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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 JUNE 30, 2003
-- OR --
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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Commission File Number 1-11668
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 August 8, 2003: 41,255,362 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 Six Months Ended June 30, 2003 and 2002............................. 1
Condensed Statements of Consolidated Cash Flows -
Six Months Ended June 30, 2003 and 2002...................................... 2
Condensed Consolidated Balance Sheets -
June 30, 2003 and December 31, 2002........................................... 3
Notes to Financial Statements................................................. 4
Independent Accountants' Report............................................... 21
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations....................................................... 22
Item 3. Quantitative and Qualitative Disclosures About Market Risk...................... 52
Item 4. Controls and Procedures......................................................... 55
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................................... 55
Item 6. Exhibits and Reports on Form 8-K................................................ 56
SIGNATURE...................................................................................... 57
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"
ERCOT.................................Electric Reliability Council of Texas
FIN...................................Financial Accounting Standards Board
Interpretation
FIN 45................................FIN No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees,
Including Indirect Guarantees of
Indebtedness of Others - an Interpretation
of FASB Statements No. 5, 57, and 107
and Rescission of FIN No. 34"
FIN 46................................FIN No. 46, "Consolidation of Variable
Interest Entities"
Fitch.................................Fitch Ratings, Ltd.
GWh...................................gigawatt-hours
Moody's...............................Moody's Investors Services, Inc.
NRC...................................United States Nuclear Regulatory
Commission
Oncor.................................Oncor Electric Delivery Company
POLR..................................provider of last resort
REPs..................................retail electric providers
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 143..............................SFAS No. 143, "Accounting for Asset
Retirement Obligations"
ii
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 of both Liabilities
and Equity"
SG&A..................................selling, general and administrative
T&D...................................transmission and distribution
TXU Energy............................TXU Energy Company LLC
TXU Fuel..............................TXU Fuel Company
TXU Gas...............................TXU Gas Company
TXU Mining............................TXU Mining Company LP
TXU Portfolio Management..............TXU Portfolio Management Company LP
US....................................United States of America
US GAAP...............................accounting principles generally accepted
in the US
US Holdings...........................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 Six Months
Ended Ended
June 30, June 30,
--------------- ----------------
2003 2002 2003 2002
----- ---- ------ ----
(millions of dollars)
Operating revenues....................................................... $2,180 $2,119 $4,112 $3,996
------ ------ ------ ------
Costs and expenses:
Cost of energy sold and delivery fees................................. 932 787 1,770 1,312
Operating costs....................................................... 361 344 727 658
Depreciation and amortization......................................... 163 174 345 357
Selling, general and administrative expenses.......................... 201 269 394 546
Franchise and revenue-based taxes..................................... 87 94 180 194
Other income.......................................................... (17) (14) (26) (17)
Other deductions...................................................... 2 2 3 5
Interest income....................................................... (4) - (9) (1)
Interest expense and other charges.................................... 157 105 308 210
------ ------ ------ ------
Total costs and expenses.......................................... 1,882 1,761 3,692 3,264
------ ------ ------ ------
Income before income taxes and cumulative effect of changes in accounting
principles............................................................. 298 358 420 732
Income tax expense....................................................... 97 114 130 235
------ ------ ------ ------
Income before cumulative effect of changes in accounting principles...... 201 244 290 497
Cumulative effect of changes in accounting principles, net of tax benefit
(Note 2)............................................................... - - (58) -
------ ------ ------ ------
Net income .............................................................. 201 244 2 232 497
Preference stock dividends............................................... 2 3 4 5
------ ------ ------ ------
Net income available for common stock.................................... $ 199 $ 241 $ 228 $ 492
====== ====== ====== ======
CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(Unaudited)
Three Months Six Months
Ended Ended
June 30, June 30,
--------------- --------------
2003 2002 2003 2002
------ ------ ------ -----
(millions of dollars)
Net income............................................................... $ 201 $ 244 $ 232 $ 497
------ ------ ------ ------
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,
$36, $53 and $60).................................................
Amounts realized in earnings during the period (net of tax benefit (20) (68) (98) (111)
of $12, $-, $39 and $2)........................................... 23 (1) 72 (3)
------ ------ ------ ------
Total............................................................... 3 (69) (26) (114)
------ ------ ------- ------
Comprehensive income..................................................... $ 204 $ 175 $ 206 $ 383
====== ====== ====== ======
See Notes to Financial Statements.
1
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
-------------------
2003 2002
---- ----
(millions of dollars)
Cash flows -- operating activities:
Income before cumulative effect of changes in accounting principles....... $ 290 $ 497
Adjustments to reconcile income before cumulative effect of changes in
accounting principles to cash provided by operating activities:
Depreciation and amortization........................................... 382 404
Deferred income taxes and investment tax credits-- net ................. 116 25
Net unrealized (gain) loss from mark-to-market valuation of commodity
contracts............................................................. (33) 12
Net gain from sales of assets........................................... (21) (12)
Reduction in regulatory liability....................................... (78) (41)
Changes in operating assets and liabilities............................... 19 (434)
------- -------
Cash provided by operating activities............................... 675 451
------- -------
Cash flows -- financing activities:
Issuances of long-term debt .............................................. 1,294 1,261
Retirements/repurchases of securities:
Long-term debt.......................................................... (490) (1,402)
Preferred stock of subsidiary, subject to mandatory redemption.......... (5) -
Change in advances-- affiliates........................................... 199 (686)
Change in notes payable-- banks........................................... (1,804) 938
Repurchase of common stock................................................ (250) -
Dividends paid to parent.................................................. (250) (427)
Preferred stock dividends paid............................................ (4) (5)
Redemption deposits applied to debt retirements........................... 210 -
Debt premium, discount, financing, and reacquisition expenses............. (37) (24)
------- -------
Cash used in financing activities................................... (1,137) (345)
------- -------
Cash flows -- investing activities:
Capital expenditures...................................................... (350) (415)
Acquisition of a business................................................. - (36)
Proceeds from sale of assets ............................................. 15 443
Nuclear fuel.............................................................. (35) (50)
Other..................................................................... 6 (66)
------- -------
Cash used in investing activities................................... (364) (124)
------- -------
Net change in cash and cash equivalents...................................... (826) (18)
Cash and cash equivalents -- beginning balance............................... 1,508 55
------- -------
Cash and cash equivalents -- ending balance.................................. $ 682 $ 37
======= =======
See Notes to Financial Statements.
2
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2003 2002
------ -----------
(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents................................................ $ 682 $ 1,508
Restricted cash.......................................................... - 210
Accounts receivable -- trade............................................. 1,193 1,386
Inventories ............................................................. 359 338
Commodity contract assets................................................ 1,366 1,298
Other current assets..................................................... 173 213
------- -------
Total current assets................................................ 3,773 4,953
------- -------
Investments:
Restricted cash.......................................................... 69 68
Other investments........................................................ 514 491
Property, plant and equipment -- net........................................ 16,672 16,183
Goodwill.................................................................... 558 558
Regulatory assets -- net.................................................... 1,770 1,630
Commodity contract assets................................................... 393 476
Cash flow hedges and other derivative assets................................ 62 14
Other noncurrent assets..................................................... 153 146
------- -------
Total assets........................................................ $23,964 $24,519
======= =======
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Advances from affiliates................................................. $ 736 $ 787
Notes payable -- banks................................................... - 1,804
Long-term debt due currently............................................. 105 397
Accounts payable -- trade................................................ 871 820
Commodity contract liabilities........................................... 1,198 1,138
Accrued taxes............................................................ 153 303
Other current liabilities................................................ 672 724
------- -------
Total current liabilities........................................... 3,735 5,973
------- -------
Accumulated deferred income taxes........................................... 3,280 3,227
Investment tax credits...................................................... 439 450
Commodity contract liabilities.............................................. 304 320
Cash flow hedges and other derivative liabilities........................... 227 150
Other noncurrent liabilities and deferred credits........................... 1,593 1,063
Long-term debt, less amounts due currently.................................. 7,715 6,613
Preferred stock subject to mandatory redemption............................. 17 21
Contingencies (Note 6)
Shareholders' equity (Note 5)............................................... 6,654 6,702
------- -------
Total liabilities and shareholders' equity.......................... $23,964 $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 has two reportable business segments: TXU Energy and
Oncor. 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 adoption of the following new accounting rules: EITF 02-3,
SFAS 143, and SFAS 145, all discussed below.
In the opinion of management, all adjustments (consisting of normal
recurring accruals) necessary for a fair presentation of the results of
operations and financial position have been included therein. All intercompany
items and transactions have been eliminated in consolidation. Certain
information and footnote disclosures normally included in annual consolidated
financial statements prepared in accordance with US GAAP have been omitted
pursuant to the rules and regulations of the SEC. Because the consolidated
interim financial statements do not include all of the information and footnotes
required by US GAAP, they should be read in conjunction with the audited
financial statements and related notes included in the 2002 Form 10-K. The
results of operations for an interim period may not give a true indication of
results for a full year. All dollar amounts in the financial statements and
tables in the notes are stated in millions of US dollars unless otherwise
indicated. Certain previously reported amounts have been reclassified to conform
to current classifications.
Effective April 1, 2003, the estimates of the depreciable lives of
the Comanche Peak nuclear generating plant and several gas generation plants
were extended to better reflect the useful lives of the assets. At the same
time, depreciation rates were increased on lignite and gas generation facilities
to reflect investments in emissions control equipment. The net impact of these
changes was a reduction in depreciation expense of $13 million (pre-tax) and an
increase in net income of $8 million in the three- and six-months ended June 30,
2003.
Income Taxes -- TXU Energy and the holders of its 9% Exchangeable
Subordinated Notes due 2012 (which were converted on July 1, 2003 to preferred
membership interests in TXU Energy, see Note 3), characterize the notes as
preferred equity interests for federal and state income tax purposes with the
result that TXU Energy is treated as a partnership for such purposes.
Changes in Accounting Standards -- In October 2002, the EITF, through
EITF 02-3, rescinded EITF 98-10, which required mark-to-market accounting for
all trading activities. SFAS 143, regarding asset retirement obligations, became
effective on January 1, 2003. As a result of the implementation of these two
accounting standards, 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/industrial retail contracts in 2003.
For the three- and six-month periods ended June 30, 2002, US Holdings had
recognized $21 million and $34 million in origination gains on such contracts,
respectively.
SFAS 145, regarding classification of items as extraordinary, became
effective on January 1, 2003. One of the provisions of this statement is the
rescission of SFAS No. 4, "Reporting Gains and Losses from Extinguishment of
Debt." The adoption of SFAS 145 does not result in a reclassification of results
for the six months ended June 30, 2002.
As a result of the implementation of SFAS No. 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 No. 145.
4
SFAS 146, regarding exit costs, became effective on January 1, 2003.
SFAS 146 requires that a liability for costs associated with an exit or disposal
activity be recognized only when the liability is incurred and measured
initially at fair value. The adoption of SFAS 146 did not materially impact
results of operations for the six months ended June 30, 2003.
FIN 45 requires recording the fair value of guarantees upon issuance
or modification after December 31, 2002. The interpretation also requires
expanded disclosures of guarantees (see Note 6 under Guarantees). The adoption
of FIN 45 did not materially impact results of operations for the six months
ended June 30, 2003.
FIN 46 was issued in January 2003. FIN 46 provides guidance related
to identifying variable interest entities and determining whether such entities
should be consolidated. This guidance will be effective for existing variable
interest entities in the quarter ending September 30, 2003 and immediately for
any new variable interest entities. The adoption of FIN 46 is not expected to
materially impact financial position or 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. US Holdings is evaluating the potential impact
of SFAS 149 on its financial position and results of operations.
SFAS 150 was issued in May 2003 and became effective June 1, 2003 for
new financial instruments and July 1, 2003 for existing financial instruments.
SFAS 150 requires that certain mandatorily redeemable preferred securities be
classified as liabilities beginning July 1, 2003. US Holdings is evaluating the
potential impact of SFAS 150 on its financial position.
EITF 01-8 was issued in May 2003 and is effective prospectively for
arrangements that are new, modified or committed to beginning July 1, 2003. This
guidance may require that certain types of arrangements be accounted for as
leases, including tolling and power supply contracts, take-or-pay contracts and
service contracts involving the use of specific property and equipment. US
Holdings is evaluating the potential impact of the adoption of EITF 01-8 on its
financial position and results of operations.
2. CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
The following summarizes the effect on results for the six months
ended June 30, 2003 for changes in accounting principles effective January 1,
2003:
Charge from rescission of EITF 98-10, net of tax effect of $34 million... $(63)
Credit from adoption of SFAS 143, net of tax effect of $3 million........ 5
----
Total net charge.................................................... $(58)
====
On October 25, 2002, the EITF, through EITF 02-3, rescinded EITF
98-10, which required mark-to-market accounting for all trading activities.
Pursuant to this rescission, only financial instruments that are derivatives
under SFAS 133 will be subject to mark-to-market accounting. Financial
instruments that may not be derivatives under SFAS 133, but were
marked-to-market under EITF 98-10, consist primarily of gas transportation and
storage agreements, power tolling, full requirements and capacity contracts.
This new accounting rule was effective for new contracts entered into after
October 25, 2002. Non-derivative contracts entered into prior to October 26,
2002, continued to be accounted for at fair value through December 31, 2002;
however, effective January 1, 2003, such contracts were required to be accounted
for on a settlement basis. Accordingly, a charge of $97 million ($63 million
after-tax) has been reported as a cumulative effect of a change in accounting
principles in the first quarter of 2003. Of the total, $75 million reduced net
commodity contract assets and liabilities and $22 million reduced inventory that
had previously been marked-to-market as a trading position. The cumulative
effect adjustment represents the net gains previously recognized for these
contracts under mark-to-market accounting.
5
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 June 30, 2003 was $564 million,
comprised of a $554 million liability as a result of adoption of SFAS 143 and
$18 million of accretion during the first six months of 2003 reduced by $8
million in reclamation payments.
With respect to nuclear decommissioning costs, 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,
as Oncor recovers regulated decommissioning fees from REPs on behalf of TXU
Energy, and will be deferring such differences as part of the regulatory
cost-recovery process.
On a pro forma basis, assuming SFAS 143 had been adopted at the
beginning of the periods, income from continuing operations for the six months
ended June 30, 2002 would have increased by $4 million after-tax and the
liability for asset retirement obligations as of June 30, 2002, would have been
$538 million.
3. FINANCING ARRANGEMENTS
Credit Facilities -- At June 30, 2003, US Holdings had outstanding
short-term borrowings consisting of advances from affiliates of $736 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 3.07% and 2.44% at June 30, 2003 and December 31,
2002, respectively.
