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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_____________________
FORM 10-Q
( X ) QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2004
-- OR --
( ) TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
_____________________
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 August 10, 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 Six Months Ended June 30, 2004 and 2003............................ 1
Condensed Statements of Consolidated Comprehensive Income-
Three and Six Months Ended June 30, 2004 and 2003............................ 2
Condensed Statements of Consolidated Cash Flows -
Six Months Ended June 30, 2004 and 2003...................................... 3
Condensed Consolidated Balance Sheets -
June 30, 2004 and December 31, 2003.......................................... 4
Notes to Condensed Financial Statements...................................... 5
Report of Independent Registered Public Accounting Firm...................... 20
Item 2. Management's Discussion and Analysis of Financial Condition
and Results of Operations.................................................... 21
Item 3. Quantitative and Qualitative Disclosures About Market Risk................... 44
Item 4. Controls and Procedures...................................................... 45
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................................. 46
Item 6. Exhibits and Reports on Form 8-K ............................................ 47
SIGNATURE.......................................................................................... 49
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.
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, theIndependent 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.
MW............................................. megawatts
NRC............................................ United States Nuclear Regulatory Commission
ii
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 Six Months Ended
June 30, June 30,
------------------ -------------------
2004 2003 2004 2003
------ ------ ------ ------
(millions of dollars)
Operating revenues................................................... $2,115 $2,016 $4,072 $3,806
Costs and expenses:
Cost of energy sold and delivery fees............................. 1,348 1,282 2,603 2,498
Operating costs.................................................. 200 162 366 341
Depreciation and amortization..................................... 88 94 185 206
Selling, general and administrative expenses...................... 163 149 307 292
Franchise and revenue-based taxes................................. 27 28 53 55
Other income...................................................... (12) (16) (13) (24)
Other deductions.................................................. 261 2 281 5
Interest income................................................... (7) (1) (8) (3)
Interest expense and related charges.............................. 93 87 172 163
------ ------ ------ ------
Total costs and expenses...................................... 2,161 1,787 3,946 3,533
------ ------ ------ ------
Income (loss) from continuing operations before income taxes and
cumulative effect of changes in accounting principles.............. (46) 229 126 273
Income tax expense (benefit)......................................... (27) 75 27 83
Income (loss) from continuing operations before cumulative effect
of changes in accounting principles............................... (19) 154 99 190
Loss from discontinued operations, net of tax benefit (Note 3)....... (27) - (30) (1)
Cumulative effect of changes in accounting principles, net of
tax benefit (Note 2) ............................................. - - - (58)
------ ------ ------ ------
Net income (loss).................................................... $ (46) $ 154 $ 69 $ 131
====== ====== ====== ======
See Notes to Financial Statements
1
TXU ENERGY COMPANY LLC
CONDENSED STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended Six Months Ended
June 30, June 30,
-------------------- --------------------
2004 2003 2004 2003
------ ------ ------ ------
(millions of dollars)
Components related to continuing operations:
Income (loss) from continuing operations before cumulative effect
of changes in accounting principles............................... $ (19) $ 154 $ 99 $ 190
Other comprehensive income (loss), net of tax effects :
Cash flow hedge activity--
Net change in fair value of derivatives (net of tax benefit of
$13, $11, $44 and $53)....................................... (17) (20) (75) (98)
Amounts realized in earnings during the period (net of tax
expense of $5, $13, $8 and $39)............................. 7 23 12 72
----- ----- ----- ----
Total......................................................... (10) 3 (63) (26)
----- ----- ----- ----
Comprehensive income (loss) related to continuing operations........ (29) 157 36 164
Comprehensive loss related to discontinued operations............... (27) - (30) (1)
Cumulative effect of changes in accounting principles.................. - - - (58)
----- ----- ----- -----
Comprehensive income (loss)............................................ $ (56) $ 157 $ 6 $ 105
===== ===== ===== =====
See Notes to Financial Statements.
2
TXU ENERGY COMPANY LLC
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
-----------------
2004 2003
------ ------
(millions of dollars)
Cash flows - operating activities:
Income from continuing operations before cumulative effect of
changes in accounting principles.............................................. $ 99 $ 190
Adjustments to reconcile income from continuing operations before cumulative
effect of changes in accounting principles to cash provided by
operating activities:
Depreciation and amortization ............................................... 215 237
Deferred income taxes and investment tax credits - net ...................... 58 40
Asset writedown charges...................................................... 188 -
Net gain from sale of assets................................................ (12) (21)
Net effect of unrealized mark-to-market valuations of commodity contracts.... 31 (47)
Changes in operating assets and liabilities..................................... (15) 212
------ ------
Cash provided by operating activities.................................... 564 611
------ ------
Cash flows - financing activities:
Issuances of long-term debt..................................................... - 1,294
Retirements/repurchases of debt................................................. (127) (170)
Increase (decrease) in notes payable to banks................................... 1,675 (282)
Net change in advances from affiliates.......................................... (1,647) (1,355)
Distribution paid to parent..................................................... (350) (400)
Decrease in note payable to TXU Electric Delivery Company....................... - (99)
Debt premium, discount, financing and reacquisition expenses.................... (2) (28)
------ ------
Cash used in financing activities........................................ (451) (1,040)
------ ------
Cash flows - investing activities:
Capital expenditures............................................................ (105) (104)
Nuclear fuel.................................................................... (48) (35)
Proceeds from sale of assets.................................................... - 15
Other........................................................................... 26 (3)
------ ------
Cash used in investing activities........................................ (127) (127)
------ ------
Cash used by discontinued operations.............................................. (2) -
------ ------
Net change in cash and cash equivalents........................................... (16) (556)
Cash and cash equivalents - beginning balance..................................... 18 603
------ ------
Cash and cash equivalents - ending balance........................................ $ 2 $ 47
====== ======
See Notes to Financial Statements.
3
TXU ENERGY COMPANY LLC
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
June 30, December 31,
2004 2003
----------- -------------
(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents........................................ $ 2 $ 18
Advances to affiliates........................................... 1,970 289
Accounts receivable - trade...................................... 1,103 943
Inventories...................................................... 310 386
Commodity contract assets........................................ 596 548
Other current assets............................................. 303 225
---------- ----------
Total current assets........................................... 4,284 2,409
---------- ----------
Investments......................................................... 579 479
Property, plant and equipment - net................................. 9,894 10,345
Goodwill............................................................ 517 533
Commodity contract assets........................................... 142 109
Cash flow hedge and other derivative assets......................... 34 88
Assets held for sale................................................ 23 59
Other noncurrent assets............................................. 138 127
---------- ----------
Total assets................................................... $ 15,611 $ 14,149
========== ==========
LIABILITIES AND MEMBERSHIP INTERESTS
Current liabilities:
Notes payable - banks............................................ $ 1,675 $ -
Long-term debt due currently..................................... 1 1
Accounts payable - trade:
Affiliates (principally TXU Electric Delivery Company)......... 293 211
All other...................................................... 944 713
Notes or other liabilities due TXU Electric Delivery Company..... 19 13
Commodity contract liabilities................................... 550 502
Accrued taxes.................................................... 228 277
Other current liabilities........................................ 629 564
---------- - ---------
Total current liabilities...................................... 4,339 2,281
---------- ----------
Accumulated deferred income taxes................................... 1,913 1,965
Investment tax credits.............................................. 349 360
Commodity contract liabilities...................................... 101 47
Cash flow hedge and other derivative liabilities.................... 242 140
Notes or other liabilities due to TXU Electric Delivery Company..... 418 424
Other noncurrent liabilities and deferred credits................... 1,213 1,341
Long-term debt, less amounts due currently.......................... 2,943 3,084
Preferred membership interests, held by TXU Corp. at June 30,
2004, net of discount of $246 and $253 (Note 4)................... 504 497
Liabilities held for sale........................................... 8 11
---------- ----------
Total liabilities.............................................. 12,030 10,150
---------- ----------
Contingencies (Note 6)
Membership interests (Note 5):
Capital account.................................................. 3,754 4,109
Accumulated other comprehensive loss............................. (173) (110)
---------- ----------
Total membership interests.................................... 3,581 3,999
---------- ----------
Total liabilities and membership interests..................... $ 15,611 $ 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 engages in power production (electricity
generation), retail and wholesale sales of electricity and natural gas, and
engages in commodity hedging and risk management activities. Energy is currently
managed as an integrated business; consequently, there are no reportable
business segments.
