==============================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-Q
( X ) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003
-- OR --
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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Commission File Number 1-12833
TXU Corp.
A Texas Corporation I.R.S. Employer Identification
No. 75-2669310
ENERGY PLAZA, 1601 BRYAN STREET, DALLAS, TEXAS 75201-3411
(214) 812-4600
---------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
--- ---
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes X No
--- ---
Common Stock outstanding at August 8, 2003: 321,995,885 shares, without par
value.
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TABLE OF CONTENTS
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PAGE
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Glossary .......................................................................................... ii
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Statements of Consolidated Income -
Three and Six Months Ended June 30, 2003 and 2002.............................. 1
Condensed Statements of Consolidated Comprehensive Income -
Three and Six Months Ended June 30, 2003 and 2002............................. 2
Condensed Statements of Consolidated Cash Flows -
Six Months Ended June 30, 2003 and 2002........................................ 3
Condensed Consolidated Balance Sheets -
June 30, 2003 and December 31, 2002............................................ 4
Notes to Financial Statements.................................................. 5
Independent Accountants' Report................................................ 30
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations..................................................... 31
Item 3. Quantitative and Qualitative Disclosures About Market Risk.................... 70
Item 4. Controls and Procedures....................................................... 73
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................................. 73
Item 4. Submission of Matters to a Vote of Security Holders .......................... 75
Item 6. Exhibits and Reports on Form 8-K ............................................. 76
SIGNATURE........................................................................................... 77
Periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K that
contain financial information of TXU Corp. and its subsidiaries are made
available to the public, free of charge, on the TXU Corp. website at
http://www.txucorp.com, shortly after they have been filed with the Securities
and Exchange Commission. TXU Corp. will provide copies of current reports not
posted on the website upon request.
i
GLOSSARY
When the following terms and abbreviations appear in the text of this report,
they have the meanings indicated below.
1999 Restructuring Legislation........Legislation that restructured the electric
utility industry in Texas to provide for
competition
2002 Form 10-K........................TXU Corp.'s Annual Report on Form 10-K for
the year ended December 31, 2002
Commission............................Public Utility Commission of Texas
EITF..................................Emerging Issues Task Force
EITF 98-10 ...........................EITF Issue No. 98-10, "Accounting for
Contracts Involved in Energy Trading and
Risk Management Activities"
EITF 01-8.............................EITF Issue No. 01-8, "Determining Whether
an Arrangement Contains a Lease"
EITF 02-3 ............................EITF Issue No. 02-3, "Issues Involved in
Accounting for Derivative Contracts
Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk
Management Activities"
ERCOT.................................Electric Reliability Council of Texas
FIN...................................Financial Accounting Standards Board
Interpretation
FIN 45................................FIN No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees,
Including Indirect Guarantees of
Indebtedness of Others - an
Interpretation of FASB Statements No. 5,
57, and 107 and Rescission of FIN No. 34"
FIN 46................................FIN No. 46, "Consolidation of Variable
Interest Entities"
Fitch.................................Fitch Ratings, Ltd.
GWh...................................gigawatt-hours
IRS...................................Internal Revenue Service
Moody's...............................Moody's Investors Services, Inc.
NRC...................................United States Nuclear Regulatory
Commission
Oncor.................................Oncor Electric Delivery Company
Pinnacle..............................Pinnacle One Partners, L.P., the
telecommunications business reported as
discontinued operations and formerly
a joint venture
POLR..................................provider of last resort
REPs..................................retail electric providers
RRC...................................Railroad Commission of Texas
S&P...................................Standard & Poor's, a division of the
McGraw Hill Companies
Sarbanes-Oxley........................Sarbanes -Oxley Act of 2002
SEC...................................United States Securities and Exchange
Commission
Settlement............................regulatory settlement agreed to by the
Commission in 2002
Settlement Plan.......................regulatory settlement plan filed with the
Commission in December 2001
SFAS..................................Statement of Financial Accounting
Standards
SFAS 123..............................SFAS No. 123, "Accounting for Stock-Based
Compensation"
ii
SFAS 133..............................SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities"
SFAS 143..............................SFAS No. 143, "Accounting for Asset
Retirement Obligations"
SFAS 145..............................SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment
of FASB Statement 13, and Technical
Corrections"
SFAS 146..............................SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal
Activities"
SFAS 148..............................SFAS No. 148, "Accounting for Stock-Based
Compensation-- Transition and Disclosure"
SFAS 149..............................SFAS No. 149, "Amendment of Statement 133
on Derivative Instruments and
Hedging Activities"
SFAS 150..............................SFAS No. 150, "Accounting for Certain
Financial Instruments with
Characteristics of both Liabilities
and Equity"
SG&A..................................selling, general and administrative
T&D...................................transmission and distribution
TXU Australia.........................TXU Australia Holdings (Partnership)
Limited Partnership
TXU Corp..............................refers to TXU Corp. or TXU Corp. and its
consolidated subsidiaries, depending on
context
TXU Energy............................TXU Energy Company LLC
TXU Europe............................TXU Europe Limited
TXU Fuel..............................TXU Fuel Company
TXU Gas...............................TXU Gas Company
TXU Mining............................TXU Mining Company LP
TXU Portfolio Management..............TXU Portfolio Management Company LP
US....................................United States of America
US GAAP...............................accounting principles generally accepted
in the US
US Holdings...........................TXU US Holdings Company
iii
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
TXU CORP. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ------------------
2003 2002 2003 2002
-------- -------- ------- ------
(millions of dollars, except per share amounts)
Operating revenues................................................... $2,672 $2,505 $5,471 $4,958
------ ------ ----- ------
Costs and expenses:
Cost of energy sold and delivery fees............................. 1,176 983 2,563 1,783
Operating costs.................................................. 426 402 851 767
Depreciation and amortization..................................... 208 213 432 433
Selling, general and administrative expenses...................... 269 330 516 668
Franchise and revenue-based taxes................................. 120 117 231 235
Other income...................................................... (23) (19) (34) (26)
Other deductions.................................................. 7 12 24 59
Interest income................................................... (10) (7) (19) (15)
Interest expense and other charges................................ 248 217 496 433
----- ----- ----- -----
Total costs and expenses...................................... 2,421 2,248 5,060 4,337
----- ----- ----- -----
Income from continuing operations before income taxes and cumulative effect
of changes in accounting principles.............................. 251 257 411 621
Income tax expense................................................... 74 79 118 186
----- ----- ----- -----
Income from continuing operations before cumulative effect
of changes in accounting principles............................... 177 178 293 435
Income (loss) on discontinued operations, net of tax effect (Note 3). (66) 23 (79) 21
Cumulative effect of changes in accounting principles, net of tax benefit
(Note 2).......................................................... - - (58) -
----- ----- ----- -----
Net income .......................................................... 111 201 156 456
Preference stock dividends........................................... 6 6 11 11
----- ----- ----- -----
Net income available for common stock................................ $ 105 $ 195 $ 145 $ 445
===== ===== ===== =====
Average shares of common stock outstanding (millions):
Basic............................................................. 321 269 321 267
Diluted........................................................... 378 269 378 267
Per share of common stock:
Basic earnings:
Income from continuing operations before cumulative effect of
changes in accounting principles.............................. $ .54 $ .64 $ .88 $ 1.59
Income (loss) on discontinued operations, net of tax effect..... (.21) .09 (.25) .08
Cumulative effect of changes in accounting principles,
net of tax benefit............................................ - - (.18) -
Net income available for common stock........................... .33 .73 .45 1.67
Diluted earnings:
Income from continuing operations before cumulative effect of
changes in accounting principles.............................. $ .49 $ .64 $ .82 $ 1.59
Income (loss) on discontinued operations, net of tax effect..... (.18) .09 (.22) .08
Cumulative effect of changes in accounting principles,
net of tax benefit............................................ - - (.15) -
Net income available for common stock........................... .31 .73 .45 1.67
Dividends declared............................................... .125 .600 .250 1.200
See Notes to Financial Statements.
1
TXU CORP. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
------------------- ------------------
2003 2002 2003 2002
---- ---- ---- ----
(millions of dollars)
Components related to continuing operations:
Income from continuing operations before cumulative effect
of changes in accounting principles................................... $ 177 $ 178 $ 293 $ 435
----- ----- ----- -----
Other comprehensive income (loss), net of tax effects:
Cumulative foreign currency translation adjustments.................... 106 42 161 73
Cash flow hedges-
Net change in fair value of derivatives (net of tax benefit
of $37, $46, $93 and $64).......................................... (76) (88) (184) (119)
Amounts realized in earnings during the period
(net of tax expense of $36, $12, $78 and $19)....................... 72 27 153 42
----- ----- ----- -----
Total............................................................. 102 (19) 130 (4)
----- ----- ----- -----
Comprehensive income from continuing operations.............................. 279 159 423 431
Comprehensive income from discontinued operations:
Income (loss) on discontinued operations, net of tax effect.............. (66) 23 (79) 21
Minimum pension liability adjustments (net of tax benefit of $3)......... - - (6) -
Cumulative foreign currency translation adjustment....................... - 238 - 177
Cash flow hedges (net of tax expense of $4 and $8)....................... - 9 - 19
----- ----- ----- -----
Total.............................................................. (66) 270 (85) 217
----- ----- ----- -----
Cumulative effect of changes in accounting principles, net of tax benefit..... - - (58) -
----- ----- ----- -----
Comprehensive income......................................................... $ 213 $ 429 $ 280 $ 648
===== ===== ===== =====
See Notes to Financial Statements.
2
TXU CORP. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
-----------------
2003 2002
---- ----
(millions of dollars)
Cash flows - operating activities:
Income from continuing operations before cumulative effect of
changes in accounting principles............................................. $ 293 $ 435
Adjustments to reconcile income from continuing operations before cumulative
effect of changes in accounting principles to cash provided by operating activities:
Depreciation and amortization ............................................... 470 467
Deferred income taxes and investment tax credits - net ...................... 87 (6)
Net gain from sale of assets................................................ (20) (13)
Net unrealized gain from mark-to-market valuations of commodity contracts.... (27) (6)
Net equity loss from unconsolidated affiliates and joint ventures............ 16 24
Recovery of gas costs........................................................ 34 67
Reduction in regulatory liability............................................ (78) (41)
Changes in operating assets and liabilities..................................... 667 (315)
------ -----
Cash provided by operating activities.................................... 1,442 612
------ -----
Cash flows - financing activities:
Issuances of securities:
Long-term debt............................................................... 1,317 1,846
Common stock................................................................. 8 605
Retirements/repurchases of securities:
Long-term debt............................................................... (761) (1,677)
Preferred stock of subsidiary, subject to mandatory redemption............... (4) -
Change in notes payable:
Commercial paper............................................................. 11 383
Banks........................................................................ (2,299) (517)
Cash dividends paid:
Common stock................................................................. (80) (318)
Preference stock............................................................. (11) (11)
Redemption deposit applied to debt retirements.................................. 210 -
Debt premium, discount, financing and reacquisition expenses.................... (53) (81)
------ -----
Cash provided by (used in) financing activities.......................... (1,662) 230
------ -----
Cash flows - investing activities:
Capital expenditures............................................................ (458) (502)
Acquisitions of businesses..................................................... (150) (36)
Proceeds from sale of assets................................................... 15 444
Nuclear fuel ................................................................... (35) (50)
Other........................................................................... 14 (43)
------ ------
Cash used in investing activities........................................ (614) (187)
------ -----
Effect of exchange rates on cash and cash equivalents............................. 8 (16)
Cash used by discontinued operations.............................................. (15) (595)
------ -----
Net change in cash and cash equivalents........................................... (841) 44
Cash and cash equivalents - beginning balance..................................... 1,574 216
------ -----
Cash and cash equivalents - ending balance........................................ $ 733 $ 260
====== =====
See Notes to Financial Statements.
3
TXU CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2003 2002
--------- -------
ASSETS (millions of dollars)
Current assets:
Cash and cash equivalents..................................................... $ 733 $ 1,574
Restricted cash............................................................... - 210
Accounts receivable-- trade................................................... 1,529 1,696
Income taxes receivable....................................................... 33 488
Inventories................................................................... 522 493
Commodity contract assets..................................................... 1,366 1,298
Assets of telecommunications holding company.................................. 145 -
Other current assets.......................................................... 233 263
------ ------
Total current assets................................................... 4,561 6,022
------ ------
Investments:
Restricted cash............................................................... 111 96
Other investments............................................................. 640 757
Property, plant and equipment-- net............................................. 20,467 19,642
Goodwill and other unamortized intangible assets................................ 1,723 1,588
Regulatory assets-- net........................................................ 1,880 1,772
Commodity contract assets....................................................... 646 657
Cash flow hedges and other derivative assets.................................... 160 150
Other noncurrent assets......................................................... 336 332
Telecommunications assets held for sale......................................... 670 -
------- -------
Total assets........................................................... $31,194 $31,016
======= =======
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Notes payable:
Commercial paper........................................................... $ 33 $ 18
Banks...................................................................... 8 2,306
Long-term debt due currently.................................................. 743 958
Accounts payable-- trade...................................................... 1,083 1,054
Commodity contract liabilities................................................ 1,198 1,138
Liabilities of telecommunications holding company............................. 854 -
Other current liabilities..................................................... 1,073 1,209
------ ------
Total current liabilities.............................................. 4,992 6,683
------ ------
Accumulated deferred income taxes and investment tax credits.................... 4,322 4,060
Commodity contract liabilities.................................................. 554 520
Cash flow hedges and other derivative liabilities............................... 363 220
Other noncurrent liabilities and deferred credits............................... 2,298 2,144
Long-term debt, less amounts due currently...................................... 12,563 11,597
Telecommunications liabilities held for sale.................................... 121 --
Mandatorily redeemable, preferred securities of subsidiary trusts, each holding
solely junior subordinated debentures of the obligated company:
TXU Corp. obligated........................................................ 368 368
Subsidiary obligated....................................................... 147 147
Preferred stock of subsidiaries:
Not subject to mandatory redemption........................................ 190 190
Subject to mandatory redemption............................................ 17 21
Contingencies (Note 7)
Shareholders' equity (Note 6)................................................... 5,259 5,066
------ ------
Total liabilities and shareholders' equity............................. $31,194 $31,016
======= =======
See Notes to Financial Statements.
4
TXU CORP. AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
1. SIGNIFICANT ACCOUNTING POLICIES
Description of Business -- TXU Corp. is an energy company that engages
in power production (electricity generation), wholesale energy sales, retail
energy sales and related services, portfolio management, including risk
management and certain trading activities, energy delivery and, through a
business held for sale and formerly a joint venture, telecommunications
services. TXU Corp. is a holding company with its US operations conducted
through US Holdings and TXU Gas. US Holdings is also a holding company with its
principal operations conducted through TXU Energy and Oncor. TXU Corp.'s
principal international operations are conducted through TXU Australia.
Discontinued Businesses - Prior to October 2002, TXU Corp. also
conducted international operations through TXU Europe. The consolidated
financial statements for 2002 and discussion of results of operations of TXU
Corp. reflect the reclassification of the TXU Europe business as discontinued
operations (see Note 3 for information about discontinued operations).
With respect to the telecommunications business, Pinnacle, in May
2003, TXU Corp. acquired for $150 million in cash the interests it did not
previously own from the joint venture partner under a put/call agreement, which
had been executed in late February 2003, and finalized a formal plan to dispose
of the telecommunications business by sale. Accordingly, effective with
reporting for the second quarter of 2003, activities of Pinnacle since March 1,
2003 are reported as discontinued operations. TXU Corp. had used the equity
method of accounting for its investment in Pinnacle until March 1, 2003 when the
business was consolidated as a result of the execution of the put/call
agreement. Accounting rules provide that businesses accounted for under the
equity method should not be reported as discontinued operations; therefore,
results prior to March 1, 2003 are reported in other deductions in the statement
of income, consistent with prior reporting. (Also see Note 3.)
Basis of Presentation -- The condensed consolidated financial
statements of TXU Corp. have been prepared in accordance with US GAAP and on the
same basis as the audited financial statements included in its 2002 Form 10-K,
except for the discontinuance of the telecommunications business and the
adoption of the following new accounting rules: EITF 02-3, SFAS 143, and SFAS
145, all discussed below.
In the opinion of management, all adjustments (consisting of normal
recurring accruals) necessary for a fair presentation of the results of
operations and financial position have been included therein. All intercompany
items and transactions have been eliminated in consolidation. Certain
information and footnote disclosures normally included in annual consolidated
financial statements prepared in accordance with US GAAP have been omitted
pursuant to the rules and regulations of the SEC. Because the consolidated
interim financial statements do not include all of the information and footnotes
required by US GAAP, they should be read in conjunction with the audited
financial statements and related notes included in the 2002 Form 10-K. The
results of operations for an interim period may not give a true indication of
results for a full year. All dollar amounts in the financial statements and
tables in the notes, except per share amounts, are stated in millions of US
dollars unless otherwise indicated. Certain previously reported amounts have
been reclassified to conform to current classifications.
Effective April 1, 2003, the estimates of the depreciable lives of the
Comanche Peak nuclear generating plant and several gas generation plants were
extended to better reflect the useful lives of the assets. At the same time,
depreciation rates were increased on lignite and gas generation facilities to
reflect investments in emissions control equipment. The net impact of these
changes was a reduction in depreciation expense of $13 million (pre-tax) and an
increase in income from continuing operations of $8 million ($0.02 per diluted
share) in the three- and six-month periods ended June 30, 2003.
5
Income Taxes -- TXU Energy and the holders of its 9% Exchangeable
Subordinated Notes due 2012 (which were converted on July 1, 2003 to preferred
membership interests in TXU Energy, see Note 4), characterize the notes as
preferred equity interests for federal and state income tax purposes with the
result that TXU Energy is treated as a partnership for such purposes.
Changes in Accounting Standards -- In October 2002, the EITF, through
EITF 02-3, rescinded EITF 98-10, which required mark-to-market accounting for
all trading activities. SFAS 143, regarding asset retirement obligations, became
effective on January 1, 2003. As a result of the implementation of these two
accounting standards, TXU Corp. recorded a cumulative effect of changes in
accounting principles as of January 1, 2003. (See Note 2 for a discussion of the
impacts of these two accounting standards.)
As a result of guidance provided in EITF 02-3, TXU Corp. has not
recognized origination gains on commercial/industrial retail contracts in 2003.
For the three- and six-month periods ended June 30, 2002, TXU Corp. had
recognized $21 million and $34 million in origination gains on such contracts,
respectively.
SFAS 145, regarding classification of items as extraordinary, became
effective on January 1, 2003. One of the provisions of this statement is the
rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of
Debt." As required by the standard, the results for the six months ended June
30, 2002 reflect a reclassification of a previously reported (in the first
quarter of 2002) extraordinary loss of $17 million (after-tax) on the early
extinguishment of debt to other deductions ($26 million) and income tax expense
($9 million), as the loss does not meet the criteria of an extraordinary item as
defined by Accounting Principles Board Opinion 30, "Reporting the Results of
Operations - Reporting the Effects of Disposal of a Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions."
As a result of the implementation of SFAS 145 as of January 1, 2003,
the previously reported after-tax losses on the early extinguishment of debt of
$41 million in the year ended December 31, 2002 and $97 million in the year
ended December 31, 2001 (as described in the Notes to Financial Statements in
the 2002 Form 10-K) will be reclassified from extraordinary items to other
deductions and income tax expense in income from continuing operations as such
losses do not meet the criteria of an extraordinary item. There is no effect on
net income as a result of the implementation of SFAS 145.
This reclassification decreases basic and fully diluted income from
continuing operations before extraordinary loss per share by $0.15 and $0.38 for
the years ended December 31, 2002 and 2001, respectively, and decreases the
extraordinary loss, per share, by the same amounts.
SFAS 146, regarding exit costs, became effective on January 1, 2003.
SFAS 146 requires that a liability for costs associated with an exit or disposal
activity be recognized only when the liability is incurred and measured
initially at fair value. The adoption of SFAS 146 did not materially impact
results of operations for the six months ended June 30, 2003.
SFAS 148 was issued in December 2002. TXU Corp. adopted the
disclosure requirements of SFAS 148 effective December 31, 2002. This statement
provides transition alternatives when companies adopt fair value accounting for
stock-based compensation. TXU Corp. accounts for certain of its stock-based
compensation plans, including stock options, using the intrinsic value method.
TXU Corp. does not currently issue stock options, and only approximately 26,000
previously issued options remain outstanding at June 30, 2003. Had compensation
expense for these stock-based compensation plans been determined based upon the
fair value methodology prescribed under SFAS 123, TXU Corp.'s net income and per
share amounts would not have been materially different from reported amounts.
FIN 45 requires recording the fair value of guarantees upon issuance
or modification after December 31, 2002. The interpretation also requires
expanded disclosures of guarantees (see Note 7 under Guarantees). The adoption
of FIN 45 did not materially impact results of operations for the six months
ended June 30, 2003.
FIN 46 was issued in January 2003. FIN 46 provides guidance related to
identifying variable interest entities and determining whether such entities
should be consolidated. This guidance will be effective for existing variable
interest entities in the quarter ending September 30, 2003 and immediately for
any new variable interest entities. TXU Corp. is evaluating the potential impact
of FIN 46 on its financial position.
6
SFAS 149 was issued in April 2003 and became effective for contracts
entered into or modified after June 30, 2003. SFAS 149 clarifies what contracts
may be eligible for the normal purchase and sale exception, the definition of a
derivative and the treatment in the statement of cash flows when a derivative
contains a financing component. TXU Corp. is evaluating the potential impact of
SFAS 149 on its financial position and results of operations.
SFAS 150 was issued in May 2003 and became effective June 1, 2003 for
new financial instruments and July 1, 2003 for existing financial instruments.
SFAS 150 requires that certain mandatorily redeemable preferred securities (see
Note 5) be classified as liabilities beginning July 1, 2003. TXU Corp. is
evaluating the potential impact of SFAS 150 on its financial position.
EITF 01-8 was issued in May 2003 and is effective prospectively for
arrangements that are new, modified or committed to beginning July 1, 2003. This
guidance may require that certain types of arrangements be accounted for as
leases, including tolling and power supply contracts, take-or-pay contracts and
service contracts involving the use of specific property and equipment. TXU
Corp. is evaluating the potential impact of the adoption of EITF 01-8 on its
financial position and results of operations.
Earnings Per Share -- Basic earnings per share applicable to common
stock are based on the weighted average number of common shares outstanding
during the quarter. Diluted earnings per share include the effect of all
potential issuances of common shares under certain debt securities and other
arrangements. For the three months and six months ended June 30, 2003, the $750
million of 9% Exchangeable Subordinated Notes issued by TXU Energy in November
2002 were dilutive and were included in the calculation of diluted earnings per
share. Assuming these securities were converted to common stock at the beginning
of the period at the exercise price of $13.1242 per share, 57.1 million more
shares would have been issued and net income would have increased by $13.2
million and $26.3 million for the three months and six months ended June 30,
2003, respectively, representing the after-tax interest savings on the notes.
Additional dilution of earnings per share would result from
approximately 7.0 million shares and 18.0 million shares of common stock
issuable in connection with equity-linked debt securities issued in 2002 and
2001, respectively, if the average of the closing price per share of TXU Corp.
common stock on each of the twenty consecutive trading days ending on the third
day immediately preceding the end of a reporting period is above the strike
price of $62.91 and $55.68 per share, for the respective issuances.
2. CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
The following summarizes the effect on results for the six months
ended June 30, 2003 for changes in accounting principles effective January 1,
2003:
Charge from rescission of EITF 98-10, net of tax effect of $34 million.... $(63)
Credit from adoption of SFAS 143, net of tax effect of $3 million......... 5
----
Total net charge............................................ $(58)
====
On October 25, 2002, the EITF, through EITF 02-3, rescinded EITF
98-10, which required mark-to-market accounting for all trading activities.
Pursuant to this rescission, only financial instruments that are derivatives
under SFAS 133 will be subject to mark-to-market accounting. Financial
instruments that may not be derivatives under SFAS 133, but were
marked-to-market under EITF 98-10, consist primarily of gas transportation and
storage agreements, power tolling, full requirements and capacity contracts.
This new accounting rule was effective for new contracts entered into after
October 25, 2002. Non-derivative contracts entered into prior to October 26,
2002, continued to be accounted for at fair value through December 31, 2002;
however, effective January 1, 2003, such contracts were required to be accounted
for on a settlement basis. Accordingly, a charge of $97 million ($63 million
after-tax) has been reported as a cumulative effect of a change in accounting
principles in the first quarter of 2003. Of the total, $75 million reduced net
commodity contract assets and liabilities and $22 million reduced inventory that
had previously been marked-to-market as a trading position. The cumulative
effect adjustment represents the net gains previously recognized for these
contracts under mark-to-market accounting.
7
SFAS 143 became effective on January 1, 2003. SFAS 143 requires
entities to record the fair value of a legal liability for an asset retirement
obligation in the period of its inception. For TXU Corp., such liabilities
relate to nuclear generation plant decommissioning, land reclamation related to
lignite mining and removal of lignite plant ash treatment facilities. The
liability is recorded at its net present value with a corresponding increase in
the carrying value of the related long-lived asset. The liability is accreted
each period, representing the time value of money, and the capitalized cost is
depreciated over the remaining useful life of the related asset.
As the new accounting rule required retrospective application to the
inception of the liability, the effects of the adoption reflect the accretion
and depreciation from the liability inception date through December 31, 2002.
Further, the effects of adoption take into consideration liabilities of $215
million (previously reflected in accumulated depreciation) TXU Corp. had
previously recorded as depreciation expense and $26 million (reflected in other
noncurrent liabilities) of unrealized net gains associated with the
decommissioning trusts.
The following table summarizes the impact as of January 1, 2003 of
adopting SFAS 143:
Increase in property, plant and equipment - net................ $488
Increase in other noncurrent liabilities and deferred credits.. (528)
Increase in accumulated deferred income taxes.................. (3)
Increase in regulatory assets - net............................ 48
----
Cumulative effect of change in accounting principles.... $ 5
====
The asset retirement liability at June 30, 2003 was $564 million,
comprised of a $554 million liability as a result of adoption of SFAS 143 and
$18 million of accretion during the first six months of 2003 reduced by $8
million in reclamation payments.
With respect to nuclear decommissioning costs, TXU Corp. believes
that the adoption of SFAS 143 results primarily in timing differences in the
recognition of asset retirement costs that TXU Energy is currently recovering,
as Oncor recovers regulated decommissioning fees from REPs on behalf of TXU
Energy, and will be deferring such differences as part of the regulatory
cost-recovery process.
On a pro forma basis, assuming SFAS 143 had been adopted at the
beginning of the periods, income from continuing operations for the six months
ended June 30, 2002 would have increased by $4 million after-tax and the
liability for asset retirement obligations as of June 30, 2002, would have been
$538 million.
8
3. DISCONTINUED OPERATIONS
The following summarizes the historical consolidated financial
information of TXU Europe and the telecommunications business reported as
discontinued operations:
Europe Telecommunications
--------------------------- --------------------------
Three Months Six Months Three Months Six Months
Ended Ended Ended Ended
June 30, 2002 June 30, 2002 June 30, 2003 June 30, 2003
------------- ------------- ------------- -------------
Operating revenues......................... $1,184 $2,694 $ 52 $ 68
------ ------ ------ ------
Operating costs and expenses............... 1,086 2,531 48 69
Other deductions-- net..................... 7 10 - 1
Interest income............................ (4) (10) (2) (3)
Interest expense and other charges......... 83 166 20 26
------ ----- ------ ------
Income (loss) before income taxes.......... 12 (3) (14) (25)
Income tax expense (benefit)............... (11) (24) 53 52
------ ----- ------ ------
Income (loss) from discontinued operations. $ 23 $ 21 $ (67) $ (77)
====== ===== ====== ======
The loss from the telecommunications business for the three and six
months ended June 30, 2003 includes a deferred income tax provision of $60
million on the excess of the carrying value of the investment in the business
over the tax basis.
