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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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 SEPTEMBER 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
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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 November 7, 2003: 323,889,698 shares,
without par value.
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TABLE OF CONTENTS
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PAGE
----
Glossary .......................................................................................... ii
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Statements of Consolidated Income -
Three and Nine Months Ended September 30, 2003 and 2002............... 1
Condensed Statements of Consolidated Comprehensive Income -
Three and Nine Months Ended September 30, 2003 and 2002.............. 2
Condensed Statements of Consolidated Cash Flows -
Nine Months Ended September 30, 2003 and 2002......................... 3
Condensed Consolidated Balance Sheets -
September 30, 2003 and December 31, 2002.............................. 4
Notes to Financial Statements......................................... 5
Independent Accountants' Report....................................... 31
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations............................................. 32
Item 3. Quantitative and Qualitative Disclosures About Market Risk........... 72
Item 4. Controls and Procedures.............................................. 75
PART II. OTHER INFORMATION
Item 1. Legal Proceedings.................................................... 76
Item 6. Exhibits and Reports on Form 8-K .................................... 77
SIGNATURE.................................................................................. 79
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 8-K.........................the Form 8-K of TXU Corp. filed
September 23, 2003, reflecting the impact
of adopting SFAS 145 on the financial
information reported in the 2002
Form 10-K
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"
EITF 03-11............................EITF Issue No. 03-11, `Reporting Realized
Gains and Losses on Derivative Instruments
That Are Subject to FASB Statement
No. 133 and Not "Held for Trading
Purposes" As Defined in EITF No. 02-3'
ERCOT.................................Electric Reliability Council of Texas
FASB..................................Financial Accounting Standards Board, the
designated organization in the private
sector for establishing standards for
financial accounting and reporting.
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, a
subsidiary of US Holdings
Pinnacle..............................Pinnacle One Partners, L.P., the
telecommunications business reported as
discontinued operations and formerly a
joint venture
POLR..................................provider of last resort of electricity to
certain customers under the Commission
rules interpreting the 1999
Restructuring Legislation
Price-to-beat rate....................residential and small commercial
customer electricity rates established by
the Commission in the restructuring of
the Texas market and required to be
charged in a REP's historical service
territories until January 1, 2005 or
when 40% of the electricity consumed by
such customer classes is supplied by
competing REPs, adjusted periodically for
changes in fuel costs
ii
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"
SFAS 133..............................SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities"
SFAS 140..............................SFAS No. 140, "Accounting for Transfers
and Servicing of Financial Assets and
Extinguishments of Liabilities a
replacement of FASB Statement 125"
SFAS 142..............................SFAS No. 142, "Goodwill and Other
Intangible Assets"
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, a subsidiary of
TXU Corp.
TXU Corp..............................refers to TXU Corp. or TXU Corp. and its
consolidated subsidiaries, depending
on context
TXU Energy............................TXU Energy Company LLC, a subsidiary of
US Holdings
TXU Europe............................TXU Europe Limited, a subsidiary of
TXU Corp.
TXU Fuel..............................TXU Fuel Company, a subsidiary of
TXU Energy
TXU Gas...............................TXU Gas Company, a subsidiary of TXU Corp.
TXU Mining............................TXU Mining Company LP, a subsidiary of
TXU Energy
TXU Portfolio Management..............TXU Portfolio Management Company LP, a
subsidiary of TXU Energy
TXU SESCO.............................TXU SESCO Company, a subsidiary of
TXU Energy which serves as a REP in ten
counties in the eastern and central
parts of Texas
US....................................United States of America
US GAAP...............................accounting principles generally accepted
in the US
US Holdings...........................TXU US Holdings Company, a subsidiary of
TXU Corp.
iii
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
TXU CORP. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2003 2002 2003 2002
-------- ------- ------- ------
(millions of dollars, except per share amounts)
Operating revenues...................................................... $3,136 $2,918 $8,607 $7,876
Costs and expenses:
Cost of energy sold and delivery fees................................ 1,342 1,279 3,905 3,062
Operating costs...................................................... 418 407 1,273 1,187
Depreciation and amortization........................................ 223 220 655 653
Selling, general and administrative expenses......................... 280 320 799 975
Franchise and revenue-based taxes.................................... 104 108 335 343
Other income......................................................... (26) (20) (66) (46)
Other deductions..................................................... 13 23 36 82
Interest income...................................................... (6) (6) (25) (21)
Interest expense and related charges................................. 240 214 736 647
----- ----- ----- -----
Total costs and expenses......................................... 2,588 2,545 7,648 6,882
----- ----- ----- -----
Income from continuing operations before income taxes and cumulative effect
of changes in accounting principles................................. 548 373 959 994
Income tax expense...................................................... 175 118 293 304
----- ----- ----- -----
Income from continuing operations before cumulative effect
of changes in accounting principles.................................. 373 255 666 690
Income (loss) on discontinued operations, net of tax effect (Note 3).... 24 (44) (55) (23)
Cumulative effect of changes in accounting principles, net of tax
benefit (Note 2)....................................................... - - (58) -
----- ----- ------ -----
Net income ............................................................. 397 211 553 667
Preference stock dividends.............................................. 5 5 16 16
----- ----- ----- -----
Net income available for common stock................................... $ 392 $ 206 $ 537 $ 651
===== ===== ===== =====
Average shares of common stock outstanding (millions):
Basic................................................................ 322 282 321 272
Diluted.............................................................. 379 282 378 272
Per share of common stock:
Basic earnings:
Income from continuing operations before cumulative effect of
changes in accounting principles................................. $ 1.14 $ .88 $2.02 $ 2.48
Income (loss) on discontinued operations, net of tax effect........ .08 (.15) (.17) (.08)
Cumulative effect of changes in accounting principles, net of
tax benefit...................................................... - - (.18) -
----- ----- ----- -----
Net income available for common stock.............................. $ 1.22 $ .73 $1.67 $ 2.40
===== ===== ===== =====
Diluted earnings:
Income from continuing operations before cumulative effect of
changes in accounting principles................................ $ 1.01 $ .88 $1.82 $2.48
Income (loss) on discontinued operations, net of tax effect....... .06 (.15) (.15) (0.08)
Cumulative effect of changes in accounting principles, net of
tax benefit..................................................... - - (.15) -
----- ----- ----- -----
Net income available for common stock............................. $ 1.07 $ .73 $1.52 $2.40
====== ===== ===== =====
Dividends declared............................................... .125 .60 .375 1.80
See Notes to Financial Statements.
1
TXU CORP. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 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.......................... $ 373 $ 255 $ 666 $ 690
Other comprehensive income (loss), net of tax effects:
Cumulative foreign currency translation adjustments.......... 19 (29) 180 44
Cash flow hedges-
Net change in fair value of derivatives (net of tax
benefit of $11, $42, $104 and $114)...................... (20) (95) (204) (214)
Amounts realized in earnings during the period
(net of tax expense of $33, $10, $111 and $36)........... 64 32 217 74
----- ----- ----- -----
Total.................................................. 63 (92) 193 (96)
----- ------ ----- ------
Comprehensive income from continuing operations................... 436 163 859 594
Comprehensive income from discontinued operations:
Income (loss) on discontinued operations, net of tax effect.. 24 (44) (55) (23)
Minimum pension liability adjustments (net of tax benefit
of $3)..................................................... - - (6) -
Cumulative foreign currency translation adjustment........... - 76 - 253
Cash flow hedges (net of tax expense of $12 and $21)......... - 29 - 48
----- ----- ----- -----
Total.................................................. 24 61 (61) 278
Cumulative effect of changes in accounting principles, net of
tax benefit..................................................... - - (58) -
----- ----- ------ -----
Comprehensive income........................................ $ 460 $ 224 $ 740 $ 872
===== ===== ===== =====
See Notes to Financial Statements.
2
TXU CORP. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
-----------------
2003 2002
(millions of dollars)
Cash flows - operating activities:
Income from continuing operations before cumulative effect of
changes in accounting principles.......................................... $ 666 $ 690
Adjustments to reconcile income from continuing operations before cumulative
effect of changes in accounting principles to cash provided by
operating activities:
Depreciation and amortization ............................................... 712 715
Deferred income taxes and investment tax credits - net ...................... 118 169
Net gain from sale of assets................................................ (39) (30)
Net unrealized gain from mark-to-market valuations of commodity contracts.... (15) (6)
Net equity loss from unconsolidated affiliates and joint ventures............ 18 40
Adjustments related to gas cost recovery..................................... 47 67
Reduction in regulatory liability............................................ (125) (112)
Reduction in retail clawback accrual......................................... (19) -
Asset impairment charge...................................................... - 11
Changes in operating assets and liabilities..................................... 674 (505)
------ -----
Cash provided by operating activities.................................... 2,037 1,039
Cash flows - financing activities:
Issuances of securities:
Long-term debt............................................................... 2,449 2,868
Common stock................................................................. 27 717
Retirements/repurchases of securities:
Long-term debt............................................................... (1,705) (2,707)
Preferred stock of subsidiary................................................ (91) -
Change in notes payable:
Commercial paper............................................................. 11 284
Banks........................................................................ (2,301) (693)
Cash dividends paid:
Common stock................................................................. (120) (481)
Preference stock............................................................. (16) (16)
Redemption deposit applied to debt retirements.................................. 210 -
Debt premium, discount, financing and reacquisition expenses.................... (27) (77)
Other financing costs........................................................... - (30)
------ -----
Cash used in financing activities........................................ (1,563) (135)
Cash flows - investing activities:
Capital expenditures............................................................ (640) (733)
Acquisitions of businesses...................................................... (150) (36)
Proceeds from sale of assets.................................................... 19 445
Nuclear fuel ................................................................... (45) (51)
Investment in collateral trust ................................................. (525) -
Other........................................................................... (17) (25)
------- -----
Cash used in investing activities........................................ (1,358) (400)
Effect of exchange rates on cash and cash equivalents............................. - (6)
Cash used by discontinued operations.............................................. (39) (601)
------- ------
Net change in cash and cash equivalents........................................... (923) (103)
Cash and cash equivalents - beginning balance..................................... 1,574 216
------ -----
Cash and cash equivalents - ending balance........................................ $ 651 $ 113
====== =====
See Notes to Financial Statements.
3
TXU CORP. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
--------- -------
ASSETS (millions of dollars)
Current assets:
Cash and cash equivalents................................................... $ 651 $ 1,574
Restricted cash............................................................. - 210
Accounts receivable-- trade................................................. 1,332 1,696
Income taxes receivable..................................................... 36 488
Inventories................................................................. 546 493
Commodity contract assets................................................... 746 1,298
Assets of telecommunications holding company (Note 3)....................... 103 -
Other current assets........................................................ 272 263
----- ------
Total current assets................................................. 3,686 6,022
Investments:
Restricted cash............................................................. 643 96
Other investments........................................................... 658 757
Property, plant and equipment-- net........................................... 20,464 19,642
Goodwill and other unamortized intangible assets.............................. 1,737 1,588
Regulatory assets-- net...................................................... 1,934 1,772
Commodity contract assets..................................................... 461 657
Cash flow hedges and other derivative assets.................................. 145 150
Other noncurrent assets....................................................... 371 332
Telecommunications assets held for sale (Note 3).............................. 670 -
------- -------
Total assets......................................................... $30,769 $31,016
======= =======
LIABILITIES, PREFERRED INTERESTS
AND SHAREHOLDERS' EQUITY
Current liabilities:
Notes payable:
Commercial paper......................................................... $ 34 $ 18
Banks.................................................................... 6 2,306
Long-term debt due currently................................................ 402 958
Accounts payable-- trade.................................................... 891 1,054
Commodity contract liabilities.............................................. 550 1,138
Liabilities of telecommunications holding company (Note 3).................. 695 -
Other current liabilities................................................... 1,094 1,209
------- -------
Total current liabilities............................................ 3,672 6,683
Accumulated deferred income taxes and investment tax credits.................. 4,374 4,060
Commodity contract liabilities................................................ 404 520
Cash flow hedges and other derivative liabilities............................. 279 220
Other noncurrent liabilities and deferred credits............................. 2,350 2,144
Telecommunications liabilities held for sale (Note 3)......................... 133 --
Long-term debt, less amounts due currently.................................... 12,596 11,597
------ ------
Total liabilities.................................................... 23,808 25,224
Preferred securities of subsidiaries (Note 5)................................. 1,272 726
Contingencies (Note 7)
Shareholders' equity (Note 6):
Preferred stock - not subject to mandatory redemption....................... 300 300
Common stock without par value: Authorized shares: 1,000,000,000
Outstanding shares: September 30, 2003 - 323,802,730
and December 31, 2002 - 321,974,000.................................... 25 7,995
Additional paid in capital.................................................. 8,097 111
Retained deficit............................................................ (2,480) (2,900)
Accumulated other comprehensive loss........................................ (253) (440)
-------- --------
Total common stock equity............................................ 5,389 4,766
------- -------
Total shareholders' equity........................................... 5,689 5,066
------- -------
Total liabilities, preferred interests and shareholders' equity...... $30,769 $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, SFAS 145 (the effects of
which have been reflected in the 2002 Form 8-K filed September 23, 2003) and
SFAS 150, all discussed below.
In the opinion of management, all other 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 8-K. The
results of operations for an interim period may not give a true indication of
results for a full year. Certain previously reported amounts have been
reclassified to conform to current classifications.
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.
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 $25 million (pre-tax) and an
increase in net income of $16 million ($0.04 per diluted share) in the
nine-months ended September 30, 2003.
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.)
5
As a result of guidance provided in EITF 02-3, TXU Corp. has not
recognized origination gains on commercial and industrial retail contracts in
2003. For the three- and nine-month periods ended September 30, 2002, TXU Corp.
recognized $2 million and $36 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 nine months ended
September 30, 2002 reflect a reclassification of a previously reported
extraordinary loss of $18 million (after-tax) on the early extinguishment of
debt to other deductions ($28 million) and income tax expense ($10 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." 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 $0.07 for the nine
months ended September 30, 2002 and decreases the extraordinary loss, per share,
by the same amount.
SFAS 146 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 impact results of operations for the nine months
ended September 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 stock-based compensation plans,
including stock options, using the intrinsic value method. TXU Corp. does not
currently issue stock options, and only 23,674 previously issued options remain
outstanding at September 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 was issued in November 2002 and 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 impact results of operations
for the nine months ended September 30, 2003.
FIN 46, which was issued in January 2003, provides guidance related to
identifying variable interest entities and determining whether such entities
should be consolidated. On October 8, 2003, the FASB decided to defer
implementation of FIN 46 until the fourth quarter of 2003. This deferral only
applies to variable interest entities that existed prior to February 1, 2003.
The adoption of FIN 46 did not and is not expected to impact results of
operations.
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. Also, EITF 03-11 became effective October 1,
2003 and, among other things, discussed the nature of certain power contracts.
As a result of the issuance of SFAS 149 and EITF 03-11, certain commodity
contract hedges are expected to be replaced with another type of hedge that is
subject to effectiveness testing. The adoption of these changes did not impact
results of operations for the nine months ended September 30, 2003.
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 mandatorily redeemable preferred securities be classified as
liabilities beginning July 1, 2003. A FASB Staff Position (FSP 150-3) issued
November 7, 2003 defers the applicability of SFAS 150 to the
mandatorily redeemable preferred securities of subsidiary trusts. The
September 30, 2003 balance sheet reflects the classification of certain
preferred securities of subsidiaries subject to mandatory redemption as
liabilities (see Note 5). In accordance with SFAS 150, those securities were
not reclassified on the balance sheet at December 31, 2002.
6
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 requires 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. The adoption of
this change did not impact results of operations for the nine months ended
September 30, 2003.
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 nine months ended September 30, 2003, the $750 million
of 9% Exchangeable Preferred Membership Interests in TXU Energy (originally
issued as subordinated notes in November 2002) were dilutive and were included
in the calculation of diluted earnings per share. Assuming these securities were
converted to TXU Corp. 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 million and $40 million for
the three months and nine months ended September 30, 2003, respectively,
representing the after-tax interest savings on the preferred membership
interests.
In July 2003, TXU Corp. issued $525 million of floating rate convertible
senior notes convertible into 15.2 million shares of TXU Corp. common stock (see
Note 4). For the three months and nine months ended September 30, 2003, these
notes had no effect on the calculation of earnings per share as the market price
of TXU Corp. common stock was below the $41.48 per share trigger price for the
quarter.
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 nine months ended
September 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 September 30, 2003 was $569 million,
comprised of a $554 million liability as a result of adoption of SFAS 143 and
$27 million of accretion during the first nine months of 2003 reduced by $12
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 through the
regulatory process.