Strategic Initiatives and Other Actions - As previously reported, on
February 23, 2004, C. John Wilder was named president and chief executive of TXU
Corp. Mr. Wilder was formerly executive vice president and chief financial
officer of Entergy Corporation. Mr. Wilder has been reviewing the operations of
TXU Corp. and has formulated certain strategic initiatives and continues 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 immediately below, the effects of the implementation of the
strategic initiatives as well as other actions taken to date have resulted in
total charges of $257 million ($167 million after-tax) in the second quarter of
2004 and $274 million ($178 million after-tax) year-to-date, reported in other
deductions, related to asset writedowns and employee severance.
Charges recorded in the three-month and six-month periods ended June 30,
2004 and 2003 reported in other deductions are detailed in Note 7.
Capgemini Energy Agreement
--------------------------
On May 17, 2004, Energy entered into a service 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 include information technology, customer call center, billing and
collections, human resources, supply chain and certain accounting activities.
As part of the agreements, TXU Corp. provided Capgemini a royalty-free
right, under an asset license arrangement, to use Energy's 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, and 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 previously capitalized balance for these software projects was
written off in the second quarter of 2004, resulting in a charge of $109 million
($71 million after-tax), reported in other deductions. The remaining assets,
totaling $134 million, were transferred to a subsidiary of TXU Corp. at book
value, which subsidiary holds the investment in Capgemini, in exchange for an
interest in that subsidiary, which such interest is accounted for by Energy
on the equity method.
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 recorded during the
remainder of 2004.
5
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 intent to sell the business had
been previously disclosed. 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.
Generation Facility Closures and Inventory Write-Down
-----------------------------------------------------
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 represent 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 will close its Winfield North
Monticello lignite mine in Texas later this year as it is no longer economical
to operate. The mine closure will result in the need to purchase 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) and impairments
related to the various facility closures ($1 million).
As part of Energy's review of its generation asset portfolio, during the
second quarter of 2004, 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, to reflect excess inventory on hand
and to write down carrying values to scrap values.
Impairment of New Jersey Generation Facility
---------------------------------------------
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 are
reported in discontinued operations as discussed in Note 3.
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.
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 an approximate $246 million remaining unamortized
discount and $31 million in unamortized debt issuance costs.
See Note 4 for further detail of financing arrangements.
6
Discontinued Businesses - Note 3 presents detailed information regarding
the discontinued New Jersey generation operations, as well as a previously
disclosed discontinued business. The condensed consolidated financial statements
for all periods presented reflect the reclassification of the results of these
businesses (for the periods they were consolidated) 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 components 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.
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 $12 million
and $22 million ($8 million and $14 million after-tax) in the three and six
months, respectively, ended June 30, 2004.
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 six months ended June 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 six months of 2004.
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 six months ended June 30, 2004, the effect of adoption of the
Medicare Act was a reduction of approximately $3 million and $6 million,
respectively, in Energy's postretirement benefit costs.
7
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
====
The asset retirement liability at June 30, 2004 was $607 million,
comprised of a $599 million liability as of December 31, 2003, $20 million of
accretion during the six months ended June 30, 2004, reduced by $12 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.
8
3. DISCONTINUED OPERATIONS
The following summarizes the historical consolidated financial information
of the various businesses reported as discontinued operations:
Three Months Ended June 30, 2004 Six Months Ended June 30, 2004
---------------------------------- ------------------------------------
Strategic Strategic
Retail Retail
Services Pedricktown Total Services Pedricktown Total
-------- ----------- ----- --------- ----------- -----
Operating revenues........................ $ 4 $ 8 $ 12 $ 10 $ 19 $ 29
Operating costs and expenses.............. 5 9 14 12 22 34
Other deductions (income) - net........... 10 - 10 10 - 10
----- ----- ----- ----- ----- -----
Operating income (loss) before income taxes (11) (1) (12) (12) (3) (15)
Income tax expense (benefit).............. (3) - (3) (5) (1) (6)
Operating income (loss)................... (8) (1) (9) (7) (2) (9)
Charge related to exit (after-tax)........ (1) (17) (18) (4) (17) (21)
----- ----- ----- ----- ----- -----
Income (loss) from discontinued operations $ (9) $ (18) $ (27) $ (11) $ (19) $ (30)
----- ----- ----- ----- ----- -----
Three Months Ended June 30, 2003 Six Months Ended June 30, 2003
---------------------------------- -----------------------------------
Strategic Strategic
Retail Retail
Services Pedricktown Total Services Pedricktown Total
-------- ----------- ----- --------- ----------- -----
Operating revenues........................ $ 28 $ 5 $ 33 $ 43 $ 8 $ 51
Operating costs and expenses.............. 26 7 33 41 11 52
----- ----- ----- ----- ----- -----
Operating income (loss) before income taxes 2 (2) - 2 (3) (1)
Income tax expense (benefit).............. 1 (1) - 1 (1) -
Operating income (loss)................... 1 (1) - 1 (2) (1)
----- ----- ----- ----- ----- -----
Income (loss) from discontinued operations $ 1 $ (1) $ - $ 1 $ (2) $ (1)
----- ----- ----- ----- ----- -----
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 include 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.
Balance sheet - The following details the assets and liabilities held for
sale:
June 30, 2004
----------------------------------
Strategic
Retail
Services Pedricktown Total
-------- ----------- -----
Current assets........................................... $ 3 $ 2 $ 5
Investments.............................................. 2 - 2
Property, plant and equipment............................ 1 15 16
----- ----- -----
Total............................................... $ 6 $ 17 $ 23
===== ===== =====
Current liabilities...................................... $ - $ 4 $ 4
Noncurrent liabilities................................... - 4 4
----- ----- -----
Total............................................... $ - $ 8 $ 8
===== ===== =====
9
4. FINANCING ARRANGEMENTS
Short-term Borrowings -- At June 30, 2004, Energy had outstanding
short-term borrowings consisting of bank borrowings of $1.7 billion at a
weighted average interest rate of 3.01%. At December 31, 2003, Energy had no
outstanding short-term borrowings.
Credit Facilities -- At June 30, 2004, TXU Corp. and its subsidiaries had
credit facilities (some of which provide for long-term borrowings) as follows:
- ----------------------------------------------------------------------------------------------------------------
At June 30, 2004
----------------------------------------------
Expiration Authorized Facility Letters of Cash
Facility Date Borrowers Limit Credit Borrowings Availability
- ----------------------------------------------------------------------------------------------------------------
364-day Credit Facility April 2005 TXU Corp. $ 700 $ -- $ 700 $ --
- ----------------------------------------------------------------------------------------------------------------
364-day Credit Facility April 2005 Energy 1,000 -- 1,000 --
- ----------------------------------------------------------------------------------------------------------------
364-day Credit Facility April 2005 TXU Gas 300 -- 300 --
- ----------------------------------------------------------------------------------------------------------------
Energy,Electric
364-day Credit Facility June 2005 Delivery 600 -- -- 600
- ----------------------------------------------------------------------------------------------------------------
Three-Year Revolving Credit Energy,Electric
Facility June 2007 Delivery 1,400 -- 675 725
- ----------------------------------------------------------------------------------------------------------------
Five-Year Revolving Credit
Facility August 2008 TXU Corp. 500 465 -- 35
- ----------------------------------------------------------------------------------------------------------------
Five-Year Revolving Credit Energy,Electric
Facility June 2009 Delivery 500 -- -- 500
------ ------ ------ ------
- ----------------------------------------------------------------------------------------------------------------
Total $5,000 $ 465 $2,675 $1,860
- ----------------------------------------------------------------------------------------------------------------
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 maturing in June 2005, 2007 and 2009. These new 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 June
30, 2004, there was no such commercial paper outstanding.
In April 2004, Energy entered into a $1.0 billion, 364-day credit
facility. At June 30, 2004, the facility was fully drawn and borrowings had been
advanced to affiliates. In July 2004, this facility was repaid with proceeds
from Energy's issuance of $800 million floating rate senior notes and advances
from affiliates and 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 June 30, 2004, $445 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. Additionally, the extension allows for increased availability of
funding through a credit ratings-based reduction 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 deposit for a Baa3/BBB-
rating; 50% for a Baa2/BBB rating; and zero % for a Baa1/BBB+ and above rating
(based on each originator's credit rating).
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.