6
At June 30, 2003, US Holdings had credit facilities as follows:
At June 30, 2003
--------------------------------------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
- -------- --------------- --------- ----- ------ ---------- ------------
Five-Year Revolving Credit Facility February 2005 US Holdings $ 1,400 $ 391 $ -- $1,009
Revolving Credit Facility February 2005 TXU Energy, Oncor 450 21 -- 429
Three-Year Revolving Credit Facility May 2005 US Holdings 400 -- -- 400
------- ------ ------ ------
Total North America $ 2,250 $ 412 $ -- $1,838
======= ====== ====== ======
Through April 2003, $1.8 billion in outstanding cash borrowings as of
December 31, 2002 under the credit facilities were repaid, and the facilities
were restructured. A $450 million revolving credit facility was established for
TXU Energy and Oncor that matures on February 25, 2005. This facility will be
used for working capital and other general corporate purposes, including letters
of credit, and replaces the $1 billion 364-day revolving credit facility that
expired in April 2003. Up to $450 million of letters of credit may be issued
under the facility.
This facility, as well as others available to US Holdings, will
provide back-up for any future issuance of commercial paper by TXU Energy and
Oncor. At June 30, 2003, there was no outstanding commercial paper under the
credit facilities.
In connection with the restructuring of the North America credit
facilities of TXU Corp., in April 2003:
o Oncor cancelled its undrawn $150 million secured 364-day credit
facility that was scheduled to expire in December 2003.
o US Holdings replaced TXU Corp. as the borrower under the $500
million three-year revolving credit facility. Concurrently, the
facility was reduced to $400 million.
o US Holdings' $1.4 billion five-year revolving credit facility was
amended. Among other things, the amendment increased the amount of
letters of credit allowed to be issued under the facility to $1
billion from $500 million.
7
Long-Term Debt -- At June 30, 2003 and December 31, 2002, the
long-term debt of US Holdings and its consolidated subsidiaries consisted of
the following:
June 30, December 31,
2003 2002
-------- ------------
TXU Energy
Pollution Control Revenue Bonds:
Brazos River Authority:
Floating Taxable Series 1993 due June 1, 2023....................................... $ -- $ 44
4.900% Fixed Series 1994A due May 1, 2029(a)........................................ -- 39
5.400% Fixed Series 1994B due May 1, 2029, remarketing date May 1, 2006(a).......... 39 39
5.400% Fixed Series 1995A due April 1, 2030, remarketing date May 1, 2006(a)........ 50 50
5.050% Fixed Series 1995B due June 1, 2030, remarketing date June 19, 2006(a)....... 118 118
7.700% Fixed Series 1999A due April 1, 2033......................................... 111 111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013(a).. 16 16
7.700% Fixed Series 1999C due March 1, 2032......................................... 50 50
4.950% Fixed Series 2001A due October 1, 2030, remarketing date April 1, 2004(a).... 121 121
4.750% Fixed Series 2001B due May 1, 2029, remarketing date November 1, 2006(a)..... 19 19
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011(a)..... 274 274
4.250% Fixed Series 2001D due May 1, 2033, remarketing date November 1, 2003(a)..... 271 271
1.150% Floating Taxable Series 2001F due December 31, 2036(b)....................... 39 39
1.150% Floating Taxable Series 2001G due December 31, 2036(b)....................... 72 72
1.070% Floating Taxable Series 2001H due December 31, 2036(b)....................... 31 31
1.020% Floating Taxable Series 2001I due December 31, 2036(b)....................... 63 63
1.050% Floating Series 2002A due May 1, 2037(b)..................................... 61 61
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)...... 44 --
Sabine River Authority of Texas:
6.450% Fixed Series 2000A due June 1, 2021.......................................... 51 51
5.500% Fixed Series 2001A due May 1, 2022, remarketing date November 1, 2011(a)..... 91 91
5.750% Fixed Series 2001B due May 1, 2030, remarketing date November 1, 2011(a)..... 107 107
4.000% Fixed Series 2001C due May 1, 2028, remarketing date November 1, 2003(a)..... 70 70
1.150% Floating Taxable Series 2001D due December 31, 2036(b)....................... 12 12
1.070% Floating Taxable Series 2001E due December 31, 2036(b)....................... 45 45
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028........................................... -- 14
5.000% Fixed Series 2001A due May 1, 2027, remarketing date November 1, 2006(a)..... 37 37
Other:
7.000% Fixed Senior Notes - TXU Mining due May 1, 2003.............................. -- 72
6.875% Fixed Senior Notes - TXU Mining due August 1, 2005........................... 30 30
9.000% Fixed Exchangeable Subordinated Notes due November 22, 2012.................. 750 750
6.125% Fixed Senior Notes due March 15, 2008........................................ 250 --
7.000% Fixed Senior Notes due March 15, 2013........................................ 1,000 --
Capital lease obligations........................................................... 10 10
Other............................................................................... 7 8
Unamortized premium and discount.................................................... (259) (264)
------ ------
Total TXU Energy ............................................................... 3,580 2,451
------ ------
US Holdings
7.170% Fixed Senior Debentures due August 1, 2007................................... 10 10
9.556% Fixed Notes due in bi-annual installments through December 4, 2019........... 73 73
8.254% Fixed Notes due in quarterly installments through December 31, 2021.......... 67 68
2.110% Floating Rate Junior Subordinated Debentures, Series D due January 30,2037(c) 1 1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037.......... 8 8
------ ------
Total US Holdings .............................................................. 159 160
------ ------
8
June 30, December 31,
2003 2002
-------- ------------
Oncor
9.530% Fixed Medium Term Secured Notes due January 30, 2003...................... -- 4
9.700% Fixed Medium Term Secured Notes due February 28, 2003..................... -- 11
6.750% Fixed First Mortgage Bonds due March 1, 2003.............................. -- 133
6.750% Fixed First Mortgage Bonds due April 1, 2003.............................. -- 70
8.250% Fixed First Mortgage Bonds due April 1, 2004.............................. 100 100
6.250% Fixed First Mortgage Bonds due October 1, 2004............................ 121 121
6.750% Fixed First Mortgage Bonds due July 1, 2005............................... 92 92
7.875% Fixed First Mortgage Bonds due March 1, 2023.............................. 224 224
8.750% Fixed First Mortgage Bonds due November 1, 2023........................... -- 103
7.875% Fixed First Mortgage Bonds due April 1, 2024.............................. 133 133
7.625% Fixed First Mortgage Bonds due July 1, 2025............................... 215 215
7.375% Fixed First Mortgage Bonds due October 1, 2025............................ 178 178
6.375% Fixed Senior Secured Notes due May 1, 2012................................ 700 700
7.000% Fixed Senior Secured Notes due May 1, 2032................................ 500 500
6.375% Fixed Senior Secured Notes due January 15, 2015........................... 500 500
7.250% Fixed Senior Secured Notes due January 15, 2033........................... 350 350
5.000% Fixed Debentures due September 1, 2007.................................... 200 200
7.000% Fixed Debentures due September 1, 2022.................................... 800 800
Unamortized premium and discount................................................. (32) (35)
------- -------
Total Oncor.................................................................. 4,081 4,399
------- -------
Total US Holdings consolidated................................................... 7,820 7,010
Less amount due currently........................................................ 105 397
------- -------
Total long-term debt............................................................. $ 7,715 $ 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 June 30, 2003. These series are in a flexible
or weekly rate mode and are classified as long-term as they are supported
by long-term irrevocable letters of credit. Series in the flexible mode
will be remarketed for periods of less than 270 days.
(c) Interest rates in effect at June 30, 2003.
In July 2003, TXU Energy exercised its right to exchange its $750
million 9% Exchangeable Subordinated Notes due November 22, 2012 for
exchangeable preferred membership interests with identical economic and other
terms. These securities are convertible into TXU Corp. common stock at an
exercise price of $13.1242. The market price of TXU Corp. common stock on June
30, 2003 was $22.45. As disclosed in the 2002 Form 10-K, any exchange of these
securities into common stock would result in a proportionate write-off of the
related unamortized discount as a charge to earnings. If all the securities
had been exchanged into common stock on June 30, 2003, the pre-tax charge
would have been $259 million.
In July 2003, the Brazos River Authority issued $39 million
aggregate principal amount of Series 2003B pollution control revenue bonds for
TXU Energy. The bonds will bear interest at an annual rate of 6.30% until
maturity in 2032. Proceeds from the issuance of the bonds were used to refund
the entire principal amount of Brazos River Authority Taxable Series 2001F
variable rate pollution control revenue bonds due December 31, 2036. The Sabine
River Authority also issued $12 million aggregate principal amount of Series
2003A pollution control revenue bonds for TXU Energy. The bonds will bear
interest at an annual rate of 5.80% until maturity in 2022. Proceeds from the
issuance of these bonds were used to refund the entire principal amount of
Sabine River Authority Taxable Series 2001D pollution control revenue bonds due
December 31, 2036.
In May 2003, the Brazos River Authority Series 1994A and the Trinity
River Authority Series 2000A pollution control revenue bonds (aggregate
principal amount of $53 million) were purchased upon mandatory tender. In July
2003, the bonds were remarketed and converted from a floating rate mode to a
multiannual mode at an annual rate of 3.00% and 6.25%, respectively. The rate on
the 1994A bonds will remain in effect until their mandatory tender date of May
1, 2005, at which time they will be remarketed. The rate on the 2000A bonds will
remain in effect until their maturity in 2028.
In May 2003, $72 million principal amount of the 7% TXU Mining fixed
rate senior notes were repaid at maturity.
9
In April 2003, Oncor repaid all ($70 million principal amount) of its
First Mortgage Bonds, 6.75% Series, at the maturity date for par value plus
accrued interest. A restricted cash deposit of $72 million was utilized to fund
the maturity.
In April 2003, the Brazos River Authority Series 1999A pollution
control revenue bonds, with an aggregate principal amount of $111 million, were
remarketed. The bonds now bear interest at a fixed annual rate of 7.70% and are
callable beginning on April 1, 2013 at a price of 101% until March 31, 2014 and
at 100% thereafter.
In March 2003, the Brazos River Authority Series 1999B and 1999C
pollution control revenue bonds (aggregate principal amount of $66 million) were
converted from a floating rate mode to a multiannual mode at annual rates of
6.75% and 7.70%, respectively. The rate on the 1999B bonds will remain in effect
until 2013 at which time they will be remarketed. The rate on the 1999C bonds is
fixed to maturity in 2032, however they become callable in 2013.
In March 2003, the Brazos River Authority issued $44 million
aggregate principal amount of pollution control revenue bonds for TXU Energy.
The bonds will bear interest at an annual rate of 6.75% until the mandatory
tender date of April 1, 2013. On April 1, 2013, the bonds will be remarketed.
Proceeds from the issuance of the bonds were used to repay the entire principal
amount of Brazos River Authority Series 1993 pollution control revenue bonds due
June 1, 2023.
In March 2003, Oncor repaid all ($133 million principal amount) of
its First Mortgage Bonds, 6.75% Series, at the maturity date for par value plus
accrued interest. A restricted cash deposit of $138 million was utilized to fund
the maturity.
In March 2003, Oncor redeemed all ($103 million principal amount) of
its First Mortgage and Collateral Trust Bonds, 8.75% Series due November 1,
2023, at 104.01% of the principal amount thereof, plus accrued interest to the
redemption date.
In March 2003, TXU Energy issued $1.25 billion aggregate principal
amount of senior unsecured notes in two series in a private placement with
registration rights. One series in the amount of $250 million is due March 15,
2008, and bears interest at the annual rate of 6.125%, and the other series in
the amount of $1 billion is due March 15, 2013, and bears interest at the annual
rate of 7%. Net proceeds from the issuance were used for general corporate
purposes, including the repayment of borrowings under TXU Corp.'s North America
credit facilities. In August 2003, TXU Energy entered into interest rate swap
transactions to effectively convert $500 million of the notes to floating
interest rates.
Sale of Receivables -- Certain subsidiaries of TXU Corp. sell trade
accounts receivable to TXU Receivables Company, a wholly-owned bankruptcy remote
subsidiary of TXU Corp., which sells undivided interests in accounts receivable
it purchases to financial institutions. As of June 30, 2003, TXU Energy (through
certain subsidiaries), Oncor and TXU Gas are qualified originators of accounts
receivable under the program. TXU Receivables Company may sell up to an
aggregate of $600 million in undivided interests in the receivables purchased
from the originators under the program. The June 30, 2003 financial statements
reflect the sale of $1.1 billion face amount of US Holdings' receivables to TXU
Receivables Company under the program in exchange for cash of $494 million and
$563 million in subordinated notes, with $10 million of losses on sales for the
six months ended June 30, 2003 that principally represents the interest costs on
the underlying financing. These losses approximated 6% of the cash proceeds from
the sale of undivided interests in accounts receivable on an annualized basis.
Funding under the program increased $47 million for the six month period ended
June 30, 2003 primarily due to reserve requirements that were reduced through a
temporary amendment in recognition of improving collection trends. Higher loss
reserve requirements in previous periods reflected the billing and collection
delays previously experienced as a result of new systems and processes in TXU
Energy and ERCOT for clearing customers' switching and billing data upon the
transition to competition. Funding increases or decreases under the program are
reflected as cash provided by or used in operating activities.
10
Upon termination, cash flows to the originators would be delayed as
collections of sold receivables would be used by TXU Receivables Company to
repurchase the undivided interests of the financial institutions instead of
purchasing new receivables. The level of cash flows would normalize in
approximately 16 to 31 days. TXU Business Services Company, a subsidiary of TXU
Corp., services the purchased receivables and is paid a market based servicing
fee by TXU Receivables Company. The subordinated notes receivable from TXU
Receivables Company represent TXU Corp.'s subsidiaries' retained interests in
the transferred receivables and are recorded at book value, net of allowances
for bad debts, which approximates fair value due to the short-term nature of the
subordinated notes, and are included in accounts receivable in the consolidated
balance sheet.
In August 2003, the program was amended to extend the term to July
2004, as well as to extend the period providing temporarily higher delinquency
and default compliance ratios through December 31, 2003. The program was also
amended to coincide with the credit facilities' covenants by removing investment
grade credit ratings as a requirement of an eligible originator and substituting
maintenance of fixed charge coverage ratios and debt to capital ratios as
requirements of an eligible originator. In June 2003, the program was amended to
provide temporarily higher delinquency and default compliance ratios and
temporary relief from the loss reserve formula. The June amendment reflected the
billing and collection delays previously experienced as a result of new systems
and processes in TXU Energy and ERCOT for clearing customers' switching and
billing data upon the transition to competition.
