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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-Q
( X ) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2004
-- OR --
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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Commission File Number 333-108876
TXU Energy Company LLC
A Delaware Limited Liability Company 75-2967817
(State of Organization) (I.R.S. Employer Identification No.)
1601 Bryan Street, Dallas TX, 75201-3411 (214) 812-4600
(Address of Principal Executive Offices) (Registrant's Telephone Number)
(Zip Code)
---------------------
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
--- ----
As of November 9, 2004, all outstanding common membership interests in TXU
Energy Company LLC were held by TXU US Holdings Company.
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TABLE OF CONTENTS
- ----------------------------------------------------------------------------------------------------------------
PAGE
----
Glossary .......................................................................................... ii
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Condensed Statements of Consolidated Income -
Three and Nine Months Ended September 30, 2004 and 2003..................... 1
Condensed Statements of Consolidated Comprehensive Income-
Three and Nine Months Ended September 30, 2004 and 2003..................... 2
Condensed Statements of Consolidated Cash Flows -
Nine Months Ended September 30, 2004 and 2003............................... 3
Condensed Consolidated Balance Sheets -
September 30, 2004 and December 31, 2003.................................... 4
Notes to Condensed Financial Statements..................................... 5
Report of Independent Registered Public Accounting Firm..................... 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................... 47
Item 4. Controls and Procedures...................................................... 49
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................................. 50
Item 6. Exhibits...................................................................... 50
SIGNATURE.......................................................................................... 51
Periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K that
contain financial information of TXU Energy Company LLC 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 Energy Company LLC will provide copies of current
reports not posted on the website upon request. The information on TXU Corp.'s
website shall not be deemed a part of, or incorporated by reference into, this
report on Form 10-Q.
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 retail competition
2003 Form 10-K................................. Energy's Annual Report on Form 10-K for the year ended
December 31, 2003
Bcf............................................ billion cubic feet
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 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"
Electric Delivery.............................. refers to TXU Electric Delivery Company, formerly Oncor
Electric Delivery Company, a subsidiary of US Holdings,
or Electric Delivery and its consolidated bankruptcy
remote financing subsidiary, TXU Electric Delivery
Transition Bond Company LLC, depending on context
Energy......................................... refers to TXU Energy Company LLC, a subsidiary of US
Holdings, and/or its consolidated subsidiaries, depending on
context
ERCOT.......................................... Electric Reliability Council of Texas, the Independent
System Operator and the regional reliability
coordinator of various electricity systems within
Texas
FASB........................................... Financial Accounting Standards Board, the designated
organization in the private sector for establishing
standards for financial accounting and reporting
FERC........................................... Federal Energy Regulatory Commission
FIN............................................ Financial Accounting Standards Board Interpretation
FIN 46......................................... FIN No. 46, "Consolidation of Variable Interest Entities -
An Interpretation of ARB No. 51"
FIN 46R........................................ FIN No. 46 (Revised 2003), "Consolidation of Variable
Interest Entities - An Interpretation of ARB No. 51"
Fitch.......................................... Fitch Ratings, Ltd.
GWh............................................ gigawatt-hours
Historical service territory................... US Holdings' historical service territory, largely in north
Texas, at the time of entering retail competition on January
1, 2002
Moody's........................................ Moody's Investors Services, Inc.
ii
MW............................................. megawatts
NRC............................................ United States Nuclear Regulatory Commission
price-to-beat rate............................. residential and small business customer electricity rates
established by the Commission in the restructuring of the Texas
market that are required to be charged in a REP's historical
service territories until January 1, 2005 or when 40% of the
electricity consumed by such customer classes is supplied
by competing REPs, adjusted periodically for changes in
fuel costs, and required to be available to those
customers until January 1, 2007
REP............................................ retail electric provider
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
SFAS........................................... Statement of Financial Accounting Standards issued by the
FASB
SFAS 133....................................... SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities"
SFAS 140....................................... SFAS No. 140, "Accounting for Transfers and Servicing of
Financial Assets and Extinguishments of Liabilities, a
replacement of FASB Statement 125"
SFAS 143....................................... SFAS No. 143, "Accounting for Asset Retirement Obligations"
SFAS 150....................................... SFAS No. 150, "Accounting for Certain Financial Instruments
with Characteristics of Both Liabilities and Equity"
SG&A........................................... selling, general and administrative
TXU Business Services.......................... TXU Business Services Company, a subsidiary of TXU Corp.
TXU Corp....................................... refers to TXU Corp., a holding company, and/or its
consolidated subsidiaries, depending on context
TXU Gas........................................ TXU Gas Company, a subsidiary of TXU Corp.
TXU Mining..................................... TXU Mining Company LP, a subsidiary of Energy
TXU Portfolio Management....................... TXU Portfolio Management Company LP, a subsidiary of Energy
US............................................. United States of America
US GAAP........................................ accounting principles generally accepted in the US
US Holdings.................................... TXU US Holdings Company, a subsidiary of TXU Corp.
iii
PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
TXU ENERGY COMPANY LLC
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ---------------------
2004 2003 2004 2003
(millions of dollars)
Operating revenues................................................... $2,517 $2,437 $6,589 $6,243
------ ------ ------ ------
Costs and expenses:
Cost of energy sold, including delivery fees...................... 1,556 1,539 4,157 4,037
Operating costs.................................................. 145 164 513 506
Depreciation and amortization..................................... 83 100 268 306
Selling, general and administrative expenses...................... 182 166 491 456
Franchise and revenue-based taxes................................. 28 29 80 84
Other income...................................................... (36) (20) (50) (43)
Other deductions.................................................. 20 4 301 9
Interest income................................................... (13) (1) (21) (3)
Interest expense and related charges.............................. 91 83 263 246
----- ----- ----- -----
Total costs and expenses...................................... 2,056 2,064 6,002 5,598
----- ----- ----- -----
Income from continuing operations before income taxes and cumulative
effectof changes in accounting principles......................... 461 373 587 645
Income tax expense................................................... 152 123 179 205
----- ----- ----- -----
Income from continuing operations before cumulative effect
of changes in accounting principles............................... 309 250 408 440
Loss from discontinued operations, net of tax benefit (Note 3)....... (3) (1) (33) (2)
Cumulative effect of changes in accounting principles, net of
tax benefit (Note 2) ............................................. - - - (58)
----- ----- ----- ------
Net income........................................................... $ 306 $ 249 $ 375 $ 380
===== ===== ===== =====
See Notes to Financial Statements
1
TXU ENERGY COMPANY LLC
CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
--------------------- --------------------
2004 2003 2004 2003
------ ------ ------ -------
(millions of dollars)
Components related to continuing operations:
Income from continuing operations before cumulative effect of
changes in accounting principles.................................... $ 309 $ 250 $ 408 $ 440
----- ---- ----- -----
Other comprehensive income (loss), net of tax effects :
Cash flow hedge activity--
Net change in fair value of derivatives (net of tax benefit of
$2, $11, $46 and $63)........................................... (12) (20) (87) (118)
Amounts realized in earnings during the period (net of tax
expense of $3, $24, $11 and $63)................................ 8 46 20 117
----- ----- ----- -----
Total........................................................... (4) 26 (67) (1)
------ ----- ------ ------
Comprehensive income related to continuing operations................. 305 276 341 439
Comprehensive loss related to discontinued operations................. (3) (1) (33) (2)
Cumulative effect of changes in accounting principles, net of
tax benefit........................................................... - - - (58)
----- ----- ----- ------
Comprehensive income..................................................... $ 302 $ 275 $ 308 $ 379
===== ===== ===== =====
See Notes to Financial Statements.
2
TXU ENERGY COMPANY LLC
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
Nine Months Ended
September 30,
-------------------
2004 2003
------ ------
(millions of dollars)
Cash flows - operating activities:
Income from continuing operations before cumulative effect of
changes in accounting principles.............................................. $ 408 $ 440
Adjustments to reconcile income from continuing operations before cumulative
effect of changes in accounting principles to cash provided by
operating activities:
Depreciation and amortization ............................................... 315 356
Deferred income taxes and investment tax credits - net ...................... 17 30
Asset writedown charges...................................................... 186 -
Net gain from sale of assets................................................ (48) (40)
Net effect of unrealized mark-to-market valuations of commodity contracts.... 46 (58)
Retail clawback accrual...................................................... - (19)
Loss on early extinguishment of debt......................................... 1 1
Net equity loss from unconsolidated affiliates and joint ventures............ 7 -
Changes in operating assets and liabilities..................................... (144) 319
------ ------
Cash provided by operating activities.................................... 788 1,029
------ ------
Cash flows - financing activities:
Issuances of long-term debt..................................................... 800 1,400
Retirements/repurchases of debt................................................. (229) (222)
Increase (decrease) in notes payable to banks................................... 565 (282)
Net change in advances from affiliates.......................................... (1,201) (1,580)
Distribution paid to parent..................................................... (525) (575)
Decrease in note payable to TXU Electric Delivery Company....................... - (161)
Debt premium, discount, financing and reacquisition expenses.................... (15) (30)
------ ------
Cash used in financing activities........................................ (605) (1,450)
------ ------
Cash flows - investing activities:
Capital expenditures............................................................ (149) (123)
Nuclear fuel.................................................................... (46) (45)
Proceeds from sale of assets.................................................... 19 19
Other........................................................................... 20 (9)
------ ------
Cash used in investing activities........................................ (156) (158)
------ ------
Cash used by discontinued operations.............................................. (40) (3)
------ ------
Net change in cash and cash equivalents........................................... (13) (582)
Cash and cash equivalents - beginning balance..................................... 18 603
------ ------
Cash and cash equivalents - ending balance........................................ $ 5 $ 21
====== ======
See Notes to Financial Statements.
3
TXU ENERGY COMPANY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
September 30, December 31,
2004 2003
---------- ---------
(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents..................................... $ 5 $ 18
Advances to affiliates........................................ 1,524 289
Accounts receivable - trade................................... 989 943
Inventories................................................... 296 386
Commodity contract assets..................................... 707 548
Other current assets.......................................... 317 225
---------- ----------
Total current assets........................................ 3,838 2,409
---------- ----------
Investments...................................................... 522 479
Property, plant and equipment - net.............................. 9,833 10,345
Goodwill......................................................... 517 533
Commodity contract assets........................................ 229 109
Cash flow hedge and other derivative assets...................... 24 88
Assets held for sale............................................. 27 59
Other noncurrent assets.......................................... 200 127
---------- ----------
Total assets................................................ $ 15,190 $ 14,149
========== ==========
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Notes payable - banks......................................... $ 565 $ -
Long-term debt due currently.................................. 31 1
Accounts payable - trade:
Affiliates (principally TXU Electric Delivery Company)...... 243 211
All other................................................... 844 712
Notes or other liabilities due TXU Electric Delivery Company.. 30 13
Commodity contract liabilities................................ 545 502
Accrued taxes................................................. 163 292
Other current liabilities..................................... 549 564
---------- ----------
Total current liabilities................................... 2,970 2,295
---------- ----------
Accumulated deferred income taxes................................ 1,892 1,950
Investment tax credits........................................... 346 360
Commodity contract liabilities................................... 309 47
Cash flow hedge and other derivative liabilities................. 218 140
Notes or other liabilities due to TXU Electric Delivery Company.. 407 424
Other noncurrent liabilities and deferred credits................ 1,193 1,342
Long-term debt, less amounts due currently....................... 3,630 3,084
Preferred membership interests, held by TXU Corp. at September 30,
2004, net of discount of $242 and $253 (Note 4)............... 508 497
Liabilities held for sale........................................ 8 11
---------- ----------
Total liabilities........................................... 11,481 10,150
---------- ----------
Contingencies (Note 6)
Membership interests (Note 5):
Capital account............................................... 3,886 4,109
Accumulated other comprehensive loss.......................... (177) (110)
----------- -----------
Total membership interests.................................. 3,709 3,999
---------- ----------
Total liabilities and membership interests.................. $ 15,190 $ 14,149
========== ==========
See Notes to Financial Statements.
4
TXU ENERGY COMPANY LLC
NOTES TO CONDENSED FINANCIAL STATEMENTS
(Unaudited)
1. SIGNIFICANT ACCOUNTING POLICIES AND BUSINESS
Description of Business - Energy is a subsidiary of US Holdings, which is
a subsidiary of TXU Corp. Energy is engaged in electricity generation and retail
and wholesale energy sales and hedging and risk management operations. Energy
is currently managed as an integrated business; consequently, there are no
reportable business segments.
Strategic Initiatives and Other Actions - Mr. C. John Wilder, who was
named president and chief executive of TXU Corp. in February 2004, and senior
management have been reviewing the operations of TXU Corp. and have formulated
certain strategic initiatives and continue to develop others. Areas being
reviewed include:
o Performance in competitive markets, including profitability in new
markets;
o Cost structure, including organizational alignments and headcount;
o Management of natural gas price risk and cost effectiveness of the
generation fleet; and
o Non-core business activities.
As discussed below, implementation of the strategic initiatives as well as
other actions taken to date have resulted in total charges of $8 million ($5
million after-tax) in the third quarter of 2004 and $284 million ($185 million
after-tax) year-to-date, substantially all reported in other deductions, related
to asset writedowns and employee severance. In the third quarter of 2004, Energy
recorded gains on the disposition of properties, principally undeveloped land,
totaling $18 million ($12 million after-tax), reported in other income.
Charges recorded in the three-month and nine-month periods ended September
30, 2004 and 2003 reported in other deductions are detailed in Note 8.
Capgemini Energy Agreement
--------------------------
On May 17, 2004, Energy entered into a services agreement with a
subsidiary of Cap Gemini North America Inc., Capgemini Energy LP (Capgemini), a
new company initially providing business process support services to TXU Corp.,
but immediately implementing a plan to offer similar services to other utility
companies. Under the ten-year agreement, over 2,500 TXU Corp. employees
(including approximately 1,100 from Energy) transferred to Capgemini effective
July 1, 2004. Outsourced base support services performed by Capgemini for a
fixed fee, subject to adjustment for volumes or other factors, include
information technology, customer call center, billing and collections, human
resources, supply chain and certain accounting activities.
As part of the agreement, Capgemini was provided a royalty-free
right, under an asset license arrangement, to use information technology assets,
consisting primarily of capitalized software. A portion of the software was in
development and had not yet been placed in service by Energy. As a result of
outsourcing its information technology activities, Energy no longer intends to
develop the majority of these projects and from Energy's perspective the
software is abandoned. The agreements with Capgemini do not require that any
software in development be completed and placed in service. Consequently, the
carrying value of these software projects was written off, resulting in a charge
of $107 million ($70 million after-tax) for the nine months ended September 30,
2004, reported in other deductions, essentially all of which was recorded in the
second quarter of 2004. The remaining assets were transferred to a subsidiary
of TXU Corp. at book value in exchange for an interest in that subsidiary. Such
interest is accounted for by Energy on the equity method, and Energy recorded
equity losses (representing depreciation expense) of $7 million in the third
quarter of 2004, reported in other deductions.
The TXU Corp. subsidiary received a 2.9% limited partnership interest in
Capgemini in exchange for the asset license described above. Energy and Electric
Delivery have the right to sell (the "put option") their interest in the
subsidiary to Cap Gemini America Inc. for $200 million, plus the subsidiary's
share of Capgemini's undistributed earnings, upon expiration of the services
agreement, or earlier upon the occurrence of certain unexpected events. Cap
Gemini North America Inc. has the right to purchase Energy's and Electric
Delivery's interests under the same terms and conditions. The partnership
interest has been recorded at an initial value of $2.9 million and is being
accounted for on the cost method.
5
Energy has recorded its share of the fair value of the put option as a
noncurrent asset largely offset by a reduction to the carrying value of the
software transferred to the subsidiary, in accordance with the accounting
principles related to sales and licensing of internally developed software
described in AICPA Statement of Position 98-1, "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use."
Also as part of its agreement, TXU Corp. agreed to indemnify Capgemini for
severance costs incurred by Capgemini for former TXU Corp. employees terminated
within 18 months of their transfer to Capgemini. Accordingly, Energy recorded a
$27 million ($18 million after-tax) charge for severance expense in the second
quarter of 2004, which represents a reasonable estimate of the indemnity and is
reported in other deductions. The charge includes an allocation of severance
related to TXU Business Services Company employees. The transition costs
applicable to Energy are expected to be largely recorded during the fourth
quarter of 2004.
Transfer and Sale of TXU Fuel Company
--------------------------------------
On April 30, 2004, Energy distributed the assets of TXU Fuel Company, its
gas transportation subsidiary, to US Holdings at book value, including $16
million of allocated goodwill (see Note 5). On June 2, 2004, US Holdings
completed the sale of the assets of TXU Fuel Company to Energy Transfer
Partners, L.P. for $500 million in cash. The assets of TXU Fuel Company
consisted of approximately 1,900 miles of intrastate pipeline and a total system
capacity of 1.3 Bcf/day. As part of the transaction, Energy entered into a
market-price based transportation agreement with the new owner to transport gas
to Energy's generation plants. Because of the continuing involvement in the
business through the transportation agreement, the business has not been
accounted for as a discontinued operation.
Facility Closures and Other Actions Related to Generation Operations
--------------------------------------------------------------------
In the third quarter of 2004, Energy recorded gains totaling $18 million
($12 million after-tax) related to the sale of undeveloped land. The gains are
reported in other income.
In the second quarter of 2004, Energy initiated a plan to sell the
Pedricktown, New Jersey 122 MW power production facility and exit the related
power supply and gas transportation agreements. Accordingly, Energy recorded an
impairment charge of $26 million ($17 million after-tax) to write down the
facility to estimated fair market value. The results of the business and the
impairment charge are reported in discontinued operations as discussed in Note
3.
