 2.1% 1.7% --% 4.1% 71.4%
- -----------------------------------------------------------------------------------------------------------------------------------
* 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 6.6% for 1997, 6.8% for 1996, and 6.9% for
1995.
Certain financial statistics for 1997 were affected by the August 1997
acquisition of ENSERCH and the November 1997 acquisition of LCC; for 1996 and
1995 were affected by the December 1995 acquisition of Eastern Energy; for the
year 1995, were affected by recording of the impairment of certain assets (see
Note 14 to Consolidated Financial Statements); and for the year 1993, were
affected by TU Electric recording a regulatory disallowance in a rate order
issued by the PUC in Docket 11735 (see Note 13 to Consolidated Financial
Statements). Shares outstanding assuming dilution for 1997 was 231,957,491.
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,
-----------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
ELECTRIC ENERGY GENERATED AND
PURCHASED (MWh)
Generated -- net station output............... 91,297,900 88,129,637 83,876,565 81,320,922 79,105,495
Purchased and net interchange................. 17,170,477 18,119,171 11,880,174 12,551,167 12,785,246
----------- ----------- ---------- ---------- ----------
Total generated and purchased............... 108,468,377 106,248,808 95,756,739 93,872,089 91,890,741
Company use, losses and unaccounted for...... 6,255,458 5,905,076 5,653,698 5,246,480 5,631,085
----------- ----------- ---------- ---------- ----------
Total electric energy sales............ 102,212,919 100,343,732 90,103,041 88,625,609 86,259,656
=========== =========== ========== ========== ==========
SALES VOLUMES
Electric Energy Sales (MWh)
Residential................................. 36,376,916 35,855,314 31,284,477 30,460,307 30,504,991
Commercial.................................. 28,851,097 27,946,728 25,899,942 25,073,687 24,269,456
Industrial.................................. 26,253,835 25,755,045 23,586,291 23,154,145 21,586,803
Government and municipal.................... 6,231,775 6,161,150 5,752,800 5,619,135 5,427,436
----------- ----------- ---------- ---------- ----------
Total general business................. 97,713,622 95,718,237 86,523,510 84,307,274 81,788,686
Other electric utilities............... 4,499,296 4,625,495 3,579,531 4,318,335 4,470,970
----------- ----------- ---------- ---------- ----------
Total electric energy sales............ 102,212,919 100,343,732 90,103,041 88,625,609 86,259,656
=========== =========== ========== ========== ==========
Gas Distribution (million cubic feet):
Residential................................. 33,417 -- -- -- --
Commercial.................................. 20,996 -- -- -- --
Industrial.................................. 2,094 -- -- -- --
Electric generation......................... 463 -- -- -- --
---------- ---------- ---------- ---------- ----------
Total gas distribution................. 56,970 -- -- -- --
---------- ---------- ---------- ---------- ----------
Pipeline transportation (million cubic feet).. 255,391 -- -- -- --
Gas liquids (thousand barrels)................ 2,521 -- -- -- --
Gas marketing (million cubic feet)............ 292,264 -- -- -- --
OPERATING REVENUES (thousands)
Electric base rate:
Residential................................. $2,248,411 $2,251,734 $1,920,087 $1,862,525 $1,704,766
Commercial.................................. 1,368,057 1,357,326 1,219,443 1,183,757 1,061,591
Industrial.................................. 668,805 690,943 602,518 595,213 536,800
Government and municipal.................... 319,795 322,013 287,674 283,783 245,458
---------- ---------- ---------- ---------- ----------
Total general business................. 4,605,068 4,622,016 4,029,722 3,925,278 3,548,615
Other electric utilities............... 138,974 146,358 117,904 155,389 149,289
---------- ---------- ---------- ---------- ----------
Total base rate revenues............... 4,744,042 4,768,374 4,147,626 4,080,667 3,697,904
Fuel revenue (including over/under-recovered). 1,696,409 1,670,844 1,418,211 1,513,929 1,657,331
Transmission service revenues................. 113,196 -- -- -- --
Other operating revenues...................... 110,670 111,710 72,851 68,947 79,277
---------- ---------- ---------- ---------- ----------
Total electric operating revenues...... 6,664,317 6,550,928 5,638,688 5,663,543 5,434,512
---------- ---------- ---------- ---------- ----------
Gas distribution
Residential................................. 205,760 -- -- -- --
Commercial.................................. 108,650 -- -- -- --
Industrial.................................. 8,594 -- -- -- --
Electric generation......................... 6,424 -- -- -- --
---------- ---------- ---------- ---------- ----------
Total gas distribution................. 329,428 -- -- -- --
---------- ---------- ---------- ---------- ----------
Pipeline transportation....................... 57,544 -- -- -- --
Gas liquids................................... 36,514 -- -- -- --
Gas marketing................................. 858,566 -- -- -- --
Telecommunications............................ 11,900 -- -- -- --
Other......................................... 43,877 -- -- -- --
Less intercompany revenues.................... (56,538) -- -- -- --
---------- ---------- ---------- ---------- ----------
Total operating revenues............... $7,945,608 $6,550,928 $5,638,688 $5,663,543 $5,434,512
========== ========== ========== ========== ==========
A-3
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
CONSOLIDATED OPERATING STATISTICS
Year Ended December 31,
-----------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
CUSTOMERS (end of year)
Electric
Residential................................. 2,607,803 2,558,025 2,504,128 2,053,235 2,020,667
Commercial.................................. 281,694 274,076 267,579 225,479 221,422
Industrial.................................. 50,153 49,390 49,558 21,673 21,954
Government and municipal.................... 32,289 31,108 30,458 29,437 29,034
--------- --------- --------- --------- ---------
Total general business................... 2,971,939 2,912,599 2,851,723 2,329,824 2,293,077
Other electric utilities.................... 128 161 165 212 220
--------- --------- --------- --------- ---------
Total electric customers................. 2,972,067 2,912,760 2,851,888 2,330,036 2,293,297
========= ========= ========= ========= =========
Gas distribution............................. 1,355,402 -- -- -- --
========= ========= ========= ========= =========
ELECTRIC RESIDENTIAL STATISTICS
(excludes master-metered
customers, kWh sales and revenues)
Average annual kWh per customer.......... 13,495 13,551 12,003 14,192 14,594
Average revenue per kWh.................. 7.95c 8.02c 8.08c 8.25c 7.56c
- ----------
Industrial classification
includes service to Alcoa-Sandow:
Electric energy sales (Mwh).............. 3,820,421 3,841,904 3,764,658 3,886,258 3,166,797
Operating revenues (thousands)........... $46,755 $46,853 $47,739 $54,699 $53,352
Certain previously reported operating statistics have been reclassified to
conform to current classifications. The operating statistics include the
operations of ENSERCH and Eastern Energy from their date of acquisition, August
1997 and December 1995, respectively.
A-4
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
SELECTED FINANCIAL DATA
CONSOLIDATED FINANCIAL STATISTICS
Year Ended December 31,
-----------------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
(Dollars in Thousands)
Total assets -- end of year.............................. $18,833,433 $18,794,939 $19,003,374 $19,446,998 $19,870,990
- -----------------------------------------------------------------------------------------------------------------------------------
Electric plant - gross -- end of year.................... $22,219,894 $22,664,086 $22,747,860 $23,063,436 $22,680,508
Accumulated depreciation and amortization -- end of
year................................................... 6,120,309 5,963,477 5,370,818 4,765,474 4,233,720
Reserve for regulatory disallowances -- end of year..... 836,005 836,005 1,308,460 1,308,460 1,308,460
Construction expenditures (including allowance for
funds used during construction)......................... 446,088 377,438 407,305 415,290 841,181
- -----------------------------------------------------------------------------------------------------------------------------------
Capitalization -- end of year
Long-term debt.......................................... $ 5,475,447 $ 6,310,594 $ 7,212,070 $ 7,220,641 $ 7,607,090
TU Electric obligated, mandatorily redeemable, preferred
securities of subsidiary trusts holding solely
debentures of TU Electric............................. 875,146 381,311 381,476 -- --
Preferred stock:
Not subject to mandatory redemption.................... 129,194 464,427 489,695 870,190 1,083,008
Subject to mandatory redemption........................ 20,600 238,391 263,196 387,482 396,917
Common stock equity..................................... 6,298,445 6,105,907 5,799,898 6,114,261 6,029,217
----------- ----------- ----------- ----------- -----------
Total................................................ $12,798,832 $13,500,630 $14,146,335 $14,592,574 $15,116,232
=========== =========== =========== =========== ===========
Embedded interest cost on long-term debt -- end of
year................................................... 8.3% 8.3% 8.4% 8.7% 8.8%
Embedded distribution cost on TU Electric obligated,
mandatorily redeemable, preferred securities of
subsidiary trusts holding solely debentures of TU
Electric -- end of year ................................ 8.3% 8.7% 8.6% --% --%
Embedded dividend cost on preferred stock -- end of
year*.................................................. 14.1% 7.5% 7.4% 7.5% 7.6%
- -----------------------------------------------------------------------------------------------------------------------------------
Net income available for common stock.................... $ 745,024 $ 809,337 $ 367,717 $ 556,309 $ 361,294
Dividends declared on common stock....................... $ 136,416 $ 503,328 $ 682,080 $ 715,760 $ 707,382
- -----------------------------------------------------------------------------------------------------------------------------------
Ratio of earnings to fixed charges:
Pre-tax................................................. 2.9 3.0 2.0 2.5 2.0
After-tax............................................... 2.3 2.5 1.7 2.0 1.7
Ratio of earnings to combined fixed charges and preferred
dividends........................................ 2.8 2.7 1.8 2.0 1.6
Allowance for funds used during construction as a percent
of consolidated net income available for common stock.. 1.8% 1.6% 6.0% 4.0% 72.9%
Return on average common stock equity.................... 12.0% 13.6% 6.2% 9.2% 5.9%
- -----------------------------------------------------------------------------------------------------------------------------------
* 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 6.9% for 1997, 6.8% for 1996, and 6.9% for
1995.
Certain financial statistics for 1995 were affected by the recording of the
impairment of certain assets (see Note 14 to Consolidated Financial Statements);
and for the year 1993, were affected by TU Electric recording a regulatory
disallowance in a rate order issued by the PUC in Docket 11735 (see Note 13 to
Consolidated Financial Statements).
A-5
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED OPERATING STATISTICS
Year Ended December 31,
------------------------------------------------------------------
1997 1996 1995 1994 1993
---- ---- ---- ---- ----
ELECTRIC ENERGY GENERATED AND
PURCHASED (MWh)
Generated -- net station output............................. 91,297,900 88,129,637 83,876,565 81,320,922 79,105,495
Purchased and net interchange............................... 11,442,749 12,417,774 10,683,722 11,663,148 12,431,763
----------- ----------- ----------- ----------- -----------
Total generated and purchased............................ 102,740,649 100,547,411 94,560,287 92,984,070 91,537,258
Company use, losses and unaccounted for..................... 6,161,070 5,804,526 5,532,031 5,131,173 5,572,916
----------- ----------- ----------- ----------- -----------
Total electric energy sales.............................. 96,579,579 94,742,885 89,028,256 87,852,897 85,964,342
=========== =========== =========== =========== ===========
ELECTRIC ENERGY SALES (MWh)
Residential................................................. 33,529,811 33,038,399 30,716,241 30,065,767 30,278,230
Commercial.................................................. 27,322,757 26,455,954 25,553,369 24,815,874 24,139,120
Industrial.................................................. 24,609,131 24,214,960 23,301,933 22,984,218 21,506,547
Government and municipal.................................... 6,039,407 5,929,249 5,615,715 5,505,298 5,365,815
----------- ----------- ----------- ----------- -----------
Total general business................................... 91,501,106 89,638,562 85,187,258 83,371,157 81,289,712
Other electric utilities.................................... 5,078,473 5,104,323 3,840,998 4,481,740 4,674,630
----------- ----------- ----------- ----------- -----------
Total electric energy sales.............................. 96,579,579 94,742,885 89,028,256 87,852,897 85,964,342
=========== =========== =========== =========== ===========
OPERATING REVENUES (thousands)
Base rate:
Residential................................................. $ 1,990,903 $ 1,993,506 $ 1,875,311 $ 1,832,557 $ 1,686,692
Commercial.................................................. 1,235,330 1,227,271 1,193,561 1,165,498 1,052,227
Industrial.................................................. 582,345 590,174 586,146 585,963 532,076
Government and municipal.................................... 292,623 291,020 279,803 276,856 241,600
----------- ----------- ----------- ----------- -----------
Total general business................................... 4,101,201 4,101,971 3,934,821 3,860,874 3,512,595
Other electric utilities.................................... 163,663 165,619 133,359 163,134 157,173
----------- ----------- ----------- ----------- -----------
Total from base rate revenues............................ 4,264,864 4,267,590 4,068,180 4,024,008 3,669,768
Fuel revenues (including over/under-recovered).............. 1,707,044 1,679,009 1,421,861 1,521,029 1,662,358
Transmission service revenues............................... 113,811 -- -- -- --
Other operating revenues.................................... 49,698 83,012 70,421 68,138 77,030
----------- ----------- ----------- ----------- -----------
Total operating revenues................................. $ 6,135,417 $ 6,029,611 $ 5,560,462 $ 5,613,175 $ 5,409,156
=========== =========== =========== =========== ===========
ELECTRIC CUSTOMERS (end of year)
Residential................................................. 2,152,362 2,109,343 2,061,273 2,019,025 1,986,946
Commercial.................................................. 237,312 230,253 225,183 219,604 215,621
Industrial.................................................. 21,004 21,002 21,253 21,445 21,716
Government and municipal.................................... 30,628 30,062 29,429 28,949 28,555
----------- ----------- ----------- ----------- -----------
Total general business................................... 2,441,306 2,390,660 2,337,138 2,289,023 2,252,838
Other electric utilities.................................... 140 173 177 219 228
----------- ----------- ----------- ----------- -----------
Total electric customers................................. 2,441,446 2,390,833 2,337,315 2,289,242 2,253,066
=========== =========== =========== =========== ===========
RESIDENTIAL STATISTICS (excludes master-metered
customers, kWh sales and revenues)
Average annual kWh per customer.......................... 15,026 15,100 14,336 14,236 14,604
Average revenue per kWh.................................. 7.85c 7.91c 8.08c 8.26c 7.55c
- -------------------------
Industrial classification includes service to Alcoa-Sandow:
Electric energy sales (MWh).............................. 3,820,421 3,841,904 3,764,658 3,886,258 3,166,797
Operating revenues (thousands)........................... $46,755 $46,853 $47,739 $54,699 $53,352
Certain previously reported operating statistics have been reclassified to
conform to current classifications.
A-6
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATION
FORWARD-LOOKING STATEMENTS
This report and other presentations made by Texas Utilities Company (the
Company or TUC) and its direct and indirect subsidiaries (System Companies) 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
believes that in making any such statement its expectations are based on
reasonable assumptions, any such statement involves uncertainties and is
qualified in its entirety by reference to the following important factors, among
others, that could cause the actual results of the Company or TU Electric to
differ materially from those projected in such forward-looking statement: (i)
prevailing governmental policies and regulatory actions, including those of the
Federal Energy Regulatory Commission, the Public Utility Commission of Texas
(PUC), the Railroad Commission of Texas (RRC), the Nuclear Regulatory
Commission, and, in the case of the Company, the Office of the Regulator General
of Victoria, Australia, 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 in 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, and (xiii) significant changes in the Company's
relationship with its employees and the potential adverse effects if labor
disputes or grievances were to occur.
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.
FINANCIAL CONDITION
Mergers and Acquisitions
Certain comparisons in this Form 10-K have been affected by the August 1997
acquisition of ENSERCH Corporation (ENSERCH) and the November 1997 acquisition
of Lufkin-Conroe Communications Co. (LCC) by the Company and by the December
1995 acquisition of Eastern Energy Limited (Eastern Energy) by Texas Utilities
Australia Pty. Ltd. (TU Australia), a wholly-owned subsidiary of the Company.
The results of each acquired company are included only for the periods
subsequent to acquisition. (See Note 1 to Consolidated Financial Statements.)
On August 5, 1997, the merger transactions (Merger) between the former Texas
Utilities Company, now known as Texas Energy Industries Inc. (TEI), and ENSERCH
were completed. At the effective time of the Merger: (i) the former Texas
Utilities Company changed its name to TEI, (ii) TEI and ENSERCH merged with
wholly-owned subsidiaries of TUC Holding Company, which, as a result, owned all
the common stock of TEI and of ENSERCH, (iii) TUC Holding Company changed its
name to Texas Utilities Company (now the Company), (iv) each share of TEI's
common stock was automatically converted into one share of common stock of TUC,
and (v) each share of common stock of ENSERCH was automatically converted into
0.225 share of common stock of TUC, with cash issued in lieu of fractional
shares. The share conversions were tax-free transactions.
A-7
In the Merger, approximately 15. 9 million shares of TUC common stock were
issued to former holders of ENSERCH common stock. The value assigned to the TUC
shares issued and costs incurred in connection with the acquisition of ENSERCH
aggregated $579 million. At the date of the Merger, ENSERCH had debt and
preferred stock outstanding of approximately $1.3 billion.
Businesses and subsidiaries acquired in the Merger were Lone Star Gas Company
(Lone Star Gas), a gas distribution company in Texas, Lone Star Pipeline
Company (Lone Star Pipeline) and subsidiaries engaged in natural gas processing,
natural gas marketing, independent power production and international gas
distribution systems development.
On November 21, 1997, the Company acquired LCC. Approximately 8.7 million
shares of TUC common stock were issued to LCC stockholders in a stock-for-stock
exchange. The value assigned to the TUC shares issued and costs incurred in
connection with the acquisition of LCC aggregated $319 million. At the date of
the acquisition, LCC had debt outstanding of approximately $31 million.
The acquisitions of ENSERCH, LCC and Eastern Energy were accounted for as
purchase business combinations. The assets and liabilities of the acquired
companies at the acquisition dates were adjusted to their estimated fair
values. The excess of the purchase price paid by the Company over the estimated
fair value of 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 and liabilities of ENSERCH and LCC as of the date of
acquisition is continuing, and the final result awaits primarily the resolution
of income tax and other contingencies and finalization of some preliminary
estimates.
For financial reporting purposes, the Company is being treated 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 continues to seek 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.
In January 1998, the Company announced that it had approached the Energy Group
plc (TEG) in connection with its possible interest in acquiring TEG. TEG is a
diversified international energy group. Discussions between the Company and TEG
are continuing and may or may not lead to an offer being made by the Company.
Likewise, the timing, amount and funding of any specific new business investment
opportunities are presently undetermined.
Capital Expenditures
The Company and TU Electric
- ---------------------------
The primary capital expenditures of the Company and all of its majority-owned
subsidiaries (System Companies) in 1997 and as estimated for 1998 through 2000
are as follows:
1997 1998 1999 2000
---- ---- ---- ----
Thousands of Dollars
Cash construction expenditures
(excluding allowance for funds
used during construction)..... $ 577,000 $ 886,000 $ 799,000 $ 852,000
Nuclear fuel (excluding
allowance for funds used
during construction)........... 71,000 104,000 81,000 92,000
Maturities and redemptions of
long-term debt, sinking fund
requirements, redemptions of
preferred stock and reacquisi-
tions of common stock.......... 2,276,000 772,000 505,000 1,859,000
---------- ---------- ---------- ----------
Total......................... $2,924,000 $1,762,000 $1,385,000 $2,803,000
========== ========== ========== ==========
For information concerning construction work contemplated by the System
Companies and the commitments with respect thereto, see Note 15 to the
Consolidated Financial Statements.
A-8
In 1997, the Company bought ENSERCH for $579 million and LCC for $319 million
primarily through the issuance of common stock.
The primary capital expenditures of TU Electric in 1997 and as estimated for
1998 through 2000 are as follows:
1997 1998 1999 2000
---- ---- ---- ----
Thousands of Dollars
Cash construction expenditures (excluding
allowance for funds used during construction) ..................... $ 438,000 $ 449,000 $439,000 $441,000
Nuclear fuel (excluding allowance for funds used
during construction) .............................................. 71,000 104,000 81,000 92,000
Maturities and redemptions of long-term debt,
sinking fund requirements and redemptions
of preferred stock ................................................ 1,775,000 753,000 336,000 159,000
---------- ---------- -------- --------
Total ................................................... $2,284,000 $1,306,000 $856,000 $692,000
========== ========== ======== ========
See Item 2. Properties -- Capital Expenditures and Note 15 to Consolidated
Financial Statements.
Liquidity and Capital Resources
For 1997, the System Companies generated cash from operations sufficient to
meet operating needs and debt service 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, the
Company's primary subsidiary, to fund its capital requirements from operations
include responsive regulatory practices allowing recovery of capital investment
through adequate depreciation rates, recovery of the cost of fuel and purchased
power and the opportunity to earn competitive rates of return required in the
capital markets.
External funds of a permanent or long-term nature are obtained through the
issuance of common and preferred stock, preferred securities and long-term debt
by the System Companies. The capitalization ratios of the Company and its
subsidiaries at December 31, 1997, consisted of approximately 52% long-term
debt, 5% TU Electric obligated, mandatorily redeemable, preferred securities of
subsidiary trusts holding solely debentures of TU Electric, 2% preferred stock
and 41% common stock equity.
The capitalization ratios of TU Electric at December 31, 1997 consisted of
approximately 43% long-term debt, 7% TU Electric obligated, mandatorily
redeemable, preferred securities of subsidiary trusts holding solely debentures
of TU Electric, 1% preferred stock and 49% common stock equity.
Proceeds from financings by System Companies in 1997 were used primarily for
the early redemption or reacquisition of debt and preferred stock. The
financings consisted of:
Principal Current
Description Amount Interest Rates Maturity
----------- ---------- -------------- --------
Thousands of Dollars
Senior Notes issued by the Company .................................... $ 300,000 6.20% to 6.375% 2002-2004
Unsecured Debentures issued by TU Electric ............................. 300,000 7.17% 2007
Pollution Control Revenue Bonds (backed by TU Electric First Mortgage
Bonds) ............................................................. 212,715 3.70% to 5.60% 2022-2032
TU Electric obligated, mandatorily redeemable, preferred securities .... 493,273 7.183% to 8.175% 2037
Other .................................................................. 9,964
---------
Total .............................................................. $1,315,952
=========
During 1997, the Company purchased and retired 4,015,000 shares of its common
stock at a cost of $148.8 million. In addition, long-term debt and preferred
stock of subsidiary companies totaling $2.1 billion was retired. Early
redemptions of long-term debt and preferred stock may occur from time to time in
amounts presently undetermined. (See Notes 6 and 8 to Consolidated Financial
Statements.)
A-9
At December 31, 1997, TUC, TU Electric and ENSERCH had joint lines of credit
under credit facility agreements (Credit Agreements) with a group of commercial
banks. The Credit Agreements have two facilities. Facility A provides for
short-term borrowings aggregating up to $570 million outstanding at any one time
at variable interest rates and terminates April 23, 1998. Facility B provides
for short-term borrowings aggregating up to $1,330 million outstanding at any
one time at variable interest rates and terminates April 24, 2002. The combined
borrowings of TUC, TU Electric and ENSERCH under both facilities are limited to
an aggregate of $1,900 million outstanding at any one time. ENSERCH's
borrowings under both facilities are limited to an aggregate of up to $650
million outstanding at any one time. Borrowings under these facilities will be
used for working capital and other corporate purposes, including commercial
paper backup. The total of short-term borrowings authorized by the Board of
Directors of TUC at December 31, 1997, from banks or other lenders, was $2,150
million.
In addition, certain non-U.S. subsidiaries have revolving credit agreements
aggregating approximately $95 million, of which $61 million was outstanding at
December 31, 1997. These revolving credit agreements expire at various dates
through 2000.
In January 1998, the Company issued $200 million of 6.375% Series C Senior
Notes due 2008, and ENSERCH issued $125 million of 6 1/4% Series A Notes due
2003 and $125 million of Remarketed Reset Notes due 2008 with a variable
interest rate (5.82% at date of issuance). Net proceeds from these borrowings
were used to refinance or redeem like amounts of higher rate debt and preferred
stock.
The System Companies may issue additional debt and equity securities as
needed, including the possible future sale: (i) by TU Electric of up to $148.9
million principal amount of debt securities, (ii) by TU Electric of up to
250,000 shares of Cumulative Preferred Stock ($100 liquidation value), and (iii)
by ENSERCH of up to $250 million aggregate principal amount of securities, all
of which are currently registered with the Securities and Exchange Commission
(SEC) for offering pursuant to Rule 415 under the Securities Act of 1933.
Quantitative and Qualitative Disclosure About Market Risk
The Company's market risk exposure is primarily a result of changes in
interest rates and commodity price exposures. Derivative instruments including
options, swaps, futures and other contractual commitments are used to reduce and
manage a portion of those risks. With the exception of the marketing activities
of a subsidiary, Enserch Energy Services, Inc. (EES), the Company's
participation in derivative transactions are designated for hedging purposes;
derivative instruments are not held or issued for trading purposes.
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 does not obtain collateral to support the agreements
but monitors the financial viability of counterparties and believes its credit
risk is minimal on these transactions. The Company believes the risk of
nonperformance by counterparties is minimal.
INTEREST RATE MARKET RISK - The table below provides information concerning
the Company's and TU Electric's financial instruments as of December 31, 1997
that are sensitive to changes in interest rates, which include debt obligations
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 or 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 the 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.
A-10
Expected Maturity Date
---------------------------------------------------------------------------------
There- Fair
The Company 1998 1999 2000 2001 2002 after Total Value
- ----------- ---- ---- ---- ---- ---- ------ ----- -----
December 31, 1997 Millions of Dollars
Long-term Debt (including current maturities)
Fixed Rate ($US)............................. $772.1 $504.7 $868.5 $344.4 $595.1 $4,446.2 $7,531.0 $7,931.7
Average interest rate...................... 7.18% 8.38% 6.61% 8.00% 7.53% 7.54% 7.47% --
Variable Rate ($US).......................... -- -- $990.4 -- -- $1,010.1 $2,000.5 $2,000.5
Average interest rate...................... -- -- 6.18% -- -- 4.83% 5.50% --
Interest Rate Swaps (notional amounts)
Variable to Fixed ($US)...................... $16.3 $110.5 $32.5 -- $468.2 $100.0 $ 727.5 $(57.0)
Average pay rate........................... 5.29% 6.68% 6.14% -- 8.45% 7.18% 7.83% --
Average receive rate....................... 5.08% 4.89% 4.89% -- 5.23% 6.55% 5.34% --
Fixed to Variable ($US)...................... -- -- -- -- -- $350.0 $ 350.0 $6.1
Average pay rate........................... -- -- -- -- -- 6.32% 6.32% --
Average receive rate....................... -- -- -- -- -- 6.89% 6.89% --
TU Electric
- -----------
December 31, 1997
Long-term Debt Obligations (including
current maturities)
Fixed Rate ($US)............................. $752.6 $335.9 $159.4 $225.5 $373.8 $3,370.8 $5,218.0 $5,563.4
Average interest rate...................... 7.12% 8.92% 6.62% 7.49% 8.22% 7.69% 7.68% --
Variable Rate ($US).......................... -- -- -- -- -- $1,010.1 $1,010.1 $1,010.1
Average interest rate...................... -- -- -- -- -- 4.83% 4.83% --
Interest Rate Swaps (notional amounts)
Variable to Fixed ($US)...................... -- -- -- -- -- $ 100.0 $ 100.0 $ (1.4)
Average pay rate........................... -- -- -- -- -- 7.18% 7.18% --
Average receive rate....................... -- -- -- -- -- 6.55% 6.55% --
The Company and TU Electric
- ---------------------------
ENERGY MARKETING MARKET RISK - As part of its natural gas marketing
activities, EES enters into forward contracts that principally involve physical
delivery of natural gas and derivative financial instruments, including options,
swaps, futures and other contractual arrangements to offset price risks of gas
supply. These activities involve price commitments into the future and,
therefore, give rise to market risk. EES applies mark-to-market accounting to
its business activities. At December 31, 1997, natural gas marketing operations
had net commitments to sell approximately 50.6 billion cubic feet (Bcf) of
natural gas through the year 2003 with offsetting net financial positions to
purchase approximately 61.3 Bcf.
For purposes of new SEC disclosure requirements, EES has performed a
sensitivity analysis to estimate its exposure to market risk of its commodity
and related financial commitments. The exposure for fixed price natural gas
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. EES
uses market-implied volatilities to determine its exposure to volatility risk.
Market risk is estimated as the potential loss in fair value resulting from at
least a 15% change in market factors which may differ from actual results.
Using 15%, the most adverse change in fair value at December 31, 1997 as a
result of this analysis, was a reduction of $1.1 million. For additional
information regarding derivative instruments, see Note 9 to Consolidated
Financial Statements.
A-11
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, 1997, the current market value of the
debt and equity securities was $85.9 million and $74. 1 million, respectively.
A hypothetical 10% increase in interest rates and 10% decrease in equity prices
would result in a $10.8 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 System Companies are
subject to the provisions of Statement of Financial Accounting Standards (SFAS)
No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS 71).
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 System Companies would be required to assess the recoverability of
certain assets, including plant and regulatory assets, and, if impaired, to
write down the assets to reflect their fair market value. (See Note 2 to
Consolidated Financial Statements.) The System Companies cannot predict the
timing or extent of changes in the business environment that may require the
discontinuation of SFAS 71 application.
The Company and TU Electric
- ---------------------------
Although TU Electric cannot 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
operation or cash flows. (See Note 15 to Consolidated Financial Statements.)
Docket 9300 -- The PUC's final order (Order) in connection with TU Electric's
January 1990 rate increase request (Docket 9300) was reviewed by the 250th
Judicial District Court of Travis County, Texas, (District Court) and thereafter
was appealed to the Court of Appeals for the Third District of Texas and to the
Supreme Court of Texas (Supreme Court). As a result of such review and appeals,
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 would also be 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 January 1997, the Supreme Court denied a motion for rehearing on
the Comanche Peak minority owners issue filed by the original complainants. TU
Electric cannot predict the outcome of the reconsideration of the Order on
remand by the PUC.
In its decision, the Supreme Court also affirmed the previous $472 million
prudence disallowance related to Comanche Peak. Since the Company and TU
Electric each has previously recorded a charge to earnings for this prudence
disallowance, the Supreme Court's decision did not have an effect on the
Company's or TU Electric's current financial position, results of operation or
cash flows.
Docket 11735 -- In July 1994, TU Electric filed a petition in the 200th
Judicial District Court of Travis County, Texas to seek judicial review of the
final order of the PUC granting a $449 million, or 9.0%, rate increase in
connection with TU Electric's January 1993 rate increase request of $760
million, or 15.3% (Docket 11735). Other parties to the PUC proceedings also
filed appeals with respect to various portions of the order.
A-12
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 adopted in February 1996.
These tariffs also provide for generation-related ancillary services necessary
to support wholesale transactions. In August 1997, the PUC approved final
tariffs for TU Electric and implemented rates for other transmission providers
within the Electric Reliability Council of Texas (ERCOT) (Docket 15840). Under
rates implemented by the PUC, TU Electric's payments for transmission service
will 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. As such, the
current maximum impact on TU Electric for 1998 is an $8.52 million deficit,
which, in the opinion of TU Electric, is not expected to have a material effect
on its financial position, results of operation or cash flows.