Contingencies Related to Receivables Program -- Although TXU
Receivables Company expects to be able to pay its subordinated notes from the
collections of purchased receivables, these notes are subordinated to the
undivided interests of the financial institutions in those receivables, and
collections might not be sufficient to pay the subordinated notes. The program
may be terminated if either of the following events occurs:
1) each of the originators cease to maintain their required fixed
charge coverage ratio and debt to capital (leverage) ratio;
2) the delinquency ratio (delinquent for 31 days) for the sold
receivables, the default ratio (delinquent for 91 days or deemed
uncollectible), the dilution ratio (reductions for discounts,
disputes and other allowances) or the days collection outstanding
ratio exceed stated thresholds and the financial institutions do not
waive such event of termination. The thresholds apply to the entire
portfolio of sold receivables, not separately to the receivables of
each originator.
The delinquency and dilution ratios exceeded the relevant thresholds
during the first four months of 2003, but waivers were granted. These ratios
were affected by issues related to the transition to deregulation. Certain
billing and collection delays arose due to implementation of new systems and
processes within TXU Energy and ERCOT for clearing customers' switching and
billing data. The billing delays have been resolved but, while improving, the
lagging collection issues continue to impact the ratios. The implementation of
new POLR rules by the Commission and strengthened credit and collection policies
and practices are expected to bring the ratios into consistent compliance with
the program.
Under the receivables sale program, all the originators are required
to maintain specified fixed charge coverage and leverage ratios (or supply a
parent guarantor that meets the ratio requirements). Prior to the August 2003
amendment extending the program, originator eligibility was predicated on the
maintenance of an investment grade credit rating. 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.
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 June 30, 2003, US Holdings and its subsidiaries were in
compliance with all such applicable covenants.
11
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 is a failure under other financing
arrangements to meet payment terms or to observe other covenants that would
result in an acceleration of payments due. Such provisions are referred to as
"cross default" provisions.
A default by US Holdings or any subsidiary thereof on financing
arrangements of $50 million or more would result in a cross default under the
$1.4 billion US Holdings five-year revolving credit facility, the $400 million
US Holdings credit facility, the $68 million US Holdings letter of credit
reimbursement and credit facility agreement and $30 million of TXU Mining senior
notes (which have a $1 million threshold).
A default by TXU Energy or Oncor or any subsidiary thereof in respect
of indebtedness in a principal amount in excess of $50 million or more would
result in a cross default for such party under the TXU Energy/Oncor $450 million
revolving credit facility. Under this credit facility, a default by TXU Energy
or any subsidiary thereof would cause the maturity of outstanding balances under
such facility to be accelerated as to TXU Energy, but not as to Oncor. Also,
under this credit facility, a default by Oncor or any subsidiary thereof would
cause the maturity of outstanding balances to be accelerated under such facility
as to Oncor, but not as to TXU Energy.
A default or similar event under the terms of the TXU Energy
preferred membership interests (formerly subordinated notes) that results in the
acceleration (or other mandatory repayment prior to the mandatory redemption
date) of such security or the failure to pay such security at the mandatory
redemption date would result in a default under TXU Energy's $1.25 billion
senior unsecured notes.
TXU Energy has entered into certain mining and equipment leasing
arrangements aggregating $127 million that would terminate upon the default of
any other obligations of TXU Energy owed to the lessor. In the event of a
default by TXU Mining, a subsidiary of TXU Energy, on indebtedness in excess of
$1 million, a cross default would result under the $31 million TXU Mining
leveraged lease and the lease would terminate.
The accounts receivable program also contains a cross default
provision with a threshold of $50 million applicable to each of the originators
under the program. TXU Receivables Company and TXU Business Services Company
each have a cross default threshold of $50,000. If either an originator, TXU
Business Services Company or TXU Receivables Company defaults on indebtedness of
the applicable threshold, the facility could terminate.
TXU Energy enters into energy-related contracts, the master forms of
which contain provisions whereby an event of default would occur if TXU Energy
were to default under an obligation in respect of borrowings in excess of
thresholds stated in the contracts, which thresholds vary.
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.
12
4. PREFERRED STOCK
In July 2003, US Holdings redeemed all of the shares of its $7.98
series, $7.50 series and $7.22 series of preferred stock not subject to
mandatory redemption and the shares of its $6.98 series of preferred stock
subject to mandatory redemption for an aggregate principle amount of $91
million.
5. SHAREHOLDERS' EQUITY
June 30, December 31,
2003 2002
--------- -----------
Shareholders' equity:
Preferred stock - not subject to mandatory redemption......... $ 115 $ 115
------ ------
Common stock without par value:
Authorized shares: 180,000,000
Outstanding shares: June 30, 2003 -- 46,567,862
and December 31, 2002-- 52,817,862 ................. 2,264 2,514
Retained earnings............................................. 4,489 4,261
Accumulated other comprehensive loss.......................... (214) (188)
------ ------
Total common stock equity........................... 6,539 6,587
------ ------
Total shareholders' equity.......................... $6,654 $6,702
====== ======
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.
An Oncor mortgage restricts its payment of dividends to the amount of
its retained earnings. Certain other 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. At June 30, 2003, there were no restrictions on the payment of dividends
under 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.
Project development guarantees -- In 1990, US Holdings repurchased an
electric co-op's minority ownership interest in the Comanche Peak nuclear
generation plant and assumed the co-op's indebtedness to the US government for
the facilities. US Holdings is making principal and interest payments to the
co-op in an amount sufficient for the co-op to make payments on its
indebtedness. US Holdings guaranteed the co-op's payments, and in the event that
the co-op fails to make its payments on the indebtedness, the US government
would assume the co-op's rights under the agreement, and such payments would
then be owed directly by US Holdings. At June 30, 2003, the balance of the
indebtedness was $139 million with maturities of principal and interest
extending to December 2021. The indebtedness is secured by a lien on the
purchased facilities.
Residual value guarantees in operating leases -- US Holdings is the
lessee under various operating leases that obligate it to guarantee the residual
values of the leased facilities. At June 30, 2003, the aggregate maximum amount
of residual values guaranteed was approximately $279 million with an estimated
residual recovery of approximately $210 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 has exceeded
the annual savings guaranteed. The maximum potential annual payout is
approximately $8 million and the maximum total potential payout is approximately
$56 million. During the three months ended June 30, 2003 no shared savings
contracts were executed. The average remaining life of the portfolio is
approximately nine years.
13
Letters of credit -- US Holdings has entered into various agreements
that require letters of credit for financial assurance purposes. Approximately
$350 million of letters of credit were outstanding at June 30, 2003 to support
existing floating rate pollution control revenue bond debt of approximately $323
million. The letters of credit are available to fund the payment of such debt
obligations. These letters of credit have expiration dates in 2003 and 2004;
however, 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. In July 2003, approximately $56 million of the $350 million of letters of
credit referenced above were terminated as a result of the refinancing of
approximately $51 million of floating rate pollution control revenue bonds.
US Holdings has outstanding letters of credit in the amount of $118
million to support portfolio management margin requirements in the normal
course of business. As of June 30, 2003, approximately 73% of the obligations
supported by these letters of credit mature within one year, and substantially
all of the remainder mature in the second year.
Surety bonds -- US Holdings has outstanding surety bonds of
approximately $60 million to support performance under various subsidiary
construction contracts in the normal course of business. The term of the surety
bond obligations is approximately two years.
Other --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, $16 million at June 30, 2003, and
interest on bonds issued by the agencies to finance the reservoirs from which
the water is supplied. The bonds mature at various dates through 2011 and have
interest rates ranging from 5.50% to 7%. 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 June 30, 2003, issued for similar purposes, which had previously been
guaranteed by US Holdings. US Holdings is, however, contingently liable in the
unlikely event of default by the municipality.
Legal Proceedings
On April 28, 2003, a lawsuit was filed by a former employee of TXU
Portfolio Management in the United States District Court for the Northern
District of Texas, Dallas Division, against TXU Corp., TXU Energy and TXU
Portfolio Management. Plaintiff asserts claims under Section 806 of
Sarbanes-Oxley arising from plaintiff's employment termination and claims for
breach of contract relating to payment of certain bonuses. Plaintiff seeks back
pay, payment of bonuses and alternatively, reinstatement or future compensation,
including bonuses. TXU Corp. believes the plaintiff's claims are without merit.
The plaintiff was terminated as the result of a reduction in force, not as a
reaction to any concerns the plaintiff had expressed, and plaintiff was not in a
position with TXU Portfolio Management such that he had knowledge or information
that would qualify the plaintiff to evaluate TXU Corp.'s financial statements or
assess the adequacy of TXU Corp.'s financial disclosures. Thus, TXU Corp. does
not believe that there is any merit to the plaintiff's claims under
Sarbanes-Oxley. Accordingly, TXU Corp., TXU Energy and TXU Portfolio Management
intend to vigorously defend the litigation. While TXU Corp., TXU Energy and TXU
Portfolio Management dispute the plaintiff's claims, like any litigation, TXU
Corp. is unable to predict the outcome of this litigation or the possible loss
in the event of an adverse judgment.
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
14
conditions in late February 2003. On August 6, 2003, the complaint was amended
to omit one of the other defendants. 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. As with any litigation of this nature, US
Holdings is unable to estimate any possible loss or predict the outcome of this
action.
On March 10, 2003, a lawsuit was filed by Kimberly P. Killebrew in
the United States District Court for the Eastern District of Texas, Lufkin
Division, against TXU Corp. and TXU Portfolio Management, asserting generally
that defendants engaged in manipulation of the wholesale electric market, in
violation of antitrust and other laws. This lawsuit was not served on TXU Corp.
until mid-July 2003. This action is brought by an individual, alleged to be a
retail consumer of electricity, on behalf of herself and as a proposed
representative of a putative class of retail purchasers of electricity that are
similarly situated. US Holdings believes that the plaintiff likely lacks
standing to assert any antitrust claims against TXU Corp. or TXU Portfolio
Management, and that defendants have not violated antitrust laws or other laws
as claimed by the plaintiff. Therefore, US Holdings believes that plaintiff's
claims are without merit and plans to vigorously defend the lawsuit. As with any
litigation of this nature, however, 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 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.
US Holdings is unable to predict the outcome of any litigation related to this
matter.
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,
wholesale energy sales, retail energy sales and 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.
15
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 Six Months Ended
June 30, June 30,
------------------ ----------------
2003 2002 2003 2002
---- ---- ---- ----
Operating revenues:
TXU Energy.......................................... $ 2,045 $ 2,019 $ 3,851 $ 3,818
Oncor............................................... 486 500 992 994
Eliminations........................................ (351) (400) (731) (816)
------- ------- ------- -------
Consolidated.................................. $ 2,180 $ 2,119 $ 4,112 $ 3,996
======= ======= ======= =======
Regulated revenues included in operating revenues:
TXU Energy.......................................... $ -- $ -- $ -- $ --
Oncor............................................... 486 500 992 994
Eliminations........................................ (349) (397) (726) (813)
------- ------- ------- -------
Consolidated.................................. $ 137 $ 103 $ 266 $ 181
======= ======= ======= =======
Affiliated revenues included in operating revenues:
TXU Energy.......................................... $ 2 $ 3 $ 5 $ 3
Oncor............................................... 349 397 726 813
Eliminations........................................ (351) (400) (731) (816)
------- ------- ------- -------
Consolidated.................................. $ -- $ -- $ -- $ --
======= ======= ======= =======
Income before cumulative effect of changes in accounting
principles:
TXU Energy.......................................... $ 154 $ 183 $ 189 $ 370
Oncor............................................... 52 65 113 136
Other............................................... (5) (4) (12) (9)
------- ------- ------- -------
Consolidated.................................. $ 201 $ 244 $ 290 $ 497
======= ======= ======= =======
16
8. SUPPLEMENTARY FINANCIAL INFORMATION
Regulated Versus Unregulated Operations --
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
2003 2002 2003 2002
---- ---- ---- ----
Operating revenues:
Regulated.................................................. $ 486 $ 500 $ 992 $ 994
Unregulated................................................ 2,045 2,019 3,851 3,818
Intercompany sales eliminations - regulated................ (349) (397) (726) (813)
Intercompany sales eliminations - unregulated.............. (2) (3) (5) (3)
------ ------- -------- -------
Total operating revenues.............................. 2,180 2,119 4,112 3,996
------ ------- ------- -------
Costs and operating expenses:
Cost of energy sold and delivery fees - unregulated*........ 932 787 1,770 1,312
Operating costs - regulated................................. 176 167 349 319
Operating costs - unregulated............................... 185 177 378 339
Depreciation and amortization - regulated................... 68 67 137 131
Depreciation and amortization - unregulated................. 95 107 208 226
Selling, general and administrative expenses - regulated.... 48 53 97 110
Selling, general and administrative expenses - unregulated.. 153 216 297 436
Franchise and revenue-based taxes - regulated............... 60 62 120 128
Franchise and revenue-based taxes - unregulated............. 27 32 60 66
Other income................................................ (17) (14) (26) (17)
Other deductions............................................ 2 2 3 5
Interest income............................................. (4) - (9) (1)
Interest expense and other charges.......................... 157 105 308 210
------ ------- ------- -------
Total costs and expenses............................... 1,882 1,761 3,692 3,264
------ ------- ------- -------
Income before income taxes and cumulative effect of changes
in accounting principles....................................$ 298 $ 358 $ 420 $ 732
====== ======= ======= =======
* Includes cost of fuel consumed of $423 million and $358 million for the
three months ended June 30, 2003 and 2002, and $836 million and $617
million for the six months ended June 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 Six Months Ended
June 30, June 30,
------------------ ----------------
2003 2002 2003 2002
---- ---- ---- ----
Other income:
Net gain on sale of properties and businesses........... $ 15 $ 12 $ 21 $ 12
Lignite coal royalties.................................. -- -- -- 2
Allowance for funds used during construction............ 1 1 2 2
Other................................................... 1 1 3 1
------ ------ ------ ------
Total other income.................................. $ 17 $ 14 $ 26 $ 17
====== ====== ====== ======
Other deductions:
Equity in losses of unconsolidated subsidiaries......... $ -- $ -- $ -- $ 1
Loss on retirement of debt.............................. 1 1 1 1
Other................................................... 1 1 2 3
------ ------ ------ ------
Total other deductions.............................. $ 2 $ 2 $ 3 $ 5
====== ====== ====== ======
17
Interest Expense and Other Charges --
Three Months Ended Six Months Ended
June 30, June 30,
------------------ -----------------
2003 2002 2003 2002
---- ---- ---- ----
Interest...................................................... $ 152 $ 105 $ 298 $ 208
Amortization of deferred debt costs........................... 7 3 15 8
Allowance for borrowed funds used during construction
and capitalized interest.................................. (2) (3) (5) (6)
-------- -------- -------- -------
Total interest expense and other charges................ $ 157 $ 105 $ 308 $ 210
======== ======== ========= =======
Regulatory Assets and Liabilities --
June 30, December 31,
2003 2002
---- ----
Regulatory Assets:
Generation-related regulatory assets subject to securitization. $1,652 $1,652
Securities reacquisition costs................................. 124 124
Recoverable deferred income taxes -- net....................... 78 76
Other regulatory assets........................................ 99 46
------ ------
Total regulatory assets.................................... 1,953 1,898
------ ------
Regulatory Liabilities:
Liability related to excess mitigation credit.................. 91 170
Investment tax credit and protected excess deferred taxes...... 92 98
------ ------
Total regulatory liabilities............................... 183 268
------ ------
Net regulatory assets...................................... $1,770 $1,630
====== ======
Included above are assets of $1.8 billion at June 30, 2003 and
December 31, 2002, that were not earning a return. Of the assets not earning a
return, $1.652 billion is expected to be recovered over the term of the
securitization bonds expected to be issued by Oncor in the third quarter of 2003
and the first half of 2004 pursuant to the regulatory Settlement Plan. All other
regulatory assets have a remaining recovery period of 15 to 48 years.
