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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 1-11668
TXU US Holdings Company
A Texas Corporation I.R.S. Employer Identification
No. 75-1837355
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 ____ No __X__
Common Stock outstanding at November 7, 2003: 2,062,768 Class A shares, without
par value and 39,192,594 Class B 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 and Comprehensive Income -
Three and Nine Months Ended September 30, 2003 and 2002....................... 1
Condensed Statements of Consolidated Cash Flows -
Nine Months Ended September 30, 2003 and 2002................................. 2
Condensed Consolidated Balance Sheets -
September 30, 2003 and December 31, 2002...................................... 3
Notes to Financial Statements................................................. 4
Independent Accountants' Report............................................... 22
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................................... 23
Item 3. Quantitative and Qualitative Disclosures About Market Risk...................... 53
Item 4. Controls and Procedures......................................................... 56
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................................... 56
Item 6. Exhibits and Reports on Form 8-K................................................ 56
SIGNATURE ..................................................................................... 59
Periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K that
contain financial information of TXU US Holdings Company 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 US Holdings Company will provide copies of current
reports not posted on the website upon request.
i
GLOSSARY
When the following terms and abbreviations appear in the text of this report,
they have the meanings indicated below.
1999 Restructuring Legislation........legislation that restructured the
electric utility industry in Texas to
provide for competition
2002 Form 10-K........................TXU US Holdings Company'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 of
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
Moody's...............................Moody's Investors Services, Inc.
NRC...................................United States Nuclear Regulatory
Commission
Oncor.................................Oncor Electric Delivery Company, a
subsidiary of TXU US Holdings
POLR..................................provider of last resort of electricity
to certain customers under the
Commission rules interpreting the 1999
Restructuring Legislation
Price-to-beat rates...................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
REPs..................................retail electric providers
ii
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 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
Extinguishment of Liabilities - a
Replacement of FASB Statement No. 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 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
Liabilities and Equity"
SG&A..................................selling, general and administrative
T&D...................................transmission and distribution
TXU Energy............................TXU Energy Company LLC, a REP subsidiary
of US Holdings
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...........................refers to TXU US Holdings Company or TXU
US Holdings Company and its consolidated
subsidiaries, depending on the context
iii
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(Unaudited)
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2002 2003 2002
----- ---- ----- ----
(millions of dollars)
Operating revenues....................................................... $2,622 $2,536 $6,734 $6,532
Costs and expenses:
Cost of energy sold and delivery fees................................. 1,100 1,095 2,870 2,407
Operating costs....................................................... 345 356 1,072 1,027
Depreciation and amortization......................................... 178 182 523 539
Selling, general and administrative expenses.......................... 216 250 610 783
Franchise and revenue-based taxes..................................... 88 95 268 289
Other income.......................................................... (21) (19) (47) (36)
Other deductions...................................................... 10 3 13 8
Interest income....................................................... (2) - (11) (1)
Interest expense and related charges.................................. 151 104 459 314
------ ------ ------ ------
Total costs and expenses.......................................... 2,065 2,066 5,757 5,330
------ ------ ------ ------
Income before income taxes and cumulative effect of changes in accounting
principles............................................................. 557 470 977 1,202
Income tax expense....................................................... 186 150 316 385
------ ------ ------ ------
Income before cumulative effect of changes in accounting principles...... 371 320 661 817
Cumulative effect of changes in accounting principles, net of tax benefit
(Note 2) ............................................................. - - (58) -
----- ----- ----- -----
Net income .............................................................. 371 320 603 817
Preferred stock dividends................................................ 1 2 5 7
------ ------ ------ ------
Net income available for common stock.................................... $ 370 $ 318 $ 598 $ 810
====== ====== ====== ======
CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(Unaudited)
Three Months Nine Months
Ended Ended
September 30, September 30,
2003 2002 2003 2002
------ ------ ------ -----
(millions of dollars)
Net income............................................................... $ 371 $ 320 $ 603 $ 817
Other comprehensive income (loss), net of tax effects:
Cash flow hedge activity -
Net change in fair value of derivatives (net of tax benefit of $11, (20) (60) (118) (171)
$33,$63 and $92)......................................................
Amounts realized in earnings during the period (net of tax expense
of $24, $7, $63 and $5)........................................... 45 13 117 10
------ ------ ------ ------
Total............................................................... 25 (47) (1) (161)
------ ------ ------ ------
Comprehensive income..................................................... $ 396 $ 273 $ 602 $ 656
====== ====== ====== ======
See Notes to Financial Statements.
1
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
-------------------
2003 2002
---- ----
(millions of dollars)
Cash flows -- operating activities:
Income before cumulative effect of changes in accounting principles....... $ 661 $ 817
Adjustments to reconcile income before cumulative effect of changes in
accounting principles to cash provided by operating activities:
Depreciation and amortization........................................... 577 599
Deferred income taxes and investment tax credits-- net ................. 140 167
Net unrealized (gain) loss from mark-to-market valuation of
commodity contracts................................................... (34) 4
Net gain from sales of assets........................................... (40) (30)
Reduction in regulatory liability....................................... (125) (112)
Retail clawback accrual................................................. (19) -
Changes in operating assets and liabilities............................... 159 (477)
------- -------
Cash provided by operating activities............................... 1,319 968
Cash flows -- financing activities:
Issuances of long-term debt .............................................. 1,900 2,261
Retirements/repurchases of securities:
Long-term debt.......................................................... (899) (2,265)
Preferred stock......................................................... (91) -
Change in advances -- affiliates.......................................... (246) (1,022)
Change in notes payable -- banks.......................................... (1,804) 1,082
Repurchase of common stock................................................ (463) -
Dividends paid to parent.................................................. (250) (677)
Preferred stock dividends paid............................................ (5) (7)
Redemption deposits applied to debt retirements........................... 210 -
Debt premium, discount and reacquisition expenses......................... (58) (49)
------- -------
Cash used in financing activities................................... (1,706) (677)
Cash flows -- investing activities:
Capital expenditures...................................................... (480) (591)
Acquisition of a business................................................. - (36)
Proceeds from sale of assets.............................................. 19 443
Nuclear fuel.............................................................. (45) (51)
Other..................................................................... (12) (66)
------- -------
Cash used in investing activities................................... (518) (301)
------- -------
Net change in cash and cash equivalents...................................... (905) (10)
Cash and cash equivalents-- beginning balance................................ 1,508 55
------- -------
Cash and cash equivalents-- ending balance................................... $ 603 $ 45
======= =======
See Notes to Financial Statements.
2
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2003 2002
------- --------
(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents.................................................. $ 603 $1,508
Restricted cash............................................................ - 210
Accounts receivable -- trade................................................ 988 1,386
Inventories ............................................................... 361 338
Commodity contract assets.................................................. 746 1,298
Other current assets....................................................... 214 213
------- -------
Total current assets................................................ 2,912 4,953
Investments:
Restricted cash............................................................ 75 68
Other investments.......................................................... 525 491
Property, plant and equipment -- net.......................................... 16,624 16,183
Goodwill...................................................................... 558 558
Regulatory assets -- net...................................................... 1,835 1,630
Commodity contract assets..................................................... 222 476
Cash flow hedges and other derivative assets.................................. 66 14
Other noncurrent assets....................................................... 175 146
------- -------
Total assets....................................................... $22,992 $24,519
======= =======
LIABILITIES, PREFERRED INTERESTS AND SHAREHOLDERS' EQUITY
Current liabilities:
Advances from affiliates................................................... $ 291 $ 787
Notes payable -- banks...................................................... - 1,804
Long-term debt due currently............................................... 128 397
Accounts payable -- trade.................................................. 713 820
Commodity contract liabilities............................................. 550 1,138
Accrued taxes.............................................................. 352 303
Other current liabilities.................................................. 637 724
------- -------
Total current liabilities.......................................... 2,671 5,973
Accumulated deferred income taxes............................................. 3,347 3,227
Investment tax credits........................................................ 434 450
Commodity contract liabilities................................................ 149 320
Cash flow hedges and other derivative liabilities............................. 169 150
Other noncurrent liabilities and deferred credits............................. 1,553 1,063
Long-term debt, less amounts due currently.................................... 7,416 6,613
Exchangeable preferred membership interests of TXU Energy, net of $256
discount (Note 1).......................................................... 494 -
------- -------
Total liabilities................................................. 16,233 17,796
Preferred stock subject to mandatory redemption (Note 4)..................... - 21
Contingencies (Note 6)
Shareholders' equity (Note 5):
Preferred stock not subject to mandatory redemption (Note 4)................ 38 115
Common stock without par value (Note 5):
Class A - Authorized shares: September 30, 2003 -- 9,000,000 and December
31, 2003 -- 180,000,00, 0utstanding shares: September 30, 2003 --
2,062,768 and December 31, 2003 -- 52,817,862.......................... 102 2,514
Class B - Authorized shares: September 30, 2003 -- 171,000,000,
0utstanding shares: September 30, 2003 -- 39,192,594.................. 1,949 --
Retained earnings........................................................... 4,859 4,261
Accumulated other comprehensive loss........................................ (189) (188)
------- -------
Total common stock equity................................................ 6,721 6,587
------- -------
Total shareholders' equity............................................. 6,759 6,702
------- -------
Total liabilities, preferred interests and shareholders' equity...... $22,992 $24,519
======= =======
See Notes to Financial Statements.
