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2/25/98
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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 8-K
CURRENT REPORT
PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
DATE OF REPORT (DATE OF EARLIEST EVENT REPORTED) - FEBRUARY 26, 1998
TEXAS UTILITIES COMPANY
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
TEXAS 1-12833 75-2669310
(STATE OR OTHER JURISDICTION (COMMISSION (I.R.S. EMPLOYER
OF INCORPORATION) FILE NUMBER) IDENTIFICATION NO.)
ENERGY PLAZA, 1601 BRYAN STREET, DALLAS, TEXAS 75201-3411
(ADDRESS OF PRINCIPAL EXECUTIVE OFFICES)
REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE - (214) 812-4600
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ITEM 7. FINANCIAL INFORMATION
The following audited financial information of Texas Utilities Company and
Subsidiaries for the periods ended December 31, 1997 is filed herein as a part
of this Form 8-K Report.
EXHIBIT 1
FINANCIAL INFORMATION FOR TEXAS UTILITIES COMPANY AND SUBSIDIARIES
AT DECEMBER 31, 1997:
<TABLE>
<CAPTION>
PAGE
<S> <C>
Management's Discussion and Analysis of Financial Condition and Results of Operations..... 1-9
Independent Auditors' Report.............................................................. 10
Financial Statements:
Statements of Consolidated Income...................................................... 11
Statements of Consolidated Cash Flows.................................................. 12
Consolidated Balance Sheets............................................................13-14
Statements of Consolidated Common Stock Equity......................................... 15
Notes to Consolidated Financial Statements................................................16-40
EXHIBIT 23 CONSENT OF DELOITTE AND TOUCHE
EXHIBIT 27 FINANCIAL DATA SCHEDULE
</TABLE>
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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) contain forward)looking statements within the meaning of Section
21E of the Securities Exchange Act of 1934, as amended. Although the Company
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 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 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
disposals of businesses or 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 counterparties to
meet their obligations with respect to the Company's financial instruments,
(xii) changes in technology used and services offered by the Company, 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 the Company 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 the
Company 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
MERGERS AND ACQUISITIONS
Certain comparisons in this Annual Report 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.
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.
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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 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:
<TABLE>
<CAPTION>
1997 1998 1999 2000
---------- ---------- ---------- ----------
THOUSANDS OF DOLLARS
<S> <C> <C> <C> <C>
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 reacquisitions 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
========== ========== ========== ==========
</TABLE>
For information concerning construction work contemplated by the System
Companies and the commitments with respect thereto, see Note 15 to the
Consolidated Financial Statements.
In 1997, the Company bought ENSERCH for $579 million and LCC for $319
million primarily through the issuance of common stock.
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 Texas Utilities
Electric Company (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.
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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:
<TABLE>
<CAPTION>
PRINCIPAL CURRENT
DESCRIPTION AMOUNT INTEREST RATES MATURITY
----------- ---------- -------------- --------
Thousands of Dollars
<S> <C> <C> <C>
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
==========
</TABLE>
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.)
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.
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Interest Rate Market Risk - The table below provides information concerning
the Company'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 has
entered into interest rate swaps under which it has agreed to exchange the
difference between fixed-rate and variable-rate interest amounts calculated with
reference to 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 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.
