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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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FORM 10-K
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2003
-- OR --
[] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File Number 1-11668
TXU US Holdings Company
(Exact Name of Registrant as Specified in its Charter)
Texas 75-1837355
(State of Incorporation) (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)
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Securities registered pursuant to Section 12(b) of the Act: None
Securities registered pursuant to Section 12(g) of the Act: Preferred Stock,
without par value
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Indicate by check mark whether the registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months(or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. Yes X No
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Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes No X
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Aggregate market value of TXU US Holdings Common Stock held by non-affiliates:
None
Common Stock outstanding at March 12, 2004: 2,062,768 Class A shares, without
par value and 39,192,594 Class B shares, without par value.
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DOCUMENTS INCORPORATED BY REFERENCE - None
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TABLE OF CONTENTS
Page
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Glossary ii
PART I
Items 1.and 2. BUSINESS and PROPERTIES .................................... 1
TXU US HOLDINGS COMPANY AND SUBSIDIARIES....................... 1
TEXAS ELECTRIC INDUSTRY RESTRUCTURING.......................... 2
OPERATING SEGMENTS............................................. 3
TXU Energy.................................................. 3
Oncor....................................................... 8
ENVIRONMENTAL MATTERS.......................................... 10
Item 3. LEGAL PROCEEDINGS................................................. 12
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS............... 13
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS........................................................... 13
Item 6. SELECTED FINANCIAL DATA........................................... 13
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS............................................. 13
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK........ 13
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA....................... 13
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.............................................. 13
Item 9A. CONTROLS AND PROCEDURES........................................... 13
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT.................... 14
Item 11. EXECUTIVE COMPENSATION............................................ 16
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.... 27
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.................... 28
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES............................ 28
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K... 29
APPENDIX A - Financial Information of TXU US Holdings A-1
APPENDIX B -Exhibits to 2003 Form 10-K B-1
Periodic reports on Form 10-K and Form 10-Q and current reports on Form 8-K that
contain financial information of TXU US Holdings Company are made available to
the public, free of charge, on the TXU Corp. website at http://www.txucorp.com,
shortly after they have been filed with the Securities and Exchange Commission.
TXU US Holdings Company will provide copies of current reports not posted on the
website upon request.
i
GLOSSARY
When the following terms and abbreviations appear in the text of this report,
they have the meanings indicated below.
1999 Restructuring Legislation........Legislation that restructured the electric
utility industry in Texas to provide for
competition
2002 Form 8-K.........................US Holdings' Current Report on Form 8-K
filed on February 26, 2003 for TXU Energy
with respect to its financial information
for the year ended December 31, 2002, and
Form 8-K filed September 16, 2003 to
reflect the impact of adopting SFAS 145 on
the financial information reported in the
Form 8-K filed on February 26, 2003
2002 Form 10-K........................US Holdings' Annual Report on Form 10-K
for the year ended December 31, 2002
2003 Form 10-K........................TXU Energy's Annual Report on Form 10-K
for the year ended December 31, 2003
APB Opinion 30........................Accounting Principles Board Opinion No.30,
"Reporting the Results of Operations -
Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary,
Unusual and Infrequently Occurring Events
and Transactions."
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 01-8.............................EITF Issue No. 01-8, "Determining Whether
an Arrangement Contains a Lease"
EITF 02-3 ............................EITF Issue No. 02-3, "Issues Involved in
Accounting for Derivative Contracts Held
for Trading Purposes and Contracts
Involved in Energy Trading and Risk
Management Activities"
EITF 03-11............................EITF Issue No. 03-11, `Reporting Realized
Gains and Losses on Derivative Instruments
That Are Subject to FASB Statement No. 133
and Not "Held for Trading Purposes" As
Defined in EITF No. 02-3'
EPA...................................Environmental Protection Agency
ERCOT.................................Electric Reliability Council of Texas, the
Independent System Operator and the
regional coordinator of the various
electricity systems within Texas
ERISA.................................Employee Retirement Income Security Act
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 45................................FIN No. 45, "Guarantor's Accounting and
Disclosure Requirements for Guarantees,
Including Indirect Guarantees of
Indebtedness of Others - an Interpretation
of FASB Statements No. 5, 57,
and 107 and Rescission of FIN No. 34"
FIN 46................................FIN No. 46, "Consolidation of Variable
Interest Entities"
Fitch.................................Fitch Ratings, Ltd.
ii
GWh...................................gigawatt-hours
historical service territory..........US Holdings historical service territory
at the time of entering competition on
January 1, 2002
IRS...................................Internal Revenue Service
kV....................................kilovolt
Moody's...............................Moody's Investors Services, Inc.
MW....................................megawatts
NRC...................................United States Nuclear Regulatory
Commission
Oncor.................................refers to Oncor Electric Delivery Company,
a subsidiary of US Holdings, and/or its
consolidated bankruptcy remote financing
subsidiary, Oncor Electric Delivery
Transition Bond Company LLC, depending on
context
POLR..................................provider of last resort of electricity to
certain customers under the Commission
rules interpreting the 1999 Restructuring
Legislation
Price-to-beat rate....................residential and small 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
Settlement Plan.......................regulatory settlement plan that received
final approval by the Commission in
January 2003
SFAS..................................Statement of Financial Accounting
Standards issued by the FASB
SFAS 4................................SFAS No. 4, "Reporting Gains and Losses
from Extinguishment of Debt"
SFAS 34...............................SFAS No. 34, "Capitalization of Interest
Cost"
SFAS 71...............................SFAS No. 71, "Accounting for the Effect of
Certain Types of Regulation"
SFAS 87...............................SFAS No. 87, "Employers' Accounting for
Pensions"
SFAS 101..............................SFAS No. 101, "Regulated Enterprises -
Accounting for the Discontinuance of the
Application of FASB Statement No. 71."
SFAS 106..............................SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than
Pensions"
SFAS 109..............................SFAS No. 109, "Accounting for Income
Taxes"
SFAS 121..............................SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed Of"
SFAS 132..............................SFAS No. 132, "Employers' Disclosures
about Pensions and Postretirement
Benefits"
SFAS 133..............................SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities"
SFAS 140..............................SFAS No. 140, "Accounting for Transfers
and Servicing of Financial Assets and
Extinguishments of Liabilities a
replacement of FASB Statement 125"
SFAS 142..............................SFAS No. 142, "Goodwill and Other
Intangible Assets"
iii
SFAS 143..............................SFAS No. 143, "Accounting for Asset
Retirement Obligations"
SFAS 144..............................SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived
Assets"
SFAS 145..............................SFAS No. 145, "Rescission of FASB
Statements No. 4, 44 and 64, Amendment of
FASB Statement 13, and Technical
Corrections"
SFAS 146..............................SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal
Activities"
SFAS 149..............................SFAS No. 149, "Amendment of Statement 133
on Derivative Instruments and Hedging
Activities"
SFAS 150..............................SFAS No. 150, "Accounting for Certain
Financial Instruments with Characteristics
of both Liabilities and Equity"
SG&A..................................selling, general and administrative
SOP 98-1..............................American Institute of Certified Public
Accountants Statement of Position 98-1,
"Accounting for the Cost of Computer
Software Developed or Obtained for
Internal Use"
TCEQ..................................Texas Commission on Environmental Quality
TXU Business Services.................TXU Business Services Company, a
subsidiary of TXU Corp.
TXU Corp..............................refers to TXU Corp. and/or its
consolidated subsidiaries, depending on
context
TXU Energy............................refers to TXU Energy Company LLC, a
subsidiary of US Holdings, and/or its
consolidated subsidiaries, depending on
context
TXU Fuel..............................TXU Fuel Company, a subsidiary of TXU
Energy
TXU Gas...............................TXU Gas Company, a subsidiary of TXU Corp.
TXU Mining............................TXU Mining Company LP, a subsidiary of TXU
Energy
TXU Portfolio Management..............TXU Portfolio Management Company LP, a
subsidiary of TXU Energy
TXU SESCO.............................TXU SESCO Company, a subsidiary of TXU
Energy, which serves as a REP in ten
counties in the eastern and central parts
of Texas
US....................................United States of America
US GAAP...............................accounting principles generally accepted
in the US
US Holdings...........................TXU US Holdings Company, a subsidiary of
TXU Corp.
iv
PART I
Items 1. and 2. BUSINESS and PROPERTIES
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
----------------------------------------
US Holdings (formerly TXU Electric Company) is a holding company for TXU
Energy and Oncor. US Holdings is a wholly-owned subsidiary of TXU Corp., a Texas
corporation. Prior to January 1, 2002, US Holdings was a regulated, integrated
utility company directly engaged in the generation, purchase, transmission,
distribution and sale of electric energy in the north-central, eastern and
western parts of Texas.
TXU Energy serves 2.6 million retail electric customers and owns, or
leases, and operates 19,140 megawatts of power generating capacity. Oncor owns
and operates 98,286 miles of electric distribution lines and 14,180 miles of
electric transmission lines. At December 31, 2003, US Holdings and its
subsidiaries had approximately 9,384 full-time employees, including 2,049 in a
collective bargaining unit.
US Holdings and its subsidiaries operate primarily within the ERCOT
system. ERCOT is an intrastate network of investor-owned entities, cooperatives,
public entities, non-utility generators and power marketers. ERCOT is the
regional reliability coordinating organization for member electricity systems in
Texas, the Independent System Operator of the interconnected transmission system
of those systems, and is responsible for ensuring equal access to transmission
service by all wholesale market participants in the ERCOT region.
TEXAS ELECTRIC INDUSTRY RESTRUCTURING
-------------------------------------
RESTRUCTURING LEGISLATION
Business Restructuring - The 1999 Restructuring Legislation restructured
the electric utility industry in Texas and provided for a transition to
competition in the generation and retail sale of electricity. TXU Corp.
disaggregated its electric utility business, as required by the legislation, and
restructured certain of its US businesses as of January 1, 2002 resulting in two
new business operations:
o Oncor - a utility regulated by the Commission that holds electricity
transmission and distribution assets and engages in electricity
delivery services.
o TXU Energy - a competitive business that holds the power generation
assets and engages in wholesale and retail energy sales and
hedging/risk management activities.
The relationships of these entities and their rights and obligations with
respect to their collective assets and liabilities are contractually described
in a master separation agreement executed in December 2001.
The operating assets of Oncor and TXU Energy are located principally in
the north-central, eastern and western parts of Texas.
A settlement of outstanding issues and other proceedings related to
implementation of the 1999 Restructuring Legislation received final approval by
the Commission in January 2003. See Note 15 for further discussion.
In addition, as of January 1, 2002, certain other businesses within the TXU
Corp. system were transferred to TXU Energy, including TXU Gas' hedging and risk
management business and its unregulated retail commercial/industrial (business)
gas supply operation, as well as the fuel transportation and coal mining
subsidiaries that primarily service the generation operations.
In December 2003, the Commission found that TXU Energy had met the 40%
requirement to be allowed to offer alternatives to the price-to-beat rate for
small business customers in the historical service territory.
1
Under amended Commission rules, effective in April 2003, affiliated REPs
of utilities are allowed to petition the Commission for an increase in the fuel
factor component of their price-to-beat rates if the average price of natural
gas futures increases more than 5% (10% if the petition is filed after November
15 of any year) from the level used to set the existing price-to-beat fuel
factor rate.
-- In January 2003, TXU Energy filed a request with the Commission under
the prior rules to increase the fuel factor component of its
price-to-beat rates. This request was approved and became effective in
early March 2003. As a result, average monthly residential bills rose
approximately 12%. Appeals of the Commission's order have been filed
and are currently pending in the Travis County, Texas District Court.
-- On July 23, 2003, TXU Energy filed another request with the Commission
to increase the fuel factor component of its price-to-beat rates. This
request was approved and became effective in late August 2003. As a
result, average monthly residential bills rose approximately 4%.
Appeals of the Commission's order have been filed and are currently
pending in the Travis County, Texas District Court.
Also, effective January 1, 2002, power generation companies, such as TXU
Energy, affiliated with electricity delivery utilities may charge unregulated
prices in connection with ERCOT wholesale power transactions. Estimated costs
associated with nuclear power plant decommissioning obligations continue to be
recovered by Oncor as an electricity delivery charge over the life of the plant.
REGULATORY SETTLEMENT PLAN
On December 31, 2001, US Holdings filed a Settlement Plan with the
Commission. It resolved all major pending issues related to US Holdings'
transition to competition pursuant to the 1999 Restructuring Legislation. The
Settlement Plan does not remove regulatory oversight of Oncor's business nor
does it eliminate TXU Energy's price-to-beat rates and related fuel adjustments.
The Settlement Plan became final in January 2003.
Some of the major elements of the Settlement Plan are:
Excess Mitigation Credit -- Over the two-year period ended December 31,
2003, Oncor implemented a stranded cost excess mitigation credit in the amount
of $389 million (originally estimated to be $350 million), plus $26 million in
interest, applied as a reduction to delivery fees charged to all REPs, including
TXU Energy. The credit was funded by TXU Energy.
Regulatory Asset Securitization -- US Holdings received a financing order
authorizing the issuance of securitization bonds in the aggregate principal
amount of up to $1.3 billion to recover regulatory asset stranded costs and
other qualified costs. Accordingly, Oncor Electric Delivery Transition Bond
Company LLC, a bankruptcy remote financing subsidiary of Oncor, issued an
initial $500 million of securitization bonds in 2003 and is expected to issue
approximately $790 million in the first half of 2004. The principal and interest
on the bonds is recoverable through a delivery fee surcharge (transition charge)
to all REPs, including TXU Energy.
Retail Clawback Credit -- A retail clawback credit related to residential
customers was implemented in January 2004. The amount of the credit is equal to
the number of residential customers retained by TXU Energy in its historical
service territory on January 1, 2004, less the number of new residential
customers TXU Energy has added outside of the historical service territory as of
January 1, 2004, multiplied by $90. The estimated credit of $173 million will be
applied to delivery fees charged by Oncor to all REPs, including TXU Energy,
over a two-year period. TXU Energy funds the credit provided by Oncor. As the
amount of the credit will be based on power usage during the related two-year
period, the liability is subject to future adjustments.
Stranded Costs and Fuel Cost Recovery -- TXU Energy's stranded costs, not
including regulatory assets, are fixed at zero. US Holdings will not seek to
recover its unrecovered fuel costs which existed at December 31, 2001. Also, it
will not conduct a final fuel costs reconciliation, which would have covered the
period from July 1998 until the beginning of competition in January 2002.
2
PROVIDER OF LAST RESORT
Through 2002, TXU Energy was the POLR for residential and small business
customers in those areas of ERCOT where customer choice was available outside
the historical service territory and was the POLR for large business customers
in the historical service territory. Under new POLR rules effective in September
2002, instead of being transferred to the POLR, non-paying residential and small
business customers served by affiliated REPs are subject to disconnection.
Non-paying residential and small business customers served by non-affiliated
REPs are transferred to the affiliated REP. Non-paying large business customers
can be disconnected by any REP if the customer's contract does not preclude it.
Thus, within the new POLR framework, the POLR provides electric service only to
customers who request POLR service, whose selected REP goes out of business, or
who are transferred to the POLR by other REPs for reasons other than
non-payment. No later than October 1, 2004, the Commission is expected to decide
whether all REPs should be permitted to disconnect all non-paying customers.
Through a competitive bid process, the Commission selected a POLR to serve
for a two-year term beginning January 1, 2003, for several areas within Texas.
In areas for which no bids were submitted, the Commission selected the POLR by
lottery. TXU Energy did not bid to be the POLR, but was designated POLR through
lottery for residential and small business customers in certain West Texas
service areas and for small business customers in the Houston service area.
OPERATING SEGMENTS
------------------
US Holdings has aligned its operations into two reportable segments: TXU
Energy and Oncor. (See Note 17 to Financial Statements for further information
concerning reportable business segments.)
TXU Energy - operations principally in the competitive Texas market
involving power production (electricity generation) and retail and wholesale
sales of electricity and natural gas. TXU Energy engages in hedging and risk
management activities to mitigate commodity price risk.
Oncor - regulated operations in Texas involving the transmission and
distribution of electricity.
Effective with reporting for 2003, results for the TXU Energy segment
exclude expenses incurred by the US Holdings holding company in order to present
the segment on the same basis as the separate reporting for TXU Energy and as
the results of the business are evaluated by management. The activities of the
holding company consist primarily of servicing approximately $160 million of
debt. Prior year amounts are presented on the revised basis.
TXU ENERGY
TXU Energy's operations are conducted principally through the following
subsidiaries: TXU Generation Company LP; TXU Portfolio Management Company LP;
TXU Energy Retail Company LP; TXU Fuel Company; and two coal mining
subsidiaries.
TXU Energy serves 2.6 million retail electric customers, of which 2.4
million are in US Holdings' historical service territory. This territory, which
is located in the north-central, eastern and western parts of Texas, has an
estimated population in excess of 7 million, about one-third of the population
of Texas, and comprises 92 counties and 370 incorporated municipalities,
including Dallas/Fort Worth and surrounding suburbs, as well as Waco, Wichita
Falls, Odessa, Midland, Tyler and Killeen. The Dallas/Fort Worth area is a
diversified commercial and industrial center with substantial banking,
insurance, telecommunications, electronics, aerospace, petrochemical and
specialized steel manufacturing, and automotive and aircraft assembly. The
historical service territory served includes major portions of the oil and gas
fields in the Permian Basin and East Texas, as well as substantial farming and
ranching sections of the state. TXU Energy also provides retail electric service
in other areas of ERCOT now open to competition, including the Houston and
Corpus Christi areas.
Texas is one of the fastest growing states in the nation and is considered
by many to be one of the more successful deregulated energy markets in the US.
As a result, competition is expected to continue to increase.
3
POWER PRODUCTION
TXU Energy's power generating facilities provide TXU Energy with the
capability to supply a significant portion of the wholesale power market demand
in Texas, particularly in the North Texas market, at competitive production
costs. As part of TXU Energy's integrated business portfolio, much of the low
cost nuclear powered and lignite/coal-fired (base load) generation is available
to supply the power demands of its retail customers and other competitive REPs.
The power fleet in Texas consists of 22 owned or leased plants with
generating capacity fueled as follows: 2,300 MW nuclear; 5,837 MW coal/lignite;
and 10,881 MW gas/oil. TXU Energy supplies its retail customer base from its
power fleet as well as through long-term power supply agreements and purchases
in the wholesale markets. The power generating plants and other important
properties of TXU Energy are located primarily on land owned in fee simple. TXU
Energy has sold and may from time to time sell generation assets to reduce its
position in the Texas market and provide funds for other investments or to
reduce debt.
TXU Energy is one of the largest purchasers of wind-generated energy in
Texas and the US. TXU Energy currently purchases energy from over 579 MW of wind
projects located in West Texas. TXU Energy expects to continue to add additional
wind generation to its portfolio as commercial opportunities become available.
Nuclear-Powered Production Assets -- TXU Energy owns and operates two
nuclear-fueled electricity generation units at the Comanche Peak plant, each of
which is designed for a capacity of 1,150 MW.
TXU Energy has on hand, or has contracted for, enrichment services through
mid-2006 and fabrication services through 2011 for its nuclear units. TXU Energy
is finalizing supply contracts for the purchase of uranium and conversion to
meet its needs through mid-2006 and does not anticipate any problems in
completing the contracts. TXU Energy does not anticipate any difficulties
procuring raw materials and services beyond these dates.
TXU Energy's onsite spent nuclear fuel storage capability is sufficient to
accommodate the operation of Comanche Peak through the year 2017, while
maintaining the capability to off-load the core of one of the nuclear-fueled
generating units.
Under current regulatory licenses, nuclear decommissioning activities are
projected to begin in 2030 for Comanche Peak Unit 1 and 2033 for Unit 2 and
common facilities. Since January 1, 2002, projected decommissioning costs are
being recovered from Oncor's customers through a delivery charge based upon a
1997 site-specific study, adjusted for changes in the value of trust fund
assets, through rates placed into effect under the 2001 Unbundled Cost of
Service filing.
The Comanche Peak nuclear-powered generation units were originally
estimated to have a useful life of 40 years, based on the life of the operating
licenses granted by the NRC. Over the last several years, the NRC has granted
20-year extensions to the initial 40-year terms for several commercial power
reactors. Based on these extensions and current expectations of industry
practice, the useful life of the Comanche Peak nuclear-powered generation units
is now estimated to be 60 years. TXU Energy. expects to file a license extension
request in accordance with timing and other provisions established by the NRC.
(See Note 1 to Financial Statements under Property, Plant and Equipment, for a
discussion of the change in depreciable lives for accounting purposes).
Lignite/Coal -Fired Production Assets -- Lignite is used as the primary
fuel for two units at the Big Brown generating plant, three units at the
Monticello generating plant, three units at the Martin Lake generating plant,
and one unit at the Sandow generating plant, having an aggregate capacity of
5,837 MW. TXU Energy's lignite units have been constructed adjacent to surface
minable lignite reserves. TXU Energy owns in fee or has under lease proven
reserves dedicated to the Big Brown, Monticello and Martin Lake generating
plants. TXU Energy utilizes owned and/or leased equipment to remove the
overburden and recover the lignite. Approximately 75% of the fuel used at TXU
Energy's lignite plants in 2003 was supplied from owned or leased lignite.
TXU Energy supplements its lignite fuel at Big Brown, Monticello and
Martin Lake with western coal from the Powder River Basin in Wyoming. The coal
is purchased from multiple suppliers under contracts of various
4
lengths and is transported from the Powder River Basin to TXU Energy's
generating plants by railcar. Approximately 25% of the fuel used at TXU Energy's
lignite plants in 2003 was supplied from western coal under these contracts.
Based on its current usage, which includes the use of western coal to supplement
its lignite reserves, TXU Energy believes that it has sufficient lignite
reserves and access to western coal resources for its generating needs in the
foreseeable future.
Gas/Oil-Fired Production Assets -- TXU Energy has eighteen gas/oil-fueled
plants, including a plant located in Pedricktown, New Jersey, with an aggregate
capacity of 11,003 MW. A significant portion of the gas/oil generating plants
have the ability to switch between gas and fuel oil. Gas/oil fuel requirements
for 2003 were provided through a mix of contracts with producers at the wellhead
and contracts with commercial suppliers. Fuel oil can be stored at 15 of the
principally gas-fueled generating plants. At January 1, 2004, TXU Energy had
fuel oil storage capacity sufficient to accommodate approximately 5.5 million
barrels of oil and had approximately one million barrels of oil in inventory.
Capacity Auction -- To encourage competition in the ERCOT region, each
power generation company owning 400 MW or more of installed generating capacity
must annually offer to sell at auction entitlements to 15% of the output of its
installed generating capacity. Such auction sales cannot be to an affiliated
REP. The obligation of TXU Energy to sell capacity entitlements at auction
continues until the earlier of January 1, 2007 or the date the Commission
determines that 40% or more of the electric power consumed by residential and
small business customers within the affiliated delivery utility certificated
service area before the onset of customer choice is provided by non-affiliated
REPs. The October 2002 auction offered one-year and monthly entitlements for
2003 only. Not all of the entitlements offered in the October auction were sold;
however, TXU Energy did re-offer these unsold entitlements in subsequent
auctions held in November 2002 and throughout 2003. In 2003, TXU held capacity
auctions in March, July and August for 2003 capacity, and in September and
November for 2004 capacity. TXU Energy met its capacity auction obligations for
2003. The next auctions for the remaining 2004 capacity obligations are
scheduled for March and July 2004.
NATURAL GAS OPERATIONS
TXU Energy's natural gas operations in Texas include pipelines, storage
facilities, well-head production contracts, transportation agreements and
storage leases. Natural gas is purchased for internal use in the generation of
power, as well as for sale in wholesale markets and to large business customers.
Transportation services are provided to TXU Energy's generation operations and
third parties. Because of the correlation of natural gas and power prices, TXU
Energy's natural gas operations provide opportunities to hedge its margins on
power sales.
TXU Energy owns and operates an intrastate natural gas pipeline system
with approximately 1,900 miles of pipeline facilities which extends from the
gas-producing area of the Permian Basin in West Texas to the East Texas gas
fields and southward to the Gulf Coast area. The pipeline facilities were
originally built solely to serve US Holdings' generating plants. In keeping with
deregulation principles, this network now offers transportation service to third
parties at competitive prices.
TXU Energy also owns and operates two underground gas storage facilities
with a usable capacity of 14.0 Bcf. TXU Energy holds a portion of this storage
capacity for use during periods of peak demand to meet seasonal and other
fluctuations or interruption of deliveries by gas suppliers. Under normal
operating conditions, up to 400 million cubic feet can be withdrawn each day for
a ten-day period, with withdrawals at lower rates thereafter.
RETAIL
Regulatory restructuring in Texas has resulted in competitive markets
within the state, thus presenting additional opportunities for growth
accompanied by the introduction of competitive pressures. Texas is one of the
fastest growing states in the nation with a diverse and resilient economy and,
as a result, has attracted a number of competitors into the retail electricity
market. TXU Energy, as an active participant in this competitive market, is
marketing its services in Texas to add new customers and to retain its existing
customers.
5
Based on the latest data provided by ERCOT (November 2003), approximately
14% of all customers in ERCOT areas open to customer choice had elected to
switch providers. At the present time, 53 REPs are certified to compete within
the state of Texas.
TXU Energy believes that the scale derived from a large retail portfolio
provides the platform for a profitable operation by, among other things,
reducing the costs of service and billing per customer. TXU Energy emphasizes
its identification with the TXU brand and reputation. TXU Energy uses a value
pricing approach by customizing its products to each customer segment with
service enhancements that are known to be valued by customers in those segments.
With its approach, TXU Energy intends to achieve substantially higher customer
loyalty and enhanced profit margins, while reducing the costs associated with
customers frequently switching suppliers.
TXU Energy has invested in customer-related infrastructure and uses its
customer relationships, technology operating platforms, marketing, customer
service operations and customer loyalty to actively compete to retain its
customer base and to add customers.
PORTFOLIO MANAGEMENT
Portfolio management refers to risk management and value creation
activities undertaken to balance customer demand for energy with the supply of
energy in an economically efficient and effective manner. Retail and wholesale
demand is generally greater than volumes that can be supplied by TXU Energy's
base load production. Portfolio management acts to provide additional supply
balancing through TXU Energy's gas/oil-fired generation or purchases of power.
The portfolio management operation manages the commodity volume and price risks
inherent in TXU Energy's generation and sales operations through supply
structuring, pricing and risk management activities. Risk management activities
include hedging both future power sales and purchases of fuel supplies for the
generation plants. The portfolio management operation also is responsible for
the efficient dispatch of power from its generation plants.
In its risk management activities, TXU Energy enters into physical
delivery contracts, financial contracts that are traded on exchanges and
"over-the-counter" and bilateral contracts with customers. Physical delivery
contracts relate to the purchase and sale of electricity and gas primarily in
the wholesale markets in Texas and to a limited extent in select Northeast
markets in North America. TXU Energy's risk management activities consist
largely of hedging transactions, with speculative trading representing a small
fraction of such activity.
TXU Energy manages its exposure to price risk within established
transactional policies and limits. TXU Energy targets best practices in risk
management and risk control by employing proven principles used by financial
institutions. These controls have been structured so that they are practical in
application and consistent with stated business objectives. Portfolio management
revalues TXU Energy's exposures daily using integrated energy systems to capture
value and mitigate risks. A risk management forum meets regularly to ensure that
transactional practices comply with its prior approval of commodities,
instruments, exchanges and markets. Transactional risks are monitored and limits
are enforced to comply with established TXU Energy policy requirements. Risk
assessment is segregated and operated separately from compliance and enforcement
to ensure independence, accountability and integrity of actions. TXU Energy has
a strict disciplinary program to address any violations of its risk management
policy requirements. TXU Energy also periodically reviews these policies to
ensure they are responsive to changing market and business conditions. These
policies are designed to protect earnings, cash flows and credit ratings.
6
COMPETITIVE STRATEGY
TXU Energy's strategy is to defend and build its customer base in the
competitive Texas market and to accomplish this through the operation of a
single, integrated energy business managing a portfolio of assets. Achieving
operational excellence, more cost efficient processes and enhanced credibility
and reputation are all critical elements for executing on that strategy.
TXU Energy will continue to focus on sustaining its leading position in
the Texas market and being in position to move quickly toward capturing new
opportunities outside of Texas as they arise.
One of TXU Energy's key competitive strengths is its ability to produce
electricity at low variable costs in a market in which power prices are set by
gas-fired generation. New gas-fired capacity, while generally more efficient to
operate than existing gas/oil-fired capacity due to technological advances, is
subject to the volatility and increasing cost of natural gas fuel. On the other
hand, base load nuclear and lignite/coal plants have lower variable production
costs than even new gas-fired plants at current average market gas prices.
Another competitive strength for TXU Energy is the diversity of its generation
fleet. Due to the higher variable operating and fuel costs of its gas/oil-fired
units, as compared to its lignite/coal and nuclear units, production from TXU
Energy's gas/oil units is more susceptible to being displaced by the more
efficient units being constructed. This positions TXU Energy's gas/oil units to
run during intermediate and peak load periods when prices are higher and
provides more opportunities for hedging activities and increased market
liquidity.
Retail competition has remained steady in Texas with several large
participants broadly extending their marketing across all customer segments and
all geographic areas of competition. TXU Energy has successfully executed
similar marketing programs while retaining the majority of its incumbent
residential customer base.
TXU Energy believes that the ERCOT region presents an attractive
competitive electric service market due to the following factors:
o gas-fired plants are expected to set the price of generation during a
substantial portion of the year, providing an opportunity for TXU
Energy to benefit from its nuclear and lignite/coal units' fuel cost
advantages;
o peak demand is expected to grow at an average rate of approximately 3%
per year;
o it is a sizeable market with approximately 62 gigawatts (GW) of peak
demand and approximately 35 GW of average demand; and
o there is no mandatory power pool structure.
Reserve margins for ERCOT, based upon existing capacity and planned
capacity with interconnection agreements, are expected to be 29% in 2004, 25%
in 2005, 22% in 2006, 18% in 2007, and 15% in 2008.
Outside Texas -- Energy industry restructuring, although proceeding well
in Texas, has not had similar success in other parts of the U.S. As early as
2000, optimism for national legislation and increased opening of competitive
markets began to alter the strategy of many industry participants. The
establishment of Regional Transmission Organizations and open access for both
wholesale and retail customers were on the horizon. Together with increasing
customer demand for lower priced electricity and other energy services, these
measures were expected to have accelerated the industry's movement toward a more
competitive pricing and cost structure.
Many states, faced with this increasing pressure from legislative bodies
(federal and state) to become more competitive while adhering to certain
continued regulatory requirements, along with changing economic conditions and
rapid technological changes, put forth deregulation plans that have since been
deferred or changed. The result is delayed restructuring. New entry by retailers
as well as by merchant generators in states other than Texas has been slowed.
The continued uncertainty regarding many FERC policies as well as Federal
legislation have delayed the opening of new retail markets and decreased the
economic viability for merchant generation.