3
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
(Unaudited)
1. SIGNIFICANT ACCOUNTING POLICIES
Description of Business -- US Holdings is a holding company for TXU Energy
and Oncor. US Holdings is a wholly-owned subsidiary of TXU Corp., a Texas
corporation. US Holdings engages, through TXU Energy, in power production
(electricity generation), wholesale energy sales, retail energy sales and
related services, portfolio management, including risk management and certain
trading activities, as well as, through Oncor, in the transmission and
distribution of electricity. US Holdings' consolidated operations consist of its
TXU Energy and Oncor business segments and the activities of the holding
company, which consists primarily of servicing approximately $160 million in
debt. See discussion of reportable business segments in Note 7.
Basis of Presentation -- The condensed consolidated financial statements
of US Holdings 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 effect of adopting of the following new accounting rules: EITF 02-3,
SFAS 143, SFAS 145 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 10-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 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 and an
increase in net income of $16 million for the nine-month period 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, US Holdings recorded a cumulative effect of changes in
accounting principles as of January 1, 2003. (See Note 2 for a discussion of the
impacts of these two accounting standards.)
As a result of guidance provided in EITF 02-3, US Holdings has not
recognized origination gains on commercial and industrial retail contracts in
2003. For the three- and nine-month periods ended September 30, 2002, US
Holdings 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".
4
As a result of the implementation of SFAS 145 as of January 1, 2003, the
previously reported annual after-tax losses on the early extinguishment of debt
of $97 million in the year ended December 31, 2001 (as described in the Notes to
Financial Statements in the 2002 Form 10-K) will be reclassified from
extraordinary items to other deductions and income tax expense in income from
continuing operations as such losses do not meet the criteria of an
extraordinary item. There was no effect on net income as a result of the
implementation of SFAS 145.
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.
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 6
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. As a result of the implementation of SFAS
150, the September 30, 2003 balance sheet reflects the classification of $7
million of preferred stock subject to mandatory redemption as a liability (see
Note 4). In July 2003, TXU Energy exercised its right to exchange its $750
million 9% Exchangeable Subordinated Notes due 2012 for exchangeable preferred
membership interests with identical economic and other terms (see Note 3).
Because the exchangeability feature of these preferred securities provides for
the holders to exchange the securities with TXU Corp. for TXU Corp. common
stock, the securities are deemed to be mandatorily redeemable by TXU Energy.
Therefore, in accordance with SFAS 150, the September 30, 2003 balance sheet
reflects the classification of these securities (net of $256 million in
unamortized discount) as liabilities.
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.
5
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.
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 US Holdings, 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) US Holdings 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, US Holdings 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 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.
6
3. FINANCING ARRANGEMENTS
At September 30, 2003, US Holdings had outstanding short-term borrowings
consisting of advances from affiliates of $291 million. At December 31, 2002,
outstanding short-term bank borrowings were $1.8 billion and advances from
affiliates were $787 million. Weighted average interest rates on short-term
borrowings were 2.87% and 2.44% at September 30, 2003 and December 31, 2002,
respectively.
Credit Facilities -- At September 30, 2003, credit facilities available to
TXU Corp. and its US subsidiaries were as follows:
At September 30, 2003
--------------------------------------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
- -------- --------------- --------- ----- ------ ---------- ------------
Five-Year Revolving Credit Facility February 2005 US Holdings $ 1,400 $ 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 $ 2,750 $ 270 $ -- $2,480
======= ====== ====== ======
- ------------------------
(a) previously TXU Corp.
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 the $500 million 5-year revolving
credit facility that provides for up to $500 million in letters of credit or up
to $250 million of loans ($500 million in the aggregate).
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.
7
Long-Term Debt -- At September 30, 2003 and December 31, 2002, the
long-term debt of US Holdings 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 (c)........... -- 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 (264)
------- -------
Total TXU Energy ............................................................ $ 3,161 $ 2,451
8
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
Total US Holdings consolidated................................................... 7,544 7,010
Less amount due currently........................................................ 128 397
------- -------
Total long-term debt............................................................. $ 7,416 $ 6,613
======= =======
- -------------------
(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.
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. US
Holdings 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%
9
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 financing order provide for a second issuance of
$800 million expected to be completed in the first quarter of 2004.
In July 2003, TXU Energy exercised its right to exchange its $750 million
9% Exchangeable Subordinated Notes due November 22, 2012 for exchangeable
preferred membership interests with identical economic and other terms. These
securities are convertible into TXU Corp. common stock at an exercise price of
$13.1242. The market price of TXU Corp. common stock on 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 $256 million. (See Note 1
regarding classification of these securities under SFAS 150.)
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.
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.
10
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.
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., including TXU Energy, Oncor and TXU Gas
(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,
11
a direct subsidiary of TXU Corp., as well as program fees paid by TXU
Receivables Company to the financial institutions. The servicing fee
compensates TXU Business Services Company for its services as collection agent,
including maintaining the detailed accounts receivable collection records. TXU
Business Services Company charges the affiliated businesses for its servicing
costs, net of the servicing fee income. The program fees paid to financial
institutions, which consist primarily of interest costs on the underlying
financing, were $8 million and $10 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 fee
amounts represent the net incremental costs of the program to US Holdings and
are reported in SG&A expenses.
The September 30, 2003 balance sheet reflects funding under the program of
$667 million, through sale of undivided interests in receivables by TXU
Receivables Company, related to $1.4 billion face amount of US Holdings
trade accounts receivable. Funding under the program increased $220 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 $141 million. Funding increases or decreases under the program are
reflected as cash provided by or used in operating activities in the statement
of cash flows.
Upon termination of the program, cash flows to US Holdings 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. The trade accounts receivable balances on US Holdings' balance sheets
represent the face amount of its receivables less the funding under the program
and allowances for uncollectible accounts.
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.
12
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 US Holdings
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,
US Holdings and its subsidiaries were in compliance with all such applicable
covenants.
Certain financing and other arrangements of US Holdings 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 US Holdings, 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 US
Holdings or its subsidiaries.
Cross Default Provisions
------------------------
Certain financing arrangements of US Holdings 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 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
13
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.
US Holdings 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.
4. PREFERRED STOCK
September 30, December 31,
2003 2002
------------ -----------
Not Subject to Mandatory Redemption:
- ------------------------------------
$4.00 to $5.08 dividend rate series....... $38 $ 38
$7.98 series.............................. -- 26
$7.50 series ............................. -- 30
$7.22 series ............................. -- 21
--- ----
Total.................................. $38 $115
=== ====
Subject to Mandatory Redemption:
- --------------------------------
$6.98 series.............................. $-- $ 11
$6.375 series............................. 7 10
--- ----
Total.................................. $ 7 $ 21
=== ====
As a result of the adoption of SFAS 150 on July 1, 2003 (see Note 1), US
Holdings' preferred stock subject to mandatory redemption of $7 million has been
classified in the balance sheet at September 30, 2003 in liabilities (other
current liabilities). The preferred stock not subject to mandatory redemption
remains classified in shareholders' equity.
In September 2003, US Holdings called its mandatorily redeemable preferred
stock for redemption, and on October 1, 2003, those shares were redeemed for an
aggregate principal amount of $7 million.
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 amount of $91 million.
5. SHAREHOLDERS' EQUITY
In August 2003, the Articles of Incorporation of TXU Holdings were amended
to create two new classes of common stock: Class A common stock with voting
rights and Class B common stock without voting rights. All the shares of Class A
common stock and 5% of the shares of Class B common stock are held by TXU Corp.,
and 95% of the shares of Class B common stock are held by TXU Investments LLC, a
wholly-owned, direct subsidiary of TXU Corp.
On July 1, 2003, US Holdings repurchased 5,312,500 shares of its common
stock for $212.5 million and on April 1, 2003, US Holdings repurchased 6,250,000
shares of its common stock for $250 million. On November 15, 2002, US Holdings
declared a cash dividend of $250 million, which was paid to TXU Corp. on January
2, 2003.
14
The legal form of cash distributions to TXU Corp. has been both common
stock repurchases and the payment of dividends. For accounting purposes, the
cash distributions in the form of share repurchases are recorded as a return of
capital.
Certain debt instruments and preferred securities of US Holdings 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, US Holdings was in compliance with
these provisions.
6. CONTINGENCIES
Guarantees -- US Holdings 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.
Residual value guarantees in operating leases -- US Holdings 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 $272 million with an estimated residual recovery of approximately
$204 million. The average life of the lease portfolio is approximately six
years.