Docket 17250 -- In late 1996, as part of its regular earnings monitoring
process, the PUC staff advised the PUC, after reviewing the 1995 Electric
Investor-Owned Utilities Earnings Report of TU Electric, that it believed TU
Electric was earning in excess of a reasonable rate of return, and the PUC and
TU Electric subsequently began discussions concerning possible remedies. It was
decided to limit negotiations to a resolution of issues concerning TU Electric's
earnings through 1997, and discussion of a longer-term resolution was deferred.
In July 1997, the PUC issued its final written order approving TU Electric's
proposal to make a one-time $80 million refund to its customers (Rate
Settlement) and to leave rates unchanged during the remainder of 1997. TU
Electric recorded the charge to revenues in July 1997 and included the refunds
in August 1997 billings. The proposal was the result of a joint stipulation in
which TU Electric was joined by the PUC General Counsel, on behalf of the PUC
Staff and the public interest, the Office of Public Utility Counsel, the state
agency charged with representing the interests of residential and small
commercial customers, and the Coalition of Cities served by TU Electric.
Docket 18490 -- On December 17, 1997, TU Electric, together with the PUC
General Counsel, the Office of Public Utility Counsel and various other parties
interested in TU Electric's rates and services, filed with the PUC a
stipulation and joint application which, if granted, would among other things:
(i) result in permanent retail 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, (ii) result in additional permanent retail base
rate credits beginning January 1, 1999, of 1.4% for residential customers, (iii)
impose a 11.35% cap on TU Electric's rate of return on equity during 1998 and
1999, with any sums earned above that cap being applied as additional nuclear
production depreciation, (iv) allow TU Electric to record depreciation
applicable to transmission and distribution assets in 1998 and 1999 as
additional depreciation of nuclear production assets, (v) establish an updated
cost of service study that includes interruptible customers as customer classes,
(vi) result in the permanent dismissal of pending appeals of prior PUC orders
including Docket No. 11735, if all other parties that have filed appeals of
those dockets also dismiss their appeals, (vii) result in the stay of any
proceedings in the remand of Docket 9300 prior to January 1, 2000, and (viii)
result in all gains from off-system sales of electricity in excess of the amount
included in base rates being flowed to customers through the fuel factor.
The PUC has until March 31, 1998 to approve or reject the stipulation and
joint application. Otherwise, TU Electric may terminate the base rate
reductions and all other aspects of the proposal upon giving two weeks notice to
the PUC.
Fuel Cost Recovery Rule -- TU Electric in July 1997, petitioned the PUC for
and received interim approval to refund approximately $67 million, including
interest, in over-collected fuel costs for the period October 1995 through May
1997 (Fuel Refund). Such over-collection was primarily due to TU Electric's
ability to use less expensive nuclear fuel and purchased power to offset a
higher-priced natural gas market during the period. Customer refunds were
included in August 1997 billings. A final order confirming the Fuel Refund was
entered by the PUC in October 1997.
Fuel Reconciliation Proceeding -- In July 1997, the PUC ruled on TU
Electric's petition seeking final reconciliation of all eligible fuel and
purchased power expenses incurred during the reconciliation period of July 1,
1992 through June 30, 1995 (approximately $4.7 billion ). In the ruling, the
PUC disallowed approximately $81 million of eligible fuel related costs
(including interest of $12 million) incurred during the reconciliation period
(Fuel Disallowance). The majority of the Fuel Disallowance (approximately $67
million) is related to replacement fuel costs as a result of the November 1993
collapse of the emissions chimney serving Unit 3 of the Monticello lignite-
fueled generating station. In addition, the PUC ruled that approximately $10
million from the gain on sale of sulfur dioxide allowances should be deferred
and reconsidered at a future date. TU Electric received a final written order
from the PUC and recorded the charge to revenues in August 1997. TU Electric
strongly disagrees with the Fuel Disallowance and has appealed the PUC's order.
A-13
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 existing 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 an economic development rider to attract new businesses and to encourage
existing 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.
Integrated Resource Plan -- In October 1994, TU Electric filed an application
for approval by the PUC of certain aspects of its Integrated Resource Plan (IRP)
for the ten year period 1995 - 2004. The IRP, developed as an experimental
pilot project in conjunction with regulatory and customer groups, included the
acquisition of electric energy through a competitive bidding process of third
party-supplied demand-side management resources and renewable resources. In
August 1995, the PUC remanded the case to an Administrative Law Judge for
development of a solicitation plan and to more closely conform the TU Electric
1995 IRP to new state legislation that required the PUC to adopt a state-wide
integrated resource planning rule by September 1, 1996. In January 1996, TU
Electric filed an updated IRP with the PUC along with a proposed plan for the
solicitation of resources through a competitive bidding process. The PUC issued
its final order on TU Electric's IRP in October 1996, and modified the order in
December 1996 and February 1997. The modified order approved a flexible
solicitation plan that will allow TU Electric to conduct up to three optional
resource solicitations for a total of 2,074 MW of demand-side and supply-side
resources prior to the filing of its next IRP in June 1999. TU Electric is
currently reviewing the need and timing for conducting the first of these
resource solicitations.
In addition to its solicitation plan in the IRP docket, TU Electric requested
and received approval from the PUC to expand its Power Cost Recovery tariff to
provide current cost recovery of resource acquisition costs for demand-side
management resources acquired in the 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.
Open-Access Transmission -- In February 1996, pursuant to the 1995 amendments
to PURA, 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
consisting of an ERCOT system-wide component and a distance-sensitive component.
The ERCOT system-wide component provides that each load-serving entity in ERCOT
will pay a share of the ERCOT-wide transmission cost of service based on the
entity's load. The distance-sensitive component provides that a distance-
sensitive rate will be paid to utilities that own transmission facilities, based
on the impact of transmitting power and energy to loads. The rates charged for
using the transmission system are designed to ensure that all market
participants pay on a comparable basis to use the system. While all users of
the transmission grid pay rates that are comparably designed, the impact on
individual users will differ.
In May 1996, TU Electric filed with the PUC, under Docket 15638, its
transmission cost information and tariffs for open-access wholesale transmission
service. These tariffs also provide for generation-related ancillary services
necessary to support wholesale transactions. Company-specific proceedings to
determine transmission rates for each transmission provider within ERCOT were
concluded in 1996. In August 1997, the PUC approved final tariffs for TU
Electric and implemented rates for other transmission providers within ERCOT.
As a result of the PUC rules, the organization and structure of ERCOT has
been changed to provide for equal governance among all wholesale electricity
market participants. These changes were made in order to facilitate wholesale
competition while ensuring continued reliability within ERCOT.
A-14
The Company
- -----------
LONE STAR GAS COMPANY AND LONE STAR PIPELINE COMPANY RATES -- In October
1996, Lone Star Pipeline filed a request with the RRC to increase the rate it
charges Lone Star Gas to store and transport gas ultimately destined for
residential and commercial customers in the 550 Texas cities and towns served by
Lone Star Gas. Lone Star Gas also requested that the RRC separately set rates
for costs to aggregate gas supply for these cities. Rates previously in effect
were set by the RRC in 1982. In September 1997, the RRC issued an order
reducing the charges by Lone Star Pipeline to Lone Star Gas for storage and
transportation services. In that order, the RRC did authorize separate charges
for the Lone Star Pipeline storage and transportation services, a separate
charge by Lone Star Gas for the cost of aggregating gas supplies, and a
continuation of the 100% flow through of purchased gas expense. The RRC also
imposed some new criteria for affiliate gas purchases and a new reconciliation
procedure that will require a review of purchased gas expenses every three
years. The RRC order has become final, but is being appealed by several parties
including Lone Star Pipeline and Lone Star Gas. The rates authorized by the
order became effective on December 1, 1997, and will result in an annual margin
reduction of approximately $8.2 million.
On August 20, 1996, the RRC ordered a general inquiry into the rates and
services of Lone Star Gas, most notably a review of Lone Star Gas' historic gas
cost and gas acquisition practices since the last rate setting. The inquiry
docket has been separated into different phases. Two of the phases, conversion
to the NARUC account numbering system and unbundling, have been dismissed by the
RRC, and one other phase, rate case expense, is pending RRC action on the basis
of a stipulation of all parties. In the phase dealing with historic gas cost
and gas acquisition practices, Lone Star Gas and Lone Star Pipeline have filed a
motion for summary disposition stating that any retroactive rate action would be
inappropriate and unlawful. Settlement discussions with intervenor cities are
ongoing. If the motion for summary disposition is denied, a hearing has been
scheduled to begin in August 1998. A number of management and transportation
related issues have been placed in a separate phase which still has an undefined
scope and is being held in abeyance pending the resolution of the phase dealing
with gas costs. Management believes that gas costs were prudently incurred and
were properly accounted for and recovered through the gas cost recovery
mechanism previously approved by the RRC. At this time, management is unable to
determine the ultimate outcome of the inquiry.
Competition
The Company and TU Electric
- ---------------------------
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 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. Although the Company is
unable to predict the ultimate impact of the Energy Policy Act, PURA and any
related regulations or legislation on the System Companies' operations, it
believes that such actions are consistent with the trend toward increased
competition in the energy industry.
In order to remain competitive, the System 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 their 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.
While TU Electric has experienced competitive pressures in the wholesale
market resulting in a small loss of load since the beginning of 1993, wholesale
sales represented a relatively low percentage of TU Electric's consolidated
operating revenues in 1997. TU Electric is unable to predict the extent of
future competitive developments in either the wholesale or retail markets or
what impact, if any, such developments may have on its operations.
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
A-15
toward a more competitive pricing and cost structure. Competition in the
electric utility industry was also addressed in the 1995 session of the Texas
legislature. PURA was amended to encourage greater wholesale competition and
flexible retail pricing. PURA amendments also 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, 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 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 stranded cost recovery. The PUC's current
estimate for TU Electric's potentially stranded retail costs ranged from a
projected excess of net book value over market value of $7.7 billion to a
projected excess of market value over net book value of $2.1 billion.
Legislation that would have authorized retail competition was not enacted by
the 1997 Texas legislature.
While the Company and TU Electric anticipate legislation being enacted during
the 1999 session of the Texas legislature to authorize competition in the retail
market, 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
operation or cash flows.
RESULTS OF OPERATION
The Company
- -----------
For the year ended December 31, 1997, net income for the Company decreased
approximately 12% from the prior period. Results for 1997 were reduced by the
recognition of TU Electric's $80.0 million Rate Settlement refund in July 1997,
the August 1997 $81.1 million Fuel Disallowance (including interest) and a
charge of $10.1 million from the sale of sulfur dioxide allowances previously
recognized. After revenue-related and income taxes, these settlements reduced
income by $103.4 million. Excluding these items, 1997 net income increased
slightly over the 1996 period. For the year ended December 31, 1996, net
income increased approximately 14% over the comparable 1995 period, excluding
the after-tax effect of recording a September 1995 impairment of several non-
performing assets. Such impairment, on an after-tax basis, amounted to $802
million. (See Note 14 to Consolidated Financial Statements.)
TU Electric continued to experience core revenue and sales volume growth in
excess of 3% due to increases in both number of customers and usage. Warmer
than normal summer weather contributed to 1996 results, while summer weather was
normal in 1995 and 1997.
Operating revenues increased approximately 21% and 16% for the years ended
December 31, 1997 and 1996, respectively. In 1997, the increase in operating
revenues was due primarily to the inclusion of ENSERCH revenues ($1,278.0
million) for the period following the Merger and to TU Electric's transmission
service revenues ($113.8 million) from implementing the PUC's Open Access
Transmission Rule effective January 1, 1997. LCC's revenues after acquisition
were $11.9 million. In 1996, the increase was due primarily to a full year of
Eastern Energy's revenues ($474 million).
Base rate electricity revenues (including unbilled sales) decreased slightly
from 1996 as a result of the Rate Settlement refund mentioned above, while
electric energy sales in megawatt hours (including unbilled sales) increased
approximately 2% and 11% for 1997 and 1996, respectively. Fuel revenue
increased in 1997 and 1996 due primarily to increases in fuel costs driven by
increased energy sales and spot market gas prices, partially offset, in 1997, by
the Fuel Disallowance.
Fuel and purchased power expense increased approximately 4% and 30% for 1997
and 1996, respectively. The increases were primarily due to increased energy
sales and increased spot market gas prices and in 1996 included 13.1%
attributable to Eastern Energy for a full year. (See Consolidated Operating
Statistics.) Gas purchased for resale represents the cost of gas ultimately sold
to ENSERCH gas customers, which is recovered in rates.
Total operating expenses, excluding fuel and purchased power and gas
purchased for resale, increased approximately 15% for 1997 and 9% for 1996
(including 8.6% in 1997 attributable to ENSERCH companies since acquisition and
5.7% in
A-16
1996 attributable to Eastern Energy). Operation and maintenance expense
increased in 1997 as result of recording third party transmission expenses in
accordance with the PUC's Open Access Transmission Rule, partially offset by
decreased employee benefit expenses. The 1996 increase is due primarily to
increases in employee benefit expenses and payroll expenses. Taxes other than
income increased in 1997 due primarily to the effect of ENSERCH and LCC amounts
subsequent to acquisition. Taxes other than income decreased in 1996 as a result
of a reduction in TU Electric's ad valorem tax obligation due primarily to a
property tax rate reduction, partially offset by an increase in state and local
gross receipts tax.
The change in other income (deductions) - net in 1997 was primarily due to
losses from an interest in a telecommunications partnership. Amounts for 1996
were lower than the previous year due primarily to increased non-utility
property expenses and decreased allowance for equity funds used during
construction, partially offset by gains on the disposition of certain
properties.
Interest expense and distributions on preferred securities and preferred
stock of subsidiaries totaled $860.6 million in 1997, $884.3 million in 1996 and
$792.9 million in 1995. The Company's capital restructuring and debt reduction
programs have favorably affected the comparisons. Year - to - year comparisons
are also affected by the debt incurred or assumed in connection with the 1997
acquisitions of ENSERCH and LCC and the December 1995 acquisition of Eastern
Energy. Interest expense in 1996 included an interest payment related to a
settlement with the Internal Revenue Service, and 1997 interest expense included
a charge related to the settlement on over-recovered fuel. Allowance for funds
used during construction (AFUDC) decreased $2.4 million from 1996 to 1997 and
$4.1 million from 1995 to 1996.
The change in income tax expense (benefit) from 1995 to 1996 was due
primarily to the effects of the recording of the September 1995 asset
impairment. (See Note 10 to Consolidated Financial Statements for a
reconciliation of income taxes (benefit) computed at the statutory rate to
provision for income taxes (benefit).)
TU Electric
- -----------
For the year ended December 31, 1997, net income for TU Electric decreased
approximately 11% from the prior period. Results for 1997 were reduced by the
Rate Settlement, Fuel Disallowance and charge mentioned above which totaled
$103.4 million after-taxes. Excluding these items, 1997 net income increased
slightly over the 1996 period. For the year ended December 31, 1996, net
income increased approximately 12% over the comparable 1995 period (excluding
the $316 million after-tax effect of the September 1995 asset impairment).
Operating revenues increased approximately 2% and 8% for the years ended
December 31, 1997 and 1996, respectively. In 1997, the increase in operating
revenue reflects transmission service revenues ($113.5 million) from
implementing the PUC's Open Access Transmission Rule effective January 1, 1997,
with revenue increases due to customer growth essentially offsetting the impact
of the Rate Settlement, the Fuel Disallowance and the charge related to the
sulphur dioxide allowances. In 1996, the increase was a result of customer
growth, increased usage and warmer than normal summer weather.
Base rate electricity revenues (including unbilled sales) decreased slightly
from 1996 as a result of the Rate Settlement refund mentioned above while
electric energy sales in MWh (including unbilled sales) increased approximately
2% and 6% for 1997 and 1996, respectively. Fuel revenue increased in 1997 and
1996 due primarily to increases in fuel costs driven by increased energy sales
and spot market gas prices, partially offset, in 1997, by the Fuel Disallowance.
Fuel and purchased power expense increased approximately 5% and 16% for 1997
and 1996, respectively. The increases were primarily due to increased energy
sales and increased spot market gas prices.
Total operating expenses, excluding fuel and purchased power and gas purchased
for resale, increased approximately 5% for 1997 and 4% for 1996. Operation and
maintenance expense increased in 1997 as result of recording third party
transmission expenses in accordance with the PUC's Open Access Transmission
Rule, partially offset by decreased employee benefit expenses. The 1996
increase is due primarily to increases in employee benefit expense and payroll
expense. Taxes, other than income taxes decreased in 1996 as a result of a
reduction in TU Electric's ad valorem tax obligation due primarily to a property
tax rate reduction, partially offset by an increase in state and local gross
receipts tax.
A-17
Other income (deductions) - net decreased in 1997 primarily due to lower
income tax benefits while 1995 included the after tax effects of the impairment
write-down.
Total interest charges, excluding AFUDC and distributions on preferred
securities of subsidiary trusts, decreased approximately 5% in each of the years
1997 and 1996 compared to the prior year period. The capital restructuring and
debt reduction programs have favorably affected the comparisons.
CHANGES IN ACCOUNTING STANDARDS
The Company and TU Electric
- ---------------------------
SFAS 130, "Reporting Comprehensive Income," will become effective in 1998.
This statement requires companies to report and display comprehensive income and
its components (revenues, expenses, gains and losses). Comprehensive income
includes all changes in equity during a period except those resulting from
investments by owners and distributions to owners.
SFAS 131, "Disclosures About Segments of an Enterprise and Related
Information," will become effective in 1998. This statement establishes
standards for defining and reporting business segments. The Company and TU
Electric are currently determining their reportable segments.
The adoption of SFAS 130 and SFAS 131 will not affect financial position,
results of operations or cash flows.
YEAR 2000 ISSUES
Many existing computer programs use only two digits to identify a year in the
date field. These programs were designed and developed without considering the
impact of the upcoming change in the century. If not corrected, many computer
applications could fail or produce erroneous data by or at the Year 2000. The
Year 2000 issues affect virtually all companies and organizations.
The Company began its Year 2000 initiative in 1996 by addressing mainframe-
based application systems. In early 1997, an infrastructure project to address
information technology (IT) related equipment and systems software was begun.
In late 1997, a corporate-wide project to address Year 2000 issues related to
embedded systems such as process controls for energy production and delivery and
client-developed applications was begun. Most of the ENSERCH mainframe
applications, infrastructure, embedded systems and client-developed applications
that will not be migrated to existing or planned Company systems have been
incorporated into these projects. These projects extend beyond the Company's
organization in an effort to also work with key vendors, service suppliers and
others so that the Company can appropriately prepare for Year 2000.
The remediation and replacement work on the majority of IT application systems
and infrastructure are expected to be completed by the end of 1998. Much of the
work on the corporate-wide Year 2000 project is expected to be completed by the
end of 1998, although the project will extend into 1999. Based on present
assessments of the IT and infrastructure projects, a cost of $11.25 million was
estimated. These costs are being expensed as incurred over the four-year period
(1996 through 1999) covered by the projects. Assessment of the cost of the
corporate-wide Year 2000 project is in the early stages.
Eastern Energy initiated a Year 2000 project in the third quarter of 1997.
The estimated cost of that project is $1.8 million, with completion anticipated
in early 1999. The cost to either modify or replace LCC application systems
affected by Year 2000 is estimated to be $1.5 million, with completion
anticipated in 1999. The effect on LCC's embedded systems is still being
assessed.
A-18
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, 1997, 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/ J. W. PINKERTON
--------------------------------------------
J. W. Pinkerton, Controller and
Principal Accounting Officer
A-19
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, 1997, 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/ ROBERT S. SHAPARD
--------------------------------------------
Robert S. Shapard, Treasurer and Assistant
Secretary and Principal Financial Officer
/s/ J. W. PINKERTON
--------------------------------------------
J. W. Pinkerton, Controller and
Principal Accounting Officer
A-20
INDEPENDENT AUDITORS' REPORT
Texas Utilities Company and Subsidiaries:
We have audited the accompanying consolidated balance sheets of Texas
Utilities Company and subsidiaries as of December 31, 1997 and 1996, and the
related consolidated statements of income, cash flows and common stock equity
for each of the three years in the period ended December 31, 1997. 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 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 the Texas Utilities Company and
subsidiaries at December 31, 1997 and 1996, and the results of their operations
and their cash flows for each of the three years in the period ended December
31, 1997, in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Dallas, Texas
February 24, 1998
A-21
INDEPENDENT AUDITORS' REPORT
Texas Utilities Electric Company and Subsidiaries:
We have audited the accompanying consolidated balance sheets of Texas Utilities
Electric Company (TU Electric) and subsidiaries as of December 31, 1997 and
1996, and the related consolidated statements of income, retained earnings and
cash flows for each of the three years in the period ended December 31, 1997.
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, 1997 and 1996, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1997, in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Dallas, Texas
February 24, 1998
A-22
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31,
------------------------------------------
1997 1996 1995
---- ---- ----
Thousands of Dollars
OPERATING REVENUES............................................. $7,945,608 $6,550,928 $5,638,688
---------- ---------- ----------
OPERATING EXPENSES
Fuel and purchased power...................................... 2,212,689 2,136,309 1,640,990
Gas purchased for resale...................................... 1,052,977 -- --
Operation and maintenance..................................... 1,548,150 1,256,280 1,109,644
Depreciation and amortization................................. 666,448 620,505 563,819
Taxes other than income....................................... 558,673 534,844 536,608
---------- ---------- ----------
Total operating expenses..................................... 6,038,937 4,547,938 3,851,061
---------- ---------- ----------
OPERATING INCOME............................................... 1,906,671 2,002,990 1,787,627
OTHER INCOME (DEDUCTIONS) -- NET............................... (17,588) (1,148) 24,583
---------- ---------- ----------
INCOME BEFORE INTEREST, OTHER CHARGES
AND INCOME TAXES............................................. 1,889,083 2,001,842 1,812,210
---------- ---------- ----------
INTEREST AND OTHER CHARGES
Interest...................................................... 762,937 797,893 706,182
Allowance for borrowed funds used during construction......... (8,890) (11,248) (15,327)
Impairment of assets.......................................... -- -- 1,233,320
Distributions on TU Electric obligated, mandatorily
redeemable, preferred securities of subsidiary trusts
holding solely debentures of TU Electric..................... 69,701 33,001 1,801
Preferred stock dividends of subsidiaries..................... 27,983 53,358 84,914
---------- ---------- ----------
Total interest and other charges............................ 851,731 873,004 2,010,890
---------- ---------- ----------
INCOME (LOSS) BEFORE INCOME TAXES.............................. 1,037,352 1,128,838 (198,680)
INCOME TAX EXPENSE (BENEFIT)................................... 376,898 375,232 (60,035)
---------- ---------- ----------
NET INCOME (LOSS).............................................. $ 660,454 $ 753,606 $ (138,645)
========== ========== ==========
Average shares of common stock
outstanding (thousands)....................................... 230,958 225,160 225,841
Per share of common stock:
Basic earnings (loss)....................................... $2.86 $3.35 $(0.61)
Diluted earnings (loss)..................................... $2.85 $3.35 $(0.61)
Dividends declared.......................................... $2.125 $2.025 $ 2.81
See Notes to Consolidated Financial Statements.
A-23
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
-------------------------------------------
1997 1996 1995
---- ---- ----
Thousands of Dollars
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)......................................................... $ 660,454 $ 753,606 $ (138,645)
Adjustments to reconcile net income (loss) to cash
provided by operating activities:
Depreciation and amortization (including amounts charged to fuel)....... 838,606 774,305 725,646
Deferred income taxes -- net............................................ 167,705 184,612 (204,550)
Investment tax credits -- net........................................... (22,851) (33,075) (22,774)
Allowance for equity funds used during construction..................... (5,236) (1,575) (6,680)
Impairment of assets.................................................... -- -- 1,233,320
Changes in operating assets and liabilities:
Accounts receivable................................................... (441,964) (2,503) (22,898)
Inventories........................................................... (13,891) 6,328 18,701
Accounts payable...................................................... 333,763 33,388 10,904
Interest and taxes accrued............................................ 39,902 (33,463) (94,158)
Other working capital................................................. 90,322 9,912 (25,932)
Over/(under) - recovered fuel revenue -- net of deferred taxes........ (20,483) (47,368) 94,717
Gas marketing risk management assets and liabilities.................. (13,142) -- --
Other -- net.......................................................... 45,933 79,918 5,902
---------- ---------- ----------
Cash provided by operating activities............................... 1,659,118 1,724,085 1,573,553
---------- ---------- ----------
CASH FLOWS FROM FINANCING ACTIVITIES
Issuances of securities:
First mortgage bonds.................................................... 212,715 244,225 535,055
Other long-term debt.................................................... 609,964 1,199,679 300,000
TU Electric obligated, mandatorily redeemable, preferred securities
of subsidiary trusts holding solely debentures of TU Electric.......... 493,273 -- 381,476
Retirements of securities:
First mortgage bonds.................................................... (939,467) (556,847) (684,385)
Other long-term debt.................................................... (634,407) (1,273,934) (202,520)
Preferred stock of subsidiaries......................................... (553,093) (50,269) (504,781)
Common stock............................................................ (148,780) (51,636) --
Change in notes payable:
Commercial paper........................................................ 1,102,749 (31,894) (78,841)
Banks................................................................... (543,080) (140,378) 731,945
Common stock dividends paid............................................... (478,592) (451,063) (695,656)
Debt premium, discount, financing and reacquisition expenses.............. (40,774) (44,043) (123,668)
---------- ---------- ----------
Cash used in financing activities................................... (919,492) (1,156,160) (341,375)
---------- ---------- ----------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures................................................. (586,097) (434,139) (434,338)
Allowance for equity funds used during construction (excluding
amount for nuclear fuel)................................................. 2,941 892 3,952
Change in construction receivables/payables -- net........................ (1,688) (706) 2,140
Nuclear fuel (excluding allowance for equity funds used
during construction)..................................................... (74,510) (58,895) (55,013)
Acquisitions.............................................................. 4,777 (9,821) (616,865)
Other investments......................................................... (58,753) (75,822) (111,175)
---------- ---------- ----------
Cash used in investing activities................................... (713,330) (578,491) (1,211,299)
---------- ---------- ----------
EFFECT OF EXCHANGE RATE CHANGES ON CASH.................................... 2,294 1,558 (3,452)
---------- ---------- ----------
NET CHANGE IN CASH AND CASH EQUIVALENTS.................................... 28,590 (9,008) 17,427
CASH AND CASH EQUIVALENTS -- BEGINNING BALANCE............................ 15,845 24,853 7,426
---------- ---------- ----------
CASH AND CASH EQUIVALENTS -- ENDING BALANCE................................ $ 44,435 $ 15,845 $ 24,853
========== ========== ==========
See Notes to Consolidated Financial Statements.
A-24
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
--------------------------
1997 1996
---- ----
Thousands of Dollars
PROPERTY, PLANT AND EQUIPMENT
Electric:
Production............................................... $16,294,778 $16,277,151
Transmission............................................. 1,675,681 1,607,925
Distribution............................................. 5,779,226 5,655,677
Gas distribution and pipeline.............................. 1,068,708 --
Telecommunications......................................... 145,125 14
Other...................................................... 562,890 503,674
----------- -----------
Total................................................. 25,526,408 24,044,441
Less accumulated depreciation.............................. 6,715,662 6,127,610
----------- -----------
Net of accumulated depreciation........................ 18,810,746 17,916,831
Construction work in progress.............................. 330,184 240,612
Nuclear fuel (net of accumulated amortization: 1997
-- $456,490,000;
1996 --$369,114,000)................................... 242,018 252,589
Held for future use........................................ 24,087 24,483
Less reserve for regulatory disallowances 836,005 836,005
----------- -----------
Net property, plant and equipment....................... 18,571,030 17,598,510
----------- -----------
INVESTMENTS
Goodwill (net of accumulated amortization:
1997-- $33,444,000; 1996--$15,894,000)................... 1,423,420 528,102
Other investments.......................................... 851,320 630,121
----------- -----------
Total investments...................................... 2,274,740 1,158,223
----------- -----------
CURRENT ASSETS
Cash and cash equivalents.................................. 44,435 15,845
Accounts receivable:
Customers................................................. 941,506 290,111
Other..................................................... 50,883 44,032
Allowance for uncollectible accounts...................... (11,322) (6,262)
Inventories -- at average cost:
Materials and supplies.................................... 209,825 200,601
Fuel stock................................................ 81,490 77,227
Gas stored underground.................................... 156,637 44,472
Gas marketing risk management assets....................... 365,650 --
Prepayments................................................ 59,809 56,324
Deferred income taxes...................................... 76,307 50,972
Other current assets....................................... 19,628 14,084
----------- -----------
Total current assets.................................... 1,994,848 787,406
----------- -----------
DEFERRED DEBITS
Unamortized regulatory assets.............................. 1,853,016 1,753,418
Deferred income taxes...................................... -- 10,997
Other deferred debits...................................... 180,495 89,101
----------- -----------
Total deferred debits................................... 2,033,511 1,853,516
----------- -----------
Total............................................. $24,874,129 $21,397,655
=========== ===========
See Notes to Consolidated Financial Statements.
A-25
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
--------------------------
1997 1996
---- ----
Thousands of Dollars
CAPITALIZATION
Common stock without par value -- net.............. $ 5,587,200 $ 4,787,047
Retained earnings.................................. 1,311,875 1,202,390
Cumulative currency translation adjustment......... (56,013) 43,476
----------- -----------
Total common stock equity...................... 6,843,062 6,032,913
Preferred stock of subsidiaries:
Not subject to mandatory redemption.............. 304,194 464,427
Subject to mandatory redemption.................. 20,600 238,391
TU Electric obligated, mandatorily redeemable,
preferred securities of subsidiary trusts
holding solely debentures of TU Electric.......... 875,146 381,311
Long-term debt, less amounts due currently......... 8,759,379 8,668,111
----------- -----------
Total capitalization........................... 16,802,381 15,785,153
----------- -----------
CURRENT LIABILITIES
Notes payable:
Commercial paper................................. 570,000 253,151
Banks............................................ 44,442 69,788
Long-term debt due currently....................... 772,071 356,076
Accounts payable................................... 879,593 336,391
Gas marketing risk management liabilities.......... 357,044 --
Dividends declared................................. 139,994 129,879
Customers' deposits................................ 91,440 80,390
Taxes accrued...................................... 182,532 143,424
Interest accrued................................... 193,125 156,758
Deferred income taxes.............................. 7,919 10,951
Over-recovered fuel revenue........................ 11,987 42,984
Other current liabilities.......................... 271,853 90,485
----------- -----------
Total current liabilities...................... 3,522,000 1,670,277
----------- -----------
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES
Accumulated deferred income taxes.................. 2,989,254 2,812,623
Unamortized investment tax credits................. 570,283 589,713
Pensions and other postretirement benefits......... 402,292 195,667
Other deferred credits and noncurrent liabilities.. 587,919 344,222
----------- -----------
Total deferred credits and other noncurrent
liabilities................................... 4,549,748 3,942,225
COMMITMENTS AND CONTINGENCIES (Note 15)
----------- -----------
Total........................................... $24,874,129 $21,397,655
=========== ===========
See Notes to Consolidated Financial Statements.