As part of Energy's review of its generation asset portfolio, Energy
completed a review of its spare parts and equipment inventory to determine the
appropriate level of such inventory. The review included nuclear, coal and
gas-fired generation-related facilities. As a result of this review, Energy
recorded a charge of $79 million ($51 million after-tax), reported in other
deductions, in the second quarter of 2004 to reflect excess inventory on hand
and to write down carrying values to scrap values.
In March 2004, Energy announced the planned permanent retirement,
completed in the second quarter of 2004, of eight gas-fired operating units due
to electric industry market conditions in Texas. Energy also temporarily closed
four other gas-fired units and placed them under evaluation for retirement. The
12 units represented a total of 1,471 MW, or more than 13%, of Energy's
gas-fired generation capacity in Texas. A majority of the 12 units were
designated as "peaking units" and operated only during the summer for many years
and have operated only sparingly during the last two years. Most of the units
were built in the 1950's. Energy also determined that it would close its
Winfield North Monticello lignite mine in Texas, and such closure has been
completed, as it is no longer economical to operate when compared to the cost of
purchasing coal to fuel the adjacent generation facility. A total charge of $8
million ($5 million after-tax) was recorded in the first quarter of 2004,
reported in other deductions, for production employee severance costs ($7
million pre-tax) and impairments related to the various facility closures ($1
million pre-tax).
6
Organizational Realignment and Headcount Reductions
---------------------------------------------------
During the second quarter of 2004, management completed a comprehensive
organizational review, including an analysis of staffing requirements. As a
result, Energy completed a self-nomination severance program and finalized a
plan for additional headcount reductions under an involuntary severance program,
which has been largely completed. Accordingly, in the second quarter of 2004,
Energy recorded severance charges totaling $43 million ($28 million after-tax),
reported in other deductions.
Preferred Membership Interests
------------------------------
In April 2004, TXU Corp. purchased from the holders Energy's preferred
membership interests with a liquidation value of $750 million. Energy's carrying
amount of the security, which remains outstanding, is the $750 million
liquidation amount less $242 million remaining unamortized discount and $30
million in unamortized debt issuance costs.
Discontinued Businesses - Note 3 presents detailed information regarding
the discontinued New Jersey generation operations and the strategic retail
services business. The condensed consolidated financial statements for all
periods presented reflect the reclassification of the results of these
businesses as discontinued operations.
Basis of Presentation -- The condensed consolidated financial statements
of Energy have been prepared in accordance with US GAAP and on the same basis as
the audited financial statements included in its 2003 Form 10-K, except for the
changes in estimates of depreciable lives of assets discussed below and the
presentation of certain operations as discontinued. In the opinion of
management, all other adjustments (consisting of normal recurring accruals)
necessary for a fair presentation of the results of operations and financial
position have been included therein. All intercompany items and transactions
have been eliminated in consolidation. Certain information and footnote
disclosures normally included in annual consolidated financial statements
prepared in accordance with US GAAP have been omitted pursuant to the rules and
regulations of the SEC. Because the condensed 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 2003 Form 10-K. The results of operations for
an interim period may not give a true indication of results for a full year.
The Medicare Prescription Drug, Improvement and Modernization Act of 2003
(the Medicare Act) was enacted in December 2003. TXU Corp. is accounting for the
effects of the Medicare Act in accordance with FASB Staff Position 106-2. For
the three and nine months ended September 30, 2004, the effect of adoption of
the Medicare Act was a reduction of approximately $3 million and $8 million,
respectively, in Energy's postretirement benefit costs.
Certain reclassifications have been made to conform prior period data to
the current period presentation. All dollar amounts in the financial statements
and tables in the notes are stated in millions of dollars unless otherwise
indicated.
Depreciation of Energy Production Facilities -- Effective January 1, 2004,
the estimates of the depreciable lives of lignite-fired generation facilities
were extended an average of nine years to better reflect the useful lives of the
assets, and depreciation rates for the Comanche Peak nuclear generating plant
were decreased as a result of an increase in the estimated lives of boiler and
turbine generator components of the plant by an average of five years. The net
impact of these changes was a reduction in depreciation expense of $11 million
and $33 million ($7 million and $21 million after-tax) in the three and nine
months, respectively, ended September 30, 2004.
7
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 additional investments in equipment. The net impact of these changes was
an additional reduction in depreciation expense of $12 million ($8 million
after-tax) in the nine months ended September 30, 2004.
Changes in Accounting Standards -- FIN 46R was issued in December 2003 and
replaced FIN 46, which was issued in January 2003. FIN 46R expands and clarifies
the guidance originally contained in FIN 46, regarding consolidation of variable
interest entities. FIN 46R did not impact results of operations or financial
position for the first nine months of 2004.
2. CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
The following summarizes the effect on results for 2003, reported in the
first quarter, of 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
are 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) was reported as a cumulative
effect of a change in accounting principles in the first quarter of 2003. Of the
total, $75 million reduced net commodity contract assets and liabilities and $22
million reduced inventory that had previously been marked-to-market as a trading
position. The cumulative effect adjustment represents the net gains previously
recognized for these contracts under mark-to-market accounting.
SFAS 143 became effective on January 1, 2003. SFAS 143 requires entities
to record the fair value of a legal liability for an asset retirement obligation
in the period of its inception. For Energy, such liabilities primarily 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) Energy 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 affiliated receivable................................ 48
----
Cumulative effect of change in accounting principles............. $ 5
====
8
The asset retirement liability at September 30, 2004 was $610 million,
comprised of a $599 million liability as of December 31, 2003 and $30 million of
accretion during the nine months ended September 30, 2004, reduced by $19
million in reclamation payments.
With respect to nuclear decommissioning costs, for Energy the adoption of
SFAS 143 results in timing differences in the recognition of asset retirement
costs that are being recovered through the regulatory process.
3. DISCONTINUED OPERATIONS
The following summarizes the historical consolidated financial information
of the businesses reported as discontinued operations:
Three Months Ended September 30, Nine Months Ended September 30,
2004 2004
---------------------------------- ----------------------------------
Strategic Strategic
Retail Retail
Services Pedricktown Total Services Pedricktown Total
-------- ----------- ------ --------- ----------- -----
Operating revenues........................ $ 3 $ 8 $ 11 $ 13 $ 27 $ 40
Operating costs and expenses.............. 4 8 12 16 30 46
Other deductions - net.................... - - - 10 - 10
----- ----- ----- ----- ----- -----
Operating loss before income taxes........ (1) - (1) (13) (3) (16)
Income tax expense (benefit).............. 1 - 1 (4) (1) (5)
----- ----- ----- ------ ------ ------
Operating loss............................ (2) - (2) (9) (2) (11)
Charges related to exit (after-tax)....... (1) - (1) (5) (17) (22)
------ ----- ------ ------ ------ ------
Loss from discontinued operations.... $ (3) $ - $ (3) $ (14) $ (19) $ (33)
------ ----- ------ ------ ------ ------
Three Months Ended September 30, Nine Months Ended September 30,
2003 2003
----------------------------------- ----------------------------------
Strategic Strategic
Retail Retail
Services Pedricktown Total Services Pedricktown Total
-------- ----------- ----- -------- ----------- -----
Operating revenues........................... $ 11 $ 10 $ 21 $ 54 $ 18 $ 72
Operating costs and expenses................. 8 10 18 49 21 70
Other deductions - net....................... 4 - 4 4 - 4
----- ----- ----- ----- ----- -----
Operating income (loss) before income taxes.. (1) - (1) 1 (3) (2)
Income tax expense (benefit)................. - - - 1 (1) -
----- ----- ----- ----- ------ -----
Operating loss............................... (1) - (1) - (2) (2)
------ ----- ------ ----- ------ ------
Loss from discontinued operations....... $ (1) $ - $ (1) $ - $ (2) $ (2)
------ ----- ------ ----- ------ ------
Pedricktown - In the second quarter of 2004, Energy initiated a plan to
sell the Pedricktown, New Jersey 122 MW power production facility and exit the
related power supply and gas transportation agreements. Accordingly, results for
the second quarter of 2004 included a $17 million after-tax charge to write down
the facility to estimated fair market value.
Strategic Retail Services - In December 2003, Energy finalized a formal
plan to sell its strategic retail services business, which is engaged
principally in providing energy management services. Energy expects to
substantially complete the sales of these operations to various parties by
year-end 2004. Results for 2004 reflect a $9 million ($6 million after-tax)
charge recorded in the second quarter to settle a contract dispute.
9
Balance sheet - The following details the assets and liabilities held for sale:
September 30, 2004
----------------------------------
Strategic
Retail
Services Pedricktown Total
-------- ----------- ------
Current assets........................................... $ 4 $ 2 $ 6
Investments.............................................. 2 - 2
Property, plant and equipment............................ 3 16 19
----- ----- -----
Assets held for sale................................ $ 9 $ 18 $ 27
===== ===== =====
Current liabilities...................................... $ - $ 4 $ 4
Noncurrent liabilities................................... - 4 4
----- ----- -----
Liabilities held for sale........................... $ - $ 8 $ 8
===== ===== =====
4. FINANCING ARRANGEMENTS
Short-term Borrowings -- At September 30, 2004, Energy had outstanding
short-term borrowings consisting of bank borrowings under the three-year
revolving credit facility of $565 million at a weighted average interest rate of
4.27%. At December 31, 2003, Energy had no outstanding short-term borrowings.
Credit Facilities -- At September 30, 2004, TXU Corp. had credit
facilities (some of which provide for long-term borrowings) as follows:
- ----------------------------------- ------------ ---------------- ----------------------------------------------
At September 30, 2004
- ----------------------------------- ------------ ---------------- ----------------------------------------------
Maturity Authorized Facility Letters of Cash
- ----------------------------------- ------------ ---------------- --------- ---------- ------------ ------------
Facility Date Borrowers Limit Credit Borrowings Availability
- ----------------------------------- ------------ ---------------- --------- ---------- ------------ ------------
Energy, Electric
364-day Credit Facility June 2005 Delivery $ 600 $ 80 $ - $ 520
- ----------------------------------- ------------ ---------------- --------- ---------- ------------ ------------
Three-Year Revolving Credit Energy, Electric
Facility June 2007 Delivery 1,400 - 565 835
- ----------------------------------- ------------ ---------------- --------- ---------- ------------ ------------
Five-Year Revolving Credit
Facility August 2008 TXU Corp. 500 429 - 71
- ----------------------------------- ------------ ---------------- --------- ---------- ------------ ------------
Five-Year Revolving Credit Energy, Electric
Facility June 2009 Delivery 500 - - 500
- ----------------------------------- ------------ ---------------- --------- ---------- ------------ ------------
Total $3,000 $ 509 $ 565 $ 1,926
- ----------------------------------- ------------ ---------------- --------- ---------- ------------ ------------
On September 28, 2004, portions of the Brazos River Authority Pollution
Control Revenue Refunding Bonds related to the Twin Oak facility were redeemed
at par as follows: $57 million of Series 2001C; $21 million of Series 2003C; $16
million of Series 2002A; $4 million of series 1995B; and $3 million of Series
2001D.
In June 2004, US Holdings, Energy and Electric Delivery replaced $2.25
billion of credit facilities scheduled to mature in 2005 with $2.5 billion of
credit facilities for Energy and Electric Delivery maturing in June 2005, 2007
and 2009. These facilities are used for working capital and general corporate
purposes and provide back-up for any future issuances of commercial paper by
Energy or Electric Delivery. At September 30, 2004, there was no such commercial
paper outstanding.
In April 2004, Energy entered into a $1.0 billion, 364-day credit
facility. In July 2004, borrowings under this facility were repaid with proceeds
from Energy's issuance of $800 million floating rate senior notes and repayment
of advances to affiliates and the facility was subsequently terminated.
TXU Corp.'s $500 million five-year revolving credit facility provides for
up to $500 million in letters of credit and/or up to $250 million of loans ($500
million in the aggregate). To the extent capacity is available under this
facility, it may be made available to US Holdings, Energy or Electric Delivery
for borrowings, letters of credit or other purposes.
Sale of Receivables -- TXU Corp. has established an accounts receivable
securitization program. The activity under this program is accounted for as a
sale of accounts receivable in accordance with SFAS 140. Under the program,
subsidiaries of TXU Corp. (originators) sell trade accounts receivable to TXU
Receivables Company, a consolidated wholly-owned bankruptcy remote direct
subsidiary of TXU Corp., which sells undivided interests in the purchased
accounts receivable for cash to special purpose entities established by
financial institutions (the funding entities). As of September 30, 2004, $629
million of undivided interests in Energy's accounts receivable had been sold by
TXU Receivables Company. Effective June 30, 2004, the program was extended
through June 28, 2005. As part of the extension, the maximum amount available
under the program was increased from $600 million to $700 million in recognition
of seasonal power sales. Additionally, the extension allows for increased
availability of funding through a credit ratings-based reduction (based on each
originator's credit rating) of customer deposits previously used to reduce the
amount of undivided interests that could be sold. Undivided interests will now
be reduced by 100% of the customer deposits for a Baa3/BBB- rating; 50% for a
Baa2/BBB rating; and zero % for a Baa1/BBB+ and above rating.
10
All new trade receivables under the program generated by the originators
are continuously purchased by TXU Receivables Company with the proceeds from
collections of receivables previously purchased. Changes in the amount of
funding under the program, through changes in the amount of undivided interests
sold by TXU Receivables Company, are generally due to seasonal variations in the
level of accounts receivable and changes in collection trends. TXU Receivables
Company has issued subordinated notes payable to the originators for the
difference between the face amount of the uncollected accounts receivable
purchased, less a discount, and cash paid to the originators that was funded by
the sale of the undivided interests.
The discount from face amount on the purchase of receivables principally
funds program fees paid by TXU Receivables Company to the funding entities, as
well as a servicing fee paid by TXU Receivables Company to TXU Business
Services, a direct subsidiary of TXU Corp. The program fees (losses on sale),
which consist primarily of interest costs on the underlying financing, were
approximately $7 million for each of the nine-month periods ending September 30,
2004 and 2003 and approximated 1.9% and 2.5% for the first nine months of 2004
and 2003, respectively, of the average funding under the program on an
annualized basis; these fees represent the net incremental costs of the program
to Energy and are reported in SG&A expenses. The servicing fee, which totaled
approximately $3 million and $4 million for the first nine months of 2004 and
2003, respectively, compensates TXU Business Services for its services as
collection agent, including maintaining the detailed accounts receivable
collection records.
The September 30, 2004 balance sheet reflects $984 million face amount of
trade accounts receivable reduced by $629 million of undivided interests sold by
TXU Receivables Company. Funding under the program increased $125 million for
the nine months ended September 30, 2004. Funding under the program for the nine
months ended September 30, 2003 increased $198 million. Funding increases or
decreases under the program are reflected as operating cash flow activity in the
statement of cash flows. The carrying amount of the retained interests in the
accounts receivable approximated fair value due to the short-term nature of the
collection period.
Activities of TXU Receivables Company related to Energy for the nine
months ended September 30, 2004 and 2003 were as follows:
Nine Months
Ended September 30,
-------------------------
2004 2003
------ ------
Cash collections on accounts receivable...................................... $ 4,928 $4,933
Face amount of new receivables purchased..................................... (4,979) (4,862)
Discount from face amount of purchased receivables........................... 10 11
Program fees paid............................................................ (7) (7)
Servicing fees paid.......................................................... (3) (4)
Increase (decrease) in subordinated notes payable............................ (74) (268)
-------- -------
Operating cash flows provided to Energy under the program............... $ (125) $ (197)
======== =======
Upon termination of the program, cash flows to Energy would be delayed as
collections of sold receivables would be used by TXU Receivables Company to
repurchase the undivided interests sold instead of purchasing new receivables.
The level of cash flows would normalize in approximately 16 to 31 days.
11
Contingencies Related to Sale of Receivables Program -- Although TXU
Receivables Company expects to be able to pay its subordinated notes from the
collections of purchased receivables, these notes are subordinated to the
undivided interests of the financial institutions in those receivables, and
collections might not be sufficient to pay the subordinated notes. The program
may be terminated if either of the following events occurs:
1) all of the originators cease to maintain their required fixed charge
coverage ratio and debt to capital (leverage) ratio;
2) the delinquency ratio (delinquent for 31 days) for the sold
receivables, the default ratio (delinquent for 91 days or
deemed uncollectible), the dilution ratio (reductions for discounts,
disputes and other allowances) or the days collection outstanding
ratio exceed stated thresholds and the financial institutions do not
waive such event of termination. The thresholds apply to the entire
portfolio of sold receivables, not separately to the receivables of
each originator.
The delinquency and dilution ratios exceeded the relevant thresholds
during the first four months of 2003, but waivers were granted. These ratios
were affected by issues related to the transition to competition. Certain
billing and collection delays arose due to implementation of new systems and
processes within Energy and ERCOT for clearing customers' switching and billing
data. Strengthened credit and collection policies and practices have brought the
ratios into consistent compliance with the program requirement.
Under terms of the receivables sale program, all the originators are
required to maintain specified fixed charge coverage and leverage ratios (or
supply a parent guarantor that meets the ratio requirements). The failure, by an
originator or its parent guarantor, if any, to maintain the specified financial
ratios would prevent that originator from selling its accounts receivable under
the program. If all the originators and the parent guarantor, if any, fail to
maintain the specified financial ratios so that there are no eligible
originators, the facility would terminate.