On a pro forma basis, assuming SFAS 143 had been adopted at the beginning
of the periods, income from continuing operations for the nine months ended
September 30, 2002 would have increased by $7 million after-tax and the
liability for asset retirement obligations as of September 30, 2002, would have
been $546 million.
3. DISCONTINUED OPERATIONS
Income (loss) from discontinued operations was comprised of results from
the following discontinued businesses or businesses to be sold:
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- -------------------
2003 2002 2003 2002
---- ---- ---- ----
Telecommunications business................................. $ 24 $ - $ (53) $ -
Europe(a)................................................... - (29) (2) (8)
Mexico...................................................... - (15) - (15)
----- ------ ----- ------
Income (loss) from discontinued operations.................. $ 24 $ (44) $ (55) $ (23)
===== ====== ====== ======
(a) Includes legal, audit and administrative accruals related to TXU Europe of
$2 million for the nine months ended September 30, 2003.
8
Results of 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 Nine Months Three Months Nine Months
Ended Ended Ended Ended
September 30, September 30, September 30, September 30,
2002 2002 2003 2003
---- ---- ---- ----
Operating revenues.......................... $1,358 $4,052 $ 49 $ 117
Operating costs and expenses................ 1,321 3,852 41 110
Other (income) deductions-- net............. (4) 6 8 8
Interest income............................. (5) (15) (2) (4)
Interest expense and related charges........ 89 255 19 45
------ ----- ------ ------
Income (loss) before income taxes........... (43) (46) (17) (42)
Income tax (benefit) expense................ (14) (38) (41) 11
------- ------ ------- ------
Income (loss) from discontinued operations.. $ (29) $ (8) $ 24 $ (53)
====== ===== ====== =======
The income tax benefit of $41 million reported in the results of the
telecommunications business for the three months ended September 30, 2003
reflects a $37 million benefit from a change in the estimated tax basis of
the business.
TXU Corp. intends to sell its 60% interest in a gas distribution business
in Mexico and recorded a charge of $15 million (after taxes of $8 million) in
the third quarter of 2002 to write-down its investment in the business.
Balance sheet - The following details the telecommunications assets and
liabilities held for sale as of September 30, 2003:
Current assets......................................... $ 56
Investments............................................ 36
Plant, property, and equipment......................... 233
Goodwill............................................... 317
Accumulated deferred income tax asset.................. 23
Other noncurrent assets................................ 5
------
Telecommunications assets held for sale......... $ 670
======
Current liabilities.................................... $ 83
Noncurrent liabilities................................. 50
------
Telecommunications liabilities held for sale... $ 133
======
9
The following details the assets and liabilities of the telecommunications
holding company as of September 30, 2003:
Investments (a)...................................... $ 91
Other assets......................................... 12
------
Assets of telecommunications holding company..... $ 103
======
Notes payable and other debt (a)..................... $ 687
Other liabilities.................................... 8
------
Liabilities of telecommunications holding company $ 695
======
(a) Investments represents Pinnacle Overfund Trust, a trust established to
fund interest payments on notes payable of the holding company. The
notes payable outstanding totaled $810 million at December 31, 2002 and
$670 million at September 30, 2003. The trust's assets consist of TXU
Corp. debt (reported in long-term debt due currently). Upon sale of the
business, expected to occur in the first quarter of 2004, the remaining
notes outstanding will be repaid and the remaining TXU Corp. debt and
the trust will be canceled. During the nine months ended September 30,
2003, TXU Corp. repurchased $140 million of the notes payable and made
scheduled payments of $86 million on the debt held by the Overfund
Trust. In November 2003, TXU Corp. repurchased $110 million of the
notes payable.
4. FINANCING ARRANGEMENTS
Credit Facilities -- At September 30, 2003, TXU Corp. had outstanding
short-term borrowings consisting of bank borrowings of approximately $6 million
and commercial paper of $34 million (all in Australia). At December 31, 2002,
TXU Corp. had outstanding short-term borrowings consisting of bank borrowings of
approximately $2.3 billion (predominantly all in the US) at a weighted average
interest rate of 2.6% and commercial paper of $18 million (all in Australia).
At September 30, 2003, TXU Corp. and its subsidiaries had credit
facilities (some of which provide for long-term borrowings) as follows:
At September 30, 2003
--------------------------------------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
- -------- --------------- --------- ----- ------ ---------- ------------
(b)
Five-Year Revolving Credit Facility February 2005 US Holdings $ 1,400 $ 266 $ -- $1,134
Revolving Credit Facility February 2005 TXU Energy, Oncor 450 4 -- 446
Three-Year Revolving Credit Facility May 2005 US Holdings (a) 400 -- -- 400
Five-Year Revolving Credit Facility August 2008 TXU Corp. 500 -- -- 500
------- ------ ------ ------
Total US $ 2,750 $ 270 $ -- $2,480
======= ====== ====== ======
Senior Facility (b) October 2004 TXU Australia $ 1,185 $ -- $ 931 $ 237
Working Capital Facility October 2003 TXU Australia 67 -- 6 61
Standby Facility (b) December 2003 TXU Australia 17 -- -- --
------- ------ ------ ------
Total Australia $ 1,269 $ -- $ 937 $ 298
======= ====== ====== ======
(a) previously TXU Corp.
(b) Commercial paper borrowings totaling $34 million at September 30, 2003 were
supported by the Standby Facility ($17 million) and the Senior Facility
($17 million).
Through April 2003, TXU Corp. and its US subsidiaries repaid $2.3 billion
in cash borrowings outstanding as of December 31, 2002 under available credit
facilities.
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. capitalized LOC Trust
with approximately $525 million of cash, which the lenders have invested in
permitted investments as directed by LOC Trust. LOC Trust's assets, including
10
the investments, constitute collateral for the benefit of the lenders to secure
issuances of letters of credit or loans, and are owned by LOC Trust. During the
term of the facility, LOC Trust is required to maintain collateral in an amount
equal to 105% of the commitments under the secured facility. TXU Corp. may
request up to $500 million of letters of credit or up to $250 million of loans
from LOC Trust, subject in the 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 or loans, if any, from the lenders. LOC Trust is
included in the consolidated financial statements of TXU Corp. solely to comply
with GAAP.
In April 2003, the $450 million revolving credit facility was established
for TXU Energy and Oncor. This facility will be used for working capital and
other general corporate purposes, including letters of credit, and replaced a $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.
Since December 31, 2002, TXU Corp. elected to cancel $250 million in other
US credit facility capacity in response to changing liquidity needs.
The US Holdings, TXU Energy and Oncor facilities provide back-up for any
future issuance of commercial paper by TXU Energy and Oncor. At September 30,
2003, there was no such outstanding commercial paper.
The $1.4 billion facility provides for up to $1.0 billion in letters of
credit.
11
Long-Term Debt -- At September 30, 2003 and December 31, 2002, the
long-term debt of TXU Corp. and its consolidated subsidiaries consisted of the
following:
September 30, December 31,
2003 2002
------------- -----------
TXU Energy
----------
Pollution Control Revenue Bonds:
Brazos River Authority:
Floating Taxable Series 1993 due June 1, 2023....................................... $ -- $ 44
3.000% Fixed Series 1994A due May 1, 2029, remarketing date May 1, 2005(a).......... 39 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
Floating Taxable Series 2001F due December 31, 2036................................. -- 39
1.170% Floating Taxable Series 2001G due December 1, 2036(b)........................ 72 72
1.120% Floating Taxable Series 2001H due December 1, 2036(b)........................ 31 31
1.120% Floating Taxable Series 2001I due December 1, 2036(b)........................ 63 63
1.150% 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 --
6.300% Fixed Series 2003B due July 1, 2032.......................................... 39 --
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
Floating Taxable Series 2001D due December 31, 2036................................. -- 12
1.120% Floating Taxable Series 2001E due December 31, 2036(b)....................... 45 45
5.800% Fixed Series 2003A due July 1, 2022.......................................... 12 --
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028........................................... 14 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
6.125% Fixed Senior Notes due March 15, 2008........................................ 250 --
7.000% Fixed Senior Notes due March 15, 2013........................................ 1,000 --
Capital lease obligations........................................................... 12 10
Other............................................................................... 7 8
Unamortized premium and discount and fair value adjustments......................... 17 (110)
------ -----
Total TXU Energy ............................................................... 3,161 2,605
12
September 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
8.750% Fixed First Mortgage Bonds due November 1, 2023........................... -- 103
7.875% Fixed First Mortgage Bonds due April 1, 2024.............................. -- 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
2.260% Fixed Series 2003 Transition Bonds due in bi-annual installments through
February 15, 2007.............................................................. 103 --
4.030% Fixed Series 2003 Transition Bonds due in bi-annual installments through
February 15, 2010.............................................................. 122 --
4.950% Fixed Series 2003 Transition Bonds due in bi-annual installments through
February 15, 2013.............................................................. 130 --
5.420% Fixed Series 2003 Transition Bonds due in bi-annual installments through
August 15, 2015................................................................ 145 --
Unamortized premium and discount................................................. (31) (35)
------- -------
Total Oncor.................................................................. 4,225 4,399
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........ 72 73
8.254% Fixed Notes due in quarterly installments through December 31, 2021....... 67 68
1.910% 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 ........................................................... 158 160
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
- -------------
5.505% Floating Notes due October 30, 2003(d).................................... 20 17
5.365% Floating Notes due September 21, 2007(d).................................. 186 155
Floating Note, Tranche A Facility due October 26, 2004(d)........................ -- 23
5.685% Floating Note, Tranche A Facility due October 26, 2004(d)................. 84 142
5.820% Floating Note, Tranche B Facility due October 26, 2004(d)................. 136 113
5.650% Floating Note, Tranche B Facility due October 26, 2004(d)................. 41 34
5.830% Floating Note, Tranche B Facility due October 26, 2004(d)................. 75 62
5.835% Floating Note, Tranche B Facility due October 26, 2004(d)................. 88 73
6.030% Floating Note, Tranche C Facility due October 26, 2004(d)................. 373 311
6.030% Floating Note, Tranche C Facility due October 26, 2004(d)................. 135 113
7.000% Fixed Medium Term Notes due September 22, 2005............................ 135 113
6.700% Fixed Senior Notes due December 1, 2006(d)(f)............................. 243 203
5.433% Fixed Senior Notes due December 1, 2016(f)................................ 84 70
Unamortized premium and discount and fair value adjustments...................... 41 99
------- -------
Total TXU Australia.......................................................... 1,641 1,528
13
September 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
Fixed Senior Notes Series D due August 16, 2003.................................. -- 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 remarketing date
August 16, 2004(e)............................................................ 500 500
5.450% Fixed Senior Notes Series L due November 16, 2007 remarketing date
August 16, 2005(e)............................................................ 500 500
5.800% Fixed Senior Notes Series M due May 16, 2008 remarketing date
February 16, 2006(e).......................................................... 440 440
6.000% Fixed Telecom Overfund Trust Debt due bi-annually through August 15, 2004
(see Note 3).................................................................. 91 178
9.000% Floating Notes due monthly through October 31, 2007(c).................... 3 4
8.820% Building Financing due bi-annually through February 11, 2022.............. 130 140
2.606% Floating Convertible Senior Notes due July 15, 2033....................... 525 --
Unamortized premium and discount and fair value adjustments...................... 21 50
------- -------
Total Corporate and Other................................................... 3,387 3,312
------- -------
Total TXU Corp. consolidated..................................................... 12,998 12,555
Less amount due currently........................................................ 402 958
------- -------
Total long-term debt............................................................. $12,596 $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 September 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 September 30, 2003.
(d) Interest rates fixed by swaps.
(e) Equity-linked.
(f) US Dollar denominated debt. Interest rates swapped to floating
through a cross-currency fair value hedge in Australia.
In November 2003, the Brazos River Authority Series 2001D pollution
control revenue bonds (aggregate principal amount of $271 million) were
remarketed and converted from a multiannual mode to a weekly rate mode, and the
Sabine River Authority Series 2001C pollution control revenue bonds (aggregate
principal amount of $70 million) were purchased upon mandatory tender. TXU Corp.
intends to remarket these bonds in the first quarter of 2004.
In October 2003, the Brazos River Authority issued $72 million aggregate
principal amount of Series 2003C pollution control revenue bonds and $31 million
aggregate principal amount of Series 2003D pollution control revenue bonds for
TXU Energy. The Series 2003C bonds will bear interest at an annual rate of 6.75%
until maturity in 2038. The Series 2003D bonds will bear interest at an annual
rate of 5.40% until their mandatory tender date in 2014, at which time they will
be remarketed. Proceeds from the issuance of the Series 2003C and Series 2003D
bonds were used to refund the $72 million aggregate principal amount of Brazos
River Authority Taxable Series 2001G and the $31 million aggregate principal
amount of Series 2001H variable rate pollution control revenue bonds, both due
December 1, 2036. The Sabine River Authority also issued $45 million aggregate
principal amount of Series 2003B pollution control revenue bonds for TXU Energy.
The Series 2003B bonds will bear interest at an annual rate of 6.15% until
maturity in 2022, however they become callable in 2013. Proceeds from the
issuance of the Series 2003B bonds were used to refund the $45 million aggregate
principal amount of Sabine River Authority Taxable Series 2001E variable rate
pollution control revenue bonds due December 1, 2036.
In August 2003, Oncor's wholly-owned, special purpose bankruptcy-remote
subsidiary, Oncor Electric Delivery Transition Bond Company LLC, issued $500
million aggregate principal amount of transition (securitization) bonds in
accordance with the Settlement and a financing order. The bonds were issued in
four classes that require bi-annual interest and principal installment payments
beginning in 2004 through specified dates in 2007 through 2015. The transition
bonds bear interest at fixed annual rates ranging from 2.26% to 5.42%. Oncor
used the proceeds to retire the $224 million aggregate principal amount of the
7 7/8% First Mortgage Bonds due March 1, 2023 and $133 million principal amount
of the 7 7/8% First Mortgage Bonds due April 1, 2024, as well as to repurchase
outstanding common shares from its parent, US Holdings, in the amount of $125
million. The Settlement and a financing order provide for a second issuance of
$800 million expected to be completed in the first quarter of 2004.
14
In August 2003, TXU Corp. redeemed the full $323 million principal amount
of its 5.52% Series D Senior Notes, at the maturity date, for par value.
In July 2003, TXU Corp. issued $525 million of floating rate convertible
senior notes due 2033 in a private placement with registration rights. The notes
bear regular interest at an annual floating rate equal to 3-month LIBOR,
determined quarterly, plus 150 basis points, and are 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.
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. (See
Note 5.)
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 $39 million
aggregate 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 $12 million aggregate 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 remarketing date of May 1,
2005. 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.
15
In April 2003, Oncor repaid the $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 $44 million principal amount of
Brazos River Authority Series 1993 pollution control revenue bonds due June 1,
2023.
In March 2003, Oncor repaid the $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 credit facilities. In
August 2003, TXU Energy entered into interest rate swap transactions through
2013, which are being accounted for as fair value hedges, to effectively convert
$500 million of the notes to floating interest rates.
In January 2003, TXU Gas redeemed, at par value, $125 million principal
amount of its 6.25% Notes at maturity.
Australia -- At September 30, 2003, TXU Australia had A$505 million ($342
million) in medium-term notes outstanding, of which interest and principal
payments associated with A$475 million ($322 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 -- TXU Corp. has established an accounts receivable
securitization program. The activity under this program is accounted for as a
sale of accounts receivable in accordance with SFAS 140. Under the program, US
subsidiaries of TXU Corp. (originators) sell trade accounts receivable to TXU
Receivables Company, a consolidated wholly-owned bankruptcy remote direct
subsidiary of TXU Corp., which sells undivided interests in the purchased
accounts receivable for cash to special purpose entities established by
financial institutions. In September 2003, the maximum amount of undivided
interests that could be sold by TXU Receivables Company was increased by $100
million to $700 million. In November 2003, this amount decreased to $600
million.
All new trade receivables under the program generated by the originators
are continuously purchased by TXU Receivables Company with the proceeds from
collections of receivables previously purchased. Changes in the amount of
funding under the program, through changes in the amount of undivided interests
sold by TXU Receivables Company, are generally due to seasonal variations in the
level of accounts receivable and changes in collection trends. TXU Receivables
Company has issued subordinated notes payable to the originators for the
difference between the face amount of the uncollected accounts receivable
purchased, less a discount, and cash paid that was funded by the sale of the
undivided interests.