<TABLE>
<CAPTION>
Expected Maturity Date
------------------------------------------------
1998 1999 2000 2001
--------- --------- --------- ---------
Millions of Dollars
<S> <C> <C> <C> <C>
Long-term Debt (including current maturities)
Fixed Rate ($US) ........................ $ 772.1 $ 504.7 $ 868.5 $ 344.4
Average interest rate ................ 7.18% 8.38% 6.61% 8.00%
Variable Rate ($US) ..................... -- -- $ 990.4 --
Average interest rate ................ -- -- 6.18% --
Interest Rate Swaps (notional amounts)
Variable to Fixed ($US) .................. $ 16.3 $ 110.5 $ 32.5 --
Average pay rate ..................... 5.29% 6.68% 6.14% --
Average receive rate .................. 5.08% 4.89% 4.89% --
Fixed to Variable ($US) ................. -- -- -- --
Average pay rate ..................... -- -- -- --
Average receive rate ................. -- -- -- --
<CAPTION>
Expected Maturity Date
-----------------------------------------------------
There- Fair
2002 after Total Value
--------- ----------- ----------- ----------
Millions of Dollars
<S> <C> <C> <C> <C>
Long-term Debt (including current maturities)
Fixed Rate ($US) ........................ $ 595.1 $ 4,446.2 $ 7,531.0 $ 7,931.7
Average interest rate ................ 7.53% 7.54% 7.47% --
Variable Rate ($US) ..................... -- $ 1,010.1 $ 2,000.5 $ 2,000.5
Average interest rate ................ -- 4.83% 5.50% --
Interest Rate Swaps (notional amounts)
Variable to Fixed ($US) .................. $ 468.2 $ 100.0 $ 727.5 $ (57.0)
Average pay rate ..................... 8.45% 7.18% 7.83% --
Average receive rate .................. 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% --
</TABLE>
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.
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.
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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.
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 Annual
Report, that 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 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 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 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 the Company for 1998 is an $8.52 million deficit,
which, in the opinion of the Company, is not expected to have a material effect
on its financial position, results of operation or cash flows.
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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 removal 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 RECONCILIATION PROCEEDINGS - 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.
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.
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.
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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 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 Public Utility Regulatory Policy Act of
1978 (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 stranded cost recovery. The
PUC's 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 anticipates 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
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
-7-
<PAGE> 10
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 1996 attributable to Eastern Energy). Operation and maintenance expense
increased in 1997 as result of recording third party transmission expenses in
accordance with the Public Utility Commission'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).)
CHANGES IN ACCOUNTING STANDARDS
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.
-8-
<PAGE> 11
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 is currently
determining its 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.
-9-
<PAGE> 12
INDEPENDENT AUDITORS' REPORT
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 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
-10-
<PAGE> 13
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1997 1996 1995
----------- ----------- -----------
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
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
</TABLE>
See Notes to Consolidated Financial Statements.
-11-
<PAGE> 14
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1997 1996 1995
----------- ----------- -----------
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
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
=========== =========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
-12-
<PAGE> 15
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1997 1996
------------ ------------
THOUSANDS OF DOLLARS
<S> <C> <C>
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
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
-13-
<PAGE> 16
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
CAPITALIZATION AND LIABILITIES
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
1997 1996
------------ ------------
THOUSANDS OF DOLLARS
<S> <C> <C>
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
============ ============
</TABLE>
See Notes to Consolidated Financial Statements.
-14-
<PAGE> 17
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------
1997 1996 1995
----------- ----------- -----------
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
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
=========== =========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
-15-
<PAGE> 18
TEXAS UTILITIES COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. BUSINESS, MERGERS AND ACQUISITIONS
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 Statements 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 1.3
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
stock holders 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. 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
-16-
<PAGE> 19
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 operations
assuming the ENSERCH and LCC acquisitions had occurred at the beginning of the
periods presented:
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------
1997 1996
---------- ----------
Thousands of dollars
<S> <C> <C>
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
</TABLE>
2. SIGNIFICANT ACCOUNTING POLICIES
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.
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 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. 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.
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.
-17-
<PAGE> 20
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% 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.)
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.)
-18-
<PAGE> 21
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
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 cash payments and noncash
investing and financing activities:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------------
1997 1996 1995
----------- ----------- -----------
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
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
=========== =========== ===========
</TABLE>
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
-19-
<PAGE> 22
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 of the System Companies are as follows:
<TABLE>
<CAPTION>
DECEMBER 31,
------------------------------
ITEM 1997 1996
---- ----------- ------------
THOUSANDS OF DOLLARS
<S> <C> <C>
Securities reacquisition costs .............. $ 397,488 $ 396,335
Canceled lignite unit costs ................. 9,208 12,322
Rate case costs ............................. 56,637 59,444
Litigation and settlement costs ............. 72,685 72,685
Voluntary retirement/severance program ...... 100,337 128,337
Recoverable deferred income taxes - net ..... 1,249,338 1,167,922
Other regulatory assets (liabilities) ....... 40,008 (10,942)
----------- -----------
Unamortized regulatory assets ........... 1,925,701 1,826,103
Reserve for regulatory disallowances ....... (72,685) (72,685)
Unamortized investment tax credits .......... (570,283) (589,713)
----------- -----------
Unamortized regulatory assets-- net ..... $ 1,282,733 $ 1,163,705
=========== ===========
</TABLE>
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 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 has 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.