7
Customers -- There are no individually significant customers upon which
TXU Energy's business or results of operations are highly dependent.
REGULATION AND RATES
See Texas Electric Industry Restructuring above for a description of the
significant regulatory provisions relating to the deregulation of the Texas
electric industry.
US Holdings is a holding company as defined in the Public Utility Holding
Company Act of 1935. However, US Holdings and all of its subsidiary companies
are exempt from the provisions of such Act, except Section 9(a)(2) which relates
to the acquisition of securities of public utility companies and Section 33
which relates to the acquisition of foreign (non-US) utility companies.
TXU Energy is an exempt wholesale generator under the Federal Power Act
and is subject to the jurisdiction of the NRC with respect to its nuclear power
plant. NRC regulations govern the granting of licenses for the construction and
operation of nuclear power plants and subject such plants to continuing review
and regulation. TXU Energy also holds a power marketer license from FERC.
See discussion at the end of this Item for environmental regulations and
related matters.
ONCOR
The Oncor segment consists primarily of the electricity transmission and
distribution operations of Oncor. Oncor provides the essential service of
delivering electricity safely, reliably and economically to end-use customers
through its distribution system.
ELECTRICITY TRANSMISSION
Oncor's electricity transmission business is responsible for the safe and
reliable operations of its transmission network and substations. These
responsibilities consist of the construction and maintenance of transmission
facilities and substations and the monitoring, controlling and dispatching of
high-voltage electricity over Oncor's transmission facilities in coordination
with ERCOT.
Oncor is a member of ERCOT, and the transmission business actively
supports the operations of ERCOT and market participants. The transmission
business participates with ERCOT and other member utilities to plan, design,
construct and operate new transmission lines, with regulatory approval,
necessary to maintain reliability, increase bulk power transfer capability and
to minimize limitations and constraints on the ERCOT transmission grid.
Transmission revenues are provided under tariffs approved by either the
Commission or, to a small degree, FERC. Network transmission revenues compensate
Oncor for delivery of power over transmission facilities operating at 60,000
volts and above. Transformation service revenues compensate Oncor for substation
facilities that transform power from high-voltage transmission to distribution
voltages below 60,000 volts. Other services offered by the transmission business
include, but are not limited to: system impact studies, facilities studies and
maintenance of substations and transmission lines owned by other non-retail
parties.
Oncor's transmission facilities include 4,502 circuit miles of
345-kilovolt transmission lines and 9,678 circuit miles of 138- and 69-kV
transmission lines. Also, 43 generating plants totaling 33,260 megawatts are
directly connected to Oncor's transmission system, and 693 distribution
substations are served from Oncor's transmission system.
Oncor is connected by eight 345-kV lines to CenterPoint Energy; by four
345-kV (one of which is an asynchronous high voltage direct current
interconnection to American Electric Power Company in the Southwest Power Pool),
eight 138-kV and thirteen 69-kV lines to American Electric Power Company; by
four 345-kV and eighteen 138-kV lines and three 69-kV lines to the Lower
Colorado River Authority; by seven 345-kV and nine 138-kV lines to the Texas
Municipal Power Agency; and at several points with smaller systems operating
wholly within Texas.
8
ELECTRICITY DISTRIBUTION
Oncor's electricity distribution business is responsible for the overall
safe and efficient operation of distribution facilities, including power
delivery, power quality and system reliability. The Oncor distribution system
supplies electricity to over 2.9 million points of delivery. The electricity
distribution business consists of the ownership, management, construction,
maintenance and operation of the distribution system within Oncor's certificated
service area. Over the past five years, the number of Oncor's distribution
system premises served has been growing an average of 2% per year.
Oncor's distribution system receives electricity from the transmission
system through substations and distributes electricity to end users and
wholesale customers through 2,944 distribution feeders.
The Oncor distribution system consists of 55,472 miles of overhead primary
conductors, 22,076 miles of overhead secondary and street light conductors,
12,936 miles of underground primary conductors and 7,802 miles of underground
secondary and street light conductors. The majority of the distribution system
operates at 25-kV and 12.5-kV.
Most of Oncor's power lines have been constructed over lands of others
pursuant to easements or along public highways, streets and right-of-ways as
permitted by law.
CUSTOMERS
Oncor's transmission customers consist of municipalities, electric
cooperatives and other distribution companies. Oncor's distribution customers
consist of approximately 43 REPs in Oncor's certified service area, including
subsidiary REPs of TXU Energy. For the year ended December 31, 2003, delivery
fee revenues from TXU Energy represented approximately 71% of Oncor's revenues.
There are no individually significant unaffiliated customers upon which Oncor's
business or results are highly dependent.
Since January 1, 2002, the retail customers who purchase and consume
electricity and are connected to Oncor's system have been free to choose their
electricity supplier from REPs who compete for their business. The changed
character of electric service, however, does not mean that the safe and reliable
delivery of dependable power is any less critical to Oncor's success. Service
quality, safety and reliability are of paramount importance to REPs, electricity
customers, and Oncor. Oncor intends to continue to build on its inherited
tradition of low cost and high performance.
REGULATION AND RATES
See Texas Electric Industry Restructuring above for a description of the
significant regulatory provisions relating to the deregulation of the Texas
electric industry.
As its operations are wholly within Texas, Oncor believes that it is not a
public utility as defined in the Federal Power Act and has been advised by its
counsel that it is not subject to general regulation under such Act.
The Commission has original jurisdiction over transmission rates and
services and over distribution rates and services in unincorporated areas and in
those municipalities that have ceded original jurisdiction to the Commission and
has exclusive appellate jurisdiction to review the rate and service orders and
ordinances of municipalities. Generally, the Public Utility Regulatory Act
(PURA) prohibits the collection of any rates or charges by a public utility that
do not have the prior approval of the Commission.
At the state level, PURA, as amended, requires owners or operators of
transmission facilities to provide open access wholesale transmission services
to third parties at rates and terms that are non-discriminatory and comparable
to the rates and terms of the utility's own use of its system. The Commission
has adopted rules implementing the state open access requirements for utilities
that are subject to the Commission's jurisdiction over transmission services,
such as Oncor.
Provisions of the 1999 Restructuring legislation allow Oncor to annually
update its transmission rates to reflect changes in invested capital. These
provisions encourage investment in the transmission system to help ensure
reliability and efficiency by allowing for timely recovery of and return on new
transmission investments.
9
ENVIRONMENTAL MATTERS
---------------------
US Holdings is subject to extensive environmental regulation by
governmental authorities. In operating its facilities, US Holdings is required
to comply with numerous environmental laws and regulations, and to obtain
numerous governmental permits and approvals. If US Holdings fails to comply with
these requirements, it could be subject to civil or criminal liability and
fines. Existing environmental laws and regulations could be revised or
reinterpreted and new laws and regulations could be adopted or become applicable
to US Holdings or its facilities, including potential regulatory and enforcement
developments related to air emissions.
US Holdings may not be able to obtain or maintain all required
environmental regulatory approvals. If there is a delay in obtaining any
required environmental regulatory approvals or if US Holdings fails to obtain,
maintain or comply with the terms of any such approval, the operation of its
facilities could be stopped or become subject to additional costs. Further, at
some of US Holdings' older facilities, including base load lignite and coal
plants, it may be uneconomical for US Holdings to install the necessary
compliance equipment, which may cause US Holdings to shut down those facilities.
In addition, US Holdings may be responsible for any on-site liabilities
associated with the environmental condition of facilities that it has acquired
or developed regardless of when the liabilities arose and whether they are known
or unknown. In connection with acquisitions and sales of assets, US Holdings may
obtain, or be required to provide, indemnification against certain environmental
liabilities. Another party could fail to meet its indemnification obligations to
US Holdings.
Air -- Under the Texas Clean Air Act, the TCEQ has jurisdiction over the
permissible level of air contaminant emissions from, and permitting requirements
for, generating, mining and gas delivery facilities located within the State of
Texas. The New Jersey Department of Environmental Protection has jurisdiction
over the emissions from TXU Energy's generation facility in New Jersey. In
addition, the new source performance standards of the EPA promulgated under the
Federal Clean Air Act, as amended (Clean Air Act), are being implemented by the
TCEQ, and are applicable to certain generating units and ancillary equipment.
TXU Energy's generation plants and mining equipment operate in compliance with
applicable regulations, permits and emission standards promulgated pursuant to
these acts.
The Clean Air Act includes provisions which, among other things, place
limits on the sulfur dioxide (SO2) and nitrogen oxides (NOx) emissions produced
by certain generation plants. In addition to the new source performance
standards applicable to SO2 and NOx, the Clean Air Act requires that
fossil-fueled plants have sufficient SO2 emission allowances and meet certain
NOx emission standards. TXU Energy's generation plants meet the SO2 allowance
requirements and NOx emission rates. In addition, the EPA recently proposed new
requirements calling for electricity generation facilities in 28 states and the
District of Columbia to further reduce emissions of NOx and SO2. TXU Energy will
be required to make additional emissions reductions and incur associated costs
under this proposal if it is finalized in its current form.
In January 2004, the EPA issued a proposed rule to regulate mercury
emissions from power plants with the expectation that a final rule will be
issued by December 2004 with an implementation date in 2008. Two different
regulatory approaches are considered in the announcement and the final form of
the rule is unknown. It is likely that some costs, which could be material, will
be incurred for installation of additional control equipment and for facility
operations and maintenance.
The EPA has also issued rules for controlling regional haze; the impact of
these rules is unknown at this time because the TCEQ has not yet implemented the
regional haze requirements.
10
The Bush Administration is addressing greenhouse gas emissions through its
greenhouse gas emissions intensity reduction Climate VISION program. The Bush
Administration and EPA have proposed the Clear Skies legislative initiative
calling for reductions of SO2, NOx, and mercury from electricity generation
facilities over a 15-year period. Some legislative proposals for additional
regulation of SO2, NOx, mercury and carbon dioxide recently have been considered
at the federal level and it is expected that additional similar proposals will
be made in the future. TXU Energy continues to participate in a voluntary
greenhouse gas emission reduction program and since 1995 has reported the
results of its program annually to the U.S. Department of Energy. TXU Energy is
also participating in a new voluntary electric utility industry sector climate
change initiative in partnership with the Department of Energy. TXU Energy
continues to assess the financial and operational risks posed by future
regulatory or policy changes pertaining to greenhouse gas emissions and multiple
emissions, but because these proposals are in the formative stages, TXU Energy
is unable to predict their future impacts on the financial condition and
operations of TXU Energy.
Major air pollution control provisions of the 1999 Restructuring
Legislation required a 50% reduction in NOx emissions and a 25% reduction in SO2
emissions from "grandfathered" electric utility generation plants. The first
compliance period is for the year beginning May 1, 2003 through April 30, 2004.
TXU Energy has obtained all permits required for the "grandfathered" plants by
the 1999 Restructuring Legislation and has completed a construction program to
install control equipment to achieve the required reductions. US Holdings fully
anticipates that it will be in compliance with the requirements at the end of
the first compliance period.
In 2001, the Texas Clean Air Act was amended to require that
"grandfathered" facilities, other than electric utility generation plants, apply
for permits. TXU Energy and Oncor anticipate that the permits can be obtained
for their "grandfathered" facilities without significant effects on the costs of
operating these facilities.
The TCEQ has also adopted revisions to its State Implementation Plan (SIP)
rules that require an 89% reduction in NOx emissions from electricity generation
plants in the Dallas-Fort Worth ozone non-attainment area and a 51% reduction in
NOx emissions from electricity generation plants in East and Central Texas. Full
compliance is required by May 1, 2005. TXU Energy has already made significant
NOx emissions reductions to achieve the 51% reduction requirements of the 1999
Restructuring Legislation, but anticipates that additional reductions and/or
modifications in plant operations will be required to achieve the 89% reductions
called for in the SIP rules. Additionally, the TCEQ is expected to propose new
SIP rules in 2004 to deal with 1-hour and 8-hour ozone standards. These rules
could require further NOx emissions reductions from certain TXU Energy
facilities.
Water -- The TCEQ and the EPA have jurisdiction over water discharges
(including storm water) from all domestic facilities. Facilities of TXU Energy
and Oncor are presently in compliance with applicable state and federal
requirements relating to discharge of pollutants into the water. TXU Energy and
Oncor hold all required waste water discharge permits from the TCEQ for
facilities in operation and have applied for or obtained necessary permits for
facilities under construction. TXU Energy and Oncor believe they can satisfy the
requirements necessary to obtain any required permits or renewals. Recent
changes to federal rules pertaining to Spill Prevention, Control and
Countermeasure Plans for oil-filled electrical equipment and bulk storage
facilities for oil will require updating of certain facilities. Oncor is unable
to predict at this time the impact of these changes. Clean Water Act Section
316(b) regulations pertaining to existing water intake structures are being
developed by the EPA with publication scheduled for early 2004. TXU Energy is
unable to predict at this time the impacts of these regulations.
Other -- Diversion, impoundment and withdrawal of water for cooling and
other purposes are subject to the jurisdiction of the TCEQ. TXU Energy possesses
all necessary permits for these activities from the TCEQ for its present
operations.
Treatment, storage and disposal of solid and hazardous waste are regulated
at the state level under the Texas Solid Waste Disposal Act and at the federal
level under the Resource Conservation and Recovery Act of 1976, as amended, and
the Toxic Substances Control Act. The EPA has issued regulations under the
Resource Conservation and Recovery Act of 1976 and the Toxic Substances Control
Act, and the TCEQ have issued regulations under the Texas Solid Waste Disposal
Act applicable to facilities of TXU Energy and Oncor. TXU Energy has registered
solid waste disposal sites and has obtained or applied for such permits as are
required by such regulations.
11
Under the federal Low-Level Radioactive Waste Policy Act of 1980, as
amended, the State of Texas is required to provide, either on its own or jointly
with other states in a compact, for the disposal of all low-level radioactive
waste generated within the state. The State of Texas has agreed to a compact
with the States of Maine and Vermont for a disposal facility that would be
located in Texas. That compact was ratified by Congress and signed by the
President in 1998. The State of Texas had proposed to license a disposal site in
Hudspeth County, Texas, but in October 1998, the TCEQ denied that license
application. In 2003, the State of Texas enacted legislation allowing a private
entity to be licensed to accept low-level radioactive waste for disposal. TXU
Energy intends to continue to ship low-level waste material off-site for as long
as an alternative disposal site is available. Should existing off-site disposal
become unavailable, the low-level waste material will be stored on-site. TXU
Energy's on-site storage capacity is expected to be adequate until other
off-site facilities become available. (See Power Production - Nuclear Production
Assets above.)
Environmental Capital Expenditures -- Capital expenditures for TXU
Energy's environmental projects were $27 million in 2003 and are expected to be
about $14 million in 2004. Oncor's capital expenditures for environmental
matters were $2 million in 2003.
Item 3. LEGAL PROCEEDINGS
On July 7, 2003, a lawsuit was filed by Texas Commercial Energy (TCE) in
the United States District Court for the Southern District of Texas, Corpus
Christi Division, against TXU Energy and certain of its subsidiaries, as well as
various other wholesale market participants doing business in ERCOT, claiming
generally that defendants engaged in market manipulation, in violation of
antitrust and other laws, primarily during the period of extreme weather
conditions in late February 2003. An amended complaint was filed on February 3,
2004 that joined additional unaffiliated defendants. Three retail electric
providers have 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 the
behalf of a punitive basis of all former customers of TCE. US Holdings believes
that it has not committed any violation of the antitrust laws and the
Commission's investigation of the market conditions in late February 2003 has
not resulted in any findings adverse to TXU Energy. Accordingly, US Holdings
believes that TCE's and the interveners' claims against TXU Energy and its
subsidiary companies are without merit and TXU Energy and its subsidiaries
intend to vigorously defend the lawsuit. US Holdings is unable to estimate any
possible loss or predict the outcome of this action.
On April 28, 2003, a lawsuit was filed by a former employee of TXU
Portfolio Management in the United States District Court for the Northern
District of Texas, Dallas Division, against TXU Corp., TXU Energy and TXU
Portfolio Management. Plaintiff asserts claims under Section 806 of
Sarbanes-Oxley arising from plaintiff's employment termination and claims for
breach of contract relating to payment of certain bonuses. Plaintiff seeks back
pay, payment of bonuses and alternatively, reinstatement or future compensation,
including bonuses. TXU Corp. believes the plaintiff's claims are without merit.
The plaintiff was terminated as the result of a reduction in force, not as a
reaction to any concerns the plaintiff had expressed, and plaintiff was not in a
position with TXU Portfolio Management such that he had knowledge or information
that would qualify the plaintiff to evaluate TXU Corp.'s financial statements or
assess the adequacy of TXU Corp.'s financial disclosures. Thus, TXU Corp. does
not believe that there is any merit to the plaintiff's claims under
Sarbanes-Oxley. Accordingly, TXU Corp., TXU Energy and TXU Portfolio Management
intend to vigorously defend the litigation. While TXU Corp., TXU Energy and TXU
Portfolio Management dispute the plaintiff's claims, TXU Corp. is unable to
predict the outcome of this litigation or the possible loss in the event of an
adverse judgment.
On March 10, 2003, a lawsuit was filed by Kimberly P. Killebrew in the
United States District Court for the Eastern District of Texas, Lufkin Division,
against TXU Corp. and TXU Portfolio Management, asserting generally that
defendants engaged in manipulation of the wholesale electric market, in
violation of antitrust and other laws. Due to the death of the federal district
judge in Lufkin, this case has been transferred to the Beaumont Division of the
Eastern District of Texas. This action is brought by an individual, alleged to
be a retail consumer of electricity, on behalf of herself and as a proposed
representative of a putative class of retail purchasers of electricity that are
similarly situated. On September 15, 2003, defendants filed a motion to dismiss
the lawsuit and a motion to transfer the case to the Northern District of Texas,
Dallas Division. TXU Corp. believes that the plaintiff lacks standing to assert
any antitrust claims against TXU Corp. or TXU Portfolio Management, and that
defendants have not violated antitrust laws or other laws as claimed by the
plaintiff. Therefore, TXU Corp. believes that plaintiff's claims are without
merit and plans to vigorously defend the lawsuit. TXU Corp. is unable to
estimate any possible loss or predict the outcome of this action.
12
General -- In addition to the above, US Holdings is involved in various
other legal and administrative proceedings the ultimate resolution of which, in
the opinion of each, should not have a material effect upon its financial
position, results of operations or cash flows.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None.
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
Not applicable. All of US Holdings' common stock is owned by TXU Corp.
Reference is made to Note 10 to Financial Statements regarding limitations upon
payment of dividends on common stock of US Holdings.
Item 6. SELECTED FINANCIAL DATA
The information required hereunder for US Holdings is set forth under
Selected Financial Data included in Appendix A to this report.
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
The information required hereunder for US Holdings is set forth under
Management's Discussion and Analysis of Financial Condition and Results of
Operations included in Appendix A to this report.
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The information required hereunder for US Holdings is set forth in
Management's Discussion and Analysis of Financial Condition and Results of
Operations included in Appendix A to this report.
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The information required hereunder for US Holdings is set forth under
Statement of Responsibility, Independent Auditors' Report, Statements of
Consolidated Income, Statements of Consolidated Comprehensive Income, Statements
of Consolidated Cash Flows, Consolidated Balance Sheets, Statements of
Consolidated Shareholders' Equity and Notes to Financial Statements included in
Appendix A to this report.
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
Item 9A. CONTROLS AND PROCEDURES
An evaluation was performed under the supervision and with the
participation of US Holdings' management, including the principal executive
officer and principal financial officer, of the effectiveness of the design and
operation of the disclosure controls and procedures in effect as of December 31,
2003. Based on the evaluation performed, US Holdings' management, including the
principal executive officer and principal financial officer, concluded that the
disclosure controls and procedures were effective.
There have been no significant changes in US Holdings' internal controls
over financial reporting for its continuing operations that have occurred during
the most recent fiscal quarter that has materially affected, or is reasonably
likely to materially affect, US Holdings' internal controls over financial
reporting.
13
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT
Identification of Directors, business experience and other
directorships:
Other Positions and
Offices Presently Date First Elected as Present Principal Occupation or
Held With US Holdings Director Employment and Principal
(Current Term Expires (Current Term Expires Business (Preceding Five Years),
Name of Director Age in May 2004) in May 2004) Other Directorships
- ----------------------------------------------------- ------------------------- -----------------------------------------
<c>
H. Dan Farell 54 Executive Vice May 16, 2003 Executive Vice President and Chief
President and Chief Financial Officer of TXU Corp.;
Financial Officer prior thereto, President of TXU
Gas; prior thereto, President of
TXU Electric; prior thereto,
Executive Vice President of TXU
Electric; other directorships:
Oncor, Oncor Electric Delivery
Transition Bond Company LLC, TXU
Energy and TXU Gas.
Michael J. McNally 49 None February 16, 1996 Executive Vice President of TXU
Corp.; prior thereto, Executive
Vice President and Chief Financial
Officer of TXU Corp.; other
directorships: Oncor, TXU Energy
and TXU Gas.
Eric H. Peterson 43 None November 1, 2002 Executive Vice President and General
Counsel of TXU Corp.; prior
thereto, Senior Vice President and
General Counsel of DTE Energy;
prior thereto, partner in the law
firm of Worsham, Forsythe &
Wooldridge; other directorships:
Oncor, Oncor Electric Delivery
Transition Bond Company LLC, TXU
Energy and TXU Gas.
C. John Wilder 45 Chairman of the Board March 15, 2004 President and Chief Executive of TXU
and Chief Executive Corp.; prior thereto, Executive
Vice President and Chief Financial
Officer of Entergy Corporation;
other directorships: TXU Corp., Oncor,
Oncor Electric Delivery Transition
Bond Company LLC, TXU Energy and
TXU Gas.
Directors of US Holdings receive no compensation in their capacity as Directors.
14
Identification of Executive Officers and business experience:
Positions and Offices Date First Elected to
Presently Held Present Offices
(Current Term Expires (Current Term Expires Business Experience
Name of Officer Age in May 2004) in May 2004) (Preceding Five Years)
- -------------------- -------- ----------------------- ----------------------- ---------------------------------------
C.John Wilder 45 Chairman of the Board March 15, 2004 President and Chief Executive of
and Chief Executive TXU Corp.; prior thereto,
Executive Vice President and
Chief Financial Officer of
Entergy Corporation.
H. Dan Farell 54 Executive Vice March 15, 2004 Executive Vice President and Chief
President and Chief Financial Officer of TXU Corp.;
Financial Officer prior thereto, President of TXU Gas;
prior thereto, President of TXU Electric;
prior thereto, Executive Vice President
of TXU Electric.
T. L. Baker 58 President and Chief March 15, 2004 Executive Vice President of TXU Corp. and
Executive, TXU Energy President and Chief Executive of
TXU Energy; prior thereto, Executive
Vice President of TXU Corp. and President
of TXU Energy; prior thereto, Vice
Chairman of Oncor and TXU Gas; prior therto,
President of TXU Electric Company; prior
thereto, President, Electric Service
Division of TXU Electric Company and TXU Gas
Distribution Division of TXU Gas.
M. S. Greene 58 Vice Chairman and March 15, 2004 Vice Chairman and Chief Executive
Chief Executive, Oncor of Oncor and TXU Gas; prior
thereto, Vice Chairman of Oncor and
TXU Gas; prior thereto, President of
Oncor; prior thereto, President of
TXU Lone Star Pipeline and Transmission
Division of TXU Electric; prior thereto,
Executive Vice President of TXU
Fuel.
R. D. Trimble 55 President, Oncor August 4, 2003 President of Oncor; prior thereto,
Senior Vice President of Oncor; prior
thereto, Senior Vice President of Oncor
and TXU Gas Distribution Division of TXU
Gas; prior thereto, Senior Vice
President of US Holdings.
There is no family relationship between any of the above-named Directors and
Executive Officers.
15
Item 11. EXECUTIVE COMPENSATION
EXECUTIVE COMPENSATION
US Holdings (the Company) and its affiliates have paid and awarded
compensation during the last three calendar years to the executive officers
named in the Summary Compensation Table for services in all capacities. Amounts
reported in the Table as Bonus and LTIP Payouts for any calendar year reflect
the performance of the individual and TXU Corp. in prior periods. Information
relating to compensation provided in 2004 based on performance in 2003 is
contained in the Organization and Compensation Committee Report on Executive
Compensation.
SUMMARY COMPENSATION TABLE
Annual Compensation Long-Term Compensation
----------------------------------- ---------------------------------------
Awards Payouts
------------------------- ------------
Other
Annual Restricted Securities All Other
Compen- Stock Underlying LTIP Compen-
Name and Salary Bonus sation Awards Options/ Payouts sation
Principal Position Year ($) ($)(7) ($) ($)(8) SARs (#) ($)(9) ($)(10)
- ------------------------- ------ ---------- ---------- ---------- ----------- ------------ ------------ ----------
Erle Nye (1) (11)..... 2003 966,667 0 --- 213,750 --- 1,531 482,911
Chairman of the Board 2002 1,037,500 1,950,000 --- 236,250 --- 4,286,400 299,985
and Chief Executive 2001 964,583 475,000 --- 694,375 --- 519,747 222,658
of the Company
H. Dan Farell (2)(11).. 2003 366,667 0 --- 84,375 --- 12,683 62,236
Executive Vice 2002 323,333 180,000 --- 73,125 --- 349,638 64,258
President of the 2001 304,583 80,500 --- 151,375 --- 61,290 47,455
Company
T.L. Baker (3)(11).... 2003 516,667 0 --- 112,500 --- 17,047 114,620
President, TXU 2002 495,000 500,000 --- 112,500 --- 1,109,770 119,960
Energy Company LLC 2001 449,167 125,000 --- 230,750 --- 111,800 89,374
M.S.Greene (4)(11).... 2003 341,708 98,400 --- 73,800 --- 12,683 77,110
Vice Chairman, Oncor 2002 326,667 200,000 --- 73,800 --- 351,516 82,420
2001 311,667 81,500 --- 153,500 --- 18,659 62,710
R. D. Trimble (5)(11). 2003 216,625 62,100 --- 46,575 --- 7,965 42,922
President, Oncor 2002 205,667 90,252 --- 46,575 --- 233,343 42,946
2001 195,250 42,500 --- 87,275 --- 12,191 35,023
Brian N. Dickie (6)(11) 2003 585,278 0 --- 193,500 --- 0 1,394,210
President, TXU Energy 2002 856,667 625,000 --- 193,500 --- 1,071,600 122,629
Company LLC 2001 823,333 252,500 --- 441,500 --- 0 83,229
(until August 8, 2003)
- -----------------------
(1) Compensation amounts represent compensation paid by TXU Corp.
(2) Compensation amounts represent compensation paid by Oncor and, beginning
February 21, 2003, TXU Business Services Company.
(3) Mr. Baker was elected President of TXU Energy effective August 8, 2003.
Compensation amounts represent compensation paid by Oncor and, beginning
August 8, 2003, TXU Energy.
(4) Compensation amounts represent compensation paid by Oncor.
(5) Compensation amounts represent compensation paid by Oncor.
(6) Mr. Dickie resigned as President of TXU Energy effective August 8, 2003.
Compensation amounts represent compensation paid by TXU Energy.
16
(7) Amounts reported as Bonus in the Summary Compensation Table are
attributable principally to the named executive officers' participation in
the TXU Annual Incentive Plan (AIP). No AIP awards for 2002 performance
were provided in 2003 to any officers. Under the terms of the AIP
effective in 2003, target incentive awards ranging from 20% to 75% of base
salary, with a maximum award of 100% of base salary, are established. The
percentage of the target or maximum actually awarded, if any, is dependent
upon the attainment of per share net income goals established in advance
by the Organization and Compensation Committee (Committee), as well as the
Committee's evaluation of the participant's and TXU Corp.'s performance.
The amounts reported as Bonus for Messrs. Greene and Trimble represent
special bonuses awarded in February 2003 in recognition of their
significant contributions in their areas of responsibility.
(8) Amounts reported as Restricted Stock Awards in the Summary Compensation
Table are attributable to the named officer's participation in the
Deferred and Incentive Compensation Plan (DICP). Participants in the DICP
may defer a percentage of their base salary not to exceed a maximum
percentage determined by the Committee for each plan year and in any event
not to exceed 15% of the participant's base salary. Salary
deferred under the DICP is included in amounts reported as Salary in the
Summary Compensation Table. TXU Corp. makes a matching award (Matching
Award) equal to 150% of the participant's deferred salary. Prior to 2002,
one-half of any AIP award (Incentive Award) was deferred and invested
under the DICP. Matching Awards are subject to forfeiture under certain
circumstances. Under the DICP, a trustee purchases TXU Corp. common stock
with an amount of cash equal to each participant's deferred salary and
Matching Award, and accounts are established for each participant
containing performance units (Units) equal to such number of common
shares. DICP investments, including reinvested dividends, are restricted
to TXU Corp. common stock, and the value of each unit credited to
participants' accounts equals the value of a share of TXU Corp. common
stock and is at risk based on the performance of the stock. On the
expiration of the five year maturity period, the value of the
participant's maturing accounts are paid in cash based upon the then
current value of the Units; provided, however, that in no event will a
participant's account be deemed to have a cash value which is less than
the sum of such participant's deferrals together with 6% per annum
interest compounded annually. Participants may elect to defer amounts that
would otherwise mature under the DICP, under and subject to the provisions
of the Salary Deferral Program (SDP) as discussed in footnote (10). The
maturity period is waived if the participant dies or becomes totally and
permanently disabled and may be extended under certain circumstances.
Matching Awards that have been made under the DICP are included under
Restricted Stock Awards in the Summary Compensation Table. As a result of
these awards, undistributed Matching and Incentive Awards made in prior
years and dividends reinvested thereon, the number and market value at
December 31, 2003 of such Units (each of which is equal to one share of
common stock) held in the DICP accounts for Messrs. Nye, Farell, Baker,
Greene, Trimble and Dickie were 61,320 ($1,454,510), 13,628 ($323,256),
19,484 ($462,160), 13,145 ($311,799), 8,175 ($193,911) and 35,896
($851,453), respectively.
(9) Amounts reported as LTIP Payouts in the Summary Compensation Table for
2003 reflect earnings distributed during the year on salaries previously
deferred under the DICP. Amounts reported for 2002 and 2001 also include
the vesting and distribution of performance-based restricted stock awards
under the Long-Term Incentive Compensation Plan (LTICP). For the LTICP
cycle ending in 2003, no awards were earned.
The LTICP is a comprehensive, stock-based incentive compensation plan
providing for common stock-based awards, including performance-based
restricted stock. Outstanding awards, as of December 31, 2003, of
performance-based restricted stock to the named executive officers may
vest at the end of a two-year or three-year performance period, depending
on the award, and provide for an ultimate distribution of from 0% to 200%
of the number of the shares initially awarded, based on TXU Corp.'s total
return to shareholders over such performance period compared to the total
returns provided by the companies comprising the Standard & Poor's 500
Electric Utilities Index. Dividends on restricted shares are reinvested in
TXU Corp. common stock and are paid in cash upon release of the restricted
shares. Under the terms of the LTICP, the maximum amount of any award that
may be paid in any one year to any of the named executive officers is the
fair market value of 100,000 shares of TXU Corp.'s common stock determined
as of the first day of such calendar year. The portion of any award that,
based on such limitation, cannot be fully paid in any year is deferred
until a subsequent year when it can be paid. Based on TXU Corp.'s total
return to shareholders over the three-year period ending March 31, 2003
compared to the returns provided by the companies comprising the Standard
& Poor's 500 Electric Utilities Index, all of the performance-based
restricted shares awarded in May 2000 were forfeited.