Shared saving guarantees -- US Holdings 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 -- US Holdings 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, US Holdings 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.
US Holdings 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.
Surety bonds -- US Holdings has outstanding surety bonds of approximately
$57 million to support performance under various contracts in the normal course
of business. The term of the surety bond obligations is approximately two
years.
Other -- US Holdings 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%. US Holdings is required to
make periodic payments equal to such principal and interest, including amounts
assumed by a third party and reimbursed to US Holdings. In addition, US Holdings
is obligated to pay certain variable costs of operating and maintaining the
reservoirs. US Holdings 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 US Holdings. US Holdings is, however, contingently liable in
the event of default by the municipality.
15
Legal Proceedings -- 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. US Holdings 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, US Holdings believes that TCE's claims against TXU Energy
and its subsidiary companies are without merit and intends to vigorously defend
the lawsuit. US Holdings 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 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. US Holdings believes that the plaintiff lacks standing to
assert any antitrust claims against US Holdings or TXU Portfolio Management, and
that defendants have not violated antitrust laws or other laws as claimed by the
plaintiff. Therefore, US Holdings believes that plaintiff's claims are without
merit and plans to vigorously defend the lawsuit. US Holdings is unable to
estimate any possible loss or predict the outcome of this action.
Open-Access Transmission -- At the state level, the Texas Public Utility
Regulatory Act, as amended, requires owners or operators of transmission
facilities to provide open access wholesale transmission services to third
parties at rates and terms that are non-discriminatory and comparable to the
rates and terms of the utility's own use of its system. The Commission has
adopted rules implementing the state open access requirements for utilities that
are subject to the Commission's jurisdiction over transmission services, such as
Oncor.
On January 3, 2002, the Supreme Court of Texas issued a mandate affirming
the judgment of the Court of Appeals that held that the pricing provisions of
16
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 US Holdings' financial position
or results of operation, and requires that these suits be dismissed with
prejudice.
General -- US Holdings is involved in various other legal and
administrative proceedings, the ultimate resolution of which should not have a
material effect upon its financial position, results of operations or cash
flows.
7. SEGMENT INFORMATION
US Holdings has two reportable business segments: TXU Energy and Oncor.
TXU Energy (formerly Energy segment) - consists of operations, 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.
Oncor (formerly Electric Delivery segment) - consists of regulated
operations in Texas involving the transmission and distribution of electricity.
Effective with reporting for 2003, results for the TXU 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.
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2003 2002 2003 2002
------- ------- ------- -------
Operating revenues:
TXU Energy.......................................... $ 2,453 $ 2,420 $ 6,304 $ 6,238
Oncor............................................... 613 557 1,605 1,551
Eliminations........................................ (444) (441) (1,175) (1,257)
------- ------- ------- -------
Consolidated.................................. $ 2,622 $ 2,536 $ 6,734 $ 6,532
======= ======= ======= =======
Regulated revenues included in operating revenues:
TXU Energy.......................................... $ -- $ -- $ -- $ --
Oncor............................................... 613 557 1,605 1,551
Eliminations........................................ (440) (438) (1,166) (1,251)
------- ------- ------- -------
Consolidated.................................. $ 173 $ 119 $ 439 $ 300
======= ======= ======= =======
Affiliated revenues included in operating revenues:
TXU Energy.......................................... $ 4 $ 3 $ 9 $ 6
Oncor............................................... 440 438 1,166 1,251
Eliminations........................................ (444) (441) (1,175) (1,257)
------- ------- ------- -------
Consolidated.................................. $ -- $ -- $ -- $ --
======= ======= ======= =======
Income before cumulative effect of changes in
accounting principles:
TXU Energy.......................................... $ 249 $ 227 $ 438 $ 597
Oncor............................................... 126 96 239 232
Other............................................... (4) (3) (16) (12)
------- ------- ------- -------
Consolidated.................................. $ 371 $ 320 $ 661 $ 817
======= ======= ======= =======
17
8. SUPPLEMENTARY FINANCIAL INFORMATION
Regulated Versus Unregulated Operations --
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
2003 2002 2003 2002
------- ------- ------- -------
Operating revenues:
Regulated........................................... $ 613 $ 557 $ 1,605 $ 1,551
Unregulated......................................... 2,453 2,420 6,304 6,238
Intercompany sales eliminations - regulated......... (440) (438) (1,166) (1,251)
Intercompany sales eliminations - unregulated....... (4) (3) (9) (6)
------- ------- ------- -------
Total operating revenues....................... 2,622 2,536 6,734 6,532
Costs and operating expenses:
Cost of energy sold and delivery fees
- unregulated*.................................... 1,100 1,095 2,870 2,407
Operating costs - regulated......................... 175 174 524 493
Operating costs - unregulated....................... 170 182 548 534
Depreciation and amortization - regulated........... 78 66 215 197
Depreciation and amortization - unregulated......... 100 116 308 342
Selling, general and administrative expenses
- regulated....................................... 47 50 144 160
Selling, general and administrative expenses
- unregulated..................................... 169 200 466 623
Franchise and revenue-based taxes - regulated....... 63 67 183 195
Franchise and revenue-based taxes - unregulated..... 25 28 85 94
Other income........................................ (21) (19) (47) (36)
Other deductions.................................... 10 3 13 8
Interest income..................................... (2) - (11) (1)
Interest expense and related charges................ 151 104 459 314
------- ------- ------- -------
Total costs and expenses....................... 2,065 2,066 5,757 5,330
------- ------- ------- -------
Income before income taxes and cumulative effect of
changes in accounting principles.................... $ 557 $ 470 $ 977 $ 1,202
======= ======= ======= =======
- --------------------------
* Includes cost of fuel consumed of $402 million and $419 million for the
three months ended September 30, 2003 and 2002, and $1,238 million and
$1,036 million for the nine months ended September 30, 2003 and 2002,
respectively. The balance represents energy purchased for resale and
delivery fees.
The operations of the TXU 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 properties and businesses........... $ 19 $ 18 $ 40 $ 30
Lignite coal royalties.................................. - - - 2
Equity portion of allowance for funds used during
construction .......................................... 1 1 3 3
Other................................................... 1 - 4 1
------ ------ ------ ------
Total other income.................................. $ 21 $ 19 $ 47 $ 36
====== ====== ====== ======
Other deductions:
Equity in losses of unconsolidated subsidiaries......... $ - $ 1 $ - $ 2
Loss on retirement of debt.............................. 1 - 1 1
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) - - -
------ ------ ------ ------
Total other deductions.............................. $ 10 $ 3 $ 13 $ 8
====== ====== ====== ======
18
Interest Expense and Related charges --
Three Months Ended Nine Months Ended
September 30, September 30,
2003 2002 2003 2002
------- ------- ------- -------
Interest...................................................... $ 146 $ 104 $ 444 $ 312
Amortization of deferred debt costs........................... 8 3 23 11
Allowance for borrowed funds used during construction
and capitalized interest.................................. (3) (3) (8) (9)
----- ----- ----- -----
Total interest expense and related charges..... $ 151 $ 104 $ 459 $ 314
===== ===== ===== =====
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........................................ 97 46
------ ------
Total regulatory assets.................................... 1,965 1,898
Regulatory Liabilities:
Liability related to excess mitigation credit.................. 39 170
Investment tax credit and protected excess deferred taxes...... 91 98
------ ------
Total regulatory liabilities............................... 130 268
------ ------
Net regulatory assets...................................... $1,835 $ 1,630
====== ======
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
securitization 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 -- 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 March and April 2003. The remaining restricted cash
reported in investments on the balance sheet as of September 30, 2003, included
$69 million held as collateral for outstanding letters of credit and $6 million
held by the trustee in connection with the transition bonds issued by Oncor in
August 2003.
Accounts Receivable -- At September 30, 2003 and December 31, 2002,
accounts receivable of $1.0 billion and $1.4 billion are stated net of allowance
for uncollectible accounts of $74 million and $72 million, respectively. During
the nine months ended September 30, 2003, bad debt expense was $71 million,
account write-offs were $65 million and other activity decreased the allowance
for uncollectible accounts by $4 million.
Accounts receivable included $449 million and $505 million of unbilled
revenues at September 30, 2003 and December 31, 2002, respectively.
19
Intangible Assets -- SFAS 142 became effective for US Holdings 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.............. $ 391 $171 $ 220 $368 $131 $237
Land easements.................... 176 66 110 180 61 119
Mineral rights and other.......... 31 21 10 31 20 11
----- ---- ----- ---- ---- ----
Total....................... $ 598 $258 $ 340 $579 $212 $367
===== ==== ===== ==== ==== ====
Amortization expense for intangible assets was $46 million and $45 million
for the nine months ended September 30, 2003 and 2002, respectively. At
September 30, 2003, the remaining average useful lives of capitalized software,
land easements and mineral rights noted above were 6 years, 69 years and 40
years, respectively.
At September 30, 2003 and December 31, 2002, goodwill of $558 million was
stated net of previously recorded accumulated amortization of $67 million.