Legal, audit and administrative accruals related to TXU Europe were
reduced by $1 million after-tax in the three months ended June 30, 2003,
resulting in a net year to date expense of $3 million ($2 million after-tax).
The following details the telecommunications assets and liabilities
held for sale on TXU Corp.'s balance sheet as of June 30, 2003:
Current assets....................................... $ 66
Investments.......................................... 36
Plant, property, and equipment....................... 231
Goodwill............................................. 317
Accumulated deferred income tax asset................ 16
Other noncurrent assets.............................. 4
------
Telecommunications assets held for sale....... $ 670
======
Current liabilities.................................. $ 72
Noncurrent liabilities............................... 49
------
Telecommunications liabilities held for sale. $ 121
======
The following details the assets and liabilities of the telecommunications
holding company on TXU Corp.'s balance sheet as of June 30, 2003:
Investments (a)...................................... $ 135
Other assets......................................... 10
------
Assets of telecommunications holding company..... $ 145
======
Notes payable and other debt (a)..................... $ 825
Other liabilities.................................... 29
------
Liabilities of telecommunications holding company $ 854
======
(a) Investments represents Pinnacle Overfund Trust, a trust established to
fund interest payments on $810 million in notes payable of the holding
company. The trust's assets consist of TXU Corp. debt (reported in
long-term debt due currently). Upon sale of the business, expected to
occur by June 30, 2004, the notes will be repaid and the remaining TXU
Corp. debt and the trust will be cancelled.
9
4. FINANCING ARRANGEMENTS
Credit Facilities -- At June 30, 2003, TXU Corp. had outstanding
short-term borrowings consisting of bank borrowings of approximately $8 million
and commercial paper of $33 million (all in Australia).
At June 30, 2003, TXU Corp. and its subsidiaries had credit
facilities (some of which provide for long-term borrowings) as follows:
At June 30, 2003
--------------------------------------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
- -------- --------------- --------- ----- ------ ---------- ------------
Five-Year Revolving Credit Facility February 2005 US Holdings $ 1,400 $ 391 $ -- $1,009
Revolving Credit Facility February 2005 TXU Energy, Oncor 450 21 -- 429
Three-Year Revolving Credit Facility May 2005 US Holdings 400 -- -- 400
Revolving Credit Facilities May 2005 TXU Corp. 100 -- -- 100
------- ------ ------ ------
Total North America $ 2,350 $ 412 $ -- $1,938
======= ====== ====== ======
Senior Facility (a) October 2004 TXU Australia $ 1,167 $ -- $ 943 $ 208
Working Capital Facility October 2003 TXU Australia 66 -- 6 60
Standby Facility (a) December 2003 TXU Australia 17 -- -- --
------- ------ ------ ------
Total Australia $ 1,250 $ -- $ 949 $ 268
======= ====== ====== ======
(a) Commercial paper borrowings totaling $33 million at June 30, 2003 were
supported by the Standby Facility ($17 million) and the Senior Facility
($16 million).
In August 2003, TXU Corp. entered into a $500 million 5-year
revolving credit facility with LOC 2003 Trust, a special purpose, wholly-owned
subsidiary of TXU Corp. (LOC Trust). LOC Trust, in turn, entered into a $500
million 5-year secured credit facility with a group of lenders. TXU Corp.
intends to capitalize LOC Trust with approximately $525 million of cash, which
will be invested by the lenders in permitted investments as directed by LOC
Trust. LOC Trust's assets, including the investments, will constitute collateral
for the benefit of the lenders to secure issuances of letters of credit or
loans, and will be owned by LOC Trust. During the term of the facility, LOC
Trust will be required to maintain collateral in an amount equal to 105% of the
commitments under the secured facility. Upon capitalization of LOC Trust, TXU
Corp. may request up to $500 million of letters of credit or up to $250 million
of loans from LOC Trust, subject in aggregate to its $500 million commitment,
for the benefit of TXU Corp. and its subsidiaries, which may be provided through
issuances of letters of credit or loans by the lenders. LOC Trust's assets are
not available to satisfy claims of creditors of TXU Corp. or its subsidiaries.
However, LOC Trust may terminate all or a portion of the secured facility at any
time and request the release of any collateral not required to secure
outstanding letters of credit from the lenders.
Through April 2003, $2.3 billion in outstanding cash borrowings as of
December 31, 2002 under the North America credit facilities were repaid, and the
facilities were restructured. A $450 million revolving credit facility was
established for TXU Energy and Oncor that matures on February 25, 2005. This
facility will be used for working capital and other general corporate purposes,
including letters of credit, and replaces the $1 billion 364-day revolving
credit facility that expired in April 2003. Up to $450 million of letters of
credit may be issued under the facility.
This facility, as well as others available to TXU Corp., will
provide back-up for any future issuance of commercial paper by TXU Energy and
Oncor. At June 30, 2003, there was no outstanding commercial paper under the
North America credit facilities.
10
In connection with the restructuring of the North America credit
facilities of TXU Corp., in April 2003:
o Oncor cancelled its undrawn $150 million secured 364-day credit
facility that was scheduled to expire in December 2003.
o US Holdings replaced TXU Corp. as the borrower under the $500
million three-year revolving credit facility. Concurrently, the
facility was reduced to $400 million, and TXU Corp. entered into
additional credit facilities totaling $100 million, which were
cancelled in August 2003.
o US Holdings' $1.4 billion five-year revolving credit facility was
amended. Among other things, the amendment increased the amount of
letters of credit allowed to be issued under the facility to $1
billion from $500 million.
11
Long-Term Debt-- At June 30, 2003 and December 31, 2002, the long-term
debt of TXU Corp. and its consolidated subsidiaries consisted of the following:
June 30, December 31,
2003 2002
---- ----
TXU Energy
Pollution Control Revenue Bonds:
Brazos River Authority:
Floating Taxable Series 1993 due June 1, 2023....................................... $ -- $ 44
4.900% Fixed Series 1994A due May 1, 2029(a)........................................ -- 39
5.400% Fixed Series 1994B due May 1, 2029, remarketing date May 1, 2006(a).......... 39 39
5.400% Fixed Series 1995A due April 1, 2030, remarketing date May 1, 2006(a)........ 50 50
5.050% Fixed Series 1995B due June 1, 2030, remarketing date June 19, 2006(a)....... 118 118
7.700% Fixed Series 1999A due April 1, 2033......................................... 111 111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013(a).. 16 16
7.700% Fixed Series 1999C due March 1, 2032......................................... 50 50
4.950% Fixed Series 2001A due October 1, 2030, remarketing date April 1, 2004(a).... 121 121
4.750% Fixed Series 2001B due May 1, 2029, remarketing date November 1, 2006(a)..... 19 19
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011(a)..... 274 274
4.250% Fixed Series 2001D due May 1, 2033, remarketing date November 1, 2003(a)..... 271 271
1.150% Floating Taxable Series 2001F due December 31, 2036(b)....................... 39 39
1.150% Floating Taxable Series 2001G due December 31, 2036(b)....................... 72 72
1.070% Floating Taxable Series 2001H due December 31, 2036(b)....................... 31 31
1.020% Floating Taxable Series 2001I due December 31, 2036(b)....................... 63 63
1.050% Floating Series 2002A due May 1, 2037(b)..................................... 61 61
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)...... 44 --
Sabine River Authority of Texas:
6.450% Fixed Series 2000A due June 1, 2021.......................................... 51 51
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011(a)..... 91 91
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011(a)..... 107 107
4.000% Fixed Series 2001C due May 1, 2028, remarketing date November 1, 2003(a)..... 70 70
1.150% Floating Taxable Series 2001D due December 31, 2036(b)....................... 12 12
1.070% Floating Taxable Series 2001E due December 31, 2036(b)....................... 45 45
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028........................................... -- 14
5.000% Fixed Series 2001A due May 1, 2027, remarketing date November 1, 2006(a)..... 37 37
Other:
7.000% Fixed Senior Notes - TXU Mining due May 1, 2003.............................. -- 72
6.875% Fixed Senior Notes - TXU Mining due August 1, 2005........................... 30 30
9.000% Fixed Exchangeable Subordinated Notes due November 22, 2012.................. 750 750
6.125% Fixed Senior Notes due March 15, 2008........................................ 250 --
7.000% Fixed Senior Notes due March 15, 2013........................................ 1,000 --
Capital lease obligations........................................................... 10 10
Other............................................................................... 7 8
Unamortized premium and discount.................................................... (108) (110)
------- -------
Total TXU Energy ............................................................... 3,731 2,605
------- -------
US Holdings
7.170% Fixed Senior Debentures due August 1, 2007................................... 10 10
9.556% Fixed Notes due in bi-annual installments through December 4, 2019........... 73 73
8.254% Fixed Notes due in quarterly installments through December 31, 2021.......... 67 68
2.110% Floating Rate Junior Subordinated Debentures, Series D due January 30,
2037(c)............................................................................. 1 1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037.......... 8 8
------- -------
Total US Holdings .............................................................. 159 160
------- -------
12
June 30, December 31,
2003 2002
---- ----
Oncor
9.530% Fixed Medium Term Secured Notes due January 30, 2003...................... -- 4
9.700% Fixed Medium Term Secured Notes due February 28, 2003..................... -- 11
6.750% Fixed First Mortgage Bonds due March 1, 2003.............................. -- 133
6.750% Fixed First Mortgage Bonds due April 1, 2003.............................. -- 70
8.250% Fixed First Mortgage Bonds due April 1, 2004.............................. 100 100
6.250% Fixed First Mortgage Bonds due October 1, 2004............................ 121 121
6.750% Fixed First Mortgage Bonds due July 1, 2005............................... 92 92
7.875% Fixed First Mortgage Bonds due March 1, 2023.............................. 224 224
8.750% Fixed First Mortgage Bonds due November 1, 2023........................... -- 103
7.875% Fixed First Mortgage Bonds due April 1, 2024.............................. 133 133
7.625% Fixed First Mortgage Bonds due July 1, 2025............................... 215 215
7.375% Fixed First Mortgage Bonds due October 1, 2025............................ 178 178
6.375% Fixed Senior Secured Notes due May 1, 2012................................ 700 700
7.000% Fixed Senior Secured Notes due May 1, 2032................................ 500 500
6.375% Fixed Senior Secured Notes due January 15, 2015........................... 500 500
7.250% Fixed Senior Secured Notes due January 15, 2033........................... 350 350
5.000% Fixed Debentures due September 1, 2007.................................... 200 200
7.000% Fixed Debentures due September 1, 2022.................................... 800 800
Unamortized premium and discount................................................. (32) (35)
-------- -------
Total Oncor.................................................................. 4,081 4,399
------- -------
TXU Gas
6.250% Fixed Notes due January 1, 2003........................................... -- 125
6.375% Fixed Notes due February 1, 2004.......................................... 150 150
7.125% Fixed Notes due June 15, 2005............................................. 150 150
6.564% Fixed Remarketed Reset Notes due January 1, 2008 (a)...................... 125 125
Unamortized fair value adjustments............................................... 1 1
------- -------
Total TXU Gas ............................................................... 426 551
------- -------
TXU Australia
5.555% Floating Notes due October 30, 2003(d).................................... 20 17
5.055% Floating Notes due September 21, 2007(d).................................. 184 155
5.752% Floating Note, Tranche A Facility due October 26, 2004(d)................. 27 23
5.685% Floating Note, Tranche A Facility due October 26, 2004(d)................. 83 142
5.603% Floating Note, Tranche B Facility due October 26, 2004(d)................. 133 113
5.740% Floating Note, Tranche B Facility due October 26, 2004(d)................. 40 34
5.620% Floating Note, Tranche B Facility due October 26, 2004(d)................. 73 62
5.735% Floating Note, Tranche B Facility due October 26, 2004(d)................. 87 73
5.832% Floating Note, Tranche C Facility due October 26, 2004(d)................. 367 311
5.935% Floating Note, Tranche C Facility due October 26, 2004(d)................. 133 113
7.000% Fixed Medium Term Notes due September 22, 2005............................ 133 113
5.190% Floating Senior Notes due December 1, 2006(d)............................. 241 203
5.433% Floating Senior Notes due December 1, 2016(c)............................. 82 70
Unamortized premium and discount and fair value adjustments...................... 53 99
------- -------
Total TXU Australia.......................................................... 1,656 1,528
------- -------
13
June 30, December 31,
2003 2002
---- ------
Corporate and Other
6.375% Fixed Senior Notes Series B due October 1, 2004........................... 175 175
6.375% Fixed Senior Notes Series C due January 1, 2008........................... 200 200
5.520% Fixed Senior Notes Series D due August 16, 2003........................... 323 323
4.050% Fixed Senior Notes Series E due August 16, 2004........................... 2 2
6.375% Fixed Senior Notes Series J due June 15, 2006............................. 800 800
4.750% Fixed Senior Notes Series K due November 16, 2006 (equity-linked),
remarketing date November 16, 2004............................................... 500 500
5.450% Fixed Senior Notes Series L due November 16, 2007 (equity-linked),
remarketing date November 16, 2005............................................... 500 500
5.800% Fixed Senior Notes Series M due May 16, 2008 (equity-linked), remarketing
date May 16, 2006................................................................ 440 440
6.000% Fixed Telecom Overfund Trust Debt due bi-annually through August 15, 2004. 135 178
11.98% Floating Notes due monthly through October 31, 2007 (c)................... 3 4
8.820% Building Financing due bi-annually through February 11, 2022.............. 135 140
Unamortized premium and discount................................................. 40 50
------- -------
Total Corporate and Other................................................... 3,253 3,312
------- -------
Total TXU Corp. consolidated..................................................... 13,306 12,555
Less amount due currently........................................................ 743 958
------- -------
Total long-term debt............................................................. $12,563 $11,597
======= =======
(a) These series are in the multiannual mode and are subject to mandatory
tender prior to maturity on the mandatory remarketing date. On such
date, the interest rate and interest rate period will be reset for
the bonds.
(b) Interest rates in effect at June 30, 2003. These series are in a flexible
or weekly rate mode and are classified as long-term as they are
supported by long-term irrevocable letters of credit. Series in the
flexible mode will be remarketed for periods of less than 270 days.
(c) Interest rates in effect at June 30, 2003.
(d) Interest rates fixed by swaps at June 30, 2003.
In July 2003, TXU Corp. issued $525 million of floating rate
convertible senior notes due 2033 in a private placement. The notes bear
regular interest at an annual floating rate equal to 3-month LIBOR, determined
quarterly, plus 150 basis points, and payable in arrears quarterly commencing
October 15, 2003. The initial interest rate is 2.60563%. The notes will bear
additional contingent interest during periods after July 15, 2008 if the
average trading price of the notes for a specified period exceeds 120% of the
principal amount of the notes. The notes will have an initial conversion rate
of 28.9289 shares of TXU Corp. common stock per $1,000 principal amount of
notes, which equates to an initial conversion price of $34.5675 per share. The
conversion rate is subject to adjustments in certain circumstances, including a
change in the amount of quarterly cash dividends per share on TXU Corp. common
stock from the current rate of $0.125 per share. The notes will be convertible
at the conversion rate, as adjusted, until maturity if (1) during any fiscal
quarter the market price of TXU Corp. common stock is above $41.481 per share
for a specified period; (2) TXU Corp. calls the notes for redemption;
(3) the trading price of the notes falls below 95% of the conversion value of
the notes for a specified period; or (4) certain specified corporate
transactions occur. Should the holders elect to convert the notes, TXU Corp.
has the option to settle the conversion in cash, common stock or a combination
of both. The notes will be redeemable by TXU Corp. at par, plus accrued and
unpaid interest and contingent interest, if any, beginning July 15, 2008.
The holders will be entitled to require TXU Corp. to purchase the notes at par,
plus accrued and unpaid interest and contingent interest, if any, on
July 15, 2008, July 15, 2013, July 15, 2018, July 15, 2023 and July 15, 2028.
Other than on July 15, 2008, upon a holder's election to require a repurchase,
TXU Corp. may elect to pay the purchase price in cash, common stock, or a
combination of both. With certain exceptions, the holders will be entitled to
require TXU Corp. to repurchase the notes if a person or group acquires more
than 50% of TXU Corp.'s common equity or if there is a merger, sale of assets
or other transaction that results in TXU Corp.'s common stockholders owning
less than 50% of the surviving entity.
14
In July 2003, TXU Energy exercised its right to exchange its $750
million 9% Exchangeable Subordinated Notes due November 22, 2012 for
exchangeable preferred membership interests with identical economic and other
terms. These securities are convertible into TXU Corp. common stock at an
exercise price of $13.1242. The market price of TXU Corp. common stock on June
30, 2003 was $22.45. As disclosed in the 2002 Form 10-K, any exchange of these
securities into common stock would result in a proportionate write-off of the
related unamoritzed discount as a charge to earnings. If all the securities
had been exchanged into common stock on June 30, 2003, the pre-tax charge would
have been $107 million.
In July 2003, the Brazos River Authority issued $39 million
aggregate principal amount of Series 2003B pollution control revenue bonds for
TXU Energy. The bonds will bear interest at an annual rate of 6.30% until
maturity in 2032. Proceeds from the issuance of the bonds were used to refund
the entire principal amount of Brazos River Authority Taxable Series 2001F
variable rate pollution control revenue bonds due December 31, 2036. The Sabine
River Authority also issued $12 million aggregate principal amount of Series
2003A pollution control revenue bonds for TXU Energy. The bonds will bear
interest at an annual rate of 5.80% until maturity in 2022. Proceeds from the
issuance of these bonds were used to refund the entire principal amount of
Sabine River Authority Taxable Series 2001D pollution control revenue bonds due
December 31, 2036.
In May 2003, the Brazos River Authority Series 1994A and the Trinity
River Authority Series 2000A pollution control revenue bonds (aggregate
principal amount of $53 million) were purchased upon mandatory tender. In July
2003, the bonds were remarketed and converted from a floating rate mode to a
multiannual mode at an annual rate of 3.00% and 6.25%, respectively. The rate on
the 1994A bonds will remain in effect until their mandatory tender date of May
1, 2005, at which time they will be remarketed. The rate on the 2000A bonds will
remain in effect until their maturity in 2028.
In May 2003, $72 million principal amount of the 7% TXU Mining fixed
rate senior notes were repaid at maturity.
In April 2003, Oncor repaid all ($70 million principal amount) of its
First Mortgage Bonds, 6.75% Series, at the maturity date for par value plus
accrued interest. A restricted cash deposit of $72 million was utilized to fund
the maturity.
In April 2003, the Brazos River Authority Series 1999A pollution
control revenue bonds, with an aggregate principal amount of $111 million, were
remarketed. The bonds now bear interest at a fixed annual rate of 7.70% and are
callable beginning on April 1, 2013 at a price of 101% until March 31, 2014 and
at 100% thereafter.
In March 2003, the Brazos River Authority Series 1999B and 1999C
pollution control revenue bonds (aggregate principal amount of $66 million) were
converted from a floating rate mode to a multiannual mode at annual rates of
6.75% and 7.70%, respectively. The rate on the 1999B bonds will remain in effect
until 2013 at which time they will be remarketed. The rate on the 1999C bonds is
fixed to maturity in 2032, however they become callable in 2013.
In March 2003, the Brazos River Authority issued $44 million
aggregate principal amount of pollution control revenue bonds for TXU Energy.
The bonds will bear interest at an annual rate of 6.75% until the mandatory
tender date of April 1, 2013. On April 1, 2013, the bonds will be remarketed.
Proceeds from the issuance of the bonds were used to repay the entire principal
amount of Brazos River Authority Series 1993 pollution control revenue bonds due
June 1, 2023.
In March 2003, Oncor repaid all ($133 million principal amount) of
its First Mortgage Bonds, 6.75% Series, at the maturity date for par value plus
accrued interest. A restricted cash deposit of $138 million was utilized to fund
the maturity.
In March 2003, Oncor redeemed all ($103 million principal amount) of
its First Mortgage and Collateral Trust Bonds, 8.75% Series due November 1,
2023, at 104.01% of the principal amount thereof, plus accrued interest to the
redemption date.
In March 2003, TXU Energy issued $1.25 billion aggregate principal
amount of senior unsecured notes in two series in a private placement with
registration rights. One series in the amount of $250 million is due March 15,
2008, and bears interest at the annual rate of 6.125%, and the other series in
the amount of $1 billion is due March 15, 2013, and bears interest at the annual
rate of 7%. Net proceeds from the issuance were used for general corporate
purposes, including the repayment of borrowings under TXU Corp.'s North America
credit facilities. In August 2003, TXU Energy entered into interest rate swap
transactions to effectively convert $500 million of the notes to floating
interest rates.
15
In January 2003, TXU Gas redeemed, at par value, $125 million
principal amount of its 6.25% Notes at maturity.
Australia -- At June 30, 2003, TXU Australia had A$505 million ($337
million) in medium-term notes outstanding, of which interest and principal
payments associated with A$475 million ($317 million) were guaranteed under an
insurance policy. The medium-term notes have three tranches consisting of fixed
and variable rates of which A$30 million ($20 million) is due October 2003 and
the remainder is due between September 2005 and September 2007.
Sale of Receivables -- Certain subsidiaries of TXU Corp. sell trade
accounts receivable to TXU Receivables Company, a wholly-owned bankruptcy remote
subsidiary of TXU Corp., which sells undivided interests in accounts receivable
it purchases to financial institutions. As of June 30, 2003, TXU Energy (through
certain subsidiaries), Oncor and TXU Gas are qualified originators of accounts
receivable under the program. TXU Receivables Company may sell up to an
aggregate of $600 million in undivided interests in the receivables purchased
from the originators under the program. The June 30, 2003 financial statements
reflect the sale of $1.2 billion face amount of receivables to TXU Receivables
Company under the program in exchange for cash of $540 million and $615 million
in subordinated notes, with $11 million of losses on sales for the six months
ended June 30, 2003 that principally represents the interest costs on the
underlying financing. These losses approximated 6% of the cash proceeds from the
sale of undivided interests in accounts receivable on an annualized basis.
Funding under the program increased $70 million for the six month period ended
June 30, 2003 primarily due to reserve requirements that were reduced through a
temporary amendment in recognition of improving collection trends. Higher loss
reserve requirements in previous periods reflected the billing and collection
delays previously experienced as a result of new systems and processes in TXU
Energy and ERCOT for clearing customers' switching and billing data upon the
transition to competition. Funding increases or decreases under the program are
reflected as operating cash flow activity.
Upon termination, cash flows to the originators would be delayed as
collections of sold receivables would be used by TXU Receivables Company to
repurchase the undivided interests of the financial institutions instead of
purchasing new receivables. The level of cash flows would normalize in
approximately 16 to 31 days. TXU Business Services Company, a subsidiary of TXU
Corp., services the purchased receivables and is paid a market based servicing
fee by TXU Receivables Company. The subordinated notes receivable from TXU
Receivables Company represent TXU Corp.'s subsidiaries' retained interests in
the transferred receivables and are recorded at book value, net of allowances
for bad debts, which approximates fair value due to the short-term nature of the
subordinated notes, and are included in accounts receivable in the consolidated
balance sheet.
In August 2003, the program was amended to extend the term to July
2004, as well as to extend the period providing temporarily higher delinquency
and default compliance ratios through December 31, 2003. The program was also
amended to coincide with the credit facilities' covenants by removing investment
grade credit ratings as a requirement of an eligible originator and substituting
maintenance of fixed charge coverage ratios and debt to capital ratios as
requirements of an eligible originator. In June 2003, the program was amended to
provide temporarily higher delinquency and default compliance ratios and
temporary relief from the loss reserve formula. The June amendment reflected the
billing and collection delays previously experienced as a result of new systems
and processes in TXU Energy and ERCOT for clearing customers' switching and
billing data upon the transition to competition.
Contingencies Related to Receivables Program -- Although TXU
Receivables Company expects to be able to pay its subordinated notes from the
collections of purchased receivables, these notes are subordinated to the
undivided interests of the financial institutions in those receivables, and
collections might not be sufficient to pay the subordinated notes. The program
may be terminated if either of the following events occurs:
16
1) all of the originators cease to maintain their required fixed charge
coverage ratio and debt to capital (leverage) ratio;
2) the delinquency ratio (delinquent for 31 days) for the sold
receivables, the default ratio (delinquent for 91 days or deemed
uncollectible), the dilution ratio (reductions for discounts,
disputes and other allowances) or the days collection outstanding
ratio exceed stated thresholds and the financial institutions do not
waive such event of termination. The thresholds apply to the entire
portfolio of sold receivables, not separately to the receivables of
each originator.
The delinquency and dilution ratios exceeded the relevant thresholds
during the first four months of 2003, but waivers were granted. These ratios
were affected by issues related to the transition to deregulation. Certain
billing and collection delays arose due to implementation of new systems and
processes within TXU Energy and ERCOT for clearing customers' switching and
billing data. The billing delays have been resolved but, while improving, the
lagging collection issues continue to impact the ratios. The implementation of
new POLR rules by the Commission and strengthened credit and collection policies
and practices are expected to bring the ratios into consistent compliance with
the program.
Under the receivables sale program, all the originators are required
to maintain specified fixed charge coverage and leverage ratios (or supply a
parent guarantor that meets the ratio requirements). The failure by an
originator or its parent guarantor, if any, to maintain the specified financial
ratios would prevent that originator from selling its accounts receivable under
the program. If all the originators and the parent guarantor, if any, fail to
maintain the specified financial ratios so that there are no eligible
originators, the facility would terminate. Prior to the August 2003 amendment
extending the program, originator eligibility was predicated on the maintenance
of an investment grade credit rating.
Financial Covenants, Credit Rating Provisions and Cross Default
Provisions -- The terms of certain financing arrangements of TXU Corp. contain
financial covenants that require maintenance of specified fixed charge coverage
ratios, shareholders' equity to total capitalization ratios and leverage ratios
and/or contain minimum net worth covenants. TXU Energy's preferred membership
interests (formerly subordinated notes) also limit its incurrence of additional
indebtedness unless a leverage ratio and interest coverage test are met on a pro
forma basis. As of June 30, 2003, TXU Corp. and its subsidiaries were in
compliance with all such applicable covenants.
Certain financing and other arrangements of TXU Corp. contain
provisions that are specifically affected by changes in credit ratings and also
include cross default provisions. The material cross default provisions are
described below.
Other agreements of TXU Corp., including some of the credit
facilities discussed above, contain terms pursuant to which the interest rates
charged under the agreements may be adjusted depending on the credit ratings of
TXU Corp. or its subsidiaries.
Cross Default Provisions
------------------------
Certain financing arrangements of TXU Corp. contain provisions that
would result in an event of default if there is a failure under other financing
arrangements to meet payment terms or to observe other covenants that would
result in an acceleration of payments due. Such provisions are referred to as
"cross default" provisions.
A default by US Holdings or any subsidiary thereof on financing
arrangements of $50 million or more would result in a cross default under the
$1.4 billion US Holdings five-year revolving credit facility, the $400 million
US Holdings credit facility, the $68 million US Holdings letter of credit
reimbursement and credit facility agreement and $30 million of TXU Mining senior
notes (which have a $1 million threshold).