Included in other regulatory assets as of June 30, 2003 was $41
million related to nuclear decommissioning liabilities.
Restricted Cash -- As of June 30, 2003, all of the restricted cash of
$210 million from the net proceeds of Oncor's issuance of senior secured notes
in December 2002 had been used to repay 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 June 30, 2003,
included $69 million held as collateral for letters of credit issued.
Accounts Receivable -- At June 30, 2003 and December 31, 2002,
accounts receivable of $1.2 billion and $1.4 billion are stated net of allowance
for uncollectible accounts of $65 million and $72 million, respectively. During
the six months ended 2003, bad debt expense was $37 million, account write-offs
were $42 million and other activity decreased the allowance for uncollectible
accounts by $2 million.
Accounts receivable included $573 million and $505 million of
unbilled revenues at June 30, 2003 and December 31, 2002, respectively.
Intangible Assets -- SFAS No. 142, "Goodwill and Other Intangible
Assets," became effective for US Holdings on January 1, 2002. SFAS No. 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 No. 142 also requires additional disclosures
regarding intangible assets (other than goodwill) that are amortized or not
amortized:
18
As of June 30, 2003 As of December 31, 2002
------------------------------ ----------------------------
Gross Gross
Carrying Accumulated Carrying Accumulated
Amount Amortization Net Amount Amortization Net
-------- ------------ ------ ------- ------------ -----
Amortized intangible assets (included in
property, plant and equipment):
Capitalized software.............. $387 $160 $227 $368 $131 $237
Land easements.................... 171 63 108 180 61 119
Mineral rights and other.......... 31 20 11 31 20 11
---- ---- ---- ---- ---- ----
Total....................... $589 $243 $346 $579 $212 $367
==== ==== ==== ==== ==== ====
Amortization expense for intangible assets was $29 million for the
six months ended June 30, 2003 and 2002.
At June 30, 2003 and December 31, 2002, goodwill of $558 million was
stated net of previously recorded accumulated amortization of $67 million.
Commodity Contracts -- At June 30, 2003 and December 31, 2002,
current and noncurrent commodity contract assets totaling $1.8 billion are
stated net of applicable credit (collection) and performance reserves totaling
$30 million and $43 million, respectively. Performance reserves are provided for
direct, incremental costs to settle the contracts.
Inventories by Major Category --
June 30, December 31,
2003 2002
--------- ---------
Materials and supplies...................................................... $ 210 $ 211
Fuel stock.................................................................. 68 70
Gas stored underground...................................................... 81 57
----- -----
Total inventories....................................................... $ 359 $ 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 June 30, 2003 and December 31,
2002, property, plant and equipment of $16.7 billion and $16.2 billion is stated
net of accumulated depreciation and amortization of $10.5 billion and $10.4
billion, respectively.
As of June 30, 2003, substantially all of Oncor's electric utility
property, plant and equipment (with a net book value of $6.2 billion) was
pledged as collateral for Oncor's first mortgage bonds and senior secured notes.
Derivatives and Hedges -- US Holdings experienced net hedge
ineffectiveness of $8 million and $14 million, reported as a gain in revenues,
for the three and six months ended June 30, 2003, respectively. For the three
and six months ended June 30, 2002, net hedge ineffectiveness of $25 million and
$33 million, respectively, was reported as a loss in revenues. Hedge
ineffectiveness is primarily related to hedges of anticipated sales from
baseload generation.
As of June 30, 2003, it is expected that $79 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.
19
Affiliate Transactions -- The following represent significant
affiliate transactions of US Holdings:
Average daily short-term advances from affiliates during the three
months ended June 30, 2003 and 2002 were $966 million and $1.3 billion,
respectively, and interest expense incurred on the advances was $8 million and
$9 million, respectively. Average daily short-term advances from affiliates
during the six months ended June 30, 2003 and 2002 were $917 million and $1.3
billion, respectively, and interest expense incurred on the advances was $13
million and $20 million, respectively. The average interest rates for the three
months ended June 30, 2003 and 2002 were 3.07% and 2.25%, respectively. The
average interest rates for the six months ended June 30, 2003 and 2002 were 2.7%
and 2.92%, 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 June 30, 2003 and 2002, these costs
totaled $86 million and $109 million, respectively, and for the six months ended
June 30, 2003 and 2002 totaled $175 million and $214 million, respectively.
These costs are reported in SG&A expenses.
US Holdings charges TXU Gas, a subsidiary of TXU Corp., for customer
and administrative services. For the three months ended June 30, 2003 and 2002,
these charges totaled $14 million and $15 million, respectively, and for the six
months ended June 30, 2003 and 2002 totaled $29 million for both periods. 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.
20
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 June 30, 2003, and the
related condensed statements of consolidated income and of comprehensive income
for the three-month and six-month periods ended June 30, 2003 and 2002 and the
condensed statements of consolidated cash flows for the six-month periods ended
June 30, 2003 and 2002. These financial statements are the responsibility of
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 2 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" and changed its method of accounting for certain
contracts with the rescission of Emerging Issues Task Force Issue 98-10
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities."
DELOITTE & TOUCHE LLP
Dallas, Texas
August 12, 2003
21
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
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 activity of the holding company, which consists
primarily of servicing approximately $160 million in debt.
Dollar amounts in the following tables are stated in millions of US
dollars, unless otherwise noted.
RESULTS OF OPERATIONS
Consolidated
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002
- -----------------------------------------------------------------------------
Reference is made to comparisons of results by business segment
following the discussion of consolidated results presented below.
US Holdings' operating revenues increased $61 million, or 3%, to $2.2
billion in 2003. The revenue growth reflected an increase in the TXU Energy
segment of $26 million and a decrease in the Oncor segment of $14 million, or
3%. Revenue performance in the TXU Energy segment reflected higher average
pricing, partially offset by the effect of lower sales volumes and lower results
from portfolio management activities, which included realized and unrealized
gains and losses on hedging transactions. The decline in revenues in the Oncor
segment reflected higher unbilled revenues in 2002 resulting from billing issues
associated with the transition to competition, as previously disclosed. This
decline was partially offset by higher fees associated with increased
disconnect/reconnect activities and higher transmission tariffs. Consolidated
revenue growth also reflected a $48 million reduction in the intercompany sales
elimination, reflecting lower sales by Oncor to TXU Energy as sales to
non-affiliated REPs increased.
Gross Margin
Three Months Ended
June 30,
-----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 2,180 100% $ 2,119 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 932 43% 787 37%
Operating costs................................... 361 16% 344 16%
Depreciation and amortization related to operating
assets........................................ 152 7% 166 8%
------- ----- ------- ------
Gross margin........................................... $ 735 34% $ 822 39%
======= ===== ======= ======
Gross margin is considered a key operating metric as it measures the
effect of changes in sales volumes and pricing versus the direct variable and
fixed costs of energy sold, whether generated or purchased, as well as the costs
to deliver energy.
The depreciation and amortization expense included in gross margin
excludes $11 million and $8 million of such expense for the three months ended
June 30, 2003 and 2002, respectively, that is not directly related to generation
and delivery property, plant and equipment.
22
Gross margin decreased $87 million, or 11%, to $735 million in 2003.
This decline was driven by the TXU Energy segment, reflecting lower sales
volumes, primarily in the large commercial/industrial business. Higher average
pricing was largely offset by higher costs of energy sold and lower results from
portfolio management activities. Mark-to-market accounting for commodity
contracts increased revenues and gross margin by $56 million in 2003 (as
compared to accounting on a settlement basis), and increased results by $134
million in 2002. Operating costs rose $17 million, or 5%, to $361 million
primarily due to higher transmission costs paid to other utilities and the
timing of repair and maintenance expenses.
A decrease in depreciation and amortization (including amounts shown
in the gross margin table above) of $11 million, or 6%, to $163 million
reflected adjusted depreciation rates related to TXU Energy's generation fleet
primarily from an extension of the estimated depreciable life of the nuclear
generation facility, to better reflect its useful life, partially offset by the
effect of investments in energy delivery facilities to support growth and normal
replacements of equipment.
SG&A expense decreased $68 million, or 25%, to $201 million in 2003.
The decrease was driven by the TXU Energy segment and reflected lower levels of
bad debt expense, reflecting reduction in the billing and collection delays
experienced in 2002 in connection with the transition to competition and cost
reductions, primarily lower staffing and related administrative expenses,
initiated in response to the completion of the transition to competition in
Texas, the industry-wide decline in portfolio management activities and the
expected deferral of deregulation of energy markets in other states. SG&A
expenses were also favorably impacted by lower activity in the small strategic
retail services business. Favorable comparisons of SG&A expenses are expected to
continue over the balance of 2003.
Franchise and revenue-based taxes decreased $7 million, or 7%, to $87
million due primarily to lower retail revenues on which gross receipts taxes are
based.
Other income increased $3 million to $17 million in 2003. Gains on
sales of properties and business were $15 million in 2003, including a net $3
million gain on the sale of certain retail commercial and industrial gas
operations, and $12 million in 2002.
Interest income of $4 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 other charges increased $52 million, or 50%, to
$157 million in 2003. The increase reflects $38 million due to higher average
interest rates resulting in part from the refinancing of short-term borrowings
with higher-rate long-term debt, $9 million due to higher average debt levels
reflecting actions taken to ensure ample liquidity and $5 million due to higher
amortization of debt discounts, primarily related to the TXU Energy exchangeable
subordinated notes.
The effective income tax rate was 32.6% in 2003 compared to 31.8% in
2002. The increase was driven by higher state income tax accruals.
Net income declined $43 million, or 18%, to $201 million in 2003.
This performance reflected a decline of $29 million, or 16%, to $154 million in
the TXU Energy segment driven by the decreased gross margin and higher interest
expense, partially offset by decreased SG&A expenses and depreciation. Net
income in the Oncor segment declined $13 million, or 20%, to $52 million due to
lower revenues and higher interest expense. Net pension and postretirement
benefit costs, reported in operating costs and SG&A expenses, reduced net income
by $17 million in 2003 and $10 million in 2002.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
- -------------------------------------------------------------------------
Reference is made to comparisons of results by business segment
following the discussion of consolidated results presented below.
23
US Holdings' operating revenues increased $116 million, or 3%, to
$4.1 billion in 2003. The revenue growth reflected an increase in the TXU Energy
segment of $33 million, or 1%, and a nominal decrease in the Oncor segment of $2
million. Revenues in the TXU Energy segment reflected higher average pricing and
higher results from portfolio management activities largely offset by the effect
of lower sales volumes. The decline in revenues in the Oncor segment reflected
higher unbilled revenues in 2002 resulting from billing issues associated with
the transition to competition, as previously disclosed. This decline was
partially offset by higher fees associated with increased disconnect/reconnect
activities and higher transmission tariffs. Consolidated revenue growth also
reflected an $87 million reduction in the intercompany sales elimination,
reflecting lower sales by Oncor to TXU Energy as sales to non-affiliated
REPs increased.
Gross Margin
Six Months Ended
June 30,
-----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 4,112 100% $ 3,996 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 1,770 43% 1,312 33%
Operating costs................................... 727 17% 658 16%
Depreciation and amortization related to operating
assets........................................ 320 8% 329 8%
------- ----- ------- ------
Gross margin........................................... $ 1,295 32% $ 1,697 43%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $25 million and $28 million of such expense for the six months ended
June 30, 2003 and 2002, respectively, that is not directly related to generation
and delivery property, plant and equipment.
Gross margin decreased $402 million, or 24%, to $1.3 billion in 2003.
This decline was driven by the TXU Energy segment, reflecting higher costs of
energy sold, which was partially offset by higher average pricing and higher
portfolio management results, as well as the effect of lower sales volumes.
Mark-to-market accounting for commodity contracts increased revenues and gross
margin by $33 million in 2003 (as compared to accounting on a settlement basis),
and decreased revenues and gross margin by $12 million in 2002. Operating costs
rose $69 million, or 10%, to $727 million primarily due to employee severance
costs, higher pension and postemployment costs, increased insurance expenses,
higher operating costs in the small strategic retail services business and
higher transmission costs paid to other utilities.
Depreciation and amortization (including amounts shown in the gross margin
table above) decreased $12 million, or 3%, to $345 million reflecting adjusted
depreciation rates related to TXU Energy's generation fleet, primarily from an
extension of the estimated depreciable life of the nuclear generation facility,
to better reflect its useful life, partially offset by the effect of investments
in delivery facilities to support growth and normal replacements of equipment.
SG&A expense decreased $152 million, or 28%, to $394 million in 2003.
The decrease was driven primarily by the TXU Energy segment and reflected lower
levels of bad debt expense, reflecting reduction in the billing and collection
delays experienced in 2002 in connection with the transition to competition, and
cost reduction initiatives as discussed above. Favorable comparisons of SG&A
expenses are expected to continue over the balance of 2003.
Franchise and revenue-based taxes decreased $14 million, or 7%, to
$180 million due primarily to lower retail revenues on which gross receipts
taxes are based.
Other income increased $9 million to $26 million in 2003. Gains from
sales of properties and businesses were $21 million in 2003, including a net $9
million gain on the sale of certain retail commercial and industrial gas
operations, and $12 million in 2002.
Other deductions decreased $2 million to $3 million in 2003 due
primarily to lower equity losses from an unconsolidated investment.