Commodity Contracts -- At September 30, 2003 and December 31, 2002,
current and noncurrent commodity contract assets totaling $968 million and $1.8
billion, respectively, are stated net of applicable credit (collection) and
performance reserves totaling $21 million and $43 million, respectively.
Performance reserves are provided for direct, incremental costs to settle the
contracts.
Inventories by Major Category --
September 30, December 31,
2003 2002
---- ----
Materials and supplies...................................................... $ 223 $211
Fuel stock.................................................................. 75 70
Gas stored underground...................................................... 63 57
----- ----
Total inventories....................................................... $ 361 $338
===== ====
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 $16.6 billion and $16.2 billion is stated
net of accumulated depreciation and amortization of $10.7 billion and $10.4
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 -- US Holdings experienced net hedge
ineffectiveness of $10 million and $24 million, reported as a gain in revenues,
for the three and nine months ended September 30, 2003, respectively. For the
three and nine months ended September 30, 2002, net hedge ineffectiveness of $7
million and $40 million, respectively, was reported as a loss in revenues. Hedge
ineffectiveness is primarily related to hedges of anticipated sales from
baseload generation.
20
As of September 30, 2003, it is expected that $71 million of after-tax net
losses accumulated in other comprehensive income, primarily related to
commodities hedges, will be reclassified into earnings during the next twelve
months. 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.
Affiliate Transactions -- The following represent significant affiliate
transactions of US Holdings:
Average daily short-term advances from affiliates during the three months
ended September 30, 2003 and 2002 were $702 million and $575 million,
respectively, and interest expense incurred on the advances was $4 million and
$3 million, respectively. Average daily short-term advances from affiliates
during the nine months ended September 30, 2003 and 2002 were $845 million and
$1.1 billion, respectively, and interest expense incurred on the advances was
$17 million and $23 million, respectively. The average interest rates for the
three months ended September 30, 2003 and 2002 were 2.86% and 2.11%,
respectively. The average interest rates for the nine months ended September 30,
2003 and 2002 were 2.76% and 2.43%, respectively.
TXU Business Services Company, a subsidiary of TXU Corp., charges US
Holdings for certain financial, accounting, information technology,
environmental, procurement and personnel services and other administrative
services at cost. For the three months ended September 30, 2003 and 2002, these
costs totaled $79 million and $105 million, respectively, and for the nine
months ended September 30, 2003 and 2002 totaled $254 million and $319 million,
respectively. These costs are reported in SG&A expenses.
US Holdings charges TXU Gas for customer and administrative services at
cost. For the three months ended September 30, 2003 and 2002, these charges
totaled $14 million and $16 million, respectively, and for the nine months ended
September 30, 2003 and 2002 totaled $43 million and $45 million, respectively.
These charges are largely reported as a reduction in SG&A expenses.
Supplemental Cash Flow Information -- See Note 2 for the effects of
adopting SFAS 143, which were noncash in nature. See Note 3 for discussion of
the exchange of TXU Energy subordinated notes for preferred membership
interests, which was a noncash transaction.
21
INDEPENDENT ACCOUNTANTS' REPORT
TXU US Holdings Company:
We have reviewed the accompanying condensed consolidated balance sheet of TXU US
Holdings Company and subsidiaries (US Holdings) 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 US Holdings' 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 US
Holdings 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 an
explanatory paragraph related to the adoption of Statement of Financial
Accounting Standards No. 142), dated February 14, 2003 (and March 19, 2003 as to
Note 18 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, US Holdings changed
its method of accounting for asset retirement obligations in 2003 in connection
with the adoption of Statement of Financial Accounting Standards No. 143, "Asset
Retirement Obligations," changed its method of accounting for certain contracts
with the rescission of Emerging Issues Task Force Issue 98-10 "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities," and
changed its method of classifying mandatorily redeemable preferred securities in
connection with the adoption of Statement of Financial Accounting Standards No.
150, "Accounting for Certain Financial Instruments with Characteristics of Both
Liabilities and Equity."
DELOITTE & TOUCHE LLP
Dallas, Texas
November 11, 2003
22
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
BUSINESS
Description of Business -- US Holdings is a holding company for TXU Energy
and Oncor. US Holdings is a wholly-owned subsidiary of TXU Corp., a Texas
corporation. US Holdings engages, through TXU Energy, in power production
(electricity generation), wholesale energy sales, retail energy sales and
related services, portfolio management, including risk management and certain
trading activities, as well as, through Oncor, in the transmission and
distribution of electricity. US Holdings' consolidated operations consist of its
TXU Energy and Oncor business segments and the activities of the holding
company, which consists primarily of servicing approximately $160 million in
debt. See discussion of reportable business segments in Note 7.
Dollar amounts in the following tables are stated in millions of US
dollars, unless otherwise noted.
RESULTS OF OPERATIONS
Consolidated US Holdings
- ------------------------
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.
US Holdings' operating revenues increased $86 million, or 3%, to $2.6
billion in 2003. The revenue growth reflected an increase in the Oncor segment
of $56 million, or 10%, to $613 million and an increase in the TXU Energy
segment of $33 million, or 1%, to $2.5 billion. The growth in revenues in the
Oncor segment reflected higher tariffs, volume growth and higher
disconnect/reconnect fees. Revenue performance in the TXU Energy segment
reflected higher average pricing that was largely offset by the effect of lower
retail sales volumes and lower results from portfolio management activities.
Gross Margin
Three Months Ended
September 30,
-----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 2,622 100% $ 2,536 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 1,100 42% 1,095 43%
Operating costs................................... 345 13% 356 14%
Depreciation and amortization related to operating
assets........................................ 165 6% 170 7%
------- ----- ------- ------
Gross margin........................................... $ 1,012 39% $ 915 36%
======= ===== ======= ======
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 $13 million and $12 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 $97 million, or 11%, to $1.0 billion in 2003. This
increase reflected growth in the TXU Energy segment of $55 million, or 9%, to
$649 million and an increase in the Oncor segment of $43 million, or 13% to $363
23
million. The increase in the TXU Energy segment reflected higher average
pricing, partially offset by higher average costs of energy sold, the lower
portfolio management results and the effect of sales volumes declines. Increased
costs of energy sold reflected higher natural gas prices. Mark-to-market
accounting for commodity contracts increased revenues and gross margin by $1
million in 2003 (as compared to accounting on a settlement basis), and increased
results by $8 million in 2002. The increase in the Oncor segment reflected
higher revenues, partially offset by higher depreciation and amortization.
A decrease in depreciation and amortization (including amounts shown in
the gross margin table above) of $4 million, or 2%, to $178 million reflected a
decrease of $16 million primarily from adjusted depreciation rates related to
TXU Energy's generation fleet, effective with second quarter reporting,
partially offset by a $12 million increase, primarily reflecting Oncor's
amortization of regulatory assets commencing with the issuance of securitization
bonds in August 2003. The effect on Oncor's revenues of the higher distribution
rates associated with the issuance of securitization bonds is offset by the
amortization expense.
SG&A expense decreased $34 million, or 14%, to $216 million in 2003. The
decrease was driven by the TXU Energy segment and reflected nonrecurring costs
incurred in 2002 related to the transition to competition and the effects of
cost reduction initiatives.
Franchise and revenue-based taxes decreased $7 million, or 7%, to $88
million due primarily to lower retail revenues on which gross receipts taxes are
based.
Other income increased $2 million to $21 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 $7 million to $10 million in 2003. The 2003
amount included charges related to the scaling-back of the strategic retail
services business of $5 million and premiums paid on the redemption of preferred
stock of $3 million.
Interest income of $2 million in 2003 reflected higher cash balances on
hand as credit facilities were drawn down in the fourth quarter of 2002 to
enhance liquidity.
Interest expense and related charges increased $47 million, or 45%, to
$151 million in 2003. The increase was driven by higher average interest rates
resulting in part from the refinancing of short-term borrowings with higher-rate
long-term debt.
The effective income tax rate was 33.4% in 2003 compared to 31.9% 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
estimated tax provision.
Net income increased $51 million, or 16%, to $371 million in 2003. This
performance reflected an increase of $30 million, or 31%, to $126 million in the
Oncor segment reflecting the increased revenues, partially offset by higher
depreciation and amortization and increased interest expense. Net income in the
TXU Energy segment rose $22 million, or 10%, to $249 million due to higher gross
margin and decreased SG&A expenses, partially offset by higher interest expense.
Net pension and postretirement benefit costs, reported in operating costs and
SG&A expenses, reduced net income by $14 million in 2003 and $6 million in 2002.
Consolidated US Holdings
- ------------------------
Nine Months Ended September 30, 2003 Compared to Nine 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.