16
The discount from face amount on the purchase of receivables funds a
servicing fee paid by TXU Receivables Company to TXU Business Services Company,
a direct subsidiary of TXU Corp., as well as program fees paid by TXU
Receivables Company to the financial institutions. The servicing fee, which
totaled $7 million and $6 million for the nine month periods ended September 30,
2003 and 2002, respectively, compensates TXU Business Services Company for its
services as collection agent, including maintaining the detailed accounts
receivable collection records. The program fees paid to financial institutions,
which consist primarily of interest costs on the underlying financing, were $8
million and $11 million for the nine-month periods ending September 30, 2003 and
2002, respectively, and approximated 2.4% of the average funding under the
program on an annualized basis in each period; these fees represent the net
incremental costs of the program to the originators and are reported in SG&A
expenses.
The September 30, 2003 balance sheet reflects funding under the program of
$700 million, through sale of undivided interests in receivables by TXU
Receivables Company, related to $1.5 billion face amount of trade accounts
receivable of TXU Energy, TXU Gas and Oncor. Funding under the program increased
$229 million for the nine month period ended September 30, 2003, primarily due
to the program capacity increase of $100 million and the effect of improved
collection trends. Funding under the program for the nine month period ended
September 30, 2002 increased $100 million. Funding increases or decreases under
the program are reflected as operating cash flow activity in the statement of
cash flows.
Upon termination of the program, cash flows to TXU Corp. would be delayed
as collections of sold receivables would be used by TXU Receivables Company to
repurchase the undivided interests sold instead of purchasing new receivables.
The level of cash flows would normalize in approximately 16 to 31 days.
In June 2003, the program was amended to provide temporarily higher
delinquency and default compliance ratios and temporary relief from the loss
reserve formula, which allowed for increased funding under the program. 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. 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.
Contingencies Related to Sale of 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 have brought the ratios into consistent compliance with the
program.
17
Under terms of 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 September 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 were 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 (which is no longer outstanding as of October 1, 2003) 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 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 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.
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, and Pinnacle's 8.83% Senior Secured Notes due 2004, reported in
liabilities of the telecommunications holding company (see Note 3), 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.
18
TXU Energy has entered into certain mining and equipment leasing
arrangements aggregating $122 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.
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.
5. PREFERRED INTERESTS OF SUBSIDIARIES
Subsidiary preferred securities outstanding were as follows:
September 30, December 31,
2003 2002
------- ------
Classified as a liability: (a)
Preferred stock of US Holdings........................... $ 7 $ -
====== ======
Classified as preferred interests:
Exchangeable preferred membership interests of TXU Energy,
net of
$106 unamortized discount........................... $ 644 $ -
Preferred securities of subsidiary trusts................ 515 515
Preferred stock of TXU Gas............................... 75 75
Preferred stock of US Holdings........................... 38 136
------ ------
Total.................................................... $1,272 $ 726
====== ======
(a) Reported in other current liabilities.
See Note 1 for a discussion of the change in balance sheet classification
of these securities as a result of the adoption of SFAS 150.
19
Mandatorily Redeemable, Preferred Securities of Subsidiary Trusts, Each
Holding Solely Junior Subordinated Debentures of TXU Corp. or TXU Gas (Trust
Securities) -- Statutory business trusts have been established as wholly-owned
financing subsidiaries of TXU Corp. and TXU Gas. The trusts have issued
preferred interests in the form of Trust Securities, and the assets of the
trusts consist solely of Junior Subordinated Debentures of TXU Corp. or TXU Gas,
as presented below:
Trust Securities Maturity
---------------------------------------------------- Trust Assets --------
Units (000's) Amount Amount
------------------------ ------------------------- --------------------
September December 31, September December 31, September December
30, 30, 30, 31, 30, 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.
Exchangeable Preferred Membership Interests of TXU Energy - 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 per
share. The market price of TXU Corp. common stock on September 30, 2003 was
$23.56. Any exchange of these securities into common stock would result in a
proportionate write-off of the related unamortized discount as a charge to
earnings. If all the securities had been exchanged into common stock on
September 30, 2003, the pre-tax charge would have been $106 million. These
securities are considered not to be mandatorily redeemable under SFAS 150
because of the exchangeability provision.
Preferred Stock of US Holdings - 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. In September 2003, US Holdings called all of its $6.375
mandatorily redeemable preferred stock for redemption, and on October 1, 2003
all of these shares were redeemed for an aggregate principal amount of $7
million.
6. SHAREHOLDERS' EQUITY
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
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 $5.4 billion at September 30, 2003.
20
Additional paid-in capital includes $111 million related to the discount
at issuance on the 9% Exchangeable Subordinated Notes of TXU Energy at September
30, 2003 and December 31, 2002, respectively. These notes were exchanged into
preferred membership interests of TXU Energy in July 2003 (see Note 4) 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. At its August 2003
meeting, the Board of Directors of TXU Corp. declared a quarterly dividend of
$0.125 a share, payable on October 1, 2003, to shareholders of record on
September 5, 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.
Certain debt instruments and preferred securities of TXU Corp. contain
provisions that restrict payment of dividends during any interest or
distribution payment deferral period or while any payment default exists. An
Oncor mortgage restricts the payment of dividends to the amount of Oncor's
retained earnings. At September 30, 2003, TXU Corp. was in compliance with 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 September 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, entered into prior to January 1, that obligate
it to guarantee the residual values of the leased facilities. At September 30,
2003, the aggregate maximum amount of residual values guaranteed was
approximately $294 million with an estimated residual recovery of approximately
$214 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 have 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 September 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 $294
million of letters of credit were outstanding at September 30, 2003 to support
existing floating rate pollution control revenue bond debt of approximately $271
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.
21
TXU Corp. has outstanding letters of credit in the amount of $32 million
to support portfolio management margin requirements in the normal course of
business. As of September 30, 2003, approximately 81% 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 $24 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 $101 million, of which $89 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 is 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
$59 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, $13 million at September 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 September 30, 2003, issued for similar purposes, which had previously been
guaranteed by TXU Corp. TXU Corp. is, however, contingently liable in the 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 $95 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 -- On October 9, 2003, a lawsuit was filed in the
Supreme Court of the State of New York, County of New York, against TXU Corp.,
by purported beneficial owners of approximately 39% of certain TXU Corp.
equity-linked securities issued in October 2001. The common stock purchase
contract that is a part of these securities requires the holders to purchase TXU
Corp. common stock on specified dates in 2004 and 2005. The plaintiffs seek a
declaratory judgment that (a) a termination event has occurred under the common
stock purchase contract as a result of the administration of TXU Europe and,
therefore, that plaintiffs are not required to purchase TXU Corp. common stock
pursuant to the contract and (b) an event of default has occurred under the
indenture for the senior notes that constitute a part of these equity-linked
securities. Plaintiffs also seek an injunction requiring TXU Corp. to give
notice that a termination event under the common stock purchase contract has
occurred. TXU Corp. disputes plaintiffs' allegations and believes that
plaintiffs' interpretation of the common stock purchase contract and indenture
is inconsistent with the clear language of these agreements and is contrary to
applicable law. Therefore, TXU Corp. believes the claims are completely without
merit and intends to vigorously defend the lawsuit. Discovery has commenced, and
on October 31, 2003, plaintiffs served their first demand for production of
documents. TXU Corp. has not yet responded to the complaint and is unable to
estimate any possible loss or predict the outcome of this action.
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. On September 12, 2003, the TXU defendants
filed a motion to dismiss the lawsuit, which is set for hearing on January 23,
2004. 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. TXU Corp. 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, TXU Corp. is unable to
predict the outcome of this litigation or the possible loss in the event of an
adverse judgment.
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 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. On September 15, 2003, defendants filed a motion to dismiss
the lawsuit and a motion to transfer the case to the Northern District of Texas,
Dallas Division. TXU Corp. believes that the plaintiff 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. TXU Corp. 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.
23
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 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.
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 stock and
equity-linked debt securities 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 debt securities and common stock in May and June
2002. On September 24, 2003, TXU Corp. and its officer and director defendants
filed a motion to dismiss to plaintiffs' Amended Complaint. The court has not
yet ruled on the motion to dismiss. 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.
Other Contingencies - In October 2003, the former directors and officers
of TXU Europe Limited and subsidiaries that are now in administration
(collectively TXU Europe), who include current and former officers of TXU Corp.
and subsidiary companies, received notices from certain creditors and the
administrators of TXU Europe of various claims or potential claims relating to
losses incurred by creditors, including claims for alleged omissions from a
securities offering document and alleged breaches by directors of their English
law duties as directors of these companies in failing to minimize the potential
losses to the creditors of TXU Europe. Under the terms of the indemnification
agreements and bylaw and charter provisions that provide for indemnification of
corporate officers and directors, TXU Corp. or one of its subsidiaries will be
obligated to indemnify these persons from these and similar claims, unless it is
determined that the corporate officer's acts were committed in bad faith, were
the result of active and deliberate dishonesty or that the corporate officer
personally gained a financial profit to which he was not legally entitled.
Similar claims have been asserted directly against TXU Corp., as well. TXU Corp.
believes that these claims are without merit and intends to vigorously defend
any such claims if they are ultimately asserted.
24
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. Effective as
of October 3, 2003, a global settlement among all parties to these lawsuits has
been reached. The settlement was not material to TXU Corp.'s financial position
or results of operation, and requires that these suits be dismissed with
prejudice.
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: Energy, Energy Delivery and
Australia.
Energy - consists of operations of TXU Energy, which are principally in
the competitive Texas market, involving power production (electricity
generation), wholesale energy sales, retail energy sales and related services,
and portfolio management, including risk management and certain trading
activities.
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
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.
25
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
------- ------ ------- -----
Operating revenues:
Energy................................. $ 2,453 $2,420 $ 6,304 $ 6,238
Energy Delivery........................ 786 694 2,597 2,189
Australia.............................. 321 234 820 662
Corporate and other ................... 27 27 83 84
Eliminations........................... (451) (457) (1,197) (1,297)
-------- ------ -------- -------
Consolidated......................... $ 3,136 $2,918 $ 8,607 $ 7,876
======= ====== ======= =======
Regulated revenues included in
operating revenues:
Energy ................................ $ - $ - $ - $ -
Energy Delivery........................ 786 694 2,597 2,189
Australia.............................. 34 23 82 57
Corporate and other.................... 22 23 72 68
Eliminations........................... (447) (446) (1,180) (1,269)
-------- ------- -------- --------
Consolidated......................... $ 395 $ 294 $ 1,571 $ 1,045
======= ====== ======= =======
Affiliated revenues included in
operating revenues:
Energy ................................ $ 5 $ 12 $ 18 $ 29
Energy Delivery........................ 446 445 1,179 1,268
Corporate and other.................... - - - -
Eliminations........................... (451) (457) (1,197) (1,297)
-------- ------ -------- -------
Consolidated......................... $ - $ - $ - $ -
======= ====== ======= =======
Income from continuing operations
before cumulative effect of changes
in accounting principles:
Energy ................................ $ 249 $ 227 $ 438 $ 597
Energy Delivery........................ 117 78 263 220
Australia ............................. 43 16 96 77
Corporate and other.................... (36) (66) (131) (204)
-------- ------ -------- --------
Consolidated......................... $ 373 $ 255 $ 666 $ 690
======= ====== ======= =======
26
9. SUPPLEMENTARY FINANCIAL INFORMATION
Regulated Versus Unregulated Operations --
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- -------------------
2003 2002 2003 2002
---- ---- ---- ----
Operating revenues:
Regulated.................................................. $ 842 $ 740 $2,751 $2,314
Unregulated................................................ 2,745 2,635 7,053 6,859
Intercompany sales eliminations - regulated................ (447) (446) (1,180) (1,269)
Intercompany sales eliminations - unregulated ............. (4) (11) (17) (28)
------- ------- ------ -------
Total operating revenues.............................. 3,136 2,918 8,607 7,876
------- ------ ------ -------
Costs and operating expenses:
Cost of energy sold and delivery fees - regulated........... 94 64 670 357
Cost of energy sold and delivery fees - unregulated*........ 1,248 1,215 3,235 2,705
Operating costs - regulated................................. 221 214 656 606
Operating costs - unregulated............................... 197 193 617 581
Depreciation and amortization - regulated................... 112 94 315 280
Depreciation and amortization - unregulated................. 111 126 340 373
Selling, general and administrative expenses - regulated.... 118 173 230 249
Selling, general and administrative expenses - unregulated.. 162 147 569 726
Franchise and revenue-based taxes - regulated............... 76 77 238 236
Franchise and revenue-based taxes - unregulated............. 28 31 97 107
Other income................................................ (26) (20) (66) (46)
Other deductions............................................ 13 23 36 82
Interest income............................................. (6) (6) (25) (21)
Interest expense and related charges........................ 240 214 736 647
------- ------ ------ ------
Total costs and expenses............................... 2,588 2,545 7,648 6,882
------- ------ ------ ------
Income from continuing operations before income taxes and
cumulative effect of changes in accounting principles....... $ 548 $ 373 $ 959 $ 994
======= ====== ===== ======
--------------
*Includes cost of fuel consumed of $417 million and $433 million for
the three months ended September 30, 2003 and 2002, respectively, and
$1.278 billion and $1.075 billion for the nine months ended September
30, 2003 and 2002, respectively. The balance in each period represents
energy purchased for resale and delivery fees.
The operations of the 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 Nine Months Ended
September 30, September 30,
---------------------- ------------------
2003 2002 2003 2002
------ ------ ------ -----
Other income:
Net gain on sale of businesses and other properties. $ 20 $ 17 $ 41 $ 33
Lignite coal royalties................................ - - - 2
Unrealized foreign exchange gain on Australian dollar
denominated note receivable......................... 1 - 13 -
Equity portion of allowance for funds used during
construction........................................ 3 1 4 3
Other................................................. 2 2 8 8
---- ---- ---- ----
Total other income............................... $ 26 $ 20 $ 66 $ 46
==== ==== ==== ====
Other deductions:
Equity in losses of unconsolidated entities...... $ 1 $ 18 $ 17 $ 42
Loss on retirement of debt............................ 1 1 1 28
Write-off of frequency licenses....................... - - 3 -
Asset write-off in strategic retail services business. 5 - 5 -
Premium on redemption of preferred stock.............. 3 - 3 -
Expenses related to canceled construction projects.... 2 2 4 5
Other................................................. 1 2 3 7
---- ---- ---- ----
Total other deductions........................... $ 13 $ 23 $ 36 $ 82
==== ==== ==== ====
27
Interest Expense and Related Charges --
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
Interest......................................................... $207 $ 199 $ 629 $ 594
Distributions on subsidiary exchangeable interest................ 17 - 51 -
Distributions on mandatorily redeemable, preferred securities
of subsidiary trusts, each holding solely junior subordinated
debentures of the obligated company:
TXU Corp. obligated........................................ 8 7 23 22
Subsidiary obligated....................................... 1 3 6 8
Preferred stock dividends of subsidiaries........................ 2 3 8 10
Amortization of debt discounts, premiums and issuance cost....... 8 5 28 23
Allowance for borrowed funds used during construction
and capitalized interest...................................... (3) (3) (9) (10)
------ ----- ----- ----
Total interest expense and related charges............... $ 240 $ 214 $ 736 $647
===== ===== ===== ====
Regulatory Assets and Liabilities --
September 30, December 31,
2003 2002
------- ------
Regulatory Assets:
Generation-related regulatory assets subject to securitization.... $1,170 $1,652
Generation-related regulatory assets-securitized.................. 494 -
Securities reacquisition costs.................................... 123 124
Recoverable deferred income taxes-- net........................... 81 76
Other regulatory assets........................................... 210 217
------ ------
Total regulatory assets......................................... 2,078 2,069
------ ------
Regulatory Liabilities:
Liability related to excess mitigation credit.................... 39 170
Investment tax credit and protected excess deferred taxes........ 92 99
Other regulatory liabilities..................................... 13 28
------ ------
Total regulatory liabilities................................... 144 297
------ ------
Net regulatory assets.......................................... $1,934 $1,772
====== ======
Included above are assets of $1.8 billion at September 30, 2003 and
December 31, 2002, that were not earning a return. Of the assets not earning a
return, $1.7 billion is expected to be recovered over the term of the
bonds issued by Oncor in August 2003 and expected to be issued in
the first quarter of 2004 pursuant to the Settlement and a financing order. All
other regulatory assets have a remaining recovery period of 12 to 49 years.
Included in other regulatory assets as of September 30, 2003 was $43
million related to nuclear decommissioning liabilities.
Restricted Cash -- At September 30, 2003, TXU Corp. had a $525 million
investment in LOC Trust, accounted for as restricted cash, representing
collateral to support a new $500 million credit facility (see Note 4). The
remaining restricted cash reported in investments on the balance sheet as of
September 30, 2003 included $112 million held as collateral for letters of
credit issued and $6 million related to payment of fees associated with the
securitization bonds. As of September 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.