24
Interest income increased $8 million to $9 million in 2003, primarily
reflecting higher cash balances on hand as credit facilities were drawn down in
the fourth quarter of 2002 to enhance liquidity.
Interest expense and other charges increased $98 million, or 47%, to
$308 million in 2003. The increase reflects a $48 million increase due to higher
average interest rates resulting in part from the replacement of short-term
borrowings with higher-rate long-term debt, a $42 million increase due to higher
average debt levels reflecting actions taken to enhance liquidity, and a $10
million increase due higher amortization of discount related to the TXU Energy
exchangeable subordinated notes.
The effective income tax rate on income before cumulative effect of
changes in accounting principles decreased 1.2 points to 30.9% in 2003 from
32.1% in 2002 due primarily to comparable (to 2002) tax benefit amounts of
depletion allowances and amortization of investment tax credits on a lower
income base in 2003.
Income before cumulative effect of changes in accounting principles
declined $207 million, or 42%, to $290 million in 2003. This performance
reflected a decline of $181 million, or 49%, to $189 million in the TXU Energy
segment driven by the decreased gross margin and higher interest expense,
partially offset by decreased SG&A expenses. Net income in the Oncor segment
declined $23 million, or 17%, to $113 million driven by higher operating costs
and interest expense. TXU Energy's 2003 first quarter results also reflected a
$16 million (after tax) gain, primarily reported in revenues, on the settlement
of outstanding counterparty default events and $9 million (after tax) in
severance charges. Net pension and postretirement benefit costs, reported in
operating costs and SG&A expenses, reduced net income by $34 million in 2003 and
$20 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 six months ended June 30, 2003. The net increase,
excluding "cumulative effect of change in accounting principle" and "other
activity" as described below, of $33 million represents the net favorable effect
of mark-to-market accounting on earnings for the six months ended June 30, 2003.
This effect represents the difference between earnings under mark-to-market
accounting versus accounting for gains and losses upon settlement of the
contracts.
Balance of net commodity contract assets at December 31, 2002................. $ 316
Cumulative effect of change in accounting principle (1) ...................... (75)
Settlements of positions included in the opening balance (2) ................. (82)
Unrealized mark-to-market valuations of positions held at end of period (3)... 115
Other activity (4)............................................................ (17)
-----
Balance of net commodity contract assets at June 30, 2003 .................... $ 257
=====
--------------------------
(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 1 to Financial Statements.)
25
Maturity Table -- Of the net commodity contract asset balance above
at June 30, 2003, the amount representing unrealized mark-to-market net gains
that have been recognized in current and prior years' earnings is $291 million.
The offsetting net liability of $34 million included in the June 30, 2003
balance consists of unamortized net option premiums received. The following
table presents the unrealized mark-to-market balance at June 30, 2003, scheduled
by contractual settlement dates of the underlying positions.
Maturity dates of unrealized net mark-to-market balances at June 30, 2003
-------------------------------------------------------------------------
Maturity less Maturity in
than Maturity of Maturity of Excess of
Source of fair value 1 year 1-3 years 4-5 years 5 years Total
- ---------------------- ------------- ----------- ----------- ----------- -----
Prices actively quoted........... $ (7) $ - $ - $ - $ (7)
Prices provided by other
external sources............. 176 73 7 (1) 255
Prices based on models........... 30 13 - - 43
---- ---- --- ---- -----
Total............................ $199 $ 86 $ 7 $ (1) $ 291
==== ==== === ==== =====
Percentage of total fair value... 68% 30% 2% -% 100%
As the above table indicates, approximately 98% of the unrealized
mark-to-market valuations at June 30, 2003 mature within three years. This is
reflective of the terms of the positions and the methodologies employed in
valuing positions for periods where there is less market liquidity and
visibility. The "prices actively quoted" category reflects only exchange traded
contracts with active quotes available through 2005. The "prices provided by
other external sources" category represents forward commodity positions at
locations for which over-the-counter broker quotes are available.
Over-the-counter quotes for power and natural gas generally extend through 2005
and 2012, respectively. 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.
26
SEGMENTS
TXU Energy
Financial Results
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- -------------------
2003 2002 2003 2002
--------- -------- -------- -------
Operating revenues.......................................... $ 2,045 $ 2,019 $ 3,851 $ 3,818
------- ------- ------- -------
Costs and expenses:
Cost of energy sold and delivery fees.................. 1,282 1,185 2,500 2,126
Operating costs........................................ 186 178 379 340
Depreciation and amortization.......................... 95 107 208 226
Selling, general and administrative expenses........... 153 217 297 437
Franchise and revenue-based taxes ..................... 27 26 55 56
Other income .......................................... (16) (13) (24) (15)
Other deductions....................................... 3 2 5 5
Interest income........................................ (1) - (3) (9)
Interest expense and other charges..................... 86 50 163 109
------- ------- ------- -------
Total costs and expenses........................... 1,815 1,752 3,580 3,275
------- ------- ------- -------
Income before income taxes and cumulative effect of
changes in accounting principles........................ 230 267 271 543
Income tax expense.......................................... 76 84 82 173
------- ------- ------- -------
Income before cumulative effect of changes in accounting
principles................................................ $ 154 $ 183 $ 189 $ 370
======= ======= ======= =======
27
TXU Energy
Segment Highlights
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
2003 2002 2003 2002
---- ---- ---- ----
Operating statistics:
Retail electric sales volumes (GWh) ........................ 19,804 22,771 39,202 45,157
Wholesale electric sales volumes (GWh)...................... 8,384 7,115 15,835 13,314
Retail electric customers (end of period & in thousands-
number of meters)......................................... 2,649 2,731
Operating revenues (millions of dollars):
Retail electric:
Residential........................................... $ 808 $ 781 $ 1,492 $ 1,476
Commercial and industrial ............................ 832 831 1,580 1,881
------- ------- ------- -------
Total........................................... 1,640 1,612 3,072 3,357
Wholesale electric ......................................... 281 209 518 355
Portfolio management activities............................. 62 112 153 49
Other revenues.............................................. 62 86 108 57
------- ------- ------- -------
Total operating revenues......................... $ 2,045 $ 2,019 $ 3,851 $ 3,818
======= ======= ======= =======
Weather (average for service territory)
Percent of normal:
Cooling degree days............................... 107.0% 106.6% 104.7% 106.1%
Heating degree days............................... 64.0% 69.0% 103.9% 99.2%
- --------------------------
Weather data is obtained from Meteorlogix, a private company that collects
weather data from reporting stations of the National Oceanic and Atmospheric
Administration (a federal agency under the US Department of Commerce).
28
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002
- -----------------------------------------------------------------------------
Effective with reporting for 2003, results for the segment exclude
expenses incurred by the US Holdings parent company in order to present the
segment on the same basis as the separate reporting (on Form 8-K) for TXU Energy
and as the results of the business are evaluated by management. The activities
of the parent company consist primarily of the servicing of approximately $160
million of debt. Prior year amounts are presented on the revised basis.
Operating revenues increased $26 million, or 1%, to $2.0 billion in
2003. Retail and wholesale electric revenues increased $100 million, or 5%, to
$1.9 billion, reflecting a $203 million increase due to higher average prices
partially offset by a $103 million reduction due to lower sales volumes. The
price variance primarily reflects the effect of increased price-to-beat rates,
due to approved fuel factor increases and higher pricing in the large commercial
and industrial business, both resulting from higher natural gas costs. The
volume variance primarily reflects a 13% decline in overall retail electric
sales volumes due to the effects of increased competitive activity, primarily in
the large commercial and industrial segment of the market. The effect of lower
retail volumes was partially offset by an 18% increase in wholesale electric
volumes, reflecting a partial shift in the large commercial and industrial
customer base from retail to wholesale services. Results from portfolio
management activities, which include realized and unrealized gains and losses on
hedging transactions, declined $50 million due primarily to the effect of less
favorable price movements on commodity contract positions. Other revenues
declined $24 million due largely to the effect of discontinuing recognition of
origination gains on commercial/industrial retail contracts.
Gross Margin
Three Months Ended
June 30,
---------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 2,045 100% $ 2,019 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 1,282 63% 1,185 59%
Operating costs................................... 186 9% 178 9%
Depreciation and amortization related to generation
assets........................................ 87 4% 102 5%
------- ----- ------- ------
Gross margin........................................... $ 490 24% $ 554 27%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $8 million and $5 million of such expense for the three months ended
June 30, 2003 and 2002, respectively, that is not directly related to generation
property, plant and equipment.
Gross margin decreased $64 million, or 12%, to $490 million in 2003.
The decrease was driven by lower retail sales volumes, primarily in the large
commercial/industrial business. Higher average pricing was largely offset by
higher costs of energy sold and lower portfolio management results. Increased
power costs reflected higher natural gas costs and an outage at the nuclear
generation plant as a result of a lightning strike on a transmission line.
Mark-to-market accounting for commodity contracts increased revenues and gross
margin by $56 million in 2003 and by $134 million in 2002 (as compared to
accounting on a settlement basis). Operating costs rose $8 million, or 4%, to
$186 million primarily due to the timing of repair and maintenance expenses.
In July 2003, an unexpected outage occurred in one of the units at
the Comanche Peak nuclear generation facility in order to repair a reactor
coolant water pump, resulting in approximately $20 million in higher costs of
energy sold that will be reflected in third quarter results.
In July 2003, TXU Energy filed a request with the Commission to
raise its price-to-beat rates as a result of higher natural gas prices. The
Commission has 45 days from the filing of the request, or as soon as practical
thereafter, to review the request, which would increase revenues by an estimated
$180 million on an annualized basis ($50 million for the remainder of 2003, if
approved in mid-September).
29
A decrease in depreciation and amortization (including amounts shown
in the gross margin table above) of $12 million, or 11%, to $95 million in 2003
included a $13 million decline due to adjusted depreciation rates related to TXU
Energy's generation fleet effective with second quarter reporting. This
adjustment reflects an extension in the estimated depreciable life of its
nuclear generation facility of approximately 11 years (to 2041) to better
reflect its useful life, partially offset by higher depreciation rates for
lignite and gas facilities to reflect investments made in recent years.
A decrease in SG&A expenses of $64 million, or 29%, to $153 million
in 2003 was driven by cost reductions, primarily lower staffing and related
administrative expenses, initiated in response to the completion of the
transition to competition in Texas, the industry-wide decline in portfolio
management activities and the expected deferral of deregulation of energy
markets in other states. Lower SG&A expenses also reflected lower levels of bad
debt expense, reflecting reduction in billing and collection delays experienced
in 2002 in connection with the transition to competition. SG&A expenses were
also favorably impacted by lower activity in the small strategic retail services
business. Favorable comparisons of SG&A expenses are expected to continue over
the balance of 2003.
Other income increased by $3 million to $16 million in 2003. Other
income included net gains on sales of properties and businesses of $15 million
in 2003, including a $3 million net gain on the sale of certain retail
commercial and industrial gas operations, and $12 million in 2002.
Interest expense and other charges increased $36 million, or 72%, to
$86 million in 2003. The increase reflects $28 million due to higher average
interest rates, including credit line fees, $3 million due to higher average
debt levels and $5 million in amortization of the discount on the exchangeable
subordinated notes issued by TXU Energy in November 2002. Higher average
interest rates were due in part to replacement of short-term borrowings with
higher rate long-term debt.
The effective tax rate increased to 33.0% in 2003 from 31.5% in
2002. The increase was driven by higher state income tax accruals.
Income before cumulative effect of changes in accounting principles
decreased $29 million, or 16%, to $154 million in 2003. The decline was driven
by the decrease in gross margin and the increase in interest expense, partially
offset by decreased SG&A and depreciation and amortization expenses. Net pension
and postretirement benefit costs reduced net income by $9 million in 2003 and $5
million in 2002.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
- -------------------------------------------------------------------------
Operating revenues increased $33 million, or 1%, to $3.9 billion in
2003. Retail and wholesale electric revenues declined $122 million, or 3%, to
$3.6 billion, reflecting a $218 million reduction due to lower volumes partially
offset by a $96 million increase due to higher average prices. The volume
variance primarily reflects a 13% decline in overall retail electric sales
volumes due to the effects of increased competitive activity, primarily in the
large commercial and industrial segment of the market. The effect of lower
retail volumes was partially offset by a 19% increase in wholesale electric
volumes reflecting a partial shift in the large commercial and industrial
customer base from retail to wholesale services. The price variance reflects the
effect of increased price-to-beat rates and higher wholesale electric sales
prices, both resulting from higher natural gas prices. Results from portfolio
management activities, which include realized and unrealized gains and losses on
hedging transactions, rose $104 million due primarily to the effect of more
favorable price movements on commodity contract positions. Other revenues
increased $51 million due in part to activity in the small strategic retail
services business.
Gross Margin
Six Months Ended
June 30,
------------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 3,851 100% $ 3,818 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 2,500 65% 2,126 56%
Operating costs................................... 379 10% 340 9%
Depreciation and amortization related to generation
assets........................................ 189 5% 203 5%
------- ----- ------- ------
Gross margin........................................... $ 783 20% $ 1,149 30%
======= ===== ======= ======
30
The depreciation and amortization expense included in gross margin
excludes $19 million and $23 million of such expense for the six months ended
June 30, 2003 and 2002, respectively, that is not directly related to generation
property, plant and equipment.
Gross margin decreased $366 million, or 32%, to $783 million in
2003. The decrease reflected the effect of increased costs of energy sold that
exceeded higher average pricing and higher portfolio management results. Lower
retail sales volumes, primarily in the large commercial/industrial business,
also contributed to the decline in margin. Increased power costs reflected
higher natural gas costs and an outage at the nuclear generation plant as a
result of a lightning strike on a transmission line. Mark-to-market accounting
for commodity contracts increased revenues and gross margin by $33 million in
2003 and decreased results by $12 million in 2002 (as compared to accounting on
a settlement basis). Operating costs rose $39 million, or 11%, to $379 million
primarily due to the timing of repair and maintenance expenses, higher costs in
the small strategic retail services business, higher pension and other
postretirement benefit expenses and employee severance costs associated with
cost reduction initiatives.
In July 2003, an unexpected outage occurred in one of the units at
the Comanche Peak nuclear generation facility in order to repair a reactor
coolant water pump, resulting in approximately $20 million in higher costs of
energy sold that will be reflected in third quarter results.
In July 2003, TXU Energy filed a request with the Commission to
raise its price-to-beat rates as a result of higher natural gas prices. The
Commission has 45 days from the filing of the request, or as soon as practical
thereafter, to review the request, which would increase revenues by an estimated
$180 million on an annualized basis ($50 million for the remainder of 2003, if
approved in mid-September).