US Holdings' operating revenues increased $202 million, or 3%, to $6.7
billion in 2003. The revenue growth reflected an increase in the TXU Energy
24
segment of $66 million, or 1%, to $6.3 billion and an increase in the Oncor
segment of $54 million, or 3%, to $1.6 billion. Revenues in the TXU Energy
segment reflected higher average pricing largely offset by the effect of lower
sales volumes. The growth in revenues in the Oncor segment reflected higher
tariffs and higher disconnect/reconnect fees. Consolidated revenue growth also
reflected an $82 million reduction in the intercompany sales elimination,
reflecting lower sales by Oncor to TXU Energy as sales to non-affiliated REPs
increased.
Gross Margin
Nine Months Ended
September 30,
----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- -------- ---- --------
Operating revenues..................................... $ 6,734 100% $ 6,532 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 2,870 43% 2,407 37%
Operating costs................................... 1,072 16% 1,027 16%
Depreciation and amortization related to operating
assets........................................ 485 7% 499 7%
------- ----- ------- ------
Gross margin........................................... $ 2,307 34% $ 2,599 40%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $38 million and $40 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.
Gross margin decreased $292 million, or 11%, to $2.3 billion in 2003. This
decrease reflected a decline in the TXU Energy segment of $298 million, or 17%,
to $1.4 billion and an increase in the Oncor segment of $6 million, or 1%, to
$875 million. The decline in the TXU Energy segment reflected higher average
energy costs and lower retail sales volumes, partially offset by higher average
sales prices. The gross margin increase in the Oncor segment was driven by the
higher revenues.
Depreciation and amortization (including amounts shown in the gross margin
table above) decreased $16 million, or 3%, to $523 million reflecting a decrease
of $25 million due to adjusted depreciation rates related to TXU Energy's
generation fleet, as discussed above, partially offset by $8 million of
amortization of regulatory assets commencing with the issuance of the
securitization bonds in August 2003. The effect on revenues of the higher
distribution rates associated with the issuance of the securitization bonds is
offset by the amortization expense.
SG&A expense decreased $173 million, or 22%, to $610 million in 2003. The
decrease was driven by the TXU Energy segment and reflected cost reductions,
primarily lower staffing and related administrative expenses, as well as lower
levels of bad debt expense reflecting billing and collection delays experienced
in 2002 in connection with the transition to competition and initiatives
implemented in 2003 to reduce such expenses.
Franchise and revenue-based taxes decreased $21 million, or 7%, to $268
million due primarily to lower retail revenues on which gross receipts taxes are
based.
Other income increased $11 million to $47 million in 2003. Other income in
both periods included $30 million of amortization of a gain on the 2002 sale of
two generation plants. The 2003 period also included a $9 million gain on the
sale of certain retail commercial and industrial gas operations.
Other deductions increased $5 million to $13 million in 2003. The 2003
amount included $5 million in charges related to the scaling-back of the
strategic retail services business. Amounts in both periods included storage and
other incidental expenses related to two canceled generation plant construction
projects.
Interest income increased $10 million to $11 million in 2003, primarily
reflecting higher cash balances on hand as credit facilities were drawn down in
the fourth quarter of 2002 and remained outstanding through April 2003 to
enhance liquidity.
25
Interest expense and related charges increased $145 million, or 46%, to
$459 million in 2003. The increase reflected higher average interest rates and
higher average debt levels. Higher average rates were due in part to replacement
of short-term borrowings with higher rate long-term debt.
The effective tax rate of 32.3% in 2003 was comparable to the 32.0% 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
declined $156 million, or 19%, to $661 million in 2003. Net income in the TXU
Energy segment declined $159 million, or 27%, to $438 million reflecting the
lower gross margin and higher interest expense, partially offset by the lower
SG&A and depreciation and amortization expenses. Net income in the Oncor segment
rose $7 million, or 3%, to $239 million reflecting higher revenues, partially
offset by higher interest and operating expenses. Net pension and postretirement
benefit costs, reported in operating costs and SG&A expenses, reduced net income
by $41 million in 2003 and $23 million in 2002.
The cumulative effect of changes in accounting principles, representing an
after-tax charge of $58 million, reflects the rescission of EITF 98-10 and the
adoption of SFAS 143. See Note 2 to Financial Statements for further discussion.
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 $34 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......... $ 316
Cumulative effect of change in accounting principle (1) .............. (75)
Settlements of positions included in the opening balance (2) ......... (99)
Unrealized mark-to-market valuations of positions held at end
of period (3)....................................................... 133
Other activity (4).................................................... (6)
-----
Balance of net commodity contract assets at September 30, 2003 ....... $ 269
=====
- ----------------------
(1) Represents a portion of the pre-tax cumulative effect of the rescission of
EITF 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 the initial values of positions involving the receipt or
payment of cash, such as option premiums, the amortization of such
values and the sale of certain retail commercial and industrial
gas operations. These activities have no effect on unrealized
mark-to-market valuations.
As a result of guidance provided in EITF 02-3, US Holdings has not
recognized origination gains on commercial/industrial retail contracts in 2003.
(See Note 2 to Financial Statements.)
26
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 $291 million.
The offsetting net liability of $22 million included in the September 30, 2003
balance consists of unamortized net option premiums received. 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 Maturity in
less 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............. 204 60 3 (1) 266
Prices based on models........... (6) 10 4 - 8
----- ---- --- ---- -----
Total............................ $205 $ 80 $ 7 $ (1) $ 291
==== ==== === ===== =====
Percentage of total fair value... 70% 28% 2% 0% 100%
As the above table indicates, approximately 98% 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. 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. 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.
27
SEGMENTS
TXU 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
======= ======= ======= =======
28
TXU 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).
29
TXU 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).
30
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.
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.
TXU 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%
31
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.
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.
32
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.
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.
Oncor
- -----
Financial Results
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- --------------------
2003 2002 2003 2002
----- ----- ----- -----
Operating revenues....................................... $613 $557 $1,605 $1,551
Costs and expenses:
Operating costs..................................... 175 174 524 493
Depreciation and amortization....................... 78 66 215 197
Selling, general and administrative expenses........ 47 50 144 160
Franchise and revenue-based taxes................... 63 67 183 195
Other income........................................ (2) (1) (6) (3)
Interest income..................................... (14) (11) (43) (34)
Interest expense and related charges................ 75 66 230 193
---- ---- ------ ------
Total cost and expenses ........................ 422 411 1,247 1,201
---- ---- ------ ------
Income before income taxes............................... 191 146 358 350
Income tax expense....................................... 65 50 119 118
---- ---- ------ ------
Net Income............................................... $126 $ 96 $ 239 $ 232
==== ==== ====== ======
33
Segment Highlights
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
2003 2002 2003 2002
---- ---- ---- ----
Operating statistics:
Electric energy delivered (GWh) (a)............................. 31,881 30,040 80,167 79,858
Electric points of delivery (end of period and in thousands).... 2,920 2,902
Operating revenues (millions of dollars):
TXU Energy.................................................. $ 441 $ 438 $1,167 $1,252
Non-affiliated.............................................. 172 119 438 299
------ ----- ----- ------
Total electric energy delivery...................... $ 613 $ 557 $1,605 $1,551
====== ===== ====== ======
- ---------------------
(a) 2002 data revised.
Oncor
- -----
Three Months Ended September 30, 2003 Compared to Three Months Ended
September 30, 2002
- --------------------------------------------------------------------
Oncor's operating revenues increased $56 million, or 10%, to $613 million
in 2003. 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.
Gross Margin
Three Months Ended
September 30,
---------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- -------- ---- -------
Operating revenues..................................... $ 613 100% $ 557 100%
Costs and expenses:
Operating costs................................... 175 29% 174 31%
Depreciation and amortization related to transmission
and distribution assets....................... 75 12% 63 11%
------- ----- ------- ------
Gross margin........................................... $ 363 59% $ 320 58%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $3 million of such expense for the three months ended September 30,
2003 and 2002 that is not directly related to delivery property, plant and
equipment.
Gross margin increased $43 million, or 13%, to $363 million in 2003,
driven by higher revenues of $56 million, partially offset by higher
depreciation of $12 million. The increase in depreciation of $12 million, or
19%, to $75 million reflects $3 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 commencing with
the issuance of securitization bonds in August 2003. The effect on revenues of
the higher distribution rates associated with the issuance of the securitization
bonds is offset by the related amortization expense. Operating costs were about
even with the prior year reflecting an increase in third-party transmission
costs of $8 million, largely offset by lower vegetation management and overhead
distribution lines maintenance costs of $5 million.
34
SG&A expenses decreased $3 million, or 6%, to $47 million due primarily to
a $6 million decrease in outside services and consulting expenses arising from
cost saving initiatives implemented in late 2002 and the completion of
competitive market transition activities and a $3 million decrease in bad debt
expense, partially offset by a $5 million increase in employee benefit costs.
Franchise and revenue-based taxes declined $4 million, or 6%, to $63
million in 2003 due primarily to lower revenues on which gross receipts taxes
are based.