A-26
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
Year Ended December 31,
------------------------------------
1997 1996 1995
---- ---- ----
Thousands of Dollars
COMMON STOCK without par value-authorized shares -- 500,000,000:
Balance at beginning of year....................................... $4,787,047 $4,806,912 $4,798,797
Issued for acquisitions:
ENSERCH Corporation (15,861,272 shares).................... 565,105 -- --
Lufkin-Conroe Communications Co. (8,727,730 shares)....... 317,142 -- --
Issued for Long-Term Incentive Compensation Plan
(61,000 shares).............................................. 2,594 -- --
Net change in unamortized costs of Long-Term Incentive
Compensation Plan............................................ (2,197) -- --
Common stock repurchased and retired (4,015,000 shares in 1997
and 1,238,480 shares in 1996)................................ (90,186) (27,980) --
Special allocation to Thrift Plan by trustee.................... 8,115 8,137 8,115
Other........................................................... (420) (22) --
---------- ---------- ----------
Balance at end of year (1997-245,237,559 shares;
1996 -- 224,602,557 shares; and 1995 - 225,841,037 shares) 5,587,200 4,787,047 4,806,912
---------- ---------- ----------
RETAINED EARNINGS:
Balance at beginning of year....................................... 1,202,390 924,444 1,691,250
Net income (loss)............................................... 660,454 753,606 (138,645)
Dividends declared on common stock.............................. (496,244) (456,059) (634,613)
Common stock repurchased and retired............................ (58,594) (23,633) --
LESOP dividend deduction tax benefit and other.................. 3,869 4,032 6,452
---------- ---------- ----------
Balance at end of year............................................. 1,311,875 1,202,390 924,444
---------- ---------- ----------
CUMULATIVE CURRENCY TRANSLATION ADJUSTMENT:
Balance at beginning of year....................................... 43,476 397 --
Change during the year - net of deferred income taxes............ (99,489) 43,079 397
---------- ---------- ----------
Balance at end of year............................................. (56,013) 43,476 397
---------- ---------- ----------
COMMON STOCK EQUITY................................................. $6,843,062 $6,032,913 $5,731,753
========== ========== ==========
See Notes to Consolidated Financial Statements.
A-27
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31,
------------------------------
1997 1996 1995
---- ---- ----
Thousands of Dollars
OPERATING REVENUES $6,135,417 $6,029,611 $5,560,462
---------- ---------- ----------
OPERATING EXPENSES
Fuel and purchased power............. 2,062,709 1,965,756 1,697,091
Operation and maintenance............ 1,226,384 1,111,911 1,049,034
Depreciation and amortization........ 572,277 561,902 549,611
Income taxes......................... 419,681 421,012 382,315
Taxes other than income.............. 507,306 506,432 512,045
---------- ---------- ----------
Total operating expenses........... 4,788,357 4,567,013 4,190,096
---------- ---------- ----------
OPERATING INCOME....................... 1,347,060 1,462,598 1,370,366
---------- ---------- ----------
OTHER INCOME (LOSS)
Allowance for equity funds used
during construction................. 5,202 1,549 6,658
Impairment of assets................. -- -- (486,350)
Other income (deductions) -- net..... (1,699) 503 8,625
Income taxes......................... 10,135 15,513 169,362
---------- ---------- ----------
Total other income (loss).......... 13,638 17,565 (301,705)
---------- ---------- ----------
INCOME BEFORE INTEREST AND OTHER
CHARGES............................... 1,360,698 1,480,163 1,068,661
---------- ---------- ----------
INTEREST AND OTHER CHARGES
Interest on mortgage bonds........... 439,398 486,791 526,977
Interest on other long-term debt..... 22,124 26,456 44,071
Other interest....................... 65,744 82,459 58,500
Distributions on TU Electric
obligated, mandatorily redeemable,
preferred securities of subsidiary
trusts holding solely debentures
of TU Electric...................... 69,701 33,001 1,801
Allowance for borrowed funds used
during construction................. (8,143) (11,239) (15,319)
---------- ---------- ----------
Total interest and other charges.. 588,824 617,468 616,030
---------- ---------- ----------
NET INCOME............................. 771,874 862,695 452,631
PREFERRED STOCK DIVIDENDS.............. 26,850 53,358 84,914
---------- ---------- ----------
NET INCOME AVAILABLE FOR
COMMON STOCK.......................... $ 745,024 $ 809,337 $ 367,717
========== ========== ==========
STATEMENTS OF CONSOLIDATED RETAINED EARNINGS
Year Ended December 31,
-------------------------------
1997 1996 1995
---- ---- ----
Thousands of Dollars
BALANCE AT BEGINNING OF YEAR............. $1,373,602 $1,067,593 $ 948,136
Net income.............................. 771,874 862,695 452,631
Transfer from common stock.............. -- -- 433,820
Preferred stock dividends............... (26,850) (53,358) (84,914)
Common stock dividends.................. (136,416) (503,328) (682,080)
---------- ---------- ----------
BALANCE AT END OF YEAR................... $1,982,210 $1,373,602 $1,067,593
========== ========== ==========
See Notes to Consolidated Financial Statements.
A-28
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
------------------------------------------
1997 1996 1995
---- ---- ----
Thousands of Dollars
CASH FLOWS FROM OPERATING ACTIVITIES
Net income.............................................. $ 771,874 $ 862,695 $ 452,631
Adjustments to reconcile net income to cash provided by
operating activities:
Depreciation and amortization (including amounts
charged to fuel)...................................... 710,366 684,710 685,693
Deferred income taxes -- net........................... 134,263 149,851 83,621
Investment tax credits -- net.......................... (21,222) (31,501) (21,201)
Allowance for equity funds used during construction.... (5,202) (1,549) (6,658)
Impairment of assets................................... -- -- 427,478
Changes in operating assets and liabilities:
Accounts receivable................................... (123,735) 9,190 (24,807)
Inventories........................................... (4,122) 3,366 612
Accounts payable...................................... 44,169 52,126 1,842
Interest and taxes accrued............................ 42,086 (18,718) (110,455)
Other working capital................................. 82,651 (1,255) 4,917
Over/(under) - recovered fuel revenue -- net of
deferred taxes....................................... (20,488) (47,368) 94,717
Other -- net.......................................... 58,890 39,908 (2,580)
--------- --------- ---------
Cash provided by operating activities............... 1,669,530 1,701,455 1,585,810
--------- --------- ---------
CASH FLOWS FROM FINANCING
ACTIVITIES
Issuances of securities:
First mortgage bonds................................... 212,715 244,225 535,055
Other long-term debt................................... 300,000 -- 300,000
TU Electric obligated, mandatorily redeemable,
preferred securities of subsidiary trusts holding
solely debentures of TU Electric...................... 493,273 -- 381,476
Retirements of securities:
First mortgage bonds................................... (939,440) (556,820) (684,385)
Other long-term debt................................... (2,413) (302,458) (183,947)
Preferred stock........................................ (553,094) (50,269) (504,781)
Common stock........................................... (279,654) -- --
Change in notes receivable/payable -- affiliates......... 218,444 (33,159) 26,238
Change in notes payable -- commercial paper.............. (253,151) (68,839) (41,896)
Preferred stock dividends paid........................... (36,246) (54,411) (95,304)
Common stock dividends paid.............................. (272,832) (366,912) (682,080)
Debt premium, discount, financing and reacquisition
expenses................................................ (26,892) (37,898) (123,393)
--------- --------- ---------
Cash used in financing activities......................... (1,139,290) (1,226,541) (1,073,017)
--------- --------- ---------
CASH FLOWS FROM INVESTING ACTIVITIES
Construction expenditures................................ (446,088) (377,438) (407,305)
Allowance for equity funds used during construction
(excluding amount for nuclear fuel)..................... 2,907 867 3,929
Change in construction receivables/payables -- net....... (1,688) (706) (1,305)
Nuclear fuel (excluding allowance for equity funds used
during construction).................................... (74,510) (58,895) (55,013)
Other investments...................................... (12,037) (48,370) (37,165)
--------- --------- ---------
Cash used in investing activities......................... (531,416) (484,542) (496,859)
--------- --------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS................... (1,176) (9,628) 15,934
CASH AND CASH EQUIVALENTS -- BEGINNING BALANCE............ 13,005 22,633 6,699
--------- --------- ---------
CASH AND CASH EQUIVALENTS -- ENDING BALANCE............... $ 11,829 $ 13,005 $ 22,633
========= ========= =========
See Notes to Consolidated Financial Statements.
A-29
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
------------------------
1997 1996
---- ----
Thousands of Dollars
ELECTRIC PLANT
In service:
Production........................................ $15,369,306 $15,330,974
Transmission...................................... 1,669,259 1,601,628
Distribution...................................... 4,745,270 4,442,547
General........................................... 436,059 432,178
----------- -----------
Total........................................... 22,219,894 21,807,327
Less accumulated depreciation..................... 6,120,309 5,594,363
----------- -----------
Electric plant in service, less
accumulated depreciation....................... 16,099,585 16,212,964
Construction work in progress...................... 190,579 210,573
Nuclear fuel (net of accumulated amortization:
1997 -- $456,490,000, 1996 -- $369,114,000)....... 242,017 252,589
Held for future use................................ 23,966 24,483
----------- -----------
Electric plant, less accumulated
depreciation and amortization.................. 16,556,147 16,700,609
Less reserve for regulatory disallowances.......... 836,005 836,005
----------- -----------
Net electric plant.............................. 15,720,142 15,864,604
----------- -----------
INVESTMENTS......................................... 534,487 508,437
----------- -----------
CURRENT ASSETS
Cash and cash equivalents.......................... 11,829 13,005
Accounts receivable:
Customers........................................ 345,041 215,706
Other............................................ 18,710 23,282
Allowance for uncollectible accounts............. (6,049) (5,021)
Notes receivable -- affiliates..................... -- 35,515
Inventories -- at average cost:
Materials and supplies........................... 181,157 181,405
Fuel stock....................................... 81,489 77,119
Prepayments........................................ 31,338 31,758
Deferred income taxes.............................. 49,359 50,882
Other current assets............................... 1,818 3,246
----------- -----------
Total current assets............................. 714,692 626,897
----------- -----------
DEFERRED DEBITS
Unamortized regulatory assets...................... 1,796,516 1,735,306
Other deferred debits.............................. 67,596 59,695
----------- -----------
Total deferred debits............................ 1,864,112 1,795,001
----------- -----------
Total............................................ $18,833,433 $18,794,939
=========== ===========
See Notes to Consolidated Financial Statements.
A-30
TEXAS UTILITIES ELECTRIC COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
December 31,
-------------------------
1997 1996
---- ----
Thousands of Dollars
CAPITALIZATION
Common stock without par value:
Authorized shares -- 180,000,000
Outstanding shares 1997 -- 142,931,000; 1996 --
156,800,000...................................... $ 4,316,235 $ 4,732,305
Retained earnings................................... 1,982,210 1,373,602
----------- -----------
Total common stock equity........................ 6,298,445 6,105,907
Preferred stock:
Not subject to mandatory redemption............... 129,194 464,427
Subject to mandatory redemption................... 20,600 238,391
TU Electric obligated, mandatorily redeemable,
preferred securities of subsidiary trusts
holding solely debentures of TU Electric........... 875,146 381,311
Long-term debt, less amounts due currently.......... 5,475,447 6,310,594
----------- -----------
Total capitalization............................. 12,798,832 13,500,630
----------- -----------
CURRENT LIABILITIES
Notes payable:
Affiliates...................................... 182,929 --
Commercial paper................................ -- 253,151
Long-term debt due currently........................ 752,645 338,213
Accounts payable:
Affiliates........................................ 289,075 126,143
Other............................................. 152,367 136,401
Dividends declared.................................. 2,567 148,379
Customers' deposits................................. 74,256 70,141
Taxes accrued....................................... 167,009 132,514
Interest accrued.................................... 140,538 132,947
Over-recovered fuel revenue......................... 11,987 42,984
Other current liabilities 134,369 57,681
----------- -----------
Total current liabilities........................ 1,907,742 1,438,554
----------- -----------
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES
Accumulated deferred income taxes................... 3,216,951 2,989,612
Unamortized investment tax credits.................. 556,743 577,965
Other deferred credits and noncurrent liabilities 353,165 288,178
----------- -----------
Total deferred credits and other noncurrent
liabilities..................................... 4,126,859 3,855,755
COMMITMENTS AND CONTINGENCIES (Note 15)
----------- -----------
Total............................................ $18,833,433 $18,794,939
=========== ===========
See Notes to Consolidated Financial Statements.
A-31
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) is a holding company which owns
all of the outstanding common stock of Texas Energy Industries Inc. (TEI) and
ENSERCH Corporation (ENSERCH). TEI is a holding company; the assets of its
primary subsidiary, Texas Utilities Electric Company (TU Electric), and the
Company's other electric utility businesses represent in excess of 85% of the
total assets and in excess of 75% of the total revenues of the Company. TU
Electric is engaged in the generation, purchase, transmission, distribution and
sale of electric energy wholly within Texas. Two other subsidiaries of TEI are
engaged directly or indirectly in public utility operations: Southwestern
Electric Service Company (SESCO) and Texas Utilities Australia Pty. Ltd. (TU
Australia), which in December 1995 acquired the common stock of Eastern Energy
Limited (Eastern Energy), one of five electricity distribution companies
operating in Victoria, Australia. Neither SESCO nor Eastern Energy generate
electric energy. TEI has other wholly-owned service subsidiaries, which support
the operations of the Company and its operating subsidiaries. For 1997, none of
the Company's other businesses are significant individually or in the aggregate
and, accordingly, do not require separate segment disclosure under existing
accounting standards. The Company is currently determining its reportable
segments under Statement of Financial Accounting Standards (SFAS) No. 131,
which becomes effective in 1998.
On August 5, 1997, the merger transactions (Merger) between the former Texas
Utilities Company, now known as TEI and ENSERCH were completed. At the effective
time of the Merger: (i) the former Texas Utilities Company changed its name to
TEI, (ii) TEI and ENSERCH merged with wholly-owned subsidiaries of TUC Holding
Company, which, as a result, owned all the common stock of TEI and of ENSERCH,
(iii) TUC Holding Company changed its name to Texas Utilities Company (now the
Company), (iv) each share of TEI's common stock was automatically converted into
one share of common stock of TUC, and (v) each share of common stock of ENSERCH
was automatically converted into 0.225 share of common stock of TUC, with cash
issued in lieu of fractional shares. The share conversions were tax-free
transactions.
Businesses and subsidiaries acquired in the Merger were Lone Star Gas Company
(Lone Star Gas), a gas distribution company in Texas, serving over 1.35 million
customers and providing service through over 23,800 miles of distribution mains;
Lone Star Pipeline Company (Lone Star Pipeline), which has approximately 7,600
miles of gathering and transmission pipeline in Texas; and subsidiaries engaged
in natural gas processing, natural gas marketing, independent power production
and international gas distribution systems development.
In the Merger, approximately 15.9 million shares of TUC common stock were
issued to former holders of ENSERCH common stock. The value assigned to the TUC
shares issued and costs incurred in connection with the acquisition of ENSERCH
aggregated $579 million. At the date of the Merger, ENSERCH had debt and
preferred stock outstanding of approximately $1.3 billion. 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 $3,214,000 was accounted for as a part of the
cost of the acquisition. At December 31, 1997, 402,966 of these options remained
outstanding and exercisable.
On November 21, 1997, the Company acquired Lufkin-Conroe Communications Co.
(LCC). Approximately 8.7 million shares of TUC common stock were issued to LCC
stockholders in a stock-for-stock exchange. The value assigned to the TUC shares
issued and costs incurred in connection with the acquisition of LCC aggregated
$319 million. At the date of the acquisition, LCC had debt outstanding of
approximately $31 million. LCC is the parent company of Lufkin-Conroe Telephone
Exchange, Inc. (LCTX) and Lufkin-Conroe Telecommunications Corporation (LCT) and
its subsidiaries. LCTX is an independent local exchange carrier that serves
approximately 100,000 access lines in the Alto, Conroe and Lufkin areas of
southeast Texas. It also provides access services to a number of interexchange
carriers who provide long distance services.
A-32
LCT and its subsidiaries own fiber optic cable systems which they lease to
interexchange carriers, provide Internet access, radio communications tower
rentals, cellular mobile telephones and radio paging services and private branch
exchange service to local customers. LCT, through a subsidiary, also provides
interexchange long distance service, with primary focus on business customers.
The acquisitions of ENSERCH, LCC and Eastern Energy were accounted for as
purchase business combinations. The assets and liabilities of the acquired
companies at the acquisition dates were adjusted to their estimated fair values.
The excess of the purchase price paid by the Company over the estimated fair
value of 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 and liabilities of ENSERCH and LCC as of the date of acquisition is
continuing, and the final result awaits primarily the resolution of income tax
and other contingencies and finalization of some preliminary estimates. The
results of operations of ENSERCH, LCC and Eastern Energy, are reflected in the
consolidated financial statements of the Company from the respective dates of
their acquisition.
The Company continues to seek 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.
In January 1998, the Company announced that it had approached the Energy Group
plc (TEG) in connection with its possible interest in acquiring TEG. TEG is a
diversified international energy group. Discussions between the Company and TEG
are continuing and may or may not lead to an offer being made by the Company.
Likewise, the timing, amount and funding of any specific new business investment
opportunities are presently undetermined.
Following is a summary of unaudited pro forma results of the Company's
operations assuming the ENSERCH and LCC acquisitions had occurred at the
beginning of the periods presented:
Year Ended December 31,
-----------------------
1997 1996
---- ----
Thousands of dollars
Revenues............................................. $9,315,952 $8,526,600
Operating income..................................... 1,971,790 2,109,610
Net income........................................... 665,593 751,333
Earnings per share of common stock:
Basic............................................... $2.68 $3.01
Diluted............................................. $2.67 $2.99
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 (System Companies).
Prior to August 5, 1997, the date of the Merger, the Company did not have any
assets or operations. Pursuant to the Merger, the Company became the parent of
each of TEI and ENSERCH. For financial reporting purposes, the Company is
treated as the successor to TEI. Unless otherwise specified, all references to
the Company for periods prior to August 5, 1997, are deemed to be references to
TEI since the merger of the Company and TEI is the combination of entities under
common control. The Company's financial statements have been restated in a
manner similar to pooling of interests accounting. Since the acquisitions of
ENSERCH, LCC and Eastern Energy were purchase business combinations, no
financial and other information for those companies are presented for periods
prior to their dates of acquisition. 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.
Use of Estimates -- The preparation of the Company's and TU Electric's
consolidated financial statements, in conformity with generally accepted
accounting principles, 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
A-33
and expense during the periods covered by the consolidated financial statements.
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 were made to previous estimates during the
current year.
System of Accounts -- The accounting records of TU Electric and SESCO 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 and Lone Star Pipeline, divisions of ENSERCH, are subject
to the accounting requirements prescribed by the National Association of
Regulatory Utility Commissioners (NARUC).
Property, Plant and Equipment -- Electric and gas utility plant is stated at
original cost less certain regulatory disallowances. The cost of property
additions to 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 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 utility
plant. The accrual of AFUDC is in accordance with generally accepted accounting
principles for the industry, but does not represent current cash income.
TU Electric capitalizes AFUDC, compounded semi-annually, on expenditures for
ongoing construction work in progress (CWIP) and nuclear fuel in process not
otherwise allowed in rate base by regulatory authorities. For 1997, 1996 and
1995, TU Electric used rates of 7.9%, 7.4%, and 7.7%, respectively. Other
regulated subsidiaries also capitalize AFUDC.
Depreciation of Property, Plant and Equipment -- Depreciation of the
Company's 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 TU Electric's Comanche Peak
decommissioning costs which is being accrued over the lives of the units and
deposited to external trust funds. (See Note 15.) Depreciation of all other
plant and equipment generally is determined by the straight-line method over the
useful life of the asset. Consolidated depreciation as a percent of average
depreciable property for the Company and System Companies approximated 2.6% for
1997, 2.7% for 1996 and 2.6% for 1995.
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 Comanche Peak nuclear generating station (Comanche Peak)
refueling outage.
Foreign Currency Translation -- The assets and liabilities of foreign
operations denominated in foreign 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
included in the cumulative currency translation adjustment, a separate component
of common stock equity.
Derivative Instruments -- 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.
The Company also enters into derivative contracts in connection with the
wholesale purchases of electric energy by Eastern Energy and defers the impact
of changes in the market value of the contracts, which serve as hedges, until
the related transaction is completed. (See Note 9.)
A-34
Energy Marketing Activities -- The Company, through its natural gas marketing
subsidiary, Enserch Energy Services, Inc. (EES), is a marketer of natural gas
and natural gas services. As part of these business activities, EES enters into
a variety of transactions, including forward contracts principally involving
physical delivery of natural gas and derivative financial instruments, including
options, swaps, futures and other contractual arrangements. The derivative
transactions are concentrated with established energy companies and major
financial institutions. EES uses the mark-to-market method of valuing and
recognizing earnings from firm contractual commitments to purchase and sell
natural gas in the future and from its portfolio of derivative financial
instruments, including options, swaps, futures and other contractual
commitments. (See Note 9.)
Revenues --Electric revenues include billings under approved rates (including
a fixed fuel factor) applied to meter readings each month on a cycle basis and
an accrual of base rate revenue for energy provided after cycle billing but not
billed through the end of each month. Revenues also include an amount for
under- or over-recovery of fuel revenue representing the difference between
actual fuel cost and billings under the approved fixed fuel factor and a
provision that generally allows recovery through a Power Cost Recovery Factor,
on a monthly basis, of the capacity portion of purchased power cost and wheeling
cost from qualifying facilities not included in base rates. The fuel portion of
purchased power cost is included in the fixed fuel factor. A utility's fuel
factor can 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, is in excess of 4% of the annual estimated fuel costs most
recently approved by the PUC, it will be deemed to be material. A procedure
exists for an expedited change in fuel factors in the event of an emergency.
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. (See Note 13.)
The city gate rate for the cost of gas Lone Star Gas ultimately delivers to
residential and commercial customers is established by the Railroad Commission
of Texas (RRC) and provides for full recovery of the actual cost of gas
delivered, including out-of-period costs such as gas-purchase contract
settlement costs. The rates Lone Star Gas charges its residential and
commercial customers are established by the municipal governments of the cities
and towns served, with the RRC having appellate jurisdiction. Lone Star Gas
records revenues on the basis of cycle meter readings throughout the month and
accrues revenues for gas delivered from the meter reading dates to the end of
the month. The rate Lone Star Pipeline charges to Lone Star Gas for
transportation and storage of gas ultimately consumed by residential and
commercial customers is established by the RRC.
Income Taxes --The Company and its domestic (U.S.) 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 currently provided for temporary
differences between the book and tax basis of assets and liabilities (including
the provision for regulatory disallowances). Certain provisions of SFAS 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. Accordingly,
at December 31, 1997, the consolidated balance sheet includes a net regulatory
tax asset of $1,249,338,000.
Effective January 1, 1997, TU Electric's state franchise tax status changed
from a tax based on net taxable capital to a tax based on net taxable earned
surplus. Certain other subsidiaries of the Company are also taxed on the earned
surplus method. Net taxable earned surplus is based on the federal income tax
return. The portion of the franchise tax calculated under the earned surplus
method is an income tax.
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 to the United States.
Earnings Per Share --Under the provisions of SFAS 128, which became effective
in December 1997, basic earnings per share applicable to common stock are based
on the weighted average number of common shares outstanding during the
A-35
year. Diluted earnings per share since the Merger include the effect of
potential common shares resulting from the assumed conversion of the outstanding
6 3/8% Convertible Subordinated Debentures due 2002 of ENSERCH and the exercise
of all outstanding stock options. For the period from the effective date of the
Merger to December 31, 1997, 999,492 shares were added to the average shares
outstanding for 1997 and $1,545,964 of after-tax interest expense was added to
earnings applicable to common stock for the purpose of calculating diluted
earnings per share. Previously reported earnings per share amounts for prior
years were not affected by the new standard.
Consolidated Cash Flows -- For purposes of reporting cash flows, 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
noncash investing and financing activities:
Year Ended December 31,
------------------------------------
1997 1996 1995
---- ---- ----
Thousands of Dollars
The Company
- -----------
CASH PAYMENTS
Interest (net of amounts capitalized)................... $ 630,844 $757,092 $ 677,415
Income taxes............................................ 174,908 246,556 208,326
NON-CASH INVESTING AND FINANCING ACTIVITIES
Acquisition of ENSERCH and LCC (1997) and Eastern
Energy (1995):
Book value of assets acquired......................... $ 2,033,311 $ -- $ 1,329,158
Goodwill.............................................. 1,005,277 -- 302,497
Common stock issued, net of capitalized expenses...... (892,068) 9,821 --
Liabilities assumed................................... (2,124,878) -- (1,006,847)
----------- -------- -----------
Cash used.......................................... 21,642 9,821 624,808
Cash acquired......................................... (26,419) -- (7,943)
----------- -------- -----------
Net cash used (provided)........................... $ (4,777) $ 9,821 $ 616,865
=========== ======== ===========
TU Electric
- -----------
CASH PAYMENTS
Interest (net of amounts capitalized)................... $ 467,760 $558,039 $ 602,524
Income taxes............................................ 231,809 303,204 213,690
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. In accordance with this statement, the Company's regulated
subsidiaries may 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,
--------------------------------------------------
Item 1997 1996 1997 1996
---- ---- ---- ---- ----
Thousands of Dollars
Securities reacquisition costs............. $ 397,488 $ 396,335 $ 396,702 $ 394,733
Canceled lignite unit costs................ 9,208 12,322 9,208 12,322
Rate case costs............................ 56,637 59,444 56,637 59,444
Litigation and settlement costs............ 72,685 72,685 72,685 72,685
Voluntary retirement/severance program..... 100,337 128,337 107,776 108,884
Recoverable deferred income taxes -- net... 1,249,338 1,167,922 1,254,456 1,173,413
Other regulatory assets (liabilities)...... 40,008 (10,942) (28,263) (13,490)
Reserve for regulatory disallowances....... (72,685) (72,685) (72,685) (72,685)
---------- ---------- ---------- ----------
Unamortized regulatory assets............ 1,853,016 1,753,418 1,796,516 1,735,306
Unamortized investment tax credits........ (570,283) (589,713) (556,743) (577,965)
---------- ---------- ---------- ----------
Unamortized regulatory assets -- net....... $1,282,733 $1,163,705 $1,239,773 $1,157,341
========== ========== ========== ==========
A-36
Future significant changes in regulation or competition could affect the
regulated subsidiaries' ability to meet the criteria for continued application
of SFAS 71 and may affect their ability to recover these regulatory assets from,
or refund these regulatory liabilities to, customers. If the affected System
Companies were to discontinue the application of SFAS 71, they would be required
to assess the recoverability of certain assets, including plant and regulatory
assets, and, if impaired, to write down the assets to reflect their fair market
value. 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 operation or cash flows. However, the
Company and TU Electric have no current knowledge of planned or impending
actions by regulators, including the legislature of the State of Texas, that
would affect recoverability of its plant and net regulatory assets.
TU Electric
- -----------
Affiliates -- The Company provides common stock capital and partial
requirements for short-term financing to TU Electric and System Companies. The
Company has other subsidiaries which perform specialized services for the System
Companies, including TU Electric; Texas Utilities Services Inc. (TU Services)
which provides financial, accounting, information technology, environmental
services, customer services, procurement, personnel, shareholder services 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; and ENSERCH. TU Electric provided services such as energy
sales, wheeling and scheduling to SESCO.
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,
$382,142,000 at December 31, 1997, 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 6.50% to 9.42%.
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,
----------------------------
1997 1996 1995
---- ---- ----
Thousands of Dollars
Billings from:
TU Services.......................... $270,547 $263,869 $182,334
Fuel Company......................... 995,635 922,200 763,346
Mining Company....................... 354,896 368,937 327,856
Billings to:
SESCO................................ $ 35,195 $ 29,171 $ 20,657
Fuel Company......................... 900 1,619 5,669
3. SHORT-TERM FINANCING
The Company
- -----------
The Company had outstanding short-term borrowings of $614,442,000 consisting
of commercial paper of $570,000,000 and bank borrowings of $44,442,000 at
December 31, 1997. The weighted average interest rates on such borrowings was
6.18% at December 31, 1997. During the years 1997, 1996 and 1995, the
Company's average amounts outstanding for short-term borrowings, including
amounts classified as long-term, were $1,222,176,000, $593,660,000 and
$149,806,000, respectively. Weighted average interest rates for short-term
borrowings during such periods were 5.86%, 5.94%,and 6.33%, respectively.
At December 31, 1997, the Company, TU Electric and ENSERCH had joint lines of
credit under credit facility agreements (Credit Agreements) with a group of
commercial banks. The Credit Agreements have two facilities. Facility A
provides for short-term borrowings aggregating up to $570,000,000 outstanding at
any one time at variable interest rates and
A-37
terminates April 23, 1998. Facility B provides for short-term borrowings
aggregating up to $1,330,000,000 outstanding at any one time at variable
interest rates and terminates April 24, 2002. The combined borrowings of the
Company, TU Electric and ENSERCH under both facilities are limited to an
aggregate of $1,900,000,000 outstanding at any one time. ENSERCH's borrowings
under both facilities are limited to an aggregate of up to $650,000,000
outstanding at any one time. Borrowings under these facilities will be used for
working capital and other corporate purposes, including commercial paper backup.
The total of short-term borrowings authorized by the Board of Directors of the
Company at December 31, 1997, from banks or other lenders, was $2,150,000,000.
In addition, certain non-U.S. subsidiaries have revolving credit agreements
aggregating approximately $95,000,000, of which $61,000,000 was outstanding at
December 31, 1997. These revolving credit agreements expire at various dates
through 2000.
The Company intends to refinance up to $990,440,000 of its current short-term
borrowings beyond one year of the balance sheet date of December 31, 1997. As a
result, such amount has been reclassified from notes payable - commercial paper
to long-term debt on the Company's 1997 Balance Sheet (see Note 8). If
necessary, the Company would draw upon Facility B if such amount were not
refinanced in the normal course of business.
TU Electric
- -----------
TU Electric had no borrowings from banks in 1997 or 1996. Average amounts
outstanding to banks for borrowings were $11,667,000 during 1995 and TU
Electric's average commercial paper outstanding was $36,761,000, $254,027,000,
and $340,579,000 for 1997, 1996 and 1995, respectively. During such periods,
weighted average interest rates to banks for borrowings were 6.51%, and to
holders of commercial paper were 5.61%, 5.53%, and 6.10%, respectively. Average
borrowings outstanding from other affiliates were $157,608,000, $9,586,000 and
$4,079,000 during 1997, 1996, and 1995, respectively, and the respective
weighted average interest rates for such borrowings were 5.88%, 5.91% and 6.38%
4. COMMON STOCK
The Company
- -----------
The Company has an Automatic Dividend Reinvestment and Common Stock Purchase
Plan (DRIP) and an Employees' Thrift Plan of the Texas Utilities Company System
(Thrift Plan). During each of the last three years, requirements under the DRIP
and Thrift Plan have been met through open market purchases of the Company's
common stock.
At December 31, 1997, the Thrift Plan had an obligation of $250,000,000
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, 1997, the Thrift Plan trustee held 5,375,158 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 System
Companies' obligations under terms of the Thrift Plan. The Thrift Plan uses
dividends on the LESOP Shares held and contributions from the System Companies,
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
held by the trustee. Allocations to participants' accounts in each of the years
1997 and 1995 increased common stock equity by $8,115,000; 1996 increased by
$8,137,000.