10
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 $4 million and $6 million for the six-month periods ending June
30, 2004 and 2003, respectively, and approximated 2.1% and 3.6% for the first
six 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 $2 million and $3 million for the first six 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 June 30, 2004 balance sheet reflects $801 million face amount of trade
accounts receivable reduced by $445 million of undivided interests sold by TXU
Receivables Company. Funding under the program decreased $59 million for the six
months ended June 30, 2004. Funding under the program for the six months ended
June 30, 2003 increased $36 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 six months
ended June 30, 2004 and 2003 were as follows:
Six Months Ended June 30,
-------------------------
2004 2003
------ ------
Cash collections on accounts receivable...................................... $ 3,035 $3,068
Face amount of new receivables purchased..................................... (2,903) (2,698)
Discount from face amount of purchased receivables........................... 6 9
Program fees paid............................................................ (4) (6)
Servicing fees paid.......................................................... (2) (3)
Increase (decrease) in subordinated notes payable............................ (73) (406)
------- ------
Energy's operating cash flows (provided) used under the program......... $ 59 $ (36)
======= ======
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.
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.
11
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.
Long-Term Debt -- At June 30, 2004 and December 31, 2003, the long-term
debt of Energy and its consolidated subsidiaries consisted of the following:
June 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)........ 118 118
7.700% Fixed Series 1999A due April 1, 2033.......................................... 111 111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1, 2013(a)... 16 16
7.700% Fixed Series 1999C due March 1, 2032.......................................... 50 50
4.950% Fixed Series 2001A due October 1, 2030, remarketing date April 1, 2004(a)..... -- 121
4.750% Fixed Series 2001B due May 1, 2029, remarketing date November 1, 2006(a)...... 19 19
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011(a)...... 274 274
1.140% Floating Series 2001D due May 1, 2033......................................... 271 271
1.380% Floating Taxable Series 2001I due December 1, 2036(b)......................... 63 63
1.100% Floating Series 2002A due May 1, 2037(b)...................................... 61 61
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)....... 44 44
6.300% Fixed Series 2003B due July 1, 2032........................................... 39 39
6.750% Fixed Series 2003C due October 1, 2038........................................ 72 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(c)...................................... 1,000 1,000
Capital lease obligations............................................................ 12 13
Other................................................................................ 2 8
Fair value adjustments related to interest rate swaps................................ (4) 11
Unamortized discount................................................................. -- (2)
------ ------
Total Energy .................................................................... 2,944 3,085
Less amount due currently................................................................ 1 1
------ ------
Total long-term debt..................................................................... $2,943 $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 June 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 $750 million principal
amount.
12
In July 2004, Energy issued $800 million of floating rate senior notes in
a private placement offering. 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. The Notes will bear interest at an annual rate equal to
3-month LIBOR, reset quarterly, plus 0.78% and will mature on January 17, 2006.
In July 2004, Energy announced its intent to redeem at par value $101
million of Brazos River Authority Pollution Control Revenue Bonds by September
2004, before their scheduled maturity pursuant to terms in the bond documents
that provide for redemption at par upon the occurrence of certain events.
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.
Fair Value Hedges -- At June 30, 2004, $750 million of fixed rate debt was
effectively converted to variable rates through interest rate swap transactions,
accounted for as fair value hedges, expiring through 2013. In August 2004,
fixed-to-variable swaps related to $500 million of such debt were settled for a
gain of $412 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 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 November 2003, Energy approved a cash distribution of $175 million
which was paid to US Holdings in January 2004. In February 2004, Energy approved
a cash distribution of $175 million which was paid to US Holdings in April 2004.
In June 2004, Energy approved a cash distribution of $175 million which was paid
to US Holdings in July 2004.
13
The following table presents the changes in Membership Interests for the
six months ended June 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........... (350) -- (350)
----------------------------------------------------------------------------------------
Net income............................. 69 -- 69
----------------------------------------------------------------------------------------
Cash flow hedges....................... -- (63) (62)
----------------------------------------------------------------------------------------
Transfer of TXU Fuel Company ownership. (73) -- (73)
----------------------------------------------------------------------------------------
Other.................................. (1) -- (2)
----------------------------------------------------------------------------------------
Balance at June 30, 2004................... $3,754 $(173) $3,581
----------------------------------------------------------------------------------------
6. CONTINGENCIES
Request from CFTC - In October 2003, TXU Corp. received an informal
request for information from the US Commodity Futures Trading Commission (CFTC)
seeking voluntary production of information concerning disclosure of price and
volume information furnished by TXU Portfolio Management, a subsidiary of
Energy, to energy industry publications. The request sought information for the
period from January 1, 1999 to October 2003. TXU Corp. cooperated with the CFTC,
and complied with its request for such information. On May 12, 2004, TXU Corp.
received notice from the CFTC that the CFTC had closed its investigation of TXU
Corp. and its subsidiaries related to disclosure of price and volume
information.
In a similar, but unrelated matter, 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. This request seeks
information for the period of October 31, 2003 through January 2, 2004. TXU
Corp. has 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.
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 June
30, 2004, the aggregate maximum amount of residual values guaranteed was
approximately $196 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 $125 million at June
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 $6 million and the maximum total
potential payout is approximately $49 million. No guarantees were issued during
the six months ended June 30, 2004 that required recording a liability. The fair
value of guarantees recorded as of June 30, 2004 was $1.8 million with a maximum
potential payout of $42 million. The average remaining life of the portfolio is
approximately nine years. These guarantees will be transferred or eliminated as
part of expected transactions for the sale of the strategic retail services
business.
14
Letters of credit -- Energy has entered into various agreements that
require letters of credit for financial assurance purposes. Approximately $403
million of letters of credit were outstanding at June 30, 2004 to support
existing floating rate pollution control revenue bond debt of approximately $395
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 $50 million to
support hedging and risk management margin requirements in the normal course of
business. As of June 30, 2004, approximately 77% 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 have filed a motion to
intervene in the action alleging claims substantially identical to TCE's, both
on their own behalf and on behalf of a putative class of all former customers of
TCE. A hearing on these motions was conducted May 20, 2004 during which the
Court stated that it intended to enter an order dismissing the antitrust claims
and an order was entered on June 24, 2004. TCE has indicated that it intends to
appeal 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 set this case for trial on April 4, 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. TXU Corp. believes the plaintiff's claims are without merit.
The plaintiff was terminated as the result of a reduction in force, not as a
reaction to any concerns the plaintiff had expressed, and plaintiff was not in a
position with TXU Portfolio Management such that he had knowledge or information
that would qualify the plaintiff to evaluate TXU Corp.'s financial statements or
assess the adequacy of TXU Corp.'s financial disclosures. Thus, TXU Corp. does
not believe that there is any merit to the plaintiff's claims under
Sarbanes-Oxley. Accordingly, TXU Corp., Energy and TXU Portfolio Management
intend to vigorously defend the litigation. TXU Corp., Energy and TXU Portfolio
Management dispute the plaintiff's claims.
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. TXU Corp. believes that the plaintiff
lacks standing to assert any antitrust claims against TXU Corp. or TXU Portfolio
15
Management, and that defendants have not violated antitrust laws or other laws
as claimed by plaintiff. Therefore, TXU Corp. believes that plaintiff's claims
are without merit and plans to vigorously defend the lawsuit. TXU Corp. is,
however, unable to estimate any possible loss or predict the outcome of this
action.
General -- In addition to the above, Energy and its subsidiaries are
involved in various other legal and administrative proceedings in the normal
course of business the ultimate resolution of which, in the opinion of each,
should not have a material effect upon their financial position, results of
operations or cash flows.
7. SUPPLEMENTARY FINANCIAL INFORMATION
Other Income and Deductions --
Three Months Ended Six Months Ended
June 30, June 30,
------------------ ------------------
2004 2003 2004 2003
------ ------ ------ ------
Other income:
Net gain on sale of properties and businesses....... $ 11 $ 15 $ 12 $ 21
Other............................................... 1 1 1 3
------ ------ ------ ------
Total other income............................... $ 12 $ 16 $ 13 $ 24
====== ====== ====== ======
Other deductions:
Software write-off.................................. $ 109 $ - $ 109 $ -
Employee severance charges.......................... 70 - 86 -
Spare parts inventory writedown..................... 79 - 79 -
Expenses related to canceled construction projects.. 2 1 4 2
Other............................................... 1 1 3 3
------ ------ ------ ------
Total other deductions........................... $ 261 $ 2 $ 281 $ 5
====== ====== ====== ======
Interest Expense and Related Charges --
Three Months Ended Six Months Ended
June 30, June 30,
------------------ --------------------
2004 2003 2004 2003
------ ------ ------ ------
Interest (a)......................................... $ 71 $ 83 $ 129 $ 155
Distributions on preferred membership interests (b).. 17 - 34 -
Amortization of debt issuance costs.................. 6 6 12 11
Capitalized interest................................. (1) (2) (3) (3)
------ ------ ------ ------
Total interest expense and related charges........ $ 93 $ 87 $ 172 $ 163
====== ====== ====== ======
(a) Included in interest for the three and six months ended June 30, 2003 is
$17 million and $34 million, respectively, 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 June 30, 2004 and 2003, these fees
totaled $332 million and $349 million, respectively. For the six months
ended June 30, 2004 and 2003, these fees totaled $681 million and $726
million, respectively.
o Energy records interest expense payable to Electric Delivery
with respect to Electric Delivery's generation-related regulatory
assets that are subject to securitization. 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 June
30, 2004 and 2003, this interest expense totaled $14 million and $12
million, respectively. For the six months ended June 30, 2004 and 2003,
this interest expense totaled $26 million and $24 million,
respectively.