28
Accounts Receivable -- At September 30, 2003 and December 31, 2002,
accounts receivable of $1.3 billion and $1.7 billion are stated net of allowance
for uncollectible accounts of $83 million, in both periods. During the nine
months ended September 30, 2003, bad debt expense was $80 million, account
write-offs were $77 million and other activity decreased the allowance for
uncollectible accounts by $3 million.
Accounts receivable included $638 million and $644 million of unbilled
revenues at September 30, 2003 and December 31, 2002, respectively.
Intangible Assets -- SFAS 142 became effective for TXU Corp. 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 September 30, 2003 As of December 31, 2002
----------------------------- ----------------------------
Gross Gross
Carrying Accumulated Carrying Accumulated
Amount Amortization Net Amount Amortization Net
--------- ------------ ----- -------- ------------ ----
Intangible assets subject to amortization
Included in property, plant and
equipment):
Capitalized software.............. $ 608 $ 288 $320 $540 $217 $323
Land easements.................... 191 74 117 195 68 127
Mineral rights and other.......... 31 21 10 32 21 11
----- ----- ---- ------ ------ ------
Total....................... $ 830 $ 383 $447 $767 $306 $461
===== ===== ==== ==== ==== ====
Intangible assets not subject to
amortization Licenses (a)........... $ 384 $ 38 $346 $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 $72
million and $63 million for the nine months ended September 30, 2003 and 2002,
respectively. At September 30, 2003, the average remaining useful lives of
capitalized software, land easements and mineral rights and other were 6 years,
68 years and 40 years, respectively.
Changes in the carrying amount of goodwill and other unamortized
intangible assets (net of accumulated amortization) for the nine months ended
September 30, 2003, are as follows:
Energy
Energy Delivery Australia Total
------ -------- --------- -----
Balance at December 31, 2002............. $ 533 $ 331 $ 724 $ 1,588
Foreign currency translation effects... - - 149 149
------- ------ -------- ---------
Balance at September 30, 2003........... $ 533 $ 331 $ 873 $ 1,737
======= ====== ======== =========
Goodwill and other intangible assets not subject to amortization of $1.7
billion and $1.6 billion at September 30, 2003 and December 31, 2002,
respectively, were stated net of accumulated amortization (prior to SFAS 142
implementation) of $207 million and $189 million, respectively.
Commodity Contracts -- At September 30, 2003 and December 31, 2002,
current and noncurrent commodity contract assets totaling $1.2 billion and $2.0
billion, respectively, are stated net of applicable credit (collection) and
performance reserves totaling $21 million and $44 million, respectively.
Performance reserves are provided for direct, incremental costs to settle the
contracts.
29
Inventories by Major Category --
September 30, December 31,
2003 2002
------- ------
Materials and supplies..................... $ 240 $ 227
Fuel stock................................. 101 91
Gas stored underground..................... 205 175
------ ------
Total inventories...................... $ 546 $ 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 September 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 $11.7 billion and $11.1
billion, respectively.
As of September 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 $8 million and $23 million, respectively, reported as a gain in revenues, for
the three and nine months ended September 30, 2003. For the three and nine
months ended September 30, 2002, net hedge ineffectiveness of $7 million and $41
million, respectively, was reported as a loss in revenues. These gains and
losses related primarily to hedges of anticipated power sales.
As of September 30, 2003, it is expected that $105 million of after-tax
net losses accumulated in other comprehensive income will be reclassified into
earnings during the next twelve months. Of this amount, $62 million relates to
commodities hedges and $43 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.
See Note 4 for discussion of the exchange of TXU Energy subordinated notes
for preferred membership interests, which was a noncash transaction.
30
INDEPENDENT ACCOUNTANTS' REPORT
TXU Corp.:
We have reviewed the accompanying condensed consolidated balance sheet of TXU
Corp. and subsidiaries (TXU Corp.) as of September 30, 2003, and the related
condensed statements of consolidated income and of comprehensive income for the
three-month and nine-month periods ended September 30, 2003 and 2002, and the
condensed statements of consolidated cash flows for the nine-month periods ended
September 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 Nos. 142 and 145 and the discontinuance of European operations), dated
February 14, 2003 (and September 22, 2003 as to Note 2 and Note 19 therein) 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 No. 143,
"Accounting for Asset Retirement Obligations," and 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."
DELOITTE & TOUCHE LLP
Dallas, Texas
November 11, 2003
31
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. 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.
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 to Financial
Statements for information about discontinued operations).
With respect to the telecommunications business, Pinnacle, in May 2003 TXU
Corp. acquired, for $150 million in cash, the interests it did not previously
own from the joint venture partner under a put/call agreement, which had been
executed in late February 2003, and finalized a formal plan to dispose of the
telecommunications business by sale. Accordingly, effective with reporting for
the second quarter of 2003, activities of Pinnacle since March 1, 2003 are
reported as discontinued operations. TXU Corp. had used the equity method of
accounting for its investment in Pinnacle until March 1, 2003 when the business
was consolidated as a result of the execution of the put/call agreement.
Accounting rules provide that businesses accounted for under the equity method
should not be reported as discontinued operations; therefore, results prior to
March 1, 2003 are reported in other deductions in the statement of income,
consistent with prior reporting. (Also see Note 3 to Financial Statements.)
TXU Corp. has three reportable segments: Energy, Energy Delivery and
Australia. (See Note 8 to Financial Statements for further information
concerning reportable business segments.)
The following exchange rates have been used to convert foreign currency
denominated amounts into US dollars, unless they were determined using exchange
rates on the date of a specific event:
Income Statements
(Average Rates)
Balance Sheets ----------------------------------------
---------------------------- Three Months Nine Months
September 30, December 31, Ended September 30, Ended September 30,
2003 2002 2003 2002 2003 2002
---- ---- ---- ---- ---- ----
Australian dollars (A$) $ 0.6776 $ 0.5650 $0.6592 $0.5477 $ 0.6311 $ 0.5394
Dollar amounts in the following tables are stated in millions of US
dollars unless otherwise noted.
RESULTS OF OPERATIONS
TXU Corp. Consolidated
- ----------------------
Three Months Ended September 30, 2003 Compared to Three Months Ended
September 30, 2002
- ---------------------------------------------------------------------
Reference is made to comparisons of results by business segment following
the discussion of consolidated results presented below. The business segment
comparisons provide additional detail and quantification of items affecting
financial results.
TXU Corp.'s operating revenues increased $218 million, or 7%, to $3.1
billion in 2003. Operating revenues rose $92 million, or 13%, to $786 million in
the Energy Delivery segment, reflecting higher gas costs, increased transmission
and distribution tariffs, higher electric distribution volumes and increased
disconnect/reconnect fees. Revenues in the Australia segment rose by $87
million, or 37%, to $321 million driven by the translation effect of the
stronger Australian dollar and higher retail gas and electric revenues. Revenues
in the Energy segment increased $33 million, or 1%, to $2.5 billion reflecting
higher average pricing that was largely offset by the effect of lower sales
volumes and lower results from portfolio management activities.
32
Gross Margin
Three Months Ended
September 30,
------------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 3,136 100% $ 2,918 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 1,342 43% 1,279 44%
Operating costs................................... 418 13% 407 14%
Depreciation and amortization related to operating
assets........................................ 202 7% 202 7%
------- ----- ------- -------
Gross margin........................................... $ 1,174 37% $ 1,030 35%
======= ===== ======= =======
Gross margin is considered a key operating metric as it measures the
effect of changes in sales volumes and pricing versus the 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 $21 million and $18 million of such expense for the three months ended
September 30, 2003 and 2002, respectively, that is not directly related to
generation and delivery property, plant and equipment.
Gross margin increased $144 million, or 14%, to $1.2 billion in 2003. An
increase in the Energy segment's margin of $55 million, or 9%, to $649 million
was driven by higher average pricing that exceeded higher average costs of
energy sold, lower portfolio management results and the effect of volume
declines. The Energy Delivery segment's gross margin increased $51 million, or
14%, to $407 million driven by higher electricity delivery revenues. Australia's
gross margin increased $39 million, or 48%, to $121 million reflecting the
stronger Australian dollar, the effect of higher retail gas and electricity
sales volumes and lower purchased power costs. Mark-to-market accounting for
commodity contracts decreased revenues and gross margin by $12 million in 2003
(as compared to accounting on a settlement basis) and had no net effect on
results in 2002.
Depreciation and amortization (including amounts shown in the gross margin
table above) increased $3 million, or 1%, to $223 million in 2003, reflecting
investments in facilities to support growth and normal replacements of
equipment, largely offset by a $12 million impact of reducing depreciation rates
related to the generation fleet due primarily to an extension of the estimated
depreciable life of the nuclear generation facility to better reflect its useful
life.
SG&A expenses decreased $40 million, or 13%, to $280 million in 2003. The
decrease was driven by nonrecurring costs incurred in 2002 in the transition to
competition and the effects of cost reduction initiatives.
Franchise and revenue-based taxes decreased $4 million, or 4%, to $104
million in 2003, primarily due to lower state and local franchise taxes.
Other income increased $6 million to $26 million in 2003. Net gains on
sales of various businesses and properties totaled $20 million in 2003 and $17
million in 2002.
Other deductions decreased $10 million to $13 million in 2003 reflecting
the absence of equity losses of $16 million from the Pinnacle joint venture,
partially offset by charges related to the scaling-back of the strategic retail
services business.
Interest expense and related charges increased $26 million, or 12%, to
$240 million in 2003, reflecting a $21 million increase due to higher average
interest rates resulting in part from the refinancing of short-term borrowings
with higher rate long-term debt, a $3 million increase due to higher average
debt levels and a $2 million increase due to higher amortization of discount
related to the TXU Energy exchangeable subordinated notes issued in 2002. (The
notes were subsequently exchanged by TXU Energy for exchangeable preferred
membership interests.)
33
The effective income tax rate on income from continuing operations of
31.9% in 2003 was comparable to the 31.6% effective rate in 2002. A higher
effective rate in the Energy segment was largely offset by a lower effective
rate in Australia.
Income from continuing operations increased $118 million, or 46%, to $373
million in 2003. This performance reflected an increase of $39 million, or 50%,
to $117 million in the Energy Delivery segment, reflecting higher revenues in
the electricity delivery business, an increase of $27 million, or 169%, to $43
million in the Australia segment, largely due to an increase in gross margin and
the favorable effect of the stronger Australian dollar, as well as growth of $22
million, or 10%, to $249 million in the Energy segment on higher gross margin
and decreased SG&A expenses. The segment performances are discussed in more
detail below. Corporate and Other expenses declined $30 million due to the
absence of equity losses from the Pinnacle joint venture ($18 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 $19 million in 2003 and $10 million in 2002.
Diluted earnings per share available to common shareholders from
continuing operations before cumulative effect of changes in accounting
principles increased $0.13, or 15%, to $1.01 per share in 2003. Of this
increase, $0.35 per share is due to increased earnings (earnings in the
calculation reflect lower interest expense on the assumed conversion of
exchangeable notes) offset by a $0.22 per share effect of a 34% increase in
average shares in the computation. 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 from discontinued operations in 2003, consisting of the results
from the telecommunications business, was $24 million (after-tax). The results
reflected a $37 million benefit from a change in the estimated tax basis of the
business. The loss from discontinued operations of $44 million in 2002 included
$29 million related to the TXU Europe business and a $15 million impairment
charge related to the gas distribution business in Mexico held for sale.
Net income available to common shareholders increased $186 million, or
90%, to $392 million in 2003. The increase reflected the higher income from
continuing operations of $118 million and a $68 million effect of the
discontinued operations income in 2003 compared to the loss in 2002.
TXU Corp. Consolidated
- ----------------------
Nine Months Ended September 30, 2003 Compared to Nine Months Ended
September 30, 2002
- ------------------------------------------------------------------------------
TXU Corp.'s operating revenues increased $731 million, or 9%, to $8.6
billion in 2003. Revenues in the Energy Delivery segment rose by $408 million,
or 19%, to $2.6 billion driven by higher gas costs passed on to customers and
increased electricity transmission and distribution tariffs. Operating revenues
rose $158 million, or 24%, to $820 million in the Australia segment driven by
the translation effect of the stronger Australian dollar and higher retail gas
and electricity revenues. Revenues in the Energy segment increased $66 million,
or 1%, to $6.3 billion reflecting higher average pricing that was largely offset
by the effect of lower sales volumes. Consolidated revenue growth also reflected
a $100 million reduction in the intercompany sales elimination, reflecting lower
sales by Oncor to TXU Energy as sales to nonaffiliated REPs increased.
34
Gross Margin
Nine Months Ended
September 30,
-----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 8,607 100% $ 7,876 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 3,905 45% 3,062 39%
Operating costs................................... 1,273 15% 1,187 15%
Depreciation and amortization related to operating
assets........................................ 596 7% 594 8%
------- ------- ------- ------
Gross margin........................................... $ 2,833 33% $ 3,033 38%
======= ======= ======= ======
The depreciation and amortization expense included in gross margin
excludes $59 million of such expense for the nine months ended September 30,
2003 and 2002, that is not directly related to generation and delivery property,
plant and equipment.
Gross margin decreased $200 million, or 7%, to $2.8 billion in 2003. A
decline of $298 million, or 17%, to $1.4 billion at the Energy segment reflected
increased average costs of energy sold and lower retail sales volumes that
exceeded higher average sales prices. Australia's gross margin rose $52 million,
or 20%, to $310 million reflecting the effects of a stronger Australian dollar,
higher retail electric and gas sales volumes and lower purchased power costs.
The Energy Delivery segment's gross margin rose $48 million, or 5% to $1.1
billion reflecting the impact of higher volumes and base distribution rates in
the gas delivery business. Mark-to-market accounting for commodity contracts
increased revenues and gross margin by $15 million in 2003 (as compared to
accounting on a settlement basis), and increased results by $6 million in 2002.
Operating costs rose $86 million, or 7%, to $1.3 billion on higher electricity
transmission costs paid to other utilities, increased costs in the utility asset
management services and increased activity related to a previously existing
contract in the strategic retail services business.
Depreciation and amortization (including amounts shown in the gross margin
table above) increased $2 million to $655 million in 2003, reflecting
investments in facilities to support growth and normal replacements of
equipment, largely offset by a $25 million impact of reducing depreciation rates
related to TXU Energy's generation fleet due primarily to an extension of the
estimated depreciable life of the nuclear generation facility to better reflect
its useful life.
SG&A expense decreased $176 million, or 18%, to $799 million in 2003. This
decrease reflected cost reductions, primarily lower staffing and related
administrative expenses, reflecting the completion of the transition to
competition in Texas and the industry-wide decline in portfolio management
activities as well as the scaling-back of the strategic retail services
operations. Lower SG&A expenses also reflected lower bad debt expense due to the
effect of billing and collection delays in 2002 in connection with the
transition to competition and initiatives implemented in 2003 to reduce such
expenses.
Franchise and revenue-based taxes decreased $8 million, or 2%, to $335
million in 2003, due primarily to lower retail revenues on which gross receipts
taxes are based.
Other income increased $20 million to $66 million in 2003. Net gains on
sales of businesses and properties totaled $41 million in 2003 and $33 million
in 2002. The 2003 period also includes $13 million of unrealized foreign
exchange gains on an Australian dollar denominated note receivable.
Other deductions decreased $46 million to $36 million in 2003. The 2002
period includes a $28 million loss on retirement of debt. Equity losses on
unconsolidated subsidiaries, principally Pinnacle (until March 2003) were $17
million in 2003 and $42 million in 2002.
Interest income rose $4 million, or 19%, to $25 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 held to support funding of construction of a natural gas pipeline in
Australia by a joint venture.
35
Interest expense and related charges increased $89 million, or 14%, to
$736 million in 2003, reflecting a $54 million increase due to higher average
interest rates resulting in part from the replacement of short-term borrowings
with higher rate long-term debt, a $30 million increase due to higher average
debt levels reflecting actions taken to enhance liquidity and a $5 million
increase due to higher amortization of discount related to the TXU Energy
exchangeable subordinated notes issued in 2002. (The notes were subsequently
exchanged by TXU Energy for exchangeable preferred membership interests.)
The effective income tax rate on income from continuing operations before
cumulative effect of changes in accounting principles was 30.6% in both 2003 and
in 2002. The effective rates for all three business segments were largely
unchanged.
Income from continuing operations before cumulative effect of changes in
accounting principles decreased $24 million, or 3%, to $666 million in 2003.