Interest income increased $3 million in 2003 reflecting a $6 million
increase in reimbursements from TXU Energy for higher carrying costs on
regulatory assets (see discussion of higher average interest rates below),
partially offset by $4 million in lower interest from TXU Energy on the excess
mitigation credit note receivable due to principal payments (see discussion
under "Regulation and Rates").
Interest expense and related charges increased by $9 million, or 14%, to
$75 million in 2003. The increase reflects $12 million due to higher average
interest rates on borrowings, partially offset by $4 million due to lower
interest credited to customers related to the excess mitigation credits. 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 slightly to 34.0% in 2003 from
34.2% in 2002.
Net income increased $30 million, or 31%, to $126 million in 2003,
primarily due to the higher gross margin. Net pension and postretirement benefit
costs reduced net income by $5 million in 2003 and $2 million in 2002.
Oncor
- -----
Nine Months Ended September 30, 2003 Compared to Nine Months Ended
September 30, 2002
- ------------------------------------------------------------------
Oncor's operating revenues increased $54 million, or 3%, to $1.6 billion
in 2003. 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 transition (securitization) bonds
in August 2003 ($8 million). (See discussion under "Regulation and Rates.") The
revenue growth also reflected $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..................................... $ 1,605 100% $ 1,551 100%
Costs and expenses:
Operating costs................................... 524 33% 493 32%
Depreciation and amortization related to transmission
and distribution assets....................... 206 13% 189 12%
------- ----- ------- ------
Gross margin........................................... $ 875 54% $ 869 56%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $9 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.
35
Gross margin increased $6 million, or 1%, to $875 million in 2003, driven
by higher revenue of $54 million, partially offset by higher operating costs of
$31 million and depreciation and amortization of $17 million. The increase in
operating costs of $31 million, or 6%, to $524 million reflects $24 million in
higher transmission costs paid to other utilities and $7 million in higher
pension and other postretirement benefit costs. The increase in depreciation and
amortization of $17 million, or 9%, to $206 million reflects $9 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 commencing with the issuance of transition (securitization)
bonds in August 2003. The effect on revenues of the higher distribution rates
associated with the issuance of the securitization bonds is offset by the
amortization expense.
SG&A expenses decreased $16 million, or 10%, to $144 million due primarily
to $19 million lower outside services and consulting expenses arising from cost
saving initiatives implemented in late 2002, partially offset by $2 million
higher pension and other postretirement benefit costs.
Franchise and revenue-based taxes declined $12 million, or 6%, to $183
million in 2003 due primarily to lower revenues on which gross receipts taxes
are based.
Interest income increased $9 million in 2003 reflecting a $19 million
increase in the reimbursement from the TXU Energy segment for higher carrying
costs on regulatory assets (see discussion of higher average interest rates
below), partially offset by $12 million less interest on the excess mitigation
credit note receivable due to principal payments (see discussion under
"Regulation and Rates").
Interest expense and related charges increased by $37 million, or 19%, to
$230 million in 2003. Of the change, $36 million was due to higher average
interest rates on borrowings and $12 million was due to higher average
borrowings, 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 with higher rate long-term
debt issuances.
The effective income tax rate decreased a half of a point to 33.2% in 2003
from 33.7% in 2002, due to a lower state income tax provision.
Net income increased $7 million, or 3%, to $239 million in 2003,
reflecting higher gross margin and lower SG&A and gross receipts tax expenses,
partially offset by higher net interest expense. Net pension and postretirement
benefit costs reduced net income by $14 million in 2003 and $8 million in 2002.
COMPREHENSIVE INCOME
The after-tax effects of cash flow hedges reported in other comprehensive
income were as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- -------------------
2003 2002 2003 2002
-------- -------- ------- -------
Net change in fair value of hedges - gains/(losses):
Commodities........................................ $ (20) $ (5) $ (118) $ (63)
Financing - interest rate swaps.................... - (55) - (108)
-------- -------- -------- --------
(20) (60) (118) (171)
Losses realized in earnings:
Commodities........................................ 43 12 112 9
Financing - interest rate swaps.................... 2 1 5 1
-------- -------- -------- --------
45 13 117 10
-------- -------- -------- --------
Net effect.............................. $ 25 $ (47) $ (1) $ (161)
======== ======== ======== ========
Gains and losses on cash flow hedges are realized in earnings as the
underlying hedged transactions are settled.
36
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 the 2002 Form 10-K. No significant changes or events that might
affect the financial condition of US Holdings have occurred subsequent to
year-end other than as disclosed herein.
Cash Flows -- Cash flows provided by operating activities for the first
nine months of 2003 were $1.3 billion compared to $968 million for 2002. The
increase in cash flows provided by operating activities in 2003 of $351 million,
or 36%, reflected favorable working capital changes (accounts receivable,
accounts payable and inventories) of $801 million, including $79 million in
increased funding under the account receivable sales program, partially offset
by lower cash earnings of $285 million (net income adjusted for the significant
noncash items identified in the statement of cash flows) and
payments of $102 million related to counterparty default events and the
termination and liquidation of those outstanding positions. The net working
capital improvement reflected the effect of billing and collection delays in
2002 associated with the transition to competition.
Cash flows used in financing activities in 2003 were $1.7 billion compared
to $677 million in 2002. Net cash used in issuances and retirements of
borrowings totaled $897 million in 2003 compared to net cash provided of $7
million in 2002. US Holdings repurchased $91 million of preferred stock in
2003. Dividends paid to TXU Corp.and common stock repurchased from TXU Corp.
totaled $713 million in 2003 and $677 million in 2002.
Cash flows used in investing activities were $518 million in 2003 compared
to $301 million in 2002. Capital expenditures declined to $480 million in 2003
from $591 million in 2002, driven by lower developmental spending by TXU Energy.
Purchases of nuclear fuel were $45 million in 2003 compared to $51 million in
2002. Proceeds from the sale of certain retail commercial and industrial gas
operations provided $19 million in 2003, compared to $443 million from sales in
2002 including two generation plants in Texas.
Depreciation and amortization expense reported in the statement of cash
flows exceeds the amount reported in the statement of income by $54 million.
This difference represents amortization of nuclear fuel, which is reported as
cost of energy sold in the statement of income consistent with industry
practice, and amortization of regulatory assets, which is reported as operating
costs in the statement of income.
Financing Activities
Capitalization -- The capitalization ratios of US Holdings at September
30, 2003, consisted of 50.5% long-term debt, less amounts due currently ($7.4
billion), -% preferred stock subject to mandatory redemption ($7 million), 3.4%
exchangeable preferred membership interests of TXU Energy ($494 million), 0.3%
preferred stock not subject to mandatory redemption ($38 million) and 45.8%
common stock equity ($6.7 billion).
US Holdings' cash distributions may take the legal form of common stock
share repurchases or the payment of dividends on outstanding shares of its
common stock. The form of the distributions is primarily determined by current
and forecasted levels of retained earnings as well as state tax implications.
The common stock share repurchases made subsequent to January 1, 2002 are cash
distributions to TXU Corp. that for financial reporting purposes have been
recorded as a return of capital. Any future cash distributions to TXU Corp. will
be reported (i) as a return of capital if made through repurchases or (ii) as a
dividend if so declared by the board of directors. Any future common stock share
repurchases will reduce the amount of US Holdings' equity, but will not change
TXU Corp.'s 100% ownership of US Holdings.
Registered Financing Arrangements -- US Holdings and its subsidiaries may
issue and sell additional debt and equity securities as needed, including
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, all of which
are currently registered with the SEC for offering pursuant to Rule 415 under
the Securities Act of 1933.
37
Short-term Borrowings -- At September 30, 2003, US Holdings had
outstanding short-term borrowings consisting of advances from affiliates of $291
million. At December 31, 2002, outstanding short-term bank borrowings were $1.8
billion and advances from affiliates were $787 million. Weighted average
interest rates on short-term borrowings were 2.87% and 2.44% at September 30,
2003 and December 31, 2002, respectively.
Credit Facilities -- At September 30, 2003, credit facilities available to
TXU Corp. and its US subsidiaries were as follows:
At September 30, 2003
--------------------------------------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
- -------- --------------- --------- ----- ------ ---------- ------------
Five-Year Revolving Credit Facility February 2005 US Holdings $ 1,400 $ 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 $ 2,750 $ 270 $ -- $2,480
======= ====== ====== ======
- -----------------------
(a) previously TXU Corp.
In August 2003, TXU Corp. entered into the $500 million 5-year revolving
credit facility that provides for up to $500 million in letters of credit or up
to $250 million of loans ($500 million in the aggregate).
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.
In addition to providing back-up of commercial paper issuances by TXU
Energy and Oncor, the credit facilities above are for general corporate and
working capital purposes, including providing collateral support for TXU Energy
portfolio management activities.