The Long-Term Incentive Compensation Plan was approved and adopted by the
directors of the Company and approved by the shareholders in 1997. The purpose
of the plan is to assist the Company in attracting, retaining and motivating
executive officers and other key employees essential to the success of the
Company through performance-related incentives linked to long-range performance
goals. The 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. All Awards will be made in, or based on the value of,
the Company's common stock. The maximum number of shares of common stock for
which Awards may be granted under the plan is 2,500,000 subject to adjustment in
the event of a merger, consolidation, reorganization, recapitalization, stock
dividend, stock split, or other similar event. During 1997, the Board of
Directors
A-38
authorized the award of 61,000 shares of restricted common stock, which were
issued in 1997 subject to performance and vesting requirements over a three to
five year period. No stock options were granted.
At December 31, 1997, 14,154,372 shares of the authorized but unissued
common stock of the Company were reserved for issuance and sale pursuant to the
above plans, for conversion of the 6% Convertible Subordinated Debentures due
2002 (see Note 8) and for other purposes.
In November 1997, the Company's Board of Directors increased the common stock
repurchase limit to $350 million of which $148,780,000 was used as of December
31, 1997 to purchase and retire 4,015,000 shares of the Company's issued and
outstanding common stock during 1997. 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 50,000,000 authorized shares of serial preference stock
having a par value of $25 a share, none of which has been issued.
TU Electric
- -----------
During the year ended December 31, 1997, TU Electric purchased and retired a
total of 13,869,000 shares of its issued and outstanding common stock at a total
cost of approximately $416,070,000. TU Electric had no common stock
transactions in 1995 or 1996.
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.
5. DIVIDEND RESTRICTIONS OF TU ELECTRIC AND OTHER SUBSIDIARIES OF THE COMPANY
The articles of incorporation and/or the mortgages, as supplemented, and
certain other debt instruments of TU Electric and SESCO contain provisions
which, under certain conditions, restrict distributions on or acquisitions of
common stock. At December 31, 1997, $29,236,000 of retained earnings of TU
Electric, and $13,970,000 of retained earnings of SESCO, were thus restricted
as a result of such provisions.
In 1995, TU Electric transferred approximately $433,820,000 from its common
stock account to retained earnings. Such amount represented the Company's
equity in undistributed earnings, since acquisition, included in previous
transfers by TU Electric.
A-39
6. PREFERRED STOCK OF TU ELECTRIC AND OTHER SUBSIDIARIES OF THE COMPANY
Shares Outstanding Amount Redemption Price Per Share
Dividend Rate December 31, December 31, (Before Adding Accumulated Dividends)
- ------------------------------------ ------------------ -------------------- ------------------------------------
1997 1996 1997 1996 December 31, 1997 Eventual Minimum
---- ---- ---- ---- ----------------- ----------------
Thousands of Dollars
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......................... 22,406 74,367 $ 2,242 $ 7,440 $ 110.00 $ 110.00
4.00 series (Dallas Power).......... 20,755 70,000 2,090 7,049 103.56 103.56
4.56 series (Texas Power)........... 52,879 133,628 5,291 13,371 112.00 112.00
4.00 series (Texas Electric)........ 69,221 110,000 6,922 11,000 102.00 102.00
4.56 series (Texas Electric)........ 22,237 64,947 2,246 6,560 112.00 112.00
4.24 series......................... 18,194 100,000 1,834 10,081 103.50 103.50
4.64 series......................... 25,195 100,000 2,524 10,016 103.25 103.25
4.84 series......................... 15,964 70,000 1,597 7,000 101.79 101.79
4.00 series (Texas Power)........... 27,391 70,000 2,739 7,000 102.00 102.00
4.76 series......................... 23,181 100,000 2,318 10,000 102.00 102.00
5.08 series......................... 27,716 80,000 2,773 8,004 103.60 103.60
4.80 series......................... 20,420 100,000 2,044 10,009 102.79 102.79
4.44 series......................... 33,672 150,000 3,381 15,061 102.61 102.61
7.20 series......................... -- 200,000 -- 20,044 -- --
6.84 series......................... -- 200,000 -- 20,023 -- --
7.24 series......................... -- 247,862 -- 24,905 -- --
8.20 series (a) (c)................. 146,501 338,872 14,138 32,704 (b) 100.00
7.98 series......................... 261,075 474,000 25,774 46,794 (b) 100.00
7.50 series (a)..................... 308,308 392,234 29,918 38,062 (b) 100.00
7.22 series (a)..................... 220,448 301,132 21,363 29,182 (b) 100.00
Adjustable rate series A................ -- 884,700 -- 86,878 -- --
Adjustable rate series B................ -- 440,137 -- 43,244 -- --
--------- --------- -------- --------
Total............................ 1,315,563 4,701,879 129,194 464,427
--------- --------- -------- --------
ENSERCH (entitled upon liquidation to stated value per share; authorized 2,000,000 shares)
- ------------------------------------------------------------------------------------------
Adjustable Rate Preferred Stock:
Series E (c) (d).................... 100,000 -- 100,000 -- 1,000.00 1,000.00
Series F (d)........................ 75,000 -- 75,000 -- (b) 1,000.00
--------- --------- -------- --------
Total............................. 175,000 -- 175,000 --
--------- --------- -------- --------
Total........................ 1,490,563 4,701,879 $304,194 $464,427
========= ========= ======== ========
TU Electric - Subject to Mandatory Redemption (e)
- -------------------------------------------------
$ 9.64 series......................... -- 400,000 $ -- $ 39,981 -- --
6.98 series......................... 107,500 1,000,000 10,672 99,199 (b) 100.00
6.375 series........................ 100,000 1,000,000 9,928 99,211 (b) 100.00
--------- --------- -------- --------
Total............................ 207,500 2,400,000 $ 20,600 $238,391
========= ========= ======== ========
- -----------------------------------------
(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, 1997.
(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-tenth of a share of underlying preferred
stock for Series E ($100 per share) and one-fortieth of a share for Series F
($25 per share). Dividend rates are determined quarterly, in advance, based
on certain U.S. Treasury rates. At December 31, 1997, the Series E bears a
dividend rate of 7.0% and the Series F bears a dividend rate of 5.54%.
(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
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-40
During the year ended December 31, 1997, TU Electric redeemed or purchased
5,578,816 shares of its preferred stock (including 3,989,640 shares purchased by
the Company in March 1997 pursuant to a tender offer and subsequently sold to TU
Electric) with annual dividend rates ranging from 4.00% to 9.64% at a total cost
of approximately $553,093,000. In January 1998, TU Electric redeemed all of the
outstanding shares of the $8.20 series preferred stock, and ENSERCH redeemed the
Series E Adjustable Rate Preferred Stock, in each case at 100% of the
liquidation price plus accumulated and unpaid dividends.
7. TU ELECTRIC OBLIGATED, MANDATORILY REDEEMABLE, PREFERRED SECURITIES OF
SUBSIDIARY TRUSTS HOLDING SOLELY DEBENTURES OF TU ELECTRIC
Five statutory business trusts, each a TU Electric Trust, have been
established as financing subsidiaries of TU Electric for the purposes, in each
case, of issuing common and preferred trust securities and holding Junior
Subordinated Debentures issued by TU Electric (Debentures). TU Electric
Capital I, II and III preferred trust securities have a liquidation preference
of $25 per unit and TU Electric Capital IV and V preferred trust securities have
a liquidation preference of $1,000 per unit (Capital Securities). The
Debentures held by each TU Electric Trust are its only assets. The interest on
Trust assets matches the dividend rates on the trust securities. Each TU
Electric Trust will use interest payments received on the Debentures it holds to
make cash distributions on the trust securities it has issued.
The preferred 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 TU Electric, as 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 preferred securities is being increased periodically
to equal the redemption amounts at the mandatory redemption dates with a
corresponding increase in preferred securities distributions.
At December 31, 1997 and 1996, the following preferred securities and related
trust assets of the TU Electric Trusts were outstanding:
Preferred Securities Trust Assets
---------------------------------------------------------------------
Units Outstanding Amount Amount
December 31, December 31, December 31,
--------------------- ------------------ -------------------
1997 1996 1997 1996 1997 1996
---- ---- ---- ---- ---- ----
Thousands of Dollars
TU Electric Capital I (8.25% Series)..... 5,871,044 5,871,044 $140,851 $140,671 $154,869 $154,869
TU Electric Capital II (9.00% Series).... 1,991,253 1,991,253 47,374 47,301 51,419 51,419
TU Electric Capital III (8.00% Series)... 8,000,000 8,000,000 193,510 193,339 206,186 206,186
TU Electric Capital IV (floating rate
Capital Securities)(a)................. 100,000 -- 97,570 -- 103,093 --
TU Electric Capital V (8.175% Capital
Securities)............................. 400,000 -- 395,841 -- 412,372 --
---------- ---------- -------- -------- -------- --------
Total 16,362,297 15,862,297 $875,146 $381,311 $927,939 $412,474
========== ========== ======== ======== ======== ========
(a) Floating rate is determined quarterly based on LIBOR. The related
interest rate swap fixes the rate at 7.183%.
At December 31, 1997, TU Electric, with respect to its Capital IV securities,
had an interest rate swap agreement with a notional principal amount of
$100,000,000 expiring 2002 that fixed the rate on the securities at 7.183% per
annum.
The combination of the obligations of TU Electric pursuant to agreements to
pay the expenses of each of the TU Electric Trusts and TU Electric's guarantees
of distributions with respect to trust securities, to the extent the issuing
trust has funds available therefor, constitutes a full and unconditional
guarantee by TU Electric of the obligations of each trust under the trust
securities it has issued. TU Electric is the owner of all the common trust
securities of each trust, which, in each case, constitutes 3% or more of the
liquidation amount of all the trust securities issued by such trust.
In January 1998, TU Electric redeemed all of the outstanding shares of the TU
Electric Capital II preferred trust securities at 100% of the liquidation amount
of $25 per preferred security, plus accumulated and unpaid dividends.
A-41
8. LONG-TERM DEBT, less amounts due currently
The Company TU Electric
December 31, December 31,
Interest Series ---------------------- ------------------
Rate Due 1997 1996 1997 1996
---- --- ---- ---- ---- ----
Thousands of Dollars
First mortgage bonds:
5-1/2% series due 1998............................... $ -- $125,000 $ -- $125,000
5-3/4% series due 1998............................... -- 150,000 -- 150,000
5-7/8% series due 1998............................... -- 175,000 -- 175,000
6-1/2% series due 1998............................... -- 1,065 -- --
7-3/8% series due 1999............................... 100,000 100,000 100,000 100,000
Floating rate series due 1999........................ -- 300,000 -- 300,000
9-1/2% series due 1999............................... 200,000 200,000 200,000 200,000
7-3/8% series due 2001............................... 150,000 150,000 150,000 150,000
7.95 % series due 2002............................... 888 900 -- --
8 % series due 2002............................... 147,000 147,000 147,000 147,000
8-1/8% series due 2002............................... 150,000 150,000 150,000 150,000
6-3/4% series due 2003............................... 200,000 200,000 200,000 200,000
6-3/4% series due 2003............................... 100,000 100,000 100,000 100,000
6-1/4% series due 2004............................... 125,000 125,000 125,000 125,000
8-1/4% series due 2004............................... 100,000 100,000 100,000 100,000
6-3/4% series due 2005............................... 100,000 100,000 100,000 100,000
10.44% series due 2008............................... 3,000 3,000 3,000 3,000
9-3/4% series due 2021............................... 135,855 280,855 135,855 280,855
8-7/8% series due 2022............................... 125,000 175,000 125,000 175,000
9 % series due 2022............................... -- 100,000 -- 100,000
7-7/8% series due 2023............................... 300,000 300,000 300,000 300,000
8-3/4% series due 2023............................... 135,550 195,550 135,550 195,550
7-7/8% series due 2024............................... 225,000 225,000 225,000 225,000
8-1/2% series due 2024............................... 113,000 163,000 113,000 163,000
7-3/8% series due 2025............................... 208,000 208,000 208,000 208,000
7-5/8% series due 2025............................... 250,000 250,000 250,000 250,000
Pollution control series:
Brazos River Authority
7-7/8% series due 2017............................... -- 81,305 -- 81,305
9-7/8% series due 2017............................... -- 28,765 -- 28,765
9-1/4% series due 2018............................... 54,005 54,005 54,005 54,005
8-1/4% series due 2019............................... 100,000 100,000 100,000 100,000
8-1/8% series due 2020............................... 50,000 50,000 50,000 50,000
7-7/8% series due 2021............................... 100,000 100,000 100,000 100,000
Taxable series due 2021 (5.86%) (a).................. 40,895 65,940 40,895 65,940
5-1/2% series due 2022............................... 50,000 50,000 50,000 50,000
6-5/8% series due 2022............................... 33,000 33,000 33,000 33,000
6.70 % series due 2022............................... 16,935 16,935 16,935 16,935
6-3/4% series due 2022............................... 50,000 50,000 50,000 50,000
Series 1997D due 2022 (3.75%) (c).................... 28,765 -- 28,765 --
Taxable series due 2023 (5.85%) (a).................. 100,000 100,000 100,000 100,000
6.05 % series due 2025............................... 90,000 90,000 90,000 90,000
Series 1996 A due 2026 (5.10%)(c).................... 25,060 25,060 25,060 25,060
6-1/2% series due 2027............................... 46,660 46,660 46,660 46,660
6.10 % series due 2028............................... 50,000 50,000 50,000 50,000
Series 1994A due 2029 (3.75% to 3.85%) (b)........... 39,170 39,170 39,170 39,170
Series 1994B due 2029 (3.75% to 3.80%) (b)........... 39,170 39,170 39,170 39,170
Series 1995A due 2030 (5.10%) (c).................... 50,670 50,670 50,670 50,670
Series 1995B due 2030 (4.60%) (c).................... 118,355 118,355 118,355 118,355
Series 1995C due 2030 (5.10%) (c).................... 118,355 118,355 118,355 118,355
Series 1996B due 2030 (4.60%) (c).................... 61,215 61,215 61,215 61,215
Series 1996C due 2030 (5.10%) (c).................... 50,000 50,000 50,000 50,000
Series 1997A due 2032 (5.10%) (c).................... 50,000 -- 50,000 --
Series 1997B due 2032 (4.95%) (c).................... 31,305 -- 31,305 --
Series 1997C due 2032 (5.10%) (c).................... 25,045 -- 25,045 --
Sabine River Authority of Texas
9 % series due 2007............................... -- 51,525 -- 51,525
8-1/8% series due 2020............................... 40,000 40,000 40,000 40,000
8-1/4% series due 2020............................... 11,000 11,000 11,000 11,000
A-42
The Company TU Electric
December 31, December 31,
Interest Series ----------------------- -----------------------
Rate Due 1997 1996 1997 1996
---- --- ---- ---- ---- ----
Thousands of Dollars
Sabine River Authority of Texas (continued)
5.55 % series due 2022................................... $ 75,000 $ 75,000 $ 75,000 $ 75,000
6.55 % series due 2022................................... 40,000 40,000 40,000 40,000
5.85 % series due 2022................................... 33,465 33,465 33,465 33,465
Series 1997A due 2022 (3.70%)(c).......................... 51,525 -- 51,525 --
Series 1996A due 2026 (5.10%) (c)........................ 57,950 57,950 57,950 57,950
Series 1996B due 2026 (5.10%) (c)........................ 25,000 25,000 25,000 25,000
Series 1995A due 2030 (5.20%) (c)........................ 16,000 16,000 16,000 16,000
Series 1995B due 2030 (4.50%) (c)........................ 12,050 12,050 12,050 12,050
Series 1995C due 2030 (4.60%) (c)........................ 18,475 18,475 18,475 18,475
Trinity River Authority of Texas
9 % series due 2007.................................... -- 12,000 -- 12,000
Series 1997A due 2022 (3.75%) (c)......................... 12,000 -- 12,000 --
Series 1996 A due 2026 (5.10%) (c)....................... 25,000 25,000 25,000 25,000
Series 1997B due 2032 (5.95%) (c)......................... 14,075 -- 14,075 --
Secured medium-term notes, series A......................... 30,000 30,000 30,000 30,000
Secured medium-term notes, series B......................... 114,200 114,200 114,200 114,200
Secured medium-term notes, series D......................... 201,150 201,150 201,150 201,150
---------- ---------- ---------- ----------
Total first mortgage bonds.............................. 5,063,788 6,205,790 5,062,900 6,203,825
General obligation bonds..................................... 9,646 10,000 -- --
Debt assumed for purchase of utility plant (d)............... 153,537 156,182 153,537 156,182
TU Electric 7.17% Senior Debentures due 2007................. 300,000 -- 300,000 --
Senior notes:
TEI (due through 2010 at 10.2% to 10.58%)................... 235,800 239,350 -- --
TUC (due through 2004 at 6.20% to 6.375%)................... 300,000 -- -- --
ENSERCH (due through 2005 at 6.25% to 8.875%)............... 575,000 -- -- --
TUMCO (due through 2005 at 6.5% to 9.42%)................... 367,856 382,142 -- --
LCC (due through 2003 at 7.15% to 10.5%).................... 648 -- -- --
Eastern Energy (due through 2016 at 6.75% to 7.25%) (e)..... 280,994 343,389 -- --
6 3/8% Convertible subordinated debentures due 2002.......... 90,750 -- -- --
Term credit facilities (f)................................... 1,416,728 1,381,290 -- --
Unamortized premium and discount and fair value adjustments.. (35,368) (50,032) (40,990) (49,413)
---------- ---------- ---------- ----------
Total long-term debt, less amounts
due currently.................................... $8,759,379 $8,668,111 $5,475,447 $6,310,594
========== ========== ========== ==========
- ------------------------------
(a) Interest rates in effect at December 31, 1997 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, 1997 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, 1997 are presented. These series
are in a daily 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) Eastern Energy has entered into cross-currency and interest rate swap
agreements expiring on concurrent dates with the underlying fixed rate debt
through 2016. Such agreements effectively convert these fixed rate U.S.
dollar denominated Senior Notes to a floating rate Australian Dollar
liability based on the Australian Bank Bill Swap rate plus a margin. At
December 31, 1997, such floating rates ranged from 5.29% to 8.45%.
(f) Includes the Company's $990,440,000 reclassified short-term debt (see Note
3). Also includes Eastern Energy's $297,837,000 Multi Option Credit Facility
due 2001 with a floating interest rate of 5.44% on December 31, 1997 and
Eastern Energy's $128,451,000 reclassified short-term debt (all of which is
included under interest rate swap agreements with notional principal amounts
of $627,539,000 expiring at various dates through 2002 with fixed interest
rates ranging from 5.29% to 8.45% per annum and forward contracts with
notional principal amounts of $45,521,000 expiring at various dates through
1998 with an average rate of 4.8%).
Long-term debt of the Company does not include Junior Subordinated Debentures
held by each TU Electric Trust. (See Note 7.)
The ENSERCH convertible subordinated debentures, which have an interest rate
of 6 3/8%, are due in 2002 and effective with the Merger, each $1,000 of the
$90,750,000 total principal amount outstanding became convertible into 25.947
shares of TUC common stock at the option of the debenture holder. The
debentures may be redeemed at 101.27% of the principal amount, plus accrued
interest, through March 31, 1998, and at declining premiums thereafter. The
Company currently intends to redeem these debentures in 1998.
A-43
Sinking fund and maturity requirements for the years 1998 through 2002 under
long-term debt instruments in effect at December 31, 1997, were as follows:
The Company TU Electric
---------------------------------- -------------------------------
Sinking Minimum Cash Sinking Minimum Cash
Year Fund Maturity Requirement Fund Maturity Requirement
---- ------- -------- ------------ ------- -------- ------------
Thousands of Dollars
1998.. $ 20,994 $ 751,077 $ 772,071 $2,645 $750,000 $752,645
1999.. 24,680 480,012 504,692 5,906 330,000 335,906
2000.. 261,040 1,597,891 1,858,931 3,199 156,150 159,349
2001.. 22,415 322,012 344,427 3,502 222,000 225,502
2002.. 8,546 586,602 595,148 3,838 370,000 373,838
TU Electric's and SESCO's first mortgage bonds are secured by mortgages and
deeds of trust with major financial institutions. Electric plant of TU
Electric and SESCO is generally subject to the liens of their respective
mortgages.
9. DERIVATIVE INSTRUMENTS
The Company and TU Electric
- ---------------------------
The Company enters into derivative instruments, including options, swaps,
futures and other contractual commitments to manage market risks related to
changes in interest rates and commodity price exposures. The Company's
participation in derivative transactions, except for the gas marketing
activities, 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, 1997, Eastern Energy had
interest rate swaps outstanding with an aggregate notional amount of
$977,500,000. These swap agreements establish a mix of fixed and variable
interest rates on the outstanding debt and have remaining terms up to 19 years.
(See Note 8.)
At December 31,1997, TU Electric had an interest rate swap agreement with
respect to preferred securities of TU Electric Capital IV, with a notional
principal amount of $100,000,000 expiring 2002 that fixed the rate at 7.183% per
annum. (See Note 7.)
At December 31, 1997, there were $50,900,000 of net unrealized deferred
hedging losses on interest rate swaps.
Electricity Price Risk Management -- Eastern Energy and the other
distribution companies in Victoria 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 a substantial majority of its
forecasted franchise load through the end of 2000. Eastern Energy also
maintains a strategy that is aimed at seeking hedging contracts with individual
generators to cover forecast 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. During 1997, the average spot
price for electric energy from the pool approximated $14 per megawatt-hour (MWh)
as compared with the average fixed price of Eastern Energy's electric energy
under its contracts of approximately $29 per MWh. At December 31, 1997, Eastern
Energy's contracts related to its forecasted contestable and franchise load
cover a notional volume of approximately 15.6 million MWh's for 1998 through
2000. 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.
Natural Gas Marketing Activities -- EES's marketing activities involve price
commitments into the future and, therefore, give rise to market risk, which
represents the potential loss that can be caused by a change in the market value
of a particular commitment. Net open portfolio positions often result from the
origination of new transactions or in response to changing market conditions.
The Company closely monitors its exposure to market risk. The Company utilizes
a number of methods to monitor market risk, including sensitivity analysis. The
exposure for fixed price natural gas purchase and sale commitments, and
derivative financial instruments, including options, swaps, futures and other
contractual commitments,
A-44
is based on a methodology that uses a five-day holding period and a 95%
confidence level. 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% change in market factors which may differ from
actual results. Using 15%, the most adverse change in fair value at December 31,
1997 as a result of this analysis was a reduction of $1.1 million.
EES enters into contracts to purchase and sell natural gas for physical
delivery in the future. At December 31, 1997, EES had net commitments to sell
approximately 50.6 billion cubic feet (Bcf) of natural gas through the year 2003
with offsetting net financial positions to purchase approximately 61.3 Bcf.
Concurrent with the Merger, EES conformed its accounting for its gas
marketing activities to mark-to-market accounting. Under mark-to-market
accounting, changes (whether positive or negative) in the value of contractual
commitments to purchase and sell natural gas in the future and from its
portfolio of derivative financial instruments, including options, swaps, futures
and other contractual commitments are recognized as an adjustment to operating
revenues in the period of change. The market prices used to value these
transactions reflect management's best estimate of market prices considering
various factors including closing exchange and over-the-counter quotations, time
value of money and volatility factors underlying the commitments. These market
prices are adjusted to reflect the potential impact of liquidating EES's
position in an orderly manner over a reasonable period of time under present
market conditions.
EES has a number of risks and costs associated with the future contractual
commitments included in its natural gas portfolio, including credit risks
associated with the financial condition of counterparties, product location
(basis) differentials 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 natural gas has occurred,
counterparties have fulfilled their financial commitments and related financial
instruments mature or are closed out.
The following table displays the mark-to-market values of EES's natural gas
marketing risk management assets and liabilities at December 31, 1997 and the
average value for the period from August 5, 1997 through December 31, 1997:
Assets Liabilities Net
------ ----------- ---
Thousands of Dollars
Fair Value:
Current.......................... $365,650 $357,044 $ 8,606
Noncurrent....................... 41,522 31,324 10,198
-------- -------- -------
Total.......................... $407,172 $388,368 18,804
======== ========
Less reserves.................... 9,251
-------
Net of reserves................ $ 9,553
=======
Average Value:
Total............................ $291,809 $278,332 $13,477
======== ========
Less reserves.................... 8,134
-------
Net of reserves................ $ 5,343
=======
EES incurred net trading losses of $286,000 from gas marketing activities for
the period from August 5, 1997 through December 31, 1997.
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 does not obtain collateral to support the agreements
but monitors the financial viability of counterparties and believes its credit
risk is minimal on these transactions. The Company believes the risk of
nonperformance by counterparties is minimal.
A-45
10. INCOME TAXES
The components of the Company's and TU Electric provision for income taxes
are as follows:
Year Ended December 31,
-------------------------------
1997 1996 1995
-------- -------- ---------
Thousands of Dollars
The Company
- -----------
Current:
Federal.................................... $181,632 $198,522 $ 222,358
State...................................... 39,900 -- --
-------- -------- ---------
Total.................................. 221,532 198,522 222,358
-------- -------- ---------
Deferred
Federal.................................... 175,573 196,957 (259,445)
State...................................... (17,102) -- --
Foreign.................................... 19,746 12,828 (174)
-------- -------- ---------
Total.................................. 178,217 209,785 (259,619)
-------- -------- ---------
Investment Tax Credits........................ (22,851) (33,075) (22,774)
-------- -------- ---------
Total................................ $376,898 $375,232 $ (60,035)
======== ======== =========
TU Electric
- -----------
Charged (credited) to operating expenses:
Current:
Federal.................................. $283,464 $291,807 $ 260,988
State.................................... 43,601 -- --
-------- -------- ---------
Total current........................ 327,065 291,807 260,988
-------- -------- ---------
Deferred:
Depreciation differences and capitalized
construction costs...................... 146,623 151,391 205,280
Over/under-recovered fuel revenue........ 10,339 25,506 (49,798)
Alternative minimum tax.................. 728 15,000 (30,937)
Other.................................... (43,852) (32,024) 17,983
-------- -------- ---------
Total deferred -- net................ 113,838 159,873 142,528
-------- -------- ---------
Investment tax credits..................... (21,222) (30,668) (21,201)
-------- -------- ---------
Total to operating expenses.......... 419,681 421,012 382,315
-------- -------- ---------
Charged (credited) to other income:
Current:
Federal.................................. (35,964) (30,164) (59,454)
State.................................... (5,105) -- --
-------- -------- ---------
Total current........................ (41,069) (30,164) (59,454)
-------- -------- ---------
Deferred:
Federal:
Impairment of assets..................... -- -- (149,617)
Regulatory disallowance.................. 34,208 13,623 --
Other.................................... 13,462 1,861 39,709
-------- -------- ---------
Total federal....................... 47,670 15,484 (109,908)
-------- -------- ---------
State.................................... (16,736) -- --
Investment tax credits..................... -- (833) --
-------- -------- ---------
Total to other income.............. (10,135) (15,513) (169,362)
-------- -------- ---------
Total........................... $409,546 $405,499 $ 212,953
======== ======== =========
A-46
Reconciliation of income taxes (benefit) computed at the federal statutory
rate to provision for income taxes (benefit).
The Company Year Ended December 31,
- ----------- ----------------------------------------
1997 1996 1995
---- ---- ----
Thousands of Dollars
Income (loss) before income taxes:
Domestic......................... $1,001,867 $1,108,386 $(197,373)
Foreign.......................... 35,485 20,452 (1,307)
---------- ---------- ---------
Total......................... 1,037,352 1,128,838 (198,680)
Preferred stock dividends of
subsidiaries.................... 27,983 53,358 84,914
---------- ---------- ---------
Income (loss) before preferred
stock dividends
of subsidiaries................. $1,065,335 $1,182,196 $(113,766)
========== ========== =========
Income taxes (benefit) at the
federal statutory
rate of 35%....................... $ 372,867 $ 413,769 $ (39,188)
Allowance for funds used during
construction.................... (1,821) (542) (2,330)
Depletion allowance.............. (22,691) (25,657) (23,564)
Amortization of investment tax
credits......................... (22,877) (23,203) (23,036)
Amortization of tax rate
differences..................... (6,856) (9,084) (9,648)
Amortization of prior
flow-through amounts............ 36,559 35,128 38,974
Foreign operations............... 7,326 5,670 283
Prior year adjustments........... (7,673) (25,250) (4,136)
State income taxes, net of
federal tax benefit............. 14,812 -- --
Amortization of goodwill......... 3,263 -- --
Other............................ 3,989 4,401 2,610
---------- ---------- ---------
Provision for income taxes
(benefit)......................... $ 376,898 $ 375,232 $ (60,035)
========== ========== =========
Effective tax rate (on income
before preferred stock
dividends of subsidiaries)........ 35.4% 31.7% 52.8%
The Company had net tax benefits from LESOP dividend deductions of $3.9
million, $4.0 million and $6.5 million in 1997, 1996 and 1995, respectively,
which were credited directly to retained earnings.
TU Electric Year Ended December 31,
- ----------- ------------------------------------
1997 1996 1995
---- ---- ----
Thousands of Dollars
Income before income taxes $1,181,420 $1,268,194 $665,584
========== ========== ========
Income taxes at the federal
statutory rate of 35%............. $413,497 $443,868 $232,954
Allowance for funds used during
construction.................... (1,821) (542) (2,330)
Depletion allowance.............. (22,636) (25,657) (23,564)
Amortization of investment tax
credits......................... (21,222) (21,629) (21,463)
Amortization of tax rate
differences..................... (6,559) (8,740) (9,288)
Amortization of prior
flow-through amounts............ 36,332 34,896 38,630
Prior year adjustments........... (6,914) (21,813) (5,669)
State income taxes, net of
federal tax benefit............. 14,144 -- --
Other............................ 4,725 5,116 3,683
---------- ---------- --------
Provision for income taxes.......... $409,546 $405,499 $212,953
========== ========== ========
Effective tax rate.................. 34.7% 32.0% 32.0%
A-47
Deferred income taxes provided by the liability method for significant
temporary difference based on tax laws in effect at the December 31, 1997 and
1996 balance sheet dates are as follows:
The Company December 31,
- ----------- --------------------------------------------------------------------
1997 1996
--------------------------------- ---------------------------------
Non Non
Total Current current Total Current current
----- ------- ------- ----- ------- -------
Thousand of Dollars
Deferred Tax Assets:
Unbilled revenues............................... $ 28,469 $ 28,469 $ -- $ 28,521 $ 28,521 $ --
Over-recovered fuel revenue..................... 4,530 4,530 -- 15,045 15,045 --
Unamortized investment tax credits.............. 300,871 -- 300,871 312,665 -- 312,665
Impairment of assets............................ 141,678 -- 141,678 143,210 -- 143,210
Regulatory disallowance......................... 183,729 -- 183,729 222,428 -- 222,428
Alternative minimum tax......................... 589,989 -- 589,989 587,052 -- 587,052
Tax rate differences............................ 78,477 -- 78,477 78,141 -- 78,141
Employee benefits............................... 163,632 -- 163,632 100,397 -- 100,397
Net operating loss carryforwards............... 155,871 -- 155,871 -- -- --
Deferred benefits of state income tax........... 156,237 5,129 151,108 -- -- --
Unrealized currency translation adjustments..... 27,685 -- 27,685 -- -- --
Other........................................... 35,130 35,130 -- 35,316 7,406 27,910
---------- -------- ---------- ---------- -------- ----------
Total deferred federal income tax asset........ 1,866,298 73,258 1,793,040 1,522,775 50,972 1,471,803
Deferred state income taxes..................... 52,996 3,170 49,826 -- -- --
Deferred foreign income taxes................... 77,222 5,573 71,649 69,541 2,994 66,547
---------- -------- ---------- ---------- -------- ----------
Total deferred tax assets..................... 1,996,516 82,001 1,914,515 1,592,316 53,966 1,538,350
---------- -------- ---------- ---------- -------- ----------
Deferred Tax Liabilities:
Depreciation differences and capitalized
construction costs............................. 4,257,455 -- 4,257,455 4,010,105 -- 4,010,105
Redemption of long-term debt.................... 123,354 -- 123,354 125,601 -- 125,601
Deferred charges for state income tax........... 24,433 -- 24,433 -- -- --
Other........................................... 122,304 121 122,183 148,720 -- 148,720
---------- -------- ---------- ---------- -------- ----------
Total deferred federal income tax liability.. 4,527,546 121 4,527,425 4,284,426 -- 4,284,426
Deferred state income taxes..................... 295,246 -- 295,246 -- -- --
Deferred foreign income taxes................... 94,590 13,492 81,098 69,495 13,945 55,550
---------- -------- ---------- ---------- -------- ----------
Total deferred tax liabilities................ 4,917,382 13,613 4,903,769 4,353,921 13,945 4,339,976
---------- -------- ---------- ---------- -------- ----------
Net Deferred Tax Liability (Asset)............ $2,920,866 $(68,388) $2,989,254 $2,761,605 $(40,021) $2,801,626
========== ======== ========== ========== ======== ==========
At December 31, 1997, the Company had approximately $590 million of
alternative minimum tax credit carryforwards available to offset future tax
payments. At December 31, 1997, ENSERCH had $445 million of net operating loss
(NOL) carryforwards which begin to expire in 2003. Such NOL's were generated by
ENSERCH and subsidiaries prior to the Merger and can be used only to offset
future taxable income generated by ENSERCH and subsidiaries pursuant to Section
382 of the Internal Revenue Code. The Company expects to fully utilize such
NOL's prior to their expiration date.