This performance reflected a decline of $159 million, or 27%, to $438 million in
the Energy segment driven by lower gross margin and higher interest expense. An
increase in earnings in the Energy Delivery segment of $43 million, or 20%, to
$263 million was driven by improved gross margin and lower interest expense in
the gas delivery business. Earnings growth in the Australia segment of $19
million, or 25%, to $96 million reflected the favorable effect of the stronger
Australian dollar and improved retail gross margins. Corporate and Other
expenses declined $73 million due primarily to lower interest expense,
reflecting commercial paper outstanding in the prior year, a loss on retirement
of debt of $18 million (after-tax) in 2002 and the absence of a portion of
equity losses ($23 million) from the Pinnacle business, which is now accounted
for as discontinued operations. Net pension and postretirement benefit costs
reduced income from continuing operations by $58 million in 2003 and $37 million
in 2002.
Income (loss) from discontinued operations, including tax effects,
reflected a loss in 2003 of $55 million principally related to the
telecommunications business and a loss in 2002 of $23 million consisting of a
$15 million impairment charge related to a gas distribution business in Mexico
and $8 million in losses 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 $0.66, or 27%, to $1.82 per share in 2003. The decline reflected a
$0.70 per share effect of a 39% increase in average shares in the computation,
partially offset by $0.04 per share from higher earnings. (Earnings in this
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.
Net income available to common shareholders decreased $114 million, or
18%, to $537 million in 2003. The decline reflected the $58 million charge
related to accounting changes, the decrease of $32 million in results from
discontinued operations and the $24 million earnings decrease before these
items, as discussed above.
36
COMMODITY CONTRACTS AND MARK-TO-MARKET ACTIVITIES
The table below summarizes the changes in commodity contract assets and
liabilities for the nine months ended September 30, 2003. The net increase,
excluding "cumulative effect of change in accounting principle" and "other
activity" as described below, of $15 million represents the net favorable effect
of mark-to-market accounting on earnings for the nine months ended September 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) .................. (97)
Unrealized mark-to-market valuations of positions held at end of period (3).... 112
Other activity (4)............................................................. 16
-----
Balance of net commodity contract assets at September 30, 2003................ $ 253
=====
--------------------------
(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 retail and wholesale contracts in 2003. For the
three- and nine-month periods ended September 30, 2002, TXU Corp. recognized $2
million and $36 million in origination gains on such contracts, respectively.
Maturity Table -- Of the net commodity contract asset balance above at
September 30, 2003, the amount representing unrealized mark-to-market net gains
that have been recognized in current and prior years' earnings is $316 million.
The offsetting net liability of $63 million included in the September 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 September 30, 2003, scheduled
by contractual settlement dates of the underlying positions.
Maturity dates of unrealized net mark-to-market balances at September 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 $ 10 $ - $ - $ 17
Prices provided by other
external sources............. 199 67 3 (1) 268
Prices based on models........... (6) 11 5 21 31
----- ---- --- ---- -----
Total............................ $200 $ 88 $ 8 $ 20 $ 316
==== ==== === ==== =====
Percentage of total fair value... 63% 28% 3% 6% 100%
As the above table indicates, approximately 91% of the unrealized
mark-to-market valuations at September 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 2006 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 2010, respectively, in the US. The "prices based on models" category
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.
37
SEGMENTS
Energy
- ------
Financial Results
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ------------------
2003 2002 2003 2002
--------- -------- ------- ------
Operating revenues.......................................... $ 2,453 $ 2,420 $ 6,304 $ 6,238
Costs and expenses:
Cost of energy sold and delivery fees.................. 1,543 1,536 4,043 3,662
Operating costs........................................ 171 183 550 536
Depreciation and amortization.......................... 100 116 308 342
Selling, general and administrative expenses........... 168 199 465 623
Franchise and revenue-based taxes ..................... 29 27 84 83
Other income .......................................... (20) (18) (44) (33)
Other deductions....................................... 8 3 13 8
Interest income........................................ - - (3) (8)
Interest expense and related charges................... 83 46 246 154
------- ------- ------- -------
Total costs and expenses........................... 2,082 2,092 5,662 5,367
------- ------- ------- -------
Income before income taxes and cumulative effect of
changes in accounting principles........................ 371 328 642 871
Income tax expense.......................................... 122 101 204 274
------- ------- ------- -------
Income before cumulative effect of changes in accounting
principles.................................................. $ 249 $ 227 $ 438 $ 597
======= ======= ======= =======
38
Energy
- -------
Segment Highlights
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ---------------------
2003 2002 2003 2002
-------- -------- ------ ------
Operating statistics:
Retail electric sales volumes (GWh) ........................ 23,450 27,394 62,652 72,551
Wholesale electric sales volumes (GWh)...................... 10,677 9,255 26,512 22,569
------ ----- ------ ------
Total electric sales volumes (GWh)....................... 34,127 36,649 89,164 95,120
====== ====== ======== ========
Retail electric customers (end of period & in
thousands-number of meters)................................. 2,617 2,763
Operating revenues (millions of dollars):
Retail electric:
Residential........................................... $ 1,139 $ 1,093 $ 2,631 $ 2,569
Commercial and industrial ............................ 847 839 2,427 2,720
------- ------- ------- -------
Total........................................... 1,986 1,932 5,058 5,289
Wholesale electric ......................................... 406 302 924 657
Portfolio management activities............................. 16 152 169 201
Other revenues.............................................. 45 34 153 91
------- ------- ------- -------
Total operating revenues......................... $ 2,453 $ 2,420 $ 6,304 $ 6,238
======= ======= ======= =======
Weather (average for service territory)
Percent of normal:
Cooling degree days............................... 99.0% 99.8% 101.0% 102.1%
Heating degree days............................... -% -% 102.6% 98.8%
- --------------------------
Weather data is obtained from Meteorlogix, an independent company that
collects weather data from reporting stations of the National Oceanic and
Atmospheric Administration (a federal agency under the US Department of
Commerce).
39
Energy
- ------
Three Months Ended September 30, 2003 Compared to Three Months Ended
September 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 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 $33 million, or 1%, to $2.5 billion in 2003.
Retail and wholesale electric revenues increased $158 million, or 7%, to $2.4
billion, reflecting a $312 million increase due to higher average prices,
partially offset by a $154 million reduction due to lower sales volumes. The
$312 million favorable price variance reflects increased price-to-beat rates,
due to approved fuel factor increases, higher pricing in the commercial and
industrial business and increased wholesale prices, all resulting from higher
natural gas costs. The $154 million unfavorable volume variance reflects a 7%
decline in total sales volumes on a 14% decline in retail electric sales volumes
due to increased competitive activity, primarily in the commercial and
industrial segment of the market, partially offset by a 15% increase in
wholesale electric volumes, reflecting a partial shift in the commercial and
industrial customer base from retail to wholesale services. Residential and
small business customer counts at September 30, 2003 declined 3% from year-end
2002. Results from portfolio management activities declined $136 million. Such
results include realized and unrealized gains and losses from risk management
activities, and the decline reflects the effect of market price movements on
commodity contracts entered into to hedge exposures.
Gross Margin
Three Months Ended
September 30,
-----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 2,453 100% $ 2,420 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 1,543 63% 1,536 63%
Operating costs................................... 171 7% 183 8%
Depreciation and amortization related to generation
assets........................................ 90 4% 107 4%
------- ----- ------- ------
Gross margin........................................... $ 649 26% $ 594 25%
======= ===== ======= ======
The depreciation and amortization expense reported in the gross margin
amounts above excludes $10 million and $9 million of such expense for the three
months ended September 30, 2003 and 2002, respectively, that is not directly
related to generation property, plant and equipment.
Gross margin increased $55 million, or 9%, to $649 million in 2003. The
increase reflected higher average retail and wholesale sales prices, partially
offset by higher average costs of energy sold, lower portfolio management
results and the effect of volume declines. Increased costs of energy sold were
driven by higher natural gas prices. As nuclear generation is the lowest
marginal cost source of power production, average cost of energy sold was
unfavorably impacted by approximately $20 million due to an outage at the
nuclear generation facility to repair a reactor coolant water pump. Higher
average costs of energy sold were largely offset by a net reduction of $19
million in the retail clawback accrual principally because competition in the
small commercial segment of retail operations has resulted in TXU Energy not
retaining more than 60% of its historical power consumption in this segment.
Accordingly, TXU Energy does not expect to fund the related retail clawback
credit under the Settlement Plan. Mark-to-market accounting for commodity
contracts increased revenues and gross margin by $1 million in 2003 and by $8
million in 2002 (as compared to accounting on a settlement basis).
Operating costs decreased $12 million, or 7%, to $171 million in 2003 due
primarily to timing of repair and maintenance expenses. Depreciation and
amortization related to generation assets decreased $17 million, or 16%, to $90
million in 2003. Of the decrease, $12 million represented the effect of adjusted
depreciation rates related to the generation fleet, effective with second
quarter reporting. The adjusted rates reflect an extension in the estimated
depreciable life of the 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 in
emissions equipment made in recent years.
40
A decrease in depreciation and amortization (including amounts shown in
the gross margin table above) of $16 million, or 14%, to $100 million in 2003
was driven primarily by the adjusted depreciation rates related to TXU Energy's
generation fleet as discussed above.
SG&A expenses declined $31 million, or 16%, to $168 million in 2003. This
decrease reflected approximately $16 million of nonrecurring costs incurred in
2002 related to the transition to competition and $18 million in lower costs in
the strategic retail services business with the scaling-back of its operations,
partially offset by $8 million in higher bad debt expense.
Franchise and revenue-based taxes increased $2 million, or 7%, to $29
million in 2003 reflecting an increase in state franchise taxes.
Other income increased $2 million to $20 million in 2003. Other income in
both periods included $18 million of amortization of a gain on the sale of two
generation plants in 2002.
Other deductions increased $5 million to $8 million in 2003. The 2003
amount included $5 million in charges related to the scaling-back of the
strategic retail services business.
Interest expense and related charges increased $37 million, or 80%, to $83
million in 2003. The increase reflects $29 million due to higher average rates,
$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. (The notes were subsequently exchanged by TXU Energy for
exchangeable preferred membership interests.) Higher average rates were due in
part to replacement of short-term borrowings with higher rate long-term debt.
The effective income tax rate increased to 32.9% in 2003 from 30.8%
in 2002. The increase was primarily due to adjustments recorded in 2002 arising
from the reconciliation of the final 2001 federal income tax return to the
previously recorded estimated tax provision.
Income before cumulative effect of changes in accounting principles
increased $22 million, or 10%, to $249 million in 2003. The increase was driven
by the higher gross margin and the decreased SG&A expenses, partially offset by
the increase in interest expense. Net pension and postretirement benefit costs
reduced net income by $9 million in 2003 and $4 million in 2002.
Energy
- ------
Nine Months Ended September 30, 2003 Compared to Nine Months Ended
September 30, 2002
- -------------------------------------------------------------------
Operating revenues increased $66 million, or 1%, to $6.3 billion in 2003.
Retail and wholesale electric revenues increased $36 million, or 1%, to $6
billion, reflecting a $408 million increase due to higher average prices
partially offset by a $372 million reduction due to lower sales volumes. The
$408 million favorable price variance reflects increased price-to-beat rates,
due to approved fuel factor increases, higher pricing in the commercial and
industrial business and increased wholesale prices, all resulting from higher
natural gas costs. The $372 million unfavorable volume variance reflects a 6%
decline in total sales volumes on a 14% decline in retail electric sales volumes
due to the effects of increased competitive activity, primarily in the
commercial and industrial segment of the market, partially offset by a 17%
increase in wholesale electric volumes reflecting a partial shift in the
commercial and industrial customer base from retail to wholesale services.
Residential and small business customer counts at September 30, 2003 declined 3%
from year-end 2002. Results from portfolio management activities declined $32
million. Such results include realized and unrealized gains and losses from risk
management activities, and the decline reflects the effect of market price
movements on commodity contracts entered into to hedge exposures. Other revenues
increased $62 million, reflecting increased activity related to a previously
existing contract in the small strategic retail services business, higher late
fees on accounts receivable and increased pipeline transportation and other
service revenues.
41
Gross Margin
Nine Months Ended
September 30,
-------------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 6,304 100% $ 6,238 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 4,043 64% 3,662 59%
Operating costs................................... 550 9% 536 8%
Depreciation and amortization related to generation
assets........................................ 279 4% 310 5%
------- ----- ------- ------
Gross margin........................................... $ 1,432 23% $ 1,730 28%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $29 million and $32 million of such expense for the nine months ended
September 30, 2003 and 2002, respectively, that is not directly related to
generation property, plant and equipment.
Gross margin decreased $298 million, or 17%, to $1.4 billion in 2003. The
decrease reflected increased average costs of energy sold and lower retail sales
volumes, partially offset by higher average retail and wholesale sales prices.
Increased energy costs were driven by higher natural gas prices. As nuclear
generation is the lowest marginal cost source of power production, average cost
of energy sold was unfavorably impacted by approximately $45 million due to
outages in May and July of 2003 due to a lightning strike on the transmission
system and pump repairs, respectively. Higher average costs of energy sold were
partially offset by a net reduction of $19 million in the retail clawback
accrual as discussed above. Mark-to-market accounting for commodity contracts
increased revenues and gross margin by $34 million in 2003 and decreased results
by $4 million in 2002 (as compared to accounting on a settlement basis).
Operating costs rose $14 million, or 3%, to $550 million reflecting
increased activity related to a previously existing contract in the strategic
retail services business. Depreciation and amortization related to generation
assets decreased $31 million, or 10%, to $279 million. Of this decline, $25
million represented the effect of adjusted depreciation rates related to TXU
Energy's generation fleet as discussed above.
A decrease in depreciation and amortization (including amounts shown in
the gross margin table above) of $34 million, or 10%, to $308 million in 2003
reflected adjusted depreciation rates related to TXU Energy's generation fleet
as discussed above.
SG&A expenses declined $158 million, or 25%, to $465 million in 2003. This
decrease reflected cost reductions, primarily lower staffing and related
administrative expenses, totaling approximately $70 million and reflecting the
completion of the transition to competition in Texas and the industry-wide
decline in portfolio management activities, as well as $20 million from the
scaling-back of the strategic retail services operations. Lower SG&A expenses
also reflected $53 million in lower bad debt expense, due to the effect of
billing and collection delays experienced in 2002 in connection with the
transition to competition and initiatives implemented in 2003 to reduce such
expenses.
Other income increased by $11 million to $44 million in 2003. Other income
in both periods included $30 million of amortization of a gain on the sale of
two generation plants in 2002. The 2003 period also included a $9 million gain
on the sale of certain retail commercial and industrial gas operations.
Other deductions increased by $5 million, or 63%, to $13 million in 2003.
The 2003 amount included $5 million in charges related to the scaling-back of
the strategic retail services business. Other deductions in both years included
storage and other incidental expenses related to two canceled generation plant
construction projects.
Interest income declined by $5 million, or 63%, to $3 million in 2003
primarily due to lower average advances to affiliates.
42
Interest expense and related charges increased $92 million, or 60%, to
$246 million in 2003. The increase reflects $63 million due to higher average
interest rates and fees, $14 million due to higher average debt levels and $15
million in amortization of the discount on the exchangeable subordinated notes
issued in 2002. (The notes were subsequently exchanged by TXU Energy for
exchangeable preferred membership interests.) Higher average rates were due in
part to replacement of short-term borrowings with higher rate long-term debt.
The effective income tax rate of 31.8% in 2003 was comparable to the 31.5%
rate in 2002, reflecting the effect of the federal tax return related adjustment
recorded in 2002, as discussed above, largely offset by the effect of comparable
lignite depletion on lower pretax earnings in 2003.
Income before cumulative effect of changes in accounting principles
decreased $159 million, or 27%, to $438 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 $27 million in 2003 and
by $15 million in 2002.
43
Energy Delivery
- ---------------
Financial Results
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ---------------------
2003 2002 2003 2002
--------- -------- ------- ------
Operating revenues............................................ $ 786 $ 694 $ 2,597 $2,189
Costs and expenses:
Cost of energy sold and delivery fees.................... 65 45 584 297
Operating costs.......................................... 221 213 652 602
Depreciation and amortization............................ 97 83 271 246
Selling, general and administrative expenses............. 81 83 247 265
Franchise and revenue-based taxes ....................... 76 77 238 236
Other income ............................................ (3) (1) (9) (5)
Other deductions......................................... -- 2 -- 3
Interest income.......................................... (15) (11) (45) (32)
Interest expense and related charges .................... 87 83 265 244
------- ------- ------- -------
Total costs and expenses............................. 609 574 2,203 1,856
------- ------- ------- -------
Income before income taxes.................................... 177 120 394 333
Income tax expense............................................ 60 42 131 113
------- ------- ------- -------
Net income ................................................... $ 117 $ 78 $ 263 $ 220
======= ======= ======= =======
- -----------------
The Energy Delivery segment includes the electricity T&D business of Oncor
and the natural gas pipeline and distribution business of TXU Gas. Both
Oncor and TXU Gas are subject to regulation by Texas authorities.