A decrease in depreciation and amortization (including amounts shown
in the gross margin table above) of $18 million, or 8%, to $208 million in 2003
was primarily due to a $13 million decline due to adjusted depreciation rates
related to TXU Energy's generation fleet as discussed above and the timing of
intangible asset amortization expense during the 2002 year.
A decrease in SG&A expenses of $140 million, or 32%, to $297 million
in 2003 was driven by lower levels of bad debt expense, reflecting reduction in
billing and collection delays experienced in 2002 in connection with the
transition to competition, and cost reduction initiatives as discussed above.
Favorable comparisons of SG&A expenses are expected to continue over the balance
of 2003.
Other income increased by $9 million to $24 million in 2003. Other
income included net gains on sales of properties and businesses of $21 million
in 2003, including a $9 million gain on the sale of certain retail commercial
and industrial gas operations, and $12 million in 2002.
Interest income declined by $6 million, or 67%, to $3 million in
2003 primarily due to lower average advances to affiliates.
Interest expense and other charges increased $54 million, or 50%, to
$163 million in 2003. The increase reflects $33 million due to higher average
interest rates, including credit line fees, $11 million due to higher average
debt levels and $10 million in amortization of the discount on the exchangeable
subordinated notes issued by TXU Energy in November 2002. Higher average
interest rates were due in part to replacement of short-term borrowings with
higher rate long-term debt.
The effective tax rate decreased to 30.3% in 2003 from 31.9% in
2002. The decrease was driven by the effect of comparable (to 2002) tax benefit
amounts of depletion allowances and amortization of investment tax credits on a
lower income base in 2003.
31
Income before cumulative effect of changes in accounting principles
decreased $181 million, or 49%, to $189 million in 2003. The decline was driven
by the decrease in gross margin and the increase in interest expense, partially
offset by decreased SG&A and depreciation and amortization expenses. Results for
the six months reflected a $16 million (after-tax) gain on the settlement of
outstanding counterparty default events and $9 million (after-tax) in severance
charges. Net pension and postretirement benefit costs reduced net income by $18
million in 2003 and by $11 million in 2002.
32
Oncor
- -----
Financial Results
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ----------------
2003 2002 2003 2002
---- ----- ---- ----
Operating revenues....................................... $486 $500 $ 992 $ 994
---- ---- ----- -----
Costs and expenses:
Operating costs..................................... 176 167 349 319
Depreciation and amortization....................... 68 67 137 131
Selling, general and administrative expenses........ 48 53 97 110
Franchise and revenue-based taxes................... 60 62 120 128
Other income........................................ (2) (1) (4) (2)
Interest income..................................... (14) (11) (29) (23)
Interest expense and other charges.................. 75 65 155 127
---- ---- ----- -----
Total cost and expenses ........................ 411 402 825 790
---- ---- ----- -----
Income before income taxes............................... 75 98 167 204
Income tax expense....................................... 23 33 54 68
---- ---- ----- -----
Net Income............................................... $ 52 $ 65 $ 113 $ 136
==== ==== ===== =====
33
Segment Highlights
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2003 2002 2003 2002
---- ---- ---- ----
Operating statistics:
Electric energy delivered (GWh)................................. 24,378 26,232 48,286 49,818
Electric points of delivery (end of period and in thousands).... 2,909 2,887
Operating revenues (millions of dollars):
TXU Energy.................................................. $ 349 $ 397 $ 726 $ 813
Non-affiliated.............................................. 137 103 266 181
----- ------ ----- -----
Total electric energy delivery...................... $ 486 $ 500 $ 992 $ 994
===== ====== ===== =====
Three Months Ended June 30, 2003 Compared to Three Months Ended June 30, 2002
- -----------------------------------------------------------------------------
The Oncor segment's operating revenues decreased $14 million, or 3%,
to $486 million in 2003. The decrease reflected higher unbilled revenues in 2002
resulting from billing issues associated with the transition to competition, as
previously disclosed. Delivered electricity volumes for the year 2003 are
expected to grow 2% over 2002 levels. The revenue decline was partially offset
by $8 million in increased disconnect/reconnect fees due to new POLR rules in
2003 and greater competition-related customer switching activities and $2
million in higher transmission revenues due to increased tariffs. Increased
transmission tariffs approved by the Commission and effective in May 2003 and a
related increase in wholesale distribution rates, expected to be approved by the
Commission in the third quarter of 2003, are expected to result in an estimated
$44 million in incremental revenues on an annualized basis.
Gross Margin
Three Months Ended
June 30,
----------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 486 100% $ 500 100%
Costs and expenses:
Operating costs................................... 176 36% 167 33%
Depreciation and amortization related to transmission
and distribution assets....................... 65 14% 64 13%
------- ----- ------- ------
Gross margin........................................... $ 245 50% $ 269 54%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $3 million of such expense for the three months ended June 30, 2003 and
2002 that is not directly related to delivery property, plant and equipment.
Gross margin decreased $24 million, or 9%, to $245 million in 2003,
driven by lower revenues and higher operating costs. The increase in operating
costs of $9 million, or 5%, to $176 million primarily reflects higher
transmission costs paid to other utilities.
Depreciation and amortization (including amounts shown in the gross
margin table above), increased $1 million, or 1%, to $68 million. The increase
reflects investments in delivery facilities to support growth and normal
replacements of equipment.
SG&A expenses decreased $5 million, or 9%, to $48 million due
primarily to lower employee-related and outside consulting expenses arising from
cost saving initiatives implemented in late 2002 and the completion of
competitive market transition activities.
34
Franchise and revenue-based taxes declined $2 million, or 3%, to $60
million in 2003 due primarily to lower revenues on which gross receipts taxes
are based.
Interest income increased $3 million in 2003 due primarily to higher
interest reimbursements from TXU Energy. This increase reflects higher carrying
costs ($7 million) on regulatory assets (see discussion of higher average
interest rates below), partially offset by lower interest ($4 million) on the
note receivable related to the excess mitigation credit. The note principal has
declined as the credit nears the year-end 2003 expiration date.
Interest expense and other charges increased by $10 million, or 15%,
to $75 million in 2003. Of the change, $7 million was due to higher average
interest rates and $6 million was due to higher average borrowings, partially
offset by $4 million less interest passed to REPs related to the excess
mitigation credit. The increase in average interest rates reflected the
refinancing of affiliate borrowings with higher rate long-term debt issuances.
The effective tax rate decreased 3 points to 30.7% in 2003 from 33.7%
in 2002, due primarily to comparable amortization of investment tax credits and
other items for tax purposes on lower pre-tax earnings.
Net income decreased $13 million, or 20%, to $52 million in 2003,
primarily due to lower revenues and higher interest expense. Net pension and
postretirement benefit costs reduced net income by $8 million in 2003 and $6
million in 2002.
Six Months Ended June 30, 2003 Compared to Six Months Ended June 30, 2002
- -------------------------------------------------------------------------
The Oncor segment's operating revenues decreased $2 million to $992
million in 2003. The decrease reflected higher unbilled revenue in 2002
resulting from billing issues associated with the transition to competition, as
previously disclosed. Delivered electricity volumes for the year 2003 are
expected to grow 2% over 2002 levels. The revenue decline was partially offset
by $14 million in increased disconnect/reconnect fees due to the new POLR rules
in 2003 and greater competition-related customer switching activities, $3
million in nonrecurring billing settlements for tower space leases with
telecommunications companies and pole contract rentals from cable and
telecommunication companies, and $2 million in higher transmission revenues due
to increased tariffs. Increased wholesale transmission rates approved by the
Commission and effective in May 2003 and a related increase in distribution
tariffs, expected to be approved by the Commission in the third quarter of 2003,
are expected to result in an estimated $44 million in incremental revenues on an
annualized basis.
Gross Margin
Six Months Ended
June 30,
------------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 992 100% $ 994 100%
Costs and expenses:
Operating costs................................... 349 35% 319 32%
Depreciation and amortization related to transmission
and distribution assets....................... 131 13% 126 13%
------- ----- ------- ------
Gross margin........................................... $ 512 52% $ 549 55%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $6 million and $5 million of such expense for the six months ended June
30, 2003 and 2002, respectively, that is not directly related to delivery
property, plant and equipment.
Gross margin decreased $37 million, or 7%, to $512 million in 2003,
driven by higher operating costs. The increase in operating costs of $30
million, or 9%, to $349 million primarily reflects higher transmission costs
paid to other utilities and higher pension and other postretirement benefit
costs.
35
Depreciation and amortization (including amounts shown in the gross
margin table above), increased $6 million, or 5%, to $137 million. The increase
reflects investments in delivery facilities to support growth and normal
replacements of equipment.
SG&A expenses decreased $13 million, or 12%, to $97 million due
primarily to lower employee-related and outside consulting expenses arising from
cost saving initiatives implemented in late 2002.
Franchise and revenue-based taxes declined $8 million, or 6%, to $120
million in 2003 due primarily to lower revenues on which gross receipts taxes
are based.
Interest income increased $6 million in 2003 reflecting a $13 million
increase in the reimbursement from the TXU Energy segment. This increase
reflects higher carrying costs on regulatory assets (see discussion of higher
average interest rates below), partially offset by $7 million less interest on
the note receivable related to the excess mitigation credit. The note principal
has declined as the credit nears the year-end 2003 expiration date.
Interest expense and other charges increased by $28 million, or 22%,
to $155 million in 2003. Of the change, $24 million was due to higher average
interest rates and $11 million was due to higher average borrowings, partially
offset by $7 million less interest on the excess mitigation credit passed to
REPs. The higher average interest rates reflected issuances of long-term debt to
replace lower rate advances from affiliates.
The effective tax rate decreased 1 point to 32.3% in 2003 from 33.3%
in 2002, due to comparable amortization for tax purposes on lower pre-tax
earnings.
Net income decreased $23 million, or 17%, to $113 million in 2003,
primarily due to higher operating costs and interest expense. Net pension and
postretirement benefit costs reduced net income by $16 million in 2003 and $9
million in 2002.
COMPREHENSIVE INCOME
For the three months ended June 30, 2003 and 2002, changes in the
fair value of derivatives effective as cash flow hedges reflected losses of $31
million ($20 million after-tax) and $104 million ($68 million after-tax),
respectively. Losses in 2003 were due to decreases in the fair value of
commodity hedges, while losses in 2002 were primarily due to decreases in the
fair value of interest rate hedges because of lower interest rates.
For the six months ended June 30, 2003 and 2002, changes in the fair
value of derivatives effective as cash flow hedges reflected losses of $151
million ($98 million after-tax) and $171 million ($111 million after-tax),
respectively. Losses in 2003 were due to decreases in the fair value of
commodity hedges, while losses in 2002 were due to decreases in the fair value
of commodity hedges of $89 million ($58 million after-tax) and decreases in the
fair value of interest rate hedges because of lower interest rates of $82
million ($53 million after-tax).
For the three months ended June 30, 2003 and 2002, amounts realized in
earnings for cash flow hedges were losses of $35 million ($23 million after-tax)
and gains of $1 million, respectively. For the six months ended June 30, 2003
and 2002, amounts realized in earnings for cash flow hedges reflected losses of
$111 million ($72 million after-tax) and gains of $5 million ($3 million
after-tax), respectively. Losses and gains realized in earnings reflected the
recognition of hedge effects as the underlying hedged transactions were settled.
FINANCIAL CONDITION
Liquidity and Capital Resources
For information concerning liquidity and capital resources, see Item
7. Management's Discussion and Analysis of Financial Condition and Results of
Operations in 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.
36
Cash Flows -- Cash flows provided by operating activities for the
first six months of 2003 were $675 million compared to $451 million for 2002.
The increase in cash flows provided by operating activities in 2003 of $224
million, or 50%, reflected favorable working capital changes (accounts
receivable, accounts payable and inventories) of $629 million, partially offset
by lower cash earnings of $229 million (net income adjusted for the significant
noncash reconciling 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 effects of billing and collection delays
in 2002 associated with the transition to competition.
Cash flows used in financing activities in 2003 were $1.1 billion
compared to $345 million in 2002. Repayments of borrowings under credit
facilities totaled $1.8 billion in 2003. Cash dividends or share repurchase
payments to TXU Corp. totaled $500 million in 2003 compared to $427 million in
2002. Debt issuances in 2003, net of redemption deposit payments (restricted
cash), generated cash of approximately $1.0 billion, reflecting issuance of
senior notes in a private offering by TXU Energy, to establish long-term
financing to replace the credit facilities drawn down in the fourth quarter of
2002 to enhance liquidity. Debt retirements and repayments, net of issuances,
totaled $141 million in 2002. Repayments of affiliate borrowings totaled $686
million in 2002 and borrowings under credit facilities provided $938 million in
2002.
Cash flows used in investing activities were $364 million in 2003
compared to $124 million in 2002. Capital expenditures declined to $350 million
in 2003 from $415 million in 2002, driven by lower development spending by TXU
Energy. Purchases of nuclear fuel were $35 million in 2003 compared to $50
million in 2002. Proceeds from the sale of certain retail commercial and
industrial gas operations provided $15 million in 2003, compared to $443 million
from the sale in 2002 of two generation plants in Texas.
Depreciation and amortization expense reported in the statement of
cash flows exceeds the amount reported in the statement of income by $37
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 June
30, 2003, consisted of 4% exchangeable subordinated notes ($491 million), 49%
other long-term debt, less amounts due currently ($7.0 billion), 1% preferred
stock of subsidiaries not subject to mandatory redemption ($115 million) and 46%
common stock equity ($6.5 billion).
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 Securities and Exchange Commission for
offering pursuant to Rule 415 under the Securities Act of 1933.
Credit Facilities -- At June 30, 2003, US Holdings had
outstanding short-term borrowings consisting of advances from affiliates of $736
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 3.07% and 2.44% at June 30, 2003
and December 31, 2002, respectively.
37
At June 30, 2003, US Holdings had credit facilities as follows:
At June 30, 2003
--------------------------------------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
- -------- --------------- --------- ----- ------ ---------- ------------
Five-Year Revolving Credit Facility February 2005 US Holdings $ 1,400 $ 391 $ -- $1,009
Revolving Credit Facility February 2005 TXU Energy, Oncor 450 21 -- 429
Three-Year Revolving Credit Facility May 2005 US Holdings 400 -- -- 400
------- ------ ------ ------
Total North America $ 2,250 $ 412 $ -- $1,838
======= ====== ====== ======
In August 2003, TXU Corp. entered into a $500 million 5-year
revolving credit facility with LOC 2003 Trust, a special purpose, wholly-owned
subsidiary of TXU Corp. (LOC Trust). LOC Trust, in turn, entered into a $500
million 5-year secured credit facility with a group of lenders. TXU Corp.
intends to capitalize LOC Trust with approximately $525 million of cash, which
will be invested by the lenders in permitted investments as directed by LOC
Trust. LOC Trust's assets, including the investments, will constitute collateral
for the benefit of the lenders to secure issuances of letters of credit or
loans, and will be owned by LOC Trust. During the term of the facility, LOC
Trust will be required to maintain collateral in an amount equal to 105% of the
commitments under the secured facility. Upon capitalization by LOC Trust,
TXU Corp. may request up to $500 million of letters of credit or up to
$250 million of loans from LOC Trust, subject in aggregate to its $500 million
commitment, for the benefit of TXU Corp. and its subsidiaries, which may be
provided through issuances of letters of credit or loans by the lenders.