A-48
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 year 1993 and as yet no notice of proposed adjustments
has been issued. The IRS has indicated that it will commence an audit of
ENSERCH's returns for the years 1994 through 1997 in 1998. 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 in accordance with the provisions of SFAS 109.
TU Electric December 31,
- ----------- --------------------------------------------------------------------
1997 1996
--------------------------------- ---------------------------------
Non Non
Total Current current Total Current current
----- ------- ------- ----- ------- -------
Thousand of Dollars
Deferred Tax Assets:
Unbilled revenues.............................. $ 28,257 $ 28,257 $ -- $ 28,521 $ 28,521 $ --
Over-recovered fuel revenue.................... 4,530 4,530 -- 15,045 15,045 --
Unamortized investment tax credits............. 296,155 -- 296,155 307,153 -- 307,153
Impairment of assets........................... 71,548 -- 71,548 71,791 -- 71,791
Regulatory disallowance........................ 183,729 -- 183,729 222,428 -- 222,428
Alternative minimum tax........................ 422,593 -- 422,593 431,277 -- 431,277
Tax rate differences........................... 76,641 -- 76,641 77,248 -- 77,248
Employee benefits.............................. 90,088 -- 90,088 76,060 -- 76,060
Deferred benefits of state income tax.......... 152,276 5,095 147,181 -- -- --
Other.......................................... 21,678 8,408 13,270 19,664 7,316 12,348
---------- -------- ---------- ---------- -------- ----------
Total deferred federal income tax asset...... 1,347,495 46,290 1,301,205 1,249,187 50,882 1,198,305
Deferred state income taxes.................... 47,319 3,069 44,250 -- -- --
---------- -------- ---------- ---------- -------- ----------
Total deferred tax assets.................... 1,394,814 49,359 1,345,455 1,249,187 50,882 1,198,305
---------- -------- ---------- ---------- -------- ----------
Deferred Tax Liabilities:
Depreciation differences and capitalized
construction costs............................ 4,027,135 -- 4,027,135 3,938,325 -- 3,938,325
Redemption of long-term debt................... 122,691 -- 122,691 125,123 -- 125,123
Deferred charges for state income tax.......... 21,817 -- 21,817 -- -- --
Other.......................................... 116,484 -- 116,484 124,469 -- 124,469
---------- -------- ---------- ---------- -------- ----------
Total deferred federal income tax liability.. 4,288,127 -- 4,288,127 4,187,917 -- 4,187,917
Deferred state income taxes.................... 274,280 -- 274,280 -- -- --
---------- -------- ---------- ---------- -------- ----------
Total deferred tax liability................. 4,562,407 -- 4,562,407 4,187,917 -- 4,187,917
---------- -------- ---------- ---------- -------- ----------
Net Deferred Tax Liability (Asset)............. $3,167,593 $(49,359) $3,216,952 $2,938,730 $(50,882) $2,989,612
========== ======== ========== ========== ======== ==========
11. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS
Most employees of System Companies 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 pensions plans covering most of their employees and providing benefits
similar to those provided to employees of other System Companies. As a part of
the purchase accounting for ENSERCH and LCC, their accrued pension liabilities
were adjusted to recognize all previously unrecognized gains or losses arising
from past experience different from that assumed, the effects of changes in
assumptions, all unrecognized prior service costs and the remainder of any
unrecognized obligation or asset existing at the date of the initial application
of SFAS 87 by the respective company. These adjustments to the accrued pension
liability, to the extent associated with rate-regulated operations, were
recorded as regulatory assets or liabilities and, to the extent associated with
non-regulated operations, as goodwill.
Effective January 1, 1998, the ENSERCH retirement plan was merged into
another retirement plan of the Company. Also, effective during 1998, employees
of certain of the Company's emerging business units will be eligible to
participate in a cash balance plan, rather than the traditional defined benefit
plans. This change, which affects a relatively small percentage of employees,
was made in connection with overall changes in the compensation plans of these
business units designed to bring them closer to the prevailing practices of the
companies in the industries in which they compete.
A-49
In connection with the ENSERCH acquisition, certain employees of ENSERCH and
other System Companies were offered and accepted an early retirement option.
Effects of the early retirement option associated with ENSERCH employees were
included in purchase accounting adjustments as regulatory assets or goodwill, as
appropriate. Effects of the early retirement option associated with employees
of other System Companies were recorded as regulatory assets, or liabilities.
The Company TU Electric
Year Ended December 31, Year Ended December 31,
----------------------- -----------------------
1997 1996 1995 1997 1996 1995
---- ---- ---- ---- ---- ----
Thousands of Dollars
Components of Net Pension Costs(including amounts charged
to fuel cost, deferred and capitalized):
Service cost -- benefits earned during the period.......... $ 36,712 $ 36,779 $ 23,515 $ 20,892 $ 21,731 $ 16,047
Interest cost on projected benefit obligation.............. 92,121 75,501 65,675 60,184 55,999 53,684
Actual return on plan assets............................... (299,800) (183,390) (241,887) (229,303) (143,416) (199,436)
Net amortization and deferral.............................. 190,203 97,988 160,198 154,028 79,261 132,147
--------- --------- --------- --------- --------- ---------
Net periodic pension cost................................. $ 19,236 $ 26,878 $ 7,501 $ 5,801 $ 13,575 $ 2,442
========= ========= ========= ========= ========= =========
Valuation Assumptions:
Discount rate.............................................. 7.25% 7.75% 7.25% 7.25% 7.75% 7.25%
Rate of increase in compensation levels.................... 4.3% 4.3% 4.3% 4.3% 4.3% 4.3%
Expected long-term rate of return.......................... 9.0% 9.0% 9.0% 9.0% 9.0% 9.0%
The Company TU Electric
December 31, December 31,
------------------------- ----------------------
1997 1996 1997 1996
---- ---- ---- ----
Thousands of Dollars
Amounts Recognized:
Actuarial present value of accumulated benefits:
Accumulated benefit obligation......................... $(1,337,120) $ (889,057) $ (725,504) $(685,419)
=========== =========== ========== =========
Vested benefit obligations............................. $(1,264,450) $ (823,918) $ (679,514) $(638,162)
=========== =========== ========== =========
Projected benefit obligation for service
rendered to date.................................... $(1,546,854) $(1,065,396) $ (837,725) $(797,044)
Plan assets at fair value -- primarily equity
investments, government bonds and
corporate bonds........................................ 1,790,715 1,296,025 1,124,924 994,370
----------- ----------- ---------- ---------
Plan assets in excess of projected benefit obligation...... 243,861 230,629 287,199 197,326
Unrecognized net gain from past experience different
from that assumed and effects of changes
in assumptions......................................... (422,503) (350,295) (399,591) (309,042)
Prior service cost not yet recognized in net periodic
pension expense........................................ 31,574 41,566 35,540 39,226
Unrecognized plan assets in excess of projected
benefit obligation at initial application.............. (4,700) (5,708) (2,701) (3,327)
----------- ----------- ---------- ---------
Accrued pension cost................................... $ (151,768) $ (83,808) $ (79,553) $ (75,817)
=========== =========== ========== =========
The Eastern Energy, ENSERCH and LCC plans use economic assumptions similar to
the other System Companies' plans and are included in the tabular information
above.
A-50
In addition to the retirement plans, the System Companies offer certain
health care and life insurance benefits to substantially all employees,
including those of ENSERCH and LCC but excluding those of Eastern Energy, and
their eligible dependents at retirement. Benefits received vary in level
depending on years of service and retirement dates. The purchase accounting
adjustments described above for the retirement plans of ENSERCH and LCC were
also applied to the accrued liabilities for the post employment health care and
life insurance benefits.
The Company TU Electric
Year Ended December 31, Year Ended December 31,
---------------------------- ----------------------------
1997 1996 1995 1997 1996 1995
---- ---- ---- ---- ---- ----
Thousands of Dollars
Components of Net Periodic Postretirement Benefit Costs (including
amounts charged to fuel cost, deferred and capitalized):
Service cost -- benefits earned during the period................... $ 12,084 $13,513 $ 9,771 $ 7,446 $ 8,437 $ 6,559
Interest cost on the accumulated postretirement benefit obligation.. 43,057 40,809 38,842 30,885 31,394 31,109
Amortization of the transition obligation........................... 16,953 16,978 16,978 13,618 13,633 13,633
Actual return on plan assets........................................ (13,260) (7,079) (6,096) (10,073) (4,816) (4,520)
Net amortization and deferral....................................... 7,015 8,303 4,646 4,894 5,746 3,662
-------- ------- ------- ------- ------- -------
Net postretirement benefits cost................................... $ 65,849 $72,524 $64,141 $46,770 $54,394 $50,443
======== ======= ======= ======= ======= =======
Valuation assumption:
Discount rate....................................................... 7.25% 7.75% 7.25% 7.25% 7.75% 7.25%
Medical cost trend rate............................................. 5.0% 5.0% 5.0% 5.0% 5.0% 5.0%
The Company TU Electric
December 31, December 31,
--------------------- -----------------------
1997 1996 1997 1996
---- ---- ---- ----
Amounts Recognized:
Accumulated postretirement benefit obligation (APBO):
Retirees......................................................... $(412,919) $(325,672) $(274,586) $(280,541)
Fully eligible active employees.................................. (40,901) (38,320) (21,227) (22,701)
Other active employees........................................... (137,033) (187,451) (71,386) (120,452)
--------- --------- --------- ---------
Total APBO....................................................... (590,853) (551,443) (367,199) (423,694)
Plan assets at fair value........................................... 111,799 81,480 81,871 60,862
--------- --------- --------- ---------
APBO in excess of plan assets.................................... (479,054) (469,963) (285,328) (362,832)
Unrecognized net loss............................................... 67,023 92,589 45,681 68,977
Unrecognized prior service cost..................................... 18,557 819 -- --
Unrecognized transition obligation.................................. 162,359 271,649 141,685 218,126
--------- --------- --------- ---------
Accrued postretirement benefits cost............................ $(231,115) $(104,906) $ (97,962) $ (75,729)
========= ========= ========= =========
The expected increase in costs of future benefits covered by the plan is
projected using a health care cost trend rate of 5% in 1998 and thereafter. A
one percentage point increase in the assumed health care cost trend rate in each
future year would increase the APBO at December 31, 1997 by approximately
$65,900,000 for the System Companies and $40,300,000 for TU Electric, and other
postretirement benefits cost for 1997 by approximately $9,800,000 for System
Companies and $7,300,000 for TU Electric.
12. SALES OF ACCOUNTS RECEIVABLE
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 $350,000,000. ENSERCH has a facility for $100,000,000. Additional
receivables are continually sold to replace those collected. At December 31,
1997 and 1996, accounts receivable of TU Electric was reduced by $300,000,000
and at December 31, 1997, accounts receivable of ENSERCH companies were reduced
by $100,000,000, to reflect the sales of such receivables to financial
institutions under such agreements.
A-51
13. REGULATION AND RATES
The Company and TU Electric
- ---------------------------
Docket 9300 -- The PUC's final order (Order) in connection with TU
Electric's January 1990 rate increase request (Docket 9300) was reviewed by the
250th Judicial District Court of Travis County, Texas, (District Court) and
thereafter was appealed to the Court of Appeals for the Third District of Texas
and to the Supreme Court of Texas (Supreme Court). As a result of such review
and appeals, 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 would also be 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 January 1997, the Supreme Court denied a motion for rehearing on the
Comanche Peak minority owners issue filed by the original complainants. TU
Electric cannot predict the outcome of the reconsideration of the Order on
remand by the PUC.
In its decision, the Supreme Court also affirmed the previous $472 million
prudence disallowance related to Comanche Peak. Since the Company and TU
Electric have previously recorded a charge to earnings for this prudence
disallowance, the Supreme Court's decision did not have an effect on the
Company's or TU Electric's current financial position, results of operation or
cash flows.
Docket 11735 -- In July 1994, TU Electric filed a petition in the 200th
Judicial District Court of Travis County, Texas to seek judicial review of the
final order of the PUC granting a $449 million, or 9.0%, rate increase in
connection with TU Electric's January 1993 rate increase request of $760
million, or 15.3% (Docket 11735). Other parties to the PUC proceedings also
filed appeals with respect to various portions of the order.
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 adopted in February 1996.
These tariffs also provide for generation-related ancillary services necessary
to support wholesale transactions. In August 1997, the PUC approved final
tariffs for TU Electric and implemented rates for other transmission providers
within the Electric Reliability Council of Texas (ERCOT) (Docket 15840). Under
rates implemented by the PUC, TU Electric's payments for transmission service
will 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. As such, the
current maximum impact on TU Electric for 1998 is an $8.52 million deficit,
which, in the opinion of TU Electric, is not expected to have a material effect
on its financial position, results of operation or cash flows.
Docket 17250 -- In late 1996, as part of its regular earnings monitoring
process, the PUC staff advised the PUC, after reviewing the 1995 Electric
Investor-Owned Utilities Earnings Report of TU Electric, that it believed TU
Electric was earning in excess of a reasonable rate of return, and the PUC and
TU Electric subsequently began discussions concerning possible remedies. It was
decided to limit negotiations to a resolution of issues concerning TU Electric's
earnings through 1997, and discussion of a longer-term resolution was deferred.
In July 1997, the PUC issued its final written order approving TU Electric's
proposal to make a one-time $80 million refund to its customers and to leave
rates unchanged during the remainder of 1997. TU Electric recorded the charge
to revenues in July 1997 and included the refunds in August 1997 billings. The
proposal was the result of a joint stipulation in which TU Electric was joined
by the PUC General Counsel, on behalf of the PUC Staff and the public interest,
the Office of Public Utility Counsel, the state agency charged with representing
the interests of residential and small commercial customers, and the Coalition
of Cities served by TU Electric.
Docket 18490 -- On December 17, 1997, TU Electric, together with the PUC
General Counsel, the Office of Public Utility Counsel and various other parties
interested in TU Electric's rates and services, filed with the PUC a
stipulation and joint application which, if granted would, among other things:
(i) result in permanent retail base rate credits beginning January 1, 1998, of
4% for residential customers, 2% for general service secondary customers and 1%
for all other retail
A-52
customers, (ii) result in additional permanent retail base rate credits
beginning January 1, 1999, of 1.4% for residential customers, (iii) impose a
11.35% cap on TU Electric's rate of return on equity during 1998 and 1999, with
any sums earned above that cap being applied as additional nuclear production
depreciation, (iv) allow TU Electric to record depreciation applicable to
transmission and distribution assets in 1998 and 1999 as additional depreciation
of nuclear production assets, (v) establish an updated cost of service study
that includes interruptible customers as customer classes, (vi) result in the
permanent dismissal of pending appeals of prior PUC orders including Docket No.
11735, if all other parties that have filed appeals of those dockets also
dismiss their appeals, (vii) result in the stay of any proceedings in the remand
of Docket 9300 prior to January 1, 2000, and, (viii) result in all gains from
off-system sales of electricity in excess of the amount included in base rates
being flowed to customers through the fuel factor.
The PUC has until March 31, 1998 to approve or reject the stipulation and
joint application. Otherwise, TU Electric may terminate the base rate
reductions and all other aspects of the proposal upon giving two weeks notice to
the PUC.
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, as defined
by the PUC, cumulative under- or over-recovery of fuel costs. If the cumulative
difference of the under- or over-recovery, plus interest, is in excess of 4% of
the annual estimated fuel costs most recently approved by the PUC, it will be
deemed to be material. In accordance with PUC approvals, TU Electric has, since
the inception of the rule in 1986, made thirteen refunds of over-collected fuel
costs and two surcharges of under-collected fuel costs. The most recent refund
was made pursuant to a petition filed by TU Electric in July 1997 to refund
approximately $67 million, including interest, in over-collected fuel costs for
the period October 1995 through May 1997 (Fuel Refund). Such over-collection was
primarily due to TU Electric's ability to use less expensive nuclear fuel and
purchased power to offset a higher-priced natural gas market during the period.
Customer refunds were included in August 1997 billings. A final order
confirming the Fuel Refund was entered by the PUC in October 1997. The two
surcharges (one in the amount of $147.3 million and the other in the amount of
$93 million) have been appealed by certain intervenors to district courts of
Travis County, Texas. In those appeals, those parties are contending that the
PUC is without authority to allow a fuel cost surcharge without a hearing and
resultant findings that the costs are reasonable and necessary and that the
prices charged to TU Electric by supplying affiliates are no higher than the
prices charged by those affiliates to others for the same item or class of
items. TU Electric is unable to predict their outcome.
Fuel Reconciliation Proceeding -- In July 1997, the PUC ruled on TU
Electric's petition seeking final reconciliation of all eligible fuel and
purchased power expenses incurred during the reconciliation period of July 1,
1992 through June 30, 1995 (approximately $4.7 billion). In the ruling, the PUC
disallowed approximately $81 million of eligible fuel related costs (including
interest of $12 million) incurred during the reconciliation period (Fuel
Disallowance). The majority of the Fuel Disallowance (approximately $67
million) is related to replacement fuel costs as a result of the November 1993
collapse of the emissions chimney serving Unit 3 of the Monticello lignite-
fueled generating station. In addition, the PUC ruled that approximately $10
million from the gain on sale of sulfur dioxide allowances should be deferred
and reconsidered at a future date. TU Electric received a final written order
from the PUC and recorded the charge to revenues in August 1997. TU Electric
strongly disagrees with the Fuel Disallowance and continues to vigorously defend
its position. TU Electric has appealed the PUC's order to the District Court of
Travis County, Texas.
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 existing 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 existing 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.
Integrated Resource Plan -- In October 1994, TU Electric filed an application
for approval by the PUC of certain aspects of its Integrated Resource Plan (IRP)
for the ten year period 1995 - 2004. The IRP, developed as an experimental
A-53
pilot project in conjunction with regulatory and customer groups, included the
acquisition of electric energy through a competitive bidding process of third
party-supplied demand-side management resources and renewable resources. In
August 1995, the PUC remanded the case to an Administrative Law Judge for
development of a solicitation plan and to more closely conform the TU Electric
1995 IRP to new state legislation that required the PUC to adopt a state-wide
integrated resource planning rule by September 1, 1996. In January 1996, TU
Electric filed an updated IRP with the PUC along with a proposed plan for the
solicitation of resources through a competitive bidding process. The PUC issued
its final order on TU Electric's IRP in October 1996, and modified the order in
December 1996 and February 1997. The modified order approved a flexible
solicitation plan that will allow TU Electric to conduct up to three optional
resource solicitations for a total of 2,074 MW of demand-side and supply-side
resources prior to the filing of its next IRP in June 1999. TU Electric is
currently reviewing the need and timing for conducting the first of these
resource solicitations.
In addition to its solicitation plan in the IRP docket, TU Electric requested
and received approval from the PUC to expand its Power Cost Recovery tariff to
provide current cost recovery of resource acquisition costs for demand-side
management resources acquired in the 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.
Open-Access Transmission -- In February 1996, pursuant to the 1995 amendments
to PURA, 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
consisting of an ERCOT system-wide component and a distance-sensitive component.
The ERCOT system-wide component provides that each load-serving entity in ERCOT
will pay a share of the ERCOT-wide transmission cost of service based on the
entity's load. The distance-sensitive component provides that a distance-
sensitive rate will be paid to utilities that own transmission facilities, based
on the impact of transmitting power and energy to loads. The rates charged for
using the transmission system are designed to ensure that all market
participants pay on a comparable basis to use the system. While all users of
the transmission grid pay rates that are comparably designed, the impact on
individual users will differ.
In May 1996, TU Electric filed with the PUC, under Docket 15638, its
transmission cost information and tariffs for open-access wholesale transmission
service. These tariffs also provide for generation-related ancillary services
necessary to support wholesale transactions. Company-specific proceedings to
determine transmission rates for each transmission provider within ERCOT were
concluded in 1996. In August 1997, the PUC approved final tariffs for TU
Electric and implemented rates for other transmission providers within ERCOT.
As a result of the PUC rules, the organization and structure of ERCOT has
been changed to provide for equal governance among all wholesale electricity
market participants. These changes were made in order to facilitate wholesale
competition while ensuring continued reliability within ERCOT.
The Company
- -----------
Lone Star Gas and Lone Star Pipeline Rates -- In October 1996, Lone Star
Pipeline filed a request with the RRC to increase the rate it charges Lone Star
Gas to store and transport gas ultimately destined for residential and
commercial customers in the 550 Texas cities and towns served by Lone Star Gas.
Lone Star Gas also requested that the RRC separately set rates for costs to
aggregate gas supply for these cities. Rates previously in effect were set by
the RRC in 1982. In September 1997, the RRC issued an order reducing the
charges by Lone Star Pipeline to Lone Star Gas for storage and transportation
services. In that order, the RRC did authorize separate charges for the Lone
Star Pipeline storage and transportation services, a separate charge by Lone
Star Gas for the cost of aggregating gas supplies, and a continuation of the
100% flow through of purchased gas expense. The RRC also imposed some new
criteria for affiliate gas purchases and a new reconciliation procedure that
will require a review of purchased gas expenses every three years. The RRC
order has become final, but is being appealed by several parties including Lone
Star Pipeline and Lone Star Gas. The rates authorized by the order became
effective on December 1, 1997, and will result in an annual margin reduction of
approximately $8.2 million.
A-54
On August 20, 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 has been
separated into different phases. Two of the phases, conversion to the NARUC
account numbering system and unbundling, have been dismissed by the RRC, and one
other phase, rate case expense, is pending RRC action on the basis of a
stipulation of all parties. In the phase dealing with historic gas cost and gas
acquisition practices, Lone Star Gas and Lone Star Pipeline have filed a motion
for summary disposition stating that any retroactive rate action would be
inappropriate and unlawful. Settlement discussions with intervenor cities are
ongoing. If the motion for summary disposition is denied, a hearing has been
scheduled to begin in August 1998. A number of management and transportation
related issues have been placed in a separate phase which still has an undefined
scope and is being held in abeyance pending the resolution of the phase dealing
with gas costs. Management believes that gas costs were prudently incurred and
were properly accounted for and recovered through the gas cost recovery
mechanism previously approved by the RRC. At this time, management is unable to
determine the ultimate outcome of the inquiry.
14. IMPAIRMENT OF ASSETS
The Company and TU Electric
- ---------------------------
In September 1995, the Company and TU Electric recorded the impairment of
several non-performing assets pursuant to SFAS 121 which prescribes a
methodology for assessing and measuring impairments in the carrying value of
certain assets. The September 1995 impairment of the Company's assets,
including the partially completed Twin Oak and Forest Grove lignite-fueled
facilities of TU Electric, and Chaco Energy Company's (Chaco's) coal reserves in
New Mexico, as well as several minor assets, aggregated $1,233 million ($802
million after tax) for the Company and $486 million ($316 million after tax) for
TU Electric. The Company and TU Electric have determined that the Twin Oak and
Forest Grove lignite-fueled facilities are not necessary to satisfy TU
Electric's capacity requirements as currently projected due to changes in load
growth patterns and availability of alternative generation. The impairment of
TU Electric's lignite-fueled facilities has been measured based on management's
current expectations that these assets will either be sold or constructed
outside the traditional regulated utility business. The Company has determined
that the Chaco coal reserves will no longer be developed through traditional
means due to ample availability of alternative fuels at favorable prices.
Chaco's impairment was measured based on a significant decrease in the market
value of the coal reserves as determined by an external study. A variety of
options are being considered with respect to the Chaco coal reserves. (See Note
15.) The impairment of these assets involved a write-down to their estimated
fair values using a valuation study based on the discounted expected future cash
flows from the respective assets' use. With respect to the other assets
impaired, fair values were determined based on current market values of similar
assets.
15. COMMITMENTS AND CONTINGENCIES
Capital Expenditures -- The Company's construction expenditures, excluding
AFUDC, are presently estimated at $886 million, $799 million and $852 million
for 1998, 1999 and 2000, respectively. TU Electric's construction
expenditures for utility related activities, excluding AFUDC, are presently
estimated at $449 million, $439 million and $441 million for 1998, 1999 and
2000, respectively. Expenditures for TU Electric nuclear fuel are presently
estimated at $104 million for 1998, $81 million for 1999 and $92 million for
2000.
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.
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. 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
A-55
allowances from or to other utilities. The Environmental Protection Agency
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's capital requirements have not been significantly affected by the
requirements of the Clean Air Act. Although TU Electric is unable to fully
determine the cost of compliance with the Clean Air Act, it is not expected to
have a significant impact on the company. Any additional capital expenditures,
as well as any increased operating costs, associated with these new 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 System Companies have entered into purchased
power contracts to purchase portions of the generating output of certain
qualifying cogenerators and qualifying small power producers through the year
2005. These contracts provide for capacity payments subject to a facility
meeting certain operating standards and energy payments based on the actual
power taken under the contracts. The cost of these and other purchased power
contracts is recovered currently through base rates, power cost and fuel
recovery factors applied to customer billings. Capacity payments under these
contracts for the years ended December 31, 1997, 1996 and 1995 were
$240,174,000, $232,915,000, and $229,340,000, respectively, for the Company, and
$236,867,000, $228,336,000 and $223,910,000 respectively, for TU Electric.
Assuming operating standards are achieved, future capacity payments under the
agreements are estimated as follows:
The Company TU Electric
----------- -----------
Years Thousands of Dollars
- -----
1998......................... $ 248,168 $244,568
1999......................... 220,281 213,081
2000......................... 168,961 161,761
2001......................... 139,039 131,839
2002......................... 106,745 99,545
Thereafter................... 140,345 136,745
---------- --------
Total capacity payments.. $1,023,539 $987,539
========== ========
Leases -- The System Companies have entered into operating leases covering
various facilities and properties including combustion turbines, transportation,
mining and data processing equipment, and office space. Lease costs charged to
operation expense for the years ended December 31, 1997, 1996 and 1995 were
$156,710,000, $144,553,000, and $141,775,000, respectively, for the Company, and
$65,755,000, $56,376,000, and $60,156,000, respectively, for TU Electric.
Future minimum lease commitments under such operating leases that have
initial or remaining noncancellable lease terms in excess of one year as of
December 31, 1997, were as follows:
The Company TU Electric
----------- -----------
Years Thousands of Dollars
-----
1998.............................. $ 83,729 $ 35,049
1999.............................. 73,024 34,152
2000.............................. 64,161 33,834
2001.............................. 96,387 33,619
2002.............................. 55,428 32,857
Thereafter........................ 546,148 408,886
-------- --------
Total minimum lease commitments.. $918,877 $578,397
======== ========
Financial Guarantees -- TU Electric has entered into contracts with public
agencies to purchase cooling water for use in the generation of electric energy.
In connection with certain contracts, TU Electric has agreed, in effect, to
guarantee the principal, $30,005,000 at December 31, 1997, 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, for the years 1998 through 2001 as follows:
$4,435,000 for each of the
A-56
years 1998 and 1999, $4,419,000 for 2000 and $4,422,000 for 2001. Payments made
by TU Electric, net of amounts assumed by a third party under such contracts,
for 1997, 1996 and 1995 were $3,750,000, $3,548,000, and $3,628,000,
respectively. 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 $69,395,000 remaining principal amount of bonds at December 31, 1997,
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. The Company and/or its subsidiaries are the guarantor on
various commitments and obligations of others aggregating some $45,000,000 at
December 31, 1997.
The Company
- -----------
Chaco Coal Properties -- Chaco has a coal lease agreement for the rights to
certain surface minable coal reserves located in New Mexico. The agreement
encompasses a minimum of 228 million tons of coal with provisions for minimum
advance royalty payments of approximately $16 million per year through 2017.
The Company has entered into a surety agreement to assure the performance by
Chaco with respect to this agreement. Because of the present ample availability
of western coal at favorable prices from other mines, Chaco has delayed plans to
commence mining operations, and accordingly, is reassessing its alternatives
with respect to its coal properties, including seeking purchasers thereof. (See
Note 14.)
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 $8.9 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 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 $79.275 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 $1.06 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
$4.1 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
$1.1 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 $26 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.
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
A-57
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 $9 million per year.
The Company
- -----------
Gas Purchase Contracts -- Texas Utilities Fuel Company (Fuel Company) buys
gas under long-term intrastate contracts in order to assure reliable supply to
its customers. Many of these contracts require minimum purchases ("take-or-
pay") of gas. Based on Fuel Company's estimated gas demand, which assumes
normal weather conditions, requisite gas purchases are expected to substantially
satisfy purchase obligations for the year 1998 and thereafter.
Lone Star Gas buys gas under long-term, intrastate contracts in order to
assure reliable supply to its customers. Many of these contracts require
minimum purchases of gas. Lone Star Gas has made accruals for payments that may
be required for settlement of gas-purchase contract claims asserted or that are
probable of assertion. Lone Star Gas continually evaluates its position
relative to asserted and unasserted claims, above-market prices or future
commitments. Management believes that Lone Star Gas has not incurred losses for
which reserves should be provided at December 31, 1997. Based on estimated gas
demand, which assumes normal weather conditions, requisite gas purchases are
expected to substantially satisfy purchase obligations for the year 1998 and
thereafter.
TU Electric
- -----------
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, 1997, such reserve totaled $120,452,000 which includes an accrual
of $18,179,000 for the year ended December 31, 1997. As of December 31, 1997,
the market value of deposits in the external trust for decommissioning of
Comanche Peak was $160,062,000. 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 then-current dollars,
decommissioning costs for Comanche Peak Unit 1, and Unit 2 and common facilities
were estimated to be $271,000,000 and $404,000,000, respectively.