12
Long-term Debt -- At September 30, 2004 and December 31, 2003, the
long-term debt of Energy and its consolidated subsidiaries consisted of the
following:
September 30, December 31,
2004 2003
------------ ------------
Pollution Control Revenue Bonds:
Brazos River Authority:
3.000% Fixed Series 1994A due May 1, 2029, remarketing date May 1, 2005(a)........... $ 39 $ 39
5.400% Fixed Series 1994B due May 1, 2029, remarketing date May 1, 2006(a)........... 39 39
5.400% Fixed Series 1995A due April 1, 2030, remarketing date May 1, 2006(a)......... 50 50
5.050% Fixed Series 1995B due June 1, 2030, remarketing date June 19, 2006(a)........ 114 118
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
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)...... 217 274
1.464% Floating Series 2001D due May 1, 2033......................................... 268 271
1.730% Floating Taxable Series 2001I due December 1, 2036(b)......................... 63 63
1.436% Floating Series 2002A due May 1, 2037(b)...................................... 45 61
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)....... 44 44
6.300% Fixed Series 2003B due July 1, 2032........................................... 39 39
6.750% Fixed Series 2003C due October 1, 2038........................................ 52 72
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1, 2014(a)... 31 31
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
5.800% Fixed Series 2003A due July 1, 2022........................................... 12 12
6.150% Fixed Series 2003B due August 1, 2022......................................... 45 45
Trinity River Authority of Texas:
6.250% Fixed Series 2000A due May 1, 2028............................................ 14 14
5.000% Fixed Series 2001A due May 1, 2027, remarketing date November 1, 2006(a)...... 37 37
Other:
6.875% TXU Mining Fixed Senior Notes due August 1, 2005.............................. 30 30
6.125% Fixed Senior Notes due March 15, 2008(c)...................................... 250 250
7.000% Fixed Senior Notes due March 15, 2013......................................... 1,000 1,000
2.380% Floating Rate Senior Notes due January 17, 2006 .............................. 800 --
Capital lease obligations............................................................ 9 13
Other................................................................................ 1 8
Fair value adjustments related to interest rate swaps................................ 17 11
Unamortized--discount................................................................ -- (2)
------- --------
Total Energy .................................................................... 3,661 3,085
Less amount due currently................................................................ 31 1
------- -------
Total long-term debt..................................................................... $ 3,630 $ 3,084
======= =======
- --------------
(a) These series are in the multiannual mode and are subject to mandatory
tender prior to maturity on the mandatory remarketing date. On such date,
the interest rate and interest rate period will be reset for the bonds.
(b) Interest rates in effect at September 30, 2004. 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 swapped to floating on an aggregate $250 million principal
amount.
On September 28, 2004, portions of the Brazos River Authority Pollution
Control Revenue Refunding Bonds related to the Twin Oak facility were redeemed
at par as follows: $57 million of Series 2001C; $21 million of Series 2003C;
$16 million of Series 2002A; $4 million of series 1995B; and $3 million of
Series 2001D.
In July 2004, Energy issued $800 million of floating rate senior notes in
a private placement offering with registration rights. The net proceeds of $798
million were used to repay, in part, borrowings outstanding under its fully
drawn $1.0 billion 364 day credit facility, which was subsequently terminated.
The notes bear interest at an annual rate equal to 3-month LIBOR, reset
quarterly, plus 0.78% and will mature on January 17, 2006.
In April 2004, the Brazos River Authority Series 2001A pollution control
revenue bonds with an aggregate principal amount of $121 million were purchased
upon mandatory tender. Energy intends to remarket these bonds at a later date.
13
Fair Value Hedges -- Energy uses fair value hedging strategies to manage
its exposure to fixed interest rates on long-term debt. At September 30, 2004,
$250 million of fixed rate debt had been effectively converted to variable rates
through interest rate swap transactions, expiring through 2008. These swaps
qualified for and have been designated as fair value hedges using the short-cut
method of hedge accounting provided by SFAS 133. As such, the company assumes
that changes in the value of the derivative are perfectly offset by changes in
the value of the debt; therefore, there is no hedge ineffectiveness recognized.
In August 2004, fixed-to-variable swaps related to $500 million debt were
settled for a gain of $394 thousand, which will be amortized to offset interest
expense over the remaining life of the related debt. In April 2004,
fixed-to-variable interest rate swaps related to $100 million of debt were
settled for a gain of $3.5 million, which will be amortized to offset interest
expense over the remaining life of the debt. In March 2004, fixed-to-variable
interest rate swaps related to $400 million of debt were settled for a gain of
$18 million, which will also be amortized to offset interest expense over the
remaining life of the related debt.
Preferred Membership Interests -- In July 2003, Energy exercised its right
to exchange its $750 million 9% Exchangeable Subordinated Notes issued in
November 2002 and due November 2012 for exchangeable preferred membership
interests with identical economic and other terms. The preferred membership
interests bear distributions at the annual rate of 9% and permit the deferral of
such distributions. The holders of the preferred membership interests had the
option to exchange these interests at any time, subject to certain restrictions,
for up to approximately 57 million shares of TXU Corp. common stock at an
exchange price of $13.1242 per share. At issuance of the notes that were
subsequently exchanged for the preferred membership interests, Energy recognized
a capital contribution from TXU Corp. and a corresponding discount on the
securities of $266 million, which represented the value of the exchange right as
TXU Corp. granted an irrevocable right to exchange the securities for TXU Corp.
common stock. This discount is being amortized to interest expense and related
charges over the term of the securities. As a result, the effective distribution
rate on the preferred membership interests is 16.2%. In April 2004, TXU Corp.
purchased these mandatorily redeemable securities from the holders, as discussed
in Note 1, and as a result the securities effectively represent Energy debt held
by TXU Corp.
5. MEMBERSHIP INTERESTS
In August 2004, Energy approved a cash distribution of $175 million which
was paid to US Holdings in October 2004. In June 2004, Energy approved a cash
distribution of $175 million which was paid to US Holdings in July 2004. In
February 2004, Energy approved a cash distribution of $175 million which was
paid to US Holdings in April 2004. In November 2003, Energy approved a cash
distribution of $175 million which was paid to US Holdings in January 2004.
The following table presents the changes in Membership Interests for the
nine months ended September 30, 2004:
Accumulated
Other Total
Capital Comprehensive Membership
Accounts Gain (Loss) Interests
-------- ------------- ---------
Balance at December 31, 2003................ $4,109 $(110) $3,999
Distributions paid to parent........... (525) - (525)
Net income............................. 375 - 375
Cash flow hedges....................... - (67) (67)
Transfer of TXU Fuel Company ownership. (73) - (73)
------- ----- -------
Balance at September 30, 2004.............. $3,886 $(177) $3,709
====== ====== ======
14
6. CONTINGENCIES
Request from Commodities Futures Trading Commission (CFTC) On April 13,
2004, the CFTC issued a subpoena requiring TXU Corp. to produce information
about storage of natural gas, including weekly and monthly storage reports to
the Energy Information Administration submitted by TXU Fuel Company and TXU Gas.
The request sought information for the period of October 31, 2003 through
January 2, 2004. TXU Corp. cooperated with the CFTC by producing the requested
information and believes that TXU Gas and TXU Fuel Company have not engaged in
any activity that would justify action against them by the CFTC. On August 30,
2004, the CFTC issued a press release confirming that its investigation, which
included the investigation regarding gas storage reports, had been closed, and
TXU Corp. has received nothing from the CFTC to indicate that the CFTC will take
any action against TXU Gas or TXU Fuel Company.
Guarantees -- Energy has entered into contracts that contain guarantees to
outside parties that could require performance or payment under certain
conditions. These guarantees have been grouped based on similar characteristics
and are described in detail below.
Residual value guarantees in operating leases -- Energy is the lessee
under various operating leases, entered into prior to January 1, 2003 that
obligate it to guarantee the residual values of the leased facilities. At
September 30, 2004, the aggregate maximum amount of residual values guaranteed
was approximately $195 million with an estimated residual recovery of
approximately $100 million. The average life of the lease portfolio is
approximately seven years.
Debt obligations of the parent-- Energy has provided a guarantee of the
obligations under TXU Corp.'s finance lease (approximately $120 million at
September 30, 2004) for its headquarters building.
Shared saving guarantees -- As part of the operations of the strategic
retail services business, which Energy intends to sell (see Note 3), Energy has
guaranteed that certain customers will realize specified annual savings
resulting from energy management services it has provided. In aggregate, the
average annual savings have exceeded the annual savings guaranteed. The maximum
potential annual payout is approximately $1 million and the maximum total
potential payout is approximately $6 million. No shared savings guarantees were
issued during the nine months ended September 30, 2004 that required recording a
liability. The average remaining life of the portfolio is approximately seven
years. These guarantees will be transferred or eliminated as part of expected
transactions for the sale of the strategic retail services business.
Letters of credit -- Energy has entered into various agreements that
require letters of credit for financial assurance purposes. Approximately $384
million of letters of credit were outstanding at September 30, 2004 to support
existing floating rate pollution control revenue bond debt of approximately $376
million. The letters of credit are available to fund the payment of such debt
obligations. These letters of credit expire in 2008.
Energy has outstanding letters of credit in the amount of $113 million to
support hedging and risk management margin requirements in the normal course of
business. As of September 30, 2004, approximately 84% of the obligations
supported by these letters of credit mature within one year, and substantially
all of the remainder mature in the next six years.
Surety bonds -- Energy has outstanding surety bonds of approximately $29
million to support performance under various subsidiary contracts and legal
obligations in the normal course of business. The term of the surety bond
obligations is approximately one year.
Legal Proceedings -- On July 7, 2003, a lawsuit was filed by Texas
Commercial Energy (TCE) in the United States District Court for the Southern
District of Texas, Corpus Christi Division, against 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. An amended complaint
was filed in February 2004 that joined additional, unaffiliated defendants.
Three retail electric providers filed motions for leave to intervene in the
action alleging claims substantially identical to TCE's. In addition,
approximately 25 purported former customers of TCE filed a motion to intervene
in the action alleging claims substantially identical to TCE's, both on their
15
own behalf and on behalf of a putative class of all former customers of TCE. An
order granting Energy's Motion to Dismiss based on the filed rate doctrine was
entered on June 24, 2004. TCE has appealed the dismissal, however, Energy
believes the dismissal of the antitrust claims was proper and that it has not
committed any violation of the antitrust laws. Further, the Commission's
investigation of the market conditions in late February 2003 has not resulted in
any findings adverse to Energy. Accordingly, Energy believes that TCE's and the
interveners' claims against Energy and its subsidiary companies are without
merit and Energy and its subsidiaries intend to vigorously defend the lawsuit on
appeal. Energy is, however, unable to estimate any possible loss or predict the
outcome of this action.
On April 28, 2003, a lawsuit was filed by a former employee of TXU
Portfolio Management in the United States District Court for the Northern
District of Texas, Dallas Division, against TXU Corp., Energy and TXU Portfolio
Management. The Court has reset this case for trial on June 6, 2005 and
discovery in the case is proceeding. 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. Energy 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, Energy does
not believe that there is any merit to the plaintiff's claims under
Sarbanes-Oxley. TXU Corp., Energy and TXU Portfolio Management dispute the
plaintiff's claims and intend to vigorously defend the litigation.
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 case was transferred to the Beaumont
Division of the Eastern District of Texas and on March 24, 2004 subsequently
transferred to the Northern District of Texas, Dallas Division. 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. Defendants have filed a
motion to dismiss the lawsuit which is pending before the court; however, as a
result of the dismissal of the antitrust claims in the litigation described
above brought by TCE, the parties have agreed to stay this litigation until the
appeal in the TCE case has been decided. Energy believes that the plaintiff
lacks standing to assert any antitrust claims against TXU Corp. or TXU Portfolio
Management, and that defendants have not violated antitrust laws or other laws
as claimed by plaintiff. Therefore, Energy believes that plaintiff's claims
are without merit and plans to vigorously defend the lawsuit. Energy is,
however, unable to estimate any possible loss or predict the outcome of this
action.
General -- In addition to the above, Energy is involved in various other
legal and administrative proceedings in the normal course of business the
ultimate resolution of which, in the opinion of management, should not have a
material effect upon its financial position, results of operations or cash
flows.
7. DERIVATIVES AND HEDGES
As of September 30, 2004, it is expected that $68 million of after-tax net
losses accumulated in other comprehensive income will be reclassified into
earnings during the next twelve months. Of this amount, $62 million relates to
commodity hedges and $6 million relates to financing-related hedges.
Energy experienced net hedge ineffectiveness of $4 million and $21
million, reported as a loss in revenues, for the three and nine months ended
September 30, 2004, respectively. For the three and nine months ended September
30, 2003, there were no hedge ineffectiveness losses.
The net effect of unrealized mark-to-market ineffectiveness accounting
(versus settlement accounting), which includes the above amounts as well as the
effect of reversing unrealized gains and losses recorded in previous periods to
offset realized gains and losses in the current period, totaled $3 million and
$20 million, respectively, in net losses for the three and nine months ended
September 30, 2004 and $10 and $24 million in net gains for the three and nine
months ended September 30, 2003.
16
8. SUPPLEMENTARY FINANCIAL INFORMATION
Other Income and Deductions --
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- -------------------
2004 2003 2004 2003
-------- -------- -------- ------
Other income:
Net gain on sale of properties and businesses. $ 35 $ 19 $ 48 $ 40
Other......................................... 1 1 2 3
------ ------ ------ ------
Total other income......................... $ 36 $ 20 $ 50 $ 43
====== ====== ====== ======
Other deductions:
Software write-off............................ $ (2) $ - $ 107 $ -
Employee severance charges.................... 3 - 89 -
Spare parts inventory writedown............... - - 79 -
Equity in losses of unconsolidated entities... 8 - 8 -
Expenses related to canceled construction
projects.................................... 1 2 5 4
Casualty loss (gas storage explosion)......... 5 - 5 -
Settlement of purchase power agreement........ 3 - 3 -
Loss on retirement of debt.................... 1 1 1 1
Other......................................... 1 1 4 4
------ ------ ------ ------
Total other deductions..................... $ 20 $ 4 $ 301 $ 9
====== ====== ====== ======
Severance Liability Related to Restructuring Activities
Energy
------
Liability for severance costs accrued as of June 30, 2004........... $ 84
Additions to liability.......................................... 3
Payments charged against liability.............................. (53)
----
Liability for severance costs accrued as of September 30, 2004... $ 34
=====
The above table excludes severance included in discontinued operations.
Interest Expense and Related Charges --
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -------------------
2004 2003 2004 2003
-------- -------- -------- ------
Interest (a)....................................... $ 68 $ 62 $ 197 $ 217
Distributions on preferred membership interests (b) 17 17 51 17
Amortization of discount and debt issuance costs... 9 6 21 17
Capitalized interest............................... (3) (2) (6) (5)
------ ------ ------ ------
Total interest expense and related charges...... $ 91 $ 83 $ 263 $ 246
====== ====== ====== ======
(a) Included in interest for the nine months ended September 30, 2003 is $34
million related to the exchangeable subordinated notes that were exchanged
for preferred membership interests in July 2003.
(b) In April 2004, TXU Corp. purchased from the holders Energy's preferred
membership interests, and subsequent to this purchase, Energy has paid
distributions on the preferred membership interests to TXU Corp.
Affiliate Transactions - The following represent the significant affiliate
transactions of Energy:
o Energy incurs electricity delivery fees charged by Electric Delivery.
For the three months ended September 30, 2004 and 2003, these fees
totaled $417 million and $441 million, respectively. For the nine
months ended September 30, 2004 and 2003, these fees totaled $1.1
billion and $1.2 billion, respectively.
o Energy records interest expense to Electric Delivery with respect to
Electric Delivery's generation-related regulatory assets, which now
consists entirely of the securitization bonds. The interest expense
reimburses Electric Delivery for the interest expense Electric Delivery
incurs on that portion of its debt associated with the
generation-related regulatory assets. For the three months ended
September 30, 2004 and 2003, this interest expense totaled $15 million
and $12 million, respectively. For the nine months ended September 30,
2004 and 2003, this interest expense totaled $40 million and $36
million, respectively.
17
o Under the terms of the settlement plan, Electric Delivery issued an
initial $500 million of securitization bonds in 2003 and issued $790
million in June 2004. The incremental income taxes Electric Delivery
will pay on the increased delivery fees to be charged to Electric
Delivery's customers related to the bonds will be reimbursed by Energy.
Therefore, Energy's financial statements reflect a $437 million
non-interest bearing payable to Electric Delivery ($30 million of which
is due currently) that will be extinguished as Electric Delivery pays
the related income taxes.
o The average daily balances of short-term advances to affiliates during
the three months ended September 30, 2004 was $1.5 billion and average
daily short-term advances from affiliates during the three months ended
September 30, 2003 was $47 million. Interest income earned on the
advances for the three months ended September 30, 2004 was $10 million
and interest expense incurred on the advances for the three months
ended September 30, 2003 was $343 million. The weighted average
interest rate for the three months ended September 30, 2004 and
2003 was 2.62% and 2.86%, respectively. The average daily balances of
short-term advances to affiliates during the nine months ended
September 30, 2004 were $905 million and average daily short-term
advances from affiliates during the nine months ended September 30,
2003 was $500 million. Interest income earned on the advances for the
nine months ended September 30, 2004 was $19 million and interest
expense incurred on the advances for the nine months ended September
30, 2003 was $9 million. The weighted average interest rate for the
nine months ended September 30, 2004 and 2003 was 2.77% and 2.76%,
respectively.
o TXU Business Services charges Energy for financial, accounting,
environmental and other administrative services at cost. For the three
months ended September 30, 2004 and 2003, these costs totaled $10
million and $54 million, respectively, and are primarily included in
SG&A expenses. For the nine months ended September 30, 2004 and 2003,
these costs totaled $144 million and $173 million, respectively.