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 ($19 million
of which is due currently) that will be extinguished as Electric
Delivery pays the related income taxes.
16
o Average daily short-term advances to affiliates during the three months
ended June 30, 2004 was $1 billion and average daily short-term
advances from affiliates during the three months ended June 30, 2003
was $139 million. Interest income earned on the advances for the three
months ended June 30, 2004 was $7 million and interest expense incurred
on the advances for the three months ended June 30, 2003 was
$1 million. The weighted average interest rate for the three months
ended June 30, 2004 and 2003 was 2.85% and 3.07%, respectively.
Average daily short-term advances to affiliates during the six months
ended June 30, 2004 were $620 million and average daily short-term
advances from affiliates during the six months ended June 30, 2003 was
$730 million. Interest income earned on the advances for the six months
ended June 30, 2004 was $9 million and interest expense incurred on the
advances for the six months ended June 30, 2003 was $9 million. The
weighted average interest rate for the six months ended June 30, 2004
and 2003 was 2.85% and 2.83%, respectively.
o TXU Business Services charges Energy for financial,
accounting, information technology, environmental, procurement and
personnel services and other administrative services at cost. For the
three months ended June 30, 2004 and 2003, these costs totaled $83
million and $58 million, respectively, and are primarily included in
SG&A expenses. For the six months ended June 30, 2004 and 2003, these
costs totaled $134 million and $119 million, respectively.
o Energy receives payments from TXU Gas under a service
agreement that began in 2002 covering customer billing and customer
support services provided for TXU Gas. These revenues totaled $8
million and $7 million for the three months ended June 30, 2004 and
2003, respectively, and are included in other revenues. These revenues
totaled $15 million and $14 million for the six months ended June 30,
2004 and 2003, respectively, and are included in other revenues.
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 June
30, 2004, the balance of the noncurrent asset related to the Comanche
Peak nuclear facility asset retirement obligation was $37 million.
Retirement Plan 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 $15
million for each of the three month periods ended June 30, 2004 and 2003 and $31
million and $29 million for the six months ended June 30, 2004 and 2003,
respectively.
At June 30, 2004, Energy estimates that its total contributions to the
pension plan and other postretirement benefit plans for the remainder of 2004
will not be materially different than previously disclosed in the 2003 Form
10-K.
Accounts Receivable -- At June 30, 2004 and December 31, 2003, accounts
receivable of $1.1 billion and $943 million are stated net of allowance for
uncollectible accounts of $40 million and $51 million, respectively. During the
six months ended June 30, 2004, bad debt expense was $47 million, account
write-offs were $68 million and other activity increased the allowance for
uncollectible accounts by $10 million. During the six months ended June 30,
2003, bad debt expense was $36 million, account write-offs were $36 million and
other activity decreased the allowance for uncollectible accounts by $7 million.
Allowances related to receivables sold are reported in current liabilities and
totaled $29 million and $39 million at June 30, 2004 and December 31, 2003,
respectively.
Accounts receivable included $406 million and $388 million of unbilled
revenues at June 30, 2004 and December 31, 2003, respectively.
17
Intangible Assets -- Intangible assets other than goodwill are comprised
of the following:
As of June 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.... $ 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 June 30, 2004 and 2003 was $6 million and $8 million, respectively.
Aggregate Energy amortization expense for intangible assets for the six months
ended June 30, 2004 and 2003 was $20 million and $17 million, respectively. At
June 30, 2004, the weighted average useful lives of capitalized software, land
easements and mineral rights and other were 6 years, 59 years and 40 years,
respectively.
During the second quarter of 2004, Energy transferred information
technology assets totaling $134 million, 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 $453 million at June 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 June 30, 2004 and December 31, 2003, current and
noncurrent commodity contract assets, arising largely from mark-to-market
accounting, totaled $738 million and $657 million, respectively, and are stated
net of applicable credit (collection) and performance reserves totaling $19
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 $651 million and $549 million at June 30,
2004 and December 31, 2003, respectively.
Inventories by Major Category --
June 30, December 31,
2004 2003
----------- ------------
Materials and supplies.................................................... $ 129 $ 225
Fuel stock................................................................ 84 78
Gas stored underground.................................................... 97 83
------- -------
Total inventories................................................... $ 310 $ 386
======= =======
As described in Note 1, Energy recorded a charge of $79 million ($51
million after-tax) to write down spare parts and equipment inventory.
Property, Plant and Equipment -- At June 30, 2004 and December 31, 2003,
property, plant and equipment of $9.9 billion and $10.3 billion is stated net of
accumulated depreciation and amortization of $7.4 billion and $7.6 billion,
respectively.
Derivatives and Hedges -- Energy experienced net hedge ineffectiveness of
$5 million and $17 million, reported as a loss in revenues, for the three and
six months ended June 30, 2004. For the three and six months ended June 30,
2003, there was no net hedge ineffectiveness. These losses related primarily to
hedges of anticipated power sales.
18
The net effect of unrealized mark-to-market ineffectiveness 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 $2 million and $17 million in net losses
for the three and six months ended June 30, 2004, respectively, and $8 million
and $14 million in net gains for the three and six months ended June 30, 2003,
respectively.
As of June 30, 2004, it is expected that $57 million of after-tax net
losses accumulated in other comprehensive income will be reclassified into
earnings during the next twelve months. Of this amount, $51 million relates to
commodities hedges and $6 million relates to financing-related hedges. This
amount represents the projected value of the hedges over the next twelve months
relative to what would be recorded if the hedge transactions had not been
entered into. The amount expected to be reclassified is not a forecasted loss
incremental to normal operations, but rather it demonstrates the extent to which
volatility in earnings and cash flows (which would otherwise exist) is mitigated
through the use of cash flow hedges.
Supplemental Cash Flow Information -- See Note 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.
19
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 June 30, 2004, and the
related condensed statements of consolidated income and of comprehensive income
for the three-month and six-month periods ended June 30, 2004 and 2003, and the
condensed statements of consolidated cash flows for the six-month periods ended
June 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
August 12, 2004
20
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 engages in power production (electricity generation), retail and
wholesale sales of electricity and natural gas, and engages in commodity hedging
and risk management activities.
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 energy business)
effective with reporting for the first quarter of 2005.
Strategic Initiatives and Other Actions - As previously reported, on
February 23, 2004, C. John Wilder was named president and chief executive of TXU
Corp. Mr. Wilder was formerly executive vice president and chief financial
officer of Entergy Corporation. Mr. Wilder has been reviewing the operations of
TXU Corp. and has formulated certain strategic initiatives and continues 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 immediately below, the effects of
the implementation of the strategic initiatives as well as other actions taken
to date have resulted in total charges of $257 million ($167 million after-tax)
in the second quarter of 2004 and $274 million ($178 million after-tax)
year-to-date, reported in other deductions, related to asset writedowns and
employee severance.
Charges recorded in the three-month and six-month periods ended June 30,
2004 and 2003 reported in other deductions are detailed in Note 7 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
within one year. 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 changes 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 service 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 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, TXU Corp. provided Capgemini a royalty-free
right, under an asset license arrangement, to use Energy's 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 of 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 previously capitalized balance for these software projects was
written off in the second quarter of 2004, resulting in a charge of $109 million
($71 million after-tax), reported in other deductions. The remaining assets,
totaling $134 million, were transferred to a subsidiary of TXU Corp. at book
value, which subsidiary holds the investment in Capgemini, in exchange for an
interest in that subsidiary, which such interest is accounted for by Energy on
the equity method.
21
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 recorded during the
remainder 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 intent to sell the business had been previously disclosed.