Decommissioning activities are projected to begin in 2030 and 2033 for
Comanche Peak Unit 1, and Unit 2 and common facilities, respectively. TU
Electric is recovering decommissioning costs based upon a 1992 site-specific
study through rates placed in effect under Docket 11735 (see Note 13). 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 and TU Electric
- ---------------------------
General -- In addition to the above, the Company and TU Electric are involved
in various 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-58
16. 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, 1997 and 1996,
are as follows:
December 31, 1997 December 31, 1996
---------------------- ---------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------ ----- ------ -----
Thousands of Dollars
The Company
- -----------
On balance sheet assets (liabilities):
Long-term debt (including current maturities)................. $(9,531,450) $(9,932,157) $(9,024,187) $(9,406,944)
TU Electric obligated, mandatorily redeemable, preferred
securities of subsidiary trusts holding solely debentures
of TU Electric............................................. (875,146) (913,447) (381,311) (395,091)
Preferred stock of subsidiary subject to mandatory
redemption................................................ (20,600) (22,019) (238,391) (250,098)
Other investments............................................. 241,959 248,980 194,652 191,435
LESOP note receivable......................................... 250,000 280,910 250,000 262,175
Off-balance sheet assets (liabilities):
Financial guarantees.......................................... (144,732) (148,628) (107,000) (111,000)
Interest rate swaps........................................... -- (50,476) -- (32,312)
Currency swap*................................................ -- 76,420 -- (1,557)
*The foreign currency swap is a hedge of a foreign currency transaction. (See
Note 8.)
TU Electric
- -----------
On balance sheet assets (liabilities):
Long-term debt (including current maturities).................... $(6,228,092) $(6,573,526) $(6,310,594) $(6,657,126)
TU Electric obligated, mandatorily redeemable, preferred
securities of subsidiary trusts holding solely debentures
of TU Electric................................................ (875,146) (913,447) (381,311) (395,091)
Preferred stock subject to mandatory redemption.................. (20,600) (22,019) (238,391) (250,098)
Other investments................................................ 204,794 209,190 172,779 169,820
Off balance sheet assets (liabilities):
Financial guarantees............................................. (99,400) (103,296) (107,000) (111,000)
Interest rate swap............................................... -- (1,368) -- --
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 the present value of future cash flows discounted at rates consistent
with comparable maturities for credit risk. The fair values of preferred
securities are based on quoted market prices. The carrying amounts reflected in
the Consolidated Balance Sheets 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. The trust funds are 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.
A-59
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 the System Companies' 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.
17. SUPPLEMENTARY FINANCIAL 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 (Loss)
Consolidated Net Per Share of
Operating Revenues Operating Income Income (Loss) Common Stock*
---------------------- ----------------------- ------------------ --------------
Quarter Ended 1997 1996 1997 1996 1997 1996 1997 1996
- ------------- ---- ---- ---- ---- ---- ---- ---- ----
Thousands of Dollars (except per share amounts)
March 31....................................... $1,493,804 $1,463,900 $ 381,807 $ 414,938 $114,799 $126,074 $0.51 $0.56
June 30........................................ 1,588,485 1,691,313 459,929 535,047 160,746 202,957 0.72 0.90
September 30................................... 2,264,945 1,930,097 684,063 743,610 289,610 357,983 1.24 1.59
December 31.................................... 2,598,374 1,465,618 380,872 309,395 95,299 66,592 0.39 0.30
---------- ---------- ---------- ---------- -------- --------
$7,945,608 $6,550,928 $1,906,671 $2,002,990 $660,454 $753,606
========== ========== ========== ========== ======== ========
- --------------------------------------
* The sum of the quarters may not equal annual earnings per share due to
rounding. Diluted earnings per share for all other quarters were not different
from basic earnings per share.
The difference in operating income for the third quarter 1997 from amounts
previously reported reflects the reclassification of certain costs by ENSERCH to
conform to the Company's presentation.
TU Electric
- -----------
Consolidated
Operating Revenues Operating Income Net Income
---------------------- ---------------------- ------------------
Quarter Ended 1997 1996 1997 1996 1997 1996
- ------------- ---- ---- ---- ---- ---- ----
Thousands of Dollars
March 31............... $1,365,459 $1,348,330 $ 271,867 $ 305,057 $143,011 $152,785
June 30................ 1,451,541 1,558,778 329,871 391,019 182,987 227,869
September 30........... 1,851,356 1,787,412 476,910 522,270 321,992 379,438
December 31............ 1,467,061 1,335,091 268,412 244,252 123,884 102,603
---------- ---------- ---------- ---------- -------- --------
$6,135,417 $6,029,611 $1,347,060 $1,462,598 $771,874 $862,695
========== ========== ========== ========== ======== ========
A-60
Appendix B
ENSERCH CORPORATION AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF TEXAS UTILITIES COMPANY)
INDEX TO FINANCIAL INFORMATION
December 31, 1997
Page
Selected Financial Data................................................... B-2
Management's Discussion and Analysis of Financial Condition and Results
of Operation............................................................. B-3
Independent Auditors' Report.............................................. B-9
Statements of Consolidated Income......................................... B-10
Statements of Consolidated Cash Flows..................................... B-11
Consolidated Balance Sheets............................................... B-12
Statements of Consolidated Common Stock Equity............................ B-13
Notes to Consolidated Financial Statements................................ B-14
B-1
ENSERCH CORPORATION AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF TEXAS UTILITIES COMPANY)
SELECTED FINANCIAL DATA
Predecessor
-------------------------------------------------------------------------------
Period from Period from
Acquisition January 1,
Date to 1997 to Year Ended December 31,
December 31, Acquisition -----------------------------------------------------------------
1997 Date 1996 1995 1994 1993
------------------------------------------------------------------------------------------------
(Dollars in thousands)
Total assets -- end of year.. $3,236,784 $2,721,142 $2,535,400 $2,640,573 $2,315,400
========== ========== ========== ========== ==========
Capitalization -- end of
year
Long-term Debt.............. $ 646,796 $ 932,721 $ 801,226 $ 806,471 $ 720,100
Advances from Parent........ 293,843 -- -- -- --
Preferred Stock............. 175,000 175,000 175,000 175,000 175,000
Common Stock Equity......... 761,644 743,391 719,182 726,187 647,600
---------- ---------- ---------- ---------- ----------
Total...................... $1,877,283 $1,851,112 $1,695,408 $1,707,658 $1,542,700
========== ========== ========== ========== ==========
Capitalization ratios -
end of year
Long-term Debt.............. 34.5% 50.4% 47.3% 47.2% 46.7%
Advances from Parent........ 15.6 -- -- -- --
Preferred Stock............. 9.3 9.4 10.3 10.3 11.3
Common Stock Equity......... 40.6 40.2 42.4 42.5 42.0
---------- ---------- ---------- ---------- ----------
Total...................... 100.0% 100.0% 100.0% 100.0% 100.0%
========== ========== ========== ========== ==========
Sales Volumes:
Gas distribution (million
cubic feet):
Residential................ 33,417 52,891 83,054 76,896 76,741 86,324
Commercial................. 20,996 33,162 52,265 48,765 49,013 53,023
Industrial................. 2,094 3,148 7,380 13,566 15,251 16,899
Electric generation........ 463 4,179 11,199 11,023 10,983 12,377
---------- ---------- ---------- ---------- ---------- ----------
Total gas distribution.... 56,970 93,380 153,898 150,250 151,988 168,623
========== ========== ========== ========== ========== ==========
Pipeline transportation
(million cubic feet)....... 255,391 362,020 652,339 561,134 541,590 542,772
Gas liquids (thousand
barrels)................... 2,521 3,352 6,114 5,984 5,913 5,958
Gas marketing (million
cubic feet)................ 292,264 223,207 315,332 419,243 488,415 306,675
Operating Revenues
Gas distribution:
Residential................ $ 205,760 $ 335,647 $ 514,724 $ 496,993 $ 480,272 $ 536,925
Commercial................. 108,650 178,897 275,045 269,448 264,053 286,899
Industrial................. 8,594 13,861 28,647 55,724 63,482 69,555
Electric generation........ 6,424 23,317 48,139 50,929 53,183 58,732
---------- ---------- ---------- ---------- ---------- ----------
Total gas distribution.... 329,428 551,722 866,555 873,094 860,990 952,111
Pipeline transportation..... 57,544 77,307 133,930 143,487 141,002 143,350
Gas liquids................. 36,514 49,345 97,391 69,751 68,870 73,551
Gas marketing............... 858,566 601,826 825,009 750,463 997,418 666,221
Other....................... 41,952 83,628 134,140 85,600 80,922 85,138
Less intercompany revenues.. (47,897) (85,671) (162,765) (131,354) (134,826) (129,774)
---------- ---------- ---------- ---------- ---------- ----------
Total operating revenues... $1,276,107 $1,278,157 $1,894,260 $1,791,041 $2,014,376 $1,790,597
========== ========== ========== ========== ========== ==========
Income (Loss) from
Continuing Operations....... $ (9,565) $ (15,377) $ 9,751 $ 21,362 $ (5,661) $ 22,260
========== ========== ========== ========== ========== ==========
Ratio of earnings to fixed
charges..................... 0.66 0.58 1.31 1.46 0.82 1.52
Ratio of earnings to
combined fixed charges and
preferred dividends......... 0.57 0.49 1.01 1.18 0.58 1.18
Financial information of Predecessor for all periods prior to the Acquisition
Date (August 5, 1997) have been restated to reflect the results of Enserch
Exploration, Inc. and Lone Star Energy Plant Operations, Inc., as well as
engineering and construction and environmental businesses, as discontinued
operations.
B-2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATION
FORWARD-LOOKING STATEMENTS
This report and other presentations made by ENSERCH Corporation (ENSERCH or
the Corporation) contain forward-looking statements within the meaning of
Section 21E of the Securities Exchange Act of 1934, as amended. Although
ENSERCH believes that in making any such statement its expectations are based on
reasonable assumptions, any such statement involves uncertainties and is
qualified in its entirety by reference to the following important factors that
could cause the actual results of ENSERCH to differ materially from those
projected in such forward-looking statement: (i) prevailing governmental
policies and regulatory actions, including those of the Railroad Commission of
Texas (RRC), acquisitions and disposal of assets and facilities, operation and
construction of plant facilities, present or prospective wholesale and retail
competition, changes in tax laws and policies and changes in and compliance with
environmental and safety laws and policies, (ii) weather conditions and other
natural phenomena, (iii) unanticipated population growth or decline, and changes
in market demand and demographic patterns, (iv) competition for retail and
wholesale customers, (v) pricing and transportation of natural gas and other
commodities, (vi) unanticipated changes in interest rates or rates of inflation,
(vii) unanticipated changes in operating expenses and capital expenditures,
(viii) capital market conditions, (ix) competition for new energy development
opportunities, (x) legal and administrative proceedings and settlements, (xi)
inability of various counterparties to meet their obligations with respect to
ENSERCH's financial instruments, (xii) changes in technology used and services
offered by ENSERCH and (xiii) significant changes in ENSERCH's relationship with
its employees and the potential adverse effects if labor disputes or grievances
were to occur.
Any forward-looking statement speaks only as of the date on which such
statement is made, and ENSERCH undertakes no obligation to update any forward-
looking statement to reflect events or circumstances after the date on, which
such statement is made or to reflect the occurrence of unanticipated events.
New factors emerge from time to time, and it is not possible for ENSERCH to
predict all of such factors, nor can 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 be
assessed.
FINANCIAL CONDITION
Merger With TUC
On August 5, 1997 (Merger Date or Acquisition Date), all of the common stock
of ENSERCH Corporation was converted to common stock of Texas Utilities Company
(TUC), and ENSERCH became a wholly-owned subsidiary of TUC. ENSERCH shareholders
received .225 share of TUC common stock for each share of ENSERCH. Immediately
prior to ENSERCH's merger with TUC, Enserch Exploration, Inc. (EEX) and Lone
Star Energy Plant Operations, Inc. (LSEPO) were merged to form a new company
(New EEX), and ENSERCH distributed to its common shareholders its ownership
interest in New EEX, which was represented by approximately 105 million shares
of New EEX common stock with a carrying value of $583 million. In the
distribution, which was tax free to the recipients, ENSERCH shareholders of
record on August 4, 1997 received approximately 1.5 shares of New EEX common
stock for each share of ENSERCH common stock owned. ENSERCH's financial
statements for all periods presented have been restated to reflect EEX and LSEPO
as discontinued operations. ENSERCH's discontinued operations also include its
engineering and construction and environmental businesses, the principal assets
of which were sold in prior years. On December 31, 1997, ENSERCH sold to Texas
Energy Industries, Inc., a wholly-owned subsidiary of TUC, at net book value,
the group of companies which had constituted its power development and
international gas distribution operations. As a result, ENSERCH is no longer
engaged in these activities. The sale was effected in order to strengthen the
Corporation's financial position by relieving it of certain indebtedness as well
as its obligation to make capital expenditures in the future. For accounting
purposes, the sale was considered to be a merger of commonly controlled
companies, accordingly, it was reflected effective as of the Merger Date.
Operating results for periods following the Merger Date exclude these
operations.
B-3
TUC accounted for its acquisition of ENSERCH as a purchase, and push down
accounting has been applied, with the result that purchase accounting
adjustments have been reflected in the financial statements of ENSERCH and its
subsidiaries for the period subsequent to August 5, 1997. Financial statements
for periods prior to that date were prepared using ENSERCH's historical basis of
accounting and are designated as "Predecessor". For purposes of the discussion
of operating results provided herein, the financial information of the
Predecessor for the 1997 periods prior to the Merger Date have been combined
with the post-merger 1997 financial information. The business operations of
ENSERCH were not significantly changed as a result of the merger, and post-
merger and pre-merger operating results, except as noted in the discussion, are
comparable.
Capital Expenditures
The primary capital expenditures of the Corporation and its subsidiaries in
1997 and as estimated for 1998 through 2000 are as follows:
1997.......................... $119,000,000
1998.......................... 143,000,000
1999.......................... 133,000,000
2000.......................... 140,000,000
The planned expenditures are expected to be funded from internal cash flows,
borrowings under credit lines or advances from TUC.
Liquidity and Financial Resources
Continuing operations used cash of $12.2 million for operating activities in
1997 compared with providing cash of $105.0 million in 1996 and $127.8 million
in 1995. Changes in operating assets and liabilities used cash of $71.0 million
in 1997 and $15.3 million in 1995 but provided cash of $16.0 million in 1996.
Discontinued exploration and production operations used cash of $21.8 million
in 1997 compared with providing cash of $19.6 million and $37.6 million in 1996
and 1995, respectively. The discontinued engineering and construction
operations used cash of $12.2 million in 1997, $5.0 million in 1996 and $28.1
million in 1995.
Investing activities required $125.6 million in 1997 versus $176.4 million in
1996 and $120.1 million in 1995. Capital spending in 1997 was about 10% lower
than in 1996 but 11% greater than in 1995. Also, investments in unconsolidated
affiliates provided cash in 1997 but required significant cash in 1996. Other
investing activities used cash of $14.3 million in 1997 and $.9 million in 1995
versus providing cash of $8.6 million in 1996.
Total capitalization at December 31, 1997 was $1.9 billion, up slightly from
year-end 1996. Common stock equity as a percentage of total capitalization was
40.6% at December 31, 1997 compared with 40.2% at year-end 1996.
Shortly after the merger with TUC, ENSERCH's commercial paper program and
bank lines in the form of a revolving credit agreement were discontinued.
ENSERCH retired $204.5 million of commercial paper outstanding at the Merger
Date and $260.4 million of long-term debt outstanding under the credit
agreement, using advances from TUC to fund the retirements. In December 1997,
TUC purchased additional shares of ENSERCH common stock for $200 million. These
funds were used to reduce borrowings from TUC.
In January 1998, ENSERCH issued $125 million of 6 1/4% Series A Notes due
2003 and $125 million of Remarketed Reset Notes due 2008 with a variable
interest rate (5.82% at date of issuance). Net proceeds from these borrowings
were used to refinance or redeem like amounts of higher rate debt and preferred
stock. Also in January, the Series E Adjustable
B-4
Rate Preferred Stock was redeemed at 100% of its liquidation price plus accrued
and unpaid dividends. On February 25, 1998, the Corporation called for
redemption the 6 3/8% Convertible Subordinated Debentures. ENSERCH may issue
additional debt and equity securities as needed, including the possible future
sale of up to $250 million aggregate principal amount of securities currently
registered with the Securities and Exchange Commission (SEC) for offering
pursuant to Rule 415 under the Securities Act of 1933.
At December 31, 1997, TUC, Texas Utilities Electric Company, a wholly-owned
indirect subsidiary of TUC, and ENSERCH had joint lines of credit under credit
facility agreements (Credit Agreements) with a group of commercial banks. The
Credit Agreements have two facilities. Facility A provides for short-term
borrowings aggregating up to $570 million outstanding at any time at variable
interest rates and terminates April 23, 1998. Facility B provides for short-
term borrowings aggregating up to $1,330 million outstanding at any time at
variable interest rates and terminates April 24, 2002. ENSERCH borrowings under
both facilities are limited to an aggregate of $650 million outstanding at any
time. ENSERCH borrowings under these facilities will be used for working
capital and other needs. At December 31, 1997, ENSERCH had no borrowings under
these facilities.
Quantitative and Qualitative Disclosure About Market Risk
The Corporation's market risk exposure is primarily a result of changes in
interest rates and commodity price exposures. Derivative instruments including
options, swaps, futures and other contractual commitments are used to reduce and
manage a portion of those risks. With the exception of the marketing activities
of a subsidiary, Enserch Energy Services, Inc. (EES), the Corporation's
participation in derivative transactions is designated for hedging purposes;
derivative instruments are not held or issued for trading purposes.
CREDIT RISK -- Credit risk relates to the risk of loss that the Corporation
would incur as a result of nonperformance by counterparties to their respective
derivative instruments. The Corporation maintains credit policies with regard
to its counterparties that management believes significantly minimize overall
credit risk. The Corporation does not obtain collateral to support the
agreements but monitors the financial viability of counterparties and believes
its credit risk is minimal on these transactions. The Corporation believes the
risk of nonperformance by counterparties is minimal.
INTEREST RATE MARKET RISK -- The table below provides information concerning
the Corporation's financial instruments as of December 31, 1997 that are
sensitive to changes in interest rates, which consist only of debt obligations.
The table presents principal cash flows and related weighted average interest
rates by expected maturity dates.
Expected Maturity Date
---------------------------------------------------------------------
There- Fair
1998 1999 2000 2001 2002 after Total Value
------ ------ ----- ------ ------ ------- ------- ------
Millions of Dollars
Long-term Debt (including current maturities)
Fixed Rate................................. $ -- $150.0 $ -- $100.0 $90.8 $306.0 $646.8 $649.1
Average interest rate...................... -- 7.00% -- 8.88% 6.38% 6.62% 7.02% --
ENERGY MARKETING MARKET RISK -- As part of its natural gas marketing
activities, EES enters into forward contracts that principally involve physical
delivery of natural gas and derivative financial instruments, including options,
swaps, futures and other contractual arrangements to offset price risks of gas
supply. These activities involve price commitments into the future and,
therefore, give rise to market risk. EES applies mark-to-market accounting to
its business activities. At December 31, 1997, natural gas marketing operations
had net commitments to sell approximately 50.6 billion cubic feet (Bcf) of
natural gas through the year 2003 with offsetting net financial positions to
purchase approximately 61.3 Bcf.
B-5
EES has performed a sensitivity analysis to estimate its exposure to market
risk of its commodity and related financial commitments. The exposure for fixed
price natural gas 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. EES uses market-implied volatilities to determine its
exposure to volatility risk. Market risk is estimated as the potential loss in
fair value resulting from at least a 15% change in market factors which may
differ from actual results. Using 15%, the most adverse change in fair value at
December 31, 1997 as a result of this analysis, was a reduction of $1.1 million.
For additional information regarding derivative instruments, see Note 7 to
Consolidated Financial Statements.
Regulation and Rates
In October 1996, Lone Star Pipeline Company, a division of ENSERCH (Lone Star
Pipeline), filed a request with the RRC to increase the rate it charges Lone
Star Gas Company, a division of ENSERCH (Lone Star Gas), to store and transport
gas ultimately destined for residential and commercial customers in the 550
Texas cities and towns served by Lone Star Gas. Lone Star Gas also requested
that the RRC separately set rates for costs to aggregate gas supply for these
cities. Rates previously in effect were set by the RRC in 1982. In September
1997, the RRC issued an order reducing the charges by Lone Star Pipeline to Lone
Star Gas for storage and transportation services. In that order, the RRC did
authorize separate charges for the Lone Star Pipeline storage and transportation
services, a separate charge by Lone Star Gas for the cost of aggregating gas
supplies, and a continuation of the 100% flow through of purchased gas expense.
The RRC also imposed some new criteria for affiliate gas purchases and a new
reconciliation procedure that will require a review of purchased gas expenses
every three years. The RRC order has become final, but is being appealed by
several parties including Lone Star Pipeline and Lone Star Gas. The rates
authorized by the order became effective on December 1, 1997, and will result in
an annual margin reduction of approximately $8.2 million.
On August 20, 1996, the RRC ordered a general inquiry into the rates and
services of Lone Star Gas, most notably a review of Lone Star Gas' historic gas
cost and gas acquisition practices since the last rate setting. The inquiry
docket has been separated into different phases. Two of the phases, conversion
to the NARUC account numbering system and unbundling, have been dismissed by the
RRC, and one other phase, rate case expense, is pending RRC action on the basis
of a stipulation of all parties. In the phase dealing with historic gas cost
and gas acquisition practices, Lone Star Gas and Lone Star Pipeline have filed a
motion for summary disposition stating that any retroactive rate action would be
inappropriate and unlawful. Settlement discussions with intervenor cities are
ongoing. If the motion for summary disposition is denied, a hearing has been
scheduled to begin in August 1998. A number of management and transportation
related issues have been placed in a separate phase which still has an undefined
scope and is being held in abeyance pending the resolution of the phase dealing
with gas costs. Management believes that gas costs were prudently incurred and
were properly accounted for and recovered through the gas cost recovery
mechanism previously approved by the RRC. At this time, management is unable to
determine the ultimate outcome of the inquiry.
RESULTS OF OPERATION
For purposes of the discussion of operating results provided herein, the
financial information of the Predecessor for the 1997 periods prior to the
Merger Date have been combined with the post-merger 1997 financial information.
The business operations of ENSERCH were not significantly changed as a result of
the merger, and post-merger and pre-merger operating results, except as noted in
the discussion, are comparable.
For the year ended December 31, 1997, ENSERCH had a loss from continuing
operations of $24.9 million compared with income of $9.8 million in 1996 and
income of $21.4 million in 1995. The 1997 results were reduced by a first
quarter $8.6 million pretax, $5.6 million after-tax, provision for a credit Lone
Star Gas made voluntarily to its customers, and were improved by third quarter
income of $12.5 million pretax, $8.1 million after-tax, from the sale of
interests in cogeneration projects. Also, results for 1997 were reduced by
merger-related expenses, which totaled $25.1 million pretax, $21.3 million
after-tax, and the amortization of goodwill of $8.1 million arising from the
merger with TUC.
B-6
Consolidated revenues for 1997 were $2.6 billion compared with $1.9 billion
for 1996 and $1.8 billion for 1995. The higher revenues reflect an increase of
$.6 billion in gas marketing revenues. (The table of Selected Financial Data
provides additional information on revenues.) Gas purchased for resale
increased from $1.3 billion in 1996 to $2.0 billion in 1997, reflecting the
increase in natural gas marketing activity. Operating income was $66.7 million
in 1997 compared with $105.1 million in 1996 and $100.1 million in 1995.
Operating income from natural gas gathering and processing operations decreased
$12 million in 1997 from 1996 but increased $18 million in 1996 from 1995.
Fluctuations in natural gas liquids (NGL) demand, price volatility for NGL
products and natural-gas feedstock costs are the major factors that influence
financial results in the NGL processing business. Lone Star Pipeline operating
income increased $10 million in 1997 from 1996 but decreased $3 million in 1996
from 1995. The higher results in 1997, which were after a voluntary refund of
$8.6 million made prior to the Merger to residential and commercial customers,
were primarily attributable to lower operating and maintenance expenses and
lower costs of gas lost in transmission, while the decline from 1995 to 1996 was
principally due to higher operating and maintenance expenses. Lone Star Gas
operating income decreased $15 million in 1997 from 1996 after increasing $15
million in 1996 from 1995. The 1997 decline from 1996 was primarily due to
higher operating and maintenance expenses. Results for 1996 were improved from
1995 because of the higher volume of residential and commercial sales, which
have the highest margins. Natural gas marketing activities reported an
increased operating loss of $32 million in 1997 from 1996 and an increased loss
of $12 million in 1996 from 1995. Those losses were the result of low margins,
inadequate systems infrastructure and costs associated with new systems that
were implemented around year-end 1997. Natural gas marketing operations are
expected to be profitable in 1998. Power development income (prior to the
transfer of these operations to a TUC affiliate effective with the Merger)
improved $16 million in 1997 mostly due to the income from the sale of interests
in projects. The Corporation's 1997 operating results also include $8.1 million
of amortization of goodwill resulting from the Merger.
Other income (deductions) - net in 1997 included $2.4 million in gains from
the sale of cogeneration plants. Other amounts consisted principally of gains
on disposals of assets and interest income, less losses from unconsolidated
affiliates.
Interest charges for 1997 were $76.3 million compared with $76.7 million in
1996 and $71.4 million in 1995. Interest charges for 1997 included $10.7
million related to advances from TUC.
The extraordinary loss in 1996 of $2.1 million represented a premium incurred
in connection with the prepayment of ENSERCH's 9.06% Notes to facilitate the
merger with TUC.
For the year ended December 31, 1997, there was a loss from discontinued
operations of $224.7 million which included a $236 million after-tax impact of
a write-down of the carrying value of EEX's oil and gas properties due to the
U.S. cost center ceiling limitation at March 31, 1997, and a $9.7 million ($14.9
million pre-tax) provision for estimated costs and expenses to wind-up
engineering and construction operations. For the years 1996 and 1995,
discontinued operations had income of $11.4 million and a loss of $8.3 million,
respectively. (See Note 12 to consolidated financial statements.)
CHANGES IN ACCOUNTING STANDARDS
Statement of Financial Accounting Standards (SFAS) No. 130, "Reporting
Comprehensive Income," (SFAS 130) will become effective in 1998. This statement
requires companies to report and display comprehensive income and its components
(revenues, expenses, gains and losses). Comprehensive income includes all
changes in equity during a period except those resulting from investments by
owners and distributions to owners.
SFAS 131, "Disclosures About Segments of an Enterprise and Related
Information," will become effective in 1998. This statement establishes
standards for defining and reporting business segments. The Corporation is
currently determining its reportable segments.
The adoption of SFAS 130 and SFAS 131 will not affect the Corporation's
consolidated financial position, results of operations or cash flows.
B-7
YEAR 2000 ISSUES
Many existing computer programs use only two digits to identify a year in the
date field. These programs were designed and developed without considering the
impact of the upcoming change in the century. If not corrected, many computer
applications could fail or produce erroneous data by or at the Year 2000. The
Year 2000 issues affect virtually all companies and organizations.
As a result of the Merger, many of the Corporation's existing computer
applications and systems will be migrated to existing or planned TUC systems.
TUC began its Year 2000 initiative in 1996 by addressing mainframe-based
application systems. In early 1997, an infrastructure project to address
information technology (IT) related equipment and systems software was begun.
In late 1997, a corporate-wide project to address Year 2000 issues related to
embedded systems such as process controls for energy production and delivery
and client-developed applications was begun. Most of the ENSERCH mainframe
applications, infrastructure, embedded systems and client-developed applications
that will not be migrated to existing or planned TUC systems have been
incorporated into these projects. These projects extend beyond the TUC
organization in an effort to also work with key vendors, service suppliers and
others so that TUC and ENSERCH can appropriately prepare for Year 2000.
The remediation and replacement work on the majority of IT application
systems and infrastructure are expected to be completed by the end of 1998.
Much of the work on the TUC Year 2000 project is expected to be completed by the
end of 1998, although the project will extend into 1999. Based on present
assessments of the IT and infrastructure projects, a cost of $11.25 million for
TUC was estimated. ENSERCH will be billed for its share of the costs. The TUC
costs are being expensed as incurred over the four-year period (1996 through
1999) covered by the projects. Assessment of the cost of the TUC Year 2000
project is in the early stages.
B-8
INDEPENDENT AUDITORS' REPORT
ENSERCH Corporation and Subsidiaries:
We have audited the accompanying consolidated balance sheets of ENSERCH
Corporation and subsidiaries (the Corporation) as of December 31, 1997 and also
1996 (Predecessor Company balance sheet), and the related statements of
consolidated income, cash flows and common stock equity for the period from
August 5, 1997 (acquisition date) to December 31, 1997, and the period from
January 1, 1997 to the acquisition date and for each of the two years in the
period ended December 31, 1996 (Predecessor Company Operations). These
financial statements are the responsibility of the Corporation's management.
Our responsibility is to express an opinion on these financial statements based
on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of ENSERCH Corporation
and subsidiaries at December 31, 1997 and 1996, and the results of their
operations and their cash flows for the period from the acquisition date to
December 31, 1997, the period from January 1, 1997 to the acquisition date and
for the two years in the period ended December 31, 1996, in conformity with
generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Dallas, Texas
February 24, 1998
B-9
ENSERCH CORPORATION AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF TEXAS UTILITIES COMPANY)
STATEMENTS OF CONSOLIDATED INCOME
Predecessor
----------------------------------------------
Period From
Period From January 1, 1997 Year Ended
Acquisition To December 31,
Date to Acquisition -------------------------------
December 31, 1997 Date 1996 1995
------------------ ----------- ---------------- -------------
Thousands of Dollars
OPERATING REVENUES.......................... $1,276,107 $1,278,157 $1,894,260 $1,791,041
---------- ---------- ---------- ----------
OPERATING EXPENSES
Gas purchased for resale............... 1,052,658 941,626 1,316,137 1,260,191
Operation and maintenance.............. 150,569 209,596 348,830 313,633
Depreciation and amortization.......... 29,720 33,693 53,802 48,272
Gross receipts taxes................... 12,312 29,134 43,212 41,415
Payroll, ad valorem and other taxes.... 11,024 17,224 27,186 27,479
---------- ---------- ---------- ----------
Total operating expenses......... 1,256,283 1,231,273 1,789,167 1,690,990
---------- ---------- ---------- ----------
OPERATING INCOME............................ 19,824 46,884 105,093 100,051
MERGER RELATED EXPENSES..................... -- (25,135) (6,790) --
OTHER INCOME (DEDUCTIONS) -- NET............ 881 2,799 (1,575) 4,106
INTEREST CHARGES............................ (31,755) (44,537) (76,700) (71,380)
---------- ---------- ---------- ----------
INCOME (LOSS) BEFORE INCOME TAXES........... (11,050) (19,989) 20,028 32,777
INCOME TAX EXPENSE (BENEFIT)................ (1,485) (4,612) 10,277 11,415
---------- ---------- ---------- ----------
INCOME (LOSS) FROM CONTINUING OPERATIONS.... ( 9,565) (15,377) 9,751 21,362
INCOME (LOSS) FROM DISCONTINUED OPERATIONS.. -- (224,691) 11,387 (8,309)
EXTRAORDINARY LOSS ON EXTINGUISHMENT
OF DEBT................................ -- -- (2,096) --
---------- ---------- ---------- ----------
NET INCOME (LOSS)........................... (9,565) (240,068) 19,042 13,053
PREFERRED STOCK DIVIDENDS................... 4,677 6,725 11,339 11,690
---------- ---------- ---------- ----------
NET INCOME (LOSS) AVAILABLE FOR COMMON
STOCK................................. $ (14,242) $ (246,793) $ 7,703 $ 1,363
========== ========== ========== ==========
See Notes to Consolidated Financial Statements.