17
As a result of restricted stock awards under the LTICP, and reinvested
dividends thereon, the number of shares of restricted stock and the market
value of such shares at December 31, 2003 held for Messrs. Nye, Farell,
Baker, Greene, Trimble and Dickie were 459,405 ($10,897,087), 48,594
($1,152,650), 136,681 ($3,242,073), 53,702 ($1,273,811), 21,743 ($515,744)
and 66,047 ($1,566,635), respectively.
As noted, salaries deferred under the DICP are included in amounts
reported as Salary in the Summary Compensation Table. Amounts shown in the
table below represent the number of shares purchased under the DICP with
such deferred salaries for 2003 and the number of shares awarded under the
LTICP.
LONG-TERM INCENTIVE PLANS - AWARDS IN LAST FISCAL YEAR
Deferred and Incentive
Compensation Plan
(DICP) Long-Term Incentive Compensation Plan (LTICP)
---------------------------- --------------------------------------------------------------
Number of Performance Number of Performance
Shares, or Other Shares, or Other
Units or Period Until Units or Period Until
Other Maturation or Other Maturation or Estimated Future Payouts
Name Rights (#) Payout Rights (#) Payout Minimum (#) Maximum (#)
---- ---------- ------ ---------- ------ ----------- -----------
Erle Nye.......... 7,888 5 Years 80,000 2 Years 0 160,000
80,000 3 Years 0 160,000
H. Dan Farell.... 3,113 5 Years 16,000 2 Years 0 32,000
16,000 3 Years 0 32,000
T. L. Baker....... 4,151 5 Years 40,000 2 Years 0 80,000
40,000 3 Years 0 80,000
M. S. Greene...... 2,724 5 Years 18,000 2 Years 0 36,000
18,000 3 Years 0 36,000
R. D. Trimble..... 1,719 5 Years 7,000 2 Years 0 14,000
7,000 3 Years 0 14,000
Brian N. Dickie... 7,140 5 Years 30,000 2 Years 0 60,000
30,000 3 Years 0 60,000
(10) Amounts reported as All Other Compensation in the Summary Compensation
Table are attributable to the named executive officer's participation in
certain plans and as otherwise described in this footnote.
Under the TXU Thrift Plan (Thrift Plan) all eligible employees of TXU
Corp. and any of its participating subsidiaries may invest a portion of
their regular salary or wages in common stock of TXU Corp., or in a
variety of selected mutual funds. Under the Thrift Plan, TXU Corp. matches
a portion of an employee's contributions. TXU Corp.'s matching
contribution is 75% of the first 6% of the employee's contribution for
employees covered under the traditional defined benefit component of the
TXU Retirement Plan, and 100% of the first 6% of the employee's
contribution for employees covered under the cash balance component of the
TXU Retirement Plan. All matching contributions are invested in common
stock of TXU Corp. The amounts reported under All Other Compensation in
the Summary Compensation Table include these matching amounts which, for
Messrs. Nye, Farell, Baker, Greene, Trimble and Dickie were $12,000,
$9,000, $9,000, $9,000, $7,727 and $8,691, respectively, during 2003.
Under the Salary Deferral Program (SDP) each employee of TXU Corp. and its
participating subsidiaries whose annual salary is equal to or greater than
an amount established under the SDP ($107,930 for the program year
beginning January 1, 2003) may elect to defer up to 50% of annual base
salary, and/or up to 100% of any bonus or incentive award and certain
maturing DICP awards, for a period of seven years, for a period ending
with the retirement of such employee, or for a combination thereof. TXU
Corp. makes a matching award, subject to forfeiture under certain
circumstances, equal to 100% of up to the first 8% of salary deferred
18
under the SDP; provided that employees who first become eligible to
participate in the SDP on or after January 1, 2002, who are also eligible,
or become eligible, to participate in the DICP, are not eligible to
receive any SDP matching awards. Salaries and bonuses deferred under the
SDP are included in amounts reported under Salary and Bonus, respectively,
in the Summary Compensation Table. Deferrals are credited with earnings or
losses based on the performance of investment alternatives under the SDP
selected by each participant. At the end of the applicable maturity
period, the trustee for the SDP distributes the deferrals and the
applicable earnings in cash as a lump sum or in annual installments. TXU
Corp. is financing the retirement option portion of the SDP through the
purchase of corporate-owned life insurance on the lives of participants.
The proceeds from such insurance are expected to allow TXU Corp. to fully
recover the cost of the retirement option. During 2003, matching awards,
which are included under All Other Compensation in the Summary
Compensation Table, were made for Messrs. Nye, Farell, Baker, Greene,
Trimble and Dickie in the amounts of $77,333, $29,333, $41,333, $34,367,
$17,440 and $46,822, respectively. Under the TXU Split-Dollar Life
Insurance Program (Insurance Program) split-dollar life insurance policies
are purchased for eligible corporate officers of TXU Corp. and its
participating subsidiaries. The eligibility provisions of the Insurance
Program were modified in 2003 so that no new participants will be added
after December 31, 2003. The death benefit of participants' insurance
policies are equal to two, three or four times their annual Insurance
Program compensation depending on their officer category. Individuals who
first became eligible to participate in the Insurance Program after
October 15, 1996, vest in the policies issued under the Insurance Program
over a six-year period. TXU Corp. pays the premiums for the policies and
has received a collateral assignment of the policies equal in value to the
sum of all of its insurance premium payments; provided that, with respect
to executive officers, premium payments made after August 1, 2002, are
made on a non-split-dollar life insurance basis and TXU Corp.'s rights
under the collateral assignment are limited to premium payments made prior
to August 1, 2002. Although the Insurance Program is terminable at any
time, it is designed so that if it is continued, TXU Corp. will fully
recover all of the insurance premium payments covered by the collateral
assignments either upon the death of the participant or, if the
assumptions made as to policy yield are realized, upon the later of 15
years of participation or the participant's attainment of age 65. During
2003, the economic benefit derived by Messrs. Nye, Farell, Baker, Greene,
Trimble and Dickie from the term insurance coverage provided and the
interest foregone on the remainder of the insurance premiums paid by
TXU Corp. amounted to $193,578, $23,903, $64,287, $33,743, $17,755
and $31,792, respectively.
The amount reported as All Other Compensation for Mr. Nye for 2003
includes $200,000 as provided for in his employment agreement as discussed
in footnote (11).
The amount reported as All Other Compensation for 2003 for Mr. Dickie
includes a severance payment of $1,306,905 as provided for in his
employment agreement as discussed in footnote (11).
(11) TXU Corp. has entered into employment agreements with Messrs. Nye, Farell,
Baker, Greene, Trimble and Dickie as hereinafter described in this
footnote.
Effective June 1, 2002, TXU Corp. entered into a new employment agreement
with Mr. Nye, which superseded his previous employment agreement. The new
agreement provides for an initial term expiring May 31, 2005, and a
secondary term expiring May 31, 2007. During the initial term, Mr. Nye
will continue to serve as TXU Corp.'s Chairman of the Board and Chief
Executive until such time as his successor is elected at which time Mr.
Nye may continue as TXU Corp.'s Chairman of the Board and/or in such other
executive position as he and TXU Corp. may mutually agree upon. During the
secondary term, Mr. Nye will continue as an employee of TXU Corp. or, with
TXU Corp.'s approval, he may retire and serve TXU Corp. in a consulting
capacity through the expiration of the secondary term. Mr. Nye will,
during the initial term, be entitled to a minimum annual base salary of
$1,050,000, eligibility for an annual bonus under the terms of the AIP,
and minimum annual restricted stock awards of 40,000 shares under the
LTICP. The agreement also provides for a special payment of $1,000,000 in
consideration for his entering into the new agreement which amount is
payable in equal annual installments over a five year period. During the
secondary term, Mr. Nye will be entitled to an annual base salary equal to
75% of his base salary prior to expiration of the initial term and
eligibility for a prorated bonus under the terms of the AIP for the 2005
AIP plan year. The agreement also provides Mr. Nye with certain benefits
following his retirement, including administrative support, annual medical
examinations and financial planning services. The agreement also
reconfirms TXU Corp.'s prior agreement to fund the retirement benefit to
which Mr. Nye will be entitled under TXU Corp.'s supplemental retirement
19
plan. Additionally, the agreement entitles Mr. Nye to certain severance
benefits in the event he dies, becomes disabled, is terminated without
cause or resigns or retires with TXU Corp.'s approval during the term of
the agreement, including the base salary and annual incentive awards he
would have received; continued payment of the remaining special award
installments; a payment in lieu of foregone and forfeited incentive
compensation; and health care benefits. The agreement also provides for
compensation and benefits under certain circumstances following a
change-in-control of TXU Corp. during the initial term, including a
payment equal to the greater of three times his annualized base salary and
target bonus or the total base salary and bonus he would have received for
the remainder of the term of the agreement; any unpaid portion of the
special bonus; a payment in lieu of foregone and forfeited incentive
compensation; health care benefits; and a tax gross-up payment to offset
any excise tax which may result from such change-in-control payments.
TXU Business Services Company entered into an employment agreement with
Mr. Farell effective February 28, 2003. The agreement provides for the
continued service by Mr. Farell through February 28, 2006 (Term). Under
the terms of the agreement, Mr. Farell will, during the Term, be entitled
to a minimum annual base salary of $375,000 and to participate in all
employee benefit plans to the extent he is eligible by virtue of his
employment with TXU Corp. The agreement entitles Mr. Farell to certain
severance benefits in the event he is terminated without cause during the
Term, including a payment equal to the greater of his annualized base
salary and target bonus, or the total amount of base salary and target
bonuses he would have received for the remainder of the Term; a payment in
lieu of forfeited incentive compensation; and health care benefits. The
agreement also provides for compensation and benefits under certain
circumstances following a change-in-control of TXU Corp. during the Term,
including a payment equal to three times his annualized base salary and
target bonus; a payment in lieu of foregone and forfeited incentive
compensation; health care benefits and a tax gross-up payment to offset
any excise tax which may result from such change-in-control payments.
TXU Corp. entered into an employment agreement with Mr. Baker effective
July 1, 2000. The agreement, as amended, provides for the continued
service by Mr. Baker through February 28, 2006 (Term). Under the terms of
the agreement, Mr. Baker will, during the Term, be entitled to a minimum
annual base salary of $420,000, eligibility for an annual bonus under the
terms of the AIP, and minimum restricted stock awards of 12,000 shares
under the LTICP. The agreement entitles Mr. Baker to certain severance
benefits in the event he is terminated without cause during the Term,
including a payment equal to the greater of his annualized base salary and
target bonus, or the total amount of base salary and target bonuses he
would have received for the remainder of the Term; a payment in lieu of
foregone and forfeited incentive compensation; and health care benefits.
The agreement also provides for compensation and benefits under certain
circumstances following a change-in-control of TXU Corp. during the Term,
including a payment equal to three times his annualized base salary and
target bonus; a payment in lieu of foregone and forfeited incentive
compensation; health care benefits and a tax gross-up payment to offset
any excise tax which may result from such change-in-control payments.
TXU Corp. entered into an employment agreement with Mr. Greene effective
July 1, 2000. The agreement, as amended, provides for the continued
service by Mr. Greene through June 30, 2006 (Term). Under the terms of the
agreement, Mr. Greene will, during the Term, be entitled to a minimum
annual base salary of $300,000, eligibility for an annual bonus under the
terms of the AIP, and minimum restricted stock awards of 5,000 shares
under the LTICP. The agreement entitles Mr. Greene to certain severance
benefits in the event he is terminated without cause during the Term,
including a payment equal to the greater of his annualized base salary and
target bonus, or the total amount of base salary and target bonuses he
would have received for the remainder of the Term; a payment in lieu of
foregone and forfeited incentive compensation; and health care benefits.
The agreement also provides for compensation and benefits under certain
circumstances following a change-in-control of TXU Corp. during the Term,
including a payment equal to three times his annualized base salary and
target bonus; a payment in lieu of foregone and forfeited incentive
compensation; health care benefits and a tax gross-up payment to offset
any excise tax which may result from such change-in-control payments.
Oncor entered into an employment agreement with Mr. Trimble effective
March 12, 2003. The agreement provides for the continued service by Mr.
Trimble through March 12, 2006 (Term). Under the terms of the agreement,
Mr. Trimble will, during the Term, be entitled to a minimum annual base
salary of $207,000 and to participate in all employee benefit plans to the
extent he is eligible by virtue of his employment. The agreement entitles
Mr. Trimble to certain severance benefits in the event he is terminated
without cause during the Term, including a payment equal to the greater of
his annualized base salary and target bonus, or the total amount of base
salary and target bonuses he would have received for the remainder of the
Term; a payment in lieu of forfeited incentive compensation; and health
care benefits. The agreement also provides for compensation and benefits
under certain circumstances following a change-in-control of TXU Corp.
during the Term, including a payment equal to three times his annualized
base salary and target bonus; a payment in lieu of foregone and forfeited
incentive compensation; health care benefits and a tax gross-up payment to
offset any excise tax which may result from such change-in-control
payments.
20
Mr. Dickie resigned his employment with TXU Energy effective August 8,
2003. TXU Corp. had previously entered into an employment agreement with
Mr. Dickie, effective December 3, 2002, which had superseded and replaced
his previous employment agreement. Under the terms of the agreement, Mr.
Dickie was entitled during the term, which would have expired May 31,
2005, to a minimum annual base salary of $860,000, eligibility for an
annual bonus under the AIP, minimum annual restricted stock awards of
15,000 shares under the LTICP, and certain special retirement
compensation. Under the terms of the agreement, Mr. Dickie received
certain severance benefits upon his resignation, including a payment equal
to his annual base salary and target bonus, payments for otherwise
forfeited incentive compensation, and health care benefits.
TXU Corp. and its participating subsidiaries maintain a retirement plan
(Retirement Plan), which is qualified under applicable provisions of the
Internal Revenue Code of 1986, as amended (Code). The Retirement Plan contains
both a traditional defined benefit component and a cash balance component.
Annual retirement benefits under the traditional defined benefit component,
which applied during 2003 to each of the named officers other than Mr. Nye, are
computed as follows: for each year of accredited service up to a total of 40
years, 1.3% of the first $7,800, plus 1.5% of the excess over $7,800, of the
participant's average annual earnings during his or her three years of highest
earnings. The cash balance component covers all employees who first become
eligible to participate in the Retirement Plan on or after January 1, 2002, and
employees previously covered under the traditional defined benefit component who
elected to convert the actuarial equivalent of their accrued traditional defined
benefit to the cash balance plan component. Mr. Nye elected to convert to the
cash balance component. Under the cash balance component, hypothetical accounts
are established for participants and credited with monthly contribution credits
equal to a percentage of the participant's compensation (3.5%, 4.5%, 5.5% or
6.5% depending on the participant's combined age and years of accredited
service) and interest credits based on the average yield of the 30-year Treasury
bond for the 12 months ending November 30 of the prior year. Amounts reported
under Salary for the named executive officers in the Summary Compensation Table
approximate earnings as defined under the traditional defined benefit component
of the Retirement Plan without regard to any limitations imposed by the Code.
Benefits paid under the traditional defined benefit component of the Retirement
Plan are not subject to any reduction for Social Security payments but are
limited by provisions of the Code. Based on benefits accrued under the cash
balance component of the Retirement Plan as of December 31, 2003, the estimated
annual benefit payable in the form of a straight-life annuity as of that date
for Mr. Nye is $1,259,968. As of December 31, 2003, years of accredited service
under the Retirement Plan for Messrs. Nye, Farell, Baker, Greene, Trimble and
Dickie were 40, 29, 33, 33, 30 and 7, respectively.
PENSION PLAN TABLE
Years of Service
----------------------------------------------------------------------------------------
Remuneration 20 25 30 35 40
- ---------------------- ------------- -------------- ------------- ---------------- ---------------
$ 50,000 $14,688 $ 18,360 $22,032 $25,704 $29,376
100,000 29,688 37,110 44,532 51,954 59,376
200,000 59,688 74,610 89,532 104,454 119,376
400,000 119,688 149,610 179,532 209,454 239,376
800,000 239,688 299,610 359,532 419,454 479,376
1,000,000 299,688 374,610 449,532 524,454 599,376
1,400,000 419,688 524,610 629,532 734,454 839,376
1,800,000 539,688 674,610 809,532 944,454 1,079,376
2,000,000 599,688 749,610 899,532 1,049,454 1,199,376
TXU Corp.'s supplemental retirement plan (Supplemental Plan) provides
for the payment of retirement benefits, which would otherwise be limited by the
Code or the definition of earnings in the Retirement Plan, as well as retirement
compensation not payable under the Retirement Plan which TXU Corp. or its
participating subsidiaries are obligated to pay. Under the Supplemental Plan,
retirement benefits are calculated in accordance with the same formula used
under the qualified plan, except that, with respect to calculating the portion
of the Supplemental Plan benefit attributable to service under the traditional
defined benefit component of the Retirement Plan, earnings also include AIP
awards (100% of the AIP awards for 2003 and 2002 and 50% of the AIP award for
2001 are reported under Bonus for the named officers in the Summary Compensation
Table). The table set forth above illustrates the total annual benefit on a
straight-life basis payable at retirement under the Retirement Plan inclusive of
benefits payable under the Supplemental Plan, prior to any reduction for
earlier-than-normal or a contingent beneficiary option which may be selected by
participants.
21
The following report and performance graph are presented herein for
information purposes only. This information is not required to be included
herein and shall not be deemed to form a part of this report to be "filed" with
the Securities and Exchange Commission. The report set forth hereinafter is the
report of the Organization and Compensation Committee of the Board of Directors
of TXU Corp., as currently expected to be filed with the SEC in the proxy
statement of TXU Corp. on or about April 5, 2004, and is illustrative of the
methodology utilized in establishing the compensation of executive officers of
US Holdings. References in the report to the "Company" are references to
TXU Corp. and references to "this proxy statement" are references to
TXU Corp.'s proxy statement in connection with TXU Corp.'s 2004 annual meeting
of shareholders.
ORGANIZATION AND COMPENSATION COMMITTEE REPORT
ON EXECUTIVE COMPENSATION
The Organization and Compensation Committee of the Board of Directors:
(i) reviews and approves corporate goals and objectives relevant to the
compensation of the Chief Executive Officer (CEO), evaluates the CEO's
performance in light of those goals and objectives and determines and approves
the CEO's compensation based on such evaluation; (ii) oversees the evaluation of
senior executives and makes recommendations to the Board with respect to
equity-based and other compensation plans, policies and practices; (iii) reviews
and discusses with the Board executive management succession planning; and (iv)
makes recommendations to the Board with respect to the compensation of the
Company's non-employee Directors. The role and responsibilities of the Committee
are fully set forth in the Committee's written charter which was approved by the
Board of Directors and which is posted on the Company's website. The Committee
consists only of directors of the Company who satisfy the requirements for
independence under applicable law and regulations of the SEC and the NYSE and is
chaired by J. E. Oesterreicher. The Committee has directed the preparation of
this report and has approved its content and submission to the shareholders.
As a matter of policy, the Committee believes that levels of executive
compensation should be based upon an evaluation of the performance of the
Company and its officers generally, as well as in comparison to persons with
comparable responsibilities in similar business enterprises. Compensation plans
should align executive compensation with returns to shareholders with due
consideration accorded to balancing both long-term and short-term objectives.
The overall compensation program should provide for an appropriate and
competitive balance between base salaries and performance-based annual and
long-term incentives.
The Committee has determined that, as a matter of policy to be implemented over
time, the base salaries of the officers will be established around the median,
or 50th percentile, of the base salaries provided by comparable energy
companies, or other relevant market, and that opportunities for total direct
compensation (defined as the sum of base salaries, annual incentives and
long-term incentives) to reach the 75th percentile, or above, of such market or
markets will be provided through annual and long-term performance-based
incentive compensation plans. Such compensation principles and practices have
allowed, and should continue to allow, the Company to attract, retain and
motivate its key executives.
In furtherance of these policies, nationally recognized compensation
consultants have been retained to assist the Committee in its periodic reviews
of compensation and benefits provided to officers. As provided in its charter,
the Committee has the sole authority to retain any compensation consultant used
to assist in the evaluation of compensation provided to officers and directors.
The consultants' evaluations include comparisons to comparable utilities and
energy companies as well as to general industry with respect both to the level
and composition of officers' compensation.
22
The compensation of the officers of the Company consists principally of
base salaries, the opportunity to earn an incentive award under the Annual
Incentive Plan (AIP), awards of performance-based restricted shares under the
Long-Term Incentive Compensation Plan (Long-Term Plan) and, to a lesser extent,
the opportunity to participate in the Deferred and Incentive Compensation Plan
(DICP). Awards under the AIP are directly related to annual performance as
evaluated by the Committee. The ultimate value, if any, of awards of
performance-based restricted shares under the Long-Term Plan, as well as the
value of future payments under the DICP are directly related to the future
performance of the Company's common stock. It is anticipated that
performance-based incentive awards under the AIP and the Long-Term Plan, will,
in future years, continue to constitute a substantial percentage of the
officers' total compensation.
The AIP, which was first approved by the shareholders in 1995 and
reapproved in 2000, is administered by the Committee and provides an objective
framework within which annual performance can be evaluated by the Committee.
Depending on the results of such performance evaluations, and the attainment of
the per share net income goals established in advance, the Committee may provide
annual incentive compensation awards to eligible officers. The evaluation of
each individual participant's performance may be based upon the attainment of a
combination of corporate, group, business unit, function and/or individual
objectives. The Company's annual performance is evaluated based upon its total
return to shareholders, return on invested capital and earnings growth, as well
as other measures such as competitiveness, service quality and employee safety.
The combination of individual and Company results, together with the Committee's
evaluation of the competitive level of compensation which is appropriate for
such results, determines the amount of annual incentive, if any, actually
awarded. Awards under the AIP constitute the principal annual incentive
component of officers' compensation.
The Long-Term Plan, which was first approved by the shareholders in
1997 and reapproved as amended in 2002, is also administered by the Committee
and is a comprehensive stock-based incentive compensation plan under which all
awards are made in, or based on the value of, the Company's common stock. The
Long-Term Plan provides that, in the discretion of the Committee, awards may be
in the form of stock options, stock appreciation rights, performance and/or
restricted stock or stock units or in any other stock-based form. The purpose of
the Long-Term Plan is to provide performance-related incentives linked to
long-term performance goals. Such performance goals may be based on individual
performance and/or may include criteria such as absolute or relative levels of
total shareholder return, revenues, sales, net income or net worth of the
Company, any of its subsidiaries, business units or other areas, all as the
Committee may determine. Awards under the Long-Term Plan provided to the
officers of the Company have been almost exclusively in the form of
performance-based restricted stock as more fully described hereinafter. Awards
under the Long-Term Plan constitute the principal long-term component of
officers' compensation.
In establishing levels of executive compensation, the Committee has
reviewed various performance and compensation data, including the performance
measures under the AIP and the reports of its compensation consultant.
Information was also gathered from industry sources and other published and
private materials which provided a basis for comparing comparable electric and
gas utilities and other survey groups representing a large variety of business
organizations. Included in the data considered were the comparative returns
provided by the largest electric and gas utilities as represented by the returns
of the Standard & Poor's 500 Electric Utilities Index which are reflected in the
graph on page 25. Compensation amounts were established by the Committee based
upon its consideration of the above comparative data and its subjective
evaluation of Company and individual performance at levels consistent with the
Committee's policy relating to total direct compensation.
Since its last report to shareholders which was published in the proxy
statement for the 2003 annual meeting of shareholders, the Committee has
considered officers' compensation matters at several meetings. The results of
Committee actions taken in 2003 are included in the Summary Compensation Table
and related materials on pages 14 through 19 of this proxy statement. Generally
speaking, actions taken at those meetings reflected the Company's business
reversals in late 2002 and included freezing executive officers' salaries and
not providing any AIP awards for 2002 performance. Additionally, with respect to
the Long-Term Plan, the Committee determined that the Company's performance for
the three years ended in March of 2003 did not permit the payment of
performance-based restricted stock awards which had been made in May of 2000 and
such awards were completely forfeited. Moreover, it is anticipated that similar
awards provided in 2001 and 2002 for performance periods ending in 2004 and 2005
may also be completely or partially forfeited depending on returns during the
remainder of the relevant performance periods.
23
At its meetings in February 2003 and February 2004, the Committee
provided awards of performance-based restricted shares under the Long-Term Plan
to officers and other key employees. The ultimate value of all of such awards,
if any, will be determined by the Company's total return to shareholders over
future performance periods compared to the total returns for those periods of
the companies comprising the Standard & Poor's 500 Electric Utilities Index.
Depending upon the Company's relative total return for such periods, the
officers may earn from 0% to 200% of the original award, and their compensation
is, thereby, directly related to shareholder value. All of the awards
contemplate that 200% of the original award will be provided if the Company's
total return is in the 81st percentile or above of the returns of the companies
comprising the Standard & Poor's 500 Electric Utilities Index and that such
percentage of the original award will be reduced as the Company's return
compared to the returns provided by the companies in the Index declines so that
0% of the original award will be provided if the Company's return is in the 40th
percentile or below of returns provided by the companies comprising the Index.
Information relating to awards made to the named executive officers in 2003 is
contained in the Table on page 16 of this proxy statement. These awards, and any
awards that may be made in the future, are based upon the Committee's evaluation
of the appropriate level of long-term compensation consistent with its policy
relating to total direct compensation.
Actions taken by the Committee in 2003 with respect to Mr. Nye's
compensation as Chief Executive reflected the Company's business reversals in
late 2002. In February 2003, the Committee established Mr. Nye's base salary at
an annual rate of $1,050,000, which was the same rate as established in 2002. In
recognition of the Company's cost reduction efforts, Mr. Nye voluntarily reduced
his base salary to a rate of $950,000 for one year. As noted earlier, the
Committee did not provide AIP awards to any executive officers, including Mr.
Nye, in 2003 based on 2002 performance, and the May 2000 performance-based
restricted stock awards, including Mr. Nye's award, were completely forfeited.
Additionally, in 2003 and as reflected in the table on page 16 of this proxy
statement, the Committee provided awards of performance-based restricted stock
to Mr. Nye, the ultimate value of which will be determined by the Company's
performance over two and three-year performance periods. Under the terms of
those awards, Mr. Nye can earn from 0% to 200% of the original awards depending,
with respect to 80,000 shares, on the Company's total return to shareholders
over a two-year period (April 1, 2003 through March 31, 2005) and, with respect
to 80,000 shares, on the Company's total return to shareholders over a
three-year period (April 1, 2003 through March 31, 2006) compared to the total
returns provided for the respective periods by the companies comprising the
Standard & Poor's 500 Electric Utilities Index. The level of compensation
established for Mr. Nye was based upon the Committee's subjective evaluation of
the information contained in this report.
Effective February 23, 2004, C. John Wilder was elected President and
Chief Executive of the Company. In connection with his employment, the Committee
recommended, and the Board approved, entering into an employment agreement with
Mr. Wilder. The agreement provides for Mr. Wilder's service as President and
Chief Executive during a five-year term which may be extended for successive
one-year periods. The agreement contemplates that Mr. Wilder will be elected
Chairman of the Board following the annual meeting of shareholders in 2005.
Under the terms of the agreement, Mr. Wilder will be entitled to an annual base
salary of $1,250,000; target annual bonuses under the Annual Incentive Plan of
200% of base salary; annual performance-based restricted stock awards under the
Long-Term Incentive Compensation Plan, the ultimate value of which will be
determined by the Company's relative returns to shareholders, of 300,000 shares
in 2004 and 150,000 shares in each of 2005, 2006 and 2007; 1,000,000 phantom
performance units, each of which is equal to one share of the Company's common
stock, one third of which will become distributable in stock or cash if and when
the Company's common stock trades at $29, $31 and $33, respectively, for thirty
consecutive trading days; the establishment of a trust which will purchase
500,000 shares of Company common stock, to be distributed to Mr. Wilder in cash
or stock, in equal portions on the third and sixth anniversaries of the
agreement; a signing bonus of $1,000,000; and certain fringe benefits and tax
reimbursement payments related to certain fringe benefits. The agreement also
entitles Mr. Wilder to certain payments and benefits upon the expiration or
termination of the agreement under various circumstances and allows him to
elect to defer the receipt of certain payments. The Committee determined, based
upon its subjective evaluation of competitive market conditions, that the amount
as well as the form of Mr. Wilder's compensation was required and appropriate
in order to attract, incent and retain an individual with Mr. Wilder's
capabilities. A very significant portion of Mr. Wilder's total expected future
compensation (namely his annual bonus, performance units and performance-based
restricted stock awards) will only be provided based on the Company's future
performance, and his compensation is, therefore, directly linked to
shareholders' long-term interests.
24
As previously reported, the Company has entered into employment
agreements, as approved by the Committee, with certain officers. The terms of
employment agreements with the named executive officers are described in
Footnote 5 to the Summary Compensation Table on pages 17, 18 and 19 of this
proxy statement.
Certain of the Company's business units have developed separate annual
incentive compensation plans. Those plans focus on the results achieved by those
individual business units and the compensation opportunities provided by those
plans are considered to be competitive in the markets in which those units
compete. Generally, officers may not participate in both the traditional
incentive compensation plans as discussed herein and the business unit plans.
None of the named executive officers participate in the individual business unit
plans.
In discharging its responsibilities with respect to establishing
officers' compensation, the Committee normally considers such matters at its
February and May meetings. Although Company management may be present during
Committee discussions of officers' compensation, Committee decisions with
respect to the compensation of the Chief Executive are reached in private
session without the presence of any member of Company management.
Section 162(m) of the Code limits the deductibility of compensation
which a publicly traded corporation provides to its most highly compensated
officers. As a general policy, the Company does not intend to provide
compensation which is not deductible for federal income tax purposes. However,
the Committee reserves the right to provide compensation which may not be
deductible when it believes that providing such compensation is consistent with
the strategic goals of the Company and in its best interests. Awards under the
AIP and the Long-Term Plan are expected to be fully deductible and the DICP and
the Salary Deferral Program require the deferral of distributions of maturing
amounts until the time when such amounts would be deductible.
Shareholder comments to the Committee are welcomed and should be
addressed to the Secretary of the Company at the Company's offices.
Organization and Compensation Committee
J. E. Oesterreicher, Chair Jack E. Little
E. Gail de Planque Margaret N. Maxey
(appointed February 2004) (retired February 2004)
Derek C. Bonham Michael W. Ranger
William M. Griffin Herbert H. Richardson
Kerney Laday
25
PERFORMANCE GRAPH
The following graph compares the performance of TXU Corp.'s common
stock to the S&P 500 Index and S&P 500 Electric Utilities Index for the last
five years. The graph assumes the investment of $100 at December 31, 1998 and
that all dividends were reinvested. The amount of the investment at the end of
each year is shown in the graph and in the table which follows.