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.
Generation Facility Closures and Inventory Write-Down
-----------------------------------------------------
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 will also temporarily
closed four other gas-fired units and place them under evaluation for
retirement. The 12 units represent 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 will close its Winfield
North Monticello lignite mine in Texas later this year as it is no longer
economical to operate. The mine closure will result in the need to purchase 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) and impairments
related to the various facility closures ($1 million). Should final decisions be
reached, additional charges of approximately $68 million ($44 million after-tax)
would be incurred during the remainder of 2004 associated with future
generation-related facility closures.
As part of Energy's review of its generation asset portfolio, during the
second quarter of 2004, 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, to reflect excess inventory on hand
and to write down carrying values to scrap values.
Impairment of New Jersey Generation Facility
--------------------------------------------
In the second quarter of 2004, management 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 the facility
down to estimated fair market value. The results of the business are reported in
discontinued operations as discussed in Note 3 to the Financial Statements.
22
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 energy business.
Processes are currently being developed to report operating results of
the Power and Energy business segments, taking into consideration the effects of
the expected formation of the energy marketing and trading joint venture. (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.
Accordingly, in the second quarter of 2004, Energy recorded severance charges
totaling $43 million ($28 million after-tax), reported in other deductions.
Investment in New Trading Entity
--------------------------------
Energy and Credit Suisse First Boston (USA), Inc. have entered into a
memorandum of understanding to establish a 50/50 investment in an entity that
would become the exclusive energy marketing and trading vehicle for both parties
in North America. The new entity will market and trade power, natural gas and
other energy-related commodities in North America. The new entity is expected to
begin operations in late 2004.
Strategic Review of Nuclear Assets
----------------------------------
Energy announced its intent to undertake 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.
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 an approximate $246 million remaining unamortized
discount and $31 million in unamortized debt issuance costs.
See Note 4 to Financial Statements for further detail of financing
arrangements.
Consolidation of Real Estate
----------------------------
Currently, TXU Corp. owns or leases more than 1.7 million square feet in
various management and support office locations, far more than its anticipated
needs, which are approximately 20% of that total. TXU Corp. is exploring
alternatives to reduce current office space and consolidate into a location that
will enable better employee communication and collaboration and cost
effectiveness. Implementation of these initiatives may result in charges for
Energy in the second half of 2004, but the amounts are not yet estimable.
23
Capital Allocation Strategy
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.
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.
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.)
24
Operating Data
- --------------
Three Months Ended Six Months Ended
June 30, June 30,
------------------- ------------------
2004 2003 2004 2003
------ ------ ----- ------
Operating statistics - volumes:
Retail electricity (GWh):
Historical service territory (a):
Residential.............................................. 7,367 8,080 14,486 16,250
Small business (b)....................................... 2,542 3,321 5,075 6,565
------- ------- ------- -------
Total historical service territory..................... 9,909 11,401 19,561 22,815
------- ------- ------- -------
Other territories (a):
Residential.............................................. 731 437 1,249 799
Small business (b)....................................... 89 77 150 148
------- ------- ------- -------
Total other territories................................ 820 514 1,399 947
Large business and other customers....................... 6,771 7,889 13,480 15,440
------- ------- ------- -------
Total retail electricity............................... 17,500 19,804 34,440 39,202
Wholesale electricity (GWh)................................. 12,171 8,337 24,724 15,743
------- ------- ------- -------
Total retail and wholesale electricity................. 29,671 28,141 59,164 54,945
======= ======= ======= =======
Production and purchased power (GWh):
Nuclear (base load)...................................... 3,992 4,413 8,845 9,153
Lignite/coal (base load)................................. 10,223 10,144 20,426 18,831
Gas/oil.................................................. 1,401 4,160 2,311 7,822
Purchased power.......................................... 15,237 11,367 29,469 21,863
------- ------- ------- -------
Total energy supply.................................... 30,853 30,084 61,051 57,669
Less line loss and other................................. 1,182 1,943 1,887 2,724
------- ------- ------- -------
Net energy supply...................................... 29,671 28,141 59,164 54,945
======= ======= ======= =======
Base load capacity factors (%):
Nuclear ................................................. 79.5 88.1 88.3 91.7
Lignite/coal ............................................ 83.9 83.0 83.8 78.1
Customer counts:
Retail electricity customers (end of period and in
thousands - based on
number of meters):
Historical service territory (a):
Residential.............................................. 2,037 2,139
Small business (b)....................................... 318 324
------ ------
Total historical service territory..................... 2,355 2,463
Other territories (a)
Residential.............................................. 183 109
Small business (b)....................................... 6 4
------ ------
Total other territories................................ 189 113
Large business and other customers....................... 77 73
------ ------
Total retail electricity customers..................... 2,621 2,649
(a) Historical service and other territory data for 2003 are best estimates.
(b) Customers with demand of less than 1 MW annually.
25
Three Months Ended Six Months Ended
June 30, June 30,
---------------------- ------------------
2004 2003 2004 2003
------ ------ ----- ------
Operating revenues (millions of dollars):
Retail electricity revenues:
Historical service territory (a):
Residential.............................................. $ 750 $ 768 $ 1,400 $ 1,421
Small business (b)....................................... 258 339 514 633
------- ------- ------- -------
Total historical service territory..................... 1,008 1,107 1,914 2,054
Other territories (a):
Residential.............................................. 72 40 115 71
Small business (b)....................................... 8 5 14 11
------- ------- ------- -------
Total other territories................................ 80 45 129 82
Large business and other customers....................... 455 488 908 936
------- ------- ------- -------
Total retail electricity revenues........................... 1,543 1,640 2,951 3,072
Wholesale electricity revenues.............................. 476 279 942 515
Hedging and risk management activities...................... 11 52 3 135
Other revenues.............................................. 85 45 176 84
------- ------- ------- -------
Total operating revenues............................... $ 2,115 $ 2,016 $ 4,072 $ 3,806
Weather (average for service territory) (c)
Percent of normal:
Cooling degree days.................................... 102.7 107.1 105.2 104.7
Heating degree days.................................... 82.0 53.0 87.6 102.3
(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 Meteorlogix, an independent company that
collects weather data from reporting stations of the National Oceanic and
Atmospheric Administration (a federal agency under the US Department of
Commerce).
26
Three Months Ended Six Months Ended
June 30, June 30,
------------------- -------------------
2004 2003 2004 2003
------ ------ ------ ------
Fuel and Purchased Power Costs ($/MWh)
Nuclear generation....................................... $ 4.25 $ 4.35 $ 4.34 $ 4.33
Lignite/coal generation.................................. $ 12.35 $12.84 $12.81 $12.94
Gas/oil generation and purchased power................... $ 47.17 $48.68 $45.60 $48.41
Average total electricity supply....................... $ 30.08 $30.09 $28.66 $29.83
Average Retail Volume (KWh)/Customer
(calculated using average no. of customers for period)
Residential.............................................. 3,649 3,748 7,108 7,456
Small business........................................... 8,161 10,342 16,222 20,272
Large business and other customers....................... 87,380 106,038 184,108 204,454
Average Revenues ($/MWh)
Residential.............................................. $101.53 $94.77 $96.27 $87.45
Small business........................................... $101.28 $101.37 $101.06 $95.97
Large business and other customers....................... $ 67.14 $61.84 $67.33 $60.64
Average Delivery Fees ($/MWh) $ 20.86 $17.90 $21.59 $18.83
Estimated Share of ERCOT Retail Markets
Historical service territory (a):
Residential (b).......................................... 85% 91%
Small business (b)....................................... 79% 85%
Total ERCOT
Residential (b).......................................... 45% 47%
Small business (b)....................................... 32% 34%
Large business and other customers (c)................... 35% 39%
Hedging and Risk Management Activities
Net unrealized mark-to-market gains/(losses)............. $ (13) $ 64 $ (31) $ 47
Realized gains/(losses).................................. 24 (12) 34 88
----- ----- ----- -----
Total.................................................. $ 11 $ 52 $ 3 $ 135
(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 June 30, 2004 Compared to Three Months Ended June 30, 2003
- -----------------------------------------------------------------------------
Operating revenues increased $99 million, or 5%, to $2.1 billion in 2004.
Retail electricity revenues decreased $97 million, or 6%, to $1.5 billion
reflecting a $191 million decline attributable to a 12% drop in sales volumes,
driven by the effect of competitive activity and, to a lesser extent, milder
weather, partially offset by a $94 million increase due to higher pricing.