3. SHORT-TERM FINANCING
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 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.
-20-
<PAGE> 23
4. COMMON STOCK
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 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 3/8% 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.
5. DIVIDEND RESTRICTIONS OF SUBSIDIARIES
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.
-21-
<PAGE> 24
6. PREFERRED STOCK OF SUBSIDIARIES
<TABLE>
<CAPTION>
REDEMPTION PRICE PER SHARE
(BEFORE ADDING ACCUMULATED DIVIDENDS)
SHARES OUTSTANDING AMOUNT ------------------------------------
DIVIDEND RATE DECEMBER 31, DECEMBER 31, DECEMBER 31,1997 EVENTUAL MINIMUM
------------- ----------------- --------------------- ---------------- ----------------
1997 1996 1997 1996
------ ------- --------- --------
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)
- --------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
$ 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
========= ========= ========= ========
</TABLE>
- ----------------
(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.
<TABLE>
<CAPTION>
MINIMUM REDEEMABLE INITIAL/NEXT DATE OF
SERIES SHARES MANDATORY REDEMPTION
------ ------ --------------------
<S> <C> <C>
$ 6.98 50,000 annually July 1, 2003
6.375 50,000 annually October 1, 2003
</TABLE>
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.
-22-
<PAGE> 25
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, at 100% of their
principal amount plus accrued interest, after an initial period during which
they may not be redeemed and at any time upon the occurrence of certain events.
The carrying value of the 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:
<TABLE>
<CAPTION>
PREFERRED SECURITIES TRUST ASSETS
------------------------------------------------- -----------------------
UNITS OUTSTANDING AMOUNT AMOUNT
DECEMBER 31, DECEMBER 31, DECEMBER 31,
----------------------- ----------------------- -----------------------
1997 1996 1997 1996 1997 1996
---------- ---------- ---------- ---------- ---------- ----------
COMPANY THOUSANDS OF DOLLARS
- -------
<S> <C> <C> <C> <C> <C> <C>
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
========== ========== ========== ========== ========== ==========
</TABLE>
(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.
-23-
<PAGE> 26
8. LONG-TERM DEBT, LESS AMOUNTS DUE CURRENTLY
<TABLE>
<CAPTION>
INTEREST SERIES DECEMBER 31,
RATE DUE ---------------------
---- --- 1997 1996
---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
First mortgage bonds:
5-1/2% series due 1998 ................... $ -- $125,000
5-3/4% series due 1998 ................... -- 150,000
5-7/8% series due 1998 ................... -- 175,000
6-1/2% series due 1998 ................... -- 1,065
7-3/8% series due 1999 ................... 100,000 100,000
Floating rate series due 1999 ............ -- 300,000
9-1/2% series due 1999 ................... 200,000 200,000
7-3/8% series due 2001 ................... 150,000 150,000
7.95 % series due 2002 ................... 888 900
8 % series due 2002 ................... 147,000 147,000
8-1/8% series due 2002 ................... 150,000 150,000
6-3/4% series due 2003 ................... 200,000 200,000
6-3/4% series due 2003 ................... 100,000 100,000
6-1/4% series due 2004 ................... 125,000 125,000
8-1/4% series due 2004 ................... 100,000 100,000
6-3/4% series due 2005 ................... 100,000 100,000
10.44% series due 2008 ................... 3,000 3,000
9-3/4% series due 2021 ................... 135,855 280,855
8-7/8% series due 2022 ................... 125,000 175,000
9 % series due 2022 ................... -- 100,000
7-7/8% series due 2023 ................... 300,000 300,000
8-3/4% series due 2023 ................... 135,550 195,550
7-7/8% series due 2024 ................... 225,000 225,000