A default by TXU Energy or Oncor or any subsidiary thereof in respect
of indebtedness in a principal amount in excess of $50 million or more would
result in a cross default for such party under the TXU Energy/Oncor $450 million
revolving credit facility. Under this credit facility, a default by TXU Energy
or any subsidiary thereof would cause the maturity of outstanding balances under
such facility to be accelerated as to TXU Energy, but not as to Oncor. Also,
under this credit facility, a default by Oncor or any subsidiary thereof would
cause the maturity of outstanding balances to be accelerated under such facility
as to Oncor, but not as to TXU Energy.
17
A default or similar event under the terms of the TXU Energy
preferred membership interests (formerly subordinated notes) that results in the
acceleration (or other mandatory repayment prior to the mandatory redemption
date) of such security or the failure to pay such security at the mandatory
redemption date would result in a default under TXU Energy's $1.25 billion
senior unsecured notes.
TXU Corp.'s 6% Notes due 2003 to 2004, which are held by the Pinnacle
Overfund Trust ($135 million outstanding at June 30, 2003) and Pinnacle's 8.83%
Senior Secured Notes due 2004 ($810 million outstanding at June 30, 2003)
contain cross default provisions relating to a failure to pay principal or
interest on indebtedness of TXU Corp. or TXU Communications Ventures Company (in
the case of the 8.83% Senior Secured Notes due 2004) in a principal amount of
$50 million or above.
TXU Energy has entered into certain mining and equipment leasing
arrangements aggregating $127 million that would terminate upon the default of
any other obligations of TXU Energy owed to the lessor. In the event of a
default by TXU Mining, a subsidiary of TXU Energy, on indebtedness in excess of
$1 million, a cross default would result under the $31 million TXU Mining
leveraged lease and the lease would terminate.
The accounts receivable program also contains a cross default
provision with a threshold of $50 million applicable to each of the originators
under the program. TXU Receivables Company and TXU Business Services Company
each have a cross default threshold of $50,000. If either an originator, TXU
Business Services Company or TXU Receivables Company defaults on indebtedness of
the applicable threshold, the facility could terminate.
TXU Energy enters into energy-related contracts, the master forms of
which contain provisions whereby an event of default would occur if TXU Energy
were to default under an obligation in respect of borrowings in excess of
thresholds stated in the contracts, which thresholds vary.
A default by TXU Gas or any of its material subsidiaries on
indebtedness of $25 million or more would result in a cross default under the
$300 million TXU Gas senior notes due 2004 and 2005.
A default by TXU Corp. on indebtedness of $50 million or more would
result in a cross default under the new $500 million five-year revolving credit
facility.
TXU Corp. and its subsidiaries have other arrangements, including
interest rate swap agreements and leases with cross default provisions, the
triggering of which would not result in a significant effect on liquidity.
18
5. PREFERRED STOCK OF SUBSIDIARIES AND TRUST SECURITIES
Preferred Stock - In July 2003, US Holdings redeemed all of the
shares of its $7.98 series, $7.50 series and $7.22 series of preferred stock not
subject to mandatory redemption and the shares of its $6.98 series of preferred
stock subject to mandatory redemption for an aggregate principal amount of $91
million.
TXU Corp. or Subsidiary Obligated, Mandatorily Redeemable, Preferred
Securities of Subsidiary Trusts, Each Holding Solely Junior Subordinated
Debentures of TXU Corp. or Related Subsidiary (Trust Securities) -- The
statutory business trust subsidiaries had Trust Securities and trust assets
outstanding as follows:
Trust Securities
---------------------------------------------- Trust Assets Maturity
Units (000's) Amount Amount
--------------------- ---------------------- -----------------------
June 30, December 31, June 30, December 31, June 30, December 31,
2003 2002 2003 2002 2003 2002
---- ---- ---- ---- ---- ----
TXU Corp.
- ---------
TXU Corp. Capital I
(7.25% Series)..... 9,200 9,200 $ 223 $ 223 $237 $237 2029
TXU Corp. Capital II
(8.70% Series)..... 6,000 6,000 145 145 155 155 2034
------ ------ ----- ----- ---- ----
Total TXU Corp..... 15,200 15,200 368 368 392 392
------ ------ ----- ----- ---- ----
TXU Gas
- -------
TXU Gas Capital I
(Floating Rate Trust
Securities)(a).... 150 150 147 147 155 155 2028
------ ------ ----- ----- ---- ----
Total.............. 15,350 15,350 $ 515 $ 515 $547 $547
====== ====== ===== ===== ==== ====
(a) Interest rate swaps effectively fixed the rate on $100 million of the TXU
Gas Floating Rate Trust Securities at 6.629% and at 6.444% on the remaining
$50 million of the Trust Securities to July 1, 2003. TXU Corp. elected not
to renew these swaps and will pay variable interest rates on these Trust
Securities based on the three-month LIBOR rate plus a margin of 135 basis
points.
Each parent company owns the common trust securities issued by its
subsidiary trust and has effectively issued a full and unconditional guarantee
of such trust's securities.
6. SHAREHOLDERS' EQUITY
June 30, December 31,
2003 2002
------- ------
Shareholders' equity:
Preferred stock - not subject to mandatory redemption........... $ 300 $ 300
------ ------
Common stock without par value:
Authorized shares: 1,000,000,000
Outstanding shares: June 30, 2003 -- 321,908,423
and December 31, 2002-- 321,974,000 ....................... 12 7,995
Additional paid in capital...................................... 8,097 111
Retained deficit................................................ (2,834) (2,900)
Accumulated other comprehensive loss............................ (316) (440)
------- -------
Total common stock equity.................................. 4,959 4,766
------ ------
Total shareholders' equity............................... $5,259 $5,066
====== ======
Under Texas law, TXU Corp. may only declare dividends out of surplus,
which is statutorily defined as total shareholders' equity less the book value
of common stock and preferred stock (stated capital). The write-off in 2002 of
19
TXU Corp.'s investment in TXU Europe resulted in negative surplus as of December
31, 2002. Texas law permits, subject to the receipt of shareholder approval, the
reclassification of stated capital into surplus. TXU Corp. received such
shareholder approval of this reclassification in a special meeting of
shareholders held February 14, 2003. Accordingly, approximately $8.0 billion was
reclassified from stated capital to additional paid-in capital, resulting in
surplus of $4.95 billion at June 30, 2003.
Additional paid-in capital includes $107 million and $111 million of
discount on the 9% Exchangeable Subordinated Notes of TXU Energy at June 30,
2003 and December 31, 2002, respectively. These notes were exchanged into
preferred membership interests in July 2003 and continue to be exchangeable into
TXU Corp. common stock.
The Board of Directors of TXU Corp., at its February 2003 meeting,
declared a quarterly dividend of $0.125 a share, payable April 1, 2003, to
shareholders of record on March 7, 2003. At its May 2003 meeting, the Board of
Directors of TXU Corp. declared a quarterly dividend of $0.125 a share, payable
on July 1, 2003, to shareholders of record on June 6, 2003. Future dividends may
vary depending upon TXU Corp.'s profit levels, operating cash flows and capital
requirements as well as financial and other business conditions existing at the
time.
An Oncor mortgage restricts its payment of dividends to the amount
of its retained earnings. Certain other debt instruments and preferred
securities of TXU Corp.'s subsidiaries contain provisions that restrict payment
of dividends during any interest or distribution payment deferral period or
while any payment default exists. At June 30, 2003, there were no restrictions
on the payment of dividends under these provisions.
7. CONTINGENCIES
Guarantees -- TXU Corp. has entered into contracts that contain
guarantees to outside parties that could require performance or payment under
certain conditions. These guarantees have been grouped based on similar
characteristics and are described in detail below.
Project development guarantees -- In 1990, TXU Corp. repurchased an
electric co-op's minority ownership interest in the Comanche Peak nuclear
generation plant and assumed the co-op's indebtedness to the US government for
the facilities. TXU Corp. is making principal and interest payments to the co-op
in an amount sufficient for the co-op to make payments on its indebtedness. TXU
Corp. guaranteed the co-op's payments, and in the event that the co-op fails to
make its payments on the indebtedness, the US government would assume the
co-op's rights under the agreement, and such payments would then be owed
directly by TXU Corp. At June 30, 2003, the balance of the indebtedness was $139
million with maturities of principal and interest extending to December 2021.
The indebtedness is secured by a lien on the purchased facilities.
Residual value guarantees in operating leases -- TXU Corp. is the
lessee under various operating leases that obligate it to guarantee the residual
values of the leased facilities. At June 30, 2003, the aggregate maximum amount
of residual values guaranteed was approximately $303 million with an estimated
residual recovery of approximately $221 million. The average life of the lease
portfolio is approximately seven years.
Shared saving guarantees -- TXU Corp. has guaranteed that certain
customers will realize specified annual savings resulting from energy management
services it has provided. In aggregate, the average annual savings has exceeded
the annual savings guaranteed. The maximum potential annual payout is
approximately $8 million and the maximum total potential payout is approximately
$56 million. During the three months ended June 30, 2003 no shared savings
contracts were executed. The average remaining life of the portfolio is
approximately nine years.
Letters of credit -- TXU Corp. has entered into various agreements
that require letters of credit for financial assurance purposes. Approximately
$350 million of letters of credit were outstanding at June 30, 2003 to support
existing floating rate pollution control revenue bond debt of approximately $323
million. The letters of credit are available to fund the payment of such debt
obligations. These letters of credit have expiration dates in 2003 and 2004;
however, TXU Corp. intends to provide from either existing or new facilities for
the extension, renewal or substitution of these letters of credit to the extent
required for such floating rate debt or their remarketing as fixed rate debt. In
July 2003, approximately $56 million of the $350 million of letters of credit
referenced above were terminated as a result of the refinancing of approximately
$51 million of floating rate pollution control revenue bonds.
20
TXU Corp. has outstanding letters of credit in the amount of $118
million to support portfolio management margin requirements in the normal
course of business. As of June 30, 2003, approximately 73% of the obligations
supported by these letters of credit mature within one year, and substantially
all of the remainder mature in the second year.
TXU Corp. has an outstanding letter of credit in the amount of $37
million as support for a subordinated loan to a joint venture related to a
pipeline construction project in Australia. The obligation expires on January
31, 2005.
TXU Australia has outstanding letters of credit in the amount of
approximately $70 million, of which $57 million is to allow for participation
in the electricity and gas spot markets, $12 million is to provide credit
support for the shipping of gas and $1 million for miscellaneous credit support
requirements. Although the average life of these guarantees is for
approximately one year, the obligation to provide guarantees is ongoing based
on TXU Australia's continued participation in the electricity and gas spot
markets and its ability to ship gas on the SEA Gas pipeline.
Surety bonds -- TXU Corp. has outstanding surety bonds of
approximately $60 million to support performance under various subsidiary
construction contracts in the normal course of business. The term of the surety
bond obligations is approximately two years.
Other --TXU Corp. has entered into contracts with public agencies
to purchase cooling water for use in the generation of electric energy and has
agreed, in effect, to guarantee the principal, $16 million at June 30, 2003, and
interest on bonds issued by the agencies to finance the reservoirs from which
the water is supplied. The bonds mature at various dates through 2011 and have
interest rates ranging from 5.50% to 7%. TXU Corp. is required to make
periodic payments equal to such principal and interest, including amounts
assumed by a third party and reimbursed to TXU Corp. In addition, TXU Corp.
is obligated to pay certain variable costs of operating and maintaining the
reservoirs. TXU Corp. has assigned to a municipality all its contract rights
and obligations in connection with $19 million remaining principal amount of
bonds at June 30, 2003, issued for similar purposes, which had previously been
guaranteed by TXU Corp. TXU Corp. is, however, contingently liable in the
unlikely event of default by the municipality.
In 1992, a discontinued engineering and construction business of TXU
Gas completed construction of a plant, the performance of which is warranted by
TXU Gas through 2008. The maximum contingent liability under the guarantee is
approximately $96 million. No claims have been asserted under the guarantee and
none are anticipated.
Income Tax Contingencies -- On its US federal income tax return for
calendar year 2002, TXU Corp. claimed a deduction related to the worthlessness
of TXU Corp.'s investment in TXU Europe, the tax benefit of which is now
expected, as reported in the first quarter of 2003, to be $983 million. The
estimate at year-end 2002 of the tax benefit was $1.2 billion. While TXU Corp.
believes that its tax reporting for the TXU Europe write-off was proper, there
is a risk that the IRS could challenge TXU Corp.'s position regarding this
deduction. As reported in the first quarter, TXU Corp. has not recognized in
book income any tax benefit for the TXU Europe deduction. In the first quarter
of 2003, TXU Corp. received a cash refund of $527 million related to the
deduction, which may be repaid in the future, with interest, should TXU Corp.
not prevail in its position.
Legal Proceedings -- In October, November and December 2002 and
January 2003, a number of lawsuits were filed in, removed to or transferred to
the United States District Court for the Northern District of Texas against TXU
Corp., and certain of its officers. These lawsuits have all been consolidated
and lead plaintiffs have been appointed by the Court. On July 21, 2003, the lead
plaintiffs filed an amended consolidated complaint naming Erle Nye, Michael J.
McNally, V.J. Horgan and Brian N. Dickie and directors Derek C. Bonham, J.S.
Farrington, William M. Griffin, Kerney Laday, Jack E. Little, Margaret N. Maxey,
J.E. Oesterreicher, Herbert H. Richardson and Charles R. Perry, as defendants.
The plaintiffs seek to represent classes of certain purchasers of TXU Corp.
common and equity-linked debt during a proposed class period from April 26, 2001
to October 11, 2002. No class or classes have been certified. The complaint
alleges violations of the provisions of Sections 10(b) and 20(a) of the
Securities Exchange Act of 1934, as amended, and Rule 10b-5 promulgated
thereunder, and Sections 11 and 12 of the Securities Act of 1933, as amended
(Securities Act), relating to alleged materially false and misleading
statements, including statements in prospectuses related to the offering by
TXU Corp. of its equity-linked securities and common stock in May and June 2002.
The named individual defendants are current or former officers and/or directors
of TXU Corp. While TXU Corp. believes the claims are without merit and intends
to vigorously defend this lawsuit, it is unable to estimate any possible loss
or predict the outcome of this action.
21
On October 23, 2002, a derivative lawsuit was filed by a purported
shareholder on behalf of TXU Corp. in the 116th Judicial District Court of
Dallas County, Texas, against TXU Corp., Erle Nye, Michael J. McNally, David W.
Biegler, J.S. Farrington, William M. Griffin, Kerney Laday, Jack E. Little,
Margaret N. Maxey, J.E. Oesterreicher, Charles R. Perry and Herbert H.
Richardson. The plaintiff alleges breach of fiduciary duty, abuse of control,
mismanagement, waste of corporate assets, and breach of the duties of loyalty
and good faith. The named individual defendants are current or former officers
and/or directors of TXU Corp. No amount of damages has been specified.
Furthermore, plaintiffs in such suit have failed to make a demand upon the
directors as is required by law. Therefore, TXU Corp. is unable to estimate any
possible loss or predict the outcome of this action.
On November 26, 2002, a lawsuit was filed in the United States
District Court for the Northern District of Texas against TXU Corp. and the
directors of TXU Corp. asserting claims under the Employee Retirement Income
Security Act (ERISA) on behalf of a putative class of participants in various
employee benefit plans of TXU Corp. The plaintiff seeks to represent a class of
participants in such plans during the period between January 31, 2002, and
October 11, 2002, based on factual allegations substantially the same as the
other cases described above pending in the United States District Court for the
Northern District of Texas. While TXU Corp. believes the claims are without
merit and intends to vigorously defend the lawsuit, it is unable to estimate any
possible loss or predict the outcome of this action.
On February 28, 2003, a lawsuit was filed in the United States
District Court for the Northern District of Texas, Dallas Division, against TXU
Corp., the directors of TXU Corp., Peter B. Tinkham, Diane J. Kubin, Robert L.
Turpin and other former unidentified members of the TXU Thrift Plan Committee
asserting claims under ERISA on behalf of a putative class of participants and
beneficiaries of the TXU Thrift Plan. The plaintiff seeks to represent a class
of participants in such plan during the period between November 23, 2001 through
October 11, 2002. While TXU Corp. believes the claim is without merit and
intends to vigorously defend the lawsuit, it is unable to estimate any possible
loss or predict the outcome of this action.
On March 18, 2003, a lawsuit was filed in the United States District
Court of Texas against TXU Corp., Erle Nye, H. Jarrell Gibbs, Peter B. Tinkham,
Robert L. Turpin and Diane J. Kubin asserting claims under ERISA on behalf of a
putative class of participants and beneficiaries of the TXU Thrift Plan. The
plaintiff seeks to represent a class of participants in such plan during the
period between January 31, 2002 and the present. This ERISA suit is being
consolidated with the other two ERISA suits filed on November 26, 2002 and
February 28, 2003, respectively. While TXU Corp. believes the claim is without
merit and intends to vigorously defend the lawsuit, it is unable to estimate any
possible loss or predict the outcome of this action.
On April 28, 2003, a lawsuit was filed by a former employee of TXU
Portfolio Management in the United States District Court for the Northern
District of Texas, Dallas Division, against TXU Corp., TXU Energy and TXU
Portfolio Management. Plaintiff asserts claims under Section 806 of
Sarbanes-Oxley arising from plaintiff's employment termination and claims for
breach of contract relating to payment of certain bonuses. Plaintiff seeks back
pay, payment of bonuses and alternatively, reinstatement or future compensation,
including bonuses. TXU Corp. believes the plaintiff's claims are without merit.
The plaintiff was terminated as the result of a reduction in force, not as a
reaction to any concerns the plaintiff had expressed, and plaintiff was not in a
position with TXU Portfolio Management such that he had knowledge or information
that would qualify the plaintiff to evaluate TXU Corp.'s financial statements or
assess the adequacy of TXU Corp.'s financial disclosures. Thus, TXU Corp. does
not believe that there is any merit to the plaintiff's claims under
Sarbanes-Oxley. Accordingly, TXU Corp., TXU Energy and TXU Portfolio Management
intend to vigorously defend the litigation. While TXU Corp., TXU Energy and TXU
Portfolio Management dispute the plaintiff's claims, like any litigation, TXU
Corp. is unable to predict the outcome of this litigation or the possible loss
in the event of an adverse judgment.
22
On July 7, 2003, a lawsuit was filed by Texas Commercial Energy
(TCE) in the United States District Court for the Southern District of Texas,
Corpus Christi Division, against TXU Energy and certain of its subsidiaries, as
well as various other wholesale market participants doing business in ERCOT,
claiming generally that defendants engaged in market manipulation, in violation
of antitrust and other laws, primarily during the period of extreme weather
conditions in late February 2003. On August 6, 2003, the complaint was amended
to omit one of the other defendants. TXU Corp. believes that it has not
committed any violation of the antitrust laws and the Commission's investigation
of the market conditions in late February 2003 has not resulted in any findings
adverse to TXU Energy. Accordingly, TXU Corp. believes that TCE's claims against
TXU Energy and its subsidiary companies are without merit and intends to
vigorously defend the lawsuit. As with any litigation of this nature, TXU Corp.
is unable to estimate any possible loss or predict the outcome of this action.
On March 10, 2003, a lawsuit was filed by Kimberly P. Killebrew in
the United States District Court for the Eastern District of Texas, Lufkin
Division, against TXU Corp. and TXU Portfolio Management, asserting generally
that defendants engaged in manipulation of the wholesale electric market, in
violation of antitrust and other laws. This lawsuit was not served on TXU Corp.
until mid-July 2003. This action is brought by an individual, alleged to be a
retail consumer of electricity, on behalf of herself and as a proposed
representative of a putative class of retail purchasers of electricity that are
similarly situated. TXU Corp. believes that the Plaintiff likely lacks standing
to assert any antitrust claims against TXU Corp. or TXU Portfolio Management,
and that defendants have not violated antitrust laws or other laws as claimed by
the Plaintiff. Therefore, TXU Corp. believes that plaintiff's claims are without
merit and plans to vigorously defend the lawsuit. As with any litigation of this
nature, however, TXU Corp. is unable to estimate any possible loss or predict
the outcome of this action.
Open-Access Transmission -- At the state level, the Texas Public
Utility Regulatory Act, as amended, requires owners or operators of transmission
facilities to provide open access wholesale transmission services to third
parties at rates and terms that are non-discriminatory and comparable to the
rates and terms of the utility's own use of its system. The Commission has
adopted rules implementing the state open access requirements for utilities that
are subject to the Commission's jurisdiction over transmission services, such as
Oncor.
On January 3, 2002, the Supreme Court of Texas issued a mandate
affirming the judgment of the Court of Appeals that held that the pricing
provisions of the Commission's open access wholesale transmission rules, which
had mandated the use of a particular rate setting methodology, were invalid
because they exceeded the statutory authority of the Commission. On January 10,
2002, Reliant Energy Incorporated and the City Public Service Board of San
Antonio each filed lawsuits in the Travis County, Texas, District Court against
the Commission and each of the entities to whom they had made payments for
transmission service under the invalidated pricing rules for the period January
1, 1997, through August 31, 1999, seeking declaratory orders that, as a result
of the application of the invalid pricing rules, the defendants owe unspecified
amounts. US Holdings and TXU SESCO Company are named defendants in both suits.
TXU Corp. is unable to predict the outcome of any litigation related to this
matter.
23
General -- In addition to the above, TXU Corp. and its US and
Australian subsidiaries are involved in various other legal and administrative
proceedings the ultimate resolution of which, in the opinion of each, should not
have a material effect upon their financial position, results of operations or
cash flows.
8. SEGMENT INFORMATION
TXU Corp. has three reportable segments: North America Energy,
North America Energy Delivery and Australia.
North America Energy - consists of operations of TXU Energy, which
are principally in the competitive Texas market, involving power production,
wholesale energy sales, retail energy sales and services, and portfolio
management, including risk management and certain trading activities.
North America Energy Delivery - consists of operations of Oncor and
TXU Gas, which are largely regulated, involving the transmission and
distribution of electricity and the purchase, transportation, distribution and
sale of natural gas in Texas.
Australia - consists of operations, principally in Victoria and South
Australia, involving the generation of electricity, wholesale sales of energy,
retail energy sales and services in largely competitive markets, portfolio
management and gas storage, as well as regulated electricity and gas
distribution.
Effective with reporting for the first quarter of 2003, results for
the North America Energy segment exclude expenses incurred by the US Holdings
holding company in order to present the segment on the same basis as the
separate reporting for TXU Energy and as the results of the business are
evaluated by management. The activities of the holding company consist primarily
of servicing approximately $160 million of debt. Prior year amounts are
presented on the revised basis.
Certain of the business segments provide services or sell products to
one or more of the other segments. Generally, such sales are made at prices
comparable with those received from nonaffiliated customers for similar products
or services. Effective January 1, 2003, TXU Business Services Company billings
for such services in Corporate and Other are presented for segment reporting
purposes as allocations of costs rather than revenues. Prior year amounts have
been reclassified to conform to this presentation.
24
Three Months Ended Six Months Ended
June 30, June 30,
2003 2002 2003 2002
------- ------ ------- -----
Operating revenues -
North America Energy................... $ 2,045 $2,019 $ 3,851 $ 3,818
North America Energy Delivery.......... 684 657 1,811 1,495
Australia.............................. 274 216 499 428
Corporate and other ................... 29 27 56 57
Eliminations........................... (360) (414) (746) (840)
------- ------ ------- -------
Consolidated......................... $ 2,672 $2,505 $ 5,471 $ 4,958
======= ====== ======= =======
Regulated revenues included in
operating revenues -
North America Energy .................. $ - $ - $ - $ -
North America Energy Delivery.......... 684 657 1,811 1,495
Australia.............................. 28 20 48 34
Corporate and other.................... 27 22 50 45
Eliminations........................... (353) (404) (733) (823)
------- ------ ------- -------
Consolidated......................... $ 386 $ 295 $ 1,176 $ 751
======= ====== ======= =======
Affiliated revenues included in
operating revenues -
North America Energy .................. $ 7 $ 10 $ 13 $ 17
North America Energy Delivery.......... 353 404 733 823
Corporate and other.................... - - - -
Eliminations........................... (360) (414) (746) (840)
------- ------ ------- -------
Consolidated......................... $ - $ - $ - $ -
======= ====== ======= =======
Income from continuing operations
before cumulative effect of changes
in accounting principles -
North America Energy .................. $ 154 $ 183 $ 189 $ 370
North America Energy Delivery.......... 36 41 146 142
Australia ............................. 26 10 53 61
Corporate and other.................... (39) (56) (95) (138)
------- ------ ------- -------
Consolidated......................... $ 177 $ 178 $ 293 $ 435
======= ====== ======= =======
25
9. SUPPLEMENTARY FINANCIAL INFORMATION
Regulated Versus Unregulated Operations --
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ----------------
2003 2002 2003 2002
---- ---- ---- ----
Operating revenues:
Regulated .................................................. $ 739 $ 699 $ 1,909 $ 1,574
Unregulated ................................................ 2,293 2,220 4,308 4,224
Intercompany sales eliminations - regulated ................ (353) (404) (733) (823)
Intercompany sales eliminations - unregulated .............. (7) (10) (13) (17)
------ ------- ------- -------
Total operating revenues .............................. 2,672 2,505 5,471 4,958
------ ------- ------- -------
Costs and operating expenses:
Cost of energy sold and delivery fees - regulated........... 119 90 576 293
Cost of energy sold and delivery fees - unregulated*........ 1,057 893 1,987 1,490
Operating costs - regulated ................................ 219 205 431 392
Operating costs - unregulated .............................. 207 197 420 375
Depreciation and amortization - regulated .................. 103 95 203 186
Depreciation and amortization - unregulated ................ 105 118 229 247
Selling, general and administrative expenses - regulated.... 68 35 109 76
Selling, general and administrative expenses - unregulated.. 201 295 407 592
Franchise and revenue-based taxes - regulated .............. 88 80 162 159
Franchise and revenue-based taxes - unregulated ............ 32 37 69 76
Other income ............................................... (23) (19) (34) (26)
Other deductions ........................................... 7 12 24 59
Interest income ............................................ (10) (7) (19) (15)
Interest expense and other charges ......................... 248 217 496 433
------ ------- ------- -------
Total costs and expenses............................... 2,421 2,248 5,060 4,337
------ ------- ------- -------
Income from continuing operations before income taxes and
cumulative effect of changes in accounting principles....... $ 251 $ 257 $ 411 $ 621
====== ======= ======= =======
--------------
*Includes cost of fuel consumed of $436 million and $372 million for
the three months ended June 30, 2003 and 2002, respectively, and $861
million and $642 million for the six months ended June 30, 2003 and
2002, respectively. The balance in each period represents energy
purchased for resale and delivery fees.
The operations of the North America Energy segment are included above
as unregulated, as the Texas market is open to competition. However, retail
pricing to residential and small business customers in its historical service
territory continues to be subject to transitional regulatory provisions.