Higher pricing reflected increased price-to-beat rates, due to approved fuel
factor increases, and higher contract pricing in the competitive large business
market, both resulting from higher natural gas prices. Retail electricity
customer counts at June 30, 2004 declined 1% from June 30, 2003 but have
increased 1% from December 31, 2003. Wholesale electricity revenues grew $197
million, or 71%, to $476 million reflecting a $128 million increase attributable
to a 46% rise in sales volumes and a $69 million increase due to the effect of
increased natural gas prices on wholesale prices. Higher wholesale electricity
volumes reflected the establishment of the new northeast zone in ERCOT. Because
Energy has a generation plant in the new zone, wholesale sales have increased.
Wholesale power purchases also increased as a result of the establishment of the
new zone. 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.
27
Net results from hedging and risk management activities, which are
reported in revenues and include both realized and unrealized gains and losses,
declined $41 million from a net gain of $52 million in 2003 to a net gain of $11
million in 2004. Changes in these results reflect market price movements on
commodity positions held to hedge gross margin. 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. Results from these activities include net unrealized losses
arising from mark-to-market accounting of $13 million in 2004 and net unrealized
gains of $64 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 $42 million
in revenues for the second quarter of 2004. The increase in other revenues of
$40 million to $85 million was primarily driven by this change.
Gross Margin
Three Months Ended
June 30,
--------------------------------------------------
% of % of
2004 Revenue 2003 Revenue
------ ------- ------ -------
Operating revenues............................................... $ 2,115 100% $ 2,016 100%
Costs and expenses:
Cost of energy sold and delivery fees....................... 1,348 64% 1,282 64%
Operating costs............................................. 200 9% 162 8%
Depreciation and amortization related to generation assets.. 82 4% 86 4%
------- --- ------- ---
Gross margin..................................................... $ 485 23% $ 486 24%
======= === ======= ===
Gross margin is considered a key operating metric as it measures the
effect of changes in sales volumes and pricing versus the variable and fixed
costs of energy sold, whether generated or purchased.
Gross margin decreased $1 million to $485 million in 2004. The favorable
effect of higher sales pricing, which was partially offset by lower results from
hedging and risk management activities, and more effective management of
gas-fired generation versus purchased power supply sourcing approximated the
unfavorable effects of a volume mix shift from higher margin retail sales to
wholesale sales, higher delivery fees, increased operating costs and milder
weather. Cost of energy sold in 2004 was unfavorably impacted by an estimated
$40 million effect of the planned nuclear facility outage (due to higher cost of
replacement power), compared to a similar estimated $25 million in 2003 due to
an unplanned outage caused by a transmission grid disturbance.
Operating costs increased $38 million, or 23%, to $200 million in 2004.
The increase reflected $23 million in incremental testing, inspection and
component repair costs associated with the planned outage for refueling at the
nuclear facility, as well as increases in various cost categories that were
individually immaterial. Depreciation and amortization related to generation
assets decreased $4 million, or 5%, to $82 million, reflecting a decrease of $12
million due to extensions of estimated average depreciable lives of nuclear and
lignite generation facilities' assets to better reflect their useful lives,
partially offset by the effect of higher asset retirement obligations due to new
mining activity. (See Note 1 to Financial Statements).
Depreciation and amortization not included in gross margin totaled $6
million and $8 million for the three months ended June 30, 2004 and 2003,
respectively. This decline reflects the transfer of information technology
assets, principally capitalized software, to an affiliate in connection with the
Capgemini transaction.
SG&A expenses increased $14 million, or 9%, to $163 million in 2004
reflecting increases of $11 million in increased staffing and other costs to
improve customer call center service levels and $10 million in deferred
incentive compensation expense due to the increase in the price of TXU Corp.
stock, partially offset by the benefits of various cost reduction initiatives of
$5 million and lower bad debt expense of $2 million.
28
Other income decreased by $4 million to $12 million in 2004. Other income
in both 2004 and 2003 reflected $12 million of amortization of a gain on the
sale of two generation plants in 2002. Other income in 2003 also included a $3
million net gain on the sale of certain retail gas operations.
Other deductions increased by $259 million to $261 million in 2004. Other
deductions in 2004 consist largely of $109 million in software write-offs, $79
million in spare parts inventory writedowns and $70 million for employee
severance. These charges are discussed above under "Strategic Initiatives and
Other Actions."
Interest income increased by $6 million to $7 million in 2004 primarily
due to higher average advances to affiliates.
Interest expense and related charges increased by $6 million, or 7%, to
$93 million in 2004. The increase reflects $18 million due to higher average
debt levels partially offset by $9 million due to lower average interest rates
and $3 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 58.7% on a loss in 2004 and 32.8% on
income in 2003. The effective rate increase was driven by the effects of ongoing
tax benefits of depletion allowances and amortization of investment tax credits.
Results from continuing operations before cumulative effect of changes in
accounting principles decreased $173 million to a loss of $19 million in 2004,
reflecting the increase in other deductions and SG&A expenses. Net pension and
postretirement benefit costs reduced results from continuing operations by $9
million in both 2004 and 2003.
Loss from discontinued operations (see Note 3 to Financial Statements) was
$27 million in 2004 compared to breakeven in 2003. The 2004 loss reflected a $17
million after-tax impairment charge related to the Pedricktown, New Jersey
generation facility and a $6 million after-tax charge to settle a contract
dispute in the strategic retail services business.
Six Months Ended June 30, 2004 Compared to Six Months Ended June 30, 2003
- -------------------------------------------------------------------------
Operating revenues increased $266 million, or 7%, to $4.1 billion in 2004.
Retail electricity revenues decreased $121 million, or 4%, to $3.0 billion
reflecting a $373 million decline attributable to a 12% drop in sales volumes,
driven by the effect of competitive activity and, to a lesser extent, milder
weather, partially offset by a $252 million increase due to higher pricing.
Higher pricing reflected increased price-to-beat rates, due to approved fuel
factor increases, and higher contract pricing in the competitive large business
market, both resulting from higher natural gas prices. Retail electricity
customer counts at June 30, 2004 declined 1% from June 30, 2003 but have
increased 1% from December 31, 2003. Wholesale electricity revenues grew $427
million, or 83%, to $942 million reflecting a $294 million increase attributable
to a 57% rise in sales volumes and a $133 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 in the new zone, wholesale sales have
increased. Wholesale power purchases also increased as a result of the
establishment of the new zone. 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.
Net results from hedging and risk management activities, which are
reported in revenues and include both realized and unrealized gains and losses,
declined $132 million from a net gain of $135 million in 2003 to a net gain of
$3 million in 2004. Changes in these results reflect market price movements on
commodity positions held to hedge gross margin. The comparison to 2003 also
reflects the effect of favorable gas price movements in 2003 in the wholesale
gas operations (approximately $40 million) and a decline of $18 million due to a
favorable settlement with a counterparty in 2003. 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. Results from these activities include net unrealized
losses arising from mark-to-market accounting of $31 million in 2004 and net
unrealized gains of $47 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 $88 million in revenues for the first six months of 2004. The increase
in other revenues of $92 million to $176 million in 2004 was primarily driven by
this change.
29
Gross Margin
Six Months Ended
June 30,
-------------------------------------------------
% of % of
2004 Revenue 2003 Revenue
------ --------- ----- ---------
Operating revenues................................................. $ 4,072 100% $ 3,806 100%
Costs and expenses:
Cost of energy sold and delivery fees......................... 2,603 64% 2,498 66%
Operating costs............................................... 366 9% 341 9%
Depreciation and amortization related to generation assets.... 164 4% 188 5%
------ --- ------- ---
Gross margin....................................................... $ 939 23% $ 779 20%
====== === ======= ===
Gross margin increased $160 million, or 21%, to $939 million in 2004. The
favorable effect of higher sales pricing, which was partially offset by lower
results from hedging and risk management activities, more effective management
of gas-fired generation versus purchased power supply sourcing, as well as
increased base load coal-fired production, were partially offset by the
unfavorable effects of a volume mix shift from higher-margin retail sales to
wholesale sales, higher delivery fees, increased operating costs and milder
weather. Cost of energy sold in 2004 was unfavorably impacted by an estimated
$40 million effect of the planned nuclear facility outage (due to higher cost of
replacement power), compared to a similar estimated $30 million effect in 2003
due to an unplanned outage caused by a transmission grid disturbance and an
unplanned outage to repair a pump motor.