Cumulative Total Returns for the Five Years Ended 12/31/03
Line graph inserted here that shows Cumulative Total Returns in
dollars by years 1998-2003, using the data points in the table below.
1998 1999 2000 2001 2002 2003
---- ---- ---- ---- ---- ----
TXU Corp...................................... 100 81 108 121 50 65
S&P 500 Index................................. 100 121 110 97 76 97
S&P 500 Electric Utilities Index.............. 100 84 129 107 91 113
26
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Security ownership of certain beneficial owners at March 15, 2004:
Amount and Nature
Name and Address Of Beneficial Ownership
Title of Class of Beneficial Owner Percent of Class
-------------------- ------------------------------- ------------------------ -------------------
Class A common TXU Corp. 2,062,768 shares 100%
stock, without par Energy Plaza voting and
value, of 1601 Bryan Street investment power
US Holdings Dallas, TX 75201
Class B common TXU US Holdings Investment 39,192,594 shares 100%
stock, without par Company LLC (a) voting and
value, of 1403 Foulk Road investment power
US Holdings Wilmington, DE 19803
(a) A wholly-owned subsidiary of TXU Corp.
Security ownership of management March 15, 2004:
The following lists the common stock of TXU Corp. owned by the
Directors and Executive Officers of US Holdings. The named individuals have sole
voting and investment power for the shares of common stock reported. Ownership
of such common stock by the Directors and Executive Officers, individually and
as a group, constituted less than 1% of the outstanding shares at March 15,
2004. None of the named individuals own any of the preferred stock of US
Holdings or the preferred securities of any subsidiaries of US Holdings.
Number of Shares
--------------------------------------------------------------------------
Name Beneficially Owned Share Units (1) Total
---- ------------------ --------------- -----
T. L. Baker....................... 160,794 30,791 191,585
Brian N. Dickie................... 67,446 56,397 123,843
H. Dan Farell..................... 55,661 21,639 77,300
M. S. Greene...................... 58,232 20,815 79,047
Michael J. McNally................ 178,681 37,254 215,935
Erle Nye.......................... 503,741 95,694 599,435
Eric H. Peterson.................. 77,901 5,626 83,527
R. D. Trimble..................... 23,602 13,067 36,669
C. John Wilder.................... 300,000 1,500,000 (2) 1,800,000
All Directors and Executive
Officers as a group (9)......... 1,426,058 1,781,283 3,207,341
- -----------------
(1) Share units held in deferred compensation accounts under the Deferred
and Incentive Compensation Plan. Although these plans allow such units
to be paid only in the form of cash, investments in such units create
essentially the same investment stake in the performance of TXU Corp.'s
common stock as do investments in actual shares of common stock.
(2) Share units held in accounts established for Mr. Wilder pursuant to his
employment agreement. Such units may be paid in the form of stock or
cash at Mr. Wilder's election. Investments in such units create
essentially the same investment stake in the performance of TXU Corp.'s
common stock as do investments in actual shares of common stock.
27
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None
Item 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
US Holdings has no Audit Committee of its own, but relies upon the TXU
Corp. Audit Committee (Committee). The Committee has adopted a policy relating
to engagement of the TXU Corp.'s independent auditors. The policy provides that
in addition to the audit of the financial statements, related quarterly reviews
and other audit services, Deloitte & Touche LLP may be engaged to provide
non-audit services as described herein. Prior to engagement, all services to be
rendered by the independent auditors must be authorized by the Committee in
accordance with pre-approval procedures which are defined in the policy. The
pre-approval procedures require (i) the annual review and pre-approval by the
Committee of all anticipated audit and non-audit services; and (ii) the
quarterly pre-approval by the Committee of services, if any, not previously
approved and the review of the status of previously approved services. The
Committee may also approve certain on-going non-audit services not previously
approved in the limited circumstances provided for in the SEC rules. All
services performed by the independent auditor were pre-approved.
The policy defines those non-audit services which Deloitte & Touche may
also be engaged to provide as follows: (i) audit related services (e.g. due
diligence related to mergers, acquisitions and divestitures; employee benefit
plan audits; accounting and financial reporting standards consultation; internal
control reviews; and the like); (ii) tax services (e.g. Federal and state tax
returns; regulatory rulings preparation; general tax, merger, acquisition and
divestiture consultation and planning; and the like); and (iii) other services
(e.g. process improvement, review and assurance; litigation and rate case
assistance; general research; and the like). The policy prohibits the engagement
of Deloitte & Touche to provide: (i) bookkeeping or other services related to
the accounting records or financial statements of US Holdings; (ii) financial
information systems design and implementation services; (iii) appraisal or
valuation services, fairness opinions, or contribution-in-kind reports; (iv)
actuarial services; (v) internal audit outsourcing services; (vi) management or
human resource functions; (vii) broker-dealer, investment advisor, or investment
banking services; (viii) legal and expert services unrelated to the audit; and
(ix) any other service that the Public Company Accounting Oversight Board
determines, by regulation, to be impermissible.
Compliance with the Committee's policy relating to the engagement of
Deloitte & Touche will be monitored on behalf of the Committee by TXU Corp.'s
chief internal audit executive. Reports from Deloitte & Touche and the chief
internal audit executive describing the services provided by the firm and fees
for such services will be provided to the Committee no less often than
quarterly.
28
For the years ended December 31, 2003 and 2002, fees billed to US
Holdings by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu
and their respective affiliates were as follows:
2003 2002
------------- --------------
Audit Fees. Fees for services necessary to perform the annual audit,
review Securities and Exchange Commission filings, fulfill statutory and
other attest service requirements, provide comfort letters and consents.. $ 1,839,000 $2,343,000
Audit-Related Fees. Fees for services including employee benefit plan audits,
due diligence related to mergers, acquisitions and divestitures, accounting
consultations and audits in connection with acquisitions, internal control
reviews, attest services that are not required by statute or regulation, and
consultation concerning financial accounting
and reporting standards.................................................. 165,000 243,000
Tax Fees. Fees for tax compliance, tax planning, and tax advice related
to mergers and acquisitions, divestitures, and communications with and
requests for rulings from taxing authorities............................. -- --
All Other Fees. Fees for services including process improvement
reviews, forensic accounting reviews, litigation and rate case
assistance............................................................... 102,000 275,000
----------- -----------
Total.................................................................... $2,106,000 $2,861,000
=========== ===========
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K
Page
----
(a) Documents filed as part of this Report:
Financial Statements (included in Appendix A to this report):
Selected Financial Data ............................................................... A-2
Management's Discussion and Analysis of Financial Condition and
Results of Operations................................................................ A-3
Statement of Responsibility............................................................ A-49
Independent Auditors' Report........................................................... A-50
Statements of Consolidated Income for each of the three years in
the period ended December 31, 2003................................................... A-51
Statements of Consolidated Comprehensive Income for each of the
three years in the period ended December 31, 2003.................................... A-51
Statements of Consolidated Cash Flows for each of the three years
in the period ended December 31, 2003................................................ A-52
Consolidated Balance Sheets, December 31, 2003 and
2002................................................................................. A-53
Statements of Consolidated Shareholders' Equity for each of the
three years in the period ended December 31, 2003.................................... A-54
Notes to Financial Statements.......................................................... A-55
29
The consolidated financial statement schedules are omitted because of
the absence of the conditions under which they are required or because the
required information is included in the consolidated financial statements or
notes thereto.
(b) Reports on Form 8-K filed or furnished since September 30, 2003, are as
follows:
None
(c) Exhibits:
Included in Appendix B to this report.
30
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, TXU US Holdings Company has duly caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized.
TXU US HOLDINGS COMPANY
Date: March 18, 2004 By: /s/ C. JOHN WILDER
----------------------------------------
(C. John Wilder, Chairman of the Board and
Chief Executive)
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of TXU US
Holdings Company and in the capacities and on the date indicated.
Signature Title Date
/s/ C. JOHN WILDER Principal Executive
- ----------------------------------------------------------- Officer and Director March 18, 2004
(C. John Wilder, Chairman of the Board and Chief Executive)
/s/ H. DAN FARELL Principal Financial
- ----------------------------------------------------------- Officer and Director March 18, 2004
(H. Dan Farell, Executive Vice President
and Chief Financial Officer)
/s/ DAVID H. ANDERSON Principal Accounting
- ----------------------------------------------------------- Officer March 18, 2004
(David H. Anderson, Vice President and Controller)
/s/ MICHAEL J. McNALLY Director March 18, 2004
- -----------------------------------------------------------
(Michael J. McNally)
/s/ ERIC H. PETERSON Director March 18, 2004
- -----------------------------------------------------------
(Eric H. Peterson)
31
Appendix A
Supplemental Information to be Furnished with Reports Filed
Pursuant to Section 15(d) of the Act by Registrants Which Have Not Registered
Securities Pursuant to Section 12 of the Act
No annual report, proxy statement, form of proxy or other proxy soliciting
material has been sent to security holders of TXU US Holdings Company during the
period covered by this Annual Report on Form 10-K for the fiscal year ended
December 31, 2003.
32
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
INDEX TO FINANCIAL INFORMATION
December 31, 2003
Page
Selected Financial Data .................................................. A-2
Management's Discussion and Analysis of Financial
Condition and Results of Operations..................................... A-3
Statement of Responsibility............................................... A-49
Independent Auditors' Report.............................................. A-50
Financial Statements:
Statements of Consolidated Income and Comprehensive Income........... A-51
Statements of Consolidated Cash Flows................................ A-52
Consolidated Balance Sheets.......................................... A-53
Statements of Consolidated Shareholders' Equity...................... A-54
Notes to Financial Statements........................................ A-55
A-1
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
SELECTED FINANCIAL DATA
Year Ended December 31,
-----------------------
2003 2002 2001 2000 1999
---- ---- ---- ---- ----
(Millions of Dollars, except ratios)
Total assets -- end of year...................................... $23,493 $24,877 $22,086 $23,277 $20,534
Property, plant and equipment - net -- end of year............... $16,714 $16,436 $16,332 $16,095 $15,945
Capital expenditures.......................................... 706 797 962 771 577
Capitalization -- end of year
Exchangeable subordinated notes (a) .......................... $ -- $ 486 $ -- $ -- $ --
All other long-term debt, less amounts due currently.......... 7,217 6,127 5,819 5,264 4,908
Long-term debt held by subsidiary trusts...................... -- -- -- 876 876
Exchangeable preferred membership interests of TXU Energy (a) 497 -- -- -- --
Preferred stock:
Not subject to mandatory redemption........................ 38 115 115 115 115
Subject to mandatory redemption............................ -- 21 21 21 21
Common stock equity........................................... 6,282 6,587 7,349 7,336 7,147
------- ------- ------- ------- -------
Total.................................................... $14,034 $13,336 $13,304 $13,612 $13,067
======= ======= ======= ======= =======
Capitalization ratios -- end of year
Exchangeable subordinated notes (a)............................ --% 3.6% --% --% --%
All other long-term debt, less amounts due currently........... 51.4 46.0 43.8 38.7 37.6
Long-term debt held by subsidiary trusts....................... -- -- -- 6.4 6.7
Exchangeable preferred membership interests of TXU Energy (a).. 3.5 -- -- -- --
Preferred stock................................................ 0.3 1.0 1.0 1.0 1.0
Common stock equity............................................ 44.8 49.4 55.2 53.9 54.7
----- ----- ------ ------ -------
Total..................................................... 100.0% 100.0% 100.0% 100.0% 100.0%
Embedded interest cost on long-term debt -- end of year (b) 6.6% 6.9% 6.1% 7.5% 7.4%
Embedded distribution cost on long-term debt held by
subsidiary trusts -- end of year.............................. -- -- -- 8.3% 8.4%
Embedded dividend cost on preferred stock -- end of year (c)..... 13.1% 7.5% 7.5% 8.1% 11.0%
Revenues ........................................................ $ 8,582 $ 8,093 $ 7,966 $ 7,564 $ 6,277
Net income available for common stock (d)........................ 655 352 707 777 724
Ratio of earnings to fixed charges............................... 2.62 2.54 3.15 3.09 2.90
Ratio of earnings to fixed charges and preferred dividends....... 2.59 2.47 3.07 3.02 2.83
(a) Exchanged for preferred membership interests in 2003. Amount is presented
net of discount.
(b) Represents the annual interest using year-end rate for variable rate debt
and reflecting the effects of interest rate swaps and amortization of any
discounts, premiums, issuance costs and any deferred gains/losses on
reacquisitions divided by the carrying value of the debt plus or minus the
unamortized balance of any discounts, premiums, issuance costs and
gains/losses on reacquisitions at the end of the year. Includes the effect
of exchangeable subordinated notes in 2002.
(c) Includes the unamortized balance of the loss on reacquired preferred stock
and associated amortization. The embedded dividend cost, excluding the
effects of the loss on reacquired preferred stock is 6.7% for 2002, 2001,
2000 and 1999. Includes the effect of exchangeable preferred membership
interest of subsidiary in 2003.
(d) Net income available for common stock includes a loss on discontinued
operations of $14 million and the cumulative effect of changes in
accounting principles of $58 million in 2003. Net income available for
common stock in 2002 includes a loss on discontinued operations of $49
million and an extraordinary charge of $134 million. 2001 includes a loss
on discontinued operations of $28 million and an extraordinary charge of
$57 million.
Certain previously reported financial statistics have been reclassified to
conform to current classifications.
Prior year periods have been restated to reflect certain operations as
discontinued. (See Note 3 to Financial Statements.)
See Note 2 to Financial Statements for proforma amounts relating to
adoption of SFAS 143.
A-2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
BUSINESS
Use of the term "US Holdings," unless otherwise noted, refers to US
Holdings, a holding company, and/or its consolidated subsidiaries.
US Holdings is a holding company that conducts its operations through its
TXU Energy and Oncor subsidiaries. TXU Energy engages in power production
(electricity generation), retail and wholesale sales of electricity and hedging
and risk management activities. Oncor is engaged in the transmission and
distribution (delivery) of electricity.
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.
Changes in Business
- -------------------
In December 2003, US Holdings finalized a formal plan to sell its
strategic retail services business, which is engaged principally in providing
energy management services. The consolidated financial statements for all years
presented reflect the reclassification of the results of this business as
discontinued operations. (See Note 3 to Financial Statements for more detailed
information about discontinued operations.)
MANAGEMENT'S CHALLENGES AND INITIATIVES
Management Change
- -----------------
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 is in the process of
reviewing the operations of TXU Corp. and formulating strategic initiatives.
This review is expected to take up to six months. Upon completion, TXU Corp.
expects to fully describe the results of the review and subsequent actions
intended to improve the financial performance of its operations.
Areas to be 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
o Non-core business activities
If any new strategic initiatives are undertaken, US Holding's financial
results could be materially affected.
Competitive Markets
- -------------------
In the Texas market, 2003 was the second full year of competitive
activity, and that activity has impacted customer counts and sales volumes. The
area representing the historical service territory prior to deregulation,
largely in north Texas, consisted of approximately 2.8 million consumers
(measured by meter counts) as of year-end of 2003. TXU Energy currently has
approximately 2.4 million customers in that territory and has acquired
approximately 200,000 customers in other competitive areas in Texas. Total
customer counts declined 4% in 2003 and 0.5% in 2002. Retail sales volumes
declined 12% in 2003 and 9% in 2002, reflecting competitive activity in the
business market segment and to a lesser extent in the residential market. While
wholesale sales volumes have increased significantly, gross margins have been
compressed by the loss of the higher-margin retail volumes. TXU Energy intends
to aggressively compete, in terms of price and customer service, in all segments
of the retail market, both within and outside the historical service territory.
In particular, TXU Energy anticipates regaining volumes in the large business
market, reflecting contracting activity in late 2003. Because of the customer
service and marketing costs associated with entering markets outside of the
historical service territory, TXU Energy has experienced operating losses in
these new markets. TXU Energy expects to be profitable in these markets as the
customer base grows and economies of scale are achieved, but uncertainties
remain and objectives may not be achieved.
A-3
Effect of Natural Gas Prices
- ----------------------------
Wholesale electricity prices in the Texas market generally move with the
price of natural gas because marginal demand is met with gas-fired generation
plants. Natural gas prices increased significantly in 2003, but historically the
price has moved up and down due to the effects of weather, industrial demand,
supply availability and other economic factors. Consequently, sales price
management and hedging activities are critical in achieving targeted gross
margins. TXU Energy continues to have price flexibility in the large business
market, and effective January 1, 2004, has price flexibility in the small
business market, including the historical service territory. With respect to
residential customers in the historical service territory, TXU Energy is subject
to regulated "price-to-beat" rates, but such rates can be adjusted up or down
twice a year at TXU Energy's option, subject to approval by the Commission,
based on changes in natural gas prices. The challenge in adjusting these rates
is determining the appropriate timing, considering past and projected movements
in natural gas prices, such that targeted margins can be achieved while
remaining competitive with other retailers who have price flexibility. TXU
Energy increased the price-to-beat rates twice in 2003, and these actions
combined with unregulated price increases and hedging activities essentially
offset higher costs of energy sold as compared to 2002.
In its portfolio management activities, TXU Energy enters into physical
and financial energy-related (power and natural gas) contracts to hedge gross
margins. TXU Energy hedges prices of anticipated power sales against falling
natural gas prices and, to a lesser extent, hedges costs of energy sold against
rising natural gas prices. The results of hedging and risk management activities
can vary significantly from one reporting period to the next as a result of
market price movements on the values of hedging instruments. Such activity
represents an effective management tool to reduce cash gross margin risk over
time. The challenge, among others, with these activities is managing the
portfolio of positions in a market in which prices can move sharply in a short
period of time.
One of TXU Energy's cost advantages, particularly in a time of rising
natural gas prices, is its nuclear-powered and coal/lignite-fired generation
assets. Variable costs of this "base load" generation, which provided
approximately 50% of sales volumes in 2003, have in recent history been, and are
expected to be, less than the costs of gas-fired generation. Consequently,
maintaining the efficiency and reliability of the base load assets is of
critical importance in managing gross margin risk. Completing scheduled
maintenance outages at the nuclear-powered facility on a timely basis, for
example, is a critical management process. Because of the correlation of power
and natural gas prices in the Texas market, structural decreases or increases in
natural gas prices that are sustained over a multi-year period result in a
correspondingly lower or higher value of TXU Energy's base load generation
assets.
Operating Costs and SG&A Expenses
- ---------------------------------
With the transition from a fully regulated environment to competition in
the retail and wholesale electricity markets, US Holdings continues to seek
opportunities to enhance productivity, reduce complexity and improve the
effectiveness of its operating processes. Such efforts are balanced against the
need to maintain the reliability, efficiency and security of its electricity
delivery infrastructure and generation fleet. Cost reduction initiatives have
resulted in lower headcounts, the exiting of marginal business activities and
reduced discretionary spending. Total operating costs and SG&A expenses in TXU
Energy's continuing operations declined $149 million, or 10%, in 2003. These
costs include TXU Corp. corporate expenses allocated to TXU Energy. While upward
cost pressures are expected for competitive sales and marketing initiatives,
customer care and support activities, and employee and retiree benefits,
increasing productivity levels will continue to be a management priority.
A-4
In the regulated Oncor business, upward cost pressures, such as rising
employee benefits expenses, have been mitigated by efficiency enhancements.
Reported total operating and SG&A costs of Oncor were about even compared to
2002, excluding higher transmission fees that are offset by higher directly
related revenues.
Regulated Business
US Holdings' electricity delivery business is subject to regulation by
Texas authorities. The Oncor electricity delivery business provides delivery
services to REPs who sell electricity to retail customers; consequently, Oncor
has no commodity supply or price risk. Oncor operates in a favorable regulatory
environment, as evidenced by a regulatory provision that allows Oncor to
annually update its transmission rates to reflect changes in invested capital.
This provision encourages investment in the transmission system to help ensure
reliability and efficiency by allowing for timely recovery of and return on new
transmission investments. Oncor has only one transmission-related rate case
pending.
A-5
CRITICAL ACCOUNTING POLICIES
US Holdings' significant accounting policies are detailed in Note 1 to
Financial Statements. US Holdings follows accounting principles generally
accepted in the US. In applying these accounting policies in the preparation of
US Holdings' consolidated financial statements, management is required to make
estimates and assumptions about future events that affect the reporting and
disclosure of assets and liabilities at the balance sheet dates and revenue and
expense during the periods covered. The following is a summary of certain
critical accounting policies of US Holdings that are impacted by judgments and
uncertainties and for which different amounts might be reported under a
different set of conditions or using different assumptions.
Financial Instruments and Mark-to-Market Accounting -- US Holdings enters
into financial instruments, including options, swaps, futures, forwards and
other contractual commitments primarily to hedge market risks related to changes
in commodity prices as well as changes in interest rates. These financial
instruments are accounted for in accordance with SFAS 133 as well as, prior to
October 26, 2002, EITF 98-10. The majority of financial instruments entered into
by US Holdings and used in hedging activities are derivatives as defined in SFAS
133.
SFAS 133 requires the recognition of derivatives in the balance sheet, the
measurement of those instruments at fair value and the recognition in earnings
of changes in the fair value of derivatives. This recognition is referred to as
"mark-to-market" accounting. SFAS 133 provides exceptions to this accounting if
(a) the derivative is deemed to represent a transaction in the normal course of
purchasing from a supplier and selling to a customer, or (b) the derivative is
deemed to be a cash flow or fair value hedge. In accounting for cash flow
hedges, derivative assets and liabilities are recorded on the balance sheet at
fair value with an offset in other comprehensive income. Amounts are
reclassified from other comprehensive income to earnings as the underlying
transactions occur and realized gains and losses are recognized in earnings.
Fair value hedges are recorded as derivative assets or liabilities with an
offset to the carrying value of the related asset or liability. Any hedge
ineffectiveness related to cash flow and fair value hedges is recorded in
earnings.
US Holdings documents designated commodity, debt-related and other hedging
relationships, including the strategy and objectives for entering into such
hedge transactions and the related specific firm commitments or forecasted
transactions. US Holdings applies hedge accounting in accordance with SFAS 133
for these non-trading transactions, providing the underlying transactions remain
probable of occurring. Effectiveness is assessed based on changes in cash flows
of the hedges as compared to changes in cash flows of the hedged items. In its
risk management activities, TXU Energy hedges future electricity revenues using
natural gas instruments; such cross-commodity hedges are subject to
ineffectiveness calculations that can result in mark-to-market gains and losses.
Pursuant to SFAS 133, the normal purchase or sale exception and the cash
flow hedge designation are elections that can be made by management if certain
strict criteria are met and documented. As these elections can reduce the
volatility in earnings resulting from fluctuations in fair value, results of
operations could be materially affected by such elections.
Interest rate swaps entered into in connection with indebtedness to manage
interest rate risks are accounted for as cash flow hedges if the swap converts
rates from variable to fixed and are accounted for as fair value hedges if the
swap converts rates from fixed to variable.
EITF 98-10 required mark-to-market accounting for energy-related
contracts, whether or not derivatives under SFAS 133, that were deemed to be
entered into for trading purposes as defined by that rule. The majority of
commodity contracts and energy-related financial instruments entered into by US
Holdings to manage commodity price risk represented trading activities as
defined by EITF 98-10 and were therefore marked-to-market. On October 25, 2002,
the EITF rescinded EITF 98-10. Pursuant to this rescission, only financial
instruments that are derivatives under SFAS 133 are subject to mark-to-market
accounting.
A-6
In June 2002, in connection with the EITF's consensus on EITF 02-3,
additional guidance on recognizing gains and losses at the inception of a
trading contract was provided. In November 2002, this guidance was extended to
all derivatives. As a result, effective in 2003, TXU Energy discontinued
recording mark-to-market gains on inception of energy contracts. See discussion
below in Results of Operations - "Commodity Contracts and Mark-to-Market
Activities."
Mark-to-market accounting recognizes changes in the value of financial
instruments as reflected by market price fluctuations. In the energy market, the
availability of quoted market prices is dependent on the type of commodity
(e.g., natural gas, electricity, etc.), time period specified and location of
delivery. In computing the mark-to-market valuations, each market segment is
split into liquid and illiquid periods. The liquid period varies by region and
commodity. Generally, the liquid period is supported by broker quotes and
frequent trading activity. In illiquid periods, little or no market information
may exist, and the fair value is estimated through market modeling techniques.
For those periods where quoted market prices are not available, forward
price curves are developed based on the available information or through the use
of industry accepted modeling techniques and practices based on market
fundamentals (e.g., supply/demand, replacement cost, etc.). US Holdings does not
recognize income or loss from the illiquid periods unless credible price
discovery exists.
TXU Energy recorded net unrealized losses arising from mark-to-market
accounting, including hedge ineffectiveness, of $100 million and $113 million in
2003 and 2002, respectively. The 2003 amount excludes the cumulative effect of
changes in accounting principles discussed in Note 2 to Financial Statements.
Revenue Recognition -- US Holdings records revenues for retail and
wholesale energy sales and delivery fees under the accrual method. Retail
electric revenues are recognized when the commodity is provided to customers on
the basis of periodic cycle meter readings and include an estimated accrual for
the value of the commodity consumed from the meter reading date to the end of
the period. The unbilled revenue is calculated at the end of the period based on
estimated daily consumption after the meter read date to the end of the period.
Estimated daily consumption is derived using historical customer profiles
adjusted for weather and other measurable factors affecting consumption.
Electricity delivery revenues are recognized when delivery services are provided
to customers on the basis of periodic cycle meter readings and include an
estimated accrual for the delivery fee value of electricity provided from the
meter reading date to the end of the period. Unbilled revenues reflected in
accounts receivable totaled $411 million and $505 million at December 31, 2003
and 2002, respectively.
Realized and unrealized gains and losses from transacting in
energy-related contracts, principally for the purpose of hedging margins on
sales of energy, are reported as a component of revenues. As discussed above
under "Financial Instruments and Mark-to-Market Accounting," recognition of
unrealized gains and losses involves a number of assumptions and estimates that
could have a significant effect on reported revenues and earnings.
Accounting for Contingencies -- The financial results of US Holdings may
be affected by judgments and estimates related to loss contingencies. Accruals
for loss contingencies are recorded when management determines that it is
probable that an asset has been impaired or a liability has been incurred and
that such economic loss can be reasonably estimated. Such determinations are
subject to interpretations of current facts and circumstances, forecasts of
future events and estimates of the financial impacts of such events.
A significant contingency that US Holdings accounts for is the loss
associated with uncollectible trade accounts receivable. The determination of
such bad debts expense is based on factors such as historical write-off
experience, agings of accounts receivable balances, changes in operating
practices, regulatory rulings, general economic conditions and customers'
behaviors. With the opening of the Texas electricity market to competition, many
historical measures used to estimate bad debt experience may be less reliable.
The changing environment, including recent regulatory changes that allow REPs in
their historical service territories to disconnect non-paying customers, and
customer churn due to competitor actions has added a level of complexity to the
estimation process. Bad debt expense totaled $119 million and $160 million for
the years ended December 31, 2003 and 2002, respectively.
A-7
In connection with the opening of the Texas market to competition, the
Texas Legislature established a retail clawback provision intended to incent
affiliated REPs of utilities to actively compete for customers outside their
historical service territories. A retail clawback liability arises unless 40% of
the electricity consumed by residential and small business customers in the
historical service territory is supplied by competing REPs after the first two
years of competition. This threshold was reached for small business customers in
2003, but not for residential customers. The amount of the liability is equal to
the number of such customers retained by TXU Energy as of January 1, 2004, less
the number of new customers from outside the historical service territory,
multiplied by $90. The credit, which will be funded by TXU Energy, will be
applied to delivery fees charged by Oncor to REPs, including TXU Energy, over a
two-year period beginning January 1, 2004. In 2002, TXU Energy recorded a charge
to cost of energy and delivery fees sold of $185 million ($120 million
after-tax) to accrue an estimated retail clawback liability. In 2003, TXU Energy
reduced the liability to $173 million, with a credit to cost of energy sold and
delivery fees of $12 million ($8 million after-tax), to reflect the calculation
of the estimated liability applicable only to residential customers in
accordance with the Settlement Plan.
ERCOT Settlements - ERCOT's responsibilities include the balancing and
settlement of electricity volumes and related ancillary services among the
various participants in the deregulated Texas market. ERCOT settles balancing
energy with market participants through a load and resource imbalance charge or
credit for any differences between actual and scheduled volumes. Ancillary
services and various fees are allocated to market participants based on each
participant's load.
Settlement information is due from ERCOT within two months after the
operating day, and true-up settlements are due from ERCOT within twelve months
after the operating day. The ERCOT settlement process has been delayed several
times to address operational data management problems between ERCOT, the
transmission and distribution service providers and the REPs. These operational
data management issues are related to new processes and systems associated with
opening the ERCOT market to competition, which have continued to improve.
True-up settlements have been received for 2002, but true-up settlements for the
year 2003 are currently scheduled to start on June 1, 2004. All periods continue
to be subject to a dispute resolution process.
As a result of the delay in the ERCOT settlements and the normal time lags
described above, TXU Energy's operating revenues and costs of energy sold
contain estimates for load and resource imbalance charges or credits with ERCOT
and for ancillary services and related fees that are subject to change and may
result in charges or credits impacting future reported results of operations.
The amounts recorded represent the best estimate of these settlements based on
available information. During 2003, TXU Energy recorded a net expense of $20
million to adjust amounts previously recorded for 2002 and 2001 ERCOT
settlements.
Impairment of Long-Lived Assets -- US Holdings evaluates long-lived assets
for impairment whenever indications of impairment exist, in accordance with the
requirement of SFAS 144. One of those indications is a current expectation that
"more likely than not" a long-lived asset will be sold or otherwise disposed of
significantly before the end of its previously estimated useful life. The
determination of the existence of this and other indications of impairment
involves judgments that are subjective in nature and in some cases requires the
use of estimates in forecasting future results and cash flows related to an
asset or group of assets. Further, the unique nature of US Holdings' property,
plant and equipment, which includes a fleet of generation assets using different
fuels and individual plants that have varying utilization rates, requires the
use of significant judgments in determining the existence of impairment
indications and grouping assets for impairment testing.
In 2002, US Holdings recorded an impairment charge of $237 million ($154
million after-tax) for the writedown of two generation plant construction
projects as a result of weaker wholesale electricity market conditions and
reduced planned developmental capital spending. Fair value was determined based
on appraisals of property and equipment. The charge is reported in other
deductions.
A-8
Goodwill and Intangible Assets -- US Holdings evaluates goodwill for
impairment at least annually (as of October 1) in accordance with SFAS No. 142.
The impairment tests performed are based on discounted cash flow analyses. Such
analyses require a significant number of estimates and assumptions regarding
future earnings, working capital requirements, capital expenditures, discount
rate, terminal year growth factor and other modeling factors. No goodwill
impairment has been recognized for consolidated reporting units reflected in
results from continuing operations.