Other Income and Deductions --
Three Months Ended Six Months Ended
June 30, June 30,
------------------- ------------------
2003 2002 2003 2002
---- ---- ---- ----
Other income:
Net gain on sale of businesses and other properties. $ 15 $ 15 $ 21 $ 16
Lignite coal royalties.............................. - - - 2
Unrealized foreign exchange gain on Australian dollar
denominated note receivable....................... 7 - 12 -
Allowance for funds used during construction........ 1 1 1 2
Other............................................... - 3 - 6
---- ---- ---- ----
Total other income............................. $ 23 $ 19 $ 34 $ 26
==== ==== ==== ====
Other deductions:
Equity in losses of unconsolidated entities......... $ - $ 11 $ 16 $ 24
Loss on retirement of debt.......................... - - - 27
Charges related to sold business.................... - - - 3
Write-off of frequency licenses..................... 3 - 3 -
Other............................................... 4 1 5 5
---- ---- ---- ----
Total other deductions......................... $ 7 $ 12 $ 24 $ 59
==== ==== ==== ====
26
Interest Expense and Other Charges --
Three Months Ended Six Months Ended
June 30, June 30,
----------------- -----------------
2003 2002 2003 2002
---- ---- ---- ----
Interest................................................... $ 229 $ 197 $ 456 $ 395
Distributions on mandatorily redeemable, preferred securities
of subsidiary trusts, each holding solely junior subordinated
debentures of the obligated company:
TXU Corp. obligated................................... 7 7 15 15
Subsidiary obligated.................................. 3 3 5 5
Preferred stock dividends of subsidiaries................... 3 4 6 7
Amortization of debt discounts, premiums and issuance cost.. 9 10 20 18
Allowance for borrowed funds used during construction
and capitalized interest................................. (3) (4) (6) (7)
----- ----- ----- -----
Total interest expense and other charges............ $ 248 $ 217 $496 $ 433
===== ===== ==== =====
Regulatory Assets and Liabilities --
June 30, December 31,
2003 2002
------- ------
Regulatory Assets:
Generation-related regulatory assets subject to securitization $1,652 $1,652
Securities reacquisition costs............................. 124 124
Recoverable deferred income taxes-- net.................... 79 76
Other regulatory assets.................................... 210 217
------ ------
Total regulatory assets.................................. 2,065 2,069
------ ------
Regulatory Liabilities:
Liability related to excess mitigation credit.............. 91 170
Investment tax credit and protected excess deferred taxes.. 94 99
Other regulatory liabilities............................... - 28
------ ------
Total regulatory liabilities............................. 185 297
------ ------
Net regulatory assets.................................... $1,880 $1,772
====== ======
Included above are assets of $1.9 and $1.8 billion at June 30, 2003
and December 31, 2002, respectively, that were not earning a return. Of the
assets not earning a return, $1.652 billion is expected to be recovered over the
term of the securitization bonds expected to be issued by Oncor in the third
quarter of 2003 and the first half of 2004 pursuant to the regulatory Settlement
Plan. All other regulatory assets have a remaining recovery period of 13 to 48
years.
Included in other regulatory assets as of June 30, 2003 was $41
million related to nuclear decommissioning liabilities.
Restricted Cash -- As of June 30, 2003, all of the restricted cash of
$210 million from the net proceeds of Oncor's issuance of senior secured notes
in December 2002 had been used to pay the interest and principal of Oncor's
first mortgage bonds due April 1, 2003 and November 1, 2023. The remaining
restricted cash reported in investments on the balance sheet as of June 30, 2003
included $111 million held as collateral for letters of credit issued.
Accounts Receivable -- At June 30, 2003 and December 31, 2002,
accounts receivable of $1.5 billion and $1.7 billion are stated net of allowance
for uncollectible accounts of $80 million and $83 million, respectively. During
the six months ended 2003, bad debt expense was $44 million, account write-offs
were $45 million and other activity decreased the allowance for uncollectible
accounts by $2 million.
27
Accounts receivable included $767 million and $644 million of
unbilled revenues at June 30, 2003 and December 31, 2002, respectively.
Intangible Assets -- SFAS 142 became effective on January 1, 2002.
SFAS 142 requires, among other things, the allocation of goodwill to reporting
units based upon the current fair value of the reporting units, and the
discontinuance of goodwill amortization. SFAS 142 also requires additional
disclosures regarding intangible assets (other than goodwill) that are amortized
or not amortized:
As of June 30, 2003 As of December 31, 2002
------------------------------ ----------------------------
Gross Gross
Carrying Accumulated Carrying Accumulated
Amount Amortization Net Amount Amortization Net
--------- ------------ ---- -------- ------------ ----
Amortized intangible assets (included in
property, plant and equipment):
Capitalized software.............. $ 592 $ 268 $324 $540 $217 $323
Land easements.................... 187 71 116 195 68 127
Mineral rights and other.......... 32 20 12 32 21 11
----- ----- ---- ---- ---- ----
Total....................... $ 811 $ 359 $452 $767 $306 $461
===== ===== ==== ==== ==== ====
Unamortized intangible assets -
Licenses (a)................ $ 379 $ 38 $341 $321 $ 32 $289
===== ===== ==== ==== ===== ====
(a) The amortization of indefinite-life licenses was suspended with the adoption
of SFAS No. 142.
Aggregate TXU Corp. amortization expense for intangible assets was
$46 million and $41 million for the six months ended June 30, 2003 and 2002,
respectively.
Changes in the carrying amount of goodwill and other unamortized
intangible assets (net of accumulated amortization) for the quarter ended June
30, 2002, are as follows:
North
North America
America Energy
Energy Delivery Australia Total
------ -------- --------- -----
Balance at December 31, 2002......... $ 533 $ 331 $ 724 $ 1,588
Foreign currency translation effects - - 135 135
------- ------ -------- ---------
Balance at June 30, 2003............ $ 533 $ 331 $ 859 $ 1,723
======= ====== ======== =========
At June 30, 2003 and December 31, 2002, goodwill and other
unamortized intangible assets were stated net of accumulated amortization of
$205 million and $189 million, respectively.
Commodity Contract Assets-- At June 30, 2003 and December 31, 2002,
current and noncurrent commodity contract assets totaling $2.0 billion are
stated net of applicable credit (collection) and performance reserves totaling
$30 million and $44 million, respectively. Performance reserves are provided for
direct, incremental costs to settle the contracts.
28
Inventories by Major Category --
June 30, December 31,
2003 2002
------- ------
Materials and supplies........................ $ 226 $ 227
Fuel stock.................................... 94 91
Gas stored underground........................ 202 175
------ ------
Total inventories......................... $ 522 $ 493
====== ======
Inventories reflect a $22 million reduction as a result of the
rescission of EITF 98-10 as discussed in Note 2.
Property, Plant and Equipment -- As of June 30, 2003 and December
31, 2002, property, plant and equipment of $20.5 billion and $19.6 billion is
stated net of accumulated depreciation and amortization of $11.5 billion and
$11.1 billion, respectively.
As of June 30, 2003, substantially all of Oncor's electric utility
property, plant and equipment (with a net book value of $6.2 billion) was
pledged as collateral for Oncor's first mortgage bonds and senior secured notes.
Derivatives and Hedges -- TXU Corp. experienced net hedge
ineffectiveness of $9 million and $15 million, respectively, reported as a gain
in revenues, for the three and six months ended June 30, 2003. For the three and
six months ended June 30, 2002, net hedge ineffectiveness of $26 million and $34
million, respectively, was recorded as a loss in revenues and was related to
hedges of anticipated sales from baseload generation.
As of June 30, 2003, it is expected that $115 million of after-tax
net losses accumulated in other comprehensive income will be reclassified into
earnings during the next twelve months. Of this amount, $67 million relates to
commodities hedges and $48 million relates to financing-related hedges. This
amount represents the projected value of the hedges over the next twelve months
relative to what would be recorded if the hedge transactions had not been
entered into. The amount expected to be reclassified is not a forecasted loss
incremental to normal operations, but rather it demonstrates the extent to which
volatility in earnings and cash flows (which would otherwise exist) is mitigated
through the use of cash flow hedges.
Supplemental Cash Flow Information --
See Note 1 under Basis of Presentation for a summary of the balance
sheet impact of the consolidation and discontinuance of Pinnacle, which was a
noncash activity.
See Note 2 for the effects of adopting SFAS 143, which were noncash
in nature.
29
INDEPENDENT ACCOUNTANTS' REPORT
TXU Corp.:
We have reviewed the accompanying condensed consolidated balance sheet of TXU
Corp. and subsidiaries (TXU Corp.) as of June 30, 2003, and the related
condensed statements of consolidated income and of comprehensive income for the
three-month and six-month periods ended June 30, 2003 and 2002 and the condensed
statements of consolidated cash flows for the six-month periods ended June 30,
2003 and 2002. These financial statements are the responsibility of TXU Corp.'s
management.
We conducted our reviews in accordance with standards established by the
American Institute of Certified Public Accountants. A review of interim
financial information consists principally of applying analytical procedures and
making inquiries of persons responsible for financial and accounting matters. It
is substantially less in scope than an audit in accordance with auditing
standards generally accepted in the United States of America, the objective of
which is the expression of an opinion regarding the financial statements taken
as a whole. Accordingly, we do not express such an opinion.
Based on our reviews, we are not aware of any material modifications that should
be made to such condensed consolidated financial statements for them to be in
conformity with accounting principles generally accepted in the United States of
America.
We have previously audited, in accordance with auditing standards generally
accepted in the United States of America, the consolidated balance sheet of TXU
Corp. as of December 31, 2002, and the related statements of consolidated
income, comprehensive income, cash flows and shareholders' equity for the year
then ended (not presented herein); and in our report (which includes explanatory
paragraphs related to the adoption of Statement of Financial Accounting
Standards No. 142 and the discontinuance of European operations), dated February
14, 2003 we expressed an unqualified opinion on those consolidated financial
statements. In our opinion, the information set forth in the accompanying
condensed consolidated balance sheet as of December 31, 2002, is fairly stated
in all material respects in relation to the consolidated balance sheet from
which it has been derived.
As discussed in Note 1 to the Notes to Financial Statements, TXU Corp. changed
its method of accounting for asset retirement obligations in 2003 in connection
with the adoption of Statement of Financial Accounting Standards (SFAS) No. 143,
"Accounting for Asset Retirement Obligations," changed its method of accounting
for certain contracts with the rescission of Emerging Issues Task Force Issue
98-10 "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," and changed its method of reporting gains and losses on the
extinguishment of debt in accordance with the adoption of SFAS No. 145,
"Rescission of FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No.
13, and Technical Corrections."
DELOITTE & TOUCHE LLP
Dallas, Texas
August 12, 2003
30
Item 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
BUSINESS
TXU Corp. is an energy company that engages in power production
(electricity generation), wholesale energy sales, retail energy sales and
related services, portfolio management, including risk management and certain
trading activities, energy delivery and, through a business held for sale and
formerly a joint venture, telecommunications services.
The consolidated financial statements for 2002 and discussion of
results of operations of TXU Corp. reflect the reclassification of the TXU
Europe business as discontinued operations (see Note 3 to Financial Statements
for information about discontinued operations).
With respect to the telecommunications business of Pinnacle, in May
2003, TXU Corp. acquired for $150 million in cash the interests it did not
previously own from the joint venture partner under a put/call agreement that
had been executed in late February 2003, and finalized a formal plan to dispose
of the telecommunications business by sale. Accordingly, effective with
reporting for the second quarter of 2003, activities of Pinnacle since March 1,
2003 are reported as discontinued operations. TXU Corp. had used the equity
method of accounting for its investment in Pinnacle until March 1, 2003 when the
business was consolidated as a result of the execution of the put/call
agreement. Accounting rules provide that businesses accounted for under the
equity method should not be reported as discontinued operations; therefore,
results prior to March 1, 2003 are reported in other deductions in the statement
of income, consistent with prior reporting. (Also see Note 3 to Financial
Statements.)
TXU Corp. has three reportable segments: North America Energy, North
America Energy Delivery and Australia. (See Note 8 to Financial Statements for
further information concerning reportable business segments.)
The following exchange rates have been used to convert foreign
currency denominated amounts into US dollars, unless they were determined using
exchange rates on the date of a specific event:
Income Statements
(Average Rates)
---------------------------------------------
Balance Sheets Three Months Six Months
----------------------------- Ended June 30, Ended June 30,
June 30, December 31, ------------------ -------------------
2003 2002 2003 2002 2003 2002
---- ---- ---- ---- ---- ----
Australian dollars (A$) $0.6671 $0.5650 $0.6406 $0.5513 $0.6169 $0.5352
Dollar amounts in the following tables are stated in millions of US
dollars unless otherwise noted.
RESULTS OF OPERATIONS
Consolidated
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002
- -----------------------------------------------------------------------------
Reference is made to comparisons of results by business segment
following the discussion of consolidated results presented below.
TXU Corp.'s operating revenues increased $167 million, or 7%, to $2.7
billion in 2003. Operating revenues rose $58 million, or 27%, in the Australia
segment, driven by the stronger Australian dollar and higher retail electricity
revenues, primarily reflecting higher volumes. Revenues in the North America
Energy Delivery segment rose by $27 million, or 4%, driven by higher gas costs
passed on to retail customers. Revenues in the North America Energy segment
increased $26 million, or 1%, reflecting higher average pricing, partially
offset by the effect of lower sales volumes and lower results from portfolio
management activities, which included realized and unrealized gains and losses
on hedging transactions. Consolidated revenue growth also reflected a $56
million reduction in the intercompany sales elimination, reflecting lower sales
by Oncor to TXU Energy as sales to nonaffiliated REPs increased.
31
Gross Margin
Three Months Ended
June 30,
----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 2,672 100% $ 2,505 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 1,176 44% 983 39%
Operating costs................................... 426 16% 402 16%
Depreciation and amortization related to operating
assets........................................ 190 7% 199 8%
------- ----- ------- ------
Gross margin........................................... $ 880 33% $ 921 37%
======= ===== ======= ======
Gross margin is considered a key operating metric as it measures the
effect of changes in sales volumes and pricing versus the direct variable and
fixed costs of energy sold, whether generated or purchased, as well as the costs
to deliver energy.
The depreciation and amortization expense included in gross margin
excludes $18 million and $14 million of such expense for the three months ended
June 30, 2003 and 2002, respectively, that is not directly related to generation
and delivery property, plant and equipment.
Gross margin decreased $41 million, or 4%, to $880 million in 2003. A
decline in the North America Energy segment's margin of $64 million was driven
by lower sales volumes, primarily in the large commercial/industrial business.
Higher average pricing was largely offset by higher costs of energy sold and
lower results from portfolio management activities. The North America Energy
Delivery segment's gross margin declined $6 million on higher operating costs
and lower revenues in the electricity delivery business. Australia's gross
margin increased $28 million reflecting the stronger Australian dollar, the
effect of higher retail sales volumes and lower costs of energy sold.
Mark-to-market accounting for commodity contracts increased revenues and gross
margin by $54 million in 2003 (as compared to accounting on a settlement basis),
and increased results by $125 million in 2002. Operating costs rose $24 million,
or 6%, primarily due to the timing of generation facility repair and maintenance
expenses, increased pension and other postretirement benefit costs and higher
transmission costs paid to other utilities.
Depreciation and amortization (including amounts shown in the gross
margin table above) decreased $5 million, or 2%, to $208 million in 2003
reflecting adjusted depreciation rates related to the generation fleet primarily
from an extension of the estimated depreciable life of the nuclear generation
facility to better reflect the useful life, partially offset by the effect of
investments in energy delivery facilities to support growth and normal
replacements of equipment.
SG&A expenses decreased $61 million, or 18%, to $269 million in 2003.
The decrease was driven by cost reductions, primarily lower staffing and related
administrative expenses, initiated in response to the completion of the
transition to competition in Texas, the industry-wide decline in portfolio
management activities, and the expected deferral of deregulation of energy
markets in other states. SG&A expenses were also favorably impacted by lower
activity in the small strategic retail services business. Favorable comparisons
of SG&A expenses are expected to continue over the balance of 2003.
Franchise and revenue-based taxes increased $3 million, or 3%, to
$120 million in 2003, primarily due to higher revenues in prior periods on which
this tax is based.
Other income increased $4 million to $23 million in 2003 primarily
due to a $7 million unrealized foreign exchange gain on a note receivable. Net
gains on sales of businesses and properties totaled $15 million in both years.
32
Other deductions decreased $5 million to $7 million in 2003
reflecting the absence of equity losses of $12 million from the Pinnacle joint
venture, partially offset by the write-off of certain communications licenses.
Interest income rose $3 million, or 43%, to $10 million in 2003. The
increase primarily reflected interest income on higher cash balances due to
actions to ensure ample liquidity, as well as interest received on restricted
cash to support financing of construction of a natural gas pipeline in Australia
by a joint venture.
Interest expense and other charges increased $31 million, or 14%, to
$248 million in 2003, reflecting a $24 million increase due to higher average
interest rates resulting in part from the refinancing of lower-rate short-term
borrowings with higher rate long-term debt, a $6 million increase due to
higher average debt levels reflecting actions taken to ensure ample liquidity
and a $1 million increase due to higher amortization of discount related to the
TXU Energy exchangeable subordinated notes.
The effective income tax rate on income from continuing operations
before cumulative effect of changes in accounting principles was 29.5% in 2003
and 30.7% in 2002. There were no significant unusual items impacting the
effective rates.
Income from continuing operations before cumulative effect of changes
in accounting principles decreased $1 million to $177 million in 2003. This
performance reflected a decline of $29 million, or 16%, in the North America
Energy segment, driven by the decrease in gross margin, a $5 million, or 12%,
decrease in the North America Energy Delivery segment, largely due to lower
revenues and higher interest expense at Oncor, and growth of $16 million in the
Australia segment on higher volumes, lower power costs and the stronger
Australian dollar. The segment performances are discussed below. Corporate and
Other expenses declined $17 million due to the absence of equity losses from the
Pinnacle joint venture ($12 million) and lower interest expense, reflecting
commercial paper outstanding in the prior year. Net pension and postretirement
benefit costs reduced income from continuing operations by $23 million in 2003
and $16 million in 2002.
Diluted earnings per share available to common shareholders from
continuing operations before cumulative effect of changes in accounting
principles decreased $0.15, or 23%, to $0.49 per share in 2003. Of this decline,
$0.18 per share is due to a 41% increase in average shares in the computation
offset by $0.03 per share due to increased earnings (earnings in the calculation
reflect lower interest expense on the assumed conversion of exchangeable notes).
The increase in average shares reflected the issuance of common stock in June,
August and December 2002 and the dilutive effect of 57.1 million shares issuable
in connection with the $750 million of exchangeable subordinated notes issued in
November 2002.
Income (loss) from discontinued operations, including tax effects,
was a loss of $66 million in 2003, reflecting a $60 million deferred income tax
charge related to the telecommunications business on the excess of the carrying
value of the investment in the business over the tax basis. The income from
discontinued operations of $23 million in 2002 represents earnings of the TXU
Europe business.
Net income available to common shareholders decreased $90 million, or
46%, to $105 million in 2003. The decline was due to the effect of the
discontinued operations loss in 2003 compared to the gain in 2002.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
- -------------------------------------------------------------------------
TXU Corp.'s operating revenues increased $513 million, or 10%, to
$5.5 billion in 2003. Revenues in the North America Energy Delivery segment rose
by $316 million, or 21% driven by higher gas costs passed on to customers.
Operating revenues rose $71 million, or 17%, in the Australia segment driven by
the translation effect of a stronger Australian dollar, as the benefit of higher
retail sales volumes was largely offset by the effect of a $30 million gain in
2002 on termination of a wholesale power contract. Revenues in the North America
Energy segment increased $33 million reflecting higher average pricing and
higher results from portfolio management activities, largely offset by the
effect of lower sales volumes. Consolidated revenue growth also reflected a $93
million reduction in the intercompany sales elimination, reflecting lower sales
by Oncor to TXU Energy as sales to nonaffiliated REPs increased.
33
Gross Margin
Six Months Ended
June 30,
-------------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 5,471 100% $ 4,958 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 2,563 47% 1,783 36%
Operating costs................................... 851 16% 767 15%
Depreciation and amortization related to operating
assets........................................ 394 7% 392 8%
------- ----- ------- ------
Gross margin........................................... $ 1,663 30% $ 2,016 41%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $38 million and $41 million of such expense for the six months ended
June 30, 2003 and 2002, respectively, that is not directly related to generation
and delivery property, plant and equipment.
Gross margin decreased $353 million, or 18%, to $1.7 billion in 2003.
A decline of $366 million at the North America Energy segment reflected higher
costs of energy sold that was only partially offset by higher average pricing
and higher portfolio management results, as well as the effect of lower sales
volumes. Australia's gross margin rose $13 million reflecting the effects of a
stronger Australian dollar, higher volumes and lower costs of energy sold,
partially offset by the effect of a $30 million gain in 2002 on termination of
a wholesale contract. The North America Energy Delivery segment's gross margin
was even with 2002. Mark-to-market accounting for commodity contracts increased
revenues and gross margin by $27 million in 2003 (as compared to accounting on
a settlement basis), and increased results by $6 million in 2002. Operating
costs rose $84 million, or 11%, primarily due to increased pension and other
postretirement benefit costs, higher transmission costs paid to other utilities,
employee severance costs associated with cost reduction initiatives and
increased insurance expenses.
Depreciation and amortization (including amounts shown in the gross
margin table above) decreased $1 million to $432 million in 2003 reflecting
adjusted depreciation rates related to TXU Energy's generation fleet, primarily
from an extension of the estimated depreciable life of the nuclear generation
facility, to better reflect its useful life, partially offset by the effect of
investments in delivery facilities to support growth and normal replacements of
equipment.
SG&A expense decreased $152 million, or 23%, to $516 million in 2003.
The decrease was driven by lower levels of bad debt expense, reflecting
reduction in the billing and collection delays experienced in 2002 in connection
with the transition to competition, and cost reduction initiatives as discussed
above. Favorable comparisons of SG&A expenses are expected to continue over the
balance of 2003.
Franchise and revenue-based taxes decreased $4 million, or 2%, to
$231 million in 2003, due primarily to lower retail revenues on which gross
receipts taxes are based.
Other income increased $8 million to $34 million in 2003. The 2003
period includes a net $9 million gain on the sale of certain
commercial/industrial retail gas operations and $12 million of unrealized
foreign exchange gains on an Australian dollar denominated note receivable.
Other deductions decreased $35 million to $24 million in 2003. The
2002 period includes a $27 million loss on retirement of debt. Equity losses on
unconsolidated subsidiaries, principally Pinnacle (until March 2003), were $16
million in 2003 and $24 million in 2002.
Interest income rose $4 million, or 27%, to $19 million in 2003. The
increase primarily reflected interest income on higher cash balances due to
actions to ensure ample liquidity, as well as interest received on restricted
cash to support funding of construction of a natural gas pipeline in Australia
by a joint venture.
Interest expense and other charges increased $63 million, or 15%, to
$496 million in 2003, reflecting a $33 million increase due to higher average
interest rates resulting in part from the replacement of lower-rate short-term
borrowings with higher rate long-term debt, a $27 million increase due to higher
average debt levels reflecting actions taken to enhance liquidity and a $3
million increase due to higher amortization of discount related to the TXU
Energy exchangeable subordinated notes.
34
The effective income tax rate on income from continuing operations
before cumulative effect of changes in accounting principles was 28.7% in 2003
and 30.0% in 2002. There were no significant unusual items impacting the
effective rates.
Income from continuing operations before cumulative effect of changes
in accounting principles decreased $142 million, or 33%, to $293 million in
2003. This performance reflected a decline of $181 million, or 49%, in the North
America Energy segment driven by the lower gross margin. The North America
Energy segment results also reflected a $16 million (after-tax) gain, primarily
reported in revenues, on the settlement of outstanding counterparty default
events and $9 million (after-tax) in severance charges. An earnings decline in
the Australia segment of $8 million, or 13%, reflected the effect of a $30
million gain (pre and after-tax) in 2002 on termination of a wholesale contract,
partially offset by the benefits of higher retail volumes, lower costs of energy
sold and a stronger Australian dollar. Earnings growth in the North America
Energy Delivery segment of $4 million, or 3%, was driven by higher base
distribution rates and lower interest expense in the gas business. The segment
performances are discussed below. Corporate and Other expenses declined $43
million due primarily to lower interest expense, reflecting commercial paper
outstanding in the prior year, a loss on retirement of debt in 2002 of $18
million (after-tax) and the absence of a portion of equity losses from the
Pinnacle business, which is now accounted for as discontinued operations. Net
pension and postretirement benefit costs reduced income from continuing
operations by $47 million in 2003 and $31 million in 2002.
Income (loss) from discontinued operations, including tax effects,
reflected a loss in 2003 of $79 million related to the telecommunications
business, including a $60 million tax charge as discussed above, and income in
2002 of $21 million representing the results of the TXU Europe operations.
The cumulative effect of changes in accounting principles,
representing an after-tax charge of $58 million in 2003, reflects the rescission
of EITF Issue 98-10 and the adoption of SFAS 143. See Note 2 to Financial
Statements for further discussion.
Diluted earnings per share from continuing operations before
cumulative effect of changes in accounting principles available to common
shareholders decreased $0.77, or 48%, to $0.82 per share in 2003. Of this
decline, $0.46 per share is due to a 42% increase in average shares in the
computation and $0.31 per share is due to lower earnings. The increase in
average shares reflected the issuance of common stock in June, August and
December 2002 and the dilutive effect of 57.1 million shares issuable in
connection with the $750 million of exchangeable subordinated notes issued in
November 2002.
Net income available to common shareholders decreased $300 million,
or 67%, to $145 million in 2003. The decline reflected the $58 million charge
related to accounting changes, the decrease of $100 million in results from
discontinued operations and the $142 million earnings decrease before these
items, as discussed above.
35
COMMODITY CONTRACTS AND MARK-TO-MARKET ACTIVITIES
The table below summarizes the changes in commodity contract assets
and liabilities for the six months ended June 30, 2003. The net increase,
excluding "cumulative effect of change in accounting principle" and "other
activity" as described below, of $27 million represents the net favorable effect
of mark-to-market accounting on earnings for the six months ended June 30, 2003.
This effect represents the difference between earnings under mark-to-market
accounting versus accounting for gains and losses upon settlement of the
contracts.
Balance of net commodity contract assets at December 31, 2002................ $ 297
Cumulative effect of change in accounting principle (1) ..................... (75)
Settlements of positions included in the opening balance (2) ................ (80)
Unrealized mark-to-market valuations of positions held at end of period (3).. 107
Other activity (4)........................................................... 12
-----
Balance of net commodity contract assets at June 30, 2003 ................... $ 261
=====
--------------------------
(1) Represents a portion of the pre-tax cumulative effect of the rescission
of EITF Issue 98-10 (see Note 2 to Financial Statements).
(2) Represents unrealized mark-to-market valuations of these positions
recognized in earnings as of the beginning of the period.
(3) There were no significant changes in fair value attributable to changes
in valuation techniques.
(4) Includes initial values of positions involving the receipt or payment
of cash or other consideration, such as option premiums, amortization
of such values, the sale of certain retail commercial and industrial
gas operations and the impact of currency translation. These
activities have no effect on unrealized mark-to-market valuations.
As a result of guidance provided in EITF 02-3, TXU Corp. has not
recognized origination gains on commercial/industrial retail contracts in 2003.
For the three- and six-month periods ended June 30, 2002, TXU Corp. had
recognized $21 million and $34 million in origination gains on such contracts,
respectively.
Maturity Table -- Of the net commodity contract asset balance above
at June 30, 2003, the amount representing unrealized mark-to-market net gains
that have been recognized in current and prior years' earnings is $330 million.
The offsetting net liability of $69 million included in the June 30, 2003
balance sheet is comprised principally of amounts representing current and prior
years' net receipts of cash or other consideration, including option premiums,
associated with contract positions, net of any amortization. The following table
presents the unrealized mark-to-market balance at June 30, 2003, scheduled by
contractual settlement dates of the underlying positions.