8-1/2% series due 2024 ................... 113,000 163,000
7-3/8% series due 2025 ................... 208,000 208,000
7-5/8% series due 2025 ................... 250,000 250,000
Pollution control series:
Brazos River Authority
7-7/8% series due 2017 ................... -- 81,305
9-7/8% series due 2017 ................... -- 28,765
9-1/4% series due 2018 ................... 54,005 54,005
8-1/4% series due 2019 ................... 100,000 100,000
8-1/8% series due 2020 ................... 50,000 50,000
7-7/8% series due 2021 ................... 100,000 100,000
Taxable series due 2021 (5.86%) (a) ...... 40,895 65,940
5-1/2% series due 2022 ................... 50,000 50,000
6-5/8% series due 2022 ................... 33,000 33,000
6.70 % series due 2022 ................... 16,935 16,935
6-3/4% series due 2022 ................... 50,000 50,000
Series 1997D due 2022 (3.75%) (c) ........ 28,765 --
Taxable series due 2023 (5.85%) (a) ...... 100,000 100,000
6.05 % series due 2025 ................... 90,000 90,000
Series 1996A due 2026 (5.10%) (c) ........ 25,060 25,060
6-1/2% series due 2027 ................... 46,660 46,660
6.10 % series due 2028 ................... 50,000 50,000
Series 1994A due 2029 (3.75% to 3.85%) (b) 39,170 39,170
Series 1994B due 2029 (3.75% to 3.80%) (b) 39,170 39,170
Series 1995A due 2030 (5.10%) (c) ........ 50,670 50,670
Series 1995B due 2030 (4.60%) (c) ........ 118,355 118,355
Series 1995C due 2030 (5.10%) (c) ........ 118,355 118,355
Series 1996B due 2030 (4.60%) (c) ........ 61,215 61,215
Series 1996C due 2030 (5.10%) (c) ........ 50,000 50,000
Series 1997A due 2032 (5.10%) (c) ........ 50,000 --
Series 1997B due 2032 (4.95%) (c) ........ 31,305 --
Series 1997C due 2032 (5.10%) (c) ........ 25,045 --
Sabine River Authority of Texas
9 % series due 2007 ................... -- 51,525
8-1/8% series due 2020 ................... 40,000 40,000
8-1/4% series due 2020 ................... 11,000 11,000
</TABLE>
-24-
<PAGE> 27
<TABLE>
<CAPTION>
INTEREST SERIES DECEMBER 31,
RATE DUE -------------------------
---- --- 1997 1996
---- ----
THOUSANDS OF DOLLARS
<S> <C> <C>
Sabine River Authority of Texas (continued)
5.55 % series due 2022 ............................. $ 75,000 $ 75,000
6.55 % series due 2022 ............................. 40,000 40,000
5.85 % series due 2022 ............................. 33,465 33,465
Series 1997A due 2022 (3.70%) (c) .................. 51,525 --
Series 1996A due 2026 (5.10%) (c) .................. 57,950 57,950
Series 1996B due 2026 (5.10%) (c) .................. 25,000 25,000
Series 1995A due 2030 (5.20%) (c) .................. 16,000 16,000
Series 1995B due 2030 (4.50%) (c) .................. 12,050 12,050
Series 1995C due 2030 (4.60%) (c) .................. 18,475 18,475
Trinity River Authority of Texas
9% series due 2007 .................................. -- 12,000
Series 1997A due 2022 (3.75%) (c) ................... 12,000 --
Series 1996A due 2026 (5.10%) (c) .................. 25,000 25,000
Series 1997B due 2032 (5.95%) (c) ................... 14,075 --
Secured medium-term notes, series A .................... 30,000 30,000
Secured medium-term notes, series B .................... 114,200 114,200
Secured medium-term notes, series D .................... 201,150 201,150
----------- -----------
Total first mortgage bonds ....................... 5,063,788 6,205,790
General obligation bonds .................................. 9,646 10,000
Debt assumed for purchase of utility plant (d) ............ 153,537 156,182
TU Electric 7.17% Senior Debentures due 2007 .............. 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)
----------- -----------
Total long-term debt, less amounts
due currently ......................... $ 8,759,379 $ 8,668,111
=========== ===========
</TABLE>
- -------------------------
(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.