B-10
ENSERCH CORPORATION AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF TEXAS UTILITIES COMPANY)
STATEMENTS OF CONSOLIDATED CASH FLOWS
Predecessor
-------------------------------------
Period From
Period From January 1,
Acquisition 1997 Year Ended
Date to To December 31,
December 31, Acquisition --------------------------
1997 Date 1996 1995
----------- ---------- ------------ ------------
Thousands of Dollars
CASH FLOWS -- OPERATING ACTIVITIES
Income (loss) from continuing operations.... $ (9,565) $ (15,377) $ 9,751 $ 21,362
Adjustments to reconcile income (loss) from
continuing operations to cash provided by
operating activities:
Depreciation and amortization............. 29,720 33,693 53,802 48,272
Deferred income-tax expense (benefit)..... 18,718 (8,803) 5,317 5,043
Recoveries of gas-purchase contract
settlements............................. 318 27 7,926 51,297
Other..................................... 4,587 5,503 12,224 17,161
Changes in operating assets and liabilities
Accounts receivable..................... (340,758) 132,763 (101,288) (13,456)
Other current assets.................... 22,683 33,529 (24,995) (24,029)
Accounts payable
Affiliates............................ 4,926 -- -- --
Other................................. 279,756 (148,859) 98,148 10,960
Other current liabilities............... (33,737) (8,194) 44,121 11,209
Gas marketing risk management assets and
liabilities........................... (13,142) -- -- --
--------- --------- --------- ---------
Cash provided by (used for) operating
activities.......................... (36,494) 24,282 105,006 127,819
--------- --------- --------- ---------
CASH FLOWS -- INVESTING ACTIVITIES
Additions to property, plant and equipment.. (56,690) (62,074) (132,262) (106,854)
Sales and retirements of property, plant
and equipment............................. (250) 171 6,863 5,132
Investments in unconsolidated affiliates.... 188 12,267 (59,627) (8,785)
Sale of subsidiaries to an affiliated
company................................... (4,891) -- -- --
Purchases of businesses, net of cash
acquired.................................. -- -- -- (8,762)
Other....................................... (4,777) (9,539) 8,605 (875)
--------- --------- --------- ---------
Cash used for investing activities...... (66,420) (59,175) (176,421) (120,144)
--------- --------- --------- ---------
CASH FLOWS -- FINANCING ACTIVITIES
Change in commercial paper and other
short-term borrowings..................... (198,473) 66,540 (49,000) 32,759
Advances from parent........................ 382,641 -- -- --
Issuance of senior long-term debt........... -- 100,000 160,000 150,000
Debt issuance costs......................... -- -- (786) (944)
Borrowings under revolving credit agreement. -- -- 25,000 --
Retirement of senior long-term debt......... (269,335) (100,784) (66,960) (162,677)
Change in assignments of future gas purchase
credits................................... -- -- -- (17,191)
Issuance of common stock
Parent.................................... 200,000 -- -- --
Other..................................... -- 3,757 27,678 4,408
Cash dividends paid......................... (5,728) (12,771) (25,144) (25,401)
Other....................................... -- (7) (3,289) (702)
--------- --------- --------- ---------
Cash from (used for) financing activities. 109,105 56,735 67,499 (19,748)
--------- --------- --------- ---------
CASH PROVIDED BY (USED FOR) DISCONTINUED
OPERATIONS
Exploration and production.................. -- (21,773) 19,636 37,636
Engineering and construction................ (6,564) (5,641) (5,001) (28,102)
--------- --------- --------- ---------
Cash from (used for) Discontinued
Operations.............................. (6,564) (27,414) 14,635 9,534
--------- --------- --------- ---------
NET CHANGE IN CASH AND CASH EQUIVALENTS....... (373) (5,572) 10,719 (2,539)
CASH AND CASH EQUIVALENTS -- BEGINNING BALANCE 12,143 17,715 6,996 9,535
--------- --------- --------- ---------
CASH AND EQUIVALENTS -- ENDING BALANCE........ $ 11,770 $ 12,143 $ 17,715 $ 6,996
========= ========= ========= =========
See Notes to Consolidated Financial Statements.
B-11
ENSERCH CORPORATION AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF TEXAS UTILITIES COMPANY)
CONSOLIDATED BALANCE SHEETS
Predecessor
-----------
December 31,
-----------------------
1997 1996
---------- ---------
In thousands
ASSETS
Current Assets
Cash and cash equivalents......................... $ 11,770 $ 17,715
Accounts receivable............................... 506,284 350,535
Gas marketing risk management assets.............. 365,650 --
Gas stored underground............................ 114,244 119,178
Deferred income taxes............................. 22,663 20,683
Other............................................. 35,094 88,989
---------- ----------
Total current assets........................ 1,055,705 597,100
---------- ----------
Investments......................................... 37,041 113,771
---------- ----------
Net Investment in Discontinued Exploration and
Production Operations.............................. -- 798,229
---------- ----------
Property, Plant and Equipment....................... 1,200,864 1,942,528
Less accumulated depreciation and amortization... 24,669 787,205
---------- ----------
Net property, plant and equipment........... 1,176,195 1,155,323
---------- ----------
Goodwill (net of accumulated amortization:
1997 -- $8,113,000; 1996 -- $901,000).......... 791,401 8,740
---------- ----------
Other Assets
Unamortized regulatory assets for pension and
other postretirement benefits.................. 52,336 --
Deferred income taxes........................... 69,267 26,306
Other........................................... 54,839 21,673
---------- ----------
Total other assets.......................... 176,442 47,979
---------- ----------
Total....................................... $3,236,784 $2,721,142
========== ==========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current Liabilities
Commercial paper and short-term bank loans....... $ 6,067 $ 138,000
Current portion of long-term debt................ -- 1,598
Accounts payable
Affiliates.................................. 4,926 --
Other....................................... 491,645 393,097
Gas marketing risk management liabilities........ 357,044 --
Other current liabilities........................ 115,030 152,458
Liabilities for discontinued engineering and
construction operations......................... 12,932 17,933
---------- ----------
Total current liabilities................... 987,644 703,086
---------- ----------
Advances from Parent................................ 293,843 --
---------- ----------
Long-term Debt...................................... 646,796 932,721
---------- ----------
Other Liabilities
Pension and other postretirement benefits........ 165,514 48,075
Deferred income taxes............................ 10,498 13,888
Other............................................ 195,845 104,981
---------- ----------
Total other liabilities..................... 371,857 166,944
---------- ----------
Commitments and Contingent Liabilities (Note 10)....
Shareholders' Equity
Adjustable rate preferred stock.................. 175,000 175,000
Common stock equity.............................. 761,644 743,391
---------- ----------
Shareholders' equity........................ 936,644 918,391
---------- ----------
Total....................................... $3,236,784 $2,721,142
========== ==========
See Notes to Consolidated Financial Statements.
B-12
ENSERCH CORPORATION AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF TEXAS UTILITIES COMPANY)
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
Predecessor
---------------------------------
Period From
Period From January 1,
Acquisition 1997 Year Ended
Date to To December 31,
December 31, Acquisition -------------------
1997 Date 1996 1995
------------ ----------- -------- --------
(In thousands)
COMMON STOCK -- authorized 100 million shares
Balance at beginning of period ............................................... $ -- 703 $304,897 $303,301
Issuance of common stock to parent (2,000,000 shares) ................... 2 -- -- --
Issued for stock plans (0; 215,000; 1,764,000; and 358,000 shares) ...... -- 2 7,363 1,596
Reclassify par value of common stock canceled at
acquisition date ...................................................... -- (705) -- --
Change in par value to $.01 from $4.45 per share ........................ -- -- (311,557) --
-------- --------- --------- --------
Balance at end of period (par value: $.01; $.01; $.01; and $4.45 per share -
outstanding shares: 201,000; 1,000; 70,280,000; and 68,516,000) ......... 2 -- 703 304,897
-------- --------- --------- --------
PAID IN CAPITAL
Balance at beginning of period ............................................ 579,126 672,775 338,857 334,672
Issuance of common stock to parent ................................... 199,998 -- -- --
Excess of proceeds over par value of
common stock issued for stock plans ................................ -- 3,755 21,794 3,866
Dividends declared ................................................... (4,677) (9,202) -- --
Change in par value of common stock .................................. -- -- 311,557 --
Other ................................................................ (3,240) -- 567 319
Distribution of EEX to common shareholders ........................... -- (582,574) -- --
Reclassify common stock and accumulated loss at acquisition date ..... -- (172,205) -- --
Purchase accounting adjustments ...................................... -- (132,937) -- --
-------- --------- --------- --------
Subtotal .......................................................... 771,207 (220,388) 672,775 338,857
Excess of purchase price over paid in capital at acquisition date..... -- 799,514 -- --
-------- --------- --------- --------
Balance at end of period .................................................. 771,207 579,126 672,775 338,857
-------- --------- --------- --------
RETAINED EARNINGS
Balance at beginning of period ............................................ -- 70,774 76,941 89,054
Net income (loss) .................................................... (9,565) (240,068) 19,042 13,053
Dividends declared ................................................... -- (3,616) (25,209) (25,162)
Reclassify accumulated loss at acquisition date ...................... -- 172,910 -- --
Other ................................................................ -- -- -- (4)
-------- --------- --------- --------
Balance at end of period .................................................. (9,565) -- 70,774 76,941
-------- --------- --------- --------
FOREIGN CURRENCY TRANSLATION ADJUSTMENT
Balance at beginning of year .............................................. -- (861) -- --
Change during the year ............................................... -- 76 (1,325) --
Deferred income tax effects .......................................... -- (27) 464 --
Purchase accounting adjustments ...................................... -- 812 -- --
-------- --------- --------- --------
Balance at end of period .................................................. -- -- (861) --
-------- --------- --------- --------
UNAMORTIZED RESTRICTED STOCK COMPENSATION
Balance at beginning of period ............................................ -- -- (1,513) (840)
Shares granted ....................................................... -- -- (1,284) (865)
Cancellations ........................................................ -- -- -- 64
Market valuation adjustments ......................................... -- -- (73) (332)
Amortization ......................................................... -- -- 2,870 460
-------- --------- --------- --------
Balance at end of period .................................................. -- -- -- (1,513)
-------- --------- --------- --------
COMMON STOCK EQUITY ............................................................ $761,644 $ 579,126 $ 743,391 $719,182
======== ========= ========= ========
See Notes to Consolidated Financial Statements.
B-13
ENSERCH CORPORATION AND SUBSIDIARIES
(A WHOLLY-OWNED SUBSIDIARY OF TEXAS UTILITIES COMPANY)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BUSINESS , MERGERS AND DISPOSITIONS
ENSERCH Corporation (ENSERCH or the Corporation) is an integrated company
focused on natural gas. Substantially all of its business operations consist of
the gathering, processing, transmission, distribution and marketing of natural
gas. Businesses and subsidiaries of ENSERCH include Lone Star Gas Company
(Lone Star Gas), a gas distribution company in Texas, serving over 1.35
million customers and providing service through over 23,800 miles of
distribution mains; Lone Star Pipeline Company (Lone Star Pipeline), which has
approximately 7,600 miles of gathering and transmission pipeline in Texas; and
subsidiaries engaged in natural gas processing (Enserch Processing, Inc.) and
natural gas marketing (Enserch Energy Services, Inc.).
On August 5, 1997 (Merger Date or Acquisition Date), the merger transactions
between Texas Utilities Company (TUC) and ENSERCH were completed. All of the
common stock of ENSERCH was converted into common stock of TUC, and ENSERCH
became a wholly-owned subsidiary of TUC. ENSERCH shareholders became entitled
to receive .225 share of TUC common stock for each share of ENSERCH. At the
effective time of the merger, each of the 1,000 outstanding shares of common
stock of ENSERCH Merger Corp. (a transitory corporation organized to facilitate
the merger transaction and owned by TUC) was converted to one share of ENSERCH
Corporation Common Stock, (ENSERCH common stock). All of the shares of ENSERCH
common stock outstanding prior to the effective time of the merger were
converted to shares of TUC and, upon conversion, were canceled and ceased to
exist. Accordingly, upon completion of the merger the outstanding common stock
of ENSERCH consisted of 1,000 shares, par value $0.01 per share, all of which
were owned by TUC. Immediately prior to ENSERCH's merger with TUC, Enserch
Exploration, Inc. (EEX) and Lone Star Energy Plant Operations, Inc. (LSEPO),
former subsidiaries of the Corporation, were merged to form a new company (New
EEX), and ENSERCH distributed to its common shareholders its ownership interest
in these businesses, which was represented by approximately 105 million shares
of New EEX common stock with a carrying value of $583 million. In the
distribution, which was tax free to recipients, ENSERCH shareholders of record
on August 4, 1997 received approximately 1.5 shares of New EEX common stock for
each share of ENSERCH common stock owned.
The value of the TUC shares issued and costs incurred by TUC in connection
with the acquisition of ENSERCH aggregated $579 million. TUC accounted for its
acquisition of ENSERCH as a purchase, and purchase accounting adjustments,
including goodwill, have been pushed down and are reflected in the financial
statements of ENSERCH and its subsidiaries for the period subsequent to August
5, 1997. The financial statements of ENSERCH for the periods ended before
August 5, 1997, were prepared using ENSERCH's historical basis of accounting and
are designated as "Predecessor". The comparability of the operating results for
the Predecessor and the periods encompassing push down accounting are affected
by the purchase accounting adjustments including the amortization of goodwill
over a period of forty years.
The Predecessor financial statements for all periods presented have been
restated to reflect EEX and LSEPO as a discontinued operation. The historical
financial statements of ENSERCH reflect certain reclassifications made to
conform to TUC's presentation style. On December 31, 1997, ENSERCH sold, to
another subsidiary of TUC, at net book value, the group of companies which had
constituted the Corporation's power development and international gas
distribution operations. For financial reporting purposes, the sale was deemed
to have occurred on August 5, 1997. Prior periods were not restated to reflect
the sale.
The fair value of the assets and liabilities of ENSERCH's rate-regulated
natural gas utility business (conducted through its Lone Star Gas Company and
Lone Star Pipeline Company divisions) is considered to be equivalent to the
historical basis of accounting and accordingly, no adjustment has been made to
the carrying value. The excess of the consideration paid by TUC over the
estimated fair value of the assets and liabilities of ENSERCH at the merger date
was approximately $800 million and is reflected as goodwill in the ENSERCH
balance sheet as of December 31, 1997. The process of determining
B-14
the fair value of assets and liabilities at the merger date is continuing, and
the final result awaits the resolution of income tax and other contingencies and
finalization of certain estimates. The following table summarizes the changes
made to the accounts of ENSERCH as of August 5, 1997 as a result of the merger
and application of push down accounting.
Purchase Accounting
Adjustments
--------------------
Thousands of Dollars
Investments $ (4,730)
Net property, plant and equipment (35,357)
Goodwill 791,386 *
Other assets 57,794
--------
Total assets $809,093
========
Current liabilities $ 9,732
Long-term debt 8,299
Deferred income taxes (45,728)
Pension and other postretirement benefits 125,892
Other liabilities 43,509
Shareholders' equity 667,389
--------
Total liabilities and equity $809,093
========
* Net of write-off of a premerger goodwill balance of $8,128 thousand.
The following is a summary of unaudited pro forma results of operations
assuming the distribution to shareholders and the Merger with TUC had occurred
at the beginning of the periods presented.
Year Ended December 31,
-------------------------
1997 1996
------------ -----------
Thousands of Dollars
Revenues............................ $2,553,564 $1,887,774
Operating income.................... 62,318 86,710
Income (loss) before income taxes... (12,034) 10,945
Income taxes (benefit).............. (235) 11,816
Net income (loss)................... (11,799) (871)
Net loss after preferred dividends.. (23,201) (12,210)
On June 29, 1995, ENSERCH purchased the principal operating assets of a
nonregulated marketer of natural gas for approximately $9 million in cash,
including some $8 million of cost in excess of net assets acquired. The
acquisition was accounted for as a purchase. The goodwill was written off as a
purchase adjustment in connection with the merger with TUC. Operations of the
acquired company are included in the accompanying consolidated financial
statements from the date of acquisition.
Effective June 30, 1995, the Corporation exchanged 1,204,098 shares of
ENSERCH common stock for 100% of the outstanding shares of a company, which,
through its subsidiary, is a marketer of natural gas and natural-gas services.
The transaction was accounted for as a pooling-of-interests.
B-15
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND OTHER INFORMATION
Consolidation -- The consolidated financial statements include the accounts
of the Corporation and its majority-owned subsidiaries. All significant
intercompany items and transactions have been eliminated in consolidation.
Investments in significant unconsolidated affiliates are accounted for by the
equity method.
System of Accounts and Other Policies -- Lone Star Gas and Lone Star Pipeline
are subject to the accounting requirements prescribed by the National
Association of Regulatory Utility Commissioners (NARUC).
Use of Estimates -- The preparation of the Corporation's consolidated
financial statements, in conformity with generally accepted accounting
principles, 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 covered by the consolidated financial statements. 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.
Revenue Recognition -- The city gate rate for the cost of gas Lone Star Gas
ultimately delivers to residential and commercial customers is established by
the Railroad Commission of Texas (RRC) and provides for full recovery of the
actual cost of gas delivered, including out-of-period costs such as gas purchase
contract settlement costs. The rates Lone Star Gas charges it 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
records revenues on the basis of cycle meter readings throughout the month and
accrues revenues for gas delivered from the meter reading dates to the end of
the month. Gas stored underground is valued at average cost. The rate Lone
Star Pipeline charges to Lone Star Gas for transportation and storage of gas
ultimately consumed by residential and commercial customers is established by
the RRC.
Depreciation of Property, Plant and Equipment -- The pipeline and
distribution systems are depreciated by the straight line method over the
useful life of the asset; approximately 30 to 40 years from original
acquisition, respectively.
Energy Marketing Activities -- The Corporation, through its natural gas
marketing subsidiary, Enserch Energy Services, Inc. (EES), is a marketer of
natural gas and natural gas services. As part of these business activities, EES
enters into a variety of transactions, including forward contracts principally
involving physical delivery of natural gas and derivative financial instruments,
including options, swaps, futures and other contractual arrangements. The
derivative transactions are concentrated with established energy companies and
major financial institutions. Concurrent with the Merger, EES conformed its
accounting for such activities to the mark-to-market accounting method of
valuing and recognizing earnings from firm contractual commitments to purchase
and sell natural gas in the future and from its portfolio of derivative
financial instruments, including options, swaps, futures and other contractual
commitments. Hedge accounting was used previously by Predecessor.
Stock-Based Compensation -- Statement of Financial Accounting Standards
(SFAS) No. 123 encourages companies to record compensation cost for stock-based
employee compensation plans at fair value but permits other methods. Prior to
the Merger, the Corporation chose to account for stock-based compensation using
the intrinsic value method. Accordingly, compensation cost for stock options was
measured as the excess, if any, of the quoted market price of the Corporation's
stock at the date of the grant over the amount an employee must pay to acquire
the stock. The final compensation cost for restricted stock awards was based on
the quoted market price of the Corporation's stock at the date the award became
vested. As a result of the Merger, unexercised stock options at the Merger date
that had been granted under an ENSERCH plan were exchanged for options to
acquire TUC shares, and the estimated fair value assigned to such options as of
the Merger date was accounted for by TUC as a part of the cost of the
acquisition.
Consolidated Cash Flows -- For purposes of reporting cash flows, temporary
cash investments purchased with a remaining maturity of three months or less are
considered to be cash equivalents.
B-16
The schedule below details the Corporation's cash payments and noncash
investing and financing activities:
Predecessor
-----------------------------------
Period From
Period From January 1,
Acquisition 1997 Year Ended
Date to To December
December 31, Acquisition ------------------
1997 Date 1996 1995
------------ ---------- ------- --------
Thousands of Dollars
Cash payments (refunds):
Interest costs (net of amounts capitalized) ....... $ 33,535 $45,960 $75,833 $ 85,063
========= ======= ======= ========
Income taxes -- net ............................... $ (9,776) $ 4,415 $ 1,585 $ 4,187
========= ======= ======= ========
Non-cash investing and financing activities:
Sales and purchases of businesses:
Book value of assets (sold) acquired ........... $(105,878) $ -- $ -- $ 13,680
Goodwill ....................................... -- -- -- 8,325
Reduction in advances due parent ............... 20,143 -- -- --
Liabilities sold (assumed) ..................... 85,735 -- -- (12,481)
--------- ------- ------- --------
Cash required ................................ -- -- -- 9,524
Cash sold (acquired) ........................... 4,891 -- -- (762)
--------- ------- ------- --------
Net cash used ................................ $ 4,891 $ -- $ -- $ 8,762
========= ======= ======= ========
3. AFFILIATES
Transactions between ENSERCH and TUC for the period from acquisition date
through December 31, 1997 included $10,674,000 in interest expense related to
ENSERCH borrowings from TUC. In addition, ENSERCH had revenues of $8,576,000
from the sale and transportation of gas to other TUC subsidiaries during the
period. The outstanding net amount payable to TUC (including advances) was
$298,769,000 at December 31, 1997.
4. BORROWINGS AND LINES OF CREDIT
ENSERCH's commercial paper program was discontinued following the merger with
TUC, and the borrowings outstanding at the Merger Date, which totaled
$204,500,000, were paid off at maturity with funds advanced to ENSERCH by TUC.
In addition, ENSERCH redeemed long-term debt of $260,400,000 outstanding under a
revolving credit agreement with funds advanced by TUC. At December 31, 1997,
advances from TUC totaled approximately $293,843,000.
At December 31, 1997, TUC, Texas Utilities Electric Company (TU Electric), a
wholly-owned indirect subsidiary of TUC, and ENSERCH had joint lines of credit
under credit facility agreements (Credit Agreements) with a group of commercial
banks. The Credit Agreements have two facilities. Facility A provides for
short-term borrowings aggregating up to $570,000,000 outstanding at any time at
variable interest rates and terminates April 23, 1998. Facility B provides for
short-term borrowings aggregating up to $1,330,000,000 outstanding at any time
at variable interest rates and terminates April 24, 2002. The combined
borrowings of TUC, TU Electric and ENSERCH under both facilities are limited to
an aggregate of $1,900,000,000 outstanding at any one time. ENSERCH borrowings
under both facilities are limited to an aggregate of $650,000,000 outstanding at
any time. ENSERCH borrowings under these facilities will be used for working
capital and other needs. At December 31, 1997, ENSERCH had no borrowings under
these facilities.
B-17
Predecessor
------------
December 31,
----------------------------
1997 1996
-------- --------
Thousands of Dollars
Senior Long-term Debt:
8% Notes due 1997........................................................ $ -- $100,000
7% Notes due 1999........................................................ 150,000 150,000
Subsidiary Revolving Credit Agreement Maturing 2000...................... -- 25,000
ENSERCH Revolving Credit Agreement Maturing 2001......................... -- 160,000
8 7/8% Notes due 2001.................................................... 100,000 100,000
6 3/8% Notes due 2004.................................................... 150,000 150,000
7 1/8% Notes due 2005.................................................... 150,000 150,000
6 3/8% Convertible Subordinated Debentures due 2002.......................... 90,750 90,750
Unamortized premium and discount and fair value adjustments.................. 6,046 8,569
-------- --------
Total..................................................................... 646,796 934,319
Less current maturities...................................................... -- 1,598
-------- --------
Noncurrent................................................................ $646,796 $932,721
======== ========
1998 1999 2000 2001 2002
---- ---- ---- ---- ----
Maturities (for next 5 years) $ -- $150,000 $ -- $100,000 $90,750
The carrying value of ENSERCH debt has been adjusted to reflect fair value
as of the Merger date.
In connection with the Merger, the 6 3/8% Convertible Subordinated Debentures
Due in 2002 became convertible into shares of TUC common stock at $38.54 per
share (equal to 25.947 shares per $1,000 principal amount). The debentures may
be redeemed at 101.27% of the principal amount, plus accrued interest, through
March 31, 1998 and at declining premiums thereafter. The Corporation currently
intends to redeem these debentures in 1998.
In January 1998, the Corporation issued $125,000,000 of 6 1/4% Series A Notes
due 2003 and $125,000,000 of Remarketed Reset Notes due 2008 with a variable
interest rate (5.82% at date of issuance). Net proceeds from these borrowings
were used to refinance or redeem like amounts of higher rate debt and preferred
stock.
ENSERCH may issue additional debt and equity securities as needed, including
the possible future sale of up to $250,000,000 aggregate principal amount of
securities currently registered with the SEC for offering pursuant to Rule 415
under the Securities Act of 1933.
In September 1996, the Corporation paid off the outstanding balance of the
9.06% Notes due through 1999, including a prepayment premium of $3,200,000
($2,100,000 after-tax) which has been accounted for as an extraordinary loss on
early extinguishment of debt.
Interest Charges were as follows: Predecessor
-------------------------------------
Period from
Period from January 1,
Acquisition 1997
Date to To Year Ended December 31,
December 31, Acquisition -----------------------
1997 Date 1996 1995
------------ ------------ ---- ----
Thousand of Dollars
Interest costs incurred ................................... $31,801 $44,668 $76,763 $71,614
Interest capitalized ...................................... (46) (131) (63) (234)
------- ------- ------- -------
Charged to expense ........................................ $31,755 $44,537 $76,700 $71,380
======= ======= ======= =======
B-18
5. SHAREHOLDERS' EQUITY
Common Stock -- On August 5, 1997, all of the common stock of ENSERCH
Corporation was converted into common stock of TUC, and ENSERCH became a wholly
owned subsidiary of TUC. At the effective time of the merger, each of the 1,000
outstanding shares of common stock of ENSERCH Merger Corp. (a transitory
corporation organized to facilitate the merger transaction and owned by TUC) was
converted to one share of ENSERCH Corporation Common Stock, (ENSERCH common
stock). All of the shares of ENSERCH common stock outstanding prior to the
effective time of the merger were converted to shares of TUC and, upon
conversion, were canceled and ceased to exist. Accordingly, at August 5, 1997,
the outstanding common stock of ENSERCH consisted of 1,000 shares, par value
$0.01 per share, all of which were owned by TUC.
In December 1997, TUC purchased an additional 200,000 shares for $200,000,000.
At the special shareholders meeting on November 15, 1996, shareholders of the
Corporation approved a change in the par value of ENSERCH common stock from
$4.45 per share to $.01 per share to facilitate the distribution of the
Corporation's interest in EEX. The reduction in par value was recorded by the
transfer of $312,000,000 to the paid-in-capital account.
Adjustable Rate Preferred Stock
at December 31, 1997 and 1996: Stated Value Per Shares Outstanding
--------------------- ---------------------
Preferred Depositary Preferred Depositary Amount
Share Share Shares Shares (Thousands)
--------- ---------- --------- ---------- -----------
Series E.................... $1,000 $100 100,000 1,000,000 $100,000
Series F.................... 1,000 25 75,000 3,000,000 75,000
--------
Total.................... $175,000
========
On January 16, 1998, the Corporation redeemed all of the outstanding shares
of its Adjustable Rate Preferred Stock, Series E, at $1,000 per share, plus
accrued and unpaid dividends of $14.777 per share.
The Series F stock is redeemable at stated value after May 1, 1999. Holders
of the preferred stock are entitled to its stated value upon involuntary
liquidation.
Dividend rates for the Series F Stock are determined quarterly, in advance,
based on the "Applicable Rate" (highest of the three-month Treasury bill rate,
the Treasury ten-year constant maturity rate and either the Treasury twenty-year
or thirty-year constant maturity rate, as defined), as set forth below:
Per Annum Rate
(Determined Quarterly)
----------------------
Series F
----------------
Dividend rate..................... 87% of
Applicable Rate
Minimum rate...................... 4.50%
Maximum rate...................... 10.50%
B-19
Dividends Declared: Predecessor
------------------------------------------
Period from
Period from January 1,
Acquisition 1997
Date to To Year Ended December 31,
December 31, Acquisition -----------------------
1997 Date 1996 1995
------------- ----------- ---- ----
Thousands of Dollars
Adjustable Rate Preferred Stock:
Series E ($6.42, $7.00, $7.00 per depositary share)... $2,917 $ 3,500 $ 7,000 $ 7,000
Series F ($1.34, $1.45, $1.54 per depositary share)... 1,760 2,270 4,360 4,610
Common Stock ($.10, $.20, $.20 per share)................. -- 7,048 13,849 13,552
------ ------- ------- -------
Total.............................................. $4,677 $12,818 $25,209 $25,162
====== ======= ======= =======
6. STOCK COMPENSATION PLANS
Effective with the Merger, outstanding options for ENSERCH common stock were
exchanged for options for 532,913 shares of TUC common stock exercisable at
prices ranging from $7.03 to $37.71 per share, and ENSERCH was precluded from
awarding further options. The estimated fair value of these options of
$3,214,000 was accounted for as a part of the cost of the acquisition. At
December 31, 1997, 402,966 of these options remained outstanding and
exercisable. Prior to the Merger, the Corporation had three fixed option plans.
Stock options had been awarded to key employees and were outstanding under all
three plans. Options generally expire ten years after the date of the grant.
Summary of Stock Option Activity:
Weighted Average
Exercise Price Number of Options
-------------- -----------------------------------
1997 1996 1997 1996 1995
------ ------ ---------- ----------- ----------
Outstanding -- Beginning of year... $17.71 $17.27 1,182,308 2,514,598 2,308,823
Granted.......................... -- 15.13 -- 326,300 263,200
Exercised (a).................... 17.15 16.47 (214,278) (1,579,289) (27,825)
Canceled or expired.............. 16.72 17.87 (126,225) (79,301) (29,600)
Converted into TUC options....... 18.00 -- (841,805) -- --
--------- ---------- ---------
Outstanding -- End of year......... -- 17.71 -- 1,182,308 2,514,598
========= ========== =========
Exercisable........................ -- 1,182,308 1,957,637
========= ========== =========
(a) Price ranges for options exercised in 1997 (prior to the Merger) were $4.45
to $21.00; in 1996 were $4.45 to $21.13; and in 1995 were $12.50 to $17.00.
The weighted average fair value of stock options granted in 1996 and 1995 was
$4.97 and $4.80, respectively. The fair value for these options granted since
December 31, 1994 was estimated at the date of grant using a Black-Scholes
option pricing model with the following weighted average assumptions for 1996
and 1995, respectively: risk-free interest rates of 5.48% and 7.17%; dividend
yields of 1.33% and 1.48%; volatility factor of the expected market price of the
Corporation's common stock of .29; and a weighted average expected life of the
options of 6.3 years.
The stock option plans included provisions for issuing the Corporation's
common stock under performance-based grants. In 1996 and 1995, the Corporation
granted 83,500 and 59,000 shares of restricted stock under its stock option
plan, respectively. The weighted average grant-date fair value of these
restricted shares was $15.38 and $14.66, respectively. Fair value is equal to
the market value of the Corporation's common stock on the date of grant. Upon
the Board of Directors' agreement to merge with TUC in April 1996, all
restrictions were lifted on the 211,956 shares of restricted stock outstanding.
The unamortized portion of the cost of these shares of $3,100,000 was charged to
compensation expense in 1996.