Maturity dates of unrealized net mark-to-market balances at June 30, 2003
----------------------------------------------------------------------------
Maturity less Maturity in
than Maturity of Maturity of Excess of
Source of fair value 1 year 1-3 years 4-5 years 5 years Total
- ---------------------- --------- ----------- ----------- -------- -----
Prices actively quoted........... $ (7) $ - $ - $ - $ (7)
Prices provided by other
external sources............. 177 88 7 (1) 271
Prices based on models........... 30 14 1 21 66
---- ---- --- ---- -----
Total............................ $200 $102 $ 8 $ 20 $ 330
==== ==== === ==== =====
Percentage of total fair value... 61% 31% 2% 6% 100%
As the above table indicates, approximately 92% of the unrealized
mark-to-market valuations at June 30, 2003 mature within three years. This is
reflective of the terms of the positions and the methodologies employed in
valuing positions for periods where there is less market liquidity and
visibility. The "prices actively quoted" category reflects only exchange traded
contracts with active quotes available through 2005 in the US. The "prices
provided by other external sources" category represents forward commodity
positions at locations for which over-the-counter broker quotes are available.
Over-the-counter quotes for power and natural gas generally extend through 2005
and 2012, respectively, in the US. The "prices based on models" category
36
contains the value of all non-exchange traded options, valued using industry
accepted option pricing models. In addition, this category contains other
contractual arrangements which may have both forward and option components. In
many instances, these contracts can be broken down into their component parts
and modeled as simple forwards and options based on prices actively quoted. As
the modeled value is ultimately the result of a combination of prices from two
or more different instruments, it has been included in this category.
SEGMENTS
North America Energy
- --------------------
Financial Results
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- -------------------
2003 2002 2003 2002
--------- -------- --------- -------
Operating revenues.......................................... $ 2,045 $ 2,019 $ 3,851 $ 3,818
------- ------- --------- -------
Costs and expenses:
Cost of energy sold and delivery fees.................. 1,282 1,185 2,500 2,126
Operating costs........................................ 186 178 379 340
Depreciation and amortization.......................... 95 107 208 226
Selling, general and administrative expenses........... 153 217 297 437
Franchise and revenue-based taxes ..................... 27 26 55 56
Other income .......................................... (16) (13) (24) (15)
Other deductions....................................... 3 2 5 5
Interest income........................................ (1) - (3) (9)
Interest expense and other charges..................... 86 50 163 109
------- ------- ------- -------
Total costs and expenses........................... 1,815 1,752 3,580 3,275
------- ------- ------- -------
Income before income taxes and cumulative effect of
changes in accounting principles........................ 230 267 271 543
Income tax expense.......................................... 76 84 82 173
------- ------- ------- -------
Income before cumulative effect of changes in accounting
principles................................................ $ 154 $ 183 $ 189 $ 370
======= ======= ======= =======
37
North America Energy
- --------------------
Segment Highlights
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
2003 2002 2003 2002
---- ---- ---- ----
Operating statistics:
Retail electric sales volumes (GWh) ........................ 19,804 22,771 39,202 45,157
Wholesale electric sales volumes (GWh)...................... 8,384 7,115 15,835 13,314
Retail electric customers (end of period & in
thousands-number of meters)............................... 2,649 2,731
Operating revenues (millions of dollars):
Retail electric:
Residential........................................... $ 808 $ 781 $ 1,492 $ 1,476
Commercial and industrial ............................ 832 831 1,580 1,881
------- ------- ------- -------
Total........................................... 1,640 1,612 3,072 3,357
Wholesale electric ......................................... 281 209 518 355
Portfolio management activities............................. 62 112 153 49
Other revenues.............................................. 62 86 108 57
------- ------- ------- -------
Total operating revenues......................... $ 2,045 $ 2,019 $ 3,851 $ 3,818
======= ======= ======= =======
Weather (average for service territory)
Percent of normal:
Cooling degree days............................... 107.0% 106.6% 104.7% 106.1%
Heating degree days............................... 64.0% 69.0% 103.9% 99.2%
- --------------------------
Weather data is obtained from Meteorlogix, a private company that collects
weather data from reporting stations of the National Oceanic and Atmospheric
Administration (a federal agency under the US Department of Commerce).
38
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002
- -----------------------------------------------------------------------------
Effective with reporting for 2003, results for the segment exclude
expenses incurred by the US Holdings parent company in order to present the
segment on the same basis as the separate reporting (on Form 8-K) for TXU Energy
and as the results of the business are evaluated by management. The activities
of the parent company consist primarily of the servicing of approximately $160
million of debt. Prior year amounts are presented on the revised basis.
Operating revenues increased $26 million, or 1%, to $2.0 billion in
2003. Retail and wholesale electric revenues increased $100 million, or 5%, to
$1.9 billion, reflecting a $203 million increase due to higher average prices
partially offset by a $103 million reduction due to lower sales volumes. The
price variance primarily reflects the effect of increased price-to-beat rates,
due to approved fuel factor increases and higher pricing in the large commercial
and industrial business, both resulting from higher natural gas costs. The
volume variance primarily reflects a 13% decline in overall retail electric
sales volumes due to the effects of increased competitive activity, primarily in
the large commercial and industrial segment of the market. The effect of lower
retail volumes was partially offset by an 18% increase in wholesale electric
volumes, reflecting a partial shift in the large commercial and industrial
customer base from retail to wholesale services. Results from portfolio
management activities, which include realized and unrealized gains and losses on
hedging transactions, declined $50 million due primarily to the effect of less
favorable price movements on commodity contract positions. Other revenues
declined $24 million due largely to the effect of discontinuing recognition of
origination gains on commercial/industrial retail contracts.
Gross Margin
Three Months Ended
June 30,
---------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 2,045 100% $ 2,019 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 1,282 63% 1,185 59%
Operating costs................................... 186 9% 178 9%
Depreciation and amortization related to generation
assets........................................ 87 4% 102 5%
------- ----- ------- ------
Gross margin........................................... $ 490 24% $ 554 27%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $8 million and $5 million of such expense for the three months ended
June 30, 2003 and 2002, respectively, that is not directly related to generation
property, plant and equipment.
Gross margin decreased $64 million, or 12%, to $490 million in 2003.
The decrease was driven by lower retail sales volumes, primarily in the large
commercial/industrial business. Higher average pricing was largely offset by
higher costs of energy sold and lower portfolio management results. Increased
power costs reflected higher natural gas costs and an outage at the nuclear
generation plant as a result of a lightning strike on a transmission line.
Mark-to-market accounting for commodity contracts increased revenues and gross
margin by $56 million in 2003 and by $134 million in 2002 (as compared to
accounting on a settlement basis). Operating costs rose $8 million, or 4%, to
$186 million primarily due to the timing of repair and maintenance expenses.
In July 2003, an unexpected outage occurred in one of the units at
the Comanche Peak nuclear generation facility in order to repair a reactor
coolant water pump, resulting in approximately $20 million in higher costs of
energy sold that will be reflected in third quarter results.
In July 2003, TXU Energy filed a request with the Commission to
raise its price-to-beat rates as a result of higher natural gas prices. The
Commission has 45 days from the filing of the request, or as soon as practical
thereafter, to review the request, which would increase revenues by an estimated
$180 million on an annualized basis ($50 million for the remainder of 2003, if
approved in mid-September).
39
A decrease in depreciation and amortization (including amounts shown
in the gross margin table above) of $12 million, or 11%, to $95 million in 2003
included a $13 million decline due to adjusted depreciation rates related to TXU
Energy's generation fleet effective with second quarter reporting. This
adjustment reflects an extension in the estimated depreciable life of its
nuclear generation facility of approximately 11 years (to 2041) to better
reflect its useful life, partially offset by higher depreciation rates for
lignite and gas facilities to reflect investments made in recent years.
A decrease in SG&A expenses of $64 million, or 29%, to $153 million
in 2003 was driven by cost reductions, primarily lower staffing and related
administrative expenses, initiated in response to the completion of the
transition to competition in Texas, the industry-wide decline in portfolio
management activities and the expected deferral of deregulation of energy
markets in other states. Lower SG&A expenses also reflected lower levels of bad
debt expense, reflecting reduction in the billing and collection delays
experienced in 2002 in connection with the transition to competition. SG&A
expenses were also favorably impacted by lower activity in the small strategic
retail services business. Favorable comparisons of SG&A expenses are expected to
continue over the balance of 2003.
Other income increased by $3 million to $16 million in 2003. Other
income included net gains on sales of properties and businesses of $15 million
in 2003, including a $3 million net gain on the sale of certain retail
commercial and industrial gas operations, and $12 million in 2002.
Interest expense and other charges increased $36 million, or 72%, to
$86 million in 2003. The increase reflects $28 million due to higher average
interest rates, including credit line fees, $3 million due to higher average
debt levels and $5 million in amortization of the discount on the exchangeable
subordinated notes issued by TXU Energy in November 2002. Higher average
interest rates were due in part to replacement of short-term borrowings with
higher rate long-term debt.
The effective tax rate increased to 33.0% in 2003 from 31.5% in
2002. The increase was driven by higher state income tax accruals.
Income before cumulative effect of changes in accounting principles
decreased $29 million, or 16%, to $154 million in 2003. The decline was driven
by the decrease in gross margin and the increase in interest expense, partially
offset by decreased SG&A and depreciation and amortization expenses. Net pension
and postretirement benefit costs reduced net income by $9 million in 2003 and $5
million in 2002.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
- -------------------------------------------------------------------------
Operating revenues increased $33 million, or 1%, to $3.9 billion in
2003. Retail and wholesale electric revenues declined $122 million, or 3%, to
$3.6 billion, reflecting a $218 million reduction due to lower volumes partially
offset by a $96 million increase due to higher average prices. The volume
variance primarily reflects a 13% decline in overall retail electric sales
volumes due to the effects of increased competitive activity, primarily in the
large commercial and industrial segment of the market. The effect of lower
retail volumes was partially offset by a 19% increase in wholesale electric
volumes reflecting a partial shift in the large commercial and industrial
customer base from retail to wholesale services. The price variance reflects the
effect of increased price-to-beat rates and higher wholesale electric sales
prices, both resulting from higher natural gas prices. Results from portfolio
management activities, which include realized and unrealized gains and losses on
hedging transactions, rose $104 million due primarily to the effect of more
favorable price movements on commodity contract positions. Other revenues
increased $51 million due in part to activity in the small strategic retail
services business.
40
Gross Margin
Six Months Ended
June 30,
------------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 3,851 100% $ 3,818 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 2,500 65% 2,126 56%
Operating costs................................... 379 10% 340 9%
Depreciation and amortization related to generation
assets........................................ 189 5% 203 5%
------- ----- ------- ------
Gross margin........................................... $ 783 20% $ 1,149 30%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $19 million and $23 million of such expense for the six months ended
June 30, 2003 and 2002, respectively, that is not directly related to generation
property, plant and equipment.
Gross margin decreased $366 million, or 32%, to $783 million in
2003. The decrease reflected the effect of increased costs of energy sold that
exceeded higher average pricing and higher portfolio management results. Lower
retail sales volumes, primarily in the large commercial/industrial business,
also contributed to the decline in margin. Increased power costs reflected
higher natural gas costs and an outage at the nuclear generation plant as a
result of a lightning strike on a transmission line. Mark-to-market accounting
for commodity contracts increased revenues and gross margin by $33 million in
2003 and decreased results by $12 million in 2002 (as compared to accounting on
a settlement basis). Operating costs rose $39 million, or 11%, to $379 million
primarily due to the timing of repair and maintenance expenses, higher costs in
the small strategic retail services business, higher pension and other
postretirement benefit expenses and employee severance costs associated with
cost reduction initiatives.
In July 2003, an unexpected outage occurred in one of the units at
the Comanche Peak nuclear generation facility in order to repair a reactor
coolant water pump, resulting in approximately $20 million in higher costs of
energy sold that will be reflected in third quarter results.
In July 2003, TXU Energy filed a request with the Commission to
raise its price-to-beat rates as a result of higher natural gas prices. The
Commission has 45 days from the filing of the request, or as soon as practical
thereafter, to review the request, which would increase revenues by an estimated
$180 million on an annualized basis ($50 million for the remainder of 2003, if
approved in mid-September).
A decrease in depreciation and amortization (including amounts shown
in the gross margin table above) of $18 million, or 8%, to $208 million in 2003
was primarily due to a $13 million decline due to adjusted depreciation rates
related to TXU Energy's generation fleet as discussed above and the timing of
intangible asset amortization expense during the 2002 year.
A decrease in SG&A expenses of $140 million, or 32%, to $297 million
in 2003 was driven by lower levels of bad debt expense, reflecting the reduction
in billing and collection delays experienced in 2002 in connection with the
transition to competition, and cost reduction initiatives as discussed above.
Favorable comparisons of SG&A expenses are expected to continue over the balance
of 2003.
Other income increased by $9 million to $24 million in 2003. Other
income included net gains on sales of properties and businesses of $24 million
in 2003, including a $9 million gain on the sale of certain retail commercial
and industrial gas operations, and $12 million in 2002.
Interest income declined by $6 million, or 67%, to $3 million in
2003 primarily due to lower average advances to affiliates.
Interest expense and other charges increased $54 million, or 50%, to
$163 million in 2003. The increase reflects $33 million due to higher average
interest rates, including credit line fees, $11 million due to higher average
debt levels and $10 million in amortization of the discount on the exchangeable
subordinated notes issued by TXU Energy in November 2002. Higher average
interest rates were due in part to replacement of short-term borrowings with
higher rate long-term debt.
41
The effective tax rate decreased to 30.3% in 2003 from 31.9% in
2002. The decrease was driven by the effect of comparable (to 2002) tax benefit
amounts of depletion allowances and amortization of investment tax credits on a
lower income base in 2003.
Income before cumulative effect of changes in accounting principles
decreased $181 million, or 49%, to $189 million in 2003. The decline was driven
by the decrease in gross margin and the increase in interest expense, partially
offset by decreased SG&A and depreciation and amortization expenses. Results for
the six months reflected a $16 million (after-tax) gain on the settlement of
outstanding counterparty default events and $9 million (after-tax) in severance
charges. Net pension and postretirement benefit costs reduced net income by $18
million in 2003 and by $11 million in 2002.
42
North America Energy Delivery
- -----------------------------
Financial Results
Three Months Ended Six Months Ended
June 30, June 30,
------------------- -------------------
2003 2002 2003 2002
---- ---- ---- ----
Operating revenues............................................ $ 684 $ 657 $ 1,811 $ 1,495
------- ------- ------- -------
Costs and expenses:
Cost of energy sold and delivery fees.................... 89 72 519 252
Operating costs.......................................... 217 204 428 389
Depreciation and amortization............................ 87 84 174 163
Selling, general and administrative expenses............. 82 90 166 182
Franchise and revenue-based taxes ....................... 88 80 162 159
Other income ............................................ (1) (6) (3) (4)
Other deductions......................................... - - - 1
Interest income.......................................... (14) (10) (30) (21)
Interest expense and other charges ...................... 86 82 178 161
------- ------- ------- -------
Total costs and expenses............................. 634 596 1,594 1,282
------- ------- ------- -------
Income before income taxes.................................... 50 61 217 213
Income tax expense............................................ 14 20 71 71
------- ------- ------- -------
Net income ................................................... $ 36 $ 41 $ 146 $ 142
======= ======= ======= =======
- -----------------
The North America Energy Delivery segment includes the electricity T&D
business of Oncor and the natural gas pipeline and distribution business of
TXU Gas, both of which are subject to regulation by Texas authorities.
43
North America Energy Delivery
- -----------------------------
Segment Highlights
Three Months Ended Six Months Ended
June 30, June 30,
----------------------- -------------------
2003 2002 2003 2002
-------- -------- --------- --------
Operating statistics
Delivered electricity volumes (GWh).................................... 24,378 26,232 48,286 49,818
====== ====== ====== ======
Retail gas distribution volumes (Billion cubic feet-Bcf):
Residential...................................................... 8 10 53 51
Commercial....................................................... 8 9 32 31
Industrial and electric generation............................... 1 1 3 4
------ -------- -------- --------
Total gas sales............................................ 17 20 88 86
====== ======== ======== ========
Pipeline transportation volumes (Bcf).................................. 92 116 178 218
====== ======== ======== ========
Retail gas distribution customers and electric points of
delivery (end of period and in thousands):
Retail gas distribution customers................................. 1,458 1,433
Electric points of delivery....................................... 2,909 2,887
Operating revenues (millions of dollars)
Electricity distribution:
North America Energy.............................................. $ 349 $ 397 $ 726 $ 813
Non-affiliated retail electric providers.......................... 137 103 266 181
------ -------- -------- --------
Total ..................................................... 486 500 992 994
------ -------- -------- --------
Retail gas distribution:
Residential....................................................... 94 76 495 299
Commercial........................................................ 66 44 249 142
Industrial and electric generation................................ 10 5 20 13
------ -------- -------- --------
Subtotal .................................................. 170 125 764 454
Pipeline transportation................................................ 12 17 28 29
Other revenues, net of eliminations.................................... 16 15 27 18
------ -------- -------- --------
Total retail gas distribution and pipeline transportation.. 198 157 819 501
------ -------- -------- --------
Total operating revenues............................................... 684 $ 657 $ 1,811 $ 1,495
====== ======== ======== ========
44
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002
- -----------------------------------------------------------------------------
Operating revenues for the North America Energy Delivery segment
increased $27 million, or 4%, to $684 million in 2003. Gas delivery revenues
increased $41 million, or 26%, to $198 million, reflected higher gas costs
passed on to customers and $3 million in higher base distribution rates,
partially offset by the effect of lower gas sales volumes of $8 million. The
average cost of gas rose 63%, while sales volumes decreased 15% due to warmer
weather. Electricity delivery revenues decreased $14 million, or 3%, to $486
million. The decrease reflects higher unbilled revenues in 2002 resulting from
billing issues associated with the transition to competition, as previously
disclosed. Delivered electricity volumes for the year 2003 are expected to grow
2% over the 2002 levels. The revenue decline was partially offset by $8 million
in increased disconnect/reconnect fees due to new POLR rules in 2003 and greater
competition-related customer switching activities and $2 million in higher
electric transmission revenues due to increased tariffs. Increased electric
transmission tariffs approved by the Commission and effective in May 2003 and a
related increase in distribution tariffs, expected to be approved by the
Commission in September 2003, are expected to result in an estimated $44 million
in incremental revenues on an annualized basis.
Gross Margin
Three Months Ended
June 30,
----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
------ ------- ------ -------
Operating revenues......................................... $ 684 100% $ 657 100%
Costs and expenses:
Cost of gas sold...................................... 89 13% 72 11%
Operating costs....................................... 217 32% 204 31%
Depreciation and amortization related to T&D assets... 84 12% 81 12%
------- ----- ------- ------
Gross margin............................................... $ 294 43% $ 300 46%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $3 million of such expense for the three months ended June 30, 2003 and
2002, respectively, that is not directly related to delivery property, plant and
equipment.
Gross margin decreased $6 million, or 2%, to $294 million in 2003.
The decrease reflected lower revenues in the electricity business and higher
operating costs, partially offset by the effect of higher base distribution
rates in the gas business. The increase in operating costs of $13 million, or
6%, to $217 million was driven by higher transmission costs paid to other
utilities, increased pension and other postretirement benefit costs and higher
costs to support the growth of the utility asset management services business.
Depreciation and amortization (including amounts shown in the gross
margin table above), increased $3 million, or 4%, to $87 million in 2003. The
increase reflected investments in delivery facilities to support growth and
normal replacements of equipment.
SG&A expenses decreased by $8 million, or 9%, to $82 million in 2003
due primarily to lower employee-related and outside consulting expenses arising
from cost reduction initiatives implemented in late 2002.
Franchise and revenue-based taxes increased $8 million, or 10%, to
$88 million in 2003 reflecting higher local gross receipts taxes due to higher
revenues on which this tax is based.
Other income decreased by $5 million to $1 million in 2003 reflecting
gains on sales of property in 2002.
Interest income increased $4 million, or 40%, to $14 million in 2003
due primarily to higher interest reimbursements from TXU Energy. This increase
reflects higher carrying costs ($7 million) on regulatory assets (see discussion
of higher average interest rates below), partially offset by lower interest ($4
million) on the note receivable related to the excess mitigation credit. The
note principal has declined as the credit nears the year-end 2003 expiration
date.
45
Interest expense and other charges rose by $4 million, or 5%, to $86
million in 2003, driven by higher average interest rates and borrowings in the
electricity business, partially offset by less interest passed to REPs related
to the excess mitigation credit. Interest expense in the gas business declined
on lower borrowings. The increase in average interest rates reflected the
refinancing of affiliate borrowings with long-term debt issuances.
The effective income tax rate was 28.0% in 2003 compared to 32.8% in
2002, primarily reflecting comparable amortization of investment tax credits and
other items for tax purposes on lower pre-tax earnings.
Net income decreased $5 million, or 12%, to $36 million in 2003,
reflecting a decline in the electricity business of $13 million, partially
offset by decreased losses in the gas business of $8 million. The decline in the
electricity business was driven by lower revenues and higher interest expense.
The performance in the gas business reflected lower interest expense and
improved gross margin. Net pension and postretirement benefit costs reduced net
income by $11 million in 2003 and $9 million in 2002.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
- -------------------------------------------------------------------------
Operating revenues for the North America Energy Delivery segment
increased $316 million, or 21%, to $1.8 billion in 2003. Gas delivery revenues
increased $318 million, or 63%, to $819 million, due to the effects of higher
gas costs passed on to customers, $13 million from increased volumes and an
estimated $8 million from higher base distribution rates. The average cost of
gas rose 91% while sales volumes increased 2%. Electricity delivery revenues
decreased $2 million to $992 million in 2003. The decrease reflects higher
unbilled revenues in 2002 resulting from billing issues associated with the
transition to competition, as previously disclosed. Delivered electricity
volumes for the year 2003 are expected to grow 2% over the 2002 levels. The
revenue decline was partially offset by $14 million in increased
disconnect/reconnect fees due to new POLR rules in 2003 and greater
competition-related customer switching activities and $2 million in higher
electric transmission revenues due to increased tariffs. Increased electric
transmission tariffs approved by the Commission and effective in May 2003 and a
related increase in distribution tariffs, expected to be approved by the
Commission in September 2003, are expected to result in an estimated $44 million
in incremental revenues on an annualized basis.
Gross Margin
Six Months Ended
June 30,
----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ----- -------
Operating revenues..................................... $ 1,811 100% $ 1,495 100%
Costs and expenses:
Cost of gas sold.................................. 519 29% 252 17%
Operating costs................................... 428 24% 389 26%
Depreciation and amortization related to T&D assets 168 9% 158 11%
------- ----- ------- -----
Gross margin........................................... $ 696 38% $ 696 46%
======= ===== ======= =====
The depreciation and amortization expense included in gross margin
excludes $6 million and $5 million of such expense for the six months ended June
30, 2003 and 2002, respectively, that is not directly related delivery property,
plant and equipment.
Gross margin remained flat at $696 million in 2003. This comparison
primarily reflects the impact of base distribution rate increases and higher
volumes in the gas business, offset by higher operating costs, largely in the
electricity delivery business. The increase in operating costs of $39 million,
or 10%, to $428 million was driven by higher transmission costs paid to other
utilities and increased pension and other postretirement benefit costs.
46
Depreciation and amortization (including amounts shown in the gross
margin table above), increased $11 million, or 7%, to $174 million in 2003. The
increase reflected investments in delivery facilities to support growth and
normal replacements of equipment.
SG&A expenses decreased by $16 million, or 9%, to $166 in 2003
million due primarily to lower employee-related and outside consulting expenses
arising from cost reduction initiatives implemented in late 2002.
Franchise and revenue-based taxes increased $3 million, or 2%, to
$162 million in 2003 reflecting higher local gross receipts taxes due to higher
revenues on which this tax is based.
Interest income increased $9 million, or 43%, to $30 million in 2003
due primarily to higher interest reimbursements from TXU Energy. This increase
reflects higher carrying costs ($13 million) on regulatory assets (see
discussion of higher average interest rates below), partially offset by lower
interest ($7 million) on the note receivable related to the excess mitigation
credit. The note principal has declined as the credit nears the year-end 2003
expiration date.
Interest expense and other charges rose by $17 million, or 11%, to
$178 million in 2003, driven by higher average interest rates and borrowings in
the electricity business. Interest expense in the gas business declined on lower
borrowings. The higher average interest rates reflected issuances of long-term
debt to replace lower rate advances from affiliates.
The effective income tax rate was 32.7% in 2003 and 33.3% in 2002.
There were no significant unusual items impacting the effective rates.
Net income increased $4 million, or 3%, to $146 million in 2003,
reflecting an increase in the gas business of $27 million, partially offset by a
decline in the electricity business of $23 million. The performance in the gas
business reflected lower interest expense and improved gross margin. The decline
in the electricity business was driven by lower revenues and higher interest
expense. Net pension and postretirement benefit costs reduced net income by $22
million in 2003 and $14 million in 2002.
47
Australia
- ---------
Financial Results
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- ------------------
2003 2002 2003 2002
------ ------ ------ ------
Operating revenues....................................... $ 274 $ 216 $ 499 $ 428
------- ------- ------- -------
Costs and expenses:
Cost of energy sold and delivery fees............... 134 108 229 180
Operating costs..................................... 24 23 45 42
Depreciation and amortization....................... 22 17 41 32
Selling, general and administrative expenses........ 25 20 43 34
Other income ....................................... - (1) - (1)
Other deductions.................................... 1 2 2 4
Interest income..................................... (2) - (3) -
Interest expense and other charges ................. 36 33 70 62
------- ------- ------- -------
Total costs and expenses........................ 240 202 427 353
------- ------- ------- -------
Income before income taxes .............................. 34 14 72 75
Income tax expense....................................... 8 4 19 14
------- ------- ------- -------
Net income .............................................. $ 26 $ 10 $ 53 $ 61
======= ======= ======= =======
48
Australia
- ----------
Segment Highlights
Three Months Ended Six Months Ended
June 30, June 30,
------------------- -----------------
2003 2002 2003 2002
----- ----- ----- -----
Operating Statistics
Retail electricity sales volumes (GWh).................... 1,937 1,612 3,805 3,020
Retail gas sales volumes (Bcf)........................... 18 18 29 28
Wholesale electricity sales volumes (GWh)................. 582 767 996 1,320
Retail customers and points of delivery (end of period
and in thousands):
Electric............................................. 565 534
Gas.................................................. 476 431
------ ------
Total customers............................ 1,041 965
====== ======
Electricity distribution points of delivery.......... 554 541
Gas distribution points of delivery.................. 473 459
------ ------
Total points of delivery................... 1,027 1,000
====== ======
Operating revenues (millions of dollars)
Retail electric:
Residential.......................................... $ 73 $ 57 $ 129 $ 99
Commercial and industrial............................ 72 52 152 98
------ ------ ------ ------
Total........................................ 145 109 281 197
------ ------ ------ ------
Electricity delivery...................................... 14 9 27 18
------ ------ ------ ------
Retail gas sales:
Residential.......................................... 52 21 67 28
Commercial and industrial............................ 20 29 47 52
------ ------ ------ ------
Total........................................ 72 50 114 80
------ ------ ------ ------
Gas distribution.......................................... 12 11 17 15
Wholesale electric revenues............................... 14 23 24 34
Portfolio management activities and other revenues....... 17 14 36 84
------ ------ ------ ------
Total operating revenues..................... $ 274 $ 216 $ 499 $ 428
====== ====== ====== ======
49
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002
- -----------------------------------------------------------------------------
The Australia segment's operating revenues increased $58 million, or
27%, to $274 million in 2003. Of this increase, $40 million represented the
translation effect of the stronger Australian dollar. The balance of the growth
was driven by an increase in retail electricity revenues of $15 million (on a
constant exchange rate basis) or 14%, driven by higher sales volumes. Retail
electricity volumes rose 20%, primarily due to new commercial/industrial
accounts. Retail gas revenues rose 20% on a local currency basis as certain
service fee based customers under an agency arrangement in 2002 became direct
customers in October of 2002. Excluding this effect, retail gas revenues were
about even with 2002. Wholesale power revenues declined on a small base
reflecting lower wholesale market prices.