-25-
<PAGE> 28
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:
<TABLE>
<CAPTION>
SINKING MINIMUM CASH
YEAR FUND MATURITY REQUIREMENT
- ---- ---------- ---------- ----------
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
1998 .......... $ 20,994 $ 751,077 $ 772,071
1999 .......... 24,680 480,012 504,692
2000 .......... 261,040 1,597,891 1,858,931
2001 .......... 22,415 322,012 344,427
2002 .......... 8,546 586,602 595,148
</TABLE>
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 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, 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.
-26-
<PAGE> 29
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:
<TABLE>
<CAPTION>
Assets Liabilities Net
------ ----------- ---------
Thousands of Dollars
<S> <C> <C> <C>
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
========
</TABLE>
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.
-27-
<PAGE> 30
10. INCOME TAXES
The components of the Company's provision for income taxes (benefit)
are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------
1997 1996 1995
--------- --------- ---------
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
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)
========= ========= =========
</TABLE>
Reconciliation of income taxes (benefit) computed at the federal statutory
rate to provision for income taxes (benefit).
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1997 1996 1995
----------- ----------- -----------
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
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%
</TABLE>
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.
-28-
<PAGE> 31
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:
<TABLE>
<CAPTION>
DECEMBER 31,
----------------------------------------------------------------------------
1997 1996
------------------------------------ -------------------------------------
NON NON
TOTAL CURRENT CURRENT TOTAL CURRENT CURRENT
---------- ---------- ---------- ---------- ---------- ----------
THOUSAND OF DOLLARS
DEFERRED TAX ASSETS:
<S> <C> <C> <C> <C> <C> <C>
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
========== ========== ========== ========== ========== ==========
</TABLE>
-29-
<PAGE> 32
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.
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.
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.
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.
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<PAGE> 33
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------------
1997 1996 1995
---------- ---------- ----------
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
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
Interest cost on projected benefit obligation .............. 92,121 75,501 65,675
Actual return on plan assets ............................... (299,800) (183,390) (241,887)
Net amortization and deferral .............................. 190,203 97,988 160,198
---------- ---------- ----------
Net periodic pension cost ............................. $ 19,236 $ 26,878 $ 7,501
========== ========== ==========
Valuation Assumptions:
Discount rate .............................................. 7.25% 7.75% 7.25%
Rate of increase in compensation levels .................... 4.3% 4.3% 4.3%
Expected long-term rate of return .......................... 9.0% 9.0% 9.0%
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31,
--------------------------
1997 1996
----------- -----------
<S> <C> <C>
Amounts Recognized:
Actuarial present value of accumulated benefits:
Accumulated benefit obligation (including vested benefits
of $1,264,450,000 for 1997 and $823,918,000
for 1996) .................................................... $(1,337,120) $ (889,057)
=========== ===========
Projected benefit obligation for service
rendered to date ............................................ $(1,546,854 $(1,065,396)
Plan assets at fair value -- primarily equity investments,
government bonds and corporate bonds ............................ 1,790,715 1,296,025
----------- -----------
Plan assets in excess of projected benefit obligation ................ 243,861 230,629
Unrecognized net gain from past experience different
from that assumed and effects of changes
in assumptions .................................................. (422,503) (350,295)
Prior service cost not yet recognized in net periodic
pension expense .................................................. 31,574 41,566
Unrecognized plan assets in excess of projected
benefit obligation at initial application ....................... (4,700) (5,708)
----------- -----------
Accrued pension cost ............................................. $ (151,768) $ (83,808)
=========== ===========
</TABLE>
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.
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.