Depreciation -- The depreciable lives of power generation plants are based
on management's estimates/determinations of the plants' economically useful
lives. To the extent that the actual lives differ from these estimates there
would be an impact on the amount of depreciation charged to the financial
statements.
Effective April 1, 2003, the estimates of the depreciable lives of the
Comanche Peak nuclear generating plant and several gas generation plants were
extended to better reflect the useful lives of the assets. At the same time,
depreciation rates were increased on lignite and gas generation facilities to
reflect investments in emissions control equipment. The net impact of these
changes was a reduction in depreciation expense of $37 million ($24 million
after-tax) in 2003.
The Comanche Peak nuclear-powered generation units were originally
estimated to have a useful life of 40 years, based on the life of the operating
licenses granted by the NRC. Over the last several years, the NRC has granted
20-year extensions to the initial 40-year terms for several commercial power
reactors. Based on these extensions and current expectations of industry
practice, the useful life of the Comanche Peak nuclear-powered generation units
is now estimated to be 60 years. TXU Energy expects to file a license extension
request in accordance with timing and other provisions established by the NRC.
Regulatory Assets and Liabilities -- The financial statements of US
Holdings' regulated business, represented by Oncor's operations, reflect
regulatory assets and liabilities under cost-based rate regulation in accordance
with SFAS 71. As a result of the 1999 Restructuring Legislation, application of
SFAS 71 to the generation operations was discontinued in 1999. The assumptions
and judgments used by regulatory authorities continue to have an impact on the
recovery of costs, the rate earned on invested capital and the timing and amount
of assets to be recovered by rates. (See discussion in Note 1 to Financial
Statements under "Regulatory Assets and Liabilities.")
Approximately $1.8 billion in regulatory asset stranded costs arising
prior to the 1999 Restructuring Legislation became subject to recovery through
issuance of transition (securitization) bonds in accordance with the Settlement
Plan with the Commission as described in Note 15 to Financial Statements. As a
result of the final approval of the Settlement Plan in January 2003, US Holdings
recorded an extraordinary loss of $134 million (net of income tax benefit of $72
million) in the fourth quarter of 2002 principally to write down this regulatory
asset. The carrying value of the regulatory asset after the write down
represented the estimated future cash flows to be recovered from REPs, through a
delivery fee surcharge, to service the principal and interest of the bonds. The
carrying value of the regulatory asset is subject to further adjustment, which
would be recorded as an extraordinary item, as the remaining portion
(approximately $790 million) of the securitization bonds will be issued in 2004.
Defined Benefit Pension Plans and Other Postretirement Benefit Plans-- US
Holdings is a participating employer in the defined benefit pension plan
sponsored by TXU Corp. US Holdings 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. See Note 12 for information regarding retirement plans and
other postretirement benefits.
These costs are impacted by actual employee demographics (including age,
compensation levels and employment periods), the level of contributions made to
retiree plans and earnings on plan assets. TXU Corp.'s retiree plan assets are
primarily made up of equity and fixed income investments. Changes made to the
provisions of the plans may also impact current and future benefit costs.
Fluctuations in actual equity market returns as well as changes in general
interest rates may result in increased or decreased benefit costs in future
periods. Benefit costs may also be significantly affected by changes in key
actuarial assumptions, including anticipated rates of return on plan assets and
the discount rates used in determining the projected benefit obligation.
A-9
In accordance with accounting rules, changes in benefit obligations
associated with these factors may not be immediately recognized as costs on the
income statement, but are recognized in future years over the remaining average
service period of plan participants. As such, significant portions of benefit
costs recorded in any period may not reflect the actual level of cash benefits
provided to plan participants. Costs allocated from the plans are also impacted
by movement of employees between participating companies. US Holdings recorded
allocated pension and other postretirement benefits expense of $105 million in
2003, $58 million in 2002 and $31 million in 2001. US Holdings' funding
requirements for these plans were $58 million, $48 million and $36 million in
2003, 2002 and 2001, respectively.
During 2003, key assumptions of the US pension and other postretirement
benefit plans were revised, including decreasing the assumed discount rate in
2003 from 6.75% to 6.25% to reflect current interest rates. The expected rate of
return on pension plan assets remained at 8.5%, but declined to 8.01% from 8.26%
for the other postretirement benefit plan assets.
Based on current assumptions, pension and other postretirement benefits
expense for US Holdings is expected to increase $13 million to approximately
$118 million in 2004, and US Holdings' funding requirements for those plans are
expected to increase $28 million to approximately $86 million.
As a result of the pension plan asset return experience, at December 31,
2002, TXU Corp. recognized a minimum pension liability adjustment as prescribed
by SFAS 87. US Holding's allocated portion of the liability, which totaled $57
million ($37 million after-tax), was recorded as a reduction to shareholders'
equity through a charge to Other Comprehensive Income in 2002. At December 31,
2003, the adjustment to the minimum pension liability reflects a reduction of
$35 million ($23 million after-tax) as a result of improved returns on the plan
assets. The changes in the minimum pension liability do not affect net income.
TXU Corp. has elected not to defer accounting for the Medicare
Prescription Drug, Improvement and Modernization Act of 2003 (the Medicate Act)
as allowed for under FASB Staff Position 106-1. TXU Corp. believes that the plan
in which US Holdings is a participant meets the actuarial equivalency as
required by the Medicare Act and therefore a reduction in future postretirement
benefit costs is expected. Further information related to the impact of the
Medicare Act can be found in the TXU Corp. Form 10-K. The Medicare Act had no
effect on US Holdings' results of operations for 2003, but is expected to reduce
US Holdings' postretirement benefits expense other than pensions by
approximately $22 million in 2004.
RESULTS OF OPERATIONS
The results of operations and the related management's discussion of those
results for all periods presented reflect the discontinuance of certain
operations of US Holdings (see Note 3 to Financial Statements regarding
discontinued operations) and the reclassifications of losses in 2002 and 2001 on
early extinguishments of debt from extraordinary loss to other deductions in
accordance with SFAS 145. (See Note 1 to Financial Statements.)
Accounting Changes - In October 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. Effective
January 1, 2003, non-derivative energy contracts were required to be accounted
for on a settlement basis. SFAS 143, regarding asset retirement obligations,
became effective on January 1, 2003. As a result of the implementation of these
two accounting standards, TXU Energy. recorded a cumulative effect of changes in
accounting principles as of January 1, 2003 of a net charge of $58 million. (See
Note 2 for a discussion of the impacts of these two accounting standards.)
See Note 1 to Financial Statements for discussion of other changes in
accounting standards.
A-10
Consolidated US Holdings
- ------------------------
2003 compared to 2002
Reference is made to comparisons of results by business segment following
the discussion of consolidated results. The business segment comparisons provide
additional detail and quantification of items affecting financial results.
US Holdings' operating revenues increased $489 million, or 6%, to $8.6
billion in 2003. The revenue growth reflected an increase in the TXU Energy
segment of $304 million, or 4%, to $8.0 billion and an increase in the Oncor
segment of $93 million, or 5%, to $2.1 billion. Revenues in the TXU Energy
segment reflected higher retail and wholesale pricing, partially offset by the
effect of a mix shift to lower-price wholesale sales and lower sales volumes.
The growth in revenues in the Oncor segment reflected increased electricity
transmission and distribution tariffs and higher disconnect/reconnect fees.
Consolidated revenue growth also reflected a $92 million reduction in the
intercompany sales elimination, primarily reflecting lower sales by Oncor to TXU
Energy as sales to nonaffiliated REPs increased.
Gross Margin
Year Ended December 31,
--------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------------ ---- -------
Operating revenues........................................ $ 8,582 100% $ 8,093 100%
Cost and expenses:
Cost of energy sold and delivery fees................ 3,627 42% 3,194 40%
Operating costs...................................... 1,398 16% 1,374 17%
Depreciation and amortization related to operating
assets............................................. 655 8% 663 8%
------- ------- -------- ------
Gross margin.............................................. $ 2,902 34% $ 2,862 35%
======= ======= ======== ======
Gross margin is considered a key operating metric as it measures the
effect of changes in sales volumes and pricing versus the variable and fixed
costs of energy sold, whether generated or purchased, as well as the costs to
deliver energy.
The depreciation and amortization expense included in gross margin
excludes $51 million of such expense for the years ended December 31, 2003 and
2002 related to assets that are not directly used in the generation and delivery
of energy.
Gross margin increased $40 million, or 1%, to $2.9 billion in 2003. This
increase reflected growth in the Oncor segment of $29 million, or 3%, to $1.1
billion and an increase in the TXU Energy segment of $12 million, or 1%, to $1.8
billion. The gross margin increase in the Oncor segment was driven by the higher
electricity delivery fees. The TXU Energy segment gross margin was favorably
impacted by $197 million due to regulatory-related retail clawback accrual
adjustments (a $185 million charge, $120 million after-tax, in 2002 and a $12
million credit in 2003). The balance of the TXU Energy segment's gross margin
change reflected a 12% decline in retail sales volumes, partially offset by
lower depreciation expense as described immediately below.
Depreciation and amortization (including amounts shown in the gross margin
table above) decreased $8 million, or 1%, to $706 million in 2003, reflecting a
decrease due to adjusted depreciation rates related to TXU Energy's generation
fleet, partially offset by higher depreciation due to investments in delivery
facilities to support growth and normal replacements of equipment and the start
of amortization of regulatory assets associated with securitization bonds issued
in 2003.
SG&A expense decreased $145 million, or 15%, to $843 million in 2003. The
decrease was driven by the TXU Energy segment and reflected lower staffing and
related administrative expenses arising from cost reduction and productivity
enhancing initiatives and a focus on activities in the Texas market.
A-11
Franchise and revenue-based taxes decreased $35 million, or 9%, to $375
million in 2003 due primarily to a decrease in local gross receipts taxes,
partially offset by increases in property and state franchise taxes. The
decrease in local gross receipts taxes reflects a regulatory change, applicable
to Oncor, in the basis for the calculation from revenue dollars to
kilowatt-hours.
Other income increased $14 million to $52 million in 2003. The 2003 and
2002 periods included $30 million of amortization of a gain on the sale of two
generation plants in 2002. The 2003 period also included gains on the sale of
certain retail business market gas contracts. See Note 18 to Financial
Statements under Other Income and Deductions for additional detail.
Other deductions decreased $229 million to $21 million in 2003, reflecting
a $237 million ($154 million after-tax) writedown in 2002 of an investment in
generation plant construction projects. See Note 18 to Financial Statements
under Other Income and Deductions for additional detail.
Interest income rose $13 million to $19 million in 2003, the increase
primarily reflected interest income on higher cash balances due to actions taken
in late 2002, to ensure ample liquidity, as well as interest received on
restricted cash balances held as collateral for a credit facility.
Interest expense and related charges increased $165 million, or 38%, to
$605 million in 2003. The increase reflected higher average interest rates and
higher average borrowings. Higher average rates reflected replacement of
short-term borrowings with higher rate long-term debt.
The effective income tax rate on income from continuing operations before
extraordinary loss and cumulative effect of changes in accounting principles was
32.1% in 2003 compared to 29.1% in 2002. The increase reflected the effect of
comparable (to 2002) tax benefit amounts of depletion allowances and
amortization of investment tax credits on a higher income base in 2003. (See
Note 11 for an analysis of the effective tax rate.)
Income from continuing operations before extraordinary loss and cumulative
effect of changes in accounting principles increased $188 million, or 35%, to
$732 million in 2003. Earnings in the TXU Energy segment rose $174 million, or
55%, to $493 million in 2003. Results in 2002 included impairment charges
related to generation plant construction projects ($154 million) and accrual of
the retail clawback credit ($120 million). Excluding these items, earnings
declined on gross margin compression due to lower retail sales volumes as well
as higher interest expenses, partially offset by lower SG&A expenses. Earnings
in the Oncor segment rose $13 million, or 5%, to $258 million in 2003,
reflecting higher revenues, partially offset by higher interest, depreciation
and amortization and operating expenses. Net pension and postretirement benefit
costs, reported in operating costs and SG&A expenses, reduced income from
continuing operations by $36 million in 2003 and $20 million in 2002.
The loss from the discontinued strategic retail services operations was
$14 million in 2003 and $49 million in 2002. The decline reflected reductions in
headcount and other SG&A-related expenses. See Note 3 to Financial Statements.
A cumulative effect of changes in accounting principles, representing an
after-tax charge of $58 million in 2003, reflects the impact on commodity
contract mark-to-market accounting from rescission of EITF 98-10 and the
recording of asset retirement obligations under SFAS 143. See Note 2 to
Financial Statements for further discussion.
A-12
Consolidated US Holdings
- ------------------------
2002 compared to 2001
US Holdings' operating revenues increased $127 million, or 2%, to $8.1
billion in 2002. The increase reflected a decline in the Oncor segment of $320
million and an increase in the TXU Energy segment of $287 million, the net
effect of which was more than offset by a lower intercompany sales elimination
between the two segments. The lower elimination reflected the inception of the
Oncor segment providing services to unaffiliated retail electric providers. The
offsetting changes in the segments' revenues reflected certain activities
reported in the Oncor segment in 2001 that are reflected in the TXU Energy
segment's revenues in 2002, due to changes in responsibility for such
activities. Revenues in the TXU Energy segment reflected significantly higher
wholesale sales volumes and the effects of unbundling allocations, partially
offset by the effect of a 9% decline in retail electricity sales volumes,
reflecting the opening of the Texas market to competition.
Gross Margin
Year Ended December 31,
----------------------------------------------
% of % of
2002 Revenue 2001 Revenue
---- ------------ ---- -------
Operating revenues..................................... $ 8,093 100% $ 7,966 100%
Cost and expenses:
Cost of energy sold and delivery fees............. 3,194 40% 3,049 38%
Operating costs................................... 1,374 17% 1,263 16%
Depreciation and amortization related to operating
assets........................................ 663 8% 629 8%
------- ----- -------- ------
Gross margin........................................... $ 2,862 35% $ 3,025 38%
======= ===== ======== ======
The depreciation and amortization expense included in gross margin
excludes $51 million and $4 million of such expense for the years ended
December 31, 2002 and 2001, respectively, related to assets that are not
directly used in the generation and delivery of energy.
Gross margin decreased $163 million, or 5%, to $2.9 billion in 2002. This
decline reflected a $185 million ($120 million after-tax) accrual for
regulatory-related retail clawback and higher operating costs, partially offset
by the net favorable effect of lower average costs of energy sold, higher retail
electricity pricing and lower results from hedging and risk management
activities. Operating costs rose $111 million, or 9%, to $1.4 billion due to
costs of refueling two units, compared to one in 2001, at the nuclear-powered
generation plant, costs associated with a consumer energy efficiency program,
mandated by the Commission, and higher transmission costs paid to other
utilities.
An increase in depreciation and amortization, other than goodwill
(including amounts shown in the gross margin table above), of $81 million, or
13%, to $714 million reflected investments in computer systems to support the
restructuring of the Texas electricity market, expansion of office facilities
and normal growth and replacements of operating facilities.
SG&A expense increased $276 million, or 39%, to $1.0 billion in 2002. The
increase was driven by higher staffing and other administrative expenses
associated with expanded retail sales and wholesale portfolio management
operations, as well as higher bad debt expense, all due largely to the opening
of the Texas electricity market to competition. With the completion of the
transition to competition in Texas, the industry-wide decline in portfolio
management activities and the expected deferral of deregulation of energy
markets in other states, US Holdings initiated several cost savings actions in
2002. Such actions resulted in $31 million ($21 million after-tax) in severance
charges in 2002, which contributed to the increase in SG&A expense.
Franchise and revenue-based taxes decreased $31 million, or 7%, to $410
million in 2002. This decline was due to the effect of lower revenues on which
state and local gross receipts taxes are assessed.
A-13
Other income increased $27 million to $38 million in 2002. The 2002 period
included $32 million of gains on dispositions of property compared to $1 million
in the 2001 period. See Note 18 to Financial Statements for additional detail.
Other deductions decreased $19 million to $250 million in 2002. The 2002
period included a $237 million ($154 million after-tax) writedown of an
investment in generation plant construction projects. The 2001 period included
$149 million charge related to the early extinguishment of debt, a recoverable
charge of $73 million related to the regulatory restructuring of the Texas
electricity market, a $22 million nonrecoverable regulatory asset write-off
pursuant to a regulatory order and losses on sales of property of $8 million.
Interest income declined $33 million, or 85%, to $6 million in 2002, due
largely to the recovery of under-collected fuel revenue on which interest income
had been accrued under regulation in Texas in 2001.
Interest expense and related charges decreased $33 million, or 7%, to $440
million in 2002, reflecting a $65 million decrease due to lower interest rates,
partially offset by a $24 million increase due to higher debt levels and a $10
million increase due to lower capitalized interest.
Goodwill amortization of $15 million in 2001 ceased in 2002, reflecting
the discontinuance of goodwill amortization pursuant to the adoption of SFAS No.
142.
The effective income tax rate on income from continuing operations before
extraordinary loss was 29.1% in 2002 compared to 30.9% in 2001 The decrease
reflected the effect of comparable (to 2001) tax benefit amounts of depletion
allowances and amortization of investment tax credits on a lower income base in
2002. (See Note 11 to Financial Statements for an analysis of the effective tax
rate.)
Income from continuing operations before extraordinary loss decreased $258
million, or 32%, to $544 million in 2002. This performance reflected a decline
of $258 million in the TXU Energy segment, driven by higher SG&A expenses and
the accrual of regulatory-related retail clawback of $120 million. Net pension
and postretirement benefit costs reduced income from continuing operations by
$31 million in 2002 and $14 million in 2001.
The loss from the discontinued strategic retail services business was $49
million in 2002 and $28 million in 2001. Results in 2002 included approximately
$10 million after-tax in asset writedowns.
Extraordinary loss in 2002 includes a $134 million (net of income tax
benefit of $72 million) regulatory-related charge, principally to write down
regulatory assets subject to recovery through the issuance of the securitization
bonds to be issued in the future in accordance with the Settlement Plan. The
extraordinary loss in 2001 of $57 million (net of $63 million income tax
benefit) reflects net charges related to the settlement with the Commission to
resolve all major open issues related to the transition to deregulation. (See
Note 15 to Financial Statements for further information concerning the
settlement of deregulation issues.)
Commodity Contracts and Mark-to-Market Activities
- -------------------------------------------------
The table below summarizes the changes in commodity contract assets and
liabilities for the years ended December 31, 2003, 2002 and 2001. The net
changes in these assets and liabilities, excluding "cumulative effect of change
in accounting principle" and "other activity" as described below, represent the
net effect of recording unrealized gains/(losses) under mark-to-market
A-14
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.
2003 2002 2001
---- ---- ----
Balance of net commodity contract assets at beginning of year. $316 $371 $27
Cumulative effect of change in accounting principle (1)....... (75) - -
Settlements of positions included in the opening balance (2) . (145) (225) (54)
Unrealized mark-to-market valuations of positions held at end of
period (3) ................................................. 9 153 368
Other activity (4)............................................ 3 17 30
----- ------ ------
Balance of net commodity contract assets at end of year ...... $ 108 $316 $371
===== ==== ====
(1) Represents a portion of the pre-tax cumulative effect of the
rescission of EITF 98-10 (see Note 2 to Financial Statements).
(2) Represents unrealized mark-to-market valuations of these positions
recognized in earnings as of the beginning of the period.
(3) There were no significant changes in fair value attributable to
changes in valuation techniques. Includes $14 million in
origination gains recognized in 2002 related to nonderivative
wholesale contracts.
(4) Includes initial values of positions involving the receipt or
payment of cash or other consideration, such as option premiums,
the amortization of such values and the exit of certain retail gas
activities in 2003. Also includes $71 million of contract-related
liabilities to Enron Corporation reclassified to other current
liabilities in 2002. 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 that are reflected in changes in cash flow
hedges and other derivative assets and liabilities. The total net effect of
recording unrealized gains and losses under mark-to-market accounting is
summarized as follows (excludes cumulative effect of change in accounting
principle):
2003 2002 2001
---- ---- ----
Unrealized gains/(losses) in commodity contract portfolio..... $(136) $(72) $314
Ineffectiveness gains/(losses) related to cash flow hedges.... 36 (41) 4
----- ----- -----
Total unrealized gains/(losses)............................... $(100) $(113) $318
===== ===== ====
These amounts are included in the "hedging and risk management activities"
component of revenues as presented in the TXU Energy segment data.
As a result of guidance provided in EITF 02-3, US Holdings has not
recognized origination gains on energy contracts in 2003. TXU Energy recognized
origination gains on retail sales contracts of $40 million in 2002 and $88
million in 2001. Because of the short-term nature of these contracts, a portion
of these gains would have been recognized on a settlement basis in the year the
origination gain was recorded.
Maturity Table -- Of the net commodity contract asset balance above at
December 31, 2003, the amount representing unrealized mark-to-market net gains
that have been recognized in current and prior years' earnings is $121 million.
The offsetting net liability of $13 million included in the December 31, 2003
balance sheet is comprised principally of amounts representing current and prior
years' net receipts of cash or other consideration, including option premiums,
associated with contract positions, net of any amortization. The following table
presents the unrealized mark-to-market balance at December 31, 2003, scheduled
by contractual settlement dates of the underlying positions.
A-15
Maturity dates of unrealized net mark-to-market balances at December 31, 2003
-----------------------------------------------------------------------------
Maturity Maturity in
less than Maturity of Maturity of Excess of
Source of fair value 1 year 1-3 years 4-5 years 5 years Total
- -------------------- ------- --------- --------- ------- -----
Prices actively quoted........... $ 36 $ 12 $(2) $ - $ 46
Prices provided by other
external sources............. 21 53 1 (2) 73
Prices based on models........... (2) 4 - - 2
---- ---- --- --- -----
Total............................ $ 55 $ 69 $(1) $(2) $ 121
==== ==== === === =====
Percentage of total fair value... 45% 57% -% (2)% 100%
As the above table indicates, essentially all of the unrealized
mark-to-market valuations at December 31, 2003 mature within three years. This
is reflective of the terms of the positions and the methodologies employed in
valuing positions for periods where there is less market liquidity and
visibility. The "prices actively quoted" category reflects only exchange traded
contracts with active quotes available through 2008. 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.
A-16
TXU Energy
- ----------
Financial Results
- -----------------
Year Ended December 31,
-----------------------------------------
2003 2002 2001*
---- ---- -----
Operating revenues....................................... $7,995 $ 7,691 $ 7,404
Costs and expenses:
Cost of energy sold and delivery fees............... 5,124 4,783 4,800
Operating costs..................................... 691 701 671
Depreciation and amortization, other than goodwill.. 409 450 395
Selling, general and administrative expenses........ 636 775 311
Franchise and revenue-based taxes .................. 124 120 14
Other income ....................................... (48) (33) (2)
Other deductions.................................... 22 254 196
Interest income..................................... (8) (10) (38)
Interest expense and related charges ............... 323 215 224
Goodwill amortization............................... - - 14
------ ------- -------
Total costs and expenses........................ 7,273 7,255 6,585
------ ------- -------
Income from continuing operations before income taxes,
extraordinary loss and cumulative effect of
changes in accounting principles..................... 722 436 819
Income tax expense....................................... 229 117 242
------ ------- -------
Income from continuing operations before extraordinary
loss and cumulative effect of changes in
accounting principles................................ $ 493 $ 319 $ 577
====== ======= =======
- -----------------
The TXU Energy segment includes the electricity generation, wholesale and
retail energy sales, and hedging and risk management operations of TXU
Energy, operating principally in the competitive Texas market.
* Data for 2001 is included above for the purpose of providing historical
financial information about the TXU Energy segment after giving effect to the
restructuring transactions and unbundling allocations described in Note 19 to
Financial Statements. Allocations reflected in 2001 data did not necessarily
result in amounts reported in individual line items that are comparable to
actual results in 2002 and 2003. Had TXU Energy existed as a separate segment in
entity, its results of operations and financial position could have differed
materially from those reflected above.
A-17
TXU Energy
- ----------
Operating Data
- --------------
Year Ended December 31,
----------------------------------
2003 2002 2001(a)(b)
---- ---- ----------
Operating statistics - volumes:
Retail electricity (GWh)
Residential.............................................. 35,981 37,692
Small business(c)........................................ 12,986 15,907
Large business and other................................. 30,955 36,982
-------- --------
Total retail electricity............................... 79,922 90,581 99,151
======== ======== ========
Wholesale electricity (GWh)................................. 37,362 29,649 6,409
======== ======== ========
Production and purchased power (GWh):
Nuclear and lignite/coal (base load)..................... 59,028 54,738 57,828
Gas/oil and purchased power.............................. 63,319 70,321 52,925
-------- -------- --------
Total production and purchased power .................. 122,347 125,059 110,753
======== ======== ========
Customer counts:
Retail electricity customers (end of period & in thousands -
based on number of meters):
Residential.............................................. 2,207 2,302
Small business........................................... 321 333
Large business and other................................. 69 78
-------- --------
Total retail electricity customers..................... 2,597 2,713 2,728
======== ======== ========
Operating revenues (millions of dollars):
Retail electricity revenues:
Residential.............................................. $ 3,311 $ 3,108 $ 3,255
Business and other ...................................... 3,173 3,415 3,837
-------- -------- --------
Total retail electricity revenues...................... 6,484 6,523 7,092
Wholesale electricity revenues ............................. 1,274 857 96
Hedging and risk management activities...................... 18 142 358
Other revenues.............................................. 219 169 (142)
-------- -------- --------
Total operating revenues............................... $ 7,995 $ 7,691 $ 7,404
======== ======== ========
Weather (average for service territory) (d)
Percent of normal:
Cooling degree days.................................... 103.1% 99.8% 100.5%
Heating degree days.................................... 94.0% 102.0% 97.5%
- ---------------------------------
(a)See footnote on previous page.
(b)Retail volume and customer count data for 2001 not available by class.
(c)Customers with demand of less than 1 MW annually.
(d)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).
A-18
TXU Energy
- ----------
2003 compared to 2002
- ---------------------
Effective with reporting for 2003, results for the TXU Energy segment
exclude expenses incurred by the US Holdings parent company in order to present
the segment on the same basis as the results of the business are evaluated by
management. Prior year amounts are presented on this revised basis.
Operating revenues increased $304 million, or 4%, to $8.0 billion in 2003.
Total retail and wholesale electricity revenues rose $378 million, or 5%, to
$7.8 billion. This growth reflected higher retail and wholesale pricing,
partially offset by the effects of a mix shift to lower-price wholesale sales
and a 2% decline in total sales volumes. Retail electricity revenues decreased
$39 million, or 1%, to $6.5 billion reflecting a $768 million decline
attributable to a 12% drop in sales volumes, driven by the effect of competitive
activity in the business market, largely offset by a $730 million increase due
to higher pricing. Higher prices 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 declined 4% from year-end 2002. Wholesale
electricity revenues grew $417 million, or 49%, to $1.3 billion reflecting a
$223 million increase attributable to a 26% rise in sales volumes and a $194
million increase due to the effect of increased natural gas prices on wholesale
prices. Higher wholesale electricity sales volumes reflected a partial shift in
the customer base from retail to wholesale services, particularly in the
business segment.
Net gains from hedging and risk management activities, which are reported
in revenues and include both realized and unrealized gains and losses, declined
$124 million to $18 million in 2003. Changes in these results reflect market
price movements on commodity contracts entered into to hedge gross margin; the
comparison to 2002 also reflects a decline in activities in markets outside of
Texas. 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 $100 million in 2003 and $113 million in 2002. The majority of TXU 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 $39 million in revenues since that date. The increase in other
revenues of $50 million to $219 million in 2003 was driven by this change.
Gross Margin
Year Ended December 31,
--------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ------------ ---- -------
Operating revenues..................................... $ 7,995 100% $ 7,691 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 5,124 64% 4,783 62%
Operating costs................................... 691 9% 701 9%
Depreciation and amortization related to generation
assets........................................ 370 4% 409 5%
------- ----- ------- -------
Gross margin........................................... $ 1,810 23% $ 1,798 24%
======= ===== ======= =======
The depreciation and amortization expense reported in the gross margin
amounts above excludes $39 million and $41 million of such expense for the years
ended December 31, 2003 and 2002, respectively, related to assets that are not
directly used in the generation of electricity.
Gross margin increased $12 million, or 1%, to $1.8 billion in 2003. The
gross margin comparison was favorably impacted by $197 million due to
regulatory-related retail clawback accrual adjustments (a $185 million charge,
$120 million after-tax, in 2002 and a $12 million credit in 2003), as described
in Note 15 to Financial Statements, and $49 million in lower operating costs and
depreciation and amortization. Adjusting for these effects, margin declined $234
million, driven by the effect of lower retail sales volumes. The combined effect
of higher costs of energy sold and lower results from hedging and risk
management activities was essentially offset by higher sales prices. Higher
costs of energy sold were driven by higher natural gas prices, but were
mitigated by increased sourcing of retail and wholesale sales demand from TXU
Energy's base load (nuclear-powered and coal-fired) generation plants. Base load
supply of sales demand increased by four percentage points to 50% in 2003. The
balance of sales demand in 2003 was met with gas-fired generation and purchased
power.
A-19
Operating costs decreased $10 million, or 1%, to $691 million in 2003. The
decline reflected $20 million due to one scheduled outage for nuclear generation
unit refueling and maintenance in 2003 compared to two in 2002 and $15 million
from various cost reduction initiatives, partially offset by $27 million in
higher employee benefits and insurance costs. Depreciation and amortization
related to generation assets decreased $39 million, or 10%, to $370 million. Of
this decline, $37 million represented the effect of adjusted depreciation rates
related to the generation fleet effective April 2003. The adjusted rates reflect
an extension in the estimated average depreciable life of the nuclear generation
facility's assets of approximately 11 years (to 2041) to better reflect its
useful life, partially offset by higher depreciation rates for lignite and gas
facilities to reflect investments in emissions equipment made in recent years.
A decrease in depreciation and amortization (including amounts shown in
the gross margin table above) of $41 million, or 9%, to $409 million in 2003 was
driven by the adjusted depreciation rates related to the generation fleet as
discussed above.
SG&A expenses declined $139 million, or 18%, to $636 million in 2003.
Lower staffing and related administrative expenses contributed approximately $95
million to the decrease, reflecting cost reduction and productivity enhancing
initiatives and a focus on activities in the Texas market. Lower SG&A expenses
also reflected a $40 million decline in bad debt expense. In the retail
electricity business, the effect of enhanced credit and collection activities
was largely offset by increased write-offs arising from disconnections now
allowed under new regulatory rules and increased churn of non-paying customers.
The decrease in bad debts expense primarily reflected the wind down of retail
gas (business customer supply) activities outside of Texas and the recording of
reserves in 2002.
Other income increased $15 million to $48 million in 2003. Other income in
both periods included $30 million of amortization of a gain on the sale of two
generation plants in 2002. The 2003 period also included a $9 million gain on
the sale of contracts related to retail gas activities outside of Texas.
Other deductions decreased $232 million to $22 million in 2003, reflecting
a $237 million ($154 million after-tax) writedown in 2002 of an investment in
two generation plant construction projects. In addition, both periods include
several individually immaterial items.