44
Energy Delivery
- ---------------
Segment Highlights
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- ------------------
2003 2002 2003 2002
-------- -------- -------- ---------
Operating statistics
Delivered electricity volumes (GWh) (a).......................... 31,881 30,040 80,167 79,858
====== ======== ======== ========
Retail gas distribution volumes (Billion cubic feet-Bcf):
Residential................................................. 6 6 59 57
Commercial.................................................. 7 7 38 38
Industrial and electric generation.......................... 1 1 5 5
------ -------- -------- --------
Total gas sales....................................... 14 14 102 100
====== ======== ======== ========
Pipeline transportation volumes (Bcf)............................. 97 129 275 347
====== ======== ======== ========
Retail gas distribution customers and electric points of
delivery (end of period and in thousands):
Retail gas distribution customers........................... 1,457 1,443
Electric points of delivery................................. 2,920 2,902
Operating revenues (millions of dollars)
Electricity distribution:
TXU Energy.................................................. $ 441 $ 438 $ 1,167 $ 1,252
Non-affiliated retail electric providers.................... 172 119 438 299
------ -------- -------- --------
Total ............................................... 613 557 1,605 1,551
------ -------- -------- --------
Retail gas distribution:
Residential................................................. 75 64 570 363
Commercial.................................................. 53 39 302 180
Industrial and electric generation.......................... 11 5 31 18
------ -------- -------- --------
Subtotal ............................................ 139 108 903 561
Pipeline transportation.......................................... 15 20 43 48
Other revenues, net of eliminations.............................. 19 9 46 29
------ -------- -------- --------
Total retail gas distribution and pipeline........... 173 137 992 638
------ -------- -------- --------
transportation...................................................
Total operating revenues......................................... $ 786 $ 694 $ 2,597 $ 2,189
====== ======== ======== ========
(a) 2002 data revised
45
Energy Delivery
- ---------------
Three Months Ended September 30, 2003 Compared to Three Months Ended
September 30, 2002
- ---------------------------------------------------------------------
Operating revenues for the Energy Delivery segment increased $92 million,
or 13%, to $786 million in 2003. Electricity delivery revenues increased $56
million, or 10%, to $613 million. Higher tariffs provided $22 million of this
increase, reflecting transmission rate increases approved in 2003 ($14 million)
and a distribution rate increase associated with the issuance of transition
(securitization) bonds in August 2003 ($8 million) (see discussion under
"Regulation and Rates"). The higher revenues also reflected lower unbilled
revenues in 2002 of approximately $15 million resulting from billing delays
associated with the transition to competition, as previously disclosed. Higher
volumes, principally associated with large commercial and industrial customers,
resulted in a $10 million increase in revenues. Increased disconnect/reconnect
fees due primarily to new POLR rules in 2003 generated an $8 million increase in
revenues. Gas delivery revenues increased $36 million, or 26%, to $173 million,
reflecting $27 million due to higher gas costs, $8 million due to increased
activity in the utility asset management services business and $2 million due to
higher base distribution rates. The average cost of gas rose 43%, while retail
gas distribution volumes were flat.
Gross Margin
Three Months Ended
September 30,
------------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 786 100% $ 694 100%
Costs and expenses:
Cost of gas sold.................................. 65 8% 45 6%
Operating costs................................... 221 28% 213 31%
Depreciation and amortization related to T&D assets 93 12% 80 12%
------- ----- ------- ------
Gross margin........................................... $ 407 52% $ 356 51%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $4 million and $3 million of such expense for the three months ended
September 30, 2003 and 2002, respectively, that is not directly related to
delivery property, plant and equipment.
Gross margin increased $51 million, or 14%, to $407 million in 2003. The
increase was driven by higher electricity delivery margin due to the higher
revenues. The increase in cost of gas sold of $20 million, or 44%, reflects the
higher average gas cost. Higher operating costs of $8 million, or 4%, to $221
million reflected increased activity in the utility asset management services
business of $8 million and an increase in third-party transmission costs of $8
million, partially offset by lower vegetation management and overhead
distribution lines maintenance costs of $5 million.
Depreciation and amortization (including amounts shown in the gross margin
table above), increased $14 million, or 17%, to $97 million in 2003. The
increase reflects $5 million in higher depreciation due to investments in
delivery facilities to support growth and normal replacements of equipment and
$8 million in amortization of regulatory assets associated with the issuance of
securitization bonds in August 2003. The effect on revenues of the higher
distribution rates associated with the issuance of securitization bonds is
offset by the related amortization expense.
SG&A expenses decreased by $2 million, or 2%, to $81 million in 2003 due
primarily to lower outside services and consulting expenses of $6 million,
resulting from cost reduction initiatives implemented in late 2002, and lower
bad debt expense of $3 million, partially offset by higher employee benefit
costs of $5 million.
Franchise and revenue-based taxes increased $1 million, or 1%, to $76
million in 2003 reflecting higher local gross receipts taxes due to higher
revenues on which this tax is based.
46
Interest income increased $4 million, or 36%, to $15 million in 2003,
driven by the electricity delivery operations. The increase was due primarily to
higher interest reimbursements from TXU Energy of $6 million, reflecting higher
carrying costs on regulatory assets, partially offset by $4 million in lower
interest from TXU Energy on the excess mitigation credit note receivable due to
principal repayments (see discussion under "Regulation and Rates").
Interest expense and related charges rose by $4 million, or 5%, to $87
million in 2003. The increase reflects $9 million due to higher average interest
rates on borrowings, partially offset by $4 million due to lower interest
credited to electric delivery customers related to the excess mitigation credit
and $1 million due to lower debt levels. The increase in average interest rates
reflected the refinancing of affiliate borrowings with higher rate long-term
debt issuances.
The effective income tax rate decreased to 33.9% in 2003 from 35.0% in
2002, primarily reflecting a lower state income tax provision.
Net income increased $39 million, or 50%, to $117 million in 2003,
reflecting improved results of $30 million in the electricity delivery business
and $9 million in the gas delivery business. The increase in the electricity
delivery business was driven by higher revenues, partially offset by higher
depreciation and interest expense. The performance in the gas delivery business
reflected improved gross margin and lower interest expense. Net pension and
postretirement benefit costs reduced net income by $7 million in 2003 and $4
million in 2002.
Energy Delivery
- ---------------
Nine Months Ended September 30, 2003 Compared to Nine Months Ended
September 30, 2002
- -------------------------------------------------------------------
Operating revenues for the Energy Delivery segment increased $408 million,
or 19%, to $2.6 billion in 2003. Gas distribution and pipeline transportation
revenues increased $354 million, or 55%, to $992 million, reflecting $308
million in higher gas costs passed on to customers, $11 million from higher base
distribution rates, $13 million from higher sales volumes and $11 million from
increased activity in the utility asset management services business. The
average cost of gas rose 83%, while volumes increased 2% due to colder weather.
Electricity delivery revenues increased $54 million, or 3%, to $1.6 billion.
Higher tariffs provided $32 million of this increase, reflecting transmission
rate increases approved in 2003 ($24 million) and a distribution rate increase
associated with the issuance of securitization bonds in August 2003 ($8 million)
(see discussion under "Regulation and Rates"), as well as $21 million in
increased disconnect/reconnect fees due primarily to the new POLR rules in 2003.
Gross Margin
Nine Months Ended
September 30,
------------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 2,597 100% $ 2,189 100%
Costs and expenses:
Cost of gas sold.................................. 584 23% 297 13%
Operating costs................................... 652 25% 602 28%
Depreciation and amortization related to T&D assets 261 10% 238 11%
------- ----- ------- ------
Gross margin........................................... $ 1,100 42% $ 1,052 48%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $10 million and $8 million of such expense for the nine months ended
September 30, 2003 and 2002, respectively, that is not directly related to
delivery property, plant and equipment.
Gross margin increased $48 million, or 5%, to $1.1 billion in 2003. The
increase was driven by the gas delivery business, reflecting the impact of
higher volumes and base distribution rates, partially offset by higher operating
expenses and higher depreciation and amortization. The increase in operating
costs of $50 million, or 8%, to $652 million was driven by $24 million in higher
electricity transmission costs paid to other utilities, $9 million in higher
pension and other postretirement benefit costs and a $12 million increase on
greater activity in the utility asset management services business.
47
Depreciation and amortization (including amounts shown in the gross margin
table above), increased $25 million, or 10%, to $271 million in 2003. The
increase reflected higher depreciation of $15 million due to investments in
delivery facilities to support growth and normal replacements of equipment and
$8 million in amortization of regulatory assets associated with issuance of
securitization bonds in August 2003. The effect on revenues of the higher
distribution rates associated with the issuance of securitization bonds is
offset by the related amortization expense.
SG&A expenses decreased by $18 million, or 7%, to $247 million in 2003 due
primarily to lower outside services and consulting expenses arising from
electricity delivery cost reduction initiatives implemented in late 2002.
Franchise and revenue-based taxes increased $2 million, or 1%, to $238
million in 2003 reflecting higher local gross receipts taxes due to higher
revenues on which this tax is based.
Interest income increased $13 million, or 41%, to $45 million in 2003. An
increase in the electricity delivery business reflected higher interest
reimbursements from TXU Energy of $19 million due to higher carrying costs on
regulatory assets, partially offset by $12 million less interest on the excess
mitigation credit note receivable due to principal repayments (see discussion
under "Regulation and Rates"). Higher interest income also reflected increased
undercollected gas costs.
Interest expense and related charges rose by $21 million, or 9%, to $265
million in 2003. The increase reflected a $29 million impact of higher average
interest rates, partially offset by $12 million less interest credited to REPs
related to the excess mitigation credit. The change in average interest rates
reflected the refinancing of affiliate borrowings in the electricity delivery
business with higher rate long-term debt issuances.
The effective income tax rate was 33.2% in 2003 and 33.9% in 2002. There
were no significant unusual items impacting the effective rates.
Net income increased $43 million, or 20%, to $263 million in 2003,
reflecting improved results of $36 million in the gas delivery business and $7
million in the electricity delivery business. The performance in the gas
delivery business reflected improved gross margin and lower interest expense.
The increase in the electricity delivery business reflected higher revenues,
partially offset by higher operating expenses and higher interest expense. Net
pension and postretirement benefit costs reduced net income by $20 million in
2003 and $14 million in 2002.
48
Australia
- ---------
Financial Results
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- ------------------------
2003 2002 2003 2002
--------- --------- -------- ---------
Operating revenues....................................... $ 321 $ 234 $ 820 $ 662
Costs and expenses:
Cost of energy sold and delivery fees............... 153 118 382 298
Operating costs..................................... 28 19 73 61
Depreciation and amortization....................... 21 17 62 49
Selling, general and administrative expenses........ 30 30 73 64
Other income ....................................... (1) (4) - (2)
Other deductions.................................... 1 - 2 1
Interest income..................................... (1) - (4) -
Interest expense and related charges ............... 39 32 109 94
------- ------- ------- -------
Total costs and expenses........................ 270 212 697 565
------- ------- ------- -------
Income before income taxes .............................. 51 22 123 97
Income tax expense....................................... 8 6 27 20
------- ------- ------- -------
Net income .............................................. $ 43 $ 16 $ 96 $ 77
======= ======= ======= =======
49
Australia
- ---------
Segment Highlights
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- -------------------
2003 2002 2003 2002
--------- -------- --------- ---------
Operating Statistics
Retail electricity sales volumes (GWh).................... 2,337 2,026 6,142 5,062
Retail gas sales volumes (Bcf)........................... 22 21 50 52
Wholesale electricity sales volumes (GWh)................. 423 1,051 1,419 2,371
Retail customers and points of delivery
(end of period and in thousands):
Electric............................................. 556 536
Gas.................................................. 484 434
------ ------
Total customers............................ 1,040 970
====== ======
Electricity distribution points of delivery.......... 557 545
Gas distribution points of delivery.................. 477 463
------ ------
Total points of delivery................... 1,034 1,008
====== ======
Operating revenues (millions of dollars)
Retail electric:
Residential.......................................... $ 84 $ 66 $ 211 $ 165
Commercial and industrial............................ 80 58 234 157
------ ------ ------ ------
Total........................................ 164 124 445 322
------ ------ ------ ------
Electricity delivery...................................... 14 10 41 28
------ ------ ------ ------
Retail gas sales:
Residential (a)...................................... 93 43 160 71
Commercial and industrial............................ 22 17 69 69
------ ------ ------ ------
Total........................................ 115 60 229 140
------ ------ ------ ------
Gas distribution.......................................... 17 12 34 27
Wholesale electric revenues............................... 8 16 33 48
Portfolio management activities and other revenues........ 3 12 38 97
------ ------ ------ ------
Total operating revenues..................... $ 321 $ 234 $ 820 $ 662
====== ====== ====== ======
(a) Growth reflected a former agency arrangement for certain customers, which
converted to a direct sales relationship in late 2002, with revenue in 2002
representing the service fee. Reported volumes for 2003 and 2002 are
comparable.
50
Australia
- ---------
Three Months Ended September 30, 2003 Compared to Three Months Ended
September 30, 2002
- --------------------------------------------------------------------
The Australia segment's operating revenues increased $87 million, or 37%,
to $321 million in 2003. Of this increase, $46 million represented the
translation effect of the stronger Australian dollar. The balance of the growth
was driven by an increase in retail gas revenues of $43 million, or 71%, and
higher retail electricity revenues of $14 million, or 12% (both on a constant
exchange rate basis). Retail gas revenue growth in 2003 included a $22 million
effect of certain service fee based customers converting from an agency
arrangement to direct customers in October of 2002, resulting in an increase in
revenues and cost of energy sold. Retail gas revenue growth also reflected a 5%
increase in sales volumes, due primarily to colder winter weather and increased
number of residential customers. Retail electricity sales volumes rose 15%,
driven by an increase in commercial/industrial customer accounts. Wholesale
power revenues declined $11 million, or 69%, on a constant exchange rate basis
due to lower volumes generated and sold into the wholesale markets and lower
wholesale market prices. Results from portfolio management activities decreased
due to the effects of lower wholesale prices and decreased price volatility.
Gross Margin
Three Months Ended
September 30,
-------------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 321 100% $ 234 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 153 47% 118 51%
Operating costs................................... 28 9% 19 8%
Depreciation and amortization related to operating
assets........................................ 19 6% 15 6%
------- ----- ------- ------
Gross margin........................................... $ 121 38% $ 82 35%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin excludes
$2 million of such expense for the three months ended September 30, 2003 and
2002, respectively, that is not directly related to generation and delivery
property, plant and equipment.
Australia's gross margin increased $39 million, or 48%, to $121 million in
2003. On a local currency basis, margins improved 20%, driven by the higher
retail gas and electricity volumes and lower purchased power costs, partially
offset by decreased wholesale electricity sales margins and lower results from
portfolio management activities. Wholesale power prices have declined 36% from
2002 levels. Lower wholesale prices in 2003 favorably affected comparisons of
retail operations but unfavorably affected comparisons of wholesale activities.
Operating costs increased 24% on a local currency basis, reflecting higher
delivery maintenance costs due to severe weather and wildfires, as well as
increased employee benefits costs. Mark-to-market accounting for commodity
contracts decreased revenues and gross margin by $13 million in 2003 and
$8 million in 2002 (as compared to accounting on a settlement basis).
Australia's SG&A expenses in 2003 were unchanged, but on a local currency
basis, decreased 14%, primarily due to start-up expenses incurred in 2002
related to the Australia segment's involvement in a joint venture to construct a
gas pipeline.
Australia's interest expense and other charges increased $7 million, or
22%, to $39 million in 2003. On a local currency basis, interest expense and
other charges declined 1%, reflecting lower debt levels.
The effective income tax rate was 16% in 2003 compared to 27.3% in 2002,
reflecting a $5 million deferred tax adjustment relating to prior years recorded
in the third quarter 2003.
Australia's net income increased to $43 million in 2003 from $16 million
in 2002, reflecting the higher gross margin, a $7 million favorable effect of
the stronger Australian dollar and the lower effective tax rate. Net pension and
postretirement benefit costs reduced net income by less than $1 million in both
2003 and 2002.