Effective July 1, 2004, under the ten year services agreement with
Capgemini several of the functions previously performed by TXU
Business Services are now provided by Capgemini. Outsourced base
support services performed by Capgemini for a fixed fee, subject to
adjustment for volumes or other factors, include information
technology, customer call center, billing, human resources, supply
chain and certain accounting activities (See Note 1 for further
discussion).
o Energy received payments from TXU Gas under a service agreement that
began in 2002 and ended June 30, 2004 and covered customer billing and
customer support services provided for TXU Gas. These revenues totaled
$15 million and $22 million for the nine months ended September 30,
2004 and 2003, respectively, and are included in other revenues. On
October 1, 2004, TXU Corp. and Atmos Energy Corporation completed a
merger by division in which Atmos Energy Corporation acquired TXU Gas'
operations.
o Energy records the amount owed by Electric Delivery for the future
costs of decommissioning the Comanche Peak nuclear facility as a
non-current asset. Funds for decommissioning are collected monthly from
Electric Delivery. Realized gains and other earnings on the nuclear
decommissioning trust holdings reduce the non-current asset. As of
September 30, 2004, the balance of the noncurrent asset related to the
Comanche Peak nuclear facility asset retirement obligation was $42
million.
o In April 2004, TXU Corp. purchased from the holders Energy's
exchangeable preferred membership interests, and as a result Energy has
paid distributions to TXU Corp. on these securities, which remain
outstanding, since the purchase. Interest expense and related charges
associated with these securities, including amortization of the
related discount, totaled $21 million for the three months ended
September 30, 2004 and $37 million for the nine months ended
September 30, 2004 since the date of TXU Corp.'s purchase of
securities.
Pension and Other Postretirement Benefits -- Energy is a participating
employer in the TXU Retirement Plan, a defined benefit pension plan sponsored by
TXU Corp. Energy also participates with TXU Corp. and other affiliated
subsidiaries of TXU Corp. to offer health care and life insurance benefits to
eligible employees and their eligible dependents upon the retirement of such
employees. The allocated net periodic pension cost and net periodic
postretirement benefits cost other than pensions applicable to Energy was $12
million and $15 million for the three month periods ended September 30, 2004 and
2003, respectively and $43 million and $44 million for the nine months ended
September 30, 2004 and 2003, respectively.
The Capgemini outsourcing transaction on July 1, 2004, (see Note 1)
triggered a curtailment of the pension and postretirement plans and a
remeasurement of the related liabilities. The effects of the remeasurement,
which include an increase in the discount rate of 0.25%, as well as the Medicare
Act enacted in December 2003, have resulted in lower pension and postretirement
benefits expense.
18
Accounts Receivable -- At September 30, 2004 and December 31, 2003,
accounts receivable of $989 million and $943 million are stated net of allowance
for uncollectible accounts of $40 million and $51 million, respectively. During
the nine months ended September 30, 2004, bad debt expense was $76 million,
account write-offs were $90 million and other activity increased the allowance
for uncollectible accounts by $3 million. During the nine months ended September
30, 2003, bad debt expense was $68 million, account write-offs were $64 million
and other activity decreased the allowance for uncollectible accounts by $4
million. Allowances related to receivables sold are reported in current
liabilities and totaled $35 million and $39 million at September 30, 2004 and
December 31, 2003, respectively.
Accounts receivable included $406 million and $388 million of unbilled
revenues at September 30, 2004 and December 31, 2003, respectively.
Intangible Assets -- Intangible assets other than goodwill are comprised
of the following:
As of September 30, 2004 As of December 31, 2003
----------------------------- ------------------------------
Gross Gross
Carrying Accumulated Carrying Accumulated
Amount Amortization Net Amount Amortization Net
------ ------------ ---- ------- ------------ ----
Intangible assets subject to amortization included
in property, plant and equipment:
Capitalized software placed in service
(unrelated to outsourced activities at
September 30, 2004)...................... $ 3 $ 1 $ 2 $ 241 $ 112 $ 129
Land easements............................ 2 1 1 11 8 3
Mineral rights and other.................. 30 22 8 31 22 9
----- ----- ----- ----- ----- -----
Total................................... $ 35 $ 24 $ 11 $ 283 $ 142 $ 141
===== ===== ===== ===== ===== =====
Aggregate Energy amortization expense for intangible assets for the three
months ended September 30, 2004 and 2003 was less than $1 million and $10
million, respectively. Aggregate Energy amortization expense for intangible
assets for the nine months ended September 30, 2004 and 2003 was $21 million and
$27 million, respectively. At September 30, 2004, the weighted average useful
lives of capitalized software, land easements and mineral rights and other were
5 years, 54 years and 40 years, respectively.
During the second quarter of 2004, Energy transferred information
technology assets, consisting primarily of capitalized software, to a
subsidiary of TXU Corp at book value. See Note 1 for further discussion.
Goodwill of $517 million and $533 million at September 30, 2004 and
December 31, 2003, respectively, was stated net of previously recorded
accumulated amortization of $60 million. Energy transferred $16 million of
goodwill to US Holdings in connection with the transfer of TXU Fuel Company to
US Holdings on April 30, 2004.
Commodity Contracts -- At September 30, 2004 and December 31, 2003,
current and noncurrent commodity contract assets, arising largely from
mark-to-market accounting, totaled $936 million and $657 million, respectively,
and are stated net of applicable credit (collection) and performance reserves
totaling $23 million and $18 million, respectively. Performance reserves are
provided for direct, incremental costs to settle the contracts. Current and
non-current commodity contract liabilities totaled $854 million and $549 million
at September 30, 2004 and December 31, 2003, respectively.
Inventories by Major Category --
September 30, December 31,
2004 2003
------- --------
Materials and supplies.................................................... $ 133 $ 225
Fuel stock................................................................ 79 78
Gas stored underground.................................................... 84 83
------- -------
Total inventories................................................... $ 296 $ 386
======= =======
19
As described in Note 1, Energy recorded a charge in the second quarter of
$79 million ($51 million after-tax) to write down spare parts and equipment
inventory.
Property, Plant and Equipment -- At September 30, 2004 and December 31,
2003, property, plant and equipment of $9.8 billion and $10.3 billion is stated
net of accumulated depreciation and amortization of $7.4 billion and $7.6
billion, respectively.
Supplemental Cash Flow Information -- See Note 1 regarding the effects of
Capgemini being provided a royalty-free right, under an asset license
arrangement, to use information technology assets, consisting primarily
of capitalized software, which were noncash in nature. See Note 2 for the
effects of adopting SFAS 143, which were noncash in nature. The transfer of TXU
Fuel Company ownership as discussed in Note 5 was noncash in nature.
20
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
TXU Energy Company LLC:
We have reviewed the accompanying condensed consolidated balance sheet of TXU
Energy Company LLC and subsidiaries (Energy) as of September 30, 2004, and the
related condensed statements of consolidated income and of comprehensive income
for the three-month and nine-month periods ended September 30, 2004 and 2003,
and the condensed statements of consolidated cash flows for the nine-month
periods ended September 30, 2004 and 2003. These interim financial statements
are the responsibility of Energy's management.
We conducted our review in accordance with standards of the Public Company
Accounting Oversight Board (United States). A review of interim financial
information consists principally of applying analytical procedures to financial
data and making inquiries of persons responsible for financial and accounting
matters. It is substantially less in scope than an audit in accordance with
standards of the Public Company Accounting Oversight Board (United States), 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 review, we are not aware of any material modifications that should
be made to such condensed consolidated interim 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 standards of the Public Company
Accounting Oversight Board (United States), the consolidated balance sheet of
Energy as of December 31, 2003, and the related statements of consolidated
income, comprehensive income, cash flows and membership interests for the year
then ended (not presented herein); and in our report (which includes an
explanatory paragraph related to the rescission of Emerging Issues Task Force
Issue No. 98-10), dated March 11, 2004, 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, 2003, is fairly stated in all material respects in relation to the
consolidated balance sheet from which it has been derived.
DELOITTE & TOUCHE LLP
Dallas, Texas
November 12, 2004
21
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION
AND RESULTS OF OPERATIONS
BUSINESS
Energy is a subsidiary of US Holdings, which is a subsidiary of TXU Corp.
Energy is engaged in electricity generation and retail and wholesale energy
sales.
Energy currently has no reportable segments, however, management intends
to realign its operations into two core business segments consisting of Power
(the electricity production business) and Energy (the retail and wholesale
energy sales and hedging and risk management operations) effective with
reporting for the first quarter of 2005.
Strategic Initiatives and Other Actions -Mr. C. John Wilder, who was named
president and chief executive of TXU Corp. in February 2004, and senior
management have been reviewing the operations of TXU Corp. and have formulated
certain strategic initiatives and continue to develop others. Areas being
reviewed include:
o Performance in competitive markets, including profitability in new
markets;
o Cost structure, including organizational alignments and headcount;
o Management of natural gas price risk and cost effectiveness of the
generation fleet; and
o Non-core business activities.
Energy anticipates performance improvements as a result of various
strategic initiatives, including lower administrative support costs, more
efficient and cost-effective utilization of generation-related assets and
increased return on investments. As discussed below, implementation of the
strategic initiatives as well as other actions taken to date have resulted in
total charges of $8 million ($5 million after-tax) in the third quarter of 2004
and $284 million ($185 million after-tax) year-to-date, substantially all
reported in other deductions, related to asset writedowns and employee
severance. In the third quarter of 2004, Energy recorded gains on the
disposition of properties, principally undeveloped land, totaling $18 million
($12 million after-tax), reported in other income.
Charges recorded in the three-month and nine-month periods ended September
30, 2004 and 2003 reported in other deductions are detailed in Note 8 to
Financial Statements.
The review of Energy's operations and formulation of strategic initiatives
is ongoing, and additional charges are expected. The phases of the plan
resulting in the charges to date are anticipated to be largely completed in
2004. Upon completion of each phase of the plan, Energy expects to fully
describe the actions intended to improve the financial performance of its
operations. Certain of the strategic initiatives described below could result in
additional material charges that Energy is currently unable to predict. In
addition, other new strategic initiatives are likely to be undertaken that could
also materially affect Energy's financial results.
Capgemini Energy Agreement
--------------------------
On May 17, 2004, Energy entered into a services agreement with a
subsidiary of Cap Gemini North America Inc., Capgemini Energy LP (Capgemini), a
new company initially providing business process support services to TXU Corp.,
but immediately implementing a plan to offer similar services to other utility
companies. Under the ten-year agreement, over 2,500 TXU Corp. employees
(including approximately 1,100 from Energy) transferred to Capgemini effective
July 1, 2004. Outsourced base support services performed by Capgemini for a
fixed fee, subject to adjustment for volumes or other factors, include
information technology, customer call center, billing and collections, human
resources, supply chain and certain accounting activities. Energy expects that
the Capgemini arrangement will result in lower costs and improved service
levels.
As part of the agreements, Capgemini was provided a royalty-free right,
under an asset license arrangement, to use information technology assets,
consisting primarily of capitalized software. A portion of the software was in
development and had not yet been placed in service by Energy. As a result of
outsourcing its information technology activities, Energy no longer intends to
develop the majority of these projects and from Energy's perspective the
software is abandoned. The agreements with Capgemini do not
22
require that any software in development be completed and placed in
service. Consequently, the carrying value of these software projects was written
off, resulting in a charge of $107 million ($70 million after-tax) for the nine
months ended September 30, 2004, reported in other deductions, essentially all
of which was recorded in the second quarter of 2004. The remaining assets were
transferred to a subsidiary of TXU Corp. at book value in exchange for an
interest in that subsidiary. Such interest is accounted for by Energy on the
equity method, and Energy recorded equity losses (representing depreciation
expense) of $8 million in the third quarter of 2004, reported in other
deductions.
The TXU Corp. subsidiary received a 2.9% limited partnership interest in
Capgemini in exchange for the asset license described above. Energy and Electric
Delivery have the right to sell (the "put option") their interest in the
subsidiary to Cap Gemini America Inc. for $200 million, plus the subsidiary's
share of Capgemini's undistributed earnings, upon expiration of the services
agreement, or earlier upon the occurrence of certain unexpected events. Cap
Gemini North America Inc. has the right to purchase Energy's and Electric
Delivery's interests under the same terms and conditions. The partnership
interest in Capgemini has been recorded at an initial value of $2.9 million and
is being accounted for on the cost method.
Energy has recorded its share of the fair value of the put option as a
noncurrent asset largely offset by a reduction to the carrying value of the
software transferred to the subsidiary, in accordance with the accounting
principles related to sales and licensing of internally developed software
described in AICPA Statement of Position 98-1, "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use."
Also as part of the services agreements, TXU Corp. agreed to indemnify
Capgemini for severance costs incurred by Capgemini for former TXU Corp.
employees terminated within 18 months of their transfer to Capgemini.
Accordingly, Energy recorded a $27 million ($18 million after-tax) charge for
severance expense in the second quarter of 2004, which represents a reasonable
estimate of the indemnity and is reported in other deductions. The charge
includes an allocation of severance related to TXU Business Services Company
employees. In addition, TXU Corp. committed to pay up to $25 million for costs
associated with transitioning the outsourced activities to Capgemini. The
transition costs applicable to Energy are expected to be largely recorded during
the fourth quarter of 2004.
Transfer and Sale of TXU Fuel Company
-------------------------------------
On April 30, 2004, Energy distributed the assets of TXU Fuel Company, its
gas transportation subsidiary, to US Holdings at book value, including $16
million of allocated goodwill. On June 2, 2004, US Holdings completed the sale
of the assets of TXU Fuel Company to Energy Transfer Partners, L.P. for $500
million in cash. The assets of TXU Fuel Company consisted of approximately 1,900
miles of intrastate pipeline and a total system capacity of 1.3 Bcf/day. As part
of the transaction, Energy entered into a market-price based transportation
agreement with the new owner to transport gas to Energy's generation plants.
Because of the continuing involvement in the business through the transportation
agreement, the business has not been accounted for as a discontinued operation.
Facility Closures and Other Actions Related to Generation Operations
--------------------------------------------------------------------
On November 12, 2004, Energy announced plans to declare inactive, or
"mothball", eight natural gas-fired electric generating units. The units
represent a total of 2,516 megawatts (MW), or 25 percent of Energy's
natural gas-fired generation capacity in Texas. The units are less efficient
than others serving market demand. A severance charge, not yet estimated,
related to this action is expected to be recorded in the fourth quarter of
2004.
On October 1, 2004, Energy entered into an agreement to terminate the
operating lease for certain mining equipment for approximately $28 million in
cash, effective November 1, 2004. The lease termination will result in an
estimated net charge of approximately $21 million ($13 million after-tax) to be
recorded in other deductions in the fourth quarter of 2004.
In the third quarter of 2004, Energy recorded gains totaling $18 million
($12 million after-tax) related to the sale of undeveloped land. The gains are
reported in other income.
In the second quarter of 2004, Energy initiated a plan to sell the
Pedricktown, New Jersey 122 MW power production facility and exit the related
power supply and gas transportation agreements. Accordingly, Energy recorded an
impairment charge of $26 million ($17 million after-tax) to write down the
facility to estimated fair market value. The results of the business and the
impairment charge are reported in discontinued operations, as discussed in Note
3 to Financial Statements.
23
As part of Energy's review of its generation asset portfolio, Energy
completed a review of its spare parts and equipment inventory to determine the
appropriate level of such inventory. The review included nuclear, coal and
gas-fired generation-related facilities. As a result of this review, Energy
recorded a charge of $79 million ($51 million after-tax), reported in other
deductions, in the second quarter of 2004 to reflect excess inventory on hand
and to write down carrying values to scrap values.
In March 2004, Energy announced the planned permanent retirement,
completed in the second quarter of 2004, of eight gas-fired operating units due
to electric industry market conditions in Texas. Energy also temporarily closed
four other gas-fired units and placed them under evaluation for retirement. The
12 units represented a total of 1,471 MW, or more than 13%, of Energy's
gas-fired generation capacity in Texas. A majority of the 12 units were
designated as "peaking units" and operated only during the summer for many years
and have operated only sparingly during the last two years. Most of the units
were built in the 1950's. Energy also determined that it would close its
Winfield North Monticello lignite mine in Texas, and such closure has been
completed, as it is no longer economical to operate when compared to the cost of
purchasing coal to fuel the adjacent generation facility. A total charge of $8
million ($5 million after-tax) was recorded in the first quarter of 2004,
reported in other deductions, for production employee severance costs ($7
million pre-tax) and impairments related to the various facility closures ($1
million pre-tax).
Organizational Realignment and Headcount Reductions
---------------------------------------------------
Energy intends to realign its operations into two core business segments
consisting of:
o Power - the electricity production business; and
o Energy - the retail and wholesale energy sales and portfolio management
operations.
Processes are currently being developed to report operating results of the
Power and Energy business segments. (Only operating results for consolidated
Energy are provided in this report.) Results are expected to be reported under
the new segment alignment no later than the first quarter of 2005.
During the second quarter of 2004, management completed a comprehensive
organizational review, including an analysis of staffing requirements. As a
result, Energy completed a self-nomination severance program and finalized a
plan for additional headcount reductions under an involuntary severance program,
which has been largely completed. Accordingly, in the second quarter of 2004,
Energy recorded severance charges totaling $43 million ($28 million after-tax),
reported in other deductions.