LOC Trust's assets are not available to satisfy claims of creditors of TXU Corp.
or its subsidiaries. However, LOC Trust may terminate all or a portion of the
secured facility at any time and request the release of any collateral not
required to secure outstanding letters of credit from the lenders.
Through April 2003, $1.8 billion in outstanding cash borrowings as of
December 31, 2002 under the credit facilities were repaid, and the facilities
were restructured. A $450 million revolving credit facility was established for
TXU Energy and Oncor that matures on February 25, 2005. This facility will be
used for working capital and other general corporate purposes, including letters
of credit, and replaces the $1 billion 364-day revolving credit facility that
expired in April 2003. Up to $450 million of letters of credit may be issued
under the facility.
This facility, as well as others available to US Holdings, will
provide back-up for any future issuance of commercial paper by TXU Energy and
Oncor. At June 30, 2003, there was no outstanding commercial paper under the
credit facilities.
In connection with the restructuring of the North America credit
facilities of TXU Corp., in April 2003:
o Oncor cancelled its undrawn $150 million secured 364-day credit
facility that was scheduled to expire in December 2003.
o US Holdings replaced TXU Corp. as the borrower under the $500
million three-year revolving credit facility. Concurrently, the
facility was reduced to $400 million.
o US Holdings' $1.4 billion five-year revolving credit facility was
amended. Among other things, the amendment increased the amount of
letters of credit allowed to be issued under the facility to $1
billion from $500 million.
38
In addition to providing back-up of commercial paper issuances by TXU
Energy and Oncor, the North America facilities above are for general corporate
and working capital purposes, including providing collateral support for TXU
Energy portfolio management activities.
Long-term Debt -- During the six months ended June 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............................. $ -- $ 306
Medium term notes................................ -- 15
TXU Energy:
Fixed rate senior notes.......................... 1,250 72
Pollution control revenue bonds.................. 44 97
------ ------
$1,294 $ 490
====== ======
See Notes 3, 4 and 5 to Financial Statements for further detail of
debt issuance and retirements, financing arrangements, and capitalization.
Sale of Receivables -- Certain subsidiaries of TXU Corp. sell trade
accounts receivable to TXU Receivables Company, a wholly-owned bankruptcy remote
subsidiary of TXU Corp., which sells undivided interests in accounts receivable
it purchases to financial institutions. As of June 30, 2003, TXU Energy (through
certain subsidiaries), Oncor and TXU Gas are qualified originators of accounts
receivable under the program. TXU Receivables Company may sell up to an
aggregate of $600 million in undivided interests in the receivables purchased
from the originators under the program. The June 30, 2003 financial statements
reflect the sale of $1.1 billion face amount of US Holdings' receivables to TXU
Receivables Company under the program in exchange for cash of $494 million and
$563 million in subordinated notes, with $10 million of losses on sales for the
six months ended June 30, 2003 that principally represents the interest costs on
the underlying financing. These losses approximated 6% of the cash proceeds from
the sale of undivided interests in accounts receivable on an annualized basis.
Funding under the program increased $47 million for the six month period ended
June 30, 2003 primarily due to reserve requirements that were reduced through a
temporary amendment in recognition of improving collection trends. Higher loss
reserve requirements in previous periods reflected the billing and collection
delays previously experienced as a result of new systems and processes in TXU
Energy and ERCOT for clearing customers' switching and billing data upon the
transition to competition. Funding increases or decreases under the program are
reflected as cash provided by or used in operating activities.
Upon termination, cash flows to the originators would be delayed as
collections of sold receivables would be used by TXU Receivables Company to
repurchase the undivided interests of the financial institutions instead of
purchasing new receivables. The level of cash flows would normalize in
approximately 16 to 31 days. TXU Business Services Company, a subsidiary of TXU
Corp., services the purchased receivables and is paid a market based servicing
fee by TXU Receivables Company. The subordinated notes receivable from TXU
Receivables Company represent TXU Corp.'s subsidiaries' retained interests in
the transferred receivables and are recorded at book value, net of allowances
for bad debts, which approximates fair value due to the short-term nature of the
subordinated notes, and are included in accounts receivable in the consolidated
balance sheet.
In August 2003, the program was amended to extend the term to July
2004, as well as to extend the period providing temporarily higher delinquency
and default compliance ratios through December 31, 2003. The program was also
amended to coincide with the credit facilities' covenants by removing investment
grade credit ratings as a requirement of an eligible originator and substituting
maintenance of fixed charge coverage ratios and debt to capital ratios as
requirements of an eligible originator. In June 2003, the program was amended to
provide temporarily higher delinquency and default compliance ratios and
temporary relief from the loss reserve formula. The June amendment reflected the
billing and collection delays previously experienced as a result of new systems
and processes in TXU Energy and ERCOT for clearing customers' switching and
billing data upon the transition to competition.
39
Contingencies Related to Receivables Program -- Although TXU
Receivables Company expects to be able to pay its subordinated notes from the
collections of purchased receivables, these notes are subordinated to the
undivided interests of the financial institutions in those receivables, and
collections might not be sufficient to pay the subordinated notes. The program
may be terminated if either of the following events occurs:
1) each of the originators cease to maintain their required fixed
charge coverage ratio and debt to capital (leverage) ratio;
2) the delinquency ratio (delinquent for 31 days) for the sold
receivables, the default ratio (delinquent for 91 days or deemed
uncollectible), the dilution ratio (reductions for discounts,
disputes and other allowances) or the days collection outstanding
ratio exceed stated thresholds and the financial institutions do not
waive such event of termination. The thresholds apply to the entire
portfolio of sold receivables, not separately to the receivables of
each originator.
The delinquency and dilution ratios exceeded the relevant thresholds
during the first four months of 2003, but waivers were granted. These ratios
were affected by issues related to the transition to deregulation. Certain
billing and collection delays arose due to implementation of new systems and
processes within TXU Energy and ERCOT for clearing customers' switching and
billing data. The billing delays have been resolved but, while improving, the
lagging collection issues continue to impact the ratios. The implementation of
new POLR rules by the Commission and strengthened credit and collection policies
and practices are expected to bring the ratios into consistent compliance with
the program.
Under the receivables sale program, all the originators are required
to maintain specified fixed charge coverage and leverage ratios (or supply a
parent guarantor with similar ratios). Prior to the August 2003 amendment
extending the program, originator eligibility was predicated on the maintenance
of an investment grade credit rating. 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.
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
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 June 30, 2003, US Holdings and its subsidiaries were in
compliance with all such applicable covenants.
40
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 $135 million at June 30, 2003) for its headquarters
building. In the event of a downgrade of TXU Energy's credit rating to below
investment grade, a letter of credit would need to be provided within 30 days of
any such ratings decline.
TXU Energy has entered into certain commodity contracts and lease
arrangements that in some instances give the other party the right, but not the
obligation, to request TXU Energy to post collateral in the event that its
credit rating falls below investment grade.
Based on its current commodity contract positions, if TXU Energy were
downgraded below investment grade by any specified rating agency, counterparties
would have the option to request TXU Energy to post additional collateral of
approximately $204 million.
In addition, TXU Energy has a number of other contractual
arrangements where the counterparties would have the right to request TXU Energy
to post collateral if its credit rating was downgraded below investment grade by
any specified rating agency. The amount TXU Energy would post under these
transactions depends in part on the value of the contracts at that time. As of
June 30, 2003, based on current market conditions, the maximum TXU Energy would
post for these transactions is $295 million. Of this amount, $249 million
relates to an arrangement that would require that TXU Energy be downgraded to
below investment grade by all three rating agencies before collateral would be
required to be posted.
TXU Energy is also the obligor on leases aggregating $164 million.
Under the terms of those leases, if TXU Energy's credit rating was downgraded to
below investment grade by any specified rating agency, TXU Energy could be
required to sell the assets, assign the leases to a new obligor that is
investment grade, post a letter of credit or defease the leases.
ERCOT also has rules in place to assure adequate credit worthiness
for parties that schedule power on the ERCOT System. Under those rules, if TXU
Energy's credit rating was downgraded to below investment grade by any specified
rating agency, TXU Energy could be required to post collateral of approximately
$60 million.
Cross Default Provisions
------------------------
Certain financing arrangements of US Holdings contain provisions that
would result in an event of default if there is a failure under other financing
arrangements to meet payment terms or to observe other covenants that would
result in an acceleration of payments due. Such provisions are referred to as
"cross default" provisions.
A default by US Holdings or any subsidiary thereof on financing
arrangements of $50 million or more would result in a cross default under the
$1.4 billion US Holdings five-year revolving credit facility, the $400 million
US Holdings credit facility, the $68 million US Holdings letter of credit
reimbursement and credit facility agreement and $30 million of TXU Mining senior
notes (which have a $1 million threshold).
41
A default by TXU Energy or Oncor or any subsidiary thereof in respect
of indebtedness in a principal amount in excess of $50 million or more would
result in a cross default for such party under the TXU Energy/Oncor $450 million
revolving credit facility. Under this credit facility, a default by TXU Energy
or any subsidiary thereof would cause the maturity of outstanding balances under
such facility to be accelerated as to TXU Energy, but not as to Oncor. Also,
under this credit facility, a default by Oncor or any subsidiary thereof would
cause the maturity of outstanding balances to be accelerated under such facility
as to Oncor, but not as to TXU Energy.
A default or similar event under the terms of the TXU Energy
preferred membership interests (formerly subordinated notes) that results in the
acceleration (or other mandatory repayment prior to the mandatory redemption
date) of such security or the failure to pay such security at the mandatory
redemption date would result in a default under TXU Energy's $1.25 billion
senior unsecured notes.
TXU Energy has entered into certain mining and equipment leasing
arrangements aggregating $127 million that would terminate upon the default of
any other obligations of TXU Energy owed to the lessor. In the event of a
default by TXU Mining, a subsidiary of TXU Energy, on indebtedness in excess of
$1 million, a cross default would result under the $31 million TXU Mining
leveraged lease and the lease would terminate.
The accounts receivable program also contains a cross default
provision with a threshold of $50 million applicable to each of the originators
under the program. TXU Receivables Company and TXU Business Services Company
each have a cross default threshold of $50,000. If either an originator, TXU
Business Services Company or TXU Receivables Company defaults on indebtedness of
the applicable threshold, the facility could terminate.
TXU Energy enters into energy-related contracts, the master forms of
which contain provisions whereby an event of default would occur if TXU Energy
were to default under an obligation in respect of borrowings in excess of
thresholds stated in the contracts, which thresholds vary.
A default by TXU Corp. on indebtedness of $50 million or more would
result in a cross default under the new $500 million five-year revolving credit
facility.
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.
Regulatory Asset Securitization -- The Settlement Plan approved by
the Commission provides Oncor with a financing order authorizing it to issue
securitization bonds in the aggregate principal amount of $1.3 billion to
monetize and recover generation-related regulatory assets and related
transaction costs. The Settlement Plan provides that there will be an initial
issuance of securitization bonds in the amount of up to $500 million followed by
a second issuance for the remainder after 2003. The first issuance is expected
to be made in the third quarter of 2003.
OFF BALANCE SHEET ARRANGEMENTS
See discussion above under Sale of Receivables.
COMMITMENTS AND CONTINGENCIES
See Note 6 to Financial Statements for a discussion of contingencies.
There were no material changes in cash commitments from those disclosed in the
2002 Form 10-K.
REGULATION AND RATES
Settlement Plan -- On December 31, 2001, US Holdings filed the
Settlement Plan with the Commission. It resolved all major pending issues
related to US Holdings' transition to competition pursuant to the 1999
Restructuring Legislation. The Settlement provided for in the Settlement Plan
does not remove regulatory oversight of Oncor's business nor does it eliminate
TXU Energy's price-to-beat rates and related fuel adjustments. The Settlement
was approved by the Commission in June 2002 and has become final.
42
Excess Mitigation Credit -- Beginning in 2002, Oncor began
implementing an excess stranded cost mitigation credit designed to result in a
$350 million, plus interest, credit (reduction) applied to delivery fees billed
to REPs applied over a two-year period ending December 31, 2003. The actual
amount of this credit is expected to exceed $350 million as delivery volumes are
anticipated to be higher than initially estimated. The resulting net earnings
reduction for the year 2003 is currently expected to be approximately $14
million after-tax, after consideration of the portion of the credit reflected in
TXU Energy's results as an affiliated REP.
Regulatory Asset Securitization -- In accordance with the
Settlement, Oncor received a financing order authorizing it to issue
securitization bonds in the aggregate principal amount of $1.3 billion to
recover regulatory assets and other qualified costs as discussed above. The
Settlement provides that there can be an initial issuance of securitization
bonds in the amount of up to $500 million, expected to be completed in the third
quarter of 2003, followed by a second issuance of the remainder expected in the
first half of 2004. The Settlement resolves all issues related to regulatory
assets and liabilities.
Retail Clawback -- If TXU Energy retains more than 60% of its
historical residential and small commercial power consumption after the first
two years of competition, the amount of the retail clawback credit will be equal
to the number of residential and small commercial customers retained by TXU
Energy in its historical service territory on January 1, 2004, less the number
of new customers TXU Energy has added outside of its historical service
territory as of January 1, 2004, multiplied by $90. This determination will be
made separately for the residential and small commercial classes. The credit, if
any, will be applied to delivery fees billed by Oncor to REPs, including TXU
Energy, over a two-year period beginning January 1, 2004. Under the settlement
agreement, TXU Energy will make a compliance filing with the Commission
reflecting customer count as of January 1, 2004. In the fourth quarter of 2002,
TXU Energy recorded a $185 million ($120 million after-tax) charge for the
retail clawback, which represents the current best estimate of the amount to be
funded to Oncor over the two-year period.
T&D utilities in Texas are required to file a progress report with
the Commission when over 35% of the residential or small commercial
price-to-beat customer load that existed in the T&D utility's service territory
prior to the January 1, 2002 onset of customer choice is being served by REPs
other than the T&D utility's affiliated REP.