Gross Margin
Three Months Ended
June 30,
------------------------------------------------
% of % of
2003 Revenue 2002 Revenue
------ ------- ------ -------
Operating revenues..................................... $ 274 100% $ 216 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 134 49% 108 50%
Operating costs................................... 24 9% 23 11%
Depreciation and amortization related to operating
assets........................................ 19 7% 16 7%
------- ----- ------- ------
Gross margin........................................... $ 97 35% $ 69 32%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $3 million and $1 million of such expense for the three months ended
June 30, 2003 and 2002, respectively, that is not directly related to generation
and delivery property, plant and equipment.
Australia's gross margin increased $28 million, or 41%, to $97 million
in 2003. On a local currency basis, margins improved 20%, driven by the higher
retail electricity volumes, lower purchased power costs and improved results
from portfolio management activities, partially offset by decreased wholesale
electricity sales margins. Wholesale power prices have declined 42% from 2002
levels. Operating costs decreased 14% on a local currency basis, reflecting
nonrecurring costs incurred in 2002 to support the development of competitive
markets and other strategic initiatives. Depreciation and amortization related
to operating assets increased $3 million, or 4% on a local currency basis,
reflecting expenditures for electricity delivery and production assets to
support growth, as well as computer software costs related to the development of
competitive markets. Mark-to-market accounting for commodity contracts decreased
revenues and gross margin by $2 million in 2003 and $9 million in 2002 (as
compared to accounting on a settlement basis).
Australia's SG&A expenses rose $5 million, or 25%, to $25 million in
2003. On a local currency basis, SG&A expenses increased 5%, reflecting
increased staffing expenses to support retail competition activities in newly
competitive markets.
Australia's interest income increased to $2 million in 2003, from
none in 2002. The increase primarily reflected interest received on restricted
cash to support funding of construction of a natural gas pipeline in Australia
by a joint venture.
Australia's interest expense and other charges increased $3 million,
or 9%, to $36 million in 2003. On a local currency basis, interest expense and
other charges declined 3%, reflecting lower debt levels.
The effective tax rate was 23.5% in 2003 compared to 28.6% in 2002,
reflecting utilization of a capital loss carryforward.
50
Australia's net income increased to $26 million in 2003 from $10
million in 2002, driven by the increase in gross margin and reflecting a $4
million favorable effect of the stronger Australian dollar. Net pension and
postretirement benefit costs reduced net income by less than $1 million in both
2003 and 2002.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
- -------------------------------------------------------------------------
The Australia segment's operating revenues increased $71 million, or
17%, to $499 million in 2003. Of this increase, $68 million represented the
translation effect of the stronger Australian dollar. On a constant exchange
rate basis, retail electricity revenues rose $46 million, or 23%, reflecting a
26% sales volume increase due to new commercial/industrial and residential
accounts, and retail gas revenues increased $18 million due primarily to a
customer status change discussed above, while wholesale power revenues decreased
$12 million due largely to lower pricing. Portfolio management results decreased
$48 million, reflecting the impact of a $30 million gain in 2002 on the
termination of a wholesale power contract and the effects of lower wholesale
prices and decreased price volatility.
Gross Margin
Six Months Ended
June 30,
-----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
------ ------- ------ -------
Operating revenues..................................... $ 499 100% $ 428 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 229 46% 180 42%
Operating costs................................... 45 9% 42 10%
Depreciation and amortization related to operating
assets........................................ 36 7% 30 7%
------- ----- ------- ------
Gross margin........................................... $ 189 38% $ 176 41%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $5 million and $2 million of such expense for the six months ended June
30, 2003 and 2002, respectively, that is not directly related to generation and
delivery property, plant and equipment.
Australia's gross margin improved $13 million, or 7%, to $189 million
in 2003. On a local currency basis, margins declined 7%. Excluding the gain in
2002 on the wholesale power contract termination, gross margin on a local
currency basis rose 12%, driven by increased retail electric sales volumes and
lower purchased power costs, partially offset by lower results from portfolio
management activity. Operating costs decreased 6% on a local currency basis,
reflecting nonrecurring costs incurred in 2002 to support development of
competitive markets and other strategic initiatives. Depreciation and
amortization related to operating assets increased $6 million, or 5% on a local
currency basis, reflecting expenditures for electricity delivery and production
assets to support growth, as well as computer software costs related to the
development of competitive markets. Mark-to-market accounting for commodity
contracts decreased revenues and gross margin by $6 million in 2003, and
increased results in 2002 by $18 million (as compared to accounting on a
settlement basis).
Australia's SG&A expenses rose $9 million, or 26%, to $43 million in
2003. On a local currency basis, SG&A expenses increased 9%, reflecting
increased staffing expenses to support retail competition activities in newly
competitive markets.
Australia's interest income increased to $3 million in 2003, from
none in 2002. The increase primarily reflected interest received on restricted
cash to support funding of construction of a natural gas pipeline in Australia
by a joint venture.
Australia's interest expense and other charges increased $8 million,
or 13%, to $70 million in 2003. On a local currency basis, interest expense and
other charges declined 3%, reflecting lower debt levels.
The effective tax rate was 26.4% in 2003 compared to 18.7% in 2002.
The increase reflects the non-taxable nature of the 2002 contract termination
gain, partially offset by the utilization of the capital loss carryforward in
2003 discussed above.
51
Australia's net income declined $8 million, or 13%, to $53 million in
2003. This decrease reflected the $30 million (pre and after-tax) effect of the
contract termination gain in 2002, partially offset by an $8 million favorable
effect of the stronger Australian dollar and the benefit of improved retail
gross margins. On a local currency basis and excluding the effect of the
contract termination gain, Australia's net income rose 35%. Net pension and
postretirement benefit costs reduced net income by $1 million in 2003 and 2002.
COMPREHENSIVE INCOME - Continuing Operations
Foreign currency translation adjustments from continuing operations
for the three months ended June 30, 2003 and 2002 were $106 million and $42
million, respectively. These adjustments totaled $161 million and $73 million
for the six months ended June 30, 2003 and 2002, respectively. These adjustments
primarily reflect the movement in exchange rates between the US dollar and the
Australian dollar, and have no tax effects.
The after-tax effects of cash flow hedges in other comprehensive
income were as follows:
Three Months Ended Six Months Ended
June 30, June 30,
------------------- -------------------
2003 2002 2003 2002
------ ------ ----- ------
Net change in fair value of hedges - gains/(losses):
Commodities........................................ $ (24) $ (3) $ (103) $ (43)
Financing - foreign exchange and interest rates.... (52) (85) (81) (76)
------- -------- ------- -------
(76) (88) (184) (119)
Losses/(gains) realized in earnings:
Commodities........................................ 22 6 70 1
Financing - foreign exchange and interest rates.... 50 21 83 41
------- ------- ------- -------
72 27 153 42
------- ------- ------- -------
Net effect.............................. $ (4) $ (61) $ (31) $ (77)
======= ======= ======= =======
Gains and losses on cash flow hedges are realized in earnings as the
underlying hedged transactions are settled.
FINANCIAL CONDITION
Liquidity and Capital Resources
For information concerning liquidity and capital resources, see Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations in TXU Corp.'s 2002 Form 10-K. No significant changes or events that
might affect the financial condition of TXU Corp. have occurred subsequent to
year-end other than as disclosed herein.
Cash Flows -- Cash flows provided by operating activities for the six
months ended June 30, 2003, totaled $1.4 billion compared to $612 million for
2002. The increase in cash flows provided by operating activities in 2003 of
$830 million reflected a number of factors. The principal drivers of the
increase were the receipt of an income tax refund of $616 million, primarily
related to tax benefits associated with the write-off of the investment in
Europe, and improved working capital (accounts receivable, accounts payable and
inventories) of $562 million, which primarily reflects the effect of billing and
collection delays in 2002 associated with the transition to competition. These
items were partially offset by lower cash earnings (net income adjusted for the
significant noncash reconciling items identified in the statement of cash flows)
of $152 million and payments of $102 million related to counterparty default
events and the termination and liquidation of those outstanding positions.
Cash flows used in financing activities in 2003 were $1.7 billion,
primarily reflecting net repayment of borrowings. Issuances of debt securities
totaled $1.3 billion. Retirements of debt and reduction of notes payable to
banks totaled $2.9 billion, net of redemption deposit payments (restricted
cash), as TXU Corp. established permanent financing to replace the credit
facilities drawn down in the fourth quarter of 2002 to enhance liquidity. Cash
dividends paid on common shares approximated $80 million in 2003 and $318
million in 2002.
52
Cash flows used in investing activities totaled $614 million in 2003
and $187 million in 2002. Capital expenditures declined to $458 million in 2003
from $502 million in 2002 as a result of lower developmental spending. Capital
expenditures are expected to total $1.1 billion in 2003. The buyout of the joint
venture partner's interests in Pinnacle in 2003 totaled $150 million. The sale
of certain retail gas operations in 2003 provided $15 million. Proceeds from
asset sales in 2002 of $444 million included the sale of two generation plants
in Texas.
Depreciation and amortization expense reported in the statement of
cash flows exceeds the amount reported in the statement of income by $38
million. This difference represents amortization of nuclear fuel, which is
reported as cost of energy sold in the statement of income consistent with
industry practice, and amortization of regulatory assets, which is reported as
operating costs in the statement of income.
Financing Activities
Capitalization -- The capitalization ratios of TXU Corp. at June 30,
2003, consisted of 7.8% equity-linked debt securities, 3.5% exchangeable
subordinated notes, 56.5% other long-term debt, less amounts due currently, 2.8%
trust securities, 1.1% preferred stock of subsidiaries, 1.6% preference stock
and 26.7% common stock equity.
Registered Financing Arrangements -- TXU Corp., US Holdings, TXU Gas
and other subsidiaries of TXU Corp. may issue and sell additional debt and
equity securities as needed, including: (i) issuances by US Holdings of up to
$25 million of cumulative preferred stock and up to an aggregate of $924 million
of additional cumulative preferred stock, debt securities and/or preferred
securities of subsidiary trusts and (ii) issuances by TXU Gas of up to an
aggregate of $400 million of debt securities and/or preferred securities of
subsidiary trusts, all of which are currently registered with the Securities and
Exchange Commission for offering pursuant to Rule 415 under the Securities Act
of 1933.
Credit Facilities -- At June 30, 2003, TXU Corp. had outstanding
short-term borrowings consisting of bank borrowings of approximately $8 million
and commercial paper of $33 million (all in Australia).
At June 30, 2003, TXU Corp. and its subsidiaries had credit
facilities (some of which provide for long-term borrowings) as follows:
At June 30, 2003
--------------------------------------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
- -------- --------------- --------- ----- ------ ---------- ------------
Five-Year Revolving Credit Facility February 2005 US Holdings $ 1,400 $ 391 $ -- $1,009
Revolving Credit Facility February 2005 TXU Energy, Oncor 450 21 -- 429
Three-Year Revolving Credit Facility May 2005 US Holdings 400 -- -- 400
Revolving Credit Facilities May 2005 TXU Corp. 100 -- -- 100
------- ------ ------ ------
Total North America $ 2,350 $ 412 $ -- $1,938
======= ====== ====== ======
Senior Facility (a) October 2004 TXU Australia $ 1,167 $ -- $ 943 $ 208
Working Capital Facility October 2003 TXU Australia 66 -- 6 60
Standby Facility (a) December 2003 TXU Australia 17 -- -- --
------- ------ ------ ------
Total Australia $ 1,250 $ -- $ 949 $ 268
======= ====== ====== ======
(a)Commercial paper borrowings totaling $33 million at June 30, 2003 were
supported by the Standby Facility ($17 million) and the Senior Facility ($16
million).
53
In August 2003, TXU Corp. entered into a $500 million 5-year
revolving credit facility with LOC 2003 Trust, a special purpose, wholly-owned
subsidiary of TXU Corp. (LOC Trust). LOC Trust, in turn, entered into a $500
million 5-year secured credit facility with a group of lenders. TXU Corp.
intends to capitalize LOC Trust with approximately $525 million of cash, which
will be invested by the lenders in permitted investments as directed by LOC
Trust. LOC Trust's assets, including the investments, will constitute collateral
for the benefit of the lenders to secure issuances of letters of credit or
loans, and will be owned by LOC Trust. During the term of the facility,
LOC Trust will be required to maintain collateral in an amount equal to 105% of
the commitments under the secured facility. Upon capitalization of LOC Trust,
TXU Corp. may request up to $500 million of letters of credit or up to
$250 million of loans from LOC Trust, subject in aggregate to its $500 million
commitment, for the benefit of TXU Corp. and its subsidiaries, which may be
provided through issuances of letters of credit or loans by the lenders. LOC
Trust's assets are not available to satisfy claims of creditors of TXU Corp. or
its subsidiaries. However, LOC Trust may terminate all or a portion of the
secured facility at any time and request the release of any collateral not
required to secure outstanding letters of credit from the lenders.
Through April 2003, $2.3 billion in outstanding cash borrowings as of
December 31, 2002 under the North America credit facilities were repaid, and the
facilities were restructured. A $450 million revolving credit facility was
established for TXU Energy and Oncor that matures on February 25, 2005. This
facility will be used for working capital and other general corporate purposes,
including letters of credit, and replaces the $1 billion 364-day revolving
credit facility that expired in April 2003. Up to $450 million of letters of
credit may be issued under the facility.
This facility, as well as others available to TXU Corp., will
provide back-up for any future issuance of commercial paper by TXU Energy and
Oncor. At June 30, 2003, there was no outstanding commercial paper under the
North America credit facilities.
In connection with the restructuring of the North America credit
facilities of TXU Corp., in April 2003:
o Oncor cancelled its undrawn $150 million secured 364-day credit
facility that was scheduled to expire in December 2003.
o US Holdings replaced TXU Corp. as the borrower under the $500
million three-year revolving credit facility. Concurrently, the
facility was reduced to $400 million, and TXU Corp. entered into
additional credit facilities totaling $100 million, which were
cancelled in August 2003.
o US Holdings' $1.4 billion five-year revolving credit facility was
amended. Among other things, the amendment increased the amount of
letters of credit allowed to be issued under the facility to $1
billion from $500 million.
Australia's credit facilities were not affected by the above refinancings.
In addition to providing back-up of commercial paper issuance by TXU
Energy and Oncor, the North America facilities above are for general corporate
and working capital purposes, including providing collateral support for TXU
Energy portfolio management activities.
54
Long-Term Debt -- During the six months ended June 30, 2003, TXU
Corp. and its subsidiaries issued, redeemed, reacquired or made scheduled
principal payments on long-term debt as follows:
Issuances Retirements
--------- -----------
TXU Corp.:
Other long-term debt ....................... $ - $ 49
Oncor:
First mortgage bonds........................ - 306
Medium term notes........................... - 15
TXU Gas:
Senior notes................................ - 125
TXU Energy:
Fixed rate senior notes..................... 1,250 72
Pollution control revenue bonds............. 44 97
TXU Australia:
Long-term debt.............................. 23 97
------ ------
Total...................................... $1,317 $ 761
====== ======
See Note 4 to Financial Statements for further detail of debt
issuance and retirements.
Pinnacle -- See Notes 1 and 3 to Financial Statements for a
discussion of the sale and a summary of assets and liabilities associated with
Pinnacle.
Sale of Receivables -- Certain subsidiaries of TXU Corp. sell trade
accounts receivable to TXU Receivables Company, a wholly-owned bankruptcy remote
subsidiary of TXU Corp., which sells undivided interests in accounts receivable
it purchases to financial institutions. As of June 30, 2003, TXU Energy (through
certain subsidiaries), Oncor and TXU Gas are qualified originators of accounts
receivable under the program. TXU Receivables Company may sell up to an
aggregate of $600 million in undivided interests in the receivables purchased
from the originators under the program. The June 30, 2003 financial statements
reflect the sale of $1.2 billion face amount of receivables to TXU Receivables
Company under the program in exchange for cash of $540 million and $615 million
in subordinated notes, with $11 million of losses on sales for the six months
ended June 30, 2003 that principally represents the interest costs on the
underlying financing. These losses approximated 6% of the cash proceeds from the
sale of undivided interests in accounts receivable on an annualized basis.
Funding under the program increased $70 million for the six month period ended
June 30, 2003 primarily due to reserve requirements that were reduced through a
temporary amendment in recognition of improving collection trends. Higher loss
reserve requirements in previous periods reflected the billing and collection
delays previously experienced as a result of new systems and processes in TXU
Energy and ERCOT for clearing customers' switching and billing data upon the
transition to competition. Funding increases or decreases under the program are
reflected as operating cash flow activity.
Upon termination, cash flows to the originators would be delayed as
collections of sold receivables would be used by TXU Receivables Company to
repurchase the undivided interests of the financial institutions instead of
purchasing new receivables. The level of cash flows would normalize in
approximately 16 to 31 days. TXU Business Services Company, a subsidiary of TXU
Corp., services the purchased receivables and is paid a market based servicing
fee by TXU Receivables Company. The subordinated notes receivable from TXU
Receivables Company represent TXU Corp.'s subsidiaries' retained interests in
the transferred receivables and are recorded at book value, net of allowances
for bad debts, which approximates fair value due to the short-term nature of the
subordinated notes, and are included in accounts receivable in the consolidated
balance sheet.
In August 2003, the program was amended to extend the term to July
2004, as well as to extend the period providing temporarily higher delinquency
and default compliance ratios through December 31, 2003. The program was also
amended to coincide with the credit facilities' covenants by removing investment
grade credit ratings as a requirement of an eligible originator and substituting
maintenance of fixed charge coverage ratios and debt to capital ratios as
requirements of an eligible originator. In June 2003, the program was amended to
provide temporarily higher delinquency and default compliance ratios and
temporary relief from the loss reserve formula. The June amendment reflected the
billing and collection delays previously experienced as a result of new systems
and processes in TXU Energy and ERCOT for clearing customers' switching and
billing data upon the transition to competition.
55
Contingencies Related to Receivables Program -- Although TXU Receivables
Company expects to be able to pay its subordinated notes from the collections of
purchased receivables, these notes are subordinated to the undivided interests
of the financial institutions in those receivables, and collections might not be
sufficient to pay the subordinated notes. The program may be terminated if
either of the following events occurs:
1) all of the originators cease to maintain their required fixed charge
coverage ratio and debt to capital (leverage) ratio;
2) the delinquency ratio (delinquent for 31 days) for the sold
receivables, the default ratio (delinquent for 91 days or deemed
uncollectible), the dilution ratio (reductions for discounts,
disputes and other allowances) or the days collection outstanding
ratio exceed stated thresholds and the financial institutions do not
waive such event of termination. The thresholds apply to the entire
portfolio of sold receivables, not separately to the receivables of
each originator.
The delinquency and dilution ratios exceeded the relevant thresholds
during the first four months of 2003, but waivers were granted. These ratios
were affected by issues related to the transition to deregulation. Certain
billing and collection delays arose due to implementation of new systems and
processes within TXU Energy and ERCOT for clearing customers' switching and
billing data. The billing delays have been resolved but, while improving, the
lagging collection issues continue to impact the ratios. The implementation of
new POLR rules by the Commission and strengthened credit and collection policies
and practices are expected to bring the ratios into consistent compliance with
the program.
Under the receivables sale program, all the originators are required
to maintain specified fixed charge coverage and leverage ratios (or supply a
parent guarantor that meets the ratio requirements). The failure by an
originator or its parent guarantor, if any, to maintain the specified financial
ratios would prevent that originator from selling its accounts receivable under
the program. If all the originators and the parent guarantor, if any, fail to
maintain the specified financial ratios so that there are no eligible
originators, the facility would terminate. Prior to the August 2003 amendment
extending the program, originator eligibility was predicated on the maintenance
of an investment grade credit rating.
Credit Ratings of TXU Corp. and its US and Australian Subsidiaries --
The current credit ratings for TXU Corp. and certain of its US and Australian
subsidiaries are presented below:
TXU Corp. US Holdings Oncor TXU Energy TXU Gas TXU Australia
--------------- --------------- -------- --------------- ---------------- --------------
(Senior Unsecured)(Senior Unsecured)(Secured)(Senior Unsecured)(Senior Unsecured) (Senior Unsecured)
S&P.............BBB- BBB- BBB BBB BBB BBB
Moody's.........Ba1 Baa3 Baa1 Baa2 Baa3 Baa2
Fitch...........BBB- BBB- BBB+ BBB BBB- BBB-
Moody's currently maintains a negative outlook for TXU Corp., TXU Gas
and TXU Australia, and a stable outlook for US Holdings, TXU Energy and Oncor.
Fitch currently maintains a positive outlook for TXU Australia and a stable
outlook for the remaining entities. S&P currently maintains a negative outlook
for each such entity.
These ratings are investment grade, except for Moody's rating of TXU
Corp.'s senior unsecured debt, which is one notch below investment grade.
A rating reflects only the view of a rating agency, and is not a
recommendation to buy, sell or hold securities. Any rating can be revised upward
or downward at any time by a rating agency if such rating agency decides that
circumstances warrant such a change.
56
Financial Covenants, Credit Rating Provisions and Cross Default
Provisions -- The terms of certain financing arrangements of TXU Corp. contain
financial covenants that require maintenance of specified fixed charge coverage
ratios, shareholders' equity to total capitalization ratios and leverage ratios
and/or contain minimum net worth covenants. TXU Energy's preferred membership
interests (formerly subordinated notes) also limit its incurrence of additional
indebtedness unless a leverage ratio and interest coverage test are met on a pro
forma basis. As of June 30, 2003, TXU Corp. and its subsidiaries were in
compliance with all such applicable covenants.
Certain financing and other arrangements of TXU Corp. contain
provisions that are specifically affected by changes in credit ratings and also
include cross default provisions. The material cross default provisions are
described below.
Other agreements of TXU Corp., including some of the credit
facilities discussed above, contain terms pursuant to which the interest rates
charged under the agreements may be adjusted depending on the credit ratings of
TXU Corp. or its subsidiaries.
Credit Rating Provisions
------------------------
In the event of a decline in the credit rating for TXU Corp.'s
unsecured, senior long-term obligations to two notches below investment grade
(i.e., to or below 'BB' by S&P or Fitch or 'Ba2' by Moody's), coupled with a
decline in the market price of TXU Corp. common stock below $21.93 per share for
ten consecutive trading days, TXU Corp. would be required to sell equity or
otherwise raise cash proceeds sufficient to repay Pinnacle's senior secured
notes ($810 million outstanding at June 30, 2003). The market price of TXU
Corp.'s common stock is below the stated level.
TXU Energy has provided a guarantee of the obligations under TXU
Corp.'s lease (approximately $135 million at June 30, 2003) for its headquarters
building. In the event of a downgrade of TXU Energy's credit rating to below
investment grade, a letter of credit would need to be provided within 30 days of
any such ratings decline.
TXU Energy has entered into certain commodity contracts and lease
arrangements that in some instances give the other party the right, but not the
obligation, to request TXU Energy to post collateral in the event that its
credit rating falls below investment grade.
Based on its current commodity contract positions, if TXU Energy were
downgraded below investment grade by any specified rating agency, counterparties
would have the option to request TXU Energy to post additional collateral of
approximately $204 million.
In addition, TXU Energy has a number of other contractual
arrangements where the counterparties would have the right to request TXU Energy
to post collateral if its credit rating was downgraded below investment grade by
any specified rating agency. The amount TXU Energy would post under these
transactions depends in part on the value of the contracts at that time. As of
June 30, 2003, based on current market conditions, the maximum TXU Energy would
post for these transactions is $295 million. Of this amount, $249 million
relates to an arrangement that would require that TXU Energy be downgraded to
below investment grade by all three rating agencies before collateral would be
required to be posted.
TXU Energy is also the obligor on leases aggregating $164 million.
Under the terms of those leases, if TXU Energy's credit rating was downgraded to
below investment grade by any specified rating agency, TXU Energy could be
required to sell the assets, assign the leases to a new obligor that is
investment grade, post a letter of credit or defease the leases.
ERCOT also has rules in place to assure adequate credit worthiness
for parties that schedule power on the ERCOT System. Under those rules, if TXU
Energy's credit rating was downgraded to below investment grade by any specified
rating agency, TXU Energy could be required to post collateral of approximately
$60 million.
57
In the event that TXU Australia's credit rating was downgraded to
below investment grade, there are cross currency swaps and interest rate swaps
in effect with banks who have the right to terminate the swaps. These contracts
are currently out of the money by $6.7 million on a net basis.
TXU Australia has several contracts that may require additional
guarantees or cash collateral totaling approximately $71 million if its credit
rating was downgraded to below investment grade, or if there was a material
adverse change in its financial condition.
Cross Default Provisions
------------------------
Certain financing arrangements of TXU Corp. contain provisions that
would result in an event of default if there is a failure under other financing
arrangements to meet payment terms or to observe other covenants that would
result in an acceleration of payments due. Such provisions are referred to as
"cross default" provisions.
A default by US Holdings or any subsidiary thereof on financing
arrangements of $50 million or more would result in a cross default under the
$1.4 billion US Holdings five-year revolving credit facility, the $400 million
US Holdings credit facility, the $68 million US Holdings letter of credit
reimbursement and credit facility agreement and $30 million of TXU Mining senior
notes (which have a $1 million threshold).
A default by TXU Energy or Oncor or any subsidiary thereof in respect
of indebtedness in a principal amount in excess of $50 million or more would
result in a cross default for such party under the TXU Energy/Oncor $450 million
revolving credit facility. Under this credit facility, a default by TXU Energy
or any subsidiary thereof would cause the maturity of outstanding balances under
such facility to be accelerated as to TXU Energy, but not as to Oncor. Also,
under this credit facility, a default by Oncor or any subsidiary thereof would
cause the maturity of outstanding balances to be accelerated under such facility
as to Oncor, but not as to TXU Energy.
A default or similar event under the terms of the TXU Energy
preferred membership interests (formerly subordinated notes) that results in the
acceleration (or other mandatory repayment prior to the mandatory redemption
date) of such security or the failure to pay such security at the mandatory
redemption date would result in a default under TXU Energy's $1.25 billion
senior unsecured notes.
TXU Corp.'s 6% Notes due 2003 to 2004, which are held by the Pinnacle
Overfund Trust ($135 million outstanding at June 30, 2003) and Pinnacle's 8.83%
Senior Secured Notes due 2004 ($810 million outstanding at June 30, 2003)
contain cross default provisions relating to a failure to pay principal or
interest on indebtedness of TXU Corp. or TXU Communications Ventures Company (in
the case of the 8.83% Senior Secured Notes due 2004) in a principal amount of
$50 million or above.