51
Australia
- ---------
Nine Months Ended September 30, 2003 Compared to Nine Months Ended
September 30, 2002
- ------------------------------------------------------------------
The Australia segment's operating revenues increased $158 million, or 24%,
to $820 million in 2003. Of this increase, $115 million represented the
translation effect of the stronger Australian dollar. The balance of the growth
was driven by an increase in retail gas revenues of $63 million, or 45%, and
higher retail electricity revenues of $69 million, or 21% (both on a constant
exchange rate basis). Retail gas revenue growth in 2003 included a $42 million
effect of certain service fee based customers converting from an agency
arrangement to direct customers in October of 2002, resulting in an increase in
revenues and cost of energy sold. Retail gas revenue growth also reflected
higher average prices. Retail electricity sales volumes rose 21%, driven by an
increase in commercial/industrial customer accounts. Wholesale power revenues
declined $22 million, or 47%, on a constant exchange rate basis due to lower
volumes generated and sold into the wholesale markets and lower wholesale market
prices. Portfolio management results decreased $66 million on a constant
exchange rate basis, 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
Nine Months Ended
September 30,
-----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 820 100% $ 662 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 382 46% 298 45%
Operating costs................................... 73 9% 61 9%
Depreciation and amortization related to operating
assets........................................ 55 7% 45 7%
------- ----- ------- ------
Gross margin........................................... $ 310 38% $ 258 39%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin excludes
$7 million and $4 million of such expense for the nine months ended September
30, 2003 and 2002, respectively, that is not directly related to generation and
delivery property, plant and equipment.
Australia's gross margin improved $52 million, or 20%, to $310 million in
2003. On a local currency basis, margins increased 1%. Excluding the gain in
2002 on the wholesale power contract termination, gross margin on a local
currency basis rose 15%, driven by increased retail electric and gas sales
volumes and lower purchased power costs, partially offset by higher gas purchase
costs, lower wholesale electric sales margins and lower results from portfolio
management activities. Wholesale power prices have declined 31% from 2002
levels. Lower wholesale prices in 2003 favorably affected comparisons of
retail operations but unfavorably affected comparisons of wholesale activities.
Operating costs increased 3% on a local currency basis. Depreciation and
amortization related to operating assets increased 6% on a local currency basis,
reflecting expenditures for electricity delivery and production assets to
support growth. Mark-to-market accounting for commodity contracts decreased
revenues and gross margin by $19 million in 2003, and increased results in 2002
by $10 million (as compared to accounting on a settlement basis).
Australia's SG&A expenses rose $9 million, or 14%, to $73 million in 2003.
On a local currency basis, SG&A expenses decreased 1%, as increased staffing
expenses to support retail competition activities in newly competitive markets
were more than offset by the effect of start-up expenses incurred in 2002
related to the Australia segment's involvement in a joint venture to construct a
gas pipeline.
Australia's interest income increased to $4 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 project.
Australia's interest expense and other charges increased $15 million, or
16%, to $109 million in 2003. On a local currency basis, interest expense and
other charges declined 3%, reflecting lower debt levels.
52
The effective income tax rate was 22.0% in 2003 compared to 20.6% in 2002.
The increase reflects the non-taxable nature of the 2002 contract termination
gain, partially offset by an adjustment relating to prior years recorded in the
third quarter of 2003 and the utilization of a capital loss carryforward in the
second quarter of 2003.
Australia's net income rose $19 million, or 25%, to $96 million in 2003.
This increase reflected a $15 million favorable effect of the stronger
Australian dollar. Improved retail margins were partially offset by the $30
million (pre and after-tax) effect of the contract termination gain in 2002. On
a local currency basis and excluding the effect of the contract termination
gain, Australia's net income rose 40%. Net pension and postretirement benefit
costs reduced net income by $1 million in 2003 and 2002.
COMPREHENSIVE INCOME - Continuing Operations
Activities reported in other comprehensive income from continuing
operations were as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- --------------------
2003 2002 2003 2002
-------- -------- ------- -------
Cash flow hedge activity:
Net change in fair value of hedges - gains/(losses):
Commodities........................................ $ (24) $ (12) $ (127) $ (55)
Financing - interest rate and currency swaps....... 4 (83) (77) (159)
-------- --------- --------- ---------
(20) (95) (204) (214)
Losses realized in earnings:
Commodities........................................ 44 16 114 16
Financing - interest rate and currency swaps....... 20 16 103 58
-------- -------- -------- ---------
64 32 217 74
Net effect of cash flow hedges......................... 44 (63) 13 (140)
-------- --------- -------- ---------
Cumulative foreign currency exchange adjustments....... 19 (29) 180 44
-------- --------- -------- --------
Other comprehensive income (loss) net of tax effects... $ 63 $ (92) $ 193 $ (96)
======== ========= ======== =========
Gains and losses on cash flow hedges are realized in earnings as the
underlying hedged transactions are settled. Foreign currency translation
adjustments primarily reflect the movement in exchange rates between the US
dollar and the Australian dollar and have no tax effects.
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 8-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 nine
months ended September 30, 2003, totaled $2.0 billion compared to $1.0 billion
for 2002. The increase in cash flows provided by operating activities in 2003 of
$1.0 billion reflected a number of factors. The principal drivers of the
increase were improved working capital (accounts receivable, accounts payable
and inventories) of $705 million, which primarily reflects the effect of billing
and collection delays in 2002 associated with the transition to competition and
includes $129 million in increased funding under the accounts receivable sale
program, as well as 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. These items were partially offset by lower cash earnings
(net income adjusted for the significant noncash items identified in
the statement of cash flows) of $181 million and payments of $102 million
related to counterparty default events and the termination and liquidation of
those outstanding positions.
53
Cash flows used in financing activities were $1.6 billion in 2003 and $135
million in 2002. Net cash used in issuances and repayments of borrowings totaled
$1.4 billion in 2003 compared to $325 million in 2002. Net retirements of equity
securities totaled $64 million in 2003, while issuances of equity securities
totaled $717 million in 2002. Common stock dividends paid totaled $120 million
in 2003 and $481 million in 2002.
Cash flows used in investing activities totaled $1.4 billion in 2003 and
$400 million in 2002. Capital expenditures declined to $640 million in 2003 from
$733 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 $445 million included the sale of two generation plants
in Texas. Investment in a collateral trust associated with a credit facility
totaled $525 million in 2003.
Depreciation and amortization expense reported in the statement of cash
flows exceeds the amount reported in the statement of income by $57 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 certain regulatory assets, which is reported as
operating costs in the statement of income.
Financing Activities
Capitalization -- The capitalization ratios of TXU Corp. at September 30,
2003, consisted of 7.4% equity-linked debt securities, 3.3% exchangeable
preferred membership interests, 57% other long-term debt, less amounts due
currently, 2.6% trust securities, 0.6% preferred stock of subsidiaries, 1.5%
preference stock and 27.6% 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 September 30, 2003, TXU Corp. had outstanding
short-term borrowings consisting of bank borrowings of approximately $6 million
and commercial paper of $34 million (all in Australia). At December 31, 2002,
TXU Corp. had outstanding short-term borrowings consisting of bank borrowings of
approximately $2.3 billion (predominantly all in the US) at a weighted average
interest rate of 2.6% and commercial paper of $18 million (all in Australia).
54
At September 30, 2003, TXU Corp. and its subsidiaries had credit
facilities (some of which provide for long-term borrowings) as follows:
At September 30, 2003
--------------------------------------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
- -------- --------------- --------- ----- ------ ---------- ------------
(b)
Five-Year Revolving Credit Facility February 2005 US Holdings $ 1,400 $ 266 $ -- $1,134
Revolving Credit Facility February 2005 TXU Energy, Oncor 450 4 -- 446
Three-Year Revolving Credit Facility May 2005 US Holdings (a) 400 -- -- 400
Five-Year Revolving Credit Facility August 2008 TXU Corp. 500 -- -- 500
------- ------ ------ ------
Total US $ 2,750 $ 270 $ -- $2,480
======= ====== ====== ======
Senior Facility (b) October 2004 TXU Australia $ 1,185 $ -- $ 931 $ 237
Working Capital Facility October 2003 TXU Australia 67 -- 6 61
Standby Facility (b) December 2003 TXU Australia 17 -- -- --
------- ------ ------ ------
Total Australia $ 1,269 $ -- $ 937 $ 298
======= ====== ====== ======
(a) previously TXU Corp.
(b) Commercial paper borrowings totaling $34 million at September 30, 2003 were
supported by the Standby Facility ($17 million) and the Senior Facility
($17 million).
Through April 2003, TXU Corp. and its US subsidiaries repaid $2.3 billion
in cash borrowings outstanding as of December 31, 2002 under available credit
facilities.
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. capitalized LOC Trust
with approximately $525 million of cash, which the lenders have invested in
permitted investments as directed by LOC Trust. LOC Trust's assets, including
the investments, constitute collateral for the benefit of the lenders to secure
issuances of letters of credit or loans, and are owned by LOC Trust. During the
term of the facility, LOC Trust is required to maintain collateral in an amount
equal to 105% of the commitments under the secured facility. TXU Corp. may
request up to $500 million of letters of credit or up to $250 million of loans
from LOC Trust, subject in the 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 or loans, if any, from the lenders. LOC Trust is
included in the consolidated financial statements of TXU Corp. solely to comply
with GAAP.
In April 2003, the $450 million revolving credit facility was established
for TXU Energy and Oncor. This facility will be used for working capital and
other general corporate purposes, including letters of credit, and replaced a $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.
Since December 31, 2002, TXU Corp. elected to cancel $250 million in other
US credit facility capacity in response to changing liquidity needs.
The US Holdings, TXU Energy and Oncor facilities provide back-up for any
future issuance of commercial paper by TXU Energy and Oncor. At September 30,
2003, there was no such outstanding commercial paper.
The $1.4 billion facility provides for up to $1.0 billion in letters of
credit.
55
In addition to providing back-up of commercial paper issuance by TXU
Energy and Oncor, the US facilities above are for general corporate and working
capital purposes, including providing collateral support for TXU Energy
portfolio management activities.
Long-Term Debt -- During the nine months ended September 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.:
Convertible senior notes ...................... $ 525 $ -
Senior notes .................................. - 323
Other long-term debt .......................... - 97
Oncor:
First mortgage bonds........................... - 663
Medium term notes.............................. - 15
Transition bonds............................... 500 -
TXU Gas:
Senior notes................................... - 125
TXU Energy:
Fixed rate senior notes........................ 1,250 72
Pollution control revenue bonds................ 148 148
Other long-term debt........................... 2 -
US Holdings:
Other long-term debt........................... - 2
Pinnacle:
Senior notes................................... - 140
TXU Australia:
Long-term debt................................. 24 120
------ ------
Total......................................... $2,449 $1,705
====== ======
See Note 4 to Financial Statements for further detail of debt issuance and
retirements.
Pinnacle Telecommunications Business-- 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 -- TXU Corp. participates in an accounts receivable
securitization program. The activity under this program is accounted for as a
sale of accounts receivable in accordance with SFAS 140. Under the program, US
subsidiaries of TXU Corp. (originators) sell trade accounts receivable to TXU
Receivables Company, a consolidated wholly-owned bankruptcy remote direct
subsidiary of TXU Corp., which sells undivided interests in the purchased
accounts receivable for cash to special purpose entities established by
financial institutions. In September 2003, the maximum amount of undivided
interests that could be sold by TXU Receivables Company was increased by $100
million to $700 million. In November 2003, this amount decreased to $600
million.
All new trade receivables under the program generated by the originators
are continuously purchased by TXU Receivables Company with the proceeds from
collections of receivables previously purchased. Changes in the amount of
funding under the program, through changes in the amount of undivided interests
sold by TXU Receivables Company, are generally due to seasonal variations in the
level of accounts receivable and changes in collection trends. TXU Receivables
Company has issued subordinated notes payable to the originators for the
difference between the face amount of the uncollected accounts receivable
purchased, less a discount, and cash paid that was funded by the sale of the
undivided interests.
The discount from face amount on the purchase of receivables funds a
servicing fee paid by TXU Receivables Company to TXU Business Services Company,
a direct subsidiary of TXU Corp., as well as program fees paid by TXU
56
Receivables Company to the financial institutions. The servicing fee, which
totaled $7 million and $6 million for the nine month periods ended September 30,
2003 and 2002, respectively, compensates TXU Business Services Company for its
services as collection agent, including maintaining the detailed accounts
receivable collection records. The program fees paid to financial institutions,
which consist primarily of interest costs on the underlying financing, were $8
million and $11 million for the nine-month periods ending September 30, 2003 and
2002, respectively, and approximated 2.4% of the average funding under the
program on an annualized basis in each period; these fees represent the net
incremental costs of the program to the originators and are reported in SG&A
expenses.
The September 30, 2003 balance sheet reflects funding under the program of
$700 million, through sale of undivided interests in receivables by TXU
Receivables Company, related to $1.5 billion face amount of trade accounts
receivable of TXU Energy, TXU Gas and Oncor. Funding under the program increased
$229 million for the nine month period ended September 30, 2003, primarily due
to the program capacity increase of $100 million and the effect of improved
collection trends. Funding under the program for the nine month period ended
September 30, 2002 increased $100 million. Funding increases or decreases under
the program are reflected as operating cash flow activity in the statement of
cash flows.
Upon termination of the program, cash flows to TXU Corp. would be delayed
as collections of sold receivables would be used by TXU Receivables Company to
repurchase the undivided interests sold instead of purchasing new receivables.
The level of cash flows would normalize in approximately 16 to 31 days.
In June 2003, the program was amended to provide temporarily higher
delinquency and default compliance ratios and temporary relief from the loss
reserve formula, which allowed for increased funding under the program. 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. 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.
Contingencies Related to Sale of 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 have brought the ratios into consistent compliance with the
program.
Under terms of 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.
57
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.
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 September 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 ($670 million outstanding at September 30, 2003). The market price of TXU
Corp.'s common stock is above the stated level.
TXU Energy has provided a guarantee of the obligations under TXU Corp.'s
lease (approximately $130 million at September 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.
58
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 $112 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 all
three rating agencies. The amount TXU Energy would post under these transactions
depends in part on the value of the contracts at that time. As of September 30,
2003, based on current market conditions, the maximum TXU Energy would post for
these transactions is $230 million.
TXU Energy is also the obligor on leases aggregating $163 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
$24 million.
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 $6.5 million on a net basis.
TXU Australia has several contracts that may require additional guarantees
or cash collateral totaling approximately $54 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 were 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 (which is no longer outstanding as of October 1, 2003) 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 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 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.
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.
59
TXU Corp.'s 6% Notes due 2003 to 2004, which are held by the Pinnacle
Overfund Trust, and Pinnacle's 8.83% Senior Secured Notes due 2004, reported in
liabilities of the telecommunications holding company (see Note 3), 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 $122 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.
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.
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. At its
August 2003 meeting, the Board of Directors of TXU Corp. declared a quarterly
dividend of $0.125 a share, payable on October 1, 2003, to shareholders of
record on September 5, 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
Consistent with industry practices, TXU Energy has decided to replace the
four steam generators in one of the two generation units of the Comanche Peak
nuclear plant in order to maintain the operating efficiency of the unit. An
agreement for the manufacture and delivery of the equipment was completed in
October 2003, and delivery is scheduled for late 2006. Estimated project capital
requirements, including purchase and installation, are $175 million to $225
million. Cash outflows are expected to occur in 2004 through 2007, with the
significant majority after 2004.
See Note 7 to Financial Statements for a discussion of contingencies.
60
REGULATION AND RATES
In October 2003, TXU Corp. received an informal request for information
from the US Commodity Futures Trading Commission (CFTC) seeking voluntary
production of information concerning disclosure of price and volume information
furnished by TXU Portfolio Management Company LP to energy industry
publications. The request seeks information for the period from January 1, 1999
to the present. TXU Corp. intends to cooperate with the CFTC, and the Company is
preparing to respond to such information request. While TXU Corp. is just
beginning to compile the data requested, TXU Corp. believes that TXU Portfolio
Management Company LP has properly reported such information to industry
publications.
1999 Restructuring Legislation and 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 electricity
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
(including TXU Energy) applied over a two-year period ending December 31, 2003.
The $350 million credit has been funded by TXU Energy through payments on a note
payable to Oncor. The actual amount of this credit is now expected to exceed
$350 million as delivery volumes are anticipated to be higher than initially
estimated. As a result, TXU Energy's earnings for the year 2003 are expected to
be reduced by approximately $19 million ($12 million after-tax), reflected as an
increase in TXU Energy's cost of energy sold and delivery fees. This effect is
net of TXU Energy's portion of the additional credit.
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
related transaction costs. The Settlement provides that there can be an initial
issuance of securitization bonds in the amount of up to $500 million, which was
completed in August of 2003, followed by a second issuance of the remainder
expected in the first quarter of 2004. The Settlement resolves all issues
related to regulatory assets and liabilities. On August 28, 2003, Oncor began
billing REPs a transition charge associated with the issuance of $500 million in
securitization bonds. The transition charge is designed to recover the
securitization bond principal and interest, as well as related transaction
costs. A total of $8 million of such transition charge revenues are reflected in
Oncor's revenues for the three months ended September 30, 2003. Increased
revenues on an annualized basis associated with this transition charge are
estimated to be $54 million.