Liability and Capital Management
--------------------------------
On November 4, 2004, Energy entered into a five-year revolving credit
facility that allows for (i) bridge loans, (ii) revolving loans and (iii)
letters of credit having a maturity of one year. Bridge loans may total up to
$500 million and will mature no later than October 31, 2005. Letters of credit
may total up to $500 million, but in some instances require prepayment of bridge
loans in an amount equal to the face value of the letter of credit. Revolving
loans may total up to $250 million, but are only available after all bridge
loans have been repaid. The aggregate amount of borrowings outstanding at any
one time may not exceed $500 million. Energy intends to use this facility for
general and corporate purposes, including, in the case of letters of credit,
support for pollution control revenue bonds. In addition, pursuant to the terms
of the five-year revolving credit facility, bridge loans may be used to loan or
distribute funds to TXU Corp. for the repurchase of its common stock.
In April 2004, TXU Corp. purchased from the holders Energy's preferred
membership interests with a liquidation value of $750 million. Energy's carrying
amount of the security, which remains outstanding, is the $750 million
liquidation amount less $242 million remaining unamortized discount and
$30 million in unamortized debt issuance costs.
24
See Note 4 to Financial Statements for further detail of financing
arrangements.
Energy intends to utilize cash provided by operating activities in
accordance with TXU Corp.'s priorities as follows:
o First, investments to preserve and enhance the quality of customer
service and production reliability;
o Second, reinvestments in its businesses, applying stringent
expectations for cash payback timelines and minimum return on
investment; and
o Third, to reduce debt and other liabilities, with the objective of
strengthening the balance sheet and increasing financial flexibility.
Investment in New Trading Entity
--------------------------------
In May 2004, Energy and Credit Suisse First Boston (USA), Inc. announced
they had entered into a memorandum of understanding to establish a 50/50
investment in an energy marketing and trading entity. After a detailed review of
the proposed venture, the parties were unable to agree on an economic
arrangement that met each party's strategic objectives and in September 2004
announced a mutual agreement not to pursue the joint venture. Energy will
continue to leverage its internal wholesale marketing and risk management
capabilities to manage its purchased power needs and economically dispatch its
generation fleet in the Texas market.
Strategic Review of Nuclear Assets
----------------------------------
Energy is currently undertaking a strategic review of its nuclear assets,
comprised of two electricity generating units at Comanche Peak, each with a
capacity of 1,150 MW. The objectives of this strategic review are to evaluate
potential means to reduce the cost risk of outages of these low marginal cost
facilities and improve the long-term availability and certainty of electricity
supply for Energy's customers. Energy continues to identify and evaluate various
potential initiatives as part of this review. Energy expects to complete the
review within six months, and no determination has been made as to the
likelihood of implementing any of the initiatives.
Consolidation of Real Estate
----------------------------
Currently, TXU Corp. owns or leases more than 1.3 million square feet in
various management and support office locations, which exceeds its anticipated
needs. TXU Corp. has evaluated alternatives to reduce current office space and
intends to consolidate into its existing headquarters building in Dallas, Texas,
enhancing the facility to enable better employee communication and collaboration
and cost effectiveness. Implementation of this initiative is expected to result
in charges related to existing leased facilities in the fourth quarter of 2004
and the first quarter of 2005, but the amounts are not yet estimable.
Initiatives to Improve Production Reliability and Performance
-------------------------------------------------------------
Energy is undertaking a number of initiatives to improve customer service,
electricity production reliability and operational performance. These
initiatives include:
o Investment of an additional $275 million over the next three years to
improve reliability of coal and nuclear production assets, a 45%
increase in annual spending over the 2003 investment level; and
o Replacement of four steam generators in one of the two units of the
Comanche Peak nuclear plant in order to maintain the operating
efficiency of the unit. Estimated capital requirements for this
project are $175 million to $225 million, to be spent largely over
the next three years.
25
RESULTS OF OPERATIONS
All dollar amounts in Management's Discussion and Analysis of Financial
Condition and Results of Operations and the tables therein are stated in
millions of US dollars unless otherwise indicated.
The results of operations and the related management's discussion of those
results for all periods presented reflect the discontinuance of the strategic
retail services business and the Pedricktown, New Jersey generation facility
operations of Energy (see Note 3 to Financial Statements regarding discontinued
operations).
26
Operating Data
- --------------
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ ------------------
2004 2003 2004 2003
----- ----- ------ ------
Operating statistics - volumes:
Retail electricity sales volumes (GWh):
Historical service territory (a):
Residential.............................................. 9,760 10,991 24,246 27,242
Small business (b)....................................... 3,260 3,233 8,335 9,798
-------- ------- ------- -------
Total historical service territory..................... 13,020 14,224 32,581 37,040
Other territories (a):
Residential.............................................. 1,096 648 2,345 1,446
Small business (b)....................................... 127 77 277 225
-------- ------- ------- -------
Total other territories................................ 1,223 725 2,622 1,671
Large business and other customers....................... 6,412 8,501 19,891 23,941
-------- ------- ------- -------
Total retail electricity............................... 20,655 23,450 55,094 62,652
Wholesale electricity (GWh)................................. 11,929 10,402 36,653 26,145
-------- ------- ------- -------
Total retail and wholesale electricity sales volumes... 32,584 33,852 91,747 88,797
======== ======= ======= =======
Production and purchased power volumes (GWh):
Nuclear (base load)...................................... 5,036 4,455 13,882 13,608
Lignite/coal (base load)................................. 11,437 11,441 31,863 30,272
Gas/oil.................................................. 1,988 4,048 4,300 11,870
Purchased power.......................................... 15,196 15,673 44,665 37,536
-------- ------- ------- -------
Total energy supply.................................... 33,657 35,617 94,710 93,286
Less line loss and other................................. 1,073 1,765 2,963 4,489
-------- ------- ------- -------
Net energy supply volumes.............................. 32,584 33,852 91,747 88,797
======== ======= ======= =======
Base load capacity factors (%):
Nuclear ................................................. 99.5% 87.8% 92.1% 90.4%
Lignite/coal ............................................ 92.5% 92.8% 86.8% 83.2%
Customer counts:
Retail electricity customers (end of period and in
thousands - based on
number of meters):
Historical service territory (a):
Residential.............................................. 1,997 2,096
Small business (b)....................................... 313 318
------- -------
Total historical service territory..................... 2,310 2,414
Other territories (a)
Residential.............................................. 195 129
Small business (b)....................................... 6 4
------- -------
Total other territories................................ 201 133
Large business and other customers....................... 76 70
------- -------
Total retail electricity customers..................... 2,587 2,617
======= =======
(a) Historical service and other territory data for 2003 are best estimates.
(b) Customers with demand of less than 1 MW annually.
27
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- ------------------
2004 2003 2004 2003
------- ------- ------ ------
Operating revenues (millions of dollars):
Retail electricity revenues:
Historical service territory (a):
Residential.............................................. $1,073 $ 1,086 $ 2,472 $ 2,506
Small business (b)....................................... 352 289 867 922
------ ------- ------- -------
Total historical service territory..................... 1,425 1,375 3,339 3,428
Other territories (a):
Residential.............................................. 113 54 228 126
Small business (b)....................................... 12 6 25 17
------ -------- ------- --------
Total other territories................................ 125 60 253 143
Large business and other customers....................... 458 551 1,366 1,488
------ ------- ------- -------
Total retail electricity revenues........................... 2,008 1,986 4,958 5,059
Wholesale electricity revenues.............................. 487 399 1,429 914
Hedging and risk management activities...................... (64) 4 (61) 139
Other revenues.............................................. 86 48 263 131
------ ------- ------- -------
Total operating revenues............................... $2,517 $ 2,437 $ 6,589 $ 6,243
====== ======= ======= =======
Weather (average for service territory)(c)
Percent of normal:
Cooling degree days.................................... 85.5% 94.0% 87.9% 94.6%
Heating degree days.................................... - - 91.8% 109.4%
(a) Historical service and other territory data for 2003 are best estimates.
(b) Customers with demand of less than 1 MW annually.
(c) Weather data is obtained from Weatherbank, Inc., an independent company
that collects and archives 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 Nine Months Ended
September 30, September 30,
------------------- -------------------
2004 2003 2004 2003
------ ------ ------ ------
Fuel and purchased power costs ($/MWh of supply)
Nuclear generation....................................... $ 4.32 $ 4.75 $ 4.33 $ 4.47
Lignite/coal generation.................................. $ 12.33 $ 11.89 $ 12.64 $12.54
Gas/oil generation and purchased power................... $ 53.03 $ 48.38 $ 48.05 $48.34
Average total electricity supply....................... $ 31.95 $ 31.23 $ 29.77 $30.35
Average retail volume (KWh)/customer
(calculated using average no. of customers for period)
Residential.............................................. 4,921 5,204 12,091 12,673
Small business........................................... 10,530 10,183 26,905 30,599
Large business and other customers....................... 83,907 119,337 274,470 325,248
Average revenues ($/MWh)
Residential.............................................. $109.21 $ 97.99 $101.56 $91.72
Small business........................................... $107.45 $ 89.13 $103.57 $93.71
Large business and other customers....................... $ 71.47 $ 64.85 $ 68.67 $62.14
Average delivery fees ($/MWh) $ 22.06 $ 18.19 $ 21.76 $18.59
Estimated share of ERCOT retail markets
(based on number of meters)
Historical service territory (a):
Residential (b).......................................... 83% 88%
Small business (b)....................................... 81% 84%
Total ERCOT
Residential (b).......................................... 45% 46%
Small business (b)....................................... 32% 33%
Large business and other customers (c)................... 33% 39%
Hedging and risk management activities
Net unrealized mark-to-market gains/(losses)............. $ (15) $ 11 $ (46) $ 58
Realized gains/(losses).................................. (49) (7) (15) 81
------- ------ ------ ------
Total.................................................. $ (64) $ 4 $ (61) $ 139
======= ===== ====== ======
(a) Historical service and other territory data for 2003 are best estimates.
(b) Estimated market share is based on the number of customers that have
choice.
(c) Estimated market share is based on the annualized consumption for
this overall market.
Three Months Ended September 30, 2004 Compared to Three Months Ended
September 30, 2003
- -------------------------------------------------------------------------------
Operating revenues increased $80 million, or 3%, to $2.5 billion in 2004.
Retail electricity revenues increased $22 million, or 1%, to $2.0 billion
reflecting a $258 million increase due to higher average pricing, partially
offset by a $236 million decline due to lower volumes. A 12% drop in sales
volumes was driven by the effect of competitive activity, primarily in the large
business market, and milder weather. Lower business market volumes also
reflected a strategy to target higher margin customer segments. Milder weather
contributed an estimated 6 percentage points to the volume decline. Higher
pricing reflected increased price-to-beat rates, reflecting regulatory approved
fuel factor increases, and higher pricing in the competitive large business
market, both resulting from higher natural gas prices. Retail electricity
customer counts at September 30, 2004 declined 1% from September 30, 2003.
Wholesale electricity revenues grew $88 million, or 22%, to $487 million
reflecting a $58 million increase attributable to a 15% rise in sales volumes
and a $30 million increase due to the effect of increased natural gas prices on
wholesale prices. The increase in wholesale sales volumes also reflected a
partial shift in the customer base from retail to wholesale services,
particularly in the business market.
29
Net results from hedging and risk management activities, which are
reported in revenues and include both realized and unrealized gains and losses,
declined $68 million from a net gain of $4 million in 2003 to a net loss of $64
million in 2004. Because the hedging activities are intended to mitigate the
risk of commodity price movements on revenues and cost of energy sold, the
changes in such results should not be viewed in isolation, but taken together
with the effects of pricing and cost changes on gross margin. Changes in these
results reflect market price movements on commodity positions held to hedge
gross margin. The decline included $22 million in mark-to-market losses
associated with required capacity auctions, $17 million primarily reflecting
increased credit reserves due to the effect of increased natural gas prices on
contracts and $15 million in mark-to-market losses associated with market price
movements against hedges of gas in storage. Results from these activities
included the net effect of recording unrealized gains and losses under
mark-to-market accounting, versus settlement accounting, of $15 million in net
losses in 2004 and net gains of $11 million in 2003. The majority of Energy's
natural gas physical sales and purchases are in the wholesale markets and
essentially represent hedging activities. These activities are accounted for on
a net basis with the exception of retail sales to business customers, which
effective October 1, 2003 are reported gross in accordance with new accounting
rules and totaled $38 million in revenues for the third quarter of 2004. The
increase in other revenues of $38 million to $86 million was driven by this
change.
Gross Margin
Three Months Ended
September 30,
-------------------------------------------------
% of % of
2004 Revenue 2003 Revenue
------ ------- ------ -------
Operating revenues..................................... $ 2,517 100% $ 2,437 100%
Costs and expenses:
Cost of energy sold, including delivery fees...... 1,556 62% 1,539 63%
Operating costs................................... 145 6% 164 7%
Depreciation and amortization related to
generation assets............................. 82 3% 89 4%
------- ----- ------- ------
Gross margin........................................... $ 734 29% $ 645 26%
======= ===== ======= ======
Gross margin is considered a key operating metric as it measures the
effect of changes in sales volumes and pricing versus the variable and fixed
costs of energy sold.
Gross margin increased $89 million, or 14%, to $734 million in 2004. The
margin increase was driven by the higher average pricing, partially offset by
lower results from hedging and risk management activities, and the unfavorable
effects of a volume mix shift from higher margin retail sales to wholesale
sales, higher delivery fees and milder weather. The average cost of total power
produced and purchased was up 2%, reflecting improved utilization of base-load
(nuclear and lignite-fired) production and improved sourcing of purchased power
versus gas-fired generation to largely offset the effects of higher natural gas
prices. Gross margin was also favorably impacted by lower depreciation as
discussed immediately below.
Operating costs decreased $19 million, or 12%, to $145 million in 2004.
The decrease reflected $10 million related to customer care support services
previously provided to TXU Gas (largely offset by lower related revenues), and
$5 million due to the absence of the gas transportation subsidiary sold in June
2004 (largely offset by higher cost of energy sold related to gas-fired
production). Other changes in operating costs were individually immaterial and
largely offsetting.
Depreciation and amortization related to generation assets decreased $7
million, or 8%, to $82 million, reflecting a decrease of $11 million due to
extensions of estimated average depreciable lives of lignite and nuclear
generation facilities' assets to better reflect their useful lives, partially
offset by the effect of mining activity and the related asset retirement
obligation.
Depreciation and amortization not included in gross margin totaled $1
million and $11 million for the three months ended September 30, 2004 and 2003,
respectively. This decline primarily reflected the transfer of information
technology assets, principally capitalized software, to an affiliate in
connection with the Capgemini transaction.
30
SG&A expenses increased $16 million, or 10%, to $182 million in 2004
primarily reflecting a $14 million special compensation incentive program
expense related to trading activities and $12 million in higher deferred
incentive compensation expense due to the increase in the price of TXU Corp.
common stock, partially offset by $6 million in reduced marketing costs outside
the historical service territory and a $4 million decrease in bad debt expense.
Other income increased by $16 million to $36 million in 2004. Other income
in 2004 included an $18 million gain on sale of undeveloped land. Other income
in both 2004 and 2003 reflected $18 million of amortization of a gain on the
sale of two generation plants in 2002.
Other deductions increased by $16 million to $20 million in 2004. Other
deductions in 2004 consisted largely of $8 million in equity losses
(representing depreciation expense) in the TXU Corp. entity holding the
capitalized software licensed to Capgemini, a $5 million natural gas inventory
loss resulting from an explosion at a third-party storage facility and
approximately $3 million to settle a power purchase agreement.
Interest income increased by $12 million to $13 million in 2004 primarily
due to higher average advances to affiliates.
Interest expense and related charges increased by $8 million, or 10%, to
$91 million in 2004. The increase reflected $18 million due to higher average
debt levels and $2 million representing higher interest reimbursement to
Electric Delivery related to securitized regulatory assets partially offset by
$11 million due to lower average interest rates and $1 million in interest
reimbursed to Electric Delivery in 2003 related to the excess mitigation credit
that ceased at the end of 2003.
The effective income tax rate was 33.0% in 2004 and 2003. There were no
material unusual items affecting the comparison.
Results from continuing operations increased $59 million to $309 million
in 2004, reflecting the increase in gross margin partially offset by higher
SG&A. Net pension and postretirement benefit costs reduced results from
continuing operations by $8 million in 2004 and $9 million in 2003. The decrease
in these costs reflects a remeasurement of these liabilities as a result of the
transfer of Energy employees to Capgemini and an increase of 0.25% in the
discount rate due to higher interest rates, as well as the effects of the
Medicare Act enacted in December 2003.
Loss from discontinued operations (see Note 3 to Financial Statements) was
$3 million in 2004 compared to $1 million in 2003. The 2004 loss primarily
reflected costs to complete a services contract.
Nine Months Ended September 30, 2004 Compared to Nine Months Ended
September 30, 2003
- -------------------------------------------------------------------------------
Operating revenues increased $346 million, or 6%, to $6.6 billion in 2004.
Retail electricity revenues decreased $101 million, or 2%, to $5.0 billion. This
decline reflected a $611 million decrease attributable to a 12% drop in sales
volumes, driven by the effect of competitive activity and milder weather,
partially offset by a $510 million increase due to higher average pricing. Lower
business market volumes also reflected a strategy to target higher margin
customer segments. Higher pricing reflected increased price-to-beat rates,
reflecting regulatory approved fuel factor increases, and higher pricing in the
competitive large business market, both resulting from higher natural gas
prices. Retail electricity customer counts at September 30, 2004 declined 1%
from September 30, 2003. Wholesale electricity revenues grew $515 million, or
56%, to $1.4 billion reflecting a $367 million increase attributable to a 40%
rise in sales volumes and a $148 million increase due to the effect of increased
natural gas prices on wholesale prices. Higher wholesale electricity sales
volumes reflected the establishment of the new northeast zone in ERCOT. Because
Energy has a generation plant and a relatively small retail customer base in the
new zone, wholesale sales have increased, and wholesale power purchases also
increased to meet retail sales demand in other zones. The increase in wholesale
sales volumes also reflected a partial shift in the customer base from retail to
wholesale services, particularly in the business market.