TXU Energy has entered into certain mining and equipment leasing
arrangements aggregating $127 million that would terminate upon the default of
any other obligations of TXU Energy owed to the lessor. In the event of a
default by TXU Mining, a subsidiary of TXU Energy, on indebtedness in excess of
$1 million, a cross default would result under the $31 million TXU Mining
leveraged lease and the lease would terminate.
The accounts receivable program also contains a cross default
provision with a threshold of $50 million applicable to each of the originators
under the program. TXU Receivables Company and TXU Business Services Company
each have a cross default threshold of $50,000. If either an originator, TXU
Business Services Company or TXU Receivables Company defaults on indebtedness of
the applicable threshold, the facility could terminate.
TXU Energy enters into energy-related contracts, the master forms of
which contain provisions whereby an event of default would occur if TXU Energy
were to default under an obligation in respect of borrowings in excess of
thresholds stated in the contracts, which thresholds vary.
A default by TXU Gas or any of its material subsidiaries on
indebtedness of $25 million or more would result in a cross default under the
$300 million TXU Gas senior notes due 2004 and 2005.
58
A default by TXU Corp. on indebtedness of $50 million or more would
result in a cross default under the new $500 million five-year revolving credit
facility.
TXU Corp. and its subsidiaries have other arrangements, including
interest rate swap agreements and leases with cross default provisions, the
triggering of which would not result in a significant effect on liquidity.
Regulatory Asset Securitization -- The Settlement Plan approved by
the Commission provides Oncor with a financing order authorizing it to issue
securitization bonds in the aggregate principal amount of $1.3 billion to
monetize and recover generation-related regulatory assets and related
transaction costs. The Settlement Plan provides that there will be an initial
issuance of securitization bonds in the amount of up to $500 million followed by
a second issuance for the remainder in 2004. The first issuance is expected to
be made in the third quarter of 2003.
Equity - The Board of Directors of TXU Corp., at its February 2003
meeting, declared a quarterly dividend of $0.125 a share, payable April 1, 2003,
to shareholders of record on March 7, 2003. At its May 2003 meeting, the Board
of Directors of TXU Corp. declared a quarterly dividend of $0.125 a share,
payable on July 1, 2003, to shareholders of record on June 6, 2003.
Future dividends may vary depending upon TXU Corp.'s profit levels,
operating cash flows and capital requirements as well as financial and other
business conditions existing at the time.
OFF BALANCE SHEET ARRANGEMENTS
With the acquisition of the other partner's interest in Pinnacle in
May 2003 (see Note 1), the only remaining significant off balance sheet
arrangement consists of the sale of receivables program. See discussion above
under Sale of Receivables.
COMMITMENTS AND CONTINGENCIES
See Note 7 to Financial Statements for a discussion of contingencies.
There were no material changes in cash commitments from those disclosed in the
2002 Form 10-K.
REGULATION AND RATES
Settlement Plan -- On December 31, 2001, US Holdings filed the
Settlement Plan with the Commission. It resolved all major pending issues
related to US Holdings' transition to competition pursuant to the 1999
Restructuring Legislation. The Settlement provided for in the Settlement Plan
does not remove regulatory oversight of Oncor's business nor does it eliminate
TXU Energy's price-to-beat rates and related fuel adjustments. The Settlement
was approved by the Commission in June 2002 and has become final.
Excess Mitigation Credit -- Beginning in 2002, Oncor began
implementing an excess stranded cost mitigation credit designed to result in a
$350 million, plus interest, credit (reduction) applied to delivery fees billed
to REPs applied over a two-year period ending December 31, 2003. The actual
amount of this credit is expected to exceed $350 million as delivery volumes are
anticipated to be higher than initially estimated. The resulting net earnings
reduction for the year 2003 is currently expected to be approximately $14
million after-tax, after consideration of the portion of the credit reflected in
TXU Energy's results as an affiliated REP.
Regulatory Asset Securitization -- In accordance with the
Settlement, Oncor received a financing order authorizing it to issue
securitization bonds in the aggregate principal amount of $1.3 billion to
recover regulatory assets and other qualified costs as discussed above. The
Settlement provides that there can be an initial issuance of securitization
bonds in the amount of up to $500 million, expected to be completed in the third
quarter of 2003, followed by a second issuance of the remainder expected in the
first half of 2004. The Settlement resolves all issues related to regulatory
assets and liabilities.
Retail Clawback -- If TXU Energy retains more than 60% of its
historical residential and small commercial power consumption after the first
two years of competition, the amount of the retail clawback credit will be equal
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to the number of residential and small commercial customers retained by TXU
Energy in its historical service territory on January 1, 2004, less the number
of new customers TXU Energy has added outside of its historical service
territory as of January 1, 2004, multiplied by $90. This determination will be
made separately for the residential and small commercial classes. The credit, if
any, will be applied to delivery fees billed by Oncor to REPs, including TXU
Energy, over a two-year period beginning January 1, 2004. Under the settlement
agreement, TXU Energy will make a compliance filing with the Commission
reflecting customer count as of January 1, 2004. In the fourth quarter of 2002,
TXU Energy recorded a $185 million ($120 million after-tax) charge for the
retail clawback, which represents the current best estimate of the amount to be
funded to Oncor over the two-year period.
T&D utilities in Texas are required to file a progress report with
the Commission when over 35% of the residential or small commercial
price-to-beat customer load that existed in the T&D utility's service territory
prior to the January 1, 2002 onset of customer choice is being served by REPs
other than the T&D utility's affiliated REP.
Accordingly, on June 30, 2003, Oncor reported to the Commission
that, as of May 31, 2003, approximately 37%, of the total historical small
commercial customer load, as adjusted pursuant to Commission rules, in its
service territory was being served by REPs other than TXU Energy.
For purposes of these reports, the Commission rules adjust the
total historical load to remove load for those individual small commercial
customers who now use more than 1,000 kilowatts, and for those customers in
which the aggregate use of all their affiliates under common control is more
than 1,000 kilowatts and have contracted with Oncor's affiliated REP, TXU
Energy. The calculations do not take into account the small commercial load that
TXU Energy has gained outside of the Oncor service territory. Also the report
filed by Oncor does not address the residential category where a significantly
smaller percentage of the load is served by REPs other than TXU Energy.
If the 40% threshold related to the small commercial load is met,
TXU Energy would reassess, and adjust accordingly, the estimated $185 million
accrual it previously recorded, which included amounts related to this customer
category. In addition, TXU Energy would be able to price competitively to this
class of customer.
Stranded Cost Resolution -- TXU Energy's stranded costs, not
including regulatory assets, are fixed at zero. Accordingly, it will not have to
conduct the stranded cost true-up in 2004 provided for in the 1999 Restructuring
Legislation.
Fuel Cost Recovery -- The Settlement also provides that US Holdings
will not seek to recover its unrecovered fuel costs that existed at December 31,
2001. Also, it will not conduct a final fuel cost reconciliation, which would
have covered the period from July 1998 until the beginning of competition in
January 2002.
TXU Gas -- TXU Gas employs a continuing program of rate review for
all classes of customers in its regulatory jurisdictions. In July 2001 and
August 2001, TXU Gas filed two cases, a gas cost review and a gas cost
reconciliation, covering the period between November 1997 and June 2001, seeking
to recover $29 million of under-recovered gas costs. On August 6, 2002, a
settlement was approved by the RRC authorizing TXU Gas to recover $18 million of
this amount, which has been recovered through a surcharge, while $11 million in
under-recovered gas costs remains pending. On May 23, 2003, TXU Gas filed a
system-wide rate case for TXU Gas Distribution and TXU Pipeline operations. The
case was filed in all 437 cities served by TXU Gas Distribution and at the RRC
for TXU Pipeline and unincorporated cities. The RRC assigned the case Gas
Utilities Docket 9400. TXU Gas is seeking an annual revenue increase of $69.5
million or 7.24% overall increase. TXU Gas has asked the 437 incorporated cites
with original jurisdiction over TXU Gas Distribution rates to either deny or
cede jurisdiction to the RRC. Eleven parties have intervened in the case. TXU
Gas expects a final order from the RRC late in the first quarter or early in the
second quarter of 2004.
TXU Energy --The 1999 Restructuring Legislation provides that an
affiliated REP may request that the Commission adjust its price-to-beat fuel
factor not more than twice a year if the affiliated REP demonstrates that the
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existing fuel factor does not adequately reflect significant changes in the
market price of natural gas and purchased energy used to serve retail customers.
The Commission's rules further provide that an affiliated REP may request that
the Commission adjust the price-to-beat fuel factor upward or downward. Neither
the law nor the Commission's rules give the Commission or any other entity the
right to file a petition seeking to require an affiliated REP to increase or
decrease its price-to-beat fuel factor.
Under amended Commission rules, effective in March 2003, affiliated
REPs of utilities are allowed to petition the Commission twice per year for an
increase in the fuel factor component of their price-to-beat rates if the
average price of natural gas futures increases more than 5% (10% if the petition
is filed after November 15 of any year) from the level used to set the existing
price-to-beat fuel factor rate.
- -- In January 2003, TXU Energy filed a request with the Commission to
increase the fuel factor component of its price-to-beat rates based
upon significant increases in the market price of natural gas. This
request was approved on March 5, 2003. The fuel factor increase went
into effect for the billing cycle that began March 6, 2003. As a
result, average monthly residential bills rose approximately 12%.
- -- On July 23, 2003, TXU Energy filed another request with the Commission
to increase the fuel factor component of its price-to-beat rates. The
change would raise the average monthly residential electric bill
of a customer using an average of 1,000 kilowatt-hours by
3.7 percent, or $3.61 per month. Even with the increase, TXU Energy
would continue to have the lowest price-to-beat rate in the state.
The Commission has 45 days from the filing of the request, or as soon
as possible, to review the request, and is expected to make a decision
in August 2003. This request would increase TXU Energy's
revenues by approximately $180 million ($50 million for the remainder
of 2003, if approved in mid-September)on an annualized basis.
Transmission rates -- In May 2003, the Commission approved wholesale
transmission rates that are estimated to result in an annual $44 million
increase in Oncor's T&D revenues. Approximately 60% of the increase
is recoverable from Oncor's non-affiliated wholesale transmission customers.
The remaining 40% of the increase will be recoverable from REPs upon an
increase in Oncor's distribution tariffs expected to be approved by the
Commission in the third quarter of 2003. On a consolidated basis, the increase
in Oncor's distribution revenue will be partially offset by higher electricity
delivery costs at TXU Energy.
Australia -- The distribution tariffs for electricity until December
31, 2005, and for gas until December 31, 2007, are determined by the Essential
Services Commission. According to the determination, the gas distribution
tariffs are to be increased by 2.2% for 2003. Each subsequent year, the gas
distribution tariffs are to increase by 0.8% plus Consumer Price Index (CPI)
increase. The electricity distribution tariffs are to increase by the CPI, less
1% each year.
In Victoria and New South Wales, the residential electricity markets
have both become competitive since January 2002, and the residential gas markets
have become competitive in New South Wales from January 2002 and in Victoria
from October 2002. The residential and small business energy prices are still
regulated and determined by the government bodies of the respective States of
Victoria and New South Wales.
In South Australia, the residential energy market has been
competitive since January 2003, although the residential and small business
energy prices offered incumbent retailers are still regulated and determined by
the South Australian government. TXU Australia entered into this market in March
2003.
Summary -- Although TXU Corp. 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
the 2002 Form 10-K and this report, which might significantly alter its basic
financial position, results of operations or cash flows.
CHANGES IN ACCOUNTING STANDARDS
See Note 1 to Financial Statements for discussion of changes in
accounting standards.
61
RISK FACTORS THAT MAY AFFECT FUTURE RESULTS
The following risk factors are being presented in consideration of
industry practice with respect to disclosure of such information in filings
under the Securities Exchange Act of 1934, as amended.
Some important factors, in addition to others specifically addressed
in this MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS, that could have a material impact on TXU Corp.'s operations,
financial results and financial condition, and could cause TXU Corp.'s actual
results or outcomes to differ materially from any projected outcome contained in
any forward-looking statement in this report, include:
ERCOT is the independent system operator that is responsible for
maintaining reliable operation of the bulk electric power supply system in the
ERCOT region. Its responsibilities include the clearing and settlement of
electricity volumes and related ancillary services among the various
participants in the deregulated Texas market. Because of new processes and
systems associated with the opening of the market to competition, which
continue to be improved, there have been delays in finalizing settlements.
As a result, TXU Corp. is subject to settlement adjustments from ERCOT related
to prior periods, which may result in charges or credits impacting future
reported results of operations.
TXU Corp.'s businesses operate in changing market environments
influenced by various legislative and regulatory initiatives regarding
deregulation, regulation or restructuring of the energy industry, including
deregulation of the production and sale of electricity. TXU Corp. will need to
adapt to these changes and may face increasing competitive pressure.
TXU Corp.'s US businesses are subject to changes in laws (including
the Texas Public Utility Regulatory Act, as amended, Texas Gas Utility
Regulatory Act, as amended, Federal Power Act, as amended, Atomic Energy Act, as
amended, Public Utility Regulatory Policies Act of 1978, as amended, and Public
Utility Holding Company Act of 1935, as amended) and changing governmental
policy and regulatory actions (including those of the Commission, Railroad
Commission of Texas, Federal Energy Regulatory Commission, and NRC) with respect
to matters including, but not limited to, operation of nuclear power facilities,
construction and operation of other power generation facilities, construction
and operation of transmission facilities, acquisition, disposal, depreciation,
and amortization of regulated assets and facilities, recovery of purchased gas
costs, decommissioning costs, and return on invested capital for TXU Corp.'s
regulated businesses, and present or prospective wholesale and retail
competition.
TXU Corp. is also subject to changes in laws, governmental policy
and regulatory actions in Australia.
Existing laws and regulations governing the market structure in
Texas, including the provisions of the 1999 Restructuring Legislation, could be
reconsidered, revised or reinterpreted, or new laws or regulations could be
adopted.
TXU Corp. is subject to the effects of new, or changes in, income
tax rates or policies and increases in taxes related to property, plant and
equipment and gross receipts and other taxes. Further, TXU Corp. is subject to
audit and reversal of its tax positions by the IRS and other taxing authorities.
TXU Corp. is not guaranteed any rate of return on its capital
investments in unregulated businesses. TXU Corp. markets and trades power,
including power from its own production facilities, as part of its wholesale
energy sales business and portfolio management operation. TXU Corp.'s results of
operations are likely to depend, in large part, upon prevailing retail rates,
which are set, in part, by regulatory authorities, and market prices for
electricity, gas and coal in its regional market and other competitive markets.
Market prices may fluctuate substantially over relatively short periods of time.
Demand for electricity can fluctuate dramatically, creating periods of
substantial under- or over-supply. During periods of over-supply, prices might
be depressed. Also, at times there may be political pressure, or pressure from
regulatory authorities with jurisdiction over wholesale and retail energy
commodity and transportation rates, to impose price limitations, bidding rules
and other mechanisms to address volatility and other issues in these markets.
62
TXU Corp.'s US regulated businesses are subject to cost-of-service
regulation and annual earnings oversight. Oncor's rates are regulated by the
Commission based on an analysis of Oncor's costs, as reviewed and approved in a
regulatory proceeding. As part of the Settlement Plan, TXU Corp. has agreed not
to seek to increase its distribution rates prior to 2004. Thus, the rates TXU
Corp. is allowed to charge may or may not match its related costs and allowed
return on invested capital at any given time. While rate regulation is premised
on the full recovery of prudently incurred costs and a reasonable rate of return
on invested capital, there can be no assurance that the Commission will judge
all of TXU Corp.'s costs to have been prudently incurred or that the regulatory
process in which rates are determined will always result in rates that will
produce full recovery of TXU Corp.'s costs and the return on invested capital
allowed by the Commission.
Some of the fuel for TXU Corp.'s power production facilities is
purchased under short-term contracts or on the spot market. Prices of fuel,
including natural gas, may also be volatile, and the price TXU Corp. can obtain
for power sales may not change at the same rate as changes in fuel costs. In
addition, TXU Corp. markets and trades natural gas and other energy related
commodities, and volatility in these markets may affect TXU Corp.'s costs
incurred in meeting its obligations.
Volatility in market prices for fuel and electricity may result from:
o severe or unexpected weather conditions,
o seasonality,
o changes in electricity usage,
o illiquidity in the wholesale power or other markets,
o transmission or transportation constraints, inoperability or
inefficiencies,
o availability of competitively priced alternative energy sources,
o changes in supply and demand for energy commodities,
o changes in power production capacity,
o outages at TXU Corp.'s power production facilities or those of its
competitors,
o changes in production and storage levels of natural gas, lignite,
coal and crude oil and refined products,
o natural disasters, wars, sabotage, terrorist acts, embargoes and other
catastrophic events, and
o federal, state, local and foreign energy,
environmental and other regulation and legislation.
All but one of TXU Corp.'s facilities for power production in the US
are located in the ERCOT region, a market with limited interconnections to other
markets. Electricity prices in the ERCOT region are related to gas prices
because gas fired plant is the marginal cost unit during the majority of the
year in the ERCOT region. Accordingly, the contribution to earnings and the
value of TXU Corp.'s base-load plant is dependent in significant part upon the
price of gas. TXU Corp. cannot fully hedge the risk associated with dependency
on gas because of the expected useful life of TXU Corp.'s power production
assets and the size of its position relative to market liquidity.
To manage its financial exposure related to commodity price
fluctuations, TXU Corp. routinely enters into contracts to hedge portions of its
purchase and sale commitments, weather positions, fuel requirements and
inventories of natural gas, lignite, coal, crude oil and refined products, and
other commodities, within established risk management guidelines. As part of
this strategy, TXU Corp. routinely utilizes fixed-price forward physical
purchase and sales contracts, futures, financial swaps and option contracts
traded in the OTC markets or on exchanges. However, TXU Corp. cannot cover the
entire exposure of its assets or its positions to market price volatility, and
the coverage will vary over time. To the extent TXU Corp. has unhedged
positions, fluctuating commodity prices can impact TXU Corp.'s results of
operations and financial position, either favorably or unfavorably. For
additional information regarding the accounting treatment for TXU Corp.'s
hedging and portfolio management activities, see Notes 2 and 14 to Financial
Statements in the 2002 Form 10-K.
Although TXU Corp. devotes a considerable amount of management time
and effort to the establishment of risk management procedures as well as the
ongoing review of the implementation of these procedures, the procedures it has
in place may not always be followed or may not always work as planned and cannot
eliminate all the risks associated with these activities. As a result of these
and other factors, TXU Corp. cannot predict with precision the impact that its
risk management decisions may have on its businesses, results of operations or
financial position.
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In connection with TXU Corp.'s portfolio management activities, TXU
Corp. has guaranteed or indemnified the performance of a portion of the
obligations of its portfolio management subsidiaries. Some of these guarantees
and indemnities are for fixed amounts, others have a fixed maximum amount and
others do not specify a maximum amount. The obligations underlying certain of
these guarantees and indemnities are recorded on TXU Corp.'s consolidated
balance sheet as both current and noncurrent commodity contract liabilities.
These obligations make up a significant portion of these line items. TXU Corp.
might not be able to satisfy all of these guarantees and indemnification
obligations if they were to come due at the same time.
TXU Corp.'s portfolio management activities are exposed to the risk
that counterparties which owe TXU Corp. money, energy or other commodities as a
result of market transactions will not perform their obligations. The likelihood
that certain counterparties may fail to perform their obligations has increased
due to financial difficulties, brought on by improper or illegal accounting and
business practices, affecting some participants in the industry. Some of these
financial difficulties have been so severe that certain industry participants
have filed for bankruptcy protection or are facing the possibility of doing so.
Should the counterparties to these arrangements fail to perform, TXU Corp. might
be forced to acquire alternative hedging arrangements or honor the underlying
commitment at then-current market prices. In such event, TXU Corp. might incur
losses in addition to amounts, if any, already paid to the counterparties. ERCOT
market participants are also exposed to risks that another ERCOT market
participant may default in its obligations to pay ERCOT for power taken in the
ancillary services market, in which case such costs, to the extent not offset by
posted security and other protections available to ERCOT, may be allocated to
various non-defaulting ERCOT market participants.
The current credit ratings for TXU Corp.'s and its subsidiaries'
long-term debt are investment grade, except for Moody's credit rating for
long-term debt of TXU Corp. (the holding company), which is one notch below
investment grade. A rating reflects only the view of a rating agency, and it is
not a recommendation to buy, sell or hold securities. Any rating can be revised
upward or downward at any time by a rating agency if such rating agency decides
that circumstances warrant such a change. If S&P, Moody's or Fitch were to
downgrade TXU Corp.'s and/or its subsidiaries' long-term ratings, particularly
below investment grade, borrowing costs would increase and the potential pool of
investors and funding sources would likely decrease.
Most of TXU Corp.'s large customers, suppliers and counterparties
require sufficient creditworthiness in order to enter into transactions. If TXU
Corp.'s subsidiaries' ratings were to decline to below investment grade, costs
to operate the power and gas businesses would increase because counterparties
may require the posting of collateral in the form of cash-related instruments,
or counterparties may decline to do business with TXU Corp.'s subsidiaries.
In addition, as discussed elsewhere in this Quarterly Report on Form
10-Q and in TXU Corp.'s 2002 Form 10-K, the terms of certain financing and other
arrangements contain provisions that are specifically affected by changes in
credit ratings and could require the posting of collateral, the repayment of
indebtedness or the payment of other amounts.
The operation of power production and energy transportation
facilities involves many risks, including start up risks, breakdown or failure
of facilities, lack of sufficient capital to maintain the facilities, the
dependence on a specific fuel source or the impact of unusual or adverse weather
conditions or other natural events, as well as the risk of performance below
expected levels of output or efficiency, the occurrence of any of which could
result in lost revenues and/or increased expenses. A significant portion of TXU
Corp.'s facilities was constructed many years ago. In particular, older
generating equipment, even if maintained in accordance with good engineering
practices, may require significant capital expenditures to keep it operating at
peak efficiency. Increased starting and stopping of equipment due to the
volatility of the competitive market is likely to increase maintenance and
capital expenditures. TXU Corp. is subject to costs associated with any
unexpected failure to produce power, including failure caused by breakdown or
forced outage, as well as repairing damage to facilities due to storms, natural
disasters, wars, terrorist acts and other catastrophic events. Further, TXU
Corp.'s ability to successfully and timely complete capital improvements to
existing facilities or other capital projects is contingent upon many variables
and subject to substantial risks. Should any such efforts be unsuccessful, TXU
Corp. could be subject to additional costs and/or the write-off of its
investment in the project or improvement.
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Insurance, warranties or performance guarantees may not cover all or
any of the lost revenues or increased expenses, including the cost of
replacement power. Likewise, TXU Corp.'s ability to obtain insurance, and the
cost of and coverage provided by such insurance, could be affected by events
outside its control.
Current plans to meet cost reduction targets assume that TXU Corp.
will be able to lower bad debt expense, the achievement of which could be
affected by factors outside of TXU Corp.'s control, including weather, changes
in regulations, and economic and market conditions.
The ownership and operation of nuclear facilities, including TXU
Corp.'s ownership and operation of the Comanche Peak generation plant, involve
certain risks. These risks include: mechanical or structural problems;
inadequacy or lapses in maintenance protocols; the impairment of reactor
operation and safety systems due to human error; the costs of storage, handling
and disposal of nuclear materials; limitations on the amounts and types of
insurance coverage commercially available; and uncertainties with respect to the
technological and financial aspects of decommissioning nuclear facilities at the
end of their useful lives. The following are among the more significant of these
risks:
o Operational Risk - Operations at any nuclear power production plant
could degrade to the point where the plant would have to be shut down.
If this were to happen, the process of identifying and correcting the
causes of the operational downgrade to return the plant to operation
could require significant time and expense, resulting in both lost
revenue and increased fuel and purchased power expense to meet supply
commitments. Rather than incurring substantial costs to restart the
plant, the plant may be shut down. Furthermore, a shut-down or failure
at any other nuclear plant could cause regulators to require a
shut-down or reduced availability at Comanche Peak.
o Regulatory Risk - The NRC may modify, suspend or revoke licenses and
impose civil penalties for failure to comply with the Atomic Energy
Act, the regulations under it or the terms of the licenses of nuclear
facilities. Unless extended, the NRC operating licenses for Comanche
Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively.
Changes in regulations by the NRC could require a substantial increase
in capital expenditures or result in increased operating or
decommissioning costs.
o Nuclear Accident Risk - Although the safety record of Comanche Peak and
nuclear reactors generally has been very good, accidents and other
unforeseen problems have occurred both in the US and elsewhere. The
consequences of an accident can be severe and include loss of life and
property damage. Any resulting liability from a nuclear accident could
exceed TXU Corp.'s resources, including insurance coverage.
TXU Corp. will be required to apply a credit to its electricity
delivery charges (retail clawback) to REPs in Oncor's service territory
beginning in 2004 unless the Commission determines that, on or prior to January
1, 2004, 40% or more of the amount of electric power that was consumed in 2000
by residential or small commercial customers, as applicable, within its
historical service territories is committed to be served by REPs other than TXU
Corp. Under the Settlement Plan, if the 40% test is not met and a credit is
required, the amount of these credits would be $90 multiplied by the number of
residential or small commercial customers, as the case may be, that TXU Corp.
serves on January 1, 2004, in its historical service territories less the number
of retail electric customers TXU Corp. serves in other areas of Texas. As of
June 30, 2003, TXU Corp. had approximately 2.6 million residential and small
commercial customers in its historical service territories. Based on assumptions
and estimates regarding the number of customers expected in and out of
territory, TXU Corp. recorded an accrual for retail clawback in 2002 of $185
million ($120 million after-tax). This accrual is subject to adjustment as the
actual measurement date approaches.
TXU Corp. is subject to extensive environmental regulation by
governmental authorities. In operating its facilities, TXU Corp. is required to
comply with numerous environmental laws and regulations, and to obtain numerous
governmental permits. TXU Corp. may incur significant additional costs to comply
with these requirements. If TXU Corp. fails to comply with these requirements,
it could be subject to civil or criminal liability and fines. Existing
environmental regulations could be revised or reinterpreted, new laws and
regulations could be adopted or become applicable to TXU Corp. or its
facilities, and future changes in environmental laws and regulations could
occur, including potential regulatory and enforcement developments related to
air emissions.
65
TXU Corp. may not be able to obtain or maintain all required
environmental regulatory approvals. If there is a delay in obtaining any
required environmental regulatory approvals or if TXU Corp. fails to obtain,
maintain or comply with any such approval, the operation of its facilities could
be stopped or become subject to additional costs. Further, at some of TXU
Corp.'s older facilities it may be uneconomical for TXU Corp. to install the
necessary equipment, which may cause TXU Corp. to shut down those facilities.
In addition, TXU Corp. may be responsible for any on-site
liabilities associated with the environmental condition of facilities that it
has acquired or developed, regardless of when the liabilities arose and whether
they are known or unknown. In connection with certain acquisitions and sales of
assets, TXU Corp. may obtain, or be required to provide, indemnification against
certain environmental liabilities. Another party could fail to meet its
indemnification obligations to TXU Corp.
On January 1, 2002, most retail customers in Texas of investor-owned
utilities, and those of any municipal utility and electric cooperative that
opted to participate in the competitive marketplace, became able to choose their
REP. On January 1, 2002, TXU Corp. began to provide retail electric services to
all customers who did not take action to select another REP.