Retail Clawback Credit -- This provision of the 1999 Restructuring
Legislation and the Settlement Plan provides for a reduction in delivery fees
charged to REPs if certain thresholds are not achieved in the competitive
markets. Oncor will provide the credit to REPs, but TXU Energy will fund the
credit. 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 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 is to be made separately for the
residential and small commercial classes. The credit will be applied to delivery
fees billed by Oncor to REPs, including TXU Energy, over a two-year period
beginning January 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 represented the best
estimate of the amount to be funded to Oncor over the two-year period.
For purposes of this report, 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.
61
On September 30, 2003, Oncor reported to the Commission that more than 40%
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. Although the Commission is required by law and its own rules to
review and approve or reject Oncor's petition within 30 days after filing, on
October 28, 2003, it referred this case to the State Office of Administrative
Hearings. When the Commission determines that Oncor has met the 40% threshold
target, TXU Energy will be able to offer additional pricing alternatives to this
class of customer. During the third quarter of 2003, TXU Energy reduced its
retail clawback accrual by $19 million, principally as a result of the
expectation that the 40% threshold had been met.
Price-to-Beat Rates - 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
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 April 2003, affiliated REPs
of utilities are allowed to petition the Commission 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 under
the prior rules to increase the fuel factor component of its
price-to-beat rates. This request was approved and became effective in
early March 2003. As a result, average monthly residential bills rose
approximately 12%. Appeals of the Commission's Order were filed by
three parties and are currently pending in the Travis County, Texas
District Court.
-- On July 23, 2003, TXU Energy filed another request with the Commission
to increase the fuel factor component of its price-to-beat rates. This
request was approved and became effective in late August 2003. The
change raised 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. This rate change increases TXU Energy's revenues by
approximately $180 million ($65 million for the remainder of 2003) on
an annualized basis. Appeals of the Commission's order have been filed
and are currently pending in the Travis County, Texas District Court.
Wholesale market design - On August 7, 2003, the Commission adopted a rule
that, if fully implemented, would alter the wholesale market design in ERCOT.
The rule requires ERCOT:
o to use a stakeholder process to develop a new wholesale market model;
o to operate a voluntary day-ahead energy market;
o to use a stakeholder process to develop a new wholesale market model;
o to directly assign all congestion rents to the resources that caused
the congestion;
o to use nodal energy prices for resources;
o to provide information for energy trading hubs by aggregating nodes;
o to use zonal prices for loads; and
o to provide congestion revenue rights (but not physical rights).
Under the rule, the proposed market design and associated cost-benefit
analysis is to be filed with the Commission by November 1, 2004 and is to be
implemented by October 1, 2006. TXU Energy is unable to predict the cost or
impact of implementing any proposed change to the current wholesale market
design.
Transmission Rates -- In May 2003, the Commission approved an increase in
Oncor's wholesale transmission tariffs (rates) charged to distribution utilities
that became effective immediately. In August 2003, the Commission approved an
increase in the transmission cost recovery component of Oncor's distribution
rates charged to REPs (including TXU Energy). This increase was effective for
billings resulting from meter readings on or after September 1, 2003. The
combined effect of the increases in both the transmission and distribution rates
is an estimated $44 million of incremental revenues to Oncor on an annualized
basis. With respect to the impact on TXU Corp.'s consolidated results, the
higher distribution rates result in reduced margin on TXU Energy's sales to
those retail customers with pricing that does not provide for recovery of
higher delivery fees, principally price-to-beat customers.
62
Gas Distribution Rates - TXU Gas employs a continuing program of rate
review for all classes of customers in its regulatory jurisdictions. In July and
August of 2001, TXU Gas filed two cases with the RRC, 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 partial 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 the TXU Gas
Distribution and TXU Lone Star Pipeline operations. The case was filed in all
437 cities served by TXU Gas Distribution and at the RRC for TXU Lone Star
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. TXU Gas has appealed the cases filed with the 437 incorporated
cities over TXU Gas Distribution rates to the RRC. Twelve parties have
intervened in the case. Based on the current procedural schedule, TXU Gas
expects a final order from the RRC in May 2004.
In August 2003, TXU Gas filed its annual gas cost reconciliation for the
twelve month period ending June 30, 2003 with the RRC and the incorporated
cities served by TXU Gas. TXU Gas reconciled $797 million of gas costs.
Including interest and prior period adjustments, TXU Gas under-recovered $6
million of gas costs which will be recovered via a surcharge for nine months
starting October 2003.
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 were 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 by 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 8-K and this report, which might significantly alter its basic
financial position, results of operations or cash flows.
63
CHANGES IN ACCOUNTING STANDARDS
See Note 1 to Financial Statements for discussion of changes in accounting
standards.
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 these 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, RRC, 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 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.
64
TXU Corp.'s US regulated businesses are subject to cost-of-service
regulation and annual earnings oversight. This regulatory treatment does not
provide any assurance as to achievement of earnings level. 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
over the counter 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 8-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, borrowing costs would increase and
the potential pool of investors and funding sources would likely decrease. If
the downgrade was below investment grade, liquidity demands would be triggered
by the terms of a number of commodity contracts, leases and other agreements.
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 the 2002 Form 8-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. The risk of increased maintenance and capital expenditures
arises from (a) increased starting and stopping of generation equipment due to
the volatility of the competitive market, (b) any unexpected failure to produce
power, including failure caused by breakdown or forced outage, and (c) 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.
66
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 September 30, 2003,
TXU Corp. had approximately 2.4 million residential and small commercial
customers in its historical service territories in Texas. 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.
On September 30, 2003, Oncor reported to the Commission that more than 40%
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. Although the Commission is required by law and its own rules to
review and approve or reject Oncor's petition within 30 days after filing, on
October 28, 2003, it referred this case to the State Office of Administrative
Hearings. During the third quarter of 2003, TXU Energy reduced its retail
clawback accrual by $19 million, principally as a result of the expectation that
the 40% threshold had been met.
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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.
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. On September
30, 2003, Oncor reported to the Commission that more than 40% 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.
When the Commission concurs, through approval, that Oncor has met the 40%
threshold target, TXU Energy will be able to offer additional pricing
alternatives to this class of customer.
Other REPs are 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.
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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.
Under amended Commission rules, effective in April 2003, affiliated REPs
of utilities are allowed to petition the Commission twice per year for an
increase or decrease in the fuel factor component of their price-to-beat rates.
REPs may request an increase 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. This
request was approved and became effective in early March 2003. As a
result, average monthly residential bills rose approximately 12%.
Appeals of the Commission's Order were filed by three parties and are
currently pending in the Travis County, Texas District Court.
-- On July 23, 2003, TXU Energy filed another request with the Commission
to increase the fuel factor component of its price-to-beat rates. This
request was approved and became effective in late August 2003. The
change raised 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. This rate change increases TXU Energy's revenues by
approximately $180 million ($65 million for the remainder of 2003) on
an annualized basis. Appeals of the Commission's order have been filed
and are currently pending in the Travis County, Texas District Court.
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 provide service to 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.
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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.
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 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. The subsidiaries are separate and
distinct legal entities and have no obligation to provide TXU Corp. with funds
for its payment obligations, whether by dividends, distributions, loans or
otherwise.
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.
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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, and 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;
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.'s decision to exit all of its operations
in Europe, including the administration proceeding, has resulted in notices
of various claims or potential claims and might result in lawsuits by the
creditors of or other 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;
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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.
o Fluctuations in the market price of TXU Corp.'s common stock may be
unrelated to TXU Corp.'s performance. General market declines or market
volatility could adversely affect the price of TXU Corp.'s common stock
and the current market price may not be indicative of future market
prices.
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 8-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 the 2002 Form 8-K and
is therefore not presented herein.
72
COMMODITY PRICE RISK
Value at Risk (VaR) for Energy Contracts Subject to Mark-to-Market (MtM)
Accounting -- This measurement estimates the 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.
September 30, December 31,
2003 2002
---- ----
Period-end MtM VaR:
------------------
Energy................................................. $ 25 $23
Australia ............................................. $ 19 $13
Average Month-end MtM VaR (Year-to-date):
----------------------------------------
Energy................................................. $29 $ 38
Australia ............................................. $17 $ 15
Portfolio VaR -- Represents the estimated potential loss in value, due to
changes in market conditions, of the entire energy portfolio, including owned
assets, estimates of retail load and all contractual positions (the portfolio
assets). The Portfolio VaR calculations for Energy and Australia are modeled for
a duration of ten years and five years, respectively, based on the nature of
their particular markets. The Portfolio VaR for Australia does not include the
gas commodity portfolio due to a relatively illiquid gas market which does not
lend itself to reliable statistical measure. 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.
September 30, December 31,
2003 2002
---- ----
Period-end Portfolio VaR:
-------------------------
Energy................................................. $176 $144
Australia ............................................. $ 24 $22
Average Month-end Portfolio VaR (Year-to-date):
-----------------------------------------------
Energy (a)............................................. $181 N/A
Australia.............................................. $ 22 $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.
Energy Earnings at Risk (EaR) -- EaR measures the estimated potential loss
in expected earnings due to changes in market conditions. EaR metrics include
the owned assets, estimates of retail load and all contractual positions 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.
Energy 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 owned assets, estimates of retail
load and all contractual 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.
73
September 30, December 31,
2003 2002
---- ----
EaR ............................. $ 24 $ 28
CFaR ............................ $ 88 $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.
CREDIT RISK
Gross Receivables - Credit Exposure -- TXU Corp.'s regional gross exposure
to credit risk as of September 30, 2003, is as follows:
Region Credit Exposure
------ ---------------
US............................ $ 2,093
Australia..................... 591
-------
Consolidated.................. $ 2,684
=======
TXU Corp.'s gross exposure to credit risk represents trade accounts
receivable (net of allowance for uncollectible accounts receivable of $83
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.
Concentration of Credit Risk -- The following table presents the
distribution of credit exposure as of September 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.
74
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 $ 829 $ 146 $ 683 $ 481 $ 135 $ 67 $ 683
Noninvestment grade 325 96 229 187 19 23 229
Totals ------ ----- ----- ----- ----- ---- -----
$1,154 $ 242 $ 912 $ 668 $ 154 $ 90 $ 912
====== ===== ===== ===== ===== ==== =====
Investment grade 72% 60% 75%
Noninvestment grade 28% 40% 25%
The exposure to credit risk from these customers and counterparties,
excluding credit collateral, as of September 30, 2003, is $1.2 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 $912
million. Of this amount, approximately 75% 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 $912 million at September 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.
During the third quarter of 2003, and in conjunction with implementation
of a new credit risk management system, TXU Corp. implemented a change in the
method of calculating credit exposure for internal management analysis and
monitoring purposes. The change in methodology now recognizes prompt (next)
month credit exposure on a mark-to-market basis rather than the previous method
using full notional value for credit exposure calculation. Had this methodology
not been used in the third quarter of 2003, the "exposure before credit
collateral" as measured in the table above, would have been approximately 10.8%
greater. There was no impact on actual reported results of operations or
financial position as a result of this change in methodology.
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.
75
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Legal Proceedings -- On October 9, 2003, a lawsuit was filed in the
Supreme Court of the State of New York, County of New York, against TXU Corp.,
by purported beneficial owners of approximately 39% of certain TXU Corp.
equity-linked securities issued in October 2001. The common stock purchase
contract that is a part of these securities requires the holders to purchase TXU
Corp. common stock on specified dates in 2004 and 2005. The plaintiffs seek a
declaratory judgment that (a) a termination event has occurred under the common
stock purchase contract as a result of the administration of TXU Europe and,
therefore, that plaintiffs are not required to purchase TXU Corp. common stock
pursuant to the contract and (b) an event of default has occurred under the
indenture for the senior notes that constitute a part of these equity-linked
securities. Plaintiffs also seek an injunction requiring TXU Corp. to give
notice that a termination event under the common stock purchase contract has
occurred. TXU Corp. disputes plaintiffs' allegations and believes that
plaintiffs' interpretation of the common stock purchase contract and indenture
is inconsistent with the clear language of these agreements and is contrary to
applicable law. Therefore, TXU Corp. believes the claims are completely without
merit and intends to vigorously defend the lawsuit. Discovery has commenced, and
on October 31, 2003, plaintiffs served their first demand for production of
documents. TXU Corp. has not yet responded to the complaint and is unable to
estimate any possible loss or predict the outcome of this action.
Reference is made to the 2002 Form 8-K and the Form 10-Q for the quarterly
periods ended March 31, and June 30, 2003 for additional discussion of legal
proceedings.
76
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits provided as part of Part II are:
Previously Filed*
----------------------------
With
File As
Exhibit Number Exhibit
- ------- ------ -------
4(a) 333-108876 4(a) - Indenture (For Unsecured Debt
Securities), dated as of
March 1, 2003, from TXU
Energy to The Bank of New York, as
trustee (TXU Energy Indenture).
4(b) 333-108876 4(b) - Officer's Certificate, dated
March 11, 2003, to the
TXU Energy Indenture.
4(c) 333-108876 4(c) - Form of TXU Energy 6.125% Exchange
Senior Notes due 2008.
4(d) 333-108876 4(d) - Form of TXU Energy 7.000% Exchange
Senior Notes due 2013.
4(e) 333-108876 4(e) - Registration Rights Agreement,
dated March 11, 2002, between
TXU Energy and Lehman
Brothers Inc., as representative of
the initial purchasers of the Old
Notes.
4(f) 333-106894 4(d) -- Form of Oncor 6.375% Exchange
Senior Secured Notes due 2015.
4(g) 333-106894 4(e) -- Form of Oncor 7.250% Exchange
Senior Secured Notes due 2033.
4(h) 333-106894 4(g) -- Form of Oncor First Mortgage Bond,
6.375% Series due 2015.
4(i) 333-106894 4(h) -- Form of Oncor First Mortgage Bond,
7.250% Series due 2033.
4(j) 333-106894 4(i) -- Registration Rights Agreement,
dated December 20, between Oncor
and the original purchasers of
Oncor's Senior Secured Notes.
4(k) 333-110125 4(f) -- Registration Rights Agreement,
dated as of July 9, 2003,
among TXU Corp. and Credit
Suisse First Boston LLC, as
representatives of the several
other initial purchasers named
therein.
4(l) 333-110125 4(g) -- Indenture (For Unsecured Debt
Securities Series N), dated as of
July 1, 2003, between TXU Corp.
and The Bank of New York,
as trustee.
4(m) 333-110125 4(h) -- Officer's Certificate, dated
July 15, 2003.
4(n) 333-110125 4(i) -- Form of Floating Rate Convertible
Senior Notes due 2003
(incorporated as Exhibit A to
Officer's Certificate, dated July
15, 2003, contained in Exhibit
4(m)).
10(a) -- $500,000,000 Credit Agreement,
dated as of August 8, 2003, among
TXU Corp. and LOC 2003 Trust
(TXU Corp. Agreement).
10(b) -- Letter Amendment, dated
September 19, 2003, to the
TXU Corp. Agreement.
77
10(c) -- $500,000,000 Credit Agreement,
dated as of August 8, 2003, among
LOC 2003 Trust, certain banks
listed therein and Credit Suisse
First Boston, as Administrative
Agent and Collateral Agent.
10(d) -- Amendment, dated as of July 10,
2003 to the $400,000,000 Three-Year
Amended and Restated Revolving
Credit Agreement, dated as of
April 22, 2003, among US Holdings,
TXU Corp., certain banks listed
therein and Citibank, N.A., as
Administrative Agent.
10(e) -- Amendment No. 1, dated August 29,
2003, to the $450,000,000 Revolving
Credit Agreement, dated as of
April 22, 2003, among TXU Energy,
Oncor, certain banks listed therein
and JP Morgan Chase Banks as
Administrative Agent and
Fronting Bank.
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 Condensed Statements of
Consolidated Income - Twelve
Months Ended September 30, 2003.
- -----------
* Incorporated herein by reference.
** 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 furnished or filed since June 30, 2003:
Date of Report Item Reported
-------------- -------------
July 10, 2003 Item 5. Other Events and Regulation
FD Disclosure
Item 7. Financial Statements
and Exhibits
July 25, 2003 Item 5. Other Events and Regulation
FD Disclosure
Item 7. Financial Statements and Exhibits
July 31, 2003 Item 12. Results of Operations and
Financial Condition
Item 7. Financial Statements and Exhibits
July 31, 2003 Item 5. Other Events and Regulation
FD Disclosure
August 27, 2003 Item 5. Other Events and Regulation
FD Disclosure
September 23, 2003 Item 5. Other Events and Regulation
FD Disclosure
Item 7. Financial Statements and Exhibits
October 30, 2003 Item 12. Results of Operations and
Financial Disclosure
November 5, 2003 Item 12. Results of Operations and
Financial Condition
78
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: November 12, 2003
79