Operating costs increased $25 million, or 7%, to $366 million in 2004. The
increase reflected $29 million in incremental testing, inspection and component
repair costs associated with the planned outage for refueling at the nuclear
facility, partially offset by the timing of other repair and maintenance
expenses. Depreciation and amortization related to generation assets decreased
$24 million, or 13%, to $164 million, reflecting a decrease of $34 million due
to extensions of estimated average depreciable lives of nuclear and lignite
generation facilities' assets to better reflect their useful lives, partially
offset by the effect of higher asset retirement obligations due to new mining
activity. (See Note 1 to Financial Statements).
Depreciation and amortization not included in gross margin totaled $21
million and $18 million for the six months ended June 30, 2004 and 2003,
respectively. The increase reflects the acceleration of the amortization of
certain software to reflect a shorter useful life, partially offset by the
effect of the transfer of information technology assets, principally capitalized
software, to an affiliate in connection with the Capgemini transaction.
SG&A expenses increased $15 million, or 5%, to $307 million in 2004
reflecting increases of $11 million in bad debt expense, $10 million in higher
staffing and other costs to improve customer call center service levels and $8
million in higher deferred incentive compensation expense due to the increase in
the price of TXU Corp. stock, partially offset by the benefits of various cost
reduction initiatives of $12 million.
Other income decreased by $11 million to $13 million in 2004. Other income
in both 2004 and 2003 reflected $12 million of amortization of a gain on the
sale of two generation plants in 2002. Other income in 2003 also included a $9
million net gain on the sale of certain retail gas operations.
Other deductions increased $276 million to $281 million in 2004. Other
deductions in 2004 consist largely of $109 million for software write-offs, $86
million for employee severance and $79 million in spare parts inventory
writedowns. These charges are discussed above under "Strategic Initiatives and
Other Actions."
Interest income increased by $5 million to $8 million in 2004 primarily
due to higher average advances to affiliates.
30
Interest expense and related charges increased by $9 million, or 6%, to
$172 million in 2004. The increase reflects $8 million due to higher average
debt levels and $6 million due to higher average interest rates, partially
offset by $5 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 21.4% in 2004 from 30.4% 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 $91 million to $99 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 $19 million in 2004 and $18 million in 2003.
Loss from discontinued operations (see Note 3 to Financial Statements) was
$30 million in 2004 compared to $1 million in 2003. The 2004 loss reflected a
$17 million after-tax impairment charge related to the Pedricktown, New Jersey
generation facility and a $6 million after-tax charge to settle a contract
dispute in the strategic retail services business.
COMMODITY CONTRACTS AND MARK-TO-MARKET ACTIVITIES
The table below summarizes the changes in commodity contract assets and
liabilities for the six months ended June 30, 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.
Six Months
Ended
---------------
June 30, 2004
Balance of net commodity contract assets at beginning of period............... $ 108
Settlements of positions included in the opening balance (1).................. (39)
Unrealized mark-to-market valuations of positions held at end of period (2)... 25
Other activity (3)............................................................ (7)
-----
Balance of net commodity contract assets at end of period..................... $ 87
=====
__________________________
(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:
31
Six Months
Ended June 30,
-------------------
2004 2003
------ ------
Unrealized gains/(losses) related to commodity contract portfolio................ $ (14) $ 33
Ineffectiveness gains/(losses) related to cash flow hedges....................... (17) 14
------ ------
Total unrealized gains/(losses).................................................. $ (31) $ 47
====== ======
These amounts are included in the "hedging and risk management activities"
component of revenues.
Maturity Table -- Of the net commodity contract asset balance above at
June 30, 2004, the amount representing unrealized mark-to-market net gains that
have been recognized in current and prior years' earnings is $107 million. The
offsetting net liability of $20 million included in the June 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 June 30, 2004, scheduled by
contractual settlement dates of the underlying positions.
Maturity dates of unrealized net mark-to-market balances at June 30, 2004
---------------------------------------------------------------------------
Maturity Maturity in
less than Maturity of Maturity of Excess of
Source of fair value 1 year 1-3 years 4-5 years 5 years Total
- ---------------------------------- ----------- ------------- ------------ ------------ -----
Prices actively quoted........... $ 90 $ - $ - $ - $ 90
Prices provided by other
external sources............. (36) 44 - (2) 6
Prices based on models........... 11 - - - 11
---- ---- --- ---- -----
Total............................ $ 65 $ 44 $ - $ (2) $ 107
==== ==== === ==== =====
Percentage of total fair value... 61% 41% -% (2)% 100%
As the above table indicates, essentially all of the unrealized
mark-to-market valuations at June 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.
32
COMPREHENSIVE INCOME
Cash flow hedge activity reported in other comprehensive income from
continuing operations included:
Three Months Ended Six Months Ended
June 30, June 30,
------------------- -------------------
2004 2003 2004 2003
------ ------ ------ ------
Cash flow hedge activity (net of tax):
Net change in fair value of hedges - gains/(losses):
Commodities................................................ $ (17) $ (20) $ (75) $ (98)
Losses realized in earnings (net of tax):
Commodities................................................ 6 22 10 69
Financing - interest rate swaps............................ 1 1 2 3
------ ------- ------- -------
7 23 12 72
------ ------- ------- -------
Effect of cash flow hedges reported in comprehensive results
related to continuing operations........................... $ (10) $ 3 $ (63) $ (26)
====== ====== ======= =======
FINANCIAL CONDITION
LIQUIDITY AND CAPITAL RESOURCES
Cash Flows -- Cash flows provided by operating activities for the six
months ended June 30, 2004 decreased $47 million to $564 million compared to the
six-month period ended June 30, 2003. The decrease reflected unfavorable working
capital (accounts receivable, accounts payable and inventories) changes of $113
million due largely to the effect of higher collections in 2003 following
billing delays experienced during the transition to competition. Higher cash
earnings (net income adjusted for the significant noncash items identified in
the statement of cash flows) of $180 million was largely offset by $174 million
in higher margin deposits associated with hedging activities.
Cash flows used in financing activities for 2004 were $451 million
compared to $1.0 billion for 2003. The activity in 2004 primarily reflected
repayments of advances from affiliates of $1.6 billion, distributions to US
Holdings of $350 million and net cash used in debt retirements and repurchases
of $127 million, partially offset by bank borrowings of $1.7 billion. The
activity in 2003 reflected repayments of advances from affiliates of $1.4
billion and cash distributions to US Holdings of $400 million, partially offset
by net cash provided by debt issuances and retirements of $842 million.
Cash flows used in investing activities were $127 million in both 2004 and
2003. Capital expenditures, including nuclear fuel, increased to $153 million in
2004 from $139 million in 2003, driven by the timing of nuclear refueling
activities. Proceeds from the sale of certain retail commercial and industrial
gas operations provided $15 million in 2003.
Depreciation and amortization expense reported in the statement of cash
flows exceeds the amount reported in the statement of income by $30 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.
33
Long-Term Debt Activity -- During the six months ended June 30, 2004,
Energy and its subsidiaries issued, redeemed, reacquired or made scheduled
principal payments on long-term debt as follows:
Issuances Retirements
--------- -----------
Pollution control revenue bonds................. $ - $ 121
Other........................................... - 6
------ ------
Total........................................... $ - $ 127
====== ======
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 June 30, 2004,
consisted of long-term debt (less amounts due currently) of 42%, preferred
membership interests (net of unamortized discount balance of $246 million) of 7%
and common membership interests of 51%.
Credit Facilities -- At June 30, 2004 Energy had outstanding short-term
borrowings consisting of bank borrowings of $1.7 billion at a weighted average
interest rate of 3.01%. At June 30, 2004, Energy had a fully drawn $1 billion
credit facility expiring in April 2005. This facility was repaid in July with
the proceeds from Energy's issuance of $800 million floating rate senior notes
and advances from TXU Corp. and subsequently terminated. Energy and Electric
Delivery have ongoing credit facilities totaling $2.5 billion of which $675
million had been borrowed by Energy at June 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. In July, advances from TXU Corp. were used by Energy to repay the $675
million borrowings under the three-year revolving credit facility. See Note 4 to
Financial Statements for details of the arrangements.
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 June 30, 2004 and December 31, 2003 totaled $445 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 $2 million and $18
million at June 30, 2004 and December 31, 2003, respectively.
Credit Ratings of TXU Corp. and its Subsidiaries -- 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) (Unsecured) (Senior Unsecured)
S&P............... BBB- BBB- BBB BBB- BBB
Moody's........... Ba1 Baa3 Baa1 Baa2 Baa2
Fitch............. BBB- BBB- BBB+ BBB BBB
Moody's and Fitch currently maintain a stable outlook for TXU Corp., US
Holdings, Energy and Electric Delivery. 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.