Interest expense and related charges increased $108 million, or 50%, to
$323 million in 2003. The increase reflects $108 million due to higher average
interest rates resulting in part from the replacement of short-term borrowings
with higher-rate long-term debt. An $11 million full-year effect of the
amortization of the discount on the exchangeable subordinated notes issued in
2002 (subsequently exchanged by TXU Energy for exchangeable preferred membership
interests), was largely offset by the effect of lower average borrowings.
The effective income tax rate increased to 31.7% in 2003 from 26.8% in
2002. The increase was driven by the effect of comparable (to 2002) tax benefit
amounts of depletion allowances and amortization of investment tax credits on a
higher income base in 2003. (See Note 11 for analysis of the effective tax
rate.)
Income from continuing operations before extraordinary loss and cumulative
effect of changes in accounting principles increased $174 million, or 55%, to
$493 million in 2003. Results in 2002 included an impairment charge related to
generation plant construction projects and accrual of the retail clawback credit
of $154 million after-tax and $120 million after-tax, respectively. Excluding
these items, earnings declined on gross margin compression due to lower retail
sales volumes as well as higher interest expense, partially offset by lower SG&A
expenses. Net pension and postretirement benefit costs reduced net income by $36
million in 2003 and by $20 million in 2002.
A-20
TXU Energy
- ----------
2002 compared to 2001
- ---------------------
The TXU Energy segment's operating revenues increased $287 million, or 4%,
to $7.7 billion in 2002. Total retail and wholesale electricity revenues rose
$192 million, or 3%, to $7.4 billion driven by higher wholesale volumes.
Wholesale electric revenues increased $761 million to $857 million, reflecting
the substantial increase in wholesale sales volumes due to the opening of the
Texas market to competition. Retail electric revenues declined $569 million, or
8%, to $6.5 billion, reflecting a $613 million reduction due to lower volumes
partially offset by a $44 million increase due to higher average pricing. The
price variance reflects a shift in customer mix, partially offset by the effect
of lower rates. A 9% decline in overall retail electric sales volumes was
primarily due to the effects of increased competitive activity in the small
business and large business market. Year-end residential electricity customer
counts, reflecting losses in the historical service territory and gains in new
territories due to competition, were about even with the prior year. The
increase in revenues also reflects certain revenues and related retail and
generation expenses that were the responsibility of the Energy Delivery segment
in 2001, but are included in Energy revenues in 2002.
Net gains from hedging and risk management activities, which are reported
in revenues and include both realized and unrealized gains and losses, declined
$216 million to $142 million in 2002. Changes in these results reflect market
price movements on commodity contracts entered into to hedge gross margin.
Results from these activities included net unrealized losses of $113 million in
2002 and net unrealized gains of $318 million in 2001 arising from
mark-to-market accounting.
Gross Margin
Year Ended December 31,
---------------------------------------------
% of % of
2002 Revenue 2001 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 7,691 100% $ 7,404 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 4,783 62% 4,800 65%
Operating costs................................... 701 9% 671 9%
Depreciation and amortization related to generation
assets........................................ 409 5% 391 5%
------- ------ ------- -------
Gross margin........................................... $ 1,798 24% $ 1,542 21%
======= ====== ======= =======
The depreciation and amortization expense included in gross margin
excludes $41 million and $4 million of such expense for 2002 and 2001,
respectively, related to assets that are not directly used in the generation of
electricity. In addition, the 2001 period had goodwill amortization of $14
million.
Gross margin increased $256 million, or 17%, to $1.8 billion in 2002. The
increase was driven by the net favorable effect of lower average costs of energy
sold, higher retail pricing and lower results from hedging and risk management
activities. Higher gross margin also reflected significant growth in wholesale
electricity sales volumes in the newly deregulated ERCOT market, largely offset
by the effect of lower retail electricity volumes. Gross margin in 2002 was
negatively affected by the accrual of $185 million ($120 million after-tax) for
regulatory-related retail clawback, which is reported in cost of energy sold and
delivery fees. Operating costs rose $30 million, or 4%, to $701 million
primarily due to the costs of refueling two units, compared to one in 2001, at
the nuclear-powered generation plant.
An increase in depreciation and amortization, other than goodwill
(including amounts shown in the gross margin table above), of $55 million, or
14%, to $450 million was primarily due to investments in computer systems
required to operate in the newly deregulated market and expansion of office
facilities.
A-21
An increase in SG&A expenses of $464 million, or 149%, to $775 million
reflected the effect of retail customer support costs and bad debt expense of
approximately $150 million that were the responsibility of the Energy Delivery
segment in 2001. The increase in SG&A expenses also reflected $199 million in
higher staffing and other administrative costs, related to expanded retail sales
operations and hedging activities, and higher bad debt expense of $90 million,
all due largely to the opening of the Texas electricity market to competition.
With the completion of the transition to competition in Texas, the industry-wide
decline in portfolio management activities, and the expected deferral of
deregulation of energy markets in other states, TXU Energy initiated several
cost savings initiatives in 2002. Such actions resulted in $31 million in
severance charges in 2002, which contributed to the increase in SG&A expense.
Franchise and revenue-based taxes rose $106 million to $120 million due to
state gross receipts taxes that were the responsibility of the Oncor segment in
2001. Effective in 2002, state gross receipts taxes related to electricity
revenues are an expense of the TXU Energy segment, while local gross receipts
taxes are an expense of the Oncor segment.
Other income increased by $31 million to $33 million, reflecting
amortization of $30 million of a gain on the sale in 2002 of two generation
plants.
Other deductions increased by $58 million to $254 million, reflecting a
$237 million ($154 million after-tax) writedown in 2002 of an investment in two
generation plant construction projects. Amounts in 2001 included $149 million
($97 million after-tax) in losses on the early extinguishment of debt under the
debt restructuring and refinancing plan pursuant to the requirements of the 1999
Restructuring Legislation, a $22 million regulatory asset write-off pursuant to
a regulatory order and $18 million in various asset writedowns.
Interest income declined by $28 million, or 74%, to $10 million primarily
due to the recovery of under-collected fuel revenue on which interest income had
been accrued under regulation in 2001.
Interest expense and other charges decreased $9 million, or 4%, to $215
million reflecting lower average debt levels, partially offset by higher rates
and a decrease in capitalized interest.
The effective tax rate decreased to 26.8% in 2002 from 29.5% in 2001. The
decrease was driven by the effect of comparable (to 2001) tax benefit amounts of
depletion allowances and amortization of investment tax credits on a lower
income base in 2002.
Income from continuing operations before extraordinary loss and cumulative
effect of changes in accounting principles decreased $258 million, or 45%, to
$319 million in 2002. The decline was driven by an increase in SG&A expenses and
higher franchise and revenue-based taxes, partially offset by the improved gross
margin (net of the $120 million effect of the retail clawback accrual). The $154
million effect of the generation plant construction project writedown was
partially offset by the $97 million effect of losses on early extinguishment of
debt in 2001. Net pension and postretirement benefit costs reduced net income by
$20 million in 2002 and $12 million in 2001.
A-22
Oncor
- -----
Financial Results
- -----------------
Year Ended December 31,
-----------------------------------------
2003 2002 2001*
---- ---- -----
Operating revenues........................................... $2,087 $1,994 $ 2,314
Costs and expenses:
Operating costs.......................................... 709 676 594
Depreciation and amortization, other than goodwill....... 297 264 238
Selling, general and administrative expenses............. 207 213 376
Franchise and revenue-based taxes ....................... 250 272 427
Other income ............................................ (8) (9) (9)
Other deductions......................................... -- -- 73
Interest income ......................................... (52) (49) --
Interest expense and related charges .................... 300 265 267
Goodwill amortization.................................... -- -- 1
------ ------ -------
Total costs and expenses............................. 1,703 1,632 1,967
------ ------ -------
Income before income taxes and extraordinary loss............ 384 362 347
Income tax expense........................................... 126 117 119
------ ------ -------
Income before extraordinary loss............................. $ 258 $ 245 $ 228
====== ====== =======
- ------------------------
The Oncor segment includes the electricity transmission and distribution
business of Oncor, which is subject to regulation by Texas authorities.
* Data for 2001 is included above for the purpose of providing historical
financial information about the Oncor segment after giving effect to the
restructuring transactions and allocations described in Note 15 to Financial
Statements. Allocations reflected in 2001 data did not necessarily result in
amounts reported in individual line items that are comparable to actual
results in 2003 and 2002. Had Oncor existed as a separate entity in 2001,
its results of operations and financial position could have differed
materially from those reflected above.
A-23
Oncor
- -----
Operating Data
- --------------
Year Ended December 31,
----------------------------------
2003 2002 2001(a)
---- ---- -------
Operating statistics:
Electric energy delivered - volumes (GWh) (b)................... 101,810 102,481 99,139
Electricity distribution points of delivery - based on number of
meters (end of period and in thousands) (c)..................... 2,932 2,909 2,844
Operating revenues (millions of dollars):
Electricity transmission and distribution:
Affiliated (TXU Energy).................................... $ 1,489 $ 1,586 $ 2,314
Non-affiliated............................................. 598 408 -
------- ------- -------
Total operating revenues................................ $ 2,087 $ 1,994 $ 2,314
======= ======= =======
- --------------------------
(a) See footnote on previous page.
(b) 2002 data revised
(c) Includes lighting sites, primarily guard lights, for which TXU Energy is
the REP but are not included in TXU Energy's customer count. Such sites
totaled 100,901 in 2003, 105,987 in 2002 and 124,916 in 2001.
Oncor
- -----
2003 compared to 2002
- ---------------------
Oncor's operating revenues increased $93 million, or 5%, to $2.1 billion
in 2003. Higher tariffs provided $56 million of this increase, reflecting
transmission rate increases approved in 2003 ($37 million) and delivery fee
surcharges associated with the issuance of securitization bonds in August 2003
($19 million). (See Note 15 to Financial Statements.) The balance of the revenue
growth reflected $26 million in increased disconnect/reconnect fees, reflecting
disconnections initiated by REP's under new regulatory rules and increased
consumer switching due to competitive activity, and $10 million from increased
pricing to certain business consumers due to higher peak demands in 2003. The
increase in the non-affiliated component of Oncor's revenues reflects
competitive activity in the historical service territory. Delivered electricity
volumes were about even with 2002.
Gross Margin
Year Ended December 31,
------------------------------------------
% of % of
2003 Revenue 2002 Revenue
---- ---------- ---- -------
Operating revenues........................................ $ 2,087 100% $ 1,994 100%
Costs and expenses:
Operating costs...................................... 709 34% 676 34%
Depreciation and amortization related to transmission
and distribution assets.......................... 285 14% 254 13%
------- ----- ------- -----
Gross margin.............................................. $ 1,093 52% $ 1,064 53%
======= ===== ======= =====
The depreciation and amortization expense included in gross margin
excludes $12 million and $10 million of such expense for the years ended
December 31, 2003 and 2002, respectively, related to assets that are not
directly used in the delivery of energy.
A-24
Gross margin increased $29 million, or 3%, to $1.1 billion in 2003. The
increase reflected the benefit of higher electricity delivery tariffs, partially
offset by increased operating costs and depreciation and amortization. The
increase in operating costs of $33 million, or 5%, to $709 million reflects $22
million in higher electricity transmission costs paid to other utilities and $8
million in higher pension and other postretirement benefit costs. The increase
in depreciation and amortization of $31 million, or 12%, to $285 million
reflects $11 million in higher depreciation due to investments in delivery
facilities to support growth and normal replacements of equipment and $19
million in amortization of regulatory assets associated with the issuance of
securitization bonds in August 2003. The effect on revenues of the delivery fee
surcharges associated with the issuance of securitization bonds is offset by the
related amortization expense.
SG&A expenses decreased $6 million, or 3%, to $207 million in 2003 due
primarily to lower outside services and consulting expenses arising from cost
reduction initiatives implemented in late 2002.
Franchise and revenue-based taxes declined $22 million, or 8%, to $250
million in 2003 due to the full implementation of a regulatory change in the
basis for the calculation of local gross receipts taxes from revenue dollars to
kilowatt-hours.
Interest income increased $3 million, or 6%, to $52 million in 2003
reflecting a $15 million increase in the reimbursement from the TXU Energy
segment for higher carrying costs on regulatory assets (see discussion of higher
average interest rates below) and a $3 million increase in investment income,
partially offset by $15 million less interest on the excess mitigation credit
note receivable from TXU Energy due to principal payments. (See Note 15 to
Financial Statements.)
Interest expense and related charges rose by $35 million, or 13%, to $300
million in 2003. The increase reflected a $48 million impact of higher average
interest rates and a $2 million impact of higher average borrowings, partially
offset by $15 million less interest credited to REPs related to the excess
mitigation credit. The change in average interest rates reflected the
refinancing of affiliate borrowings with higher rate long-term debt issuances.
The effective income tax rate was 32.8% in 2003 compared to 32.3% in 2002.
There were no significant unusual items impacting the effective rates.
Income from continuing operations before extraordinary loss and cumulative
effect of changes in accounting principles increased $13 million, or 5%, to $258
million in 2003, reflecting higher revenues, partially offset by higher
operating expenses and higher interest expense. Net pension and postretirement
benefit costs reduced net income by $19 million in 2003 and $11 million in 2002.
Oncor
- -----
2002 compared to 2001
- ---------------------
Operating revenues decreased $320 million, or 14%, to $2.0 billion in
2002. Revenues in 2001 included amounts associated with generation and retail
expenses that were the responsibility of the Oncor segment, but in 2002 such
revenues and expenses were the responsibility of the TXU Energy segment.
Excluding the impact of such revenues in 2001, Oncor's revenues rose 3% on a 6%
increase in electricity volumes delivered. Because the fees to REPs for their
large business customers are fixed for specified ranges of volumes, changes in
distribution volumes do not necessarily result in comparable changes in reported
revenues.
A-25
Gross Margin
Year Ended December 31,
--------------------------------------------
% of % of
2002 Revenue 2001 Revenue
---- --------- ---- -------
Operating revenues........................................ $ 1,994 100% $ 2,314 100%
Cost and expenses:
Operating costs....................................... 676 34% 594 26%
Depreciation and amortization (related to transmission
and distribution assets)............................. 254 13% 238 10%
------- ----- ------- ------
Gross margin.............................................. $ 1,064 53% $ 1,482 64%
======= ===== ======= ======
The depreciation and amortization expense included in gross margin
excludes $10 million of such expense for the year ended December 31, 2002,
related to assets that are not directly used in the delivery of energy.
Gross margin decreased $418 million, or 28% to $1.1 billion in 2002. The
decrease reflects the impact of revenues allocated to the Oncor segment in 2001,
as discussed above, and higher operating costs in 2002. The increase in
operating costs of $82 million, or 14%, to $676 million primarily reflects costs
associated with a consumer energy efficiency program, mandated by the
Commission, and higher transmission costs paid to other utilities.
Depreciation and amortization, other than goodwill (including amounts
shown in the gross margin table above), increased $26 million, or 11%, to $264
million. The increase reflected investments in computer systems to support the
restructuring of the Texas electricity market, as well as normal growth and
replacements of delivery facilities.
SG&A expenses decreased by $163 million, or 43%, to $213 million due
primarily to lower bad debt expense and customer support costs of approximately
$150 million, as the retail sales function is reflected in the TXU Energy
segment in 2002. In addition, information technology costs were higher in 2001
due to system changes made in preparation of unbundling the delivery business
from the generation and retail operations.
Franchise and revenue-based taxes decreased $155 million, or 36%, to $272
million in 2002 due to state gross receipts taxes that are reported in the TXU
Energy segment in 2002. Effective in 2002, local gross receipts taxes related to
electricity revenue are an expense of the Oncor segment while state gross
receipts taxes are an expense of the TXU Energy segment.
Other deductions decreased by $73 million reflecting a recoverable charge
in 2001 of $73 million related to regulatory restructuring of the Texas
electricity market.
Interest income of $49 million in 2002 reflected the reimbursement,
effective in 2002, from the TXU Energy segment for carrying costs on regulatory
assets.
Interest expense and other charges declined by $2 million, or 1%, to $265
million. The decline reflected $25 million due to lower average debt levels,
largely offset by $21 million in interest expense credited to REPs related to
the excess mitigation credit and a $2 million decrease in capitalized interest.
Goodwill amortization of $1 million in 2001 ceased, reflecting the
discontinuance of goodwill amortization pursuant to the adoption of SFAS No.
142.
The effective tax rate was 32.3% in 2002 compared to 34.3% in 2001. The
decline reflected nonrecurring regulatory-driven adjustments recorded in 2001
relating to prior years.
Income before extraordinary loss increased $17 million, or 7%, to $245
million, driven by the declines in SG&A expenses and franchise and revenue-based
taxes, as well as higher interest income, partially offset by lower gross
margin. Net pension and postretirement benefit costs reduced net income by $11
million in 2002 and $2 million in 2001.
A-26
COMPREHENSIVE INCOME -- Continuing Operations
Cash flow hedge activity reported in other comprehensive income from
continuing operations included:
Year Ended December 31,
-------------------------------
2003 2002 2001
---- ---- ----
Cash flow hedge activity (net of tax):
Net change in fair value of hedges - gains/(losses):
Commodities............................................... $ (138) $ (96) $ 16
Financing - interest rate hedges.......................... -- (88) --
------- ------- -------
(138) (184) 16
Losses realized in earnings (net of tax):
Commodities............................................... 162 16 1
Financing - interest rate hedges.......................... 6 2 --
------- ------- -------
168 18 1
Net income(loss) effect of cash flow hedges reported
in other comprehensive income............................. $ 30 $ (166) $ 17
======= ======= =======
US Holdings has historically used, and expects to continue to use,
derivative financial instruments that are highly effective in offsetting future
cash flow volatility in energy commodity prices and interest rates. The amounts
included in accumulated other comprehensive income are expected to offset the
impact of rate or price changes on forecasted transactions. Amounts in
accumulated other comprehensive income include (i) the value of the cash flow
hedges (for the effective portion), based on current market conditions, and (ii)
the value of dedesignated and terminated cash flow hedges at the time of such
dedesignation, less amortization, providing the transaction that was hedged is
still probable. The effects of the hedge will be recorded in the statement of
income as the hedged transactions are actually settled.
Other comprehensive income also included adjustments related to minimum
pension liabilities. Minimum pension liability adjustments were a gain of $35
million ($23 million after-tax) in 2003, and losses of $57 million ($37 million
after-tax) and $1 million ($1 million after-tax) in 2002 and 2001, respectively.
The gain in 2003 reflected the impact of improved returns on plan assets. The
minimum pension liability represents the difference between the excess of the
accumulated benefit obligation over the plans' assets and the liability
reflected in the balance sheet. The recording of the liability did not affect US
Holdings' financial covenants in any of its credit agreements.
US Holdings adopted SFAS 133 effective January 1, 2001, and recorded a $1
million charge to other comprehensive income to reflect the fair value of
derivatives effective as cash flow hedges at transition.
See also Note 14 to Financial Statements.
FINANCIAL CONDITION
LIQUIDITY AND CAPITAL RESOURCES
US Holdings expects to satisfy its liquidity needs from existing cash
balances, cash flows from operations, advances from affiliates, renewal of
existing credit facilities, successful remarketing of mandatorily tendered
securities, issuance of additional securities and dispositions of non-strategic
assets.
A-27
Cash Flows -- Cash flows provided by operating activities for the year
ended December 31, 2003 were $2.0 billion compared to $1.3 billion and $1.8
billion for the years ended December 31, 2002 and 2001, respectively. The
principal driver of the $665 million increase in 2003 was favorable working
capital (accounts receivable, accounts payable and inventories) changes of $704
million, which primarily reflects the effect of billing and collection delays in
2002, due to data compilation and reconciliation issues among ERCOT and the
market participants in the newly deregulated market, and includes $100 million
in increased funding under the accounts receivable sale program.
The decrease in cash flows in 2002 from 2001 of $502 million reflected the
effect of a return in 2001 of $227 million in margins deposits related to
hedging and risk management activities (in exchange for letters of credit) and
lower cash earnings (net income adjusted for the significant noncash items
identified in the statement of cash flows). The net unfavorable change in
working capital of $403 million in 2002 was comparable to 2001.
Cash flows used in financing activities were $1.9 billion in 2003 compared
to cash flows provided by financing activities of $774 million in 2002. The
activity in 2003 reflected use of operating cash flows and cash on hand to
reduce short and long-term borrowings. Net cash used in issuances and repayments
of borrowings, including advances from affiliates, totaled $888 million in 2003
compared to cash provided of $1.7 billion in 2002. Cash distributions to TXU
Corp. and common stock repurchases totaled $11 billion in 2003 and $927 million
in 2002. As a result of the unbundling of US Holdings, there were also
substantial issuances and repayments of long-term debt and retirements of equity
securities in 2001. Cash flows used in financing activities were $795 million in
2001, which included a net $709 million in repurchases of common stock and a
capital contribution from TXU Corp.
Cash flows used in investing activities totaled $712 million, $608 million
and $991 million during 2003, 2002 and 2001, respectively. Capital expenditures,
including nuclear fuel, were $750 million in 2003, $848 million in 2002 and $1.0
billion in 2001. Capital expenditures, including nuclear fuel, are expected to
total $855 million in 2004. Proceeds from asset sales in 2002 totaled $447
million and reflected the sale of the Handley and Mountain Creek power
plants in the Dallas-Fort Worth area. Acquisitions in 2002 included $36 million
for a cogeneration and wholesale production business in New Jersey. Other
investing activities in 2002 included $137 million for terminations of
out-of-the-money cash flow hedges, primarily reflecting declines in interest
rates.
Depreciation and amortization expense reported in the statement of cash
flows exceeds the amount reported in the statement of income by $69 million for
2003. This difference reflected $62 million of amortization of nuclear fuel,
which is reported as cost of energy sold in the statement of income consistent
with industry practice, and $7 million of amortization of regulatory assets,
which is reported as operating costs in the statement of income.
Financing Activities
- --------------------
Over the next twelve months, US Holdings and its subsidiaries will need to
fund ongoing working capital requirements and maturities of debt. US Holdings
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.
A-28
Long-Term Debt Activity -- During the year ended December 31, 2003, US
Holdings and its subsidiaries issued, redeemed, reacquired or made scheduled
principal payments on long-term debt as follows:
Issuances Retirements
--------- -----------
Oncor:
First mortgage bonds............................. $ -- $ 663
Medium term notes................................ -- 15
Transition Bonds................................. 500 --
TXU Energy:
Fixed rate senior notes.......................... 1,250 72
Pollution control revenue bonds.................. 567 637
Other long-term debt............................. 3 --
US Holdings
Other long-term debt............................. -- 4
------ ------
Total............................................ $2,320 $1,391
====== ======
See Notes 7, 8, 9 and 10 to Financial Statements for further detail of
debt issuance and retirements, financing arrangements, preferred securities and
capitalization.
Regulatory Asset Securitization -- The Settlement Plan approved by the
Commission provides for the issuance of securitization bonds in the aggregate
principal amount of $1.3 billion to recover regulatory asset stranded costs.
Oncor issued $500 million of the bonds in August of 2003. In addition,
approximately $790 million is expected to be issued in the first half of 2004.
The proceeds will be used by Oncor to retire debt and repurchase equity. Because
the bond principal and interest payments are secured by the collection of
delivery fee surcharges by Oncor, the $1.3 billion in debt is excluded from US
Holdings' and Oncor's capitalization by credit rating agencies.
Credit Facilities - At December 31, 2003, TXU Corp. and its US
subsidiaries had credit facilities totaling $2.8 billion and expiring in 2005
and 2008, of which $2.3 billion was unused. These credit facilities support
issuances of letters of credit and are available to Oncor and TXU Energy for
borrowings. See Note 7 to Financial Statements for details of arrangements.
Exchangeable Preferred Membership Interests -- In July 2003, TXU Energy
exercised its right in a noncash transaction, to exchange its $750 million 9%
Exchangeable Subordinated Notes due November 22, 2012 for exchangeable preferred
membership interests with identical economic and other terms. These securities
are exchangeable for TXU Corp. common stock at an exchange price of $13.1242 per
share. The market price of TXU Corp. common stock on December 31, 2003 was
$23.72. Any exchange of these securities into common stock would result in a
proportionate write-off of the related unamortized discount as a charge to
earnings. If all the securities had been exchanged into common stock on December
31, 2003, TXU Energy would have recognized a pre-tax charge of $253 million.
Registered Financing Arrangements -- US Holdings may issue and sell
additional debt and equity securities as needed, including issuances of up to
$25 million of cumulative preferred stock and up to an aggregate of $924 million
of additional cumulative preferred stock, debt securities and/or preferred
securities of subsidiary trusts, all of which are currently registered with the
Securities and Exchange Commission for offering pursuant to Rule 415 under the
Securities Act of 1933.
Capitalization -- The capitalization ratios of US holdings at December 31,
2003, consisted of long-term debt (less amounts due currently) of 51.4%,
exchangeable preferred membership interests (net of unamortized discount balance
of $253 million) of 3.5%, preferred stock of 0.3% and common stock equity of
44.8%.
A-29
Oncor's cash distributions may take the legal form of common stock share
repurchases or the payment of dividends on outstanding shares of its common
stock. The form of the distributions is primarily determined by current and
forecasted levels of retained earnings as well as state tax implications. The
common stock share repurchases made subsequent to January 1, 2002 are cash
distributions to US Holdings that for financial reporting purposes have been
recorded as a return of capital. Any future cash distributions to US Holdings
will be reported (i) as a return of capital if made through repurchases or (ii)
as a dividend if so declared by the board of directors. Any future common stock
share repurchases will reduce the amount of Oncor's equity, but will not change
US Holdings' 100% ownership of Oncor.
Short-term Borrowings -- At December 31, 2003, US Holdings had outstanding
short-term borrowings consisting of advances from affiliates of $691 million. At
December 31, 2002, outstanding short-term bank borrowings were $1.8 billion and
advances from affiliates were $787 million. Weighted average interest rates on
short-term borrowings were 2.92% and 2.44% at December 31, 2003 and 2002,
respectively.
Sale of Receivables -- TXU Corp. has established an accounts receivable
securitization program. The activity under this program is accounted for as a
sale of accounts receivable in accordance with SFAS 140. Under the program, US
subsidiaries of TXU Corp. (originators) sell trade accounts receivable to TXU
Receivables Company, a consolidated wholly-owned bankruptcy remote direct
subsidiary of TXU Corp., which sells undivided interests in the purchased
accounts receivable for cash to special purpose entities established by
financial institutions. 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 US
Holdings under the program in 2003 totaled $547 million and $447 million in
2002. The increase of $100 million primarily reflects billing and collection
delays in 2002 due to data compilation and reconciliation issues among ERCOT and
the market participants in the newly deregulated market. See Note 7 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 $806 million and $1.5
billion at December 31, 2003 and 2002, respectively. The decline reflects
repayments of borrowings.
Credit Ratings of TXU Corp. and its US Subsidiaries -- The current credit
ratings for TXU Corp., US Holdings and certain of its US subsidiaries are
presented below:
TXU Corp. US Holdings Oncor TXU Energy
--------- ----------- ----- ----------
(Senior Unsecured) (Senior Unsecured) (Secured) (Senior Unsecured)
S&P BBB- BBB- BBB BBB
Moody's Ba1 Baa3 Baa1 Baa2
Fitch BBB- BBB- BBB+ BBB
Moody's currently maintains a negative outlook for TXU Corp. and a stable
outlook for US Holdings, TXU Energy and Oncor. Fitch currently maintains a
stable outlook for each such entity. S&P currently maintains a negative outlook
for each such entity.
These ratings are investment grade, except for Moody's rating of TXU
Corp.'s senior unsecured debt, which is one notch below investment grade.
A rating reflects only the view of a rating agency, and is not a
recommendation to buy, sell or hold securities. Any rating can be revised upward
or downward at any time by a rating agency if such rating agency decides that
circumstances warrant such a change.
Financial Covenants, Credit Rating Provisions and Cross Default
Provisions -- The terms of certain financing arrangements of US Holdings and its
subsidiaries contain financial covenants that require maintenance of specified
fixed charge coverage ratios, shareholders' equity to total capitalization
ratios and leverage ratios and/or contain minimum net worth covenants. TXU
Energy's exchangeable preferred membership interests also limit its incurrence
of additional indebtedness unless a leverage ratio and interest coverage test
are met on a pro forma basis. As of December 31, 2003, US Holdings and its
subsidiaries were in compliance with all such applicable covenants.
A-30
Certain financing and other arrangements of US Holdings 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 US Holdings, including some of the credit facilities
discussed above, contain terms pursuant to which the interest rates charged
under the agreements may be adjusted depending on the credit ratings of US
Holdings or its subsidiaries.
Credit Rating Covenants
- -----------------------
TXU Energy has provided a guarantee of the obligations under TXU Corp.'s
lease (approximately $130 million at December 31, 2003) for its headquarters
building. In the event of a downgrade of TXU Energy's credit rating to below
investment grade, a letter of credit would need to be provided within 30 days of
any such ratings decline.
TXU Energy has entered into certain commodity contracts and lease
arrangements that in some instances give the other party the right, but not the
obligation, to request TXU Energy to post collateral in the event that its
credit rating falls below investment grade.
Based on its current commodity contract positions, if TXU Energy were
downgraded below investment grade by any specified rating agency, counterparties
would have the option to request TXU Energy to post additional collateral of
approximately $145 million.
In addition, TXU Energy has a number of other contractual arrangements
where the counterparties would have the right to request TXU Energy to post
collateral if its credit rating was downgraded below investment grade by all
three rating agencies. The amount TXU Energy would post under these transactions
depends in part on the value of the contracts at that time. As of December 31,
2003, based on current market conditions, the maximum TXU Energy would post for
these transactions is $247 million. Of this amount, $228 million relates to one
specific counterparty.
TXU Energy is also the obligor on leases aggregating $161 million. Under
the terms of those leases, if TXU Energy's credit rating were downgraded to
below investment grade by any specified rating agency, TXU Energy could be
required to sell the assets, assign the leases to a new obligor that is
investment grade, post a letter of credit or defease the leases.
ERCOT also has rules in place to assure adequate credit worthiness for
parties that schedule power on the ERCOT System. Under those rules, if TXU
Energy's credit rating were downgraded to below investment grade by any
specified rating agency, TXU Energy could be required to post collateral of
approximately $32 million.
Cross Default Provisions
- ------------------------
Certain financing arrangements of US Holdings contain provisions that
would result in an event of default if there were a failure under other
financing arrangements to meet payment terms or to observe other covenants that
would result in an acceleration of payments due. Such provisions are referred to
as "cross default" provisions.
A default by US Holdings or any subsidiary thereof on financing
arrangements of $50 million or more would result in a cross default under the
$1.4 billion US Holdings five-year revolving credit facility, the $400 million
US Holdings credit facility and $30 million of TXU Mining senior notes (which
have a $1 million cross default threshold).