31
Net results from hedging and risk management activities, which are
reported in revenues and include both realized and unrealized gains and losses,
declined $200 million from a net gain of $139 million in 2003 to a net loss of
$61 million in 2004. Because the hedging activities are intended to mitigate the
risk of commodity price movements on revenues and cost of energy sold, the
changes in such results should not be viewed in isolation, but rather taken
together with the effects of pricing and cost changes on gross margin. Changes
in these results reflect market price movements on commodity positions held to
hedge gross margin. The decline included $22 million in mark-to-market losses
associated with required capacity auctions, $17 million in increased reserves,
primarily reflecting increased credit reserves due to the effect of increased
natural gas prices on contracts and $15 million in mark-to-market losses
associated with market price movements against hedges of gas in storage. The
comparison also reflected $34 million of additional gas storage and retail gas
business margin in 2003, primarily related to businesses sold in late 2003, $18
million due to a favorable settlement with a counterparty in 2003 and $11
million in gains on contracts that are no longer marked-to-market. Results from
these activities included the net effect of recording unrealized gains and
losses under mark-to-market accounting, versus settlement accounting, of $46
million in net losses in 2004 and net gains of $58 million in 2003. The majority
of Energy's natural gas physical sales and purchases are in the wholesale
markets and essentially represent hedging activities. These activities are
accounted for on a net basis with the exception of retail sales to business
customers, which effective October 1, 2003 are reported gross in accordance with
new accounting rules and totaled $126 million in revenues for the first nine
months of 2004. The increase in other revenues of $132 million to $263 million
in 2004 was primarily driven by this change.
Gross Margin
Nine Months Ended
September 30,
------------------------------------------------
% of % of
2004 Revenue 2003 Revenue
------ ------- ------ ---------
Operating revenues..................................... $ 6,589 100% $ 6,243 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 4,157 63% 4,037 65%
Operating costs................................... 513 8% 506 8%
Depreciation and amortization related to
generation assets............................. 246 4% 277 4%
------- ----- ------- ------
Gross margin........................................... $ 1,673 25% $ 1,423 23%
======= ===== ======= ======
Gross margin increased $250 million, or 18%, to $1.7 billion in 2004. The
margin increase was driven by the higher average pricing, partially offset by
lower results from hedging and risk management activities, and the unfavorable
effects of a volume mix shift from higher margin retail sales to wholesale
sales, higher delivery fees and milder weather. The average cost of total power
produced and purchased declined 2%, reflecting improved utilization of base load
(nuclear and lignite-fired) production and improved sourcing of purchased power
versus gas-fired generation to offset the effects of higher natural gas prices.
Gross margin was also favorably impacted by lower depreciation as discussed
below.
Operating costs increased $7 million, or 1%, to $513 million in 2004. The
increase reflected $31 million in incremental testing, inspection and component
repair costs associated with the planned outage for refueling at the nuclear
facility, partially offset by lower spending for other repair and maintenance
projects. Operating costs reflected decline of $10 million related to customer
care support services previously provided to TXU Gas (largely offset by lower
related revenues), and $7 million due to the absence of the gas transportation
subsidiary sold in June 2004 (largely offset by higher costs of energy sold
related to gas-fired production). Other changes in operating costs were
individually immaterial and largely offsetting.
Depreciation and amortization related to generation assets decreased $31
million, or 11%, to $246 million, reflecting a decrease of $45 million due to
extensions of estimated average depreciable lives of lignite and nuclear
generation facilities' assets to better reflect their useful lives, partially
offset by the effect of mining activity and the related asset retirement
obligation.
Depreciation and amortization not included in gross margin totaled $22
million and $29 million for the nine months ended September 30, 2004 and 2003,
respectively. The decrease reflected the effect of the transfer of information
technology assets, principally capitalized software, to an affiliate in
connection with the Capgemini transaction, partially offset by acceleration of
the amortization of certain software to reflect a shorter useful life.
32
SG&A expenses increased $35 million, or 8%, to $491 million in 2004
reflecting $29 million of higher deferred incentive compensation expense due to
the increase in the price of TXU Corp. common stock, a $14 million special
incentive compensation program expense related to trading activities, $11
million in staffing and other costs to improve customer call center service and
higher bad debt expense of $8 million primarily reflecting a favorable
settlement in 2003, partially offset by $7 million from various cost reduction
initiatives, $6 million in reduced pension and postretirement benefit costs and
$4 million in reduced marketing costs outside the historical service territory.
Other income increased by $7 million to $50 million in 2004. Other income
in 2004 included an $18 million gain on sale of undeveloped property. Other
income in both 2004 and 2003 reflected $30 million of amortization of a gain on
the sale of two generation plants in 2002.
Other deductions increased $292 million to $301 million in 2004. Other
deductions in 2004 consist largely of $107 million for software writedowns, $89
million for employee severance and $79 million in spare parts inventory
writedowns, all discussed above under "Strategic Initiatives and Other Actions."
Other deductions also reflected $8 million in equity losses (representing
depreciation expense) in the TXU Corp. entity holding the capitalized software
licensed to Capgemini, a $5 million natural gas inventory loss resulting from an
explosion at a third-party storage facility and approximately $3 million to
settle a power purchase agreement.
Interest income increased by $18 million to $21 million in 2004 primarily
due to higher average advances to affiliates.
Interest expense and related charges increased by $17 million, or 7%, to
$263 million in 2004. The increase reflected $28 million due to higher average
debt levels and $4 million representing higher interest reimbursement to
Electric Delivery related to securitized regulatory assets, partially offset by
9 million due to lower average interest rates and $6 million in interest
reimbursed to Electric Delivery in 2003 related to the excess mitigation credit
that ceased at the end of 2003.
The effective income tax rate decreased to 30.5% in 2004 from 31.8% in
2003 driven by the effects of ongoing tax benefits of depletion allowances and
amortization of investment tax credits on a lower income base in 2004.
Income from continuing operations before cumulative effect of changes in
accounting principles decreased $32 million to $408 million in 2004, reflecting
the increase in other deductions and SG&A expenses, partially offset by the
higher gross margin. Net pension and postretirement benefit costs reduced income
from continuing operations by $27 million in each of 2004 and 2003. The
decrease in these costs reflects a remeasurement of these liabilities as a
result of the transfer of Energy employees to Capgemini and an increase of
0.25% in the discount rate due to higher interest rates, as well as the effects
of the Medicare Act enacted in December 2003.
Loss from discontinued operations (see Note 3 to Financial Statements) was
$33 million in 2004 compared to $2 million in 2003. The 2004 loss reflected a
$17 million after-tax impairment charge related to the Pedricktown, New Jersey
generation facility, a $6 million after-tax charge to settle a contract dispute
in the strategic retail services business and $6 million after-tax in costs to
complete various strategic retail services contracts.
33
COMMODITY CONTRACTS AND MARK-TO-MARKET ACTIVITIES
The table below summarizes the changes in commodity contract assets and
liabilities for the three and nine months ended September 30, 2004. The net
change in these assets and liabilities, excluding "other activity" as described
below, represents the net effect of recording unrealized gains/(losses) under
mark-to-market accounting, versus settlement accounting, for positions in the
commodity contract portfolio. These positions consist largely of economic hedge
transactions, with speculative trading representing a small fraction of the
activity.
Three Months Nine Months
Ended Ended
September 30, September 30,
2004 2004
------------- -------------
Balance of net commodity contract assets at beginning of period............... $ 87 $ 108
Settlements of positions included in the opening balance (1).................. (7) (46)
Unrealized mark-to-market valuations of positions held at end of period (2)... (5) 20
Net other activity (3)........................................................ 7 -
----- -----
Balance of net commodity contract assets at end of period..................... $ 82 $ 82
===== =====
--------------------------
(1) Represents unrealized mark-to-market valuations of these positions
recognized in earnings as of the beginning of the period.
(2) There were no significant changes in fair value attributable to
changes in valuation techniques.
(3) Includes initial values of positions involving the receipt or
payment of cash or other consideration, such as option premiums
and the amortization of such values. These activities have no
effect on unrealized mark-to-market valuations.
In addition to the net effect of recording unrealized mark-to-market gains
and losses that are reflected in changes in commodity contract assets and
liabilities, similar effects arise in the recording of unrealized
ineffectiveness mark-to-market gains and losses associated with
commodity-related cash flow hedges, which are reflected in changes in cash flow
hedge and other derivative assets and liabilities. The total net effect of
recording unrealized gains and losses under mark-to-market accounting, versus
settlement accounting, is summarized as follows:
Three Months Ended Nine Months Ended
September 30, September 30,
------------------- ------------------
2004 2003 2004 2003
------ ------ ------ ------
Operating revenues:
Unrealized gains/(losses) related to commodity contract portfolio.. $ (12) $ 1 $ (26) $ 34
Ineffectiveness gains/(losses) related to cash flow hedges ....... (3) 10 (20) 24
------ ----- ------ -----
Total unrealized gains/(losses)................................... $ (15) $ 11 $ (46) $ 58
====== ===== ====== =====
These amounts are included in the "hedging and risk management activities"
component of revenues.
34
Maturity Table -- Of the net commodity contract asset balance above at
September 30, 2004, the amount representing unrealized mark-to-market net gains
that have been recognized in current and prior years' earnings is $96 million.
The offsetting net liability of $14 million included in the September 30, 2004
balance sheet is comprised principally of amounts representing current and prior
years' net receipts of cash or other consideration, including option premiums,
associated with contract positions, net of any amortization. The following table
presents the unrealized mark-to-market balance at September 30, 2004, scheduled
by contractual settlement dates of the underlying positions.
Maturity dates of unrealized net mark-to-market balances at September 30, 2004
------------------------------------------------------------------------------
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........... $ 88 $ - $ - $ - $ 88
Prices provided by other
external sources............. 76 (86) 10 (3) (3)
Prices based on models........... 12 (1) - - 11
---- ----- --- ---- -----
Total............................ $176 $(87) $10 $ (3) $ 96
==== ===== === ===== =====
Percentage of total fair value... 183% (90)% 10% (3)% 100%
As the above table indicates, 93% of the unrealized mark-to-market
valuations at September 30, 2004 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. The "prices provided by other external sources"
category represents forward commodity positions at locations for which
over-the-counter broker quotes are available. Over-the-counter quotes for power
and natural gas generally extend through 2005 and 2010, respectively. The
"prices based on models" category contains the value of all non-exchange traded
options, valued using industry accepted option pricing models. In addition, this
category contains other contractual arrangements which may have both forward and
option components. In many instances, these contracts can be broken down into
their component parts and modeled as simple forwards and options based on prices
actively quoted. As the modeled value is ultimately the result of a combination
of prices from two or more different instruments, it has been included in this
category.
COMPREHENSIVE INCOME
Cash flow hedge activity reported in other comprehensive income from
continuing operations included:
Three Months Ended Nine Months Ended
September 30, September 30,
----------------------- --------------------
2004 2003 2004 2003
--------- -------- --------- -----
Cash flow hedge activity (net of tax):
Net change in fair value of hedges-gains/(losses):
Commodities.............................................. $ (12) $ (20) $ (87) $ (118)
Losses realized in earnings (net of tax):
Commodities.............................................. 6 45 16 113
Financing - interest rate swaps.......................... 2 1 4 4
------- ------- ------- -------
8 46 20 117
------- ------- ------- -------
Effect of cash flow hedges reported in comprehensive
results related to continuing operations................. $ (4) $ 26 $ (67) $ (1)
======== ======= ======== ========
35
FINANCIAL CONDITION
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows -- Cash flows provided by operating activities for the nine
months ended September 30, 2004 decreased $241 million to $788 million compared
to the nine-month period ended September 30, 2003. The decrease reflected
unfavorable working capital (accounts receivable, accounts payable and
inventories) changes of $200 million due largely to the effect of higher
collections in 2003 following billing delays experienced during the transition
to competition, $137 million in higher margin deposits associated with hedging
activities and $103 million in higher tax payments in 2004, partially offset by
higher cash earnings (net income adjusted for the significant noncash items
identified in the statement of cash flows) of $223 million.
Cash flows used in financing activities for 2004 were $605 million
compared to $1.4 billion for 2003. The activity in 2004 primarily reflected
advances to affiliates of $1.2 billion and distributions to US Holdings of $525
million, partially offset by net cash provided by debt issuances and retirements
of $556 million and bank borrowings of $565 million. The activity in 2003
reflected repayments of advances from affiliates of $1.6 billion, cash
distributions to US Holdings of $575 million and payment of bank borrowings of
$282 million, partially offset by net cash provided by debt issuances and
retirements of $1.1 billion.
Cash flows used in investing activities were $156 million in 2004 and $158
million in 2003. Capital expenditures, including nuclear fuel, increased by $27
million in 2004 from $168 million in 2003, driven by the timing of nuclear
refueling activities. Proceeds from the sale of undeveloped land provided $18
million in 2004 and the sale of certain retail commercial and industrial gas
operations provided $19 million in 2003. Investing activities in 2004 also
included $22 million in cash from the settlement of interest rate swaps.
Depreciation and amortization expense reported in the statement of cash
flows exceeds the amount reported in the statement of income by $47 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.
Financing Activities
- --------------------
Over the next twelve months, Energy and its subsidiaries will need to fund
ongoing working capital requirements and maturities of debt. Energy and its
subsidiaries have funded or intend to fund these requirements through cash on
hand, cash flows from operations, the sale of assets, short-term credit
facilities and the issuance of long-term debt or other securities.
Long-Term Debt Activity -- During the nine months ended September 30,
2004, Energy issued, redeemed, reacquired or made scheduled principal payments
on long-term debt as follows:
Issuances Retirements
--------- -----------
Pollution control revenue bonds.................. $ - $ 222
Senior notes..................................... 800 -
Other............................................ - 7
------ ------
Total......................................... $ 800 $ 229
====== ======
See Note 4 to Financial Statements for further detail of debt issuance and
retirements, financing arrangements and capitalization.
Capitalization -- The capitalization ratios of Energy at September 30,
2004, consisted of long-term debt (less amounts due currently) of 46%, preferred
membership interests held by TXU Corp. (net of unamortized discount balance of
$242 million) of 7% and membership interests of 47%.
Short-term Borrowings --At September 30, 2004, Energy had outstanding
short-term borrowings consisting of bank borrowings under the three-year
revolving credit facility of $565 million at a weighted average interest rate of
4.27%. At December 31, 2003, Energy had no short-term borrowings outstanding.
Credit Facilities -- Energy and Electric Delivery have ongoing credit
facilities totaling $2.5 billion of which $565 million had been borrowed by
Energy at September 30, 2004 under the three-year revolving credit facility
expiring in June 2007. These credit facilities and a TXU Corp. $500 million
five-year revolving credit facility are used for working capital and general
corporate purposes and support issuances of letters of credit. See Note 4 to
Financial Statements for details of the arrangements.
36
Sale of Receivables -- TXU Corp. has established an accounts receivable
securitization program. The activity under this program is accounted for as a
sale of accounts receivable in accordance with SFAS 140. Under the program,
subsidiaries of TXU Corp. (originators) sell trade accounts receivable to TXU
Receivables Company, a consolidated wholly-owned bankruptcy remote direct
subsidiary of TXU Corp., which sells undivided interests in the purchased
accounts receivable for cash to special purpose entities established by
financial institutions. All new trade receivables under the program generated by
the originators are continuously purchased by TXU Receivables Company with the
proceeds from collections of receivables previously purchased. Funding to Energy
under the program at September 30, 2004 and December 31, 2003 totaled $629
million and $504 million, respectively. See Note 4 to Financial Statements for a
more complete description of the program including the financial impact on
earnings and cash flows for the periods presented and the contingencies that
could result in termination of the program.
Cash and Cash Equivalents -- Cash on hand totaled $5 million and $18
million at September 30, 2004 and December 31, 2003, respectively.
Credit Ratings -- The current credit ratings for TXU Corp. and certain of
its subsidiaries are presented below:
TXU Corp. US Holdings Electric Delivery Electric Delivery Energy
---------------- ---------------- ----------------- ----------------- --------------
(Senior Unsecured) (Senior Unsecured) (Secured) (Senior Unsecured) (Senior Unsecured)
---------------- ---------------- ----------------- ----------------- -----------------
S&P............... BBB- BBB- BBB BBB- BBB
Moody's........... Ba1 Baa3 Baa1 Baa2 Baa2
Fitch............. BBB- BBB- A-/BBB+ BBB+ BBB
Moody's and Fitch currently maintain a stable outlook for TXU Corp., US
Holdings, Energy and Electric Delivery. Electric Delivery first mortgage bonds
are rated A- and its senior secured notes are rated BBB+ by Fitch. 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 Energy contain financial
covenants that require maintenance of specified fixed charge coverage ratios,
membership interests to total capitalization ratios and leverage ratios and/or
contain minimum net worth covenants. As of September 30, 2004, Energy was in
compliance with all such applicable covenants.
Certain financing and other arrangements of Energy and its subsidiaries
contain provisions that are specifically affected by changes in credit ratings
and also include cross default provisions. The material credit rating and cross
default provisions are described below.
Other agreements of Energy, 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 Energy
or its subsidiaries.