34
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 and its subsidiaries
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 June 30, 2004,
Energy and its subsidiaries were 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 $125 million at June 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.
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 $162 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 June 30, 2004, based on current contract
values, the maximum Energy would post for these transactions is $230 million. Of
this amount, $209 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.
ERCOT also has rules in place to assure adequate creditworthiness for
parties that schedule power on the ERCOT System. Under those rules, if Energy's
credit rating were downgraded to below investment grade by any specified rating
agency, Energy could be required to post collateral of approximately $45
million.
Cross Default Provisions
- ------------------------
Certain financing arrangements of Energy and its subsidiaries 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.
35
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 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.
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.
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 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............ $ 228 $ 482 $ 682 $5,691
Purchase obligations........................... 1,380 1,605 568 504
Business services outsourcing obligations...... 225 337 337 834
There have been no other significant changes in contractual cash
obligations of Energy, since December 31, 2003 as disclosed in the 2003 Form
10-K.
OFF BALANCE SHEET ARRANGEMENTS
36
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.
Energy's 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
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.
On August 4, 2004, Rusk County Electric Cooperative filed a complaint at
the Commission, alleging that Energy and Electric Delivery have been violating
applicable laws by providing electric service to certain TXU Mining facilities
that the cooperative asserts may be lawfully served only by the cooperative.
Energy and Electric Delivery believe that their actions have been and continue
to be lawful, and will vigorously defend themselves against the cooperative's
complaint.
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.
37
RISKS 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.
Energy believes that the electricity market in ERCOT is workably
competitive. Energy is the largest owner of generation and has the largest
retail position in ERCOT, and, 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.
Existing laws and regulations governing the market structure in Texas
could be reconsidered, revised or reinterpreted, or new laws or regulations
could be adopted.
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.
38
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, crude oil and refined products, and
other commodities, within established risk management guidelines. As part of
this strategy, Energy routinely utilizes fixed-price forward physical purchase
and sales contracts, futures, financial swaps and option contracts traded in the
over-the-counter markets or on exchanges. However, 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.
39
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
subsidiaries' ratings were to decline to below investment grade, costs to
operate the power businesses would increase because counterparties may require
the posting of collateral in the form of cash-related instruments, or
counterparties may decline to do business with Energy's subsidiaries.
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 Company'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 and energy transportation facilities
involves many risks, including start up risks, breakdown or failure of
facilities, lack of sufficient capital to maintain the facilities, the
dependence on a specific fuel source or the impact of unusual or adverse weather
conditions or other natural events, as well as the risk of performance below
expected levels of output or efficiency, the occurrence of any of which could
result in lost revenues and/or increased expenses. A significant portion of
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 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. 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.
40
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.
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 PUCT 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.
41
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 its own such facilities, to deliver the
electricity it produces and sells to consumers, as well as to other REPs. If
transmission capacity is inadequate, 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. Energy is refining these systems and processes, and they may prove
more expensive to refine 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.
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 and/or energy
transportation 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 dividends 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 dividends, 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:
42
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 or the credit ratings of its subsidiaries;
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 these events 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.
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 risks discussed above under "RISK
FACTORS THAT MAY AFFECT FUTURE RESULTS" and factors contained in the
Forward-Looking Statements section of Item 7. Management's Discussion and
Analysis of Financial Condition and Results of Operations in Energy's 2003 Form
10-K, that could cause the actual results of Energy to differ materially from
those projected in such forward-looking statements.
Any forward-looking statement speaks only as of the date on which it is
made, and Energy undertakes no obligation to update any forward-looking
statement to reflect events or circumstances after the date on which it 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 them; nor can
Energy assess the impact of each such factor or the extent to which any factor,
or combination of factors, may cause results to differ materially from those
contained in any forward-looking statement.
43
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
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.
June 30, December 31,
2004 2003
---------- -------------
Period-end MtM VaR..................... $ 16 $ 15
Average Month-end MtM VaR.............. $ 22 $ 25
Portfolio VaR -- Represents the estimated potential loss in value, due to
changes in market conditions, of the entire energy portfolio, including owned
generation assets, estimates of retail sales load and all contractual positions
(the portfolio assets). The Portfolio VaR calculations represent a ten year view
of owned assets based on the nature of their particular markets. If the life of
an asset extends beyond the ten year duration period, the VaR calculation does
not measure the associated risk inherent in the asset over its full life.
Assumptions in determining the total Portfolio VaR include using a 95%
confidence level and a five-day holding period and includes both mark-to-market
and accrual positions.
June 30, December 31,
2004 2003
---------- --------------
Period-end Portfolio VaR............... $ 211 $ 199
Average Month-end Portfolio VaR........ $ 190 $ 181
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.
June 30, December 31,
2004 2003
---------- -------------
EaR ...................................... $ 15 $ 15
CFaR ..................................... $ 92 $ 67
44
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 June 30, 2004, the exposure to
credit risk from large business customers and hedging counterparties, excluding
credit collateral, is $987 million, 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 $863 million. Of this amount,
approximately 76% of the exposure is with investment grade customers and
counterparties, as determined 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.
The following table presents the distribution of credit exposure as of
June 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 $ 689 $ 37 $ 652 $ 555 $ 54 $ 43 $ 652
Noninvestment grade 298 87 211 179 18 14 211
------- ------ ----- ----- ---- ----- -----
Totals $ 987 $ 124 $ 863 $ 734 $ 72 $ 57 $ 863
======= ====== ===== ===== ==== ===== =====
Investment grade 70% 30% 76%
Noninvestment grade 30% 70% 24%
Energy has exposure in the amount of $87 million to one customer or
counterparty that is 10% of the net exposure of $863 million at June 30, 2004.
Energy holds a guaranty from this counterparty's investment grade parent.
Additionally, approximately 85% 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.
45
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
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 have filed a motion to
intervene in the action alleging claims substantially identical to TCE's, both
on their own behalf and on behalf of a putative class of all former customers of
TCE. A hearing on these motions was conducted May 20, 2004 during which the
Court stated that it intended to enter an order dismissing the antitrust claims
and an order was entered on June 24, 2004. TCE has indicated that it intends to
appeal 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.
46
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits provided as part of Part II are:
Previously Filed*
-----------------
With File As
Exhibits Number Exhibit
- ---------- ------ -------
(10) Material Contracts.
10(a) 1-2833 10(b) -- $1,000,000,000 Credit Agreement dated as of April 26, 2004,
Form 10-Q among TXU Energy Company LLC, the Lenders listed in Schedule
(filed August 6, 2.01 thereto, and Credit Suisse First Boston as
2004) Administrative Agent.
10(b) 1-2833 10(a) -- $2,500,000,000 Revolving Credit Agreement dated as of June
Form 8-K 24, 2004, among TXU Energy Company LLC and TXU Electric
(filed July 1, 2004) Delivery Company, the Lenders listed in Schedule 2.01
thereto, JPMorgan Chase Bank as Administrative
Agent and the other parties named therein.
10(c) 1-2833 10(j) -- Purchase and Sale Agreement between TXU Fuel Company and
Form 10-Q Energy Transfer Partners, L.P. dated April 25, 2004.
(filed August 6,
2004)
10(d) 1-2833 10(m) -- Master Framework Agreement dated May 17, 2004 by and between
Form 10-Q TXU Energy Company LLC and CapGemini Energy LP.
(filed August 6,
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 June 30, 2004.
- ------------------------------------------
* Incorporated herein by reference.
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(b) Reports on Form 8-K furnished or filed since March 31, 2004:
Date of Report Item Reported
-------------- -------------
April 26, 2004 Item 5. Other Events and Regulation FD Disclosure
Item 12. Results of Operations and Financial Condition
May 14, 2004 Item 5. Other Events and Regulation FD Disclosure
May 24, 2004 Item 5. Other Events and Regulation FD Disclosure
Item 9. Regulation FD Disclosure
June 7, 2004 Item 5. Other Events and Regulation FD Disclosure
July 1, 2004 Item 5. Other Events and Regulation FD Disclosure
July 9, 2004 Item 5. Other Events and Regulation FD Disclosure
August 5, 2004 Item 5. Other Events and Regulation FD Disclosure
48
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/ Scott Longhurst
--------------------------------
Scott Longhurst
Senior Vice President and
Principal Accounting Officer
Date: August 12, 2004
49