38
Long-term Debt -- During the nine months ended September 30, 2003, Oncor
and TXU Energy issued, redeemed, reacquired or made scheduled principal payments
on long-term debt as follows:
Issuances Retirements
--------- -----------
Oncor:
First mortgage bonds....................... $ -- $ 662
Medium term notes.......................... -- 15
Transition bonds........................... 500 --
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
------ ------
$1,900 $ 899
====== ======
See Notes 3, 4 and 5 to Financial Statements for further detail of debt
issuance and retirements, financing arrangements, and capitalization.
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., including TXU Energy, Oncor and TXU Gas
(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
Receivables Company to the financial institutions. The servicing fee
compensates TXU Business Services Company for its services as collection agent,
including maintaining the detailed accounts receivable collection records. TXU
Business Services Company charges the affiliated businesses for its servicing
costs, net of the servicing fee income. The program fees paid to financial
institutions, which consist primarily of interest costs on the underlying
financing, were $8 million and $10 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 fee
amounts represent the net incremental costs of the program to US Holdings and
are reported in SG&A expenses.
The September 30, 2003 balance sheet reflects funding under the program of
$667 million, through sale of undivided interests in receivables by TXU
Receivables Company, related to $1.4 billion face amount of US Holdings
trade accounts receivable. Funding under the program increased $220 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 $141 million. Funding increases or decreases under the program are
reflected as cash provided by or used in operating activities in the statement
of cash flows.
39
Upon termination of the program, cash flows to US Holdings 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. The trade accounts receivable balances on US Holdings' balance sheets
represent the face amount of its receivables less the funding under the program
and allowances for uncollectible accounts.
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.
Credit Ratings of TXU Corp. and its US Subsidiaries -- The current credit
ratings for TXU Corp., US Holdings and certain of its US subsidiaries are
presented below:
TXU Corp. US Holdings Oncor TXU Energy
--------- ----------- ----- ----------
(Senior Unsecured) (Senior Unsecured) (Secured) (Senior Unsecured)
S&P......... BBB- BBB- BBB BBB
Moody's..... Ba1 Baa3 Baa1 Baa2
Fitch....... BBB- BBB- BBB+ BBB
40
Moody's currently maintains a negative outlook for TXU Corp. and a stable
outlook for US Holdings, TXU Energy and Oncor. Fitch currently maintains a
stable outlook for each such entity. 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 US Holdings 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, US Holdings and its subsidiaries were in
compliance with all such applicable covenants.
Certain financing and other arrangements of US Holdings 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 US Holdings, 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 US
Holdings or its subsidiaries.
Credit Rating Provisions
------------------------
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.
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.
41
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.
Cross Default Provisions
------------------------
Certain financing arrangements of US Holdings 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 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.
US Holdings 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.
OFF BALANCE SHEET ARRANGEMENTS
See discussion above under Sale of Receivables.
42
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 6 to Financial Statements for a discussion of contingencies.
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.
43
For purposes of these reports, the Commission rules adjust the total
historical load to remove load for those individual small commercial customers
who now use more than 1,000 kilowatts, and for those customers in which the
aggregate use of all their affiliates under common control is more than 1,000
kilowatts and have contracted with Oncor's affiliated REP, TXU Energy. The
calculations do not take into account the small commercial load that TXU Energy
has gained outside of the Oncor service territory. Also the report filed by
Oncor does not address the residential category where a significantly smaller
percentage of the load is served by REPs other than TXU Energy.
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.
TXU Energy -- 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 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).
44
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 US Holdings' 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.
Summary -- Although US Holdings cannot predict future regulatory or
legislative actions or any changes in economic and securities market conditions,
no changes are expected in trends or commitments, other than those discussed in
the 2002 Form 10-K and this report, which might significantly alter its basic
financial position, results of operations or cash flows.
CHANGES IN ACCOUNTING STANDARDS
See Note 1 to Financial Statements for discussion of changes in accounting
standards.
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 US Holdings' operations,
financial results and financial condition, and could cause US Holdings' 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, US Holdings is subject to settlement adjustments from ERCOT related to
prior periods, which may result in charges or credits impacting future reported
results of operations.
US Holdings' 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. US Holdings will need to adapt to these
changes and may face increasing competitive pressure.
45
US Holdings' businesses are subject to changes in laws (including the
Texas Public 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, 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 US Holdings'
regulated businesses, and present or prospective wholesale and retail
competition.
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.
US Holdings is not guaranteed any rate of return on its capital
investments in unregulated businesses. US Holdings markets and trades power,
including power from its own production facilities, as part of its wholesale
energy sales business and portfolio management operation. US Holdings' 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.
US Holdings' 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, US
Holdings has agreed not to seek to increase its distribution rates prior to
2004. Thus, the rates US Holdings 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 US Holdings' 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 US Holdings' costs and
the return on invested capital allowed by the Commission.
Some of the fuel for US Holdings' 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 US Holdings can obtain for
power sales may not change at the same rate as changes in fuel costs. In
addition, US Holdings markets and trades natural gas and other energy related
commodities, and volatility in these markets may affect US Holdings' 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 US Holdings' 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.
46
All but one of US Holdings' 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 US Holdings' base-load plant is dependent in significant part upon the
price of gas. US Holdings cannot fully hedge the risk associated with dependency
on gas because of the expected useful life of US Holdings' power production
assets and the size of its position relative to market liquidity.
To manage its financial exposure related to commodity price fluctuations,
US Holdings 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, US Holdings 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, US Holdings 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 US Holdings has unhedged
positions, fluctuating commodity prices can impact US Holdings' results of
operations and financial position, either favorably or unfavorably. For
additional information regarding the accounting treatment for US Holdings'
hedging and portfolio management activities, see Notes 2 and 13 to Financial
Statements in the 2002 Form 10-K.
Although US Holdings 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, US Holdings cannot predict with precision the impact that its
risk management decisions may have on its businesses, results of operations or
financial position.
In connection with US Holdings' portfolio management activities, US
Holdings 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 US Holdings' consolidated
balance sheet as both current and noncurrent commodity contract liabilities.
These obligations make up a significant portion of these line items. US Holdings
might not be able to satisfy all of these guarantees and indemnification
obligations if they were to come due at the same time.
US Holdings' portfolio management activities are exposed to the risk that
counterparties which owe US Holdings 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, US Holdings
might be forced to acquire alternative hedging arrangements or honor the
underlying commitment at then-current market prices. In such event, US Holdings
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 US Holdings' and its subsidiaries'
long-term debt are 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
47
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 US Holdings' 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 US Holdings' large customers, suppliers and counterparties require
sufficient creditworthiness in order to enter into transactions. If US Holdings'
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 US Holdings' subsidiaries.
In addition, as discussed elsewhere in this Quarterly Report on Form 10-Q
and in the 2002 Form 10-K, the terms of certain financing and other arrangements
contain provisions that are specifically affected by changes in credit ratings
and could require the posting of collateral, the repayment of indebtedness or
the payment of other amounts.
The operation of power production and energy transportation facilities
involves many risks, including start up risks, breakdown or failure of
facilities, lack of sufficient capital to maintain the facilities, the
dependence on a specific fuel source or the impact of unusual or adverse weather
conditions or other natural events, as well as the risk of performance below
expected levels of output or efficiency, the occurrence of any of which could
result in lost revenues and/or increased expenses. A significant portion of US
Holdings' 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, US Holdings' 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, US Holdings could be subject to
additional costs and/or the write-off of its investment in the project or
improvement.
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, US Holdings' 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 US Holdings will
be able to lower bad debt expense, the achievement of which could be affected by
factors outside of US Holdings' control, including weather, changes in
regulations, and economic and market conditions.
The ownership and operation of nuclear facilities, including US Holdings'
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.
48
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 US Holdings' resources, including insurance coverage.
US Holdings 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 US Holdings. 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 US Holdings serves on January 1,
2004, in its historical service territories less the number of retail electric
customers US Holdings serves in other areas of Texas. As of September 30, 2003,
US Holdings 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, US Holdings 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.
US Holdings is subject to extensive environmental regulation by
governmental authorities. In operating its facilities, US Holdings is required
to comply with numerous environmental laws and regulations, and to obtain
numerous governmental permits. US Holdings may incur significant additional
costs to comply with these requirements. If US Holdings 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 US Holdings or its
facilities, and future changes in environmental laws and regulations could
occur, including potential regulatory and enforcement developments related to
air emissions.
US Holdings 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 US Holdings 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 US
Holdings' older facilities it may be uneconomical for US Holdings to install the
necessary equipment, which may cause US Holdings to shut down those facilities.
In addition, US Holdings 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,
US Holdings may obtain, or be required to provide, indemnification against
certain environmental liabilities. Another party could fail to meet its
indemnification obligations to US Holdings.
49
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, US Holdings began to provide retail electric services
to all customers who did not take action to select another REP.
US Holdings 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 US Holdings. Because US Holdings will not be able to compete for
residential and small commercial customers on the basis of price in its
historical service territory, US Holdings 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 US Holdings' cost to produce power,
US Holdings 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 US Holdings' 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.
US Holdings 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. US Holdings or any other REP
can offer to provide services to these customers at any negotiated price. US
Holdings 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 US Holdings to be its provider may
subsequently decide to switch to another provider.