A-31
A default by TXU Energy or Oncor or any subsidiary thereof in respect of
indebtedness in a principal amount in excess of $50 million would result in a
cross default for such party under the TXU Energy/Oncor $450 million revolving
credit facility. Under this credit facility, a default by TXU Energy or any
subsidiary thereof would cause the maturity of outstanding balances under such
facility to be accelerated as to TXU Energy, but not as to Oncor. Also, under
this credit facility, a default by Oncor or any subsidiary thereof would cause
the maturity of outstanding balances under such facility to be accelerated as to
Oncor, but not as to TXU Energy.
A default by TXU Corp. on indebtedness of $50 million or more would result
in a cross default under the new $500 million five-year revolving credit
facility.
A default or similar event under the terms of the TXU Energy exchangeable
preferred membership interests that results in the acceleration (or other
mandatory repayment prior to the mandatory redemption date) of such security or
the failure to pay such security at the mandatory redemption date would result
in a default under TXU Energy's $1.25 billion senior unsecured notes.
TXU Energy has entered into certain mining and equipment leasing
arrangements aggregating $118 million that would terminate upon the default of
any other obligations of TXU Energy owed to the lessor. In the event of a
default by TXU Mining on indebtedness in excess of $1 million, a cross default
would result under the $31 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.
TXU Energy enters into energy-related contracts, the master forms of which
contain provisions whereby an event of default would occur if TXU Energy were to
default under an obligation in respect of borrowings in excess of thresholds
stated in the contracts, which thresholds vary.
TXU Corp. and its subsidiaries have other arrangements, including interest
rate swap agreements and leases with cross default provisions, the triggering of
which would not result in a significant effect on liquidity.
Long-Term Contractual Obligations and Commitments -- The following table
summarizes the contractual cash obligations of US Holdings for each of the
periods presented (see Notes 8, 9 and 16 to Financial Statements for additional
disclosures regarding terms of these obligations). Because of the new disclosure
requirements, this table includes commitment amounts not previously disclosed.
More
Less One to Three to Than
Than One Three Five Five
Contractual Cash Obligations Year Years Years Years
---------------------------- ---- ----- ----- -----
Long-term debt and preferred membership interest -
principal and interest/dividends.................... $ 752 $1,180 $1,488 $12,816
Operating leases and capital lease obligations (a)... 73 152 153 479
Purchase obligations(b).............................. 2,349 1,255 545 502
Other liabilities on the balance sheet -
Pensions and other postretirement liabilities --
plan contributions (c)........................... 86 182 174 86
------ ------ ----- -------
Total contractual cash obligations.................. $3,260 $2,769 $2,360 $13,883
====== ====== ====== =======
--------------------------
(a) Includes short-term non-cancelable leases.
(b) Amounts presented for variable priced contracts assumed the year end 2003
price remained in effect for all periods except where contractual price
adjustment or index-based prices were specified.
(c) Projections of cash contributions to qualified pension and other
postretirement benefit plans for the years 2004 - 2009.
The following contractual obligations were excluded from the purchase
obligations disclosure in the table above:
(1) individual contracts that have an annual cash requirement of less than
$1 million. (However, multiple contracts with one counterparty that are
individually less than $1 million have been aggregated.)
(2) contracts that are cancelable without payment of a substantial
cancellation penalty.
(3) employment contracts with management.
A-32
Guarantees-- See Note 16 to Financial Statements for details of guarantees
Investing Activities
- --------------------
In April 2002, TXU Energy acquired a cogeneration and wholesale energy
production business in New Jersey for $36 million in cash. The acquisition
included a 122 megawatt (MW) combined-cycle power production facility and
various contracts, including electric supply and gas transportation agreements.
The acquisition was accounted for as a purchase business combination, and its
results of operations are reflected in the consolidated financial statements
from the acquisition date.
In May 2002, TXU Energy acquired a 260 MW combined-cycle power generation
facility in northwest Texas through a settlement agreement which dismissed a
lawsuit previously filed related to the plant, and included a nominal cash
payment. TXU Energy previously purchased all of the electrical output of this
plant under a long-term contract.
In April 2002, TXU Energy completed the sale of two electricity generation
plants in the Dallas-Fort Worth area with total capacity of 2,334 MW for $443
million in cash. Concurrent with the sale, TXU Energy entered into a tolling
agreement to purchase power during the summer months through 2006. The terms of
the tolling agreement include above-market pricing, representing a fair value
liability of $190 million. A pretax gain on the sale of $146 million, net of the
effects of the tolling agreement, was deferred and is being recognized in other
income during summer months over the five-year term of the tolling agreement.
Both the value of the tolling agreement and the deferred gain are reported in
other liabilities in the balance sheet. The amount of the gain recognized in
other income in 2003 was approximately $30 million.
US Holdings may pursue potential investment opportunities if it concludes
that such investments are consistent with its business strategies and will
dispose of nonstrategic assets to allow redeployment of resources into faster
growing opportunities in an effort to enhance the long-term return to its
shareholders.
Future Capital Expenditures -- Capital expenditures, including nuclear
fuel, are estimated at approximately $855 million for 2004, substantially all of
which are for major repairs and organic growth of existing operations. Of this
amount, approximately 62% is planned for the Oncor segment, and 38% for the TXU
Energy segment.
OFF BALANCE SHEET ARRANGEMENTS
See discussion above under "Sale of Receivables" and in Note 7 to
Financial Statements.
COMMITMENTS AND CONTINGENCIES
Consistent with industry practices, TXU Energy has decided to replace the
four steam generators in one of the two generation units of the Comanche Peak
nuclear plant in order to maintain the operating efficiency of the unit. An
agreement for the manufacture and delivery of the equipment was completed in
October 2003, and delivery is scheduled for late 2006. Estimated project capital
requirements, including purchase and installation, are $175 million to $225
million. Cash outflows are expected to occur in 2004 through 2007, with the
significant majority after 2004.
See Note 16 to Financial Statements for a discussion of other commitments
and contingencies, including guarantees.
A-33
REGULATION AND RATES
Information 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
Company LP to energy industry publications. The request seeks information for
the period from January 1, 1999 to the present. TXU Corp. has cooperated with
the CFTC, and is in the process of completing its response to such information
request. TXU Corp. believes that TXU Portfolio Management Company LP was not
engaged in any reporting of price or volume information that would in any way
justify any action by the CFTC.
1999 Restructuring Legislation and Settlement Plan -- On December 31,
2001, US Holdings filed the Settlement Plan with the Commission. It resolved all
major pending issues related to US Holdings' transition to electricity
competition pursuant to the 1999 Restructuring Legislation. The Settlement Plan
does not remove regulatory oversight of Oncor's business nor does it eliminate
TXU Energy's price-to-beat rates and related fuel adjustments. The Settlement
Plan became final and nonappealable in January 2003. See Note 15 to Financial
Statements for the major elements of the Settlement Plan, the most significant
of which on a go-forward basis are the retail clawback credit and the issuance
of securitization bonds to recover regulatory asset stranded costs.
Price-to-Beat Rates - Under the 1999 Restructuring Legislation, TXU Energy
is required to continue to charge a "price-to-beat" rate established by the
Commission to residential customers (and to offer, along with other pricing
alternatives, this rate to small business customers) in the historical service
territory. The 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. TXU
Energy increased its price-to-beat rate in March and August of 2003.
Wholesale market design - In August 2003, the Commission adopted a rule
that, if fully implemented, would alter the wholesale market design in ERCOT.
The rule requires ERCOT: o to use a stakeholder process to develop a new
wholesale market model; o to operate a voluntary day-ahead energy market; o to
directly assign all congestion rents to the resources that caused the
congestion; o to use nodal energy prices for resources; o to provide information
for energy trading hubs by aggregating nodes; o to use zonal prices for loads;
and o to provide congestion revenue rights (but not physical rights).
Under the rule, the proposed market design and associated cost-benefit
analysis is to be filed with the Commission by November 1, 2004 and is to be
implemented by October 1, 2006. TXU Energy is currently unable to predict the
cost or impact of implementing any proposed change to the current wholesale
market design.
Transmission Rates -- In May 2003, the Commission approved an increase in
Oncor's wholesale transmission tariffs (rates) charged to distribution utilities
that became effective immediately. In March and August 2003 and March 2004, the
Commission approved increases in the transmission cost recovery component of
Oncor's distribution rates charged to REPs (including TXU Energy). The combined
effect of these four increases in both the transmission and distribution rates
is an estimated $62 million of incremental revenues to Oncor on an annualized
basis. With respect to the impact on US Holdings' consolidated results, the
higher distribution rates result in reduced margin on TXU Energy's sales to
those retail customers with pricing that does not provide for recovery of higher
delivery fees, principally price-to-beat customers.
On March 3, 2004, Oncor filed an annual request for interim update of its
wholesale transmission rates. Oncor requested a total annualized revenue
increase of $14 million effective April 7, 2004.
A-34
Summary -- Although US Holdings cannot predict future regulatory or
legislative actions or any changes in economic and securities market conditions,
no changes are expected in trends or commitments, other than those discussed in
this report, which might significantly alter its basic financial position,
results of operations or cash flows.
QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
Market risk is the risk that US Holdings may experience a loss in value as
a result of changes in market conditions such as commodity prices and interest
rates, which US Holdings is exposed to in the ordinary course of business. US
Holdings' exposure to market risk is affected by a number of factors, including
the size, duration and composition of its energy and financial portfolio, as
well as volatility and liquidity of markets. US Holdings enters into financial
instruments such as interest rate swaps to manage interest rate risks related to
its indebtedness, as well as exchange traded, over the counter contracts and
other contractual commitments to manage commodity price risk in its portfolio
management activities.
RISK OVERSIGHT
TXU Energy's portfolio management operation manages the market, credit and
operational risk of the unregulated energy business within limitations
established by senior management and in accordance with TXU Energy's overall
risk management policies. Market risks are monitored daily by risk management
groups that operate and report independently of the portfolio management
operations, utilizing industry accepted practices and analytical methodologies.
These techniques measure the risk and change in value of the portfolio of
contracts and the hypothetical effect on this value from changes in market
conditions and include, but are not limited to, Value at Risk (VaR)
methodologies.
TXU Corp. has a corporate risk management organization that is headed by a
chief risk officer. The chief risk officer, through his designees, enforces the
VaR limits by region, including the respective policies and procedures to ensure
compliance with such limits and evaluates the risks inherent in the various
businesses of TXU Corp. and their associated transactions. Key risk control
activities include, but are not limited to, credit review and approval,
operational and market risk measurement, validation of transactions, portfolio
valuation and daily portfolio reporting, including mark-to-market valuation, VaR
and other risk measurement metrics.
In connection with Mr. Wilder's review of operations, as discussed above
under Management Change, TXU Energy has engaged a consulting firm to review its
portfolio management activities. The review, which commenced in March 2004, will
cover governance and risk policies, the control environment and management
processes. The purpose of the review is primarily to identify opportunities, if
any, to improve the effectiveness of portfolio management operations.
COMMODITY PRICE RISK
US Holdings is subject to the inherent risks of market fluctuations in the
price of electricity, natural gas and other energy-related products marketed and
purchased. US Holdings actively manages its portfolio of owned generation
assets, fuel supply and retail sales load to mitigate the near-term impacts of
these risks on its results of operations. US Holdings, as well as any
participant in the market, cannot manage the long-term value impact of
structural declines or increases in natural gas, power and oil prices and spark
spreads (differences between the market price of electricity and its cost of
production).
In managing energy price risk, US Holdings enters into short- and
long-term physical contracts, financial contracts that are traded on exchanges
and over-the-counter, and bilateral contracts with customers. Speculative
trading activities represent a small fraction of the portfolio management
process. The portfolio management operation continuously monitors the valuation
of identified risks and adjusts the portfolio based on current market
conditions. Valuation adjustments or reserves are established in recognition
that certain risks exist until full delivery of energy has occurred,
counterparties have fulfilled their financial commitments and related financial
instruments have either matured or are closed out.
A-35
US Holdings strives to use consistent assumptions regarding forward market
price curves in evaluating and recording the effects of commodity price risk.
One measure of commodity price risk is the effect of a change in natural
gas prices on operating results. For every $0.50 per million British thermal
units (Btu) reduction in natural gas prices, there would be a $250 million
reduction in annual pre-tax earnings assuming sales prices of electricity
declined accordingly, no hedges were in place and other non-price conditions
were unchanged. This effect would be mitigated in the near-term by the impact of
regulatory mechanisms that affect the timing and frequency of price-to-beat rate
changes, as well as the contractual nature of revenues related to large business
customers. Further, hedging positions in place would partially offset the
near-term effect of a decline in natural gas prices. The near-term and
longer-term effects of lower gas prices would also depend on competitors'
pricing actions and US Holdings' actions to reduce operating and SG&A costs. TXU
Energy's base load power production costs would be largely unaffected by a
decline in gas prices. A $0.50 move in gas prices represents a change of
approximately 10% in the current forward price.
To supplement the discussion of sensitivities of commodity price risk, VaR
and related measures are presented below. The value of TXU Energy's long-term
asset portfolio cannot be easily extrapolated under conventional VaR
methodologies. Because of the correlation of power and natural gas prices in the
Texas market, structural decreases or increases in natural gas prices that are
sustained over a multi-year period result in a correspondingly lower or higher
value of TXU Energy's base load generation assets.
VaR Methodology -- A VaR methodology is used to measure the amount of
market risk that exists within the portfolio under a variety of market
conditions. The resultant VaR produces an estimate of a portfolio's potential
for loss given a specified confidence level and considers among other things,
market movements utilizing standard statistical techniques given historical and
projected market prices and volatilities. Stress testing of market variables is
also conducted to simulate and address abnormal market conditions.
The use of this method requires a number of key assumptions, such as use
of (i) an assumed confidence level; (ii) an assumed holding period (i.e. the
time necessary for management action, such as to liquidate positions); and (iii)
historical estimates of volatility and correlation data.
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.
December 31, December 31,
2003 2002
---- ----
Period-end MtM VaR................................ $ 15 $ 23
Average Month-end MtM VaR (year-to-date) ......... $ 25 $ 38
A-36
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 load and all contractual positions (the
portfolio assets). The Portfolio VaR for TXU Energy represents a ten year view
of owned assets based on the nature of its particular market. 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.
December 31, December 31,
2003 2002
---- ----
Period-end Portfolio VaR............................. $199 $144
Average Month-end Portfolio VaR (a).................. $181 N/A
(a) Comparable information on an average VaR basis is not available for
the full year 2002.
Other Risk Measures -- The metrics appearing below provide information
regarding the effect of changes in energy market conditions on earnings and cash
flow of TXU Energy.
Earnings at Risk (EaR) -- EaR measures the estimated potential loss of
expected pre-tax 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.
December 31, December 31,
2003 2002
---- ----
EaR ...................................... $ 15 $ 28
CFaR ..................................... $ 67 $178
A-37
INTEREST RATE RISK
The table below provides information concerning US Holdings' financial
instruments as of December 31, 2003 and 2002, that are sensitive to changes in
interest rates. The weighted average rate is based on the rate in effect at the
reporting date. US Holdings has entered into interest rate swaps under which it
has agreed to exchange the difference between fixed-rate and variable-rate
interest amounts calculated with reference to specified notional principal
amounts at dates that generally coincide with interest payments. Capital leases
and the effects of unamortized premiums and discounts and fair value hedges on
long-term debt are excluded from the table. See Note 8 to Financial Statements
for a discussion of changes in debt obligations.
Expected Maturity Date
----------------------------------------------
2003 2002
There- 2003 Fair 2002 Fair
2004 2005 2006 2007 2008 After Total Value Total Value
---- ---- ---- ---- ---- ----- ----- ----- ----- -----
Long-term debt
(including current
maturities)
Fixed rate (a) $ 248 $ 163 $ 42 $ 254 $ 297 $6,074 $7,078 $8,660 $ 6,113 $ 6,159
Average interest rate 6.75% 5.86% 3.15% 4.98% 5.92% 6.59% 6.47% - 6.55% -
Variable rate - - - - - $ 396 $ 396 396 $ 434 $ 434
Average interest rate - - - - - 1.24% 1.24% - 1.46% -
Preferred stock of
subsidiary subject to
mandatory redemption
Fixed rate - - - - - - - - $ 21 $ 15
Average interest - - - - - - - - 6.69% -
rate
Exchangeable preferred
membership interests
Fixed rate - - - - - $ 750 $ 750 $1,580 $ 750 $ 1,076
Average interest - - - - - 9.00% 9.00% - 9.00% -
rate
Interest rate swaps
(notional amounts)
Fixed to variable $ - $ - $ - $ - $ - $ 500 $ 500 $ 10 $ - $ -
Average pay rate - - - - - 3.31% 3.31% - - -
Average receive rate - - - - - 7.00% 7.00% - - -
- -------------------------
(a) Reflects the maturity date and not the remarketing date for certain debt
which is subject to mandatory tender for remarketing prior to maturity. See
Note 8 to Financial Statements for details concerning long-term debt subject
to mandatory tender for remarketing.
(b) Amounts for 2002 were included in long-term debt as exchangeable debt.
CREDIT RISK
Credit risk relates to the risk of loss associated with non-performance by
counterparties.
Credit Exposure -- US Holdings' gross exposure to credit risk as
of December 31, 2003 was $2.2 billion, representing trade accounts receivable
(net of allowance of uncollectible accounts receivable of $53 million), as well
as commodity contract assets and other derivative assets that arise primarily
from hedging activities.
A-38
A large share of gross assets subject to credit risk represents accounts
receivable from the retail sale of electricity to residential and small business
customers. The risk of material loss (after consideration of allowances) from
non-performance from these customers is unlikely based upon historical
experience. Allowances for uncollectible accounts receivable are established for
the potential loss from non-payment by these customers based on historical
experience and market or operational conditions. In addition, Oncor has exposure
to credit risk as a result of non-performance by nonaffiliated REPs.
Most of the remaining trade accounts receivable are with large business
customers and hedging counterparties. These counterparties include major energy
companies, financial institutions, gas and electric utilities, independent power
producers, oil and gas producers and energy trading companies.
Concentration of Credit Risk -- The exposure to credit risk from these
customers and counterparties, excluding credit collateral, as of December 31,
2003, is $1.1 billion net of standardized master netting contracts and
agreements that provide the right of offset of positive and negative credit
exposures with individual customers and counterparties. When considering
collateral currently held by US Holdings (cash, letters of credit and other
security interests), the net credit exposure is $965 million. Of this amount,
approximately 86% of the associated exposure is with investment grade customers
and counterparties, as determined using publicly available information including
major rating agencies' published ratings and US Holdings' internal credit
evaluation process. Those customers and counterparties without an S&P rating of
at least BBB- or similar rating from another major rating agency are rated using
internal credit methodologies and credit scoring models to estimate an S&P
equivalent rating. US Holdings routinely monitors and manages its credit
exposure to these customers and counterparties on this basis.
The following table presents the distribution of credit exposure as of
December 31, 2003, 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 Net 2 years or Between than 5
Collateral Collateral Exposure less 2-5 years years Total
---------- ---------- -------- --------- --------- ------- ------
Investment grade $832 $ 5 $ 827 $ 579 $ 129 $ 119 $ 827
Noninvestment grade 250 112 138 107 18 13 138
---------- ---------- -------- -------- -------- ------- ------
Totals $ 1,082 $ 117 $ 965 $ 686 $ 147 $ 132 $ 965
========== ========== ======== ======== ======== ======== =======
Investment grade 77% 4% 86%
Noninvestment grade 23% 96% 14%
US Holdings had no exposure to any one customer or counterparty greater
than 10% of the net exposure of $965 million at December 31, 2003. Additionally,
approximately 71% of the credit exposure, net of collateral held, has a maturity
date of two years or less. US Holdings does not anticipate any material adverse
effect on its financial position or results of operations as a result of
non-performance by any customer or counterparty.
A-39
RISK FACTORS THAT MAY AFFECT FUTURE RESULTS
The following risk factors are being presented in consideration of
industry practice with respect to disclosure of such information in filings
under the Securities Exchange Act of 1934, as amended.
Some important factors, in addition to others specifically addressed in
this MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS, that could have a material impact on US Holdings' operations,
financial results and financial condition, and could cause US Holdings' actual
results or outcomes to differ materially from any projected outcome contained in
any forward-looking statement in this report, include:
ERCOT is the independent system operator that is responsible for
maintaining reliable operation of the bulk electric power supply system in the
ERCOT region. Its responsibilities include the clearing and settlement of
electricity volumes and related ancillary services among the various
participants in the deregulated Texas market. Because of new processes and
systems associated with the opening of the market to competition, which continue
to be improved, there have been delays in finalizing these settlements. As a
result, US Holdings is subject to settlement adjustments from ERCOT related to
prior periods, which may result in charges or credits impacting future reported
results of operations.
US Holdings' businesses operate in changing market environments influenced
by various legislative and regulatory initiatives regarding deregulation,
regulation or restructuring of the energy industry, including deregulation of
the production and sale of electricity. US Holdings will need to adapt to these
changes and may face increasing competitive pressure.
US Holdings' businesses are subject to changes in laws (including the
Texas Public Utility Regulatory Act, as amended, the Federal Power Act, as
amended, the Atomic Energy Act, as amended, the Public Utility Regulatory
Policies Act of 1978, as amended and the Public Utility Holding Company Act of
1935, as amended) and changing governmental policy and regulatory actions
(including those of the Commission, the FERC, and the NRC) with respect to
matters including, but not limited to, operation of nuclear power facilities,
construction and operation of other power generation facilities, construction
and operation of transmission facilities, acquisition, disposal, depreciation,
and amortization of regulated assets and facilities, recovery of purchased gas
costs, decommissioning costs, and return on invested capital for US Holdings'
regulated businesses, and present or prospective wholesale and retail
competition.
US Holdings believes that the electricity market in ERCOT is workably
competitive. US Holdings 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, US Holdings 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.
US Holdings is not guaranteed any rate of return on its capital
investments in unregulated businesses. US Holdings markets and trades power,
including power from its own production facilities, as part of its wholesale
energy sales business and portfolio management operation. US Holdings' results
of operations are likely to depend, in large part, upon prevailing retail rates,
which are set, in part, by regulatory authorities, and market prices for
electricity, gas and coal in its regional market and other competitive markets.
Market prices may fluctuate substantially over relatively short periods of time.
Demand for electricity can fluctuate dramatically, creating periods of
substantial under- or over-supply. During periods of over-supply, prices might
be depressed. Also, at times there may be political pressure, or pressure from
regulatory authorities with jurisdiction over wholesale and retail energy
commodity and transportation rates, to impose price limitations, bidding rules
and other mechanisms to address volatility and other issues in these markets.
A-40
US Holdings' regulated businesses are subject to cost-of-service
regulation and annual earnings oversight. This regulatory treatment does not
provide any assurance as to achievement of earnings level. Oncor's rates are
regulated by the Commission based on an analysis of Oncor's costs, as reviewed
and approved in a regulatory proceeding. While rate regulation is premised on
the full recovery of prudently incurred costs and a reasonable rate of return on
invested capital, there can be no assurance that the Commission will judge all
of US Holdings' costs to have been prudently incurred or that the regulatory
process in which rates are determined will always result in rates that will
produce full recovery of US Holdings' costs and the return on invested capital
allowed by the Commission.
Some of the fuel for TXU 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 TXU Energy can obtain for power
sales may not change at the same rate as changes in fuel costs. In addition, TXU
Energy markets and trades natural gas and other energy related commodities, and
volatility in these markets may affect TXU Energy's costs incurred in meeting
its obligations.
Volatility in market prices for fuel and electricity may result from:
o severe or unexpected weather conditions,
o seasonality,
o changes in electricity usage,
o illiquidity in the wholesale power or other markets,
o transmission or transportation constraints, inoperability or
inefficiencies,
o availability of competitively priced alternative energy sources,
o changes in supply and demand for energy commodities,
o changes in power production capacity,
o outages at TXU 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 TXU 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 related to gas prices because
gas-fired plant is the marginal cost unit during the majority of the year in the
ERCOT region. Accordingly, the contribution to earnings and the value of TXU
Energy's base load power production is dependent in significant part upon the
price of gas. TXU Energy cannot fully hedge the risk associated with dependency
on gas because of the expected useful life of TXU 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, TXU 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, TXU 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, TXU 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
TXU Energy has unhedged positions, fluctuating commodity prices can materially
impact TXU Energy's results of operations and financial position, either
favorably or unfavorably.
Although US Holdings devotes a considerable amount of management time and
effort to the establishment of risk management procedures as well as the ongoing
review of the implementation of these procedures, the procedures it has in place
may not always be followed or may not always function as planned and cannot
eliminate all the risks associated with these activities.
A-41
US Holdings might not be able to satisfy all of its guarantees and
indemnification obligations, including these related to hedging and risk
management activities, if they were to come due at the same time.
TXU Energy's hedging and risk management activities are exposed to the
risk that counterparties that owe TXU 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, TXU Energy might be forced to acquire alternative
hedging arrangements or honor the underlying commitment at then-current market
prices. In such event, TXU Energy might incur losses in addition to amounts, if
any, already paid to the counterparties. ERCOT market participants are also
exposed to risks that another ERCOT market participant may default in its
obligations to pay ERCOT for power taken in the ancillary services market, in
which case such costs, to the extent not offset by posted security and other
protections available to ERCOT, may be allocated to various non-defaulting ERCOT
market participants.
The current credit ratings for US Holdings' and its subsidiaries'
long-term debt are investment grade. A rating reflects only the view of a rating
agency, and it is not a recommendation to buy, sell or hold securities. Any
rating can be revised upward or downward at any time by a rating agency if such
rating agency decides that circumstances warrant such a change. If S&P, Moody's
or Fitch were to downgrade US Holdings' and/or its subsidiaries' long-term
ratings, particularly below investment grade, borrowing costs would increase and
the potential pool of investors and funding sources would likely decrease. 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 US Holdings' large customers, suppliers and counterparties require
sufficient creditworthiness in order to enter into transactions. If US Holdings'
subsidiaries' ratings were to decline to below investment grade, costs to
operate the power and gas businesses would increase because counterparties may
require the posting of collateral in the form of cash-related instruments, or
counterparties may decline to do business with US Holdings' subsidiaries.
In addition, as discussed elsewhere in this report, the terms of certain
financing and other arrangements contain provisions that are specifically
affected by changes in credit ratings and could require the posting of
collateral, the repayment of indebtedness or the payment of other amounts.
The operation of power production and energy delivery facilities involves
many risks, including start up risks, breakdown or failure of facilities, lack
of sufficient capital to maintain the facilities, the dependence on a specific
fuel source or the impact of unusual or adverse weather conditions or other
natural events, as well as the risk of performance below expected levels of
output or efficiency, the occurrence of any of which could result in lost
revenues and/or increased expenses. A significant portion of US Holdings'
facilities was constructed many years ago. In particular, older generating
equipment, even if maintained in accordance with good engineering practices, may
require significant capital expenditures to keep it operating at peak
efficiency. The risk of increased maintenance and capital expenditures arises
from (a) increased starting and stopping of generation equipment due to the
volatility of the competitive market, (b) any unexpected failure to produce
power, including failure caused by breakdown or forced outage, and (c) repairing
damage to facilities due to storms, natural disasters, wars, terrorist acts and
other catastrophic events. Further, US Holdings' ability to successfully and
timely complete capital improvements to existing facilities or other capital
projects is contingent upon many variables and subject to substantial risks.
Should any such efforts be unsuccessful, US Holdings could be subject to
additional costs and/or the write-off of its investment in the project or
improvement.
Insurance, warranties or performance guarantees may not cover all or any
of the lost revenues or increased expenses, including the cost of replacement
power. Likewise, US Holdings' ability to obtain insurance, and the cost of and
coverage provided by such insurance, could be affected by events outside its
control.
A-42
The ownership and operation of nuclear facilities, including TXU 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.
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 US Holdings' resources, including insurance coverage.
US Holdings is subject to extensive environmental regulation by
governmental authorities. In operating its facilities, US Holdings is required
to comply with numerous environmental laws and regulations, and to obtain
numerous governmental permits. US Holdings may incur significant additional
costs to comply with these requirements. If US Holdings fails to comply with
these requirements, it could be subject to civil or criminal liability and
fines. Existing environmental regulations could be revised or reinterpreted, new
laws and regulations could be adopted or become applicable to US Holdings or its
facilities, and future changes in environmental laws and regulations could
occur, including potential regulatory and enforcement developments related to
air emissions.
US Holdings may not be able to obtain or maintain all required
environmental regulatory approvals. If there is a delay in obtaining any
required environmental regulatory approvals or if US Holdings fails to obtain,
maintain or comply with any such approval, the operation of its facilities could
be stopped or become subject to additional costs. Further, at some of US
Holdings' older facilities, including base load lignite and coal plants, it may
be uneconomical for US Holdings to install the necessary equipment, which may
cause US Holdings to shut down those facilities.
In addition, US Holdings may be responsible for any on-site liabilities
associated with the environmental condition of facilities that it has acquired
or developed, regardless of when the liabilities arose and whether they are
known or unknown. In connection with certain acquisitions and sales of assets,
US Holdings may obtain, or be required to provide, indemnification against
certain environmental liabilities. Another party could fail to meet its
indemnification obligations to US Holdings.
TXU Energy is obligated to offer the price-to-beat rate to requesting
residential and small business customers in the historical service territory of
its incumbent utility through January 1, 2007. TXU Energy is not permitted to
offer electricity to the residential customers in the historical service
territory at a price other than the price-to-beat rate until January 1, 2005,
unless before that date the Commission determines that 40% or more of the amount
of electric power consumed by residential customers in that area is committed to
be served by REPs other than TXU Energy. Because TXU Energy will not have the
same level of residential customer price flexibility as competitors in the
historical service territory, TXU Energy could lose a significant number of
these customers to other providers. In addition, at times, during this period,
if the market price of power is lower than TXU Energy's cost to produce power,
TXU Energy would have a limited ability to mitigate the loss of margin caused by
its loss of customers by selling power from its power production facilities.
A-43
TXU Energy or any other REP can offer electricity to large business
customers at any negotiated price. The large business market has been very
competitive and customer switching has occurred.
The initial price-to-beat rates for the affiliated REPs, including TXU
Energy's, were established by the Commission on December 7, 2001. Pursuant to
Commission regulations, the initial price-to-beat rate for each affiliated REP
was 6% less than the average rates in effect for its incumbent utility on
January 1, 1999, adjusted to take into account a new fuel factor as of December
31, 2001.
Other REPs are allowed to offer electricity to TXU 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 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 TXU Energy losing customers to competitive REPs.
The results of TXU Energy's retail electric operations in the historical
service territory are largely dependent upon the amount of headroom available to
TXU Energy and the competitive REPs in TXU Energy's price-to-beat rate. Since
headroom is dependent, in part, on power production costs, TXU Energy does not
know nor can it estimate the amount of headroom that it or other REPs will have
in TXU 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 TXU 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 TXU Energy's
price-to-beat rate will not result in negative headroom in the future.
In most retail electric markets outside the historical service territory,
TXU 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, TXU 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 TXU
Energy and nationally branded providers of consumer products and services. Some
of these competitors or potential competitors may be larger and better
capitalized than TXU Energy. If there is inadequate margin in these retail
electric markets, it may not be profitable for TXU Energy to enter these
markets.