Credit Rating Covenants
- -----------------------
Energy has provided a guarantee of the obligations under TXU Corp.'s lease
(approximately $120 million at September 30, 2004) for its headquarters
building. In the event of a downgrade of Energy's credit rating to below
investment grade, a letter of credit would need to be provided within 30 days of
any such rating decline.
37
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 Energy to post collateral in the event that its credit rating falls
below investment grade. Based on its current commodity contract positions, if
Energy were downgraded below investment grade by any specified rating agency,
counterparties would have the option to request Energy to post additional
collateral of approximately $182 million.
In addition, Energy has a number of other contractual arrangements under
which the counterparties would have the right to request Energy to post
collateral. The amount Energy would post under these transactions depends in
part on the value of the contracts at that time and Energy's rating by each of
the three rating agencies. As of September 30, 2004, based on current contract
values, the maximum Energy would post for these transactions is $170 million. Of
this amount, $150 million relates to one specific counterparty that would
require Energy to post collateral if all three rating agencies downgraded Energy
to below investment grade.
Energy is also the obligor on leases aggregating $158 million. Under the
terms of those leases, if Energy's credit rating were downgraded to below
investment grade by any specified rating agency, 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.
Cross Default Provisions
- ------------------------
Certain financing arrangements contain provisions that would result in an
event of default if there were a failure under other financing arrangements to
meet payment terms or to observe other covenants that would result in an
acceleration of payments due. Such provisions are referred to as "cross default"
provisions.
A default by TXU Corp. on indebtedness with a principal amount in excess
of $50 million would result in a cross default under its $500 million five-year
revolving credit facility expiring August 2008, which facility is also made
available to Energy.
A default by TXU Corp., Energy or Electric Delivery in respect of
indebtedness in a principal amount in excess of $50 million would result in a
cross default under TXU Corp.'s new $2.3 billion, 364 day credit facility.
A default by Energy or Electric Delivery or any subsidiary thereof in
respect of indebtedness in a principal amount in excess of $50 million would
result in a cross default for such party under the $2.5 billion joint credit
facilities expiring in June 2005, 2007 and 2009. Under these credit facilities,
a default by Energy or any subsidiary thereof would cause the maturity of
outstanding balances under such facility to be accelerated as to Energy but not
as to Electric Delivery. Also, under this credit facility, a default by Electric
Delivery or any subsidiary thereof would cause the maturity of outstanding
balances under such facility to be accelerated as to Electric Delivery but not
as to Energy.
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
$30 million of TXU Mining (a subsidiary of Energy) senior notes, which have a $1
million cross default threshold.
A default by Energy in respect of indebtedness in a principal amount in
excess of $50 million would result in a cross default under its new $500 million
five year credit facility.
Energy has entered into certain mining and equipment leasing arrangements
aggregating $109 million that would terminate upon the default of any other
obligations of Energy owed to the lessor. In the event of a default by TXU
Mining on indebtedness in excess of $1 million, a cross default would result
under the $30 million TXU Mining leveraged lease and the lease could 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 each have a cross
default threshold of $50,000. If either an originator, TXU Business Services or
TXU Receivables Company defaults on indebtedness of the applicable threshold,
the facility could terminate.
38
Energy enters into energy-related contracts, the master forms of which
contain provisions whereby an event of default would occur if Energy were to
default under an obligation in respect of borrowings in excess of thresholds,
which vary, stated in the contracts.
Energy and its subsidiaries have other arrangements, including leases with
cross default provisions, the triggering of which would not result in a
significant effect on liquidity.
Long-term Contractual Obligations and Commitments -- The table below
reflects updates of amounts presented in Energy's 2003 Form 10-K to reflect the
obligation under the business services outsourcing agreement with Capgemini,
changes in purchase obligations, and the repayment of debt and other instruments
as discussed in Note 1 to Financial Statements.
Contractual Cash Obligations
One to Three to More
Less Than Three Five Than Five
One Year Years Years Years
-------- -------- ---------- -------
Long-term debt and preferred membership interest -
Principal and interest/dividends.................... $ 281 $1,266 $ 687 $5,358
Lease obligations...................................... 74 145 144 412
Purchase obligations................................... 2,265 1,598 489 455
Business services outsourcing obligations.............. 182 334 334 793
Pension and other postretirement liabilities........... 45 89 89 45
------- ------ ------ ------
Total contractual cash obligations.................. $2,847 $3,432 $1,743 $7,063
====== ====== ====== ======
OFF BALANCE SHEET ARRANGEMENTS
TXU Corp.'s accounts receivable securitization program is discussed in
Note 4 to Financial Statements.
COMMITMENTS AND CONTINGENCIES
Guarantees -- See Note 6 to Financial Statements for details of
contingencies, including guarantees.
REGULATION AND RATES
Price-to-Beat Rates - Under the 1999 Restructuring Legislation, Energy is
required to continue to charge a "price-to-beat" rate established by the
Commission to residential customers in the historical service territory. Energy
must continue to make price-to-beat rates available to small business customers,
however, it may offer rates other than price-to-beat, since it met the
requirements of the 40% threshold target calculation in December 2003. The
price-to-beat rate can be adjusted upward or downward twice a year, subject to
approval by the Commission, for changes in the market price of natural gas.
In March 2004, Energy filed a request with the Commission to increase the
fuel factor component of its price-to-beat rates. This request was approved May
13, 2004. In accordance with the Commission's order, the new rate became
effective on May 20, 2004. This adjustment raised the average monthly
residential electric bill of a customer using 1,000 kilowatt hours by 3.4% or
$3.39 per month.
In June 2004, Energy filed its second request for this year with the
Commission to increase the fuel factor component of its price-to-beat rates.
This request was approved July 28, 2004 and became effective on August 4, 2004.
The filing reflects an increase of 12.7% in the market price of natural gas
since the March 2004 filing. This adjustment raised the average monthly
residential electric bill of a customer using 1,000 kilowatt hours by 5.7% or
$5.87 per month.
Other Commission Matters -- On May 27, 2004, the Commission opened an
investigation to gather information regarding Electric Delivery's and its
affiliates' compliance with the Commission's affiliate code of conduct rules.
Conversations with the Commission indicate that this investigation was prompted
in large part by the utility's change in its legal corporate name from Oncor
Electric Delivery Company back to TXU Electric Delivery Company. Those
39
discussions indicate a reasonable expectation that the Commission will focus its
investigation on Energy's implementation of a disclaimer rule that requires
Energy to place a disclaimer in certain advertisements and on business cards to
explain the distinction between Energy and Electric Delivery.
Energy, along with several ERCOT wholesale market participants, has filed
an appeal at the Court of Appeals for the Third District of Texas (Austin)
contesting certain aspects of a recently adopted Commission rule regarding
enforcement standards applicable to the wholesale power market. Energy believes
that certain portions of the rule as adopted are unconstitutionally vague and
other portions may exact an unconstitutional taking of private property without
just compensation. There is no statutory deadline by which the court must act on
the appeal.
In August 2004, Energy proposed a tiered pricing program for
out-of-territory customers (i.e., those customers outside of Energy's
traditional North Texas service area) that would provide the lowest prices to
customers that Energy has determined will pose the lowest risk of poor payment
behavior, and higher prices to customers who will pose a higher risk of poor
payment behavior. Energy's proposed tiered pricing program would have made use
of credit information obtained from a credit reporting agency to make the
payment risk determination. On September 8, 2004, the Texas Office of Public
Utility Counsel ("OPC") filed a complaint at the Commission alleging generally
that the use of credit information is unlawfully discriminatory. Subsequently,
on September 14, 2004, Energy filed its response to the OPC complaint and in
that response, in addition to asserting that the proposed pricing plan is
lawful, notified the Commission that, pursuant to the Commission Staff's
request, Energy would suspend implementation of the proposed tiered pricing
program for at least 45 days, so that Energy could engage in discussions with
Commission Staff, OPC, and others regarding other tools to address the pressing
issue of mounting bad debt (uncollectibles). OPC requested, and the Commission
granted, the dismissal of the complaint without prejudice to refiling. These
discussions began shortly thereafter and are continuing.
ERCOT Market Issues The Texas Public Utility Regulatory Act ("PURA") and
the Commission are subject to "sunset review" by the Texas Legislature in the
2005 legislative session. Sunset review entails, generally, a comprehensive
review of the need for and efficacy of an administrative agency (e.g., the
Commission), along with an evaluation of the advisability of any changes to that
agency's authorizing legislation (e.g., PURA). As part of the sunset review
process, the legislative Sunset Advisory Commission has recommended that the
Legislature re-authorize the Commission for at least 6 years, and has
recommended other changes to PURA that are not expected to have a material
adverse impact upon the Company's operations. The Legislature could consider and
enact other changes to PURA and the Company cannot predict whether any such
changes might have a material adverse impact on its operations.
In addition to sunset review, the Texas Legislature and other Texas
governmental entities have initiated investigations into alleged improprieties
regarding some contracting practices of ERCOT, the non-governmental entity that
has operational control of the electric grid for much of Texas. To date, these
activities have not resulted in actions that are expected to have a material
impact on Energy's operations, but Energy cannot predict whether the
culmination of these or other governmental activities that may affect the ERCOT
market may result in any such material adverse effect.
Wholesale market design In August 2003, the Commission adopted a rule
that, if fully implemented, would alter the wholesale market design in ERCOT.
The rule requires ERCOT:
o to use a stakeholder process to develop a new wholesale market mode;
o to operate a voluntary day-ahead energy market;
o to directly assign all congestion rents to the resources that caused
the congestion;
o to use nodal energy prices for resources;
o to provide information for energy trading hubs by aggregating nodes;
o to use zonal prices for loads; and
o to provide congestion revenue rights (but not physical rights).
Under the rule, the proposed market design and associated cost-benefit
analysis is to be filed with the Commission by November 1, 2004 and is to be
implemented by October 1, 2006. On September 17, 2004, the Commission opened a
rulemaking project to possibly delay the filing date of the proposed market
design from November 1, 2004 to March 1, 2005. On October 28, the Commission
40
adopted a rule change that would delay the filing date for the proposed market
design until March 18, 2005. Additionally, the Commission approved an extension
until December 31, 2004 for the filing of the cost-benefit analysis. TXU Energy
is currently unable to predict the cost or impact of implementing any proposed
change to the current wholesale market design.
Environmental Matters -- On October 1, 2004, TXU Corp. released an
independent study by NERA Economic Consulting in collaboration with Marc
Goldsmith & Associates. The study evaluated TXU Corp.'s processes for following
and evaluating air emissions and climate policies and reviewed the company's
actions regarding previous major air emissions policies and compliance.
Additionally, the study considered the financial consequences and related risks
to TXU Corp. of prospective air emissions and climate change policies, including
an assessment of the financial effects of reducing emissions now in anticipation
of future requirements. The study concluded that TXU Corp. has the appropriate
processes and procedures in place and uses appropriate economic methodologies to
evaluate financial consequences of environmental regulatory policy changes and
scenarios. The study also concluded that absent certain specific circumstances,
TXU Corp.'s shareholders would not benefit if the company devoted major
financial resources now to reduce its carbon dioxide emissions in advance of
uncertain future emission regulations. In addition, the study concluded that TXU
Corp.'s efforts have consistently resulted in compliance with air emission
limits. The study is available on TXU Corp.'s website at
http://www.txucorp.com/envcom/default.asp.
Summary -- Although Energy cannot predict future regulatory or legislative
actions or any changes in economic and securities market conditions, no changes
are expected in trends or commitments, other than those discussed in this
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 Energy's operations, financial
results and financial condition, and could cause Energy's actual results or
outcomes to differ materially from any projected outcome contained in any
forward-looking statement in this report, include:
The implementation of performance improvement initiatives identified by
management may not produce the desired results and may result in disruptions
arising from employee displacements and the rapid pace of changes to
organizational structure and operating practices and processes.
ERCOT is the independent system operator that is responsible for
maintaining reliable operation of the bulk electric power supply system in the
ERCOT region. Its responsibilities include the clearing and settlement of
electricity volumes and related ancillary services among the various
participants in the deregulated Texas market. Because of new processes and
systems associated with the opening of the market to competition, which continue
to be improved, there have been delays in finalizing these settlements. As a
result, Energy is subject to settlement adjustments from ERCOT related to prior
periods, which may result in charges or credits impacting future reported
results of operations.
Energy's businesses operate in changing market environments influenced by
various legislative and regulatory initiatives regarding deregulation,
regulation or restructuring of the energy industry, including deregulation of
the production and sale of electricity. Energy will need to adapt to these
changes and may face increasing competitive pressure.
41
Energy's businesses are subject to changes in laws (including PURA, the
Federal Power Act, as amended, the Atomic Energy Act, as amended, the Public
Utility Regulatory Policies Act of 1978, as amended, the Clean Air Act, as
amended, and the Public Utility Holding Company Act of 1935, as amended) and
changing governmental policy and regulatory actions (including those of the
Commission, the FERC, the EPA and the NRC) with respect to matters including,
but not limited to, market structure and design, operation of nuclear power
facilities, construction and operation of other power generation facilities,
recovery of purchased gas costs, decommissioning costs, and present or
prospective wholesale and retail competition. In particular, PURA and the
Commission are subject to "sunset review" by Texas Legislature in the upcoming
2005 legislative session. See "ERCOT Market Issues" and "Wholesale Market
Design" above.
Energy, along with other market participants, is subject to oversight by
the Commission. In that connection, Energy and other market participants may be
subject to various competition-related rules and regulations, including but not
limited to possible price-mitigation rules, as well as rules related to market
behavior.
Energy is not guaranteed any rate of return on its capital investments in
unregulated businesses. Energy markets and trades power, including power from
its own production facilities, as part of its wholesale energy sales business
and portfolio management operation. Energy's results of operations are likely to
depend, in large part, upon prevailing retail rates, which are set, in part, by
regulatory authorities, and market prices for electricity, gas and coal in its
regional market and other competitive markets. Market prices may fluctuate
substantially over relatively short periods of time. Demand for electricity can
fluctuate dramatically, creating periods of substantial under- or over-supply.
During periods of over-supply, prices might be depressed. Also, at times there
may be political pressure, or pressure from regulatory authorities with
jurisdiction over wholesale and retail energy commodity and transportation
rates, to impose price limitations, bidding rules and other mechanisms to
address volatility and other issues in these markets.
Some of the fuel for Energy's power production facilities is purchased
under short-term contracts or on the spot market. Prices of fuel, including
natural gas, may also be volatile, and the price Energy can obtain for power
sales may not change at the same rate as changes in fuel costs. In addition,
Energy purchases and sells natural gas and other energy related commodities, and
volatility in these markets may affect Energy's costs incurred in meeting its
obligations.
Volatility in market prices for fuel and electricity may result from:
o severe or unexpected weather conditions,
o seasonality,
o changes in electricity usage,
o illiquidity in the wholesale power or other markets,
o transmission or transportation constraints, inoperability or
inefficiencies,
o availability of competitively priced alternative energy sources,
o changes in supply and demand for energy commodities,
o changes in power production capacity,
o outages at Energy's power production facilities or those of its
competitors,
o changes in production and storage levels of natural gas, lignite, coal
and crude oil and refined products,
o natural disasters, wars, sabotage, terrorist acts, embargoes and other
catastrophic events, and
o federal, state, local and foreign energy, environmental and other
regulation and legislation.
All but one of Energy's 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 correlated 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
Energy's base load power production is dependent in significant part upon the
price of gas. Energy cannot fully hedge the risk associated with dependency on
gas because of the expected useful life of Energy's power production assets and
the size of its position relative to market liquidity.
To manage its near-term financial exposure related to commodity price
fluctuations, Energy routinely enters into contracts to hedge portions of its
purchase and sale commitments, weather positions, fuel requirements and
inventories of natural gas, lignite, coal, refined products, and other
commodities, within established risk management guidelines. As part of this
strategy, Energy routinely utilizes fixed-price forward physical purchase and
42
sales contracts, futures, financial swaps and option contracts traded in the
over-the-counter markets or on exchanges. However, Energy can normally cover
only a small portion of the exposure of its assets and positions to market price
volatility, and the coverage will vary over time. To the extent Energy has
unhedged positions, fluctuating commodity prices can materially impact Energy's
results of operations and financial position, either favorably or unfavorably.
Although Energy 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 function as planned and cannot
eliminate all the risks associated with these activities. As a result of these
and other factors, Energy cannot predict with precision the impact that risk
management decisions may have on its business, results of operations or
financial position.
Energy might not be able to satisfy all of its guarantees and
indemnification obligations, including those related to hedging and risk
management activities, if they were to come due at the same time.
Energy's hedging and risk management activities are exposed to the risk
that counterparties that owe Energy 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 various factors including 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, Energy might be forced to acquire alternative hedging arrangements or
honor the underlying commitment at then-current market prices. In such event,
Energy might incur losses in addition to amounts, if any, already paid to the
counterparties. ERCOT market participants are also exposed to risks that another
ERCOT market participant may default in its obligations to pay ERCOT for power
taken in the ancillary services market, in which case such costs, to the extent
not offset by posted security and other protections available to ERCOT, may be
allocated to various non-defaulting ERCOT market participants.
The current credit ratings for Energy's 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
Energy's ratings, borrowing costs would increase and the potential pool of
investors and funding sources would likely decrease. If the downgrade were below
investment grade, liquidity demands would be triggered by the terms of a number
of commodity contracts, leases and other agreements.
Most of Energy's large customers, suppliers and counterparties require
sufficient creditworthiness in order to enter into transactions. If Energy's
ratings were to decline to below investment grade, costs to operate the power
business 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 Energy.