Accordingly, on June 30, 2003, Oncor reported to the Commission
that, as of May 31, 2003, approximately 37%, of the total historical small
commercial customer load, as adjusted pursuant to Commission rules, in its
service territory was being served by REPs other than TXU Energy.
For purposes of these reports, the Commission rules adjust the
total historical load to remove load for those individual small commercial
customers who now use more than 1,000 kilowatts, and for those customers in
which the aggregate use of all their affiliates under common control is more
than 1,000 kilowatts and have contracted with Oncor's affiliated REP, TXU
Energy. The calculations do not take into account the small commercial load that
TXU Energy has gained outside of the Oncor service territory. Also the report
filed by Oncor does not address the residential category where a significantly
smaller percentage of the load is served by REPs other than TXU Energy.
If the 40% threshold related to the small commercial load is met,
TXU Energy would reassess, and adjust accordingly, the estimated $185 million
accrual it previously recorded, which included amounts related to this customer
category. In addition, TXU Energy would be able to price competitively to this
class of customer.
Stranded Cost Resolution -- TXU Energy's stranded costs, not
including regulatory assets, are fixed at zero. Accordingly, it will not have to
conduct the stranded cost true-up in 2004 provided for in the 1999 Restructuring
Legislation.
Fuel Cost Recovery -- The Settlement also provides that US Holdings
will not seek to recover its unrecovered fuel costs that existed at December 31,
2001. Also, it will not conduct a final fuel cost reconciliation, which would
have covered the period from July 1998 until the beginning of competition in
January 2002.
43
TXU Energy --The 1999 Restructuring Legislation provides that an
affiliated REP may request that the Commission adjust its price-to-beat fuel
factor not more than twice a year if the affiliated REP demonstrates that the
existing fuel factor does not adequately reflect significant changes in the
market price of natural gas and purchased energy used to serve retail customers.
The Commission's rules further provide that an affiliated REP may request that
the Commission adjust the price-to-beat fuel factor upward or downward. Neither
the law nor the Commission's rules give the Commission or any other entity the
right to file a petition seeking to require an affiliated REP to increase or
decrease its price-to-beat fuel factor.
Under amended Commission rules, effective in March 2003, affiliated
REPs of utilities are allowed to petition the Commission twice per year for an
increase in the fuel factor component of their price-to-beat rates if the
average price of natural gas futures increases more than 5% (10% if the petition
is filed after November 15 of any year) from the level used to set the existing
price-to-beat fuel factor rate.
- -- In January 2003, TXU Energy filed a request with the Commission to
increase the fuel factor component of its price-to-beat rates based
upon significant increases in the market price of natural gas. This
request was approved on March 5, 2003. The fuel factor increase went
into effect for the billing cycle that began March 6, 2003. As a
result, average monthly residential bills will rise approximately 12%.
- -- On July 23, 2003, TXU Energy filed another request with the
Commission to increase the fuel factor component of its price-to-beat
rates. The change would raise the average monthly residential
electric bill of a customer using an average of 1,000 kilowatt-hours
by 3.7 percent, or $3.61 per month. Even with the increase, TXU Energy
would continue to have the lowest price-to-beat rate in the state.
The Commission has 45 days from the filing of the request, or as soon
as possible, to review the request, and is expected to make a decision
in August 2003. This request would increase TXU Energy's revenues
by approximately $180 million ($50 million for the remainder of 2003,
if approved in mid-September) on an annualized basis.
Transmission rates -- In May 2003, the Commission approved wholesale
transmission rates that are estimated to result in an annual $44 million
increase in Oncor's T&D revenues. Approximately 60% of the increase is
recoverable from Oncor's non-affiliated wholesale transmission customers.
The remaining 40% of the increase will be recoverable from REPs upon
an increase in Oncor's distribution tariffs expected to be approved by the
Commission in the third quarter of 2003. On a consolidated basis, the increase
in Oncor's distribution revenue will be partially offset by higher electricity
delivery costs at TXU Energy.
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 such 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.
44
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.
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 subject to the effects of new, or changes in, income
tax rates or policies and increases in taxes related to property, plant and
equipment and gross receipts and other taxes. Further, US Holdings is subject to
audit and reversal of its tax positions by the IRS and other taxing authorities.
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. 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 regulatory 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.
45
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, and local energy, environmental and other
regulation and legislation.
All but one of US Holdings' facilities for power production 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 14 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.
46
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
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, particularly below investment grade, borrowing costs would increase and
the potential pool of investors and funding sources would likely decrease.
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. Increased starting and stopping of equipment due to the
volatility of the competitive market is likely to increase maintenance and
capital expenditures. US Holdings is subject to costs associated with any
unexpected failure to produce power, including failure caused by breakdown or
forced outage, as well as repairing damage to facilities due to storms, natural
disasters, wars, terrorist acts and other catastrophic events. Further, 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:
47
o Operational Risk - Operations at any nuclear power production plant
could degrade to the point where the plant would have to be shut down.
If this were to happen, the process of identifying and correcting the
causes of the operational downgrade to return the plant to operation
could require significant time and expense, resulting in both lost
revenue and increased fuel and purchased power expense to meet supply
commitments. Rather than incurring substantial costs to restart the
plant, the plant may be shut down. Furthermore, a shut-down or failure
at any other nuclear plant could cause regulators to require a
shut-down or reduced availability at Comanche Peak.
o Regulatory Risk - The NRC may modify, suspend or revoke licenses and
impose civil penalties for failure to comply with the Atomic Energy
Act, the regulations under it or the terms of the licenses of nuclear
facilities. Unless extended, the NRC operating licenses for Comanche
Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively.
Changes in regulations by the NRC could require a substantial increase
in capital expenditures or result in increased operating or
decommissioning costs.
o Nuclear Accident Risk - Although the safety record of Comanche Peak and
nuclear reactors generally has been very good, accidents and other
unforeseen problems have occurred both in the US and elsewhere. The
consequences of an accident can be severe and include loss of life and
property damage. Any resulting liability from a nuclear accident could
exceed 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 territories
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
June 30, 2003, US Holdings had approximately 2.6 million residential and small
commercial customers in its historical service territories. Based on assumptions
and estimates regarding the number of customers expected in and out of
territories, 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.
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.
48
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 territories
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 territories, 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.
Other REPs will be 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
territories 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 territories 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
territories 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.
Under amended Commission rules, effective in March 2003, affiliated
REPs of utilities are allowed to petition the Commission twice per year for an
increase in the fuel factor component of their price-to-beat rates if the
average price of natural gas futures increases more than 5% (10% if the petition
is filed after November 15 of any year) from the level used to set the previous
price-to-beat fuel factor rate.
- -- In January 2003, TXU Energy filed a request with the Commission to
increase the fuel factor component of its price-to-beat rates based
upon significant increases in the market price of natural gas. This
request was approved on March 5, 2003. The fuel factor increase went
into effect for the billing cycle that began March 6, 2003. As a
result, average monthly residential bills rose approximately 12%.
49
- -- On July 23, 2003, TXU Energy filed another request with the Commission
to increase the fuel factor component of its price-to-beat rates. The
change would raise the average monthly residential electric bill of a
customer using an average of 1,000 kilowatt-hours by 3.7 percent, or
$3.61 per month. Even with the increase, TXU Energy would continue to
have the lowest price-to-beat rate in the state. The Commission has 45
days from the filing of the request, or as soon as possible, to review
the request. This request would increase TXU Energy's revenues by
approximately $180 million ($50 million for the remainder of 2003, if
approved in mid-September) on an annualized basis.
There is no assurance that 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
territories, 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 service 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.
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.
50
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 ERCOT market area 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 subject to employee workforce factors, including loss
or retirement of key executives, availability of qualified personnel, collective
bargaining agreements with union employees or work stoppage.
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.
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' business
that restrict US Holdings' ability to access its liquidity facilities.
51
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.
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.
52
COMMODITY PRICE RISK
Value at Risk (VaR) for Energy Contracts Subject to Mark-to-Market
Accounting -- This measurement estimates the maximum potential loss in value,
due to changes in market conditions, of all energy-related contracts subject to
mark-to-market accounting, based on a specific confidence level and an assumed
holding period. Assumptions in determining this VaR include using a 95%
confidence level and a five-day holding period. A probabilistic simulation
methodology is used to calculate VaR, and is considered by management to be the
most effective way to estimate changes in a portfolio's value based on assumed
market conditions for liquid markets.
June 30, December 31,
2003 2002
---- ----
Period-end MtM VaR.............................. $26 $23
Average MtM VaR (year-to-date).................. $31 $38
Portfolio VaR -- Represents the estimated maximum potential loss in
value, due to changes in market conditions, of the entire energy portfolio,
including owned assets and all contractual positions (the portfolio assets).
Assumptions in determining this VaR include using a 95% confidence level and a
five-day holding period and includes both mark-to-market and accrual positions.
June 30, December 31,
2003 2002
---- ----
Period-end Portfolio VaR.......................... $180 $144
Average Portfolio VaR (year-to-date) (a).......... $186 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 portfolio assets except for accrual positions expected to be settled beyond
the fiscal year. Assumptions include using a 95% confidence level over a
five-day holding period under normal market conditions.
Cash Flow at Risk (CFaR) -- CFaR measures the estimated potential
loss of expected cash flow over the next six months, due to changes in market
conditions. CFaR metrics include all portfolio positions that impact cash flow
during the next six months. Assumptions include using a 99% confidence level
over a 6-month holding period under normal market conditions. The following CFaR
calculation is based on a contract settlement period of six months.
June 30, December 31,
2003 2002
---- ----
EaR ........................................... $ 20 $ 28
CFaR .......................................... $108 $178
53
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
US Holdings' gross exposure to credit risk as of June 30, 2003 was
$3.0 billion, representing trade accounts receivable, commodity contract assets
and derivative assets (net of allowance of uncollectible accounts receivable of
$65 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.
The following table presents the distribution of credit exposure as
of June 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 $ 886 $ (35) $ 851 $ 643 $108 $100 $ 851
Noninvestment grade 501 (152) 349 281 35 33 349
Totals ------ ------ ------ ----- ---- ---- ------
$1,387 $ (187) $1,200 $ 924 $143 $133 $1,200
====== ====== ====== ===== ==== ==== ======
Investment grade 64% 19% 71%
Noninvestment grade 36% 81% 29%
The exposure to credit risk from these customers and
counterparties, excluding credit collateral, as of June 30, 2003, is $1.4
billion net of standardized master netting contracts and agreements which
provide the right of offset of positive and negative credit exposures with
individual customers and counterparties. When considering collateral currently
held by US Holdings (cash, letters of credit and other security interests), the
net credit exposure is $1.2 billion. Of this amount, approximately 71% 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 $1.2 billion at June 30, 2003.
Additionally, approximately 77% 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.
54
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
On April 28, 2003, a lawsuit was filed by a former employee of TXU
Portfolio Management in the United States District Court for the Northern
District of Texas, Dallas Division, against TXU Corp., TXU Energy and TXU
Portfolio Management. Plaintiff asserts claims under Section 806 of
Sarbanes-Oxley arising from plaintiff's employment termination and claims for
breach of contract relating to payment of certain bonuses. Plaintiff seeks back
pay, payment of bonuses and alternatively, reinstatement or future compensation,
including bonuses. TXU Corp. believes the plaintiff's claims are without merit.
The plaintiff was terminated as the result of a reduction in force, not as a
reaction to any concerns the plaintiff had expressed, and plaintiff was not in a
position with TXU Portfolio Management such that he had knowledge or information
that would qualify the plaintiff to evaluate TXU Corp.'s financial statements or
assess the adequacy of TXU Corp.'s financial disclosures. Thus, TXU Corp. does
not believe that there is any merit to the plaintiff's claims under
Sarbanes-Oxley. Accordingly, TXU Corp., TXU Energy and TXU Portfolio Management
intend to vigorously defend the litigation. While TXU Corp., TXU Energy and TXU
Portfolio Management dispute the plaintiff's claims, like any litigation, TXU
Corp. is unable to predict the outcome of this litigation or the possible loss
in the event of an adverse judgment.
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. 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. As with any litigation of this nature, US
Holdings is unable to estimate any possible loss or predict the outcome of this
action.
On March 10, 2003, a lawsuit was filed by Kimberly P. Killebrew in
the United States District Court for the Eastern District of Texas, Lufkin
Division, against TXU Corp. and TXU Portfolio Management, asserting generally
that defendants engaged in manipulation of the wholesale electric market, in
violation of antitrust and other laws. This lawsuit was not served on TXU Corp.
until mid-July 2003. This action is brought by an individual, alleged to be a
retail consumer of electricity, on behalf of herself and as a proposed
representative of a putative class of retail purchasers of electricity that are
similarly situated. US Holdings believes that the plaintiff likely lacks
standing to assert any antitrust claims against TXU Corp. or TXU Portfolio
Management, and that defendants have not violated antitrust laws or other laws
as claimed by the plaintiff. Therefore, US Holdings believes that plaintiff's
claims are without merit and plans to vigorously defend the lawsuit. As with any
litigation of this nature, however, US Holdings is unable to estimate any
possible loss or predict the outcome of this action.
55
Reference is made to the 2002 Form 10-K and the Form 10-Q for the
quarterly period ended March 31, 2003 for additional discussion of legal
proceedings.
Item 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits provided as part of Part II are:
4(a) Amendment No. 1 dated as of July 1, 2003, to the Exchange
Agreement, dated as of November 22, 2002, among TXU Corp., TXU
Energy, UXT Holdings LLC and UXT Intermediary LLC, filed as
Exhibit 4(a) with File No. 1-2833 Form 10-Q for the Quarter
ended June 30, 2003.
4(b) Amendment No. 2 dated as of July 1, 2003, to the Registration
Rights Agreement, dated as of November 22, among TXU Corp.,
UXT Holdings LLC and UXT Intermediary LLC, filed as
Exhibit 4(b) with File No. 1-2833 Form 10-Q for the Quarter
ended June 30, 2003.
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 June 30, 2003.
- -----------------
* Pursuant to Item 601(b)(32)(ii) of Regulation S-K, this certificate is
not being "filed" for purposes of Section 18 of the Securities Act of
1934.
(b) Reports on Form 8-K filed since March 31, 2003:
Date of Report Item Reported
-------------- -------------
April 30, 2003 Item 5. Other Events and
Regulation FD Disclosure.
Item 7. Exhibits.
May 1, 2003 Item 7. Exhibits.
(Form 8-K/A)
May 21, 2003 Item 5. Other Events and
Regulation FD Disclosure.
June 30, 2003 Item 5. Other Events and
Regulation FD Disclosure.
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.
56
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: August 13, 2003
57