TXU Corp. will not be permitted to offer electricity to residential
and small commercial customers in its historical service territory at a price
other than the price-to-beat rate until January 1, 2005, unless before that date
the Commission determines that 40% or more of the amount of electric power
consumed by each respective class of customers in that area is committed to be
served by REPs other than TXU Corp. Because TXU Corp. will not be able to
compete for residential and small commercial customers on the basis of price in
its historical service territory, TXU Corp. could lose a significant number of
these customers to other providers. In addition, at times, during this period,
if the market price of power is lower than TXU Corp.'s cost to produce power,
TXU Corp. would have a limited ability to mitigate the loss of margin caused by
its loss of customers by selling power from its power production facilities.
Other REPs will be allowed to offer electricity to TXU Corp.'s
residential and small commercial customers at any price. The margin or
"headroom" available in the price-to-beat rate for any REP equals the difference
between the price-to-beat rate and the sum of delivery charges and the price
that REP pays for power. The higher the amount of headroom for competitive REPs,
the more incentive those REPs should have to provide retail electric services in
a given market.
TXU Corp. provides commodity and value-added energy management
services to the large commercial and industrial customers who did not take
action to select another REP beginning on January 1, 2002. TXU Corp. or any
other REP can offer to provide services to these customers at any negotiated
price. TXU Corp. believes that this market will be very competitive;
consequently, a significant number of these customers may choose to be served by
another REP, and any of these customers that select TXU Corp. to be its provider
may subsequently decide to switch to another provider.
An affiliated REP is obligated to offer the price-to-beat rate to
requesting residential and small commercial customers in the historical service
territory of its incumbent utility through January 1, 2007. The initial
price-to-beat rates for the affiliated REPs, including TXU Corp.'s, were
established by the Commission on December 7, 2001. Pursuant to Commission
regulations, the initial price-to-beat rate for each affiliated REP is 6% less
than the average rates in effect for its incumbent utility on January 1, 1999,
adjusted to take into account a new fuel factor as of December 31, 2001.
The results of TXU Corp.'s retail electric operations in its
historical service territory will be largely dependent upon the amount of
headroom available to TXU Corp. and the competitive REPs in TXU Corp.'s
price-to-beat rate. Since headroom is dependent, in part, on power purchase
costs, TXU Corp. does not know nor can it estimate the amount of headroom that
it or other REPs will have in TXU Corp.'s price-to-beat rate or in the
price-to-beat rate for the affiliated REP in each of the other Texas retail
electric markets. Headroom may be a positive or negative number. If the amount
of headroom in its price-to-beat rate is a negative number, TXU Corp. will be
selling power to its price-to-beat rate customers in its historical service
territory at prices below its costs of purchasing and delivering power to those
customers. If the amount of positive headroom for competitive REPs in its
price-to-beat rate is large, TXU Corp. may lose customers to competitive REPs.
66
Under amended Commission rules, effective in March 2003, affiliated
REPs of utilities are allowed to petition the Commission twice per year for an
increase in the fuel factor component of their price-to-beat rates if the
average price of natural gas futures increases more than 5% (10% if the petition
is filed after November 15 of any year) from the level used to set the previous
price-to-beat fuel factor rate.
- -- In January 2003, TXU Energy filed a request with the Commission to
increase the fuel factor component of its price-to-beat rates based
upon significant increases in the market price of natural gas. This
request was approved on March 5, 2003. The fuel factor increase went
into effect for the billing cycle that began March 6, 2003. As a
result, average monthly residential bills will rise approximately 12%.
- -- On July 23, 2003, TXU Energy filed another request with the Commission
to increase the fuel factor component of its price-to-beat rates. The
change would raise the average monthly residential electric bill of a
customer using an average of 1,000 kilowatt-hours by 3.7 percent, or
$3.61 per month. Even with the increase, TXU Energy would continue to
have the lowest price-to-beat rate in the state. The Commission has 45
days from the filing of the request, or as soon as possible, to review
the request. This request would increase TXU Energy's revenues by
approximately $180 million ($50 million for the remainder of 2003, if
approved in mid-September) on an annualized basis.
There is no assurance that TXU Corp.'s price-to-beat rate will not
result in negative headroom in the future, or that future adjustments to its
price-to-beat rate will be adequate to cover future increases in its costs to
purchase power to serve its price-to-beat rate customers.
In most retail electric markets outside its historical service
territory, TXU Corp.'s principal competitor may be the local incumbent utility
company or its retail affiliate. The incumbent utilities have the advantage of
long-standing relationships with their customers. In addition to competition
from the incumbent utilities and their affiliates, TXU Corp. may face
competition from a number of other energy service providers, or other energy
industry participants, who may develop businesses that will compete with TXU
Corp. in both local and national markets, and nationally branded providers of
consumer products and services. Some of these competitors or potential
competitors may be larger and better capitalized than TXU Corp. If there is
inadequate margin in these retail electric markets, it may not be profitable for
TXU Corp. to enter these markets.
TXU Corp. depends on T&D facilities owned and operated by other
utilities, as well as its own such facilities, to deliver the electricity it
produces and sells to consumers, as well as to other REPs. If transmission
capacity is inadequate, TXU Corp.'s ability to sell and deliver electricity may
be hindered, it may have to forgo sales or it may have to buy more expensive
wholesale electricity that is available in the capacity-constrained area. In
particular, during some periods transmission access is constrained to some areas
of the Dallas-Fort Worth metroplex. TXU Corp. expects to have a significant
number of customers inside these constrained areas. The cost to provide service
to these customers may exceed the cost to service other customers, resulting in
lower headroom. In addition, any infrastructure failure that interrupts or
impairs delivery of electricity to TXU Corp.'s customers could negatively impact
the satisfaction of its customers with its service.
Additionally, in certain parts of Texas, TXU Corp. is dependent on
unaffiliated T&D utilities for the reading of its customers' energy meters. TXU
Corp. is required to rely on the utility or, in some cases, the independent
transmission system operator, to provide it with its customers' information
regarding energy usage, and it may be limited in its ability to confirm the
accuracy of the information.
TXU Corp. offers its customers a bundle of services that include, at
a minimum, the electric commodity itself plus transmission, distribution and
related services. To the extent that the prices TXU Corp. charges for this
bundle of services or for the various components of the bundle, either of which
may be fixed by contract with the customer for a period of time, differ from TXU
Corp.'s underlying cost to obtain the commodities or services, its results of
operations would be adversely affected. TXU Corp. will encounter similar risks
in selling bundled services that include non-energy-related services, such as
telecommunications, facilities management, and the like. In some cases, TXU
Corp. has little, if any, prior experience in selling these non-energy-related
services.
67
Under the Commission's rules, as an affiliated REP, TXU Corp. may
have to temporarily provide electric service to some customers that are unable
to pay their electric bills. If the numbers of such customers are significant
and TXU Corp. is delayed in terminating electric service to those customers, its
results of operations may be adversely affected.
The information systems and processes necessary to support risk
management, sales, customer service and energy procurement and supply in
competitive retail markets in Texas and elsewhere are new, complex and
extensive. TXU Corp. is refining these systems and processes, and they may prove
more expensive to refine than planned and may not work as planned.
Research and development activities are ongoing to improve existing
and alternative technologies to produce electricity, including gas turbines,
fuel cells, microturbines and photovoltaic (solar) cells. It is possible that
advances in these or other alternative technologies will reduce the costs of
electricity production from these technologies to a level that will enable these
technologies to compete effectively with electricity production from traditional
power plants like TXU Corp.'s. While demand for electric energy services is
generally increasing throughout the US, the rate of construction and development
of new, more efficient power production facilities may exceed increases in
demand in some regional electric markets. The commencement of commercial
operation of new facilities in the regional markets where TXU Corp. has
facilities will likely increase the competitiveness of the wholesale power
market in that region. In addition, the market value of TXU Corp.'s power
production and/or energy transportation facilities may be significantly reduced.
Also, electricity demand could be reduced by increased conservation efforts and
advances in technology, which could likewise significantly reduce the value of
TXU Corp.'s facilities. Changes in technology could also alter the channels
through which retail electric customers buy electricity.
TXU Corp. is subject to employee workforce factors, including loss
or retirement of key executives, availability of qualified personnel, collective
bargaining agreements with union employees or work stoppage.
TXU Corp. is a holding company and conducts its operations primarily
through wholly-owned subsidiaries. Substantially all of TXU Corp.'s consolidated
assets are held by these subsidiaries. Accordingly, TXU Corp.'s cash flows and
ability to meet its obligations and to pay dividends are largely dependent upon
the earnings of its subsidiaries and the distribution or other payment of such
earnings to TXU Corp. in the form of distributions, loans or advances, and
repayment of loans or advances from TXU Corp.
Because TXU Corp. is a holding company, its obligations to its
creditors are structurally subordinated to all existing and future liabilities
and existing and future preferred stock of its subsidiaries. Therefore, TXU
Corp.'s rights and the rights of its creditors to participate in the assets of
any subsidiary in the event that such a subsidiary is liquidated or reorganized
are subject to the prior claims of such subsidiary's creditors and holders of
its preferred stock. To the extent that TXU Corp. may be a creditor with
recognized claims against any such subsidiary, its claims would still be subject
to the prior claims of such subsidiary's creditors to the extent that they are
secured or senior to those held by TXU Corp.
The inability to raise capital on favorable terms, particularly
during times of uncertainty in the financial markets, could impact TXU Corp.'s
ability to sustain and grow its businesses, which are capital intensive, would
increase its capital costs. TXU Corp. relies on access to financial markets as a
significant source of liquidity for capital requirements not satisfied by cash
on hand or operating cash flows. TXU Corp.'s access to the financial markets
could be adversely impacted by various factors, such as:
o changes in credit markets that reduce available credit or the ability to
renew existing liquidity facilities on acceptable terms;
o inability to access commercial paper markets;
68
o a deterioration of TXU Corp.'s credit or a reduction in TXU Corp.'s
credit ratings or the credit ratings of its subsidiaries;
o extreme volatility in TXU Corp.'s markets that increases margin or credit
requirements;
o a material breakdown in TXU Corp.'s risk management procedures;
o prolonged delays in billing and payment resulting from delays in switching
customers from one REP to another; and
o the occurrence of material adverse changes in TXU Corp.'s businesses
that restrict TXU Corp.'s ability to access its liquidity facilities.
A lack of necessary capital and cash reserves could adversely impact
the evaluation of TXU Corp.'s credit worthiness by counterparties and rating
agencies. Further, concerns on the part of counterparties regarding TXU Corp.'s
liquidity and credit could limit its portfolio management activities.
As a result of the energy crisis in California during 2001, the
recent volatility of natural gas prices in North America, the bankruptcy filing
by Enron Corporation, accounting irregularities of public companies, and
investigations by governmental authorities into energy trading activities,
companies in the regulated and non-regulated utility businesses have been under
a generally increased amount of public and regulatory scrutiny. Accounting
irregularities at certain companies in the industry have caused regulators and
legislators to review current accounting practices and financial disclosures.
The capital markets and ratings agencies also have increased their level of
scrutiny. Additionally, allegations against various energy trading companies of
"round trip" or "wash" transactions, which involve the simultaneous buying and
selling of the same amount of power at the same price and provide no true
economic benefit, power market manipulation and inaccurate power and commodity
price reporting have had a negative effect on the industry. TXU Corp. believes
that it is complying with all applicable laws, but it is difficult or impossible
to predict or control what effect these events may have on TXU Corp.'s financial
condition or access to the capital markets. Additionally, it is unclear what
laws and regulations may develop, and TXU Corp. cannot predict the ultimate
impact of any future changes in accounting regulations or practices in general
with respect to public companies, the energy industry or its operations
specifically.
TXU Corp. is subject to costs and other effects of legal and
administrative proceedings, settlements, investigations and claims. Since
October 2002, a number of lawsuits have been filed in federal and state courts
in Texas against TXU Corp. and various of its officers, directors and
underwriters. In addition, TXU Corp. is unable to predict whether its decision
to exit all of its operations in Europe, including the administration
proceeding, might result in lawsuits by the creditors of or others associated
with TXU Europe. Such current and potential legal proceedings could result in
payments of judgment or settlement amounts.
The market price of TXU Corp.'s common stock has been volatile in
the past, and a variety of factors could cause the price to fluctuate in the
future. In addition to the matters discussed above and in TXU Corp.'s other
filings under the Securities Exchange Act of 1934, as amended, the following
could impact the market price for TXU Corp.'s common stock:
o developments related to TXU Corp.'s businesses;
o fluctuations in TXU Corp.'s results of operations;
o the level of dividends;
o TXU Corp.'s debt to equity ratios and other leverage ratios;
o effect of significant events relating to the energy sector in general;
o sales of TXU Corp. securities into the marketplace;
o general conditions in the industry and the energy markets in which
TXU Corp. is a participant;
o the worldwide economy;
o an outbreak of war or hostilities;
o a shortfall in revenues or earnings compared to securities analysts'
expectations;
o changes in analysts' recommendations or projections; and
o actions by credit rating agencies.
69
The issues and associated risks and uncertainties described above
are not the only ones TXU Corp. may face. Additional issues may arise or become
material as the energy industry evolves.
FORWARD-LOOKING STATEMENTS
This report and other presentations made by TXU Corp. contain
forward-looking statements within the meaning of Section 21E of the Securities
Exchange Act of 1934, as amended. Although TXU Corp. 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 risks discussed above under RISK FACTORS THAT MAY AFFECT FUTURE RESULTS
and factors contained in the Forward-Looking Statements section of Item 7.
Management's Discussion and Analysis of Financial Condition and Results of
Operations in TXU Corp.'s 2002 Form 10-K, that could cause the actual results of
TXU Corp. to differ materially from those projected in such forward-looking
statements.
Any forward-looking statement speaks only as of the date on which
such statement is made, and TXU Corp. 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 TXU
Corp. to predict all of such factors, nor can it assess the impact of each such
factor or the extent to which any factor, or combination of factors, may cause
actual results to differ materially from those contained in any forward-looking
statement.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Except as discussed below, the information required hereunder is not
significantly different from the information set forth in Item 7A. Quantitative
and Qualitative Disclosures About Market Risk included in TXU Corp.'s 2002 Form
10-K and is therefore not presented herein.
COMMODITY PRICE RISK
Value at Risk (VaR) for Energy Contracts Subject to Mark-to-Market
Accounting -- This measurement estimates the maximum potential loss in value,
due to changes in market conditions, of all energy-related contracts subject to
mark-to-market accounting, based on a specific confidence level and an assumed
holding period. Assumptions in determining this VaR include using a 95%
confidence level and a five-day holding period. A probabilistic simulation
methodology is used to calculate VaR, and is considered by management to be the
most effective way to estimate changes in a portfolio's value based on assumed
market conditions for liquid markets. TXU Australia uses a variance-covariance
methodology in deriving its VaR calculation, due to the differences in its
market as compared to that of TXU Energy.
June 30, December 31,
2003 2002
---- ----
Period-end MtM VaR:
------------------
North America Energy......................... $ 26 $23
Australia ................................... $ 16 $13
Average MtM VaR (Year-to-date):
-------------------------------
North America Energy......................... $31 $ 38
Australia ................................... $16 $ 15
70
Portfolio VaR -- Represents the estimated maximum potential loss in
value, due to changes in market conditions, of the entire energy portfolio,
including owned assets and all contractual positions (the portfolio assets).
Assumptions in determining this VaR include using a 95% confidence level and a
five-day holding period and includes both mark-to-market and accrual positions.
June 30, December 31,
2003 2002
---- ----
Period-end Portfolio VaR:
-------------------------
North America Energy............................. $180 $144
Australia ....................................... $ 21 $22
Average Portfolio VaR (Year-to-date):
------------------------------------
North America Energy (a)......................... $186 N/A
Australia........................................ $ 21 $23
(a) Comparable information on an average VaR basis is not available for the full
year 2002.
Other Risk Measures -- The metrics appearing below provide
information regarding the effect of energy changes in market conditions on
earnings and cash flow of TXU Energy. Similar metrics for TXU Australia are not
available.
North America Earnings at Risk (EaR) -- EaR measures the estimated
potential loss in expected earnings due to changes in market conditions. EaR
metrics include the portfolio assets except for accrual positions expected to be
settled beyond the fiscal year. Assumptions include using a 95% confidence level
over a five-day holding period under normal market conditions.
North America Cash Flow at Risk (CFaR) -- CFaR measures the
estimated potential loss of expected cash flow over the next six months, due to
changes in market conditions. CFaR metrics include all portfolio positions that
impact cash flow during the next six months. Assumptions include using a 99%
confidence level over a 6-month holding period under normal market conditions.
The following CFaR calculation is based on a contract settlement period of six
months.
June 30, December 31,
2003 2002
---- ----
EaR ..................................... $ 20 $ 28
CFaR .................................... $108 $178
INTEREST RATE RISK
See Note 4 to Financial Statements for a discussion of the issuance
of new fixed rate debt and retirement of fixed rate debt since December 31, 2002
and new interest rate swaps.
71
CREDIT RISK
Concentration of Credit Risk -- TXU Corp.'s regional gross
exposure to credit risk as of June 30, 2003, is as follows:
Region Credit Exposure
------ ---------------
US............................ $3,100
Australia..................... 601
------
Consolidated.................. $3,701
======
TXU Corp.'s gross exposure to credit risk represents trade accounts
receivable (net of allowance for uncollectible accounts receivable of $80
million), commodity contract assets and derivative assets related to cash flow
and fair value hedges. These regional concentrations have the potential to
affect TXU Corp.'s overall exposure to credit risk, either positively or
negatively, in that the customer base and counterparties may be similarly
affected, both regionally and globally, by changes in economic, regulatory,
industry, weather or other conditions. Global credit coordination is in place to
reduce credit limits on a global basis, to provide transparency across regions
and to communicate through various risk committees and forums.
A large share of gross assets subject to credit risk represents
accounts receivable from the retail sale of electricity and gas to residential
and small commercial customers. The risk of material loss from non-performance
from these customers is unlikely based upon historical experience. Reserves for
uncollectible accounts receivable are established for the potential loss from
non-payment by these customers based on historical experience and market or
operational conditions. In addition, Oncor has exposure to credit risk as a
result of non-performance by nonaffiliated REPs.
Most of the remaining trade accounts receivable are with large
commercial/industrial customers. TXU Corp.'s wholesale commodity contract
counterparties include major energy companies, financial institutions, gas and
electric utilities, independent power producers, oil and gas producers and
energy trading companies.
The following table presents the distribution of credit exposure as
of June 30, 2003, for trade accounts receivable from large
commercial/industrial customers, commodity contract assets and derivative assets
related to cash flow and fair value hedges, by investment grade and
noninvestment grade, credit quality and maturity.
Exposure by Maturity
--------------------------------------------
Exposure
before Greater
Credit Credit Net 2 years or Between than 5
Collateral Collateral Exposure less 2-5 years years Total
---------- ---------- -------- ---------- --------- ------- -----
Investment grade $ 1,092 $ (134) $ 958 $ 670 $188 $100 $ 958
Noninvestment grade 503 (153) 350 283 35 32 350
Totals --------- ------- ------ ----- ---- ---- ------
$1,595 $ (287) $1,308 $ 953 $223 $132 $1,308
========= ======= ====== ===== ==== ==== ======
Investment grade 68% 47% 73%
Noninvestment grade 32% 53% 27%
The exposure to credit risk from these customers and
counterparties, excluding credit collateral, as of June 30, 2003, is $1.6
billion net of standardized master netting contracts and agreements which
provide the right of offset of positive and negative credit exposures with
individual customers and counterparties. When considering collateral currently
held by TXU Corp. (cash, letters of credit and other security interests), the
net credit exposure is $1.3 billion. Of this amount, approximately 73% of the
associated exposure is with investment grade customers and counterparties, as
determined using publicly available information including major rating agencies'
published ratings and TXU Corp.'s internal credit evaluation process. Those
customers and counterparties without an S&P rating of at least BBB- or similar
rating from another major rating agency, are rated using internal credit
methodologies and credit scoring models to estimate an S&P equivalent rating.
TXU Corp. routinely monitors and manages its credit exposure to these customers
and counterparties on this basis.
TXU Corp. had no exposure to any one customer or counterparty
greater than 10% of the net exposure of $1.3 billion at June 30, 2003.
Additionally, approximately 73% of the credit exposure, net of collateral held,
has a maturity date of two years or less. TXU Corp. does not anticipate any
material adverse effect on its financial position or results of operations as
a result of non-performance by any customer or counterparty.
72
Item 4. CONTROLS AND PROCEDURES
An evaluation was performed under the supervision and with the
participation of TXU Corp.'s management, including the principal executive
officer and principal financial officer, of the effectiveness of the design and
operation of the disclosure controls and procedures in effect as of the end of
the current period included in this quarterly report. Based on the evaluation
performed, TXU Corp.'s management, including the principal executive officer and
principal financial officer, concluded that the disclosure controls and
procedures were effective. During the most recent fiscal quarter covered by this
quarterly report, there has been no change in TXU Corp.'s internal control over
financial reporting that has materially affected, or is reasonably likely to
materially affect, TXU Corp.'s internal control over financial reporting.
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
Legal Proceedings -- In October, November and December
2002 and January 2003, a number of lawsuits were filed in, removed to or
transferred to the United States District Court for the Northern District of
Texas against TXU Corp., and certain of its officers. These lawsuits have all
been consolidated and lead plaintiffs have been appointed by the Court. On July
21, 2003, the lead plaintiffs filed an amended consolidated complaint naming
Erle Nye, Michael J. McNally, V.J. Horgan and Brian N. Dickie and directors
Derek C. Bonham, J.S. Farrington, William M. Griffin, Kerney Laday, Jack E.
Little, Margaret N. Maxey, J.E. Oesterreicher, Herbert H. Richardson and
Charles R. Perry, as defendants. The plaintiffs seek to represent classes of
certain purchasers of TXU Corp. common and equity-linked debt during a
proposed class period from April 26, 2001 to October 11, 2002. No class or
classes have been certified. The complaint alleges violations of the provisions
of Sections 10(b) and 20(a) of the Securities Exchange Act of 1934, as amended,
and Rule 10b-5 promulgated thereunder, and Sections 11 and 12 of the Securities
Act of 1933, as amended (Securities Act), relating to alleged materially false
and misleading statements, including statements in prospectuses related to the
offering by TXU Corp. of its equity-linked securities and common stock in May
and June 2002. The named individual defendants are current or former officers
and/or directors of TXU Corp. While TXU Corp. believes the claims are without
merit and intends to vigorously defend this lawsuit, it is unable to estimate
any possible loss or predict the outcome of this action.
On July 7, 2003, a lawsuit was filed by Texas Commercial Energy
(TCE) in the United States District Court for the Southern District of Texas,
Corpus Christi Division, against TXU Energy and certain of its subsidiaries, as
well as various other wholesale market participants doing business in ERCOT,
claiming generally that defendants engaged in market manipulation, in violation
of antitrust and other laws, primarily during the period of extreme weather
conditions in late February 2003. On August 6, 2003, the complaint was amended
to omit one of the other defendants. TXU Corp. believes that it has not
committed any violation of the antitrust laws and the Commission's investigation
of the market conditions in late February 2003 has not resulted in any findings
adverse to TXU Energy. Accordingly, TXU Corp. believes that TCE's claims against
TXU Energy and its subsidiary companies are without merit and intends to
vigorously defend the lawsuit. As with any litigation of this nature, TXU Corp.
is unable to estimate any possible loss or predict the outcome of this action.
On March 10, 2003, a lawsuit was filed by Kimberly P. Killebrew in
the United States District Court for the Eastern District of Texas, Lufkin
Division, against TXU Corp. and TXU Portfolio Management, asserting generally
that defendants engaged in manipulation of the wholesale electric market, in
violation of antitrust and other laws. This lawsuit was not served on TXU Corp.
until mid-July 2003. This action is brought by an individual, alleged to be a
retail consumer of electricity, on behalf of herself and as a proposed
73
representative of a putative class of retail purchasers of electricity that are
similarly situated. TXU Corp. believes that the Plaintiff likely lacks standing
to assert any antitrust claims against TXU Corp. or TXU Portfolio Management,
and that defendants have not violated antitrust laws or other laws as claimed by
the Plaintiff. Therefore, TXU Corp. believes that plaintiff's claims are without
merit and plans to vigorously defend the lawsuit. As with any litigation of this
nature, however, TXU Corp. is unable to estimate any possible loss or predict
the outcome of this action.
Reference is made to the 2002 Form 10-K and the Form 10-Q for the
quarterly period ended March 31, 2003 for additional discussion of legal
proceedings.
74
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
TXU Corp. held its Annual Meeting of Shareholders on
May 16, 2003. The following items were presented to shareholders with the
following results:
Votes
Votes Withheld or
For Against Abstentions
----------- ------------ -----------
Election of Directors
Derek C. Bonham 260,059,953 20,652,446 None
J. S. Farrington 269,719,951 10,992,448 None
William M. Griffin 267,561,845 13,150,554 None
Kerney Laday 259,057,913 21,654,486 None
Jack E. Little 268,022,177 12,690,222 None
Margaret N. Maxey 269,476,691 11,235,708 None
Erle Nye 267,624,009 13,088,390 None
J. E. Oesterreicher 267,816,788 12,895,611 None
Michael W. Ranger 270,046,746 10,665,653 None
Herbert H. Richardson 269,753,157 10,989,242 None
Shareholder Proposal Related
to Indexed Stock Options 36,142,705 192,358,191 5,772,782
Shareholder Proposal Related
to an Environmental Report 52,207,557 163,617,392 18,448,477
Selection of Deloitte & Touche LLP
as Independent Auditors 270,703,473 7,481,478 2,527,451
75
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits provided as part of Part II are:
4(a) Amendment No. 1, dated as of July 1, 2003, to the Exchange
Agreement, dated as of November 22, 2002, among TXU Corp., TXU
Energy, UXT Holdings LLC and UXT Intermediary LLC.
4(b) Amendment No. 2, dated as of July 1, 2003, to the Registration
Rights Agreement, dated as of November 22, 2002, among TXU
Corp., UXT Holdings LLC and UXT Intermediary LLC.
15 Letter from Independent Accountants as to Unaudited Interim
Financial Information.
31(a) Section 302 Certification of Chief Executive Officer.
31(b) Section 302 Certification of Chief Financial Officer.
32(a)* Section 906 Certification of Chief Executive Officer.
32(b)* Section 906 Certification of Chief Financial Officer.
99(a) Condensed Statements of Consolidated Income - Twelve Months
Ended June 30, 2003.
* Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this
certificate is not being "filed" for purposes of Section 18 of
the Securities Act of 1934.
(b) Reports on Form 8-K filed since March 31, 2003:
Date of Report Item Reported
-------------- -------------
April 30, 2003 Item 5. Other Events and
Regulation FD Disclosure
Item 7. Exhibits
May 1, 2003 Item 9. Regulation FD Disclosure
(Being Provided Under Item 12)
Item 7. Financial Statements and Exhibits
May 1, 2003 Item 7. Exhibits
(Form 8-K/A)
June 3, 2003 Item 5. Other Events and
Regulation FD Disclosure
June 30, 2003 Item 5. Other Events and
Regulation FD Disclosure
July 10, 2003 Item 5. Other Events and
Regulation FD Disclosure
Item 7. Exhibits
July 25, 2003 Item 7. Exhibits
July 31, 2003 Item 12. Results of Operations and
Regulation FD Disclosure
Item 7. Financial Statements and Exhibits
July 31, 2003 Item 5. Other Events and
Regulation FD Disclosure
76
SIGNATURE
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.
TXU CORP.
By /s/ David H. Anderson
---------------------------------
David H. Anderson
Vice President and Controller
Date: August 13, 2003
77