In addition, as discussed in Energy's Annual Report on Form 10-K for the
year ended December 31, 2003, the terms of certain of Energy's 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 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 Energy's facilities was constructed many
years ago. In particular, older generating equipment, even if maintained in
accordance with good engineering practices, may require significant capital
expenditures to keep it operating at peak efficiency. The risk of increased
maintenance and capital expenditures arises from (a) increased starting and
stopping of generation equipment due to the volatility of the competitive
market, (b) any unexpected failure to produce power, including failure caused by
43
breakdown or forced outage, and (c) repairing damage to facilities due to
storms, natural disasters, wars, terrorist acts and other catastrophic events.
Further, Energy's ability to successfully and timely complete capital
improvements to existing facilities or other capital projects is contingent upon
many variables and subject to substantial risks. Should any such efforts be
unsuccessful, Energy 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, Energy's ability to obtain insurance, and the cost of and
coverage provided by such insurance, could be affected by events outside its
control.
The ownership and operation of nuclear facilities, including Energy's
ownership and operation of the Comanche Peak generation plant, involve certain
risks. These risks include: mechanical or structural problems; inadequacy or
lapses in maintenance protocols; the impairment of reactor operation and safety
systems due to human error; the costs of storage, handling and disposal of
nuclear materials; limitations on the amounts and types of insurance coverage
commercially available; and uncertainties with respect to the technological and
financial aspects of decommissioning nuclear facilities at the end of their
useful lives. The following are among the more significant of these risks:
o Operational Risk - Operations at any nuclear power production plant could
degrade to the point where the plant would have to be shut down. Over the
next three years, certain equipment at Comanche Peak is expected to be
replaced. The cost of these actions is currently expected to be material
and could result in extended outages. 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
other 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 Energy's resources, including insurance coverage.
Energy is subject to extensive environmental regulation by governmental
authorities. In operating its facilities, Energy is required to comply with
numerous environmental laws and regulations, and to obtain numerous governmental
permits. Energy may incur significant additional costs to comply with these
requirements. If Energy 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 Energy or its facilities, and future changes in
environmental laws and regulations could occur, including potential regulatory
and enforcement developments related to air emissions.
Energy 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 Energy 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 Energy's older
facilities, including base load lignite and coal plants, it may be uneconomical
for Energy to install the necessary equipment, which may cause Energy to shut
down those facilities.
44
In addition, Energy 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,
Energy may obtain, or be required to provide, indemnification against certain
environmental liabilities. Another party could fail to meet its indemnification
obligations to Energy.
Energy is obligated to offer the price-to-beat rate to requesting
residential and small business customers in its historical service territory
within Texas through January 1, 2007. Energy is not permitted to offer
electricity to the residential customers in the historical service territory at
a price other than the price-to-beat rate until January 1, 2005, unless before
that date the Commission determines that 40% or more of the amount of electric
power consumed by residential customers in that area is committed to be served
by REPs other than Energy. Because Energy will not have the same level of
residential customer price flexibility as competitors in the historical service
territory, Energy could lose a significant number of these customers to other
providers.
Other REPs are allowed to offer electricity to Energy's residential
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. Headroom may be a
positive or a negative number. The higher the amount of positive headroom for
competitive REPs in a given market, the more incentive those REPs would have to
compete in providing retail electric services in that market, which may result
in Energy losing customers to competitive REPs.
The results of Energy's retail electric operations in the historical
service territory is largely dependent upon the amount of headroom available to
Energy and the competitive REPs in Energy's price-to-beat rate. Since headroom
is dependent, in part, on power production and purchase costs, Energy does not
know nor can it estimate the amount of headroom that it or other REPs will have
in Energy's price-to-beat rate or in the price-to-beat rate for the affiliated
REP in each of the other Texas retail electric markets.
There is no assurance that future adjustments to Energy's price-to-beat
rate will be adequate to cover future increases in its costs of electricity to
serve its price-to-beat rate customers or that Energy's price-to-beat rate will
not result in negative headroom in the future.
In most retail electric markets outside the historical service territory,
Energy's principal competitor may be the retail affiliate of the local incumbent
utility company. The incumbent retail affiliates have the advantage of
long-standing relationships with their customers. In addition to competition
from the incumbent utilities and their affiliates, Energy may face competition
from a number of other energy service providers, or other energy industry
participants, who may develop businesses that will compete with Energy and
nationally branded providers of consumer products and services. Some of these
competitors or potential competitors may be larger and better capitalized than
Energy. If there is inadequate margin in these retail electric markets, it may
not be profitable for Energy to enter these markets.
Energy depends on transmission and distribution facilities owned and
operated by other utilities, as well as Electric Delivery's facilities, to
deliver the electricity it produces and sells to consumers, as well as to other
REPs. If transmission capacity is inadequate, Energy's ability to sell and
deliver electricity may be hindered, it may have to forgo sales or it may have
to buy more expensive wholesale electricity that is available in the
capacity-constrained area. In particular, during some periods transmission
access is constrained to some areas of the Dallas-Fort Worth metroplex. Energy
expects to have a significant number of customers inside these constrained
areas. The cost to provide service to these customers may exceed the cost to
provide service to other customers, resulting in lower headroom. In addition,
any infrastructure failure that interrupts or impairs delivery of electricity to
Energy's customers could negatively impact the satisfaction of its customers
with its service.
Energy offers its customers a bundle of services that include, at a
minimum, the electric commodity itself plus transmission, distribution and
related services. The prices Energy 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, could fall below Energy's underlying
cost to obtain the commodities or services.
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. These systems and processes require ongoing refinement, which may
prove more expensive than planned and may not work as planned. Delays in the
perfection of these systems and processes and any related increase in costs
could have a material adverse impact on Energy's business and results of
operations.
45
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 Energy's. While demand for electric energy services is
generally increasing throughout the US, the rate of construction and development
of new, more efficient power production facilities may exceed increases in
demand in some regional electric markets. Consequently, where Energy has
facilities, the market value of Energy's power production facilities could 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 Energy's facilities. Changes in technology
could also alter the channels through which retail electric customers buy
electricity.
Energy is a holding company and conducts its operations primarily through
wholly-owned subsidiaries. Substantially all of Energy's consolidated assets are
held by these subsidiaries. Accordingly, Energy's cash flows and ability to meet
its obligations and to pay distributions are largely dependent upon the earnings
of its subsidiaries and the distribution or other payment of such earnings to
Energy in the form of distributions, loans or advances, and repayment of loans
or advances from Energy. The subsidiaries are separate and distinct legal
entities and have no obligation to provide Energy with funds for its payment
obligations, whether by distributions, loans or otherwise.
The inability to raise capital on favorable terms, particularly during
times of uncertainty in the financial markets, could impact Energy's ability to
sustain and grow its businesses, which are capital intensive, and would increase
its capital costs. Energy 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. Energy's access to the financial markets could be
adversely impacted by various factors, such as:
o changes in credit markets that reduce available credit or the ability
to renew existing liquidity facilities on acceptable terms;
o inability to access commercial paper markets;
o a deterioration of Energy's credit or a reduction in Energy's credit
ratings;
o extreme volatility in Energy's markets that increases margin or
credit requirements;
o a material breakdown in Energy's risk management procedures;
o prolonged delays in billing and payment resulting from delays in
switching customers from one REP to another; and
o the occurrence of material adverse changes in Energy's businesses
that restrict Energy's ability to access its liquidity facilities.
A lack of necessary capital and cash reserves could adversely impact the
evaluation of Energy's credit worthiness by counterparties and rating agencies,
and would likely increase its capital costs. Further, concerns on the part of
counterparties regarding Energy's liquidity and credit could limit its portfolio
management activities.
As a result of the energy crisis in California during 2001, the recent
volatility of natural gas prices in North America, the bankruptcy filing by
Enron Corporation, accounting irregularities of public companies, and
investigations by governmental authorities into energy trading activities,
companies in the regulated and non-regulated utility businesses have been under
a generally increased amount of public and regulatory scrutiny. Accounting
irregularities at certain companies in the industry have caused regulators and
legislators to review current accounting practices and financial disclosures.
The capital markets and ratings agencies also have increased their level of
scrutiny. Additionally, allegations against various energy trading companies of
"round trip" or "wash" transactions, which involve the simultaneous buying and
selling of the same amount of power at the same price and delivery location and
provide no true economic benefit, power market manipulation and inaccurate power
and commodity price reporting have had a negative effect on the industry. Energy
believes that it is complying with all applicable laws, but it is difficult or
impossible to predict or control what effect events and investigations in the
energy industry may have on Energy's financial condition or access to the
capital markets. Additionally, it is unclear what laws and regulations may
develop, and Energy 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. Any such new accounting
standards could negatively impact reported financial results.
46
The issues and associated risks and uncertainties described above are not
the only ones Energy may face. Additional issues may arise or become material as
the energy industry evolves.
FORWARD-LOOKING STATEMENTS
This report and other presentations made by Energy and its
subsidiaries (collectively, Energy) contain forward-looking statements
within the meaning of Section 21E of the Securities Exchange Act of 1934, as
amended. Although Energy believes that in making any such statement its
expectations are based on reasonable assumptions, any such statement involves
uncertainties and is qualified in its entirety by reference to the following
important factors, among others, that could cause the actual results of
Energy to differ materially from those projected in such forward-looking
statements: (i) prevailing governmental policies and regulatory actions,
including those of the Federal Energy Regulatory Commission, the Commission, the
NRC, particularly with respect to allowed rates of return, industry, market and
rate structure, purchased power and investment recovery, operations of nuclear
generating facilities, acquisitions and disposal of assets and facilities,
operation and construction of plant facilities, decommissioning costs, present
or prospective wholesale and retail competition, changes in tax laws and
policies and changes in and compliance with environmental and safety laws and
policies, (ii) general industry trends, (iii) weather conditions and other
natural phenomena, and acts of sabotage, wars or terrorist activities, (iv)
unanticipated population growth or decline, and changes in market demand and
demographic patterns, (v) competition for retail and wholesale customers, (vi)
pricing and transportation of crude oil, natural gas and other commodities,
(vii) unanticipated changes in interest rates, commodity prices or rates of
inflation, (viii) unanticipated changes in operating expenses, liquidity needs
and capital expenditures, (ix) commercial bank market and capital market
conditions, (x) competition for new energy development opportunities, (xi) legal
and administrative proceedings and settlements, (xii) inability of the various
counterparties to meet their obligations with respect to Energy's financial
instruments, (xiii) changes in technology used and services offered by
Energy, and (xiv) significant changes in Energy's relationship with its
employees and the potential adverse effects if labor disputes or grievances were
to occur, (xv) power costs and availability, (xvi) changes in business strategy,
development plans or vendor relationships, (xvii) availability of qualified
personnel, (xviii) implementation of new accounting standards, (xix) global
financial and credit market conditions, and credit rating agency actions and
(xx) access to adequate transmission facilities to meet changing demands.
Any forward-looking statement speaks only as of the date on which such
statement is made, and Energy 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
Energy 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 presented 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 2003 Form 10-K and
is therefore not presented herein.
COMMODITY PRICE RISK
Energy continuously reviews its disclosed risk analysis metrics. In the
course of this review, it was determined that the Portfolio VaR metric would no
longer be disclosed as it is not a meaningful measure of actionable commodity
price risk. Other metrics that measure the effect of such risk on earnings, cash
flows and the value of its mark-to-market contract portfolio continue to be
disclosed. Energy may in the future add or eliminate other metrics in its
disclosures of risks.
47
VaR for Energy Contracts Subject to Mark-to-Market Accounting -- This
measurement estimates the potential loss in value, due to changes in market
conditions, of all energy-related contracts subject to mark-to-market
accounting, based on a specific confidence level and an assumed holding period.
Assumptions in determining this VaR include using a 95% confidence level and a
five-day holding period. A probabilistic simulation methodology is used to
calculate VaR, and is considered by management to be the most effective way to
estimate changes in a portfolio's value based on assumed market conditions for
liquid markets.
September 30, December 31,
2004 2003
------------- ------------
Period-end MtM VaR..................................................... $ 15 $ 15
Average Month-end MtM VaR: over the nine and twelve month periods...... $ 19 $ 25
Other Risk Measures -- The metrics appearing below provide information
regarding the effect of changes in energy market conditions on earnings and cash
flow.
Earnings at Risk (EaR) -- EaR measures the estimated potential loss of
expected pretax earnings for the year presented due to changes in market
conditions. EaR metrics include the owned generation assets, estimates of retail
load and all contractual positions except for accrual positions expected to be
settled beyond the fiscal year. Assumptions include using a 95% confidence level
over a five-day holding period under normal market conditions.
Cash Flow at Risk (CFaR) -- CFaR measures the estimated potential loss of
expected cash flow over the next six months, due to changes in market
conditions. CFaR metrics include all owned generation assets, estimates of
retail load and all contractual positions that impact cash flow during the next
six months. Assumptions include using a 99% confidence level over a six-month
holding period under normal market conditions.
September 30, December 31,
2004 2003
------------- -------------
EaR .............................................................. $ 6 $ 15
CFaR ............................................................. $ 57 $ 67
INTEREST RATE RISK
See Note 4 to Financial Statements for a discussion of the issuance and
retirement of debt since December 31, 2003.
CREDIT RISK
Concentration of Credit Risk -- As of September 30, 2004, the exposure to
credit risk from large business customers and hedging counterparties, excluding
credit collateral, is $1.0 billion, net of standardized master netting contracts
and agreements that provide the right of offset of positive and negative credit
exposures with individual customers and counterparties. When considering
collateral currently held by Energy (cash, letters of credit and other security
interests), the net credit exposure is $914 million. Of this amount,
approximately 83% is with investment grade customers and counterparties, as
determined by using publicly available information including major rating
agencies' published ratings and Energy's internal credit evaluation process.
Those customers and counterparties without an S&P rating of at least BBB- or
similar rating from another major rating agency are rated using internal credit
methodologies and credit scoring models to estimate an S&P equivalent rating.
Energy routinely monitors and manages its credit exposure to these customers and
counterparties on this basis.
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The following table presents the distribution of credit exposure as of
September 30, 2004, for trade accounts receivable from large business customers,
commodity contract assets and other derivative assets that arise primarily from
hedging activities, by investment grade and noninvestment grade, credit quality
and maturity.
Exposure by Maturity
----------------------------------------
Exposure
before Greater
Credit Credit 2 years or Between than 5
Collateral Collateral Net Exposure less 2-5 years years Total
---------- ---------- ------------ ---------- --------- ------ -----
Investment grade $ 805 $ 43 $ 762 $ 628 $ 72 $ 62 $ 762
Noninvestment grade 205 53 152 127 14 11 152
------- ------ ----- ----- ---- ----- -----
Totals $ 1,010 $ 96 $ 914 $ 755 $ 86 $ 73 $ 914
======= ====== ===== ===== ==== ===== =====
Investment grade 80% 44% 83%
Noninvestment grade 20% 56% 17%
Energy has exposure in the amount of $108 million to one customer or
counterparty that is 12% of the net exposure of $914 million at September 30,
2004. Energy holds a $75 million guaranty from this counterparty's investment
grade parent and is currently negotiating the increase of such guaranty amount.
Additionally, approximately 83% of the credit exposure, net of collateral held,
has a maturity date of two years or less. Energy 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.
ITEM 4. CONTROLS AND PROCEDURES
An evaluation was performed under the supervision and with the
participation of Energy's management, including the principal executive officer
and principal financial officer, of the effectiveness of the design and
operation of the disclosure controls and procedures in effect as of the end of
the current period included in this quarterly report. This evaluation took into
consideration the strategic initiatives described in Note 1 to Financial
Statements. Based on the evaluation performed, Energy's management, including
the principal executive officer and principal financial officer, concluded that
the disclosure controls and procedures were effective. During the most recent
fiscal quarter covered by this quarterly report, there has been no change in
Energy's internal control over financial reporting that has materially affected,
or is reasonably likely to materially affect, Energy's internal control over
financial reporting.
49
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
Reference is made to the discussion in Note 6 to Financial Statements
regarding legal proceedings.
ITEM 6. EXHIBITS
(a) Exhibits provided as part of Part II are:
Previously Filed*
-----------------
With File As
Exhibits Number Exhibit
- -------- ------- -------
10(a) 1-12833 10(c) -- Credit agreement, dated November 4, 2004, by and between TXU
Form 10-Q Energy Company LLC and Wachovia Bank, National Association
(filed November 5,
2004)
(31) Rule 13a - 14(a)/15d - 14(a) Certifications.
31(a) -- Certification of Paul O'Malley, principal executive officer
of TXU Energy Company LLC, pursuant to Rule
13a-14(a)/15d-14(a) of the Securities Act of 1934, as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
31(b) -- Certification of Kirk R. Oliver, principal financial officer
of TXU Energy Company LLC, pursuant to Rule
13a-14(a)/15d-14(a) of the Securities Act of 1934, as
adopted pursuant to Section 302 of the Sarbanes-Oxley Act of
2002.
(32) Section 1350 Certifications.
32(a) -- Certification of Paul O'Malley, principal executive officer
of TXU Energy Company LLC, pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32(b) -- Certification of Kirk R. Oliver, principal financial officer
of TXU Energy Company LLC, pursuant to 18 U.S.C. Section
1350, as adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
(99) Additional Exhibits
99 Condensed Statements of Consolidated Income -
Twelve Months Ended September 30, 2004.
- ------------------
* Incorporated herein by reference.
50
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 ENERGY COMPANY LLC
By /s/ Stanley J. Szlauderbach
----------------------------
Stanley J. Szlauderbach
Assistant Controller and
Interim Controller
Date: November 12, 2004
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