-31-
<PAGE> 34
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
----------------------------------
1997 1996 1995
-------- -------- --------
THOUSANDS OF DOLLARS
<S> <C> <C> <C>
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
Interest cost on the accumulated postretirement benefit obligation .................. 43,057 40,809 38,842
Amortization of the transition obligation ........................................... 16,953 16,978 16,978
Actual return on plan assets ........................................................ (13,260) (7,079) (6,096)
Net amortization and deferral ....................................................... 7,015 8,303 4,646
-------- -------- --------
Net postretirement benefits cost ................................................ $ 65,849 $ 72,524 $ 64,141
======== ======== ========
Valuation assumption:
Discount rate ....................................................................... 7.25% 7.75% 7.25%
Medical cost trend rate ............................................................. 5.0% 5.0% 5.0%
</TABLE>
<TABLE>
<CAPTION>
DECEMBER 31
----------------------
1997 1996
--------- ---------
<S> <C> <C>
Amounts Recognized:
Accumulated postretirement benefit obligation (APBO):
Retirees ................................................ $(412,919) $(325,672)
Fully eligible active employees ......................... (40,901) (38,320)
Other active employees .................................. (137,033) (187,451)
--------- ---------
Total APBO .......................................... (590,853) (551,443)
Plan assets at fair value .................................. 111,799 81,480
--------- ---------
APBO in excess of plan assets ....................... (479,054) (469,963)
Unrecognized net loss ...................................... 67,023 92,589
Unrecognized prior service cost ............................ 18,557 819
Unrecognized transition obligation ......................... 162,359 271,649
--------- ---------
Accrued postretirement benefits cost ................ $(231,115) $(104,906)
========= =========
</TABLE>
The expected increase in costs of future benefits covered by the plan is
projected using a health care cost trend rate of 5.0% 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 $65.9
million for the System Companies, and other postretirement benefits cost for
1997 by approximately $9.8 million.
12. SALES OF ACCOUNTS RECEIVABLE
The Company has facilities with financial institutions whereby it is
entitled to sell and such financial institutions may purchase, on an ongoing
basis, undivided interests in customer accounts receivable representing up to an
aggregate of $450,000,000 , including $100,000,000 related to ENSERCH in 1997.
Additional receivables are continually sold to replace those collected. At
December 31, 1997 and 1996, accounts receivable was reduced by $400,000,000 and
$300,000,000 , respectively, to reflect the sales of such receivables to
financial institutions under such agreements.
13. REGULATION AND RATES
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 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.
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<PAGE> 35
In its decision, the Supreme Court also affirmed the previous $472
million prudence disallowance related to Comanche Peak. Since the Company 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 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 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 removal 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.
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
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<PAGE> 36
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.
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
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<PAGE> 37
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.
-35-
<PAGE> 38
14. IMPAIRMENT OF ASSETS
In September 1995, the Company 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). The
Company has 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. Expenditures for 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.
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
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.
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.
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<PAGE> 39
Assuming operating standards are achieved, future capacity payments
under the agreements are estimated as follows:
<TABLE>
<CAPTION>
YEARS THOUSANDS OF DOLLARS
- ----- --------------------
<S> <C>
1998....................................................... $ 248,168
1999....................................................... 220,281
2000....................................................... 168,961
2001....................................................... 139,039
2002....................................................... 106,745
Thereafter................................................. 140,345
----------
Total capacity payments................................ $1,023,539
==========
</TABLE>
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.
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:
<TABLE>
<CAPTION>
YEARS THOUSANDS OF DOLLARS
- ----- --------------------
<S> <C>
1998....................................................... $ 83,729
1999....................................................... 73,024
2000....................................................... 64,161
2001....................................................... 96,387
2002....................................................... 55,428
Thereafter................................................. 546,148
--------
Total minimum lease commitments.......................... $918,877
========
</TABLE>
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
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.
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.)
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
-37-
<PAGE> 40
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 NML's and/or NEIL's losses under this type of insurance for major
incidents at nuclear plants participating in these programs exceed the
respective 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 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.
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.
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.
-38-
<PAGE> 41
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.
GENERAL
In addition to the above, the Company and System Companies are involved in
various legal and administrative proceedings which, in the opinion of the
Company, should not have a material effect upon its financial position, results
of operation or cash flows.
16. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and related estimated fair values of the Company's
significant financial instruments at December 31, 1997 and 1996, are as follows:
<TABLE>
<CAPTION>
DECEMBER 31, 1997 DECEMBER 31, 1996
--------------------------- ---------------------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
------------ ------------ ------------ ------------
THOUSANDS OF DOLLARS
<S> <C> <C> <C> <C>
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)
</TABLE>
*The foreign currency swap is a hedge of a foreign currency transaction. (See
Note 8.)