B-20
Pro forma information regarding net income is mandated by SFAS 123 and has
been determined as if the Corporation had accounted for its employee stock
options under the fair value method of that Statement. Had compensation cost
for the Corporation's stock option plans been determined based on the fair value
at the grant dates for awards under those plans in accordance with the provision
of SFAS 123, the Corporation's net income (loss) for the following periods would
have been reduced to the pro forma amounts indicated below:
Predecessor
--------------------------------------------
Period from
January 1,
1997
To Year Ended December 31,
Acquisition ----------------------------
Date 1996 1995
------------- ---- ----
Thousands of Dollars
Net income (loss) (after provision for dividends on
preferred stock):
As reported.............................................. $(246,793) $7,703 $1,363
Pro forma................................................ (246,793) 5,498 1,179
7. DERIVATIVE INSTRUMENTS
The Corporation enters into derivative instruments, including options, swaps,
futures and other contractual commitments to manage market risks related to
changes in interest rates and commodity price exposures. The Corporation's
participation in derivative transactions, except for the gas marketing
activities, has been designated for hedging purposes, and the derivatives
are not held or issued for trading purposes. (For a discussion of accounting
policies relating to derivative instruments, see Note 2.)
Natural Gas Marketing Activities -- EES's marketing activities involve price
commitments into the future and, therefore, give rise to market risk, which
represents the potential loss that can be caused by a change in the market value
of a particular commitment. Net open portfolio positions often result from the
origination of new transactions or in response to changing market conditions.
The Corporation closely monitors its exposure to market risk. The Corporation
utilizes a number of methods to monitor market risk, including sensitivity
analysis. The exposure for fixed price natural gas 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. 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% change in
market factors which may differ from actual results. Using 15%, the most
adverse change in fair value at December 31, 1997, as a result of this analysis,
was a reduction of $1,100,000.
EES enters into contracts to purchase and sell natural gas for physical
delivery in the future. At December 31, 1997, EES had net commitments to sell
approximately 50.6 billion cubic feet (Bcf) of natural gas through the year 2003
with offsetting net financial positions to purchase approximately 61.3 Bcf.
Concurrent with the Merger, EES conformed its accounting for its gas
marketing activities to mark-to-market accounting, which is the accounting
method used by TUC. Under mark-to-market accounting, changes (whether positive
or negative) in the value of contractual commitments to purchase and sell
natural gas in the future and from its portfolio of derivative financial
instruments, including options, swaps, futures and other contractual commitments
are recognized as an adjustment to operating revenues in the period of change.
The market prices used to value these transactions reflect management's best
estimate of market prices considering various factors including closing exchange
and over-the-counter quotations, time value of money and volatility factors
underlying the commitments. These market prices are adjusted to reflect the
potential impact of liquidating EES's position in an orderly manner over a
reasonable period of time under present market conditions.
B-21
EES has a number of risks and costs associated with the future contractual
commitments included in its natural gas portfolio, including credit risks
associated with the financial condition of counterparties, product location
(basis) differentials 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 natural gas has occurred,
counterparties have fulfilled their financial commitments and related financial
instruments mature or are closed out.
The following table displays the mark-to-market values of EES's natural gas
marketing risk management assets and liabilities at December 31, 1997 and the
average value for the period from August 5, 1997 through December 31, 1997:
Assets Liabilities Net
------ ----------- ---
Thousands of Dollars
Fair Value:
Current............. $365,650 $357,044 $ 8,606
Noncurrent.......... 41,522 31,324 10,198
-------- -------- -------
Total.............. $407,172 $388,368 18,804
======== ========
Less reserves....... 9,251
-------
Net of reserves.... $ 9,553
=======
Average Value:
Total............... $291,809 $278,332 $13,477
======== ========
Less reserves....... 8,134
-------
Net of reserves.... $ 5,343
=======
The following table summarizes EES results from its gas marketing activities
for the periods presented:
Predecessor
----------------------------------------
Period from
Period from January 1,
Acquisition 1997
Date to To Year Ended December 31,
December 31, Acquisition -------------------------
1997 Date 1996 1995
---------- ---------- ---------- ----------
Thousands of Dollars
Revenues........................ $858,467 $601,881 $825,009 $750,463
Net trading income (loss)....... (286) (4,709) 18,144 26,166
Credit Risk -- Credit risk relates to the risk of loss that the Corporation
would incur as a result of nonperformance by counterparties to their respective
derivative instruments. The Corporation maintains credit policies with regard
to its counterparties that management believes significantly minimize overall
credit risk. The Corporation does not obtain collateral to support the
agreements but monitors the financial viability of counterparties and believes
its credit risk is minimal on these transactions. The Company believes the
risk of nonperformance by counterparties is minimal.
B-22
8. INCOME TAXES
Predecessor
------------------------------------
Period from
Period from January 1,
Acquisition 1997
Date to To Year Ended December 31,
Income Tax Expense (Benefit) December 31, Acquisition -----------------------
of Continuing Operations: 1997 Date 1996 1995
-------- --------- ------- -------
Thousands of Dollars
Current
Federal................... $(20,378) $ 4,297 $ 4,745 $ 6,230
State..................... 175 9 136 92
Foreign................... -- (115) 79 50
-------- ------- ------- -------
Total.................... (20,203) 4,191 4,960 6,372
-------- ------- ------- -------
Deferred
Federal................... 18,775 (8,719) 5,429 5,185
Foreign................... -- -- 29 --
-------- ------- ------- -------
Total.................... 18,775 (8,719) 5,458 5,185
-------- ------- ------- -------
Investment Tax Credits..... (57) (84) (141) (142)
-------- ------- ------- -------
Total.................... $ (1,485) $(4,612) $10,277 $11,415
======== ======= ======= =======
Reconciliation of Income Taxes (Benefit) Computed at the Federal Statutory Rate
to Income Tax Expense (Benefit) of Continuing Operations:
Predecessor
-------------------------------------
Period from
Period from January 1,
Acquisition 1997
Date to To Year Ended December 31,
December 31, Acquisition -----------------------
1997 Date 1996 1995
---------- ---------- --------- ---------
Thousands of Dollars
Income (loss) from continuing operations before income taxes:
Domestic.................................................... $(11,072) $(22,815) $27,084 $33,020
Foreign..................................................... 22 2,826 (7,056) (243)
-------- -------- ------- -------
Total..................................................... $(11,050) $(19,989) $20,028 $32,777
======== ======== ======= =======
Income taxes (benefit) at the federal statutory rate of 35%..... $ (3,868) $ (6,996) $ 7,010 $11,472
Amortization of investment tax credits.......................... (57) (84) (141) (142)
Amortization of goodwill........................................ 2,840 -- -- --
State and foreign taxes, net of federal tax benefit............. 114 (69) 159 93
Nondeductible distribution and merger related costs............. -- 4,948 2,275 --
Nondeductible meals and entertainment........................... 175 180 324 342
Change in cash surrender value of life insurance policies....... (313) (389) (24) (19)
Increase in (reduction of) prior year tax liabilities........... -- (2,530) 601 (501)
Other --- net................................................... ( 376) 328 73 170
-------- -------- ------- -------
Income Tax Expense (Benefit).............................. $ (1,485) $ (4,612) $10,277 $11,415
======== ======== ======= =======
B-23
Deferred income taxes provided by the liability method for significant
temporary differences based on tax laws and statutory rates in effect at the
December 31, 1997 and 1996 balance sheet dates are as follows:
Predecessor
-----------------------------
1997 1996
------------------------------ -----------------------------
Total Current Noncurrent Total Current Noncurrent
-------- -------- ---------- -------- ------- ----------
Thousands of Dollars
Deferred Tax Assets:
Net operating--loss and other tax--
credit carryforwards............... $163,061 $ -- $163,061 $154,558 $ -- $154,558
Retirement and other employee
benefit obligations................ 47,128 4,469 42,659 22,916 2,600 20,316
Accruals and allowances.............. 11,779 10,004 1,775 24,728 11,420 13,308
Losses of controlled foreign
corporations....................... 2,557 -- 2,557 5,936 -- 5,936
All other............................ 8,358 8,358 -- 23,712 8,053 15,659
-------- ------- -------- -------- ------- --------
Total.............................. 232,883 22,831 210,052 231,850 22,073 209,777
-------- ------- -------- -------- ------- --------
Deferred Tax Liabilities:
Property-- related differences....... 139,934 -- 139,934 136,617 -- 136,617
All other............................ 11,517 168 11,349 62,132 1,390 60,742
-------- ------- -------- -------- ------- --------
Total.............................. 151,451 168 151,283 198,749 1,390 197,359
-------- ------- -------- -------- ------- --------
Net Deferred Tax Asset............... $ 81,432 $22,663 $ 58,769 $ 33,101 $20,683 $ 12,418
======== ======= ======== ======== ======= ========
At December 31, 1997, domestic net operating-loss (NOL) carryforwards total
$445 million, which begin to expire in 2003, and alternative minimum tax-credit
carryforwards total $7 million. The tax benefits of these carryforwards of $163
million, as shown above, are available to offset future tax payments. ENSERCH
expects to fully utilize such NOL's prior to their expiration date. At December
31, 1997, ENSERCH also had $17 million of general business credit carryforwards
which begin to expire in 1999. As a result of limitations on the timing of use
arising from the Merger, ENSERCH does not expect to fully utilize such tax
credit carryforwards prior to their expiration date; therefore, such credits
were written off as a purchase accounting adjustment.
Predecessor
------------------------------------
Period From
Period From January 1,
Acquisition 1997
Date to To Year Ended December 31,
Cash Payments (Refunds) of Income Taxes Allocated December 31, Acquisition -----------------------
to Continuing Operations: 1997 Date 1996 1995
------------- ----------- ---------- ----------
Thousands of Dollars
Federal:
Current year, including alternative minimum tax............ $(9,245) $2,203 $2,013 $ 8,840
Prior years................................................. (586) 2,149 (535) (5,026)
------- ------ ------ -------
Total..................................................... (9,831) 4,352 1,478 3,814
State......................................................... 55 63 (82) 373
Foreign....................................................... -- -- 189 --
------- ------ ------ -------
Total..................................................... $(9,776) $4,415 $1,585 $ 4,187
======= ====== ====== =======
B-24
9. EMPLOYEE BENEFIT PLANS
Pension Plan -- At the date of the Merger, ENSERCH had a defined benefit
pension plan providing retirement income benefits for substantially all of its
employees. As a part of purchase accounting, the accrued pension liability was
adjusted to recognize all previously unrecognized gains or losses arising from
past experience different from that assumed, the effects of changes in
assumptions, all unrecognized prior service costs and the remainder of
unrecognized asset existing at the date of the initial application of SFAS 87.
These adjustments to the accrued pension liability, to the extent associated
with rate-regulated operations, were recorded as regulatory assets or
liabilities and, to the extent associated with non-regulated operations, as
goodwill. Accrued retirement costs are funded to the extent such amounts are
deductible for federal income-tax purposes. Plan assets consist primarily of
equity investments, government bonds and corporate bonds. Benefits are based on
years of credited service and average compensation.
Effective January 1, 1998, the ENSERCH qualified retirement plan was merged
into another retirement plan of TUC.
In connection with the Merger, certain employees of ENSERCH were offered
and accepted an early retirement option. Effects of the early retirement option
associated with ENSERCH employees were included in purchase accounting
adjustments as regulatory assets or goodwill, as appropriate.
Predecessor
---------------------------------------
Period from
Period from January 1,
Acquisition 1997
Date to To Year Ended December 31,
December 31, Acquisition ------------------------
1997 Date 1996 1995
------------- ------------ ----------- -----------
Thousands of Dollars
Components of Net Pension Costs:
Service cost -- benefits earned during the period.. $ 1,758 $ 2,466 $ 5,228 $ 3,801
Interest cost on projected benefit obligation...... 11,186 14,367 24,418 23,530
Actual return on plan assets....................... (9,606) (46,504) (40,474) (46,777)
Net amortization and deferral...................... (1,016) 31,226 14,295 23,975
------- -------- -------- --------
Net periodic pension cost......................... $ 2,322 $ 1,555 $ 3,467 $ 4,529
======= ======== ======== ========
Valuation Assumptions:
Discount rate...................................... 7.25% 7.75% 7.75% 7.65%
Rate of increase in compensation levels............ 4.30% 4.30% 4.00% 4.00%
Expected long-term rate of return on assets........ 9.00% 9.00% 9.50%
Amounts Recognized:
Actuarial present value of accumulated benefits:
Accumulated benefit obligation...................... $(351,976) $(305,041)
========= =========
Vested benefit obligation........................... $(349,711) $(302,360)
========= =========
Projected pension benefit obligation for service
rendered to date.................................. $(379,217) $(333,955)
Plan assets at fair value - primarily equity
investments, government bonds and corporate bonds.... 275,863 285,810
--------- ---------
Projected benefit obligation in excess of plan assets.. (103,354) (48,145)
Unrecognized net gain from past experience different
from that assumed and effects of changes
in assumptions........................................ 24,743 3,437
Prior service cost not yet recognized in net periodic
pension expense....................................... (6,077) (3,555)
Unrecognized plan assets in excess of projected benefit
obligation at initial application.................. -- (3,406)
--------- ---------
Accrued pension cost............................ $(84,688) $ (51,669)
========= =========
B-25
Postretirement Benefits Other than Pensions -- In addition to the retirement
plan, ENSERCH offers certain health care and life insurance benefits to
substantially all employees and their eligible dependents at retirement. In
connection with the Merger, the plan was amended to provide coverage to those
employees hired after July 1, 1989 not previously eligible for postretirement
medical benefits. In addition, the health care benefits provided to retirees
under the Plan were enhanced to reflect the same level of benefits as offered by
other such plans of TUC companies. The unrecognized prior service cost at
December 31, 1997 arose from these two changes which occurred after the Merger
Date. Obligations have not been prefunded. Benefits received vary in level
depending on years of service and retirement dates. The purchase accounting
adjustments described above for the retirement plan of ENSERCH were also applied
to the accrued liabilities for the postretirement health care and life insurance
benefits.
Predecessor
-------------------------------------
Period from
Period from January 1,
Acquisition 1997
Date to To Year Ended December 31,
December 31, Acquisition -----------------------
1997 Date 1996 1995
------------ ------------ ------------ --------
Thousands of Dollars
Components of Net Periodic Postretirement Benefit Cost:
Service cost -- benefits earned during the period.................. $ 84 $ 142 $ 309 $ 227
Interest cost on accumulated postretirement benefit
obligation...................................................... 2,514 2,899 5,473 5,966
Amortization of the transition obligation.......................... -- 2,189 4,037 4,037
Net amortization and deferral...................................... -- 128 (63) (445)
--------- ------ -------- -------
Net periodic postretirement benefits cost.......................... $ 2,598 $5,358 $ 9,756 $9,785
========= ====== ======== =======
Valuation Assumptions:
Discount rate...................................................... 7.25% 7.75% 7.75% 7.65%
Medical cost trend rate............................................ 5.0% 5.0% 6.50%
Amounts Recognized:
Accumulated postretirement benefit obligation (APBO):
Retirees........................................................ $ (82,570) $(65,997)
Fully eligible active employees................................. (3,339) (499)
Other active employees.......................................... (20,504) (6,720)
--------- --------
Total APBO...................................................... (106,413) (73,216)
Unrecognized transition obligation................................. -- 53,013
Unrecognized prior service cost.................................... 17,822 --
Unrecognized net loss.............................................. 3,455 10,718
--------- --------
Accrued postretirement benefits cost........................... $ (85,136) $ (9,485)
========= ========
The expected increase in costs of future benefits covered by the plan is
projected using a health care cost trend rate of 5% in 1998 and thereafter. A
one percentage point increase in the assumed health care cost trend rate in each
future year would increase the APBO at December 31, 1997 by approximately $11.6
million and other postretirement benefits cost for 1997 by approximately $.1
million.
B-26
10. COMMITMENTS AND CONTINGENT LIABILITIES
Legal Proceedings -- A lawsuit was filed on February 24, 1987, in the 112th
Judicial District of Sutton County, Texas, against subsidiaries and affiliates
of the Corporation and its utility division. The plaintiffs have claimed that
defendants failed to make certain production and minimum-purchase payments under
a gas-purchase contract. The plaintiffs initially alleged a conspiracy to
violate purchase obligations, improper accounting of amounts due, fraud,
misrepresentation, duress, failure to properly market gas and failure to act in
good faith. Under amended pleadings filed in January 1997, plaintiffs have
added allegations of negligence and gross negligence in connection with the
measurement of gas and conversion. Plaintiffs seek actual damages in excess of
$5,000,000 and punitive damages in an amount equal to .5% of the consolidated
gross revenues of the Corporation for the years 1982-1986 (approximately
$85,000,000), interest, costs and attorneys' fees.
On October 30, 1995, a lawsuit was filed in the Supreme Court of Western
Australia by Woodside Petroleum Ltd. and its joint venture partners against the
Corporation, a former subsidiary of the Corporation and others. Plaintiffs seek
damages of approximately $18,000,000 from the Corporation based on an indemnity
arrangement and approximately $208,000,000 from the other defendants for alleged
breaches of contract and breaches of a trade practice act, all in connection
with the construction of an offshore gas and condensate drilling production
platform. The Corporation has agreed to indemnify the current owner of the
former subsidiary pursuant to the provisions in the prior sales agreement.
Following a preliminary hearing, the Court, on December 4, 1997, delivered an
opinion in favor of the Corporation, the former subsidiary and the other
defendants finding that the defendants are additional insurers under certain
insurance policies owned by the plaintiffs and that the plaintiffs and their
insurers are precluded from bringing a subrogated claim against the defendants.
An appeal of this ruling is anticipated.
Management of the Corporation believes it has meritorious defenses to the
claims made in these and other actions brought in the ordinary course of
business. In the opinion of management, the Corporation will incur no liability
from these and all other pending claims and suits that is material for financial
reporting purposes.
Environmental Matters -- The Corporation is subject to federal, state and
local environmental laws and regulations that regulate the discharge of
materials into the environment. Environmental expenditures are expensed or
capitalized depending on their future economic benefit. The level of future
expenditures for environmental matters, including costs of obtaining operating
permits, equipment monitoring and modifications under the Clean Air Act and
cleanup obligations, cannot be fully ascertained until the regulations that
implement the applicable laws have been approved and adopted. It is
management's opinion that all such costs, when finally determined, will not have
a material adverse effect on the consolidated financial position, results of
operations or cash flows of the Corporation.
Commitments -- Future minimum commitments are as follows (in thousands):
1998 1999 2000 2001 2002 Thereafter
------- ------- ------ ------ ------ ----------
Operating leases........ $ 6,100 $ 5,500 $4,800 $3,500 $3,200 $54,500
Gas-purchase contracts.. 87,600 33,900 8,100 5,400 3,000 1,400
The Corporation had a number of noncancelable long-term operating leases at
December 31, 1997, principally for office space and machinery and equipment.
Rental expenses for continuing operations incurred under all operating leases
aggregated $2,600,000 for the pre-and post-merger periods of 1997, $3,600,000 in
1996 and $5,600,000 in 1995. Rental income received for subleased office space
was $2,000,000 in 1997, $3,400,000 in 1996 and $3,400,000 in 1995. Future
minimum rental income to be received for subleased office space is $11,500,000
over the next five years.
B-27
Gas-Purchase Contracts -- Lone Star Gas buys gas under long-term, intrastate
contracts in order to assure a reliable supply to its customers. Many of these
contracts require minimum purchases of gas. Lone Star Gas has made accruals for
payments that may be required for settlement of gas-purchase contract claims
asserted or that are probable of assertion. Lone Star Gas continually evaluates
its position relative to asserted and unasserted claims, above-market prices or
future commitments. Management believes that Lone Star Gas has not incurred
losses for which reserves should be provided at December 31, 1997. Based on
estimated gas demand, which assumes normal weather conditions, requisite gas
purchases are expected to substantially satisfy purchase obligations for the
year 1998 and thereafter.
Sales of Receivables -- The Corporation has sold $100 million of receivables
under an amended limited recourse agreement that matures on September 22, 1998.
Additional receivables are continually sold to replace those collected. The
uncollected balances of receivables sold were $100 million at both year-end 1997
and 1996.
Guarantees -- The Corporation and/or its subsidiaries are the guarantor on
various commitments and obligations of others aggregating some $45,300,000 at
December 31, 1997. The Corporation is exposed to loss in the event of
nonperformance by other parties. However, the Corporation does not anticipate
nonperformance by the counterparties.
Concentrations of Credit Risk -- Lone Star Gas operations have trade
receivables from a few large industrial customers in North Central Texas arising
from the sale of natural gas. A change in economic conditions may affect the
ability of customers to meet their contractual obligations. At December 31,
1997 and 1996, the allowance for possible losses deducted from accounts
receivable was $3,902,000 and $3,968,000 respectively. The Corporation believes
that its provision for possible losses on uncollectible accounts receivable is
adequate for its credit loss exposure.
Inquiry into Lone Star Gas Company Rates -- In October 1996, Lone Star
Pipeline filed a request with the RRC to increase the rate it charges Lone Star
Gas to store and transport gas ultimately destined for residential and
commercial customers in the 550 Texas cities and towns served by Lone Star Gas.
Lone Star Gas also requested that the RRC separately set rates for costs to
aggregate gas supply for these cities. Rates previously in effect were set by
the RRC in 1982. In September 1997, the RRC issued an order reducing the
charges by Lone Star Pipeline to Lone Star Gas for storage and transportation
services. In that order, the RRC did authorize separate charges for the Lone
Star Pipeline storage and transportation services, a separate charge by Lone
Star Gas for the cost of aggregating gas supplies, and a continuation of the
100% flow through of purchased gas expense. The RRC also imposed some new
criteria for affiliate gas purchases and a new reconciliation procedure that
will require a review of purchased gas expenses every three years. The RRC
order has become final, but is being appealed by several parties including Lone
Star Pipeline and Lone Star Gas. The rates authorized by the order became
effective on December 1, 1997, and will result in an annual margin reduction of
approximately $8.2 million.
On August 20, 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 has been
separated into different phases. Two of the phases, conversion to the NARUC
account numbering system and unbundling, have been dismissed by the RRC, and one
other phase, rate case expense, is pending RRC action on the basis of a
stipulation of all parties. In the phase dealing with historic gas cost and gas
acquisition practices, Lone Star Gas and Lone Star Pipeline have filed a motion
for summary disposition stating that any retroactive rate action would be
inappropriate and unlawful. Settlement discussions with intervenor cities are
ongoing. If the motion for summary disposition is denied, a hearing has been
scheduled to begin in August 1998. A number of management and transportation
related issues have been placed in a separate phase which still has an undefined
scope and is being held in abeyance pending the resolution of the phase dealing
with gas costs. Management believes that gas costs were prudently incurred and
were properly accounted for and recovered through the gas cost recovery
mechanism previously approved by the RRC. At this time, management is unable to
determine the ultimate outcome of the inquiry.
B-28
11. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying value and related estimated fair values of the Corporation's
significant financial instruments at December 31, 1997 and 1996 are as follows:
1997 1996
------------------------ ------------------------
Carrying Estimated Carrying Estimated
or Notional Fair or Notional Fair
Amount Value Amount Value
------------ ---------- ------------ ----------
Thousand of Dollars
On-balance sheet liabilities:
Long-term debt (including current maturities) (a)........ $(646,796) $(649,089) $(934,319) $(935,626)
Off-balance sheet assets (liabilities):
Financial guarantees (b)................................. -- (45,332) -- (104,044)
EES derivatives (c)...................................... -- -- -- 749
Estimated fair value: (a) variable-rate debt - approximates carrying amount,
exchange traded debt - quoted market prices, and other debt - discounted value
using rates for debt with similar characteristics; (b) approximates carrying or
notional amount; (c) 1996 based on mark-to-market valuations (see Note 7
concerning EES accounting in 1997).
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.
B-29
12. DISCONTINUED OPERATIONS
In connection with the merger of ENSERCH with TUC, EEX and LSEPO were merged
to form a new company (New EEX), and ENSERCH distributed to its common
shareholders its ownership interest in New EEX, which was represented by
approximately 105 million shares of New EEX common stock with a carrying value
of $583 million. In the distribution, which was tax free to the recipients,
ENSERCH shareholders of record on August 4, 1997 received approximately 1.5
shares of New EEX common stock for each share of ENSERCH common stock owned.
ENSERCH's financial statements for all periods presented have been restated to
reflect EEX and LSEPO as discontinued operations. ENSERCH's discontinued
operations also include its engineering and construction and environmental
businesses, the principal assets of which were sold in prior years. The results
of operations of ENSERCH's discontinued businesses were as follows:
Predeccessor
-----------------------------------------------------
Period From Period From
Acquisition January 1, 1997
Date to To Year Ended December 31,
December 31, Acquisition -------------------------
1997 Date 1996 1995
------------- ------------ ---- ----
(Thousands of Dollars)
Revenues from exploration and production operations.. $ -- $ 159,547 $248,365 $140,199
======= ========= ======== ========
Operating income (loss) from exploration and
production operations........................... $ -- $(375,510)* $ 36,078 $ 7,929
======= ========= ======== ========
Income (loss) from exploration and production
operations...................................... $ -- $(215,006)* $ 12,947 $ (8,309)
Provision for additional costs and expenses
for the wind-up of discontinued engineering and
construction business, net of tax benefit of $5,215
in 1997 and tax provision of $2,160 in 1996......... -- (9,685) (1,560) --
------- --------- -------- --------
Total........................................ $ -- $(224,691) $ 11,387 $ (8,309)
======= ========= ======== ========
Cash Flow Information:
Net cash flows from (used for)
Operating activities................................ $(6,564) $ 111,533 $154,307 $ 81,876
Investing activities................................ -- (125,333) (73,487) (152,127)
Purchase of business, net of cash acquired.......... -- -- -- (332,888)
Financing activities................................ -- (13,614) (66,185) 412,673
------- --------- -------- --------
Net cash flows from (used for) discontinued
operations........................................ $(6,564) $ (27,414) $ 14,635 $ 9,534
======= ========= ======== ========
By Discontinued Operation:
Exploration and production.......................... $ -- $ (21,773) $ 19,636 $ 37,636
Engineering and construction........................ (6,564) (5,641) (5,001) (28,102)
------- --------- -------- --------
Total........................................ $(6,564) $ (27,414) $ 14,635 $ 9,534
======= ========= ======== ========
* Includes a $426 million pretax ($236 million after-tax) write-down of the
carrying value of EEX's oil and gas properties due to the U.S. cost center
ceiling limitation at March 31, 1997.
B-30
The net investment in the discontinued exploration and production business as
of December 31, 1996 consisted of the following (in thousands):
Current assets................................... $ 114,329
Net property, plant and equipment................ 1,493,210
Other assets..................................... 12,161
Current liabilities.............................. (118,191)
Long-term debt................................... (95,564)
Deferred income taxes payable.................... (258,712)
Other liabilities................................ (349,004)
----------
Net investment................................ $ 798,229
==========
Loss provisions of $9.7 million in 1997 and $1.6 million in 1996 after-tax
were recorded in recognition that certain claims and accounts receivable were
settled at amounts less than previously estimated and costs and expenses
incurred for the windup of discontinued engineering and construction businesses
would be greater than previously estimated.
At December 31, 1997, discontinued engineering and construction businesses
had assets of $42 million, consisting principally of retained claims and
accounts receivable of the Ebasco and Enserch Environmental business units, and
current and other liabilities and reserves of $14 million. The Corporation has
filed suit against certain parties to recover amounts outstanding. Management
expects that substantially all disputes will be resolved by year-end 1998 and
that adequate provision for uncollectible claims and accounts receivable,
income-tax matters and expenses for windup of discontinued engineering and
construction operations has been made.
B-31
QUARTERLY RESULTS (UNAUDITED) -- The results of operations by quarters are
summarized below. In the opinion of the Corporation's management, all
adjustments (consisting only of normal recurring accruals) necessary for a fair
presentation have been made. Previously reported amounts have been restated to
reflect EEX and LSEPO as discontinued operations and to reflect the sale of the
power development and international gas distribution operations to Texas Energy
Industries, Inc., a wholly-owned subsidiary of TUC. For accounting purposes,
the sale was considered to be effective as of the Merger date.
Predecessor
----------------------------------
Period From
July 1 Period From
Quarter Ended To Acquisition Quarter
--------------------- Acquisition Date to Ended
March 31 June 30 Date September 30 December 31
---------- --------- ------------ ------------- ------------
Thousands of Dollars
1997:
Revenues........................................ $ 794,813 $348,047 $135,297 $275,906 $1,000,201
Operating Income (Loss)......................... 51,328 (16,250) 11,806 (6,301) 26,125
Income (Loss) From Continuing Operations........ 18,576 (21,576) (12,377) (12,271) 2,706
Income (Loss) From Discontinued Operations...... (219,501) (8,511) 3,321 -- --
Net Income (Loss)............................... (200,925) (30,087) (9,056) (12,271) 2,706
Loss Applicable to Common Stock................. (203,787) (32,980) (10,026) (14,149) (93)
Predecessor
--------------------------------------------------------------
Quarter Ended
--------------------------------------------------------------
March 31 June 30 September 30 December 31
-------- ------- ------------ -----------
Thousands of Dollars
1996:
Revenues........................................ $650,237 $341,432 $311,040 $591,551
Operating Income (Loss)......................... 63,911 (377) (5,589) 47,148
Income (Loss) From Continuing Operations........ 29,485 (12,805) (17,398) 10,469
Income From Discontinued Operations............. 292 6,104 2,117 2,874
Extraordinary Loss on Extinguishment of Debt.... -- -- (2,096) --
Net Income (Loss)............................... 29,777 (6,701) (17,377) 13,343
Earnings (Loss) Applicable to Common Stock...... 27,018 (9,518) (20,263) 10,466
B-32
RECONCILIATION OF PREVIOUSLY REPORTED AMOUNTS
Results of operations were restated for discontinued operations of EEX and
LSEPO effective with the quarterly report ended June 30, 1997. During the
fourth quarter of 1997, results of operations were also restated to reflect the
sale of the power development and international gas distribution operations
effective as of the Merger date. Following the Merger, certain
reclassifications, which only affected operating income, were made to prior
periods to conform to TUC's presentation.
Increase (Decrease)
-----------------------------------------------------------------
Period From
July 1 Period From
Quarter Ended To Acquisition Quarter
---------------------- Acquisition Date to Ended
March 31 June 30 Date September 30 December 31
---------- ---------- ------------ ------------- ------------
Thousands of Dollars
1997:
Revenues.................................... $ (73,154) $ -- $ -- $ (745) $ --
Operating Income (Loss)..................... 395,448 (1,481) (500) 628 --
Income From Continuing Operations........... 219,501 -- -- 1,507 --
Loss From Discontinued Operations........... (219,501) -- -- -- --
Net Income (Loss)........................... -- -- -- 1,507 --
Earnings (Loss) Applicable to Common Stock.. -- -- -- 1,507 --
Quarter Ended
----------------------------------------------------------------
March 31 June 30 September 30 December 31
--------- --------- ------------ -----------
Thousands of Dollars
1996:
Revenues.................................... $ (28,406) $(73,723) $ (74,475) $ (71,761)
Operating Income (Loss)..................... (6,481) (15,452) (10,285) (9,009)
Loss From Continuing Operations............. (292) (6,104) (2,117) (4,434)
Income From Discontinued Operations......... 292 6,104 2,117 4,434
B-33