An affiliated REP is obligated to offer the price-to-beat rate to
requesting residential and small commercial customers in the historical service
territory of its incumbent utility through January 1, 2007. The initial
price-to-beat rates for the affiliated REPs, including US Holdings', 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 US Holdings' retail electric operations in its historical
service territory will be largely dependent upon the amount of headroom
available to US Holdings and the competitive REPs in US Holdings' price-to-beat
rate. Since headroom is dependent, in part, on power purchase costs, US Holdings
does not know nor can it estimate the amount of headroom that it or other REPs
will have in US Holdings' 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, US Holdings 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, US Holdings may lose customers to competitive REPs.
50
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 US Holdings' 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,
US Holdings' 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, US Holdings may face
competition from a number of other energy service providers, or other energy
industry participants, who may develop businesses that will compete with US
Holdings 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 US Holdings. If there is
inadequate margin in these retail electric markets, it may not be profitable for
US Holdings to enter these markets.
US Holdings 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, US Holdings' 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. US Holdings 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 US Holdings' customers could
negatively impact the satisfaction of its customers with its service.
Additionally, in certain parts of Texas, US Holdings is dependent on
unaffiliated T&D utilities for the reading of its customers' energy meters. US
Holdings 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.
US Holdings 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 US Holdings 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 US
Holdings' underlying cost to obtain the commodities or services, its results of
operations would be adversely affected. US Holdings 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, US
Holdings has little, if any, prior experience in selling these
non-energy-related services.
Under the Commission's rules, as an affiliated REP, US Holdings 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 US
Holdings is delayed in terminating electric service to those customers, its
results of operations may be adversely affected.
51
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. US Holdings 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 US Holdings'. 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 US Holdings has
facilities will likely increase the competitiveness of the wholesale power
market in that region. In addition, the market value of US Holdings' 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
US Holdings' facilities. Changes in technology could also alter the channels
through which retail electric customers buy electricity.
US Holdings is a holding company and conducts its operations primarily
through wholly-owned subsidiaries. Substantially all of US Holdings'
consolidated assets are held by these subsidiaries. Accordingly, US Holdings'
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 US Holdings in the form of distributions, loans or
advances, and repayment of loans or advances from US Holdings. The subsidiaries
are separate and distinct legal entities and have no obligation to provide US
Holdings with funds for its payment obligations, whether by dividends,
distributions, loans or otherwise.
Because US Holdings 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, US Holdings'
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 US Holdings 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 US Holdings.
The inability to raise capital on favorable terms, particularly during
times of uncertainty in the financial markets, could impact US Holdings' ability
to sustain and grow its businesses, which are capital intensive, and would
increase its capital costs. US Holdings 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. US Holdings' 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 US Holdings' credit or a reduction in US Holdings'
credit ratings or the credit ratings of its subsidiaries;
o extreme volatility in US Holdings' markets that increases margin or
credit requirements;
o a material breakdown in US Holdings' 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 US Holdings' businesses
that restrict US Holdings' ability to access its liquidity facilities.
52
A lack of necessary capital and cash reserves could adversely impact the
evaluation of US Holdings' credit worthiness by counterparties and rating
agencies. Further, concerns on the part of counterparties regarding US Holdings'
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. US Holdings 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 US Holdings'
financial condition or access to the capital markets. Additionally, it is
unclear what laws and regulations may develop, and US Holdings 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.
In addition, TXU Corp. is unable to predict whether its decision to exit
all of its operations in Europe might result in lawsuits by the creditors of or
others associated with TXU Europe. If any such lawsuits were filed and resulted
in a substantial monetary judgment against TXU Corp. or were settled on
unfavorable terms, TXU Corp.'s financial results could be adversely affected.
Since TXU Corp. is a holding company, any substantial costs relating to these
matters would likely be funded in whole or in part using cash generated by its
subsidiaries, including TXU Energy.
US Holdings is subject to costs and other effects of legal and
administrative proceedings, settlements, investigations and claims.
The issues and associated risks and uncertainties described above are not
the only ones US Holdings may face. Additional issues may arise or become
material as the energy industry evolves.
FORWARD-LOOKING STATEMENTS
This report and other presentations made by US Holdings contain
forward-looking statements within the meaning of Section 21E of the Securities
Exchange Act of 1934, as amended. Although US Holdings 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 the 2002 Form 10-K, that could cause the actual results of US
Holdings 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 US Holdings 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 US
Holdings 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 10-K and
is therefore not presented herein.
53
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.
September 30, December 31,
2003 2002
---- ----
Period-end MtM VaR............................ $ 25 $23
Average Month-end MtM VaR (year-to-date)...... $ 29 $38
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 for TXU Energy is modeled for a duration of ten years
based on the nature of its particular market. 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.................... $176 $144
Average Month-end Portfolio VaR
(year-to-date)(a)......................... $181 N/A
(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.
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.
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.
September 30, December 31,
2002 2003
---- -----
EaR .......................................... $ 24 $ 28
CFaR ......................................... $ 88 $178
54
INTEREST RATE RISK
See Note 3 to Financial Statements for discussion of the issuances of new
fixed rate debt and retirements of fixed rate debt since December 31, 2002 and
new interest rate swaps.
CREDIT RISK
Gross Receivables - Credit Exposure -- US Holdings' gross exposure to
credit risk as of September 30, 2003 was $2.0 billion, representing trade
accounts receivable, commodity contract assets and derivative assets (net of
allowance of uncollectible accounts receivable of $74 million).
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.
Most of the remaining trade accounts receivable are with large commercial
and industrial customers. US Holdings' 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 commodity contract
assets, and derivative assets and trade accounts receivable from large
commercial and industrial customers, by investment grade and noninvestment
grade, credit quality and maturity.
Exposure by Maturity
Exposure -----------------------------------------
before Greater
Credit Credit Net 2 years or Between than 5
Collateral Collateral Exposure less 2-5 years years Total
---------- ---------- --------- ---------- --------- ------- -----
Investment grade $ 630 $ 24 $ 606 $ 480 $ 59 $ 67 $ 606
Noninvestment grade 323 95 228 184 21 23 228
Totals ----- ----- ----- ----- ----- ----- -----
$ 953 $ 119 $ 834 $ 664 $ 80 $ 90 $ 834
===== ===== ===== ===== ===== ===== =====
Investment grade 66% 20% 73%
Noninvestment grade 34% 80% 27%
The exposure to credit risk from these customers and counterparties,
excluding credit collateral, as of September 30, 2003, is $953 million 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 US Holdings (cash,
letters of credit and other security interests), the net credit exposure is $834
million. Of this amount, approximately 73% of the associated exposure is with
investment grade customers and counterparties, as determined using publicly
available information including major rating agencies' published ratings and US
Holdings' 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. US Holdings routinely monitors and
manages its credit exposure to these customers and counterparties on this basis.
US Holdings had no exposure to any one customer or counterparty greater
than 10% of the net exposure of $834 million at September 30, 2003.
Additionally, approximately 80% of the credit exposure, net of collateral held,
has a maturity date of two years or less. US Holdings 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.
55
During the third quarter of 2003, and in conjunction with implementation
of a new credit risk management system, US Holdings 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 12.8%
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 US Holdings' 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, US Holdings' 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 US Holdings' internal control over
financial reporting that has materially affected, or is reasonably likely to
materially affect, US Holdings' internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Reference is made to the 2002 Form 10-K and the Form 10-Q for the
quarterly period ended June 30, 2003 for discussion of legal proceedings.
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
- ------- ------- -------
3(i) -- Amended and Restated Articles
of Incorporation of TXU US
Holdings Company.
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.
56
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (Cont.)
Previously Filed*
-----------------
With
File As
Exhibit Number Exhibit
- ------- ------ -------
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.
10(a) 1-2833 4(d) -- Amendment, dated as of July 10,
Form 10-Q 2003 to the $400,000,000 Three-
(Quarter ended Year Amended and Restated
September 30, Revolving Credit Agreement,
2003) dated as of April 22, 2003, among
US Holdings, TXU Corp., certain
banks listed therein and
Citibank, N.A., as Administrative
Agent.
10(b) 1-2833 4(e) -- Amendment No. 1, dated as of
Form 10-Q August 29, 2003 to the
(Quarter ended $450,000,000 Revolving Credit
September 30, Agreement, dated as of
2003) 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.
57
(b) Reports on Form 8-K furnished or filed since June 30, 2003:
Date of Report Item Reported
-------------- -------------
July 25, 2003 Item 5. Other Events and Regulation FD Disclosure.
Item 7. Exhibits.
July 31, 2003 Item 5. Other Events and Regulation FD Disclosure.
August 27, 2003 Item 5. Other Events and Regulation FD Disclosure.
58
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 US HOLDINGS COMPANY
By /s/ David H. Anderson
---------------------------------------
David H. Anderson
Vice President and Controller
Date: November 12, 2003
59