-39-
<PAGE> 42
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.
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, 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.
For additional information regarding the charges for regulatory disallowances,
see Note 13.
<TABLE>
<CAPTION>
BASIC
EARNINGS
NET PER SHARE OF
OPERATING REVENUES OPERATING INCOME INCOME COMMON STOCK*
----------------------- ----------------------- ----------------------- ------------------------
QUARTER ENDED 1997 1996 1997 1996 1997 1996 1997 1996
- ------------- ---------- ---------- ---------- ---------- ---------- ---------- ---------- ---------
THOUSANDS OF DOLLARS (EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C> <C>
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
========== ========== ========== ========== =========== ===========
</TABLE>
- -------------
* The sum of the quarters may not equal annual earnings per share due to
rounding. Diluted earnings per share for all quarters are 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.
-40-
<PAGE> 43
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
Texas Utilities Company and Subsidiaries
Date: February 26, 1998 By: /s/ J. W. Pinkerton
---------------------------------------
J. W. Pinkerton
Controller
-41-
<PAGE> 44
INDEX TO EXHIBITS
EXHIBIT NO. DESCRIPTION
- ----------- -----------
23 CONSENT OF DELOITTE AND TOUCHE
27 FINANCIAL DATA SCHEDULE
<PAGE> 1
EXHIBIT 23
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in Registration Statements
No. 333-55931 and 333-32831 on Form S-3, in Registration Statement
No. 333-45999 on Form S-4, and in Registration Statements No. 333-32831,
333-32833, 333-32835, 333-32837, 333-32839, 333-32841, 333-32843 and 333-45657
on Form S-8 of Texas Utilities Company of our report dated February 24, 1998,
appearing in this Current Report on Form 8-K dated February 26, 1998.
DELOITTE & TOUCHE LLP
Dallas, Texas
February 26, 1998
<TABLE> <S> <C>
<ARTICLE> UT
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1997
<PERIOD-START> JAN-01-1997
<PERIOD-END> DEC-31-1997
<BOOK-VALUE> PER-BOOK
<TOTAL-NET-UTILITY-PLANT> 18,571,030
<OTHER-PROPERTY-AND-INVEST> 2,274,740
<TOTAL-CURRENT-ASSETS> 1,994,848
<TOTAL-DEFERRED-CHARGES> 2,033,511
<OTHER-ASSETS> 0
<TOTAL-ASSETS> 24,878,129
<COMMON> 5,587,200
<CAPITAL-SURPLUS-PAID-IN> 0
<RETAINED-EARNINGS> 1,311,875
<TOTAL-COMMON-STOCKHOLDERS-EQ> 6,843,062
895,746
304,194
<LONG-TERM-DEBT-NET> 8,759,379
<SHORT-TERM-NOTES> 44,442
<LONG-TERM-NOTES-PAYABLE> 0
<COMMERCIAL-PAPER-OBLIGATIONS> 570,000
<LONG-TERM-DEBT-CURRENT-PORT> 772,071
0
<CAPITAL-LEASE-OBLIGATIONS> 0
<LEASES-CURRENT> 0
<OTHER-ITEMS-CAPITAL-AND-LIAB> 6,685,235
<TOT-CAPITALIZATION-AND-LIAB> 24,874,129
<GROSS-OPERATING-REVENUE> 7,945,608
<INCOME-TAX-EXPENSE> 376,898
<OTHER-OPERATING-EXPENSES> 6,038,937
<TOTAL-OPERATING-EXPENSES> 6,038,937
<OPERATING-INCOME-LOSS> 1,906,671
<OTHER-INCOME-NET> (17,588)
<INCOME-BEFORE-INTEREST-EXPEN> 1,889,083
<TOTAL-INTEREST-EXPENSE> 851,731
<NET-INCOME> 660,454
0
<EARNINGS-AVAILABLE-FOR-COMM> 660,454
<COMMON-STOCK-DIVIDENDS> 478,592
<TOTAL-INTEREST-ON-BONDS> 439,539
<CASH-FLOW-OPERATIONS> 1,659,118
<EPS-PRIMARY> 2.86
<EPS-DILUTED> 2.85
</TABLE>