TXU 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, TXU 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. TXU
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 TXU Energy's customers could negatively impact the satisfaction
of its customers with its service.
A-44
TXU 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 TXU 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 differ from TXU 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. TXU Energy is refining these systems and processes, and they may
prove more expensive to refine than planned and may not function as planned.
Research and development activities are ongoing to improve existing and
alternative technologies to produce electricity, including gas turbines, fuel
cells, microturbines and photovoltaic (solar) cells. It is possible that
advances in these or other alternative technologies will reduce the costs of
electricity production from these technologies to a level that will enable these
technologies to compete effectively with electricity production from traditional
power plants like TXU 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. The commencement of commercial
operation of new facilities in the regional markets where TXU Energy has
facilities will likely increase the competitiveness of the wholesale power
market in those regions. In addition, the market value of US Holdings' power
production and/or energy transportation facilities may be significantly reduced.
Also, electricity demand could be reduced by increased conservation efforts and
advances in technology, which could likewise significantly reduce the value of
US Holdings' facilities. Changes in technology could also alter the channels
through which retail electric customers buy electricity.
US Holdings is a holding company and conducts its operations primarily
through wholly-owned subsidiaries. Substantially all of US Holdings'
consolidated assets are held by these subsidiaries. Accordingly, US Holdings'
cash flows and ability to meet its obligations and to pay dividends are largely
dependent upon the earnings of its subsidiaries and the distribution or other
payment of such earnings to US Holdings in the form of distributions, loans or
advances, and repayment of loans or advances from US Holdings. The subsidiaries
are separate and distinct legal entities and have no obligation to provide US
Holdings with funds for its payment obligations, whether by dividends,
distributions, loans or otherwise.
Because US Holdings is a holding company, its obligations to its creditors
are structurally subordinated to all existing and future liabilities and
existing and future preferred stock of its subsidiaries. Therefore, US Holdings'
rights and the rights of its creditors to participate in the assets of any
subsidiary in the event that such a subsidiary is liquidated or reorganized are
subject to the prior claims of such subsidiary's creditors and holders of its
preferred stock. To the extent that US Holdings may be a creditor with
recognized claims against any such subsidiary, its claims would still be subject
to the prior claims of such subsidiary's creditors to the extent that they are
secured or senior to those held by US Holdings.
A-45
The inability to raise capital on favorable terms, particularly during
times of uncertainty in the financial markets, could impact US Holdings' ability
to sustain and grow its businesses, which are capital intensive, and would
increase its capital costs. US Holdings relies on access to financial markets as
a significant source of liquidity for capital requirements not satisfied by cash
on hand or operating cash flows. US Holdings' access to the financial markets
could be adversely impacted by various factors, such as:
o changes in credit markets that reduce available credit or the ability
to renew existing liquidity facilities on acceptable terms;
o inability to access commercial paper markets;
o a deterioration of US Holdings' credit or a reduction in US Holdings'
credit ratings or the credit ratings of its
subsidiaries;
o extreme volatility in US Holdings' markets that increases margin or
credit requirements;
o a material breakdown in US Holdings' risk management procedures;
o prolonged delays in billing and payment resulting from delays in
switching customers from one REP to another; and
o the occurrence of material adverse changes in US Holdings' businesses
that restrict US Holdings' ability to access its liquidity facilities.
A lack of necessary capital and cash reserves could adversely impact the
evaluation of US Holdings' credit worthiness by counterparties and rating
agencies. Further, concerns on the part of counterparties regarding TXU Energy
liquidity and credit could limit its portfolio management activities.
As a result of the energy crisis in California during 2001, the recent
volatility of natural gas prices in North America, the bankruptcy filing by
Enron Corporation, accounting irregularities of public companies, and
investigations by governmental authorities into energy trading activities,
companies in the regulated and non-regulated utility businesses have been under
a generally increased amount of public and regulatory scrutiny. Accounting
irregularities at certain companies in the industry have caused regulators and
legislators to review current accounting practices and financial disclosures.
The capital markets and ratings agencies also have increased their level of
scrutiny. Additionally, allegations against various energy trading companies of
"round trip" or "wash" transactions, which involve the simultaneous buying and
selling of the same amount of power at the same price and provide no true
economic benefit, power market manipulation and inaccurate power and commodity
price reporting have had a negative effect on the industry. US Holdings believes
that it is complying with all applicable laws, but it is difficult or impossible
to predict or control what effect these events may have on US Holdings'
financial condition or access to the capital markets. Additionally, it is
unclear what laws and regulations may develop, and US Holdings cannot predict
the ultimate impact of any future changes in accounting regulations or practices
in general with respect to public companies, the energy industry or its
operations specifically.
The issues and associated risks and uncertainties described above are not
the only ones US Holdings may face. Additional issues may arise or become
material as the energy industry evolves.
A-46
FORWARD-LOOKING STATEMENTS
This report and other presentations made by US Holdings and its
subsidiaries (collectively, US Holdings) contain forward-looking statements
within the meaning of Section 21E of the Securities Exchange Act of 1934, as
amended. Although US Holdings believes that in making any such statement its
expectations are based on reasonable assumptions, any such statement involves
uncertainties and is qualified in its entirety by reference to the risks
discussed above under "Risk Factors That May Affect Future Results" and the
following important factors, among others, that could cause the actual results
of US Holdings to differ materially from those projected in such forward-looking
statements:
o prevailing governmental policies and regulatory actions, including
those of the FERC, the Commission, the RRC and the NRC, with respect
to:
o allowed rates of return;
o industry, market and rate structure;
o purchased power and recovery of investments;
o operations of nuclear generating facilities;
o acquisitions and disposal of assets and facilities;
o operation and construction of plant facilities;
o decommissioning costs;
o present or prospective wholesale and retail competition;
o changes in tax laws and policies; and
o changes in and compliance with environmental and safety laws
and policies;
o continued implementation of the 1999 Restructuring Legislation;
o legal and administrative proceedings and settlements;
o general industry trends;
o power costs and availability;
o weather conditions and other natural phenomena, and acts of sabotage, wars
or terrorist activities;
o unanticipated population growth or decline, and changes in market demand
and demographic patterns;
o changes in business strategy, development plans or vendor relationships;
o competition for retail and wholesale customers;
o access to adequate transmission facilities to meet changing demands;
o pricing and transportation of crude oil, natural gas and other commodities;
o unanticipated changes in interest rates, commodity prices, rates of
inflation or foreign exchange rates;
o unanticipated changes in operating expenses, liquidity needs and capital
expenditures;
o commercial bank market and capital market conditions;
o competition for new energy development and other business opportunities;
o inability of various counterparties to meet their obligations with respect
to US Holdings' financial instruments;
o changes in technology used by and services offered by US Holdings;
o significant changes in US Holdings' relationship with its employees,
including the availability of qualified personnel, and the potential
adverse effects if labor disputes or grievances were to occur;
o significant changes in critical accounting policies material to
US Holdings; and
o actions by credit rating agencies.
A-47
Any forward-looking statement speaks only as of the date on which it is
made, and US Holdings 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 US Holdings to predict all of them; nor
can US Holdings 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.
A-48
TXU US HOLDINGS COMPANY
STATEMENT OF RESPONSIBILITY
The management of TXU US Holdings Company is responsible for the
preparation, integrity and objectivity of the consolidated financial statements
of TXU US Holdings Company and other information included in this report. The
consolidated financial statements have been prepared in conformity with
accounting principles generally accepted in the United States of America. As
appropriate, the statements include amounts based on informed estimates and
judgments of management.
The management of TXU US Holdings Company is responsible for establishing
and maintaining a system of internal control, which includes the internal
controls and procedures for financial reporting, that is designed to provide
reasonable assurance, on a cost-effective basis, that assets are safeguarded,
transactions are executed in accordance with management's authorization and
financial records are reliable for preparing consolidated financial statements.
Management believes that the system of control provides reasonable assurance
that errors or irregularities that could be material to the consolidated
financial statements are prevented or would be detected within a timely period.
Key elements in this system include the effective communication of established
written policies and procedures, selection and training of qualified personnel
and organizational arrangements that provide an appropriate division of
responsibility. This system of control is augmented by an ongoing internal audit
program designed to evaluate its adequacy and effectiveness. Management
considers the recommendations of the internal auditors and independent auditors
concerning TXU US Holdings Company's system of internal control and takes
appropriate actions which are cost-effective in the circumstances. Management
believes that, as of December 31, 2003, TXU US Holdings Company's system of
internal control was adequate to accomplish the objectives discussed herein.
The independent auditing firm of Deloitte & Touche LLP is engaged to
audit, in accordance with auditing standards generally accepted in the United
States of America, the consolidated financial statements of TXU US Holdings
Company and its subsidiaries and to issue their report thereon.
/s/ C. JOHN WILDER /s/ M. S. GREENE
- ------------------------------------- -------------------------------------
C.John Wilder, Chairman of the Board M. S. Greene, Oncor
and Chief Executive Group President
/s/ T. L. BAKER /s/ H. DAN FARELL
- ------------------------------------- -------------------------------------
T. L. Baker, TXU Energy H.Dan Farell, Executive Vice President
Group President and Chief Financial Officer
/s/ DAVID H. ANDERSON
- -------------------------------------
David H. Anderson, Controller and
Principal Accounting Officer
A-49
INDEPENDENT AUDITORS' REPORT
TXU US Holdings Company:
We have audited the accompanying consolidated balance sheets of TXU US Holdings
Company and subsidiaries (US Holdings) as of December 31, 2003 and 2002, and the
related consolidated statements of income, comprehensive income, cash flows and
shareholder's equity for each of the three years in the period ended December
31, 2003. These financial statements are the responsibility of US Holdings'
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates and assumptions made by management, as well as evaluating
the overall financial statement presentation. We believe that our audits provide
a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of US Holdings and subsidiaries at
December 31, 2003 and 2002, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2003, in
conformity with accounting principles generally accepted in the United States
of America.
As discussed in Note 1 to the Notes to Financial Statements, the accompanying
2002 and 2001 financial statements have been reclassified to give effect to the
adoption of Statement of Financial Accounting Standards No. 145, Rescission of
FASB Statements No. 4, 44 and 64, Amendment of FASB Statement No. 13, and
Technical Corrections.
As discussed in Note 1 to the Notes to Financial Statements, US Holdings changed
its method of accounting for certain contracts with the rescission of Emerging
Issues Task Force Issue No. 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities."
As discussed in Note 6 to the Notes to Financial Statements, in 2002 US Holdings
adopted the provisions of Statement of Financial Accounting Standards No. 142,
"Goodwill and Other Intangible Assets."
DELOITTE & TOUCHE LLP
Dallas, Texas
March 11, 2004
A-50
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31,
------------------------------------
2003 2002 2001
---- ---- ----
Millions of Dollars
Operating revenues................................................... $8,582 $8,093 $7,966
Costs and expenses:
Cost of energy sold and delivery fees............................... 3,627 3,194 3,049
Operating costs..................................................... 1,398 1,374 1,263
Depreciation and amortization, other than goodwill.................. 706 714 633
Selling, general and administrative expenses........................ 843 988 712
Franchise and revenue-based taxes................................... 375 410 441
Other income........................................................ (52) (38) (11)
Other deductions.................................................... 21 250 269
Interest income..................................................... (19) (6) (39)
Interest expense and related charges................................ 605 440 473
Goodwill amortization............................................... -- - 15
------ ------ ------
Total costs and expenses.......................................... 7,504 7,326 6,805
------ ------ ------
Income from continuing operations before income taxes, extraordinary
loss and cumulative effect of changes in accounting principles...... 1,078 767 1,161
Income tax expense................................................... 346 223 359
------ ------ ------
Income from continuing operations before extraordinary loss and
cumulative effect of changes in accounting principles............... 732 544 802
Discontinued operations, net of tax effect........................... (14) (49) (28)
Extraordinary loss, net of tax effect................................ -- (134) (57)
Cumulative effect of changes in accounting principles, net of tax
effect (58) -- --
------- ------ ------
Net income........................................................... 660 361 717
Preferred stock dividends............................................ 5 9 10
------ ------ ------
Net income available for common stock................................ $ 655 $ 352 $ 707
====== ====== ======
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Year Ended December 31,
----------------------------------
2003 2002 2001
---- ---- ----
Millions of Dollars
Net income........................................................... $ 660 $ 361 $ 717
Other comprehensive income (loss)--
Net change during period, net of tax effects:
Minimum pension liability adjustments (net of tax (expense)
benefit of $(12), $20 and $-)............................. 23 (37) (1)
Cash flow hedges (SFAS No. 133):
Cumulative transition adjustment as of January 1, 2001 -- - (1)
Net change in fair value of derivative (net of tax benefit of
$74 and $99 and tax expense of $9)........................ (138) (184) 16
Amounts realized in earnings during the year (net of tax
expense of $90, $10 and $-)............................... 168 18 1
------ ------ ------
Total.......................................................... 53 (203) 15
------ ------ ------
Comprehensive income.................................................. $ 713 $ 158 $ 732
====== ======= ======
See Notes to Financial Statements.
A-51
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
-----------------------
2003 2002 2001
---- ---- ----
Millions of Dollars
Cash flows-- operating activities
Income from continuing operations before extraordinary loss and $ 732 $ 544 $ 802
cumulative effect of changes in accounting principles................
Adjustments to reconcile income from continuing operations before
extraordinary loss and cumulative effect of changes in accounting
principles to cash provided by operating activities
Depreciation and amortization.................................... 775 785 753
Deferred income taxes and investment tax credits-- net........... 119 58 (175)
Losses on early extinguishment of debt........................... -- - 149
Gains from sale of assets........................................ (45) (32) (2)
Reduction of revenues for earnings in excess of regulatory earnings
cap............................................................ -- - 39
Net effect of unrealized mark-to-market valuations of commodity 100 113 (318)
contracts......................................................
Asset impairments charge......................................... -- 237 -
Retail clawback accrual increase (decrease)...................... (12) 185 -
Reduction in regulatory liability................................ (132) (151) -
Over/(under) recovered fuel costs................................ -- - 568
Changes in operating assets and liabilities:
Accounts receivable-- trade (including affiliates)............ 327 (416) 206
Inventories................................................... (46) (44) (10)
Accounts payable-- trade (including affiliates)............... 20 57 (592)
Commodity contract assets and liabilities..................... 24 (45) (26)
Margin deposits............................................... 25 (6) 227
Other assets ................................................ (291) (43) 52
Other liabilities............................................. 360 49 120
------ ------ -------
Cash provided by operating activities....................... 1,956 1,291 1,793
Cash flows -- financing activities
Issuances of securities:
Exchangeable subordinated notes.................................. -- 750 -
Other long-term debt............................................. 2,320 3,111 3,188
Retirements/repurchases of securities:
Long-term debt................................................... (1,391) (2,772) (2,515)
Preferred securities of subsidiaries............................. (98) - -
Securities of unconsolidated subsidiary trusts................... - - (837)
Common stock..................................................... (463) - (859)
Increased (decrease) in notes payable to bank......................... (1,804) 1,804 -
Net change in advances from affiliates................................ (59) (799) 283
Dividends paid to parent.............................................. (588) (927) -
Capital contributions from parent..................................... - - 150
Preferred stock dividends paid........................................ (5) (9) (10)
Restricted cash activity related to debt.............................. 210 (210) -
Debt premium, discount, financing and reacquisition expenses.......... (66) (174) (195)
------ ------ -------
Cash provided by (used in) financing activities............... (1,944) 774 (795)
Cash flows-- investing activities
Capital expenditures................................................ (706) (797) (962)
Acquisition of a business........................................... -- (36) -
Proceeds from sale of assets........................................ 24 447 -
Nuclear fuel........................................................ (44) (51) (38)
Other............................................................... 14 (171) 9
------ ------ -------
Cash used in investing activities............................. (712) (608) (991)
Cash used by discontinued operations.................................. (2) (4) 7
------ ------ -------
Net change in cash and cash equivalents............................... (702) 1,453 14
Cash and cash equivalents-- beginning balance......................... 1,508 55 41
------ ------ -------
Cash and cash equivalents-- ending balance............................ $ 806 $1,508 $ 55
====== ====== =======
See Notes to Financial Statements.
A-52
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
December 31,
--------------------
2003 2002
---- ----
(millions of dollars)
ASSETS
Current assets:
Cash and cash equivalents................................................ $ 806 $ 1,508
Restricted cash.......................................................... 12 210
Accounts receivable-- trade.............................................. 1,001 1,384
Inventories ............................................................. 416 391
Commodity contract assets................................................ 959 1,298
Other current assets..................................................... 258 297
------- -------
Total current assets................................................ 3,452 5,088
Investments:
Restricted cash.......................................................... 13 68
Other investments........................................................ 510 427
Property, plant and equipment-- net......................................... 16,714 16,436
Goodwill.................................................................... 558 558
Regulatory assets-- net..................................................... 1,872 1,630
Commodity contract assets................................................... 121 476
Cash flow hedges and other derivative assets................................ 88 14
Assets held for sale........................................................ 14 36
Other noncurrent assets..................................................... 151 144
------- -------
Total assets..................................................... $23,493 $24,877
======= =======
LIABILITIES, PREFERRED INTERESTS AND SHAREHOLDERS' EQUITY
Current liabilities:
Advances from affiliates................................................. $ 691 $ 787
Notes payable-- banks.................................................... - 1,804
Long-term debt due currently............................................. 249 397
Accounts payable-- trade................................................. 775 820
Commodity contract liabilities........................................... 913 1,138
Accrued taxes............................................................ 414 303
Other current liabilities................................................ 786 809
------- ------
Total current liabilities........................................... 3,828 6,058
Accumulated deferred income taxes........................................... 3,403 3,227
Investment tax credits...................................................... 428 450
Commodity contract liabilities.............................................. 59 320
Cash flow hedges and other derivative liabilities........................... 140 150
Other noncurrent liabilities and deferred credits........................... 1,601 1,336
Long-term debt, less amounts due currently.................................. 7,217 6,613
Exchangeable preferred membership interests of TXU Energy, net of $253
discount (Note 1)......................................................... 497 -
------- ------
Total liabilities................................................... 17,173 18,154
Preferred stock subject to mandatory redemption (Note 4)................... - 21
Contingencies (Note 16)
Shareholders' equity and preferred interests (Notes 9 and 10)............... 6,320 6,702
------- -------
Total liabilities, preferred interests and shareholders' equity.... $23,493 $24,877
======= =======
See Notes to Financial Statements.
A-53
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED SHAREHOLDERS' EQUITY
Year Ended December 31,
-----------------------------
2003 2002 2001
---- ---- ----
Millions of Dollars
Preferred stock -- not subject to mandatory redemption:
Balance at beginning of year..................................... $ 115 $ 115 $ 115
Preferred stock repurchased and retired (2003 -- 789,830
shares)........................................................ (77) -- --
------ ------ ------
Balance at end of year (2003 -- 379,231 shares,
2002 and 2001 -- 1,169,061 shares)............................. 38 115 115
Common stock without par value -- authorized shares -- 180,000,000:
Balance at beginning of year..................................... 2,514 2,248 3,107
Common stock repurchased and retired (2003 -- 11,562,500
shares, 2002-- none and 2001-- 28,627,000 shares)............. (463) -- (859)
Non-cash capital contribution related to issuance of
exchangeable subordinated debt.................................. -- 266 --
Transfer of equity to new classes of common stock - 41,255,362
shares.......................................................... (2,051) -- --
------ ------ ------
Balance at end of year (2003 -- none; 2002 -- 52,817,862 shares;
and 2001 -- 52,817,862 shares)................................ -- 2,514 2,248
Class A common stock without par value -- authorized shares -- 9,000,000
Balance at beginning of year..................................... -- -- --
Transfer of equity from old class of common stock -
2,062,768 shares............................................... 102 -- --
------ ------ ------
Balance at end of year (2003 -- 2,062,768 shares)................ 102 -- --
Class B common stock without par value -- authorized shares --
171,000,000
Balance at beginning of year..................................... -- -- --
Transfer of equity from old class of common stock - 39,192,594
shares......................................................... 1,949 -- --
------ ------ ------
Balance at end of year (2003 -- 39,192,594 shares)............... 1,949 -- --
Retained earnings:
Balance at beginning of year..................................... 4,261 5,086 4,229
Net income.................................................... 660 361 717
Capital contributions of parent............................... -- -- 150
Common stock repurchased and retired.......................... -- -- --
Common stock dividends paid and declared...................... (550) (1,177) --
Dividends declared on preferred stock......................... (5) (9) (10)
------- ------ ------
Balance at end of year........................................... 4,366 4,261 5,086
Accumulated other comprehensive income (loss), net of tax effects:
Minimum pension liability adjustment:
Balance at beginning of year..................................... (38) (1) --
Change during the year........................................ 23 (37) (1)
------ ------ ------
Balance at end of year........................................... (15) (38) (1)
Cash flow hedges (SFAS No. 133):
Balance at beginning of year..................................... (150) 16 --
Change during the year........................................ 30 (166) 16
------ ------ ------
Balance at end of year........................................... (120) (150) 16
------ ------ ------
Total accumulated other comprehensive income (loss)........... (135) (188) 15
------ ------ ------
Total common stock equity........................................... 6,282 6,587 7,349
------ ------ ------
Shareholders' equity................................................ $6,320 $6,702 $7,464
====== ====== ======
See Notes to Financial Statements.
A-54
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES AND BUSINESS
Description of Business -- As of January 1, 2002, TXU US Holdings Company
(US Holdings, formerly TXU Electric Company) is a holding company for TXU Energy
Company LLC (TXU Energy) and Oncor Electric Delivery Company (Oncor). US
Holdings is a wholly owned subsidiary of TXU Corp., a Texas corporation. Prior
to January 1, 2002, US Holdings was a regulated, integrated utility company
directly engaged in the generation, purchase, transmission, distribution and
sale of electric energy in the north-central, eastern and western parts of
Texas.
US Holdings has two reportable segments: TXU Energy and Oncor. (See Note
17 for further information concerning reportable business segments.)
Discontinued Business -- In December 2003, TXU Energy finalized a formal
plan to sell its strategic retail services business, which is engaged
principally in providing energy management services. The consolidated financial
statements for all years presented reflect the reclassification of the results
of this business as discontinued operations.
Business Restructuring - The 1999 Restructuring Legislation restructured
the electric utility industry in Texas and provided for a transition to
competition in the generation and retail sale of electricity. TXU Corp.
disaggregated its electric utility business, as required by the legislation, and
restructured certain of its US businesses as of January 1, 2002 resulting in two
new business operations:
o Oncor - a utility regulated by the Commission that holds electricity
transmission and distribution assets and engages in electricity
delivery services.
o TXU Energy - a competitive business that holds the power generation
assets and engages in wholesale and retail energy sales and
hedging/risk management activities.
The relationships of these entities and their rights and obligations with
respect to their collective assets and liabilities are contractually described
in a master separation agreement executed in December 2001.
The operating assets of Oncor and TXU Energy are located principally in
the north-central, eastern and western parts of Texas.
A settlement of outstanding issues and other proceedings related to
implementation of the 1999 Restructuring Legislation received final approval by
the Commission in January 2003. See Note 15 for further discussion.
In addition, as of January 1, 2002, certain other businesses within the TXU
Corp. system were transferred to TXU Energy, including TXU Gas' hedging and risk
management business and its unregulated retail commercial/industrial (business)
gas supply operation, as well as the fuel transportation and coal mining
subsidiaries that primarily service the generation operations.
Other Business Changes -- In April 2002, TXU Energy acquired a
cogeneration and wholesale energy production business in New Jersey for $36
million in cash. The acquisition included a 122 megawatt (MW) combined-cycle
power production facility and various contracts, including electric supply and
gas transportation agreements. The acquisition was accounted for as a purchase
business combination, and its results of operations are reflected in the
consolidated financial statements from the acquisition date.
In May 2002, TXU Energy acquired a 260 MW combined-cycle power generation
facility in northwest Texas through a settlement agreement which dismissed a
lawsuit previously filed related to the plant, and included a nominal cash
payment. TXU Energy previously purchased all of the electrical output of this
plant under a long-term contract.
A-55
In April 2002, TXU Energy completed the sale of two electricity generation
plants in the Dallas-Fort Worth area with total capacity of 2,334 MW for $443
million in cash. Concurrent with the sale, TXU Energy entered into a tolling
agreement to purchase power during the summer months through 2006. The terms of
the tolling agreement include above-market pricing, representing a fair value
liability of $190 million. A pretax gain on the sale of $146 million, net of the
effects of the tolling agreement, was deferred and is being recognized in other
income during summer months over the five-year term of the tolling agreement.
Both the value of the tolling agreement and the deferred gain are reported in
other liabilities in the balance sheet. The amount of the gain recognized in
other income in 2003 was approximately $30 million.
Basis of Presentation -- The consolidated financial statements of US
Holdings have been prepared in accordance with accounting principles generally
accepted in the US and, except for the discontinuance of the strategic retail
services business and the adoption of EITF 02-3, SFAS 143 and SFAS 145 as
discussed below and in Note 2, on the same basis as the audited financial
statements included in its 2002 Form 10-K. 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. The financial statements reflect reclassifications of prior
period amounts to conform to the current period presentation.. All intercompany
items and transactions have been eliminated in consolidation. All dollar amounts
in the financial statements and tables in the notes are stated in millions of US
dollars unless otherwise indicated.
The 2001 financial information includes information derived from the
historical financial statements of US Holdings. Reasonable allocation
methodologies were used to unbundle the financial statements of US Holdings
between its generation and transmission and distribution (delivery) operations.
Allocation of revenues reflected consideration of return on invested capital,
which continues to be regulated for the delivery operations. US Holdings
maintained expense accounts for each of its component operations. Costs of
energy and expenses related to operations and maintenance and depreciation and
amortization, as well as assets, such as property, plant and equipment,
materials and supplies and fuel, were specifically identified by component
operation and disaggregated. Various allocation methodologies were used to
disaggregate revenues, common expenses, assets and liabilities between US
Holdings' generation and delivery operations. Further, certain financial
information was deemed to be not reasonably allocable because of the changed
nature of Oncor's and TXU Energy's operations subsequent to the opening of the
market to competition, as compared to US Holdings' previous operations. Such
activities and related financial information consisted primarily of costs
related to retail customer support activities, including billing and related bad
debts expense, as well as regulated revenues associated with these costs.
Financial information related to these activities was reported in Oncor's
results of operations for the 2001 period. Interest and other financing costs
were determined based upon debt allocated. Allocations reflected in the
financial information for 2001 did not necessarily result in amounts reported in
individual line items that are comparable to actual results in 2002 and 2003.
Had the unbundled operations of US Holdings actually existed in 2001 as separate
entities in a deregulated environment, their results of operations could have
differed materially from those included in the historical financial statements
included herein.
Losses on Extinguishments of Debt -- As a result of the adoption of SFAS
145 as of January 1, 2003, any gain or loss on the early extinguishment of debt
that was classified as an extraordinary item in prior periods in accordance with
SFAS 4 is required to be reclassified if it does not meet the criteria of an
extraordinary item as defined by APB Opinion 30.
As a result of US Holdings' debt restructuring and refinancings in the
fourth quarter of 2001, US Holdings recorded losses on the early extinguishments
of debt of $97 million (net of income tax benefit of $52 million).
In accordance with SFAS 145, the income statements for the year ended
December 31, 2001 reflects the classification of these losses, previously
reported as extraordinary, as shown below:
Segment
--------------------------------------------
Energy Oncor US Holdings Total
(Parent)
----------- -------- ------------- ------
2001:
- -----
Extraordinary loss, net of tax - as previously reported $ (153) $ -- $ (1) $ (154)
Reclassifications to:
Other deductions................................. 149 -- -- 149
Income tax expense............................... (52) -- -- (52)
------ ------ ------ ------
Extraordinary loss, net of tax - as reported......... $ (56) $ -- $ (1) $ (57)
====== ====== ====== ======
The reclassifications had no effect on net income. The discussion of
extraordinary loss in Note 4, income tax information in Note 11, segment
information in Note 17 and regulated versus unregulated operations, quarterly
results and components of other deductions in Note 18 reflect the
reclassifications.
A-56
Use of Estimates -- The preparation of US Holdings' financial statements
requires management to make estimates and assumptions about future events that
affect the reporting and disclosure of assets and liabilities at the balance
sheet dates and the reported amounts of revenue and expense, including
mark-to-market valuation adjustments. In the event estimates and/or assumptions
prove to be different from actual amounts, adjustments are made in subsequent
periods to reflect more current information. No material adjustments, other than
those disclosed elsewhere herein, were made as a result of changes in previous
estimates or assumptions during the current year.
Financial Instruments and Mark-to-Market Accounting -- US Holdings enters
into financial instruments, including options, swaps, futures, forwards and
other contractual commitments primarily to manage energy price risk and interest
rate risks. These financial instruments are accounted for in accordance with
SFAS 133 as well as, prior to October 26, 2002, EITF 98-10. See Note 2 for the
effects of EITF 02-3, under which only financial instruments that are
derivatives are subject to mark-to-market accounting.
SFAS 133 requires the recognition of derivatives in the balance sheet, the
measurement of those instruments at fair value and the recognition in earnings
of changes in the fair value of derivatives. This recognition is referred to as
"mark-to-market" accounting. SFAS 133 provides exceptions to this accounting if
(a) the derivative is deemed to represent a transaction in the normal course of
purchasing from a supplier and selling to a customer, or (b) the derivative is
deemed to be a cash flow or fair value hedge. In accounting for cash flow
hedges, derivative assets and liabilities are recorded on the balance sheet at
fair value with an offset in other comprehensive income. Amounts are
reclassified from other comprehensive income to earnings as the underlying
transactions occur and realized gains and losses are recognized in earnings.
Fair value hedges are recorded as derivative assets or liabilities with an
offset to the carrying value of the related asset or liability. Any hedge
ineffectiveness related to cash flow and fair value hedges is recorded in
earnings.
Interest rate swaps entered into in connection with indebtedness to manage
interest rate risks are accounted for as cash flow hedges if the swap converts
rates from variable to fixed and are accounted for as fair value hedges if the
swap converts rates from fixed to variable.
US Holdings documents designated commodity, debt-related and other hedging
relationships, including the strategy and objectives for entering into such
hedge transactions and the related specific firm commitments or forecasted
transactions. US Holdings applies hedge accounting in accordance with SFAS 133
for these non-trading transactions, providing the underlying transactions remain
probable of occurring. Effectiveness is assessed based on changes in cash flows
of the hedges as compared to changes in cash flows of the hedged items. In its
risk management activities, TXU Energy hedges future electricity revenues using
natural gas instruments; such cross-commodity hedges are subject to
ineffectiveness calculations that can result in mark-to-market gains and losses.
Revenue Recognition -- US Holdings generally records revenue for retail
and wholesale energy sales and delivery fees under the accrual method. Retail
electric revenues are recognized when the commodity is provided to customers on
the basis of periodic cycle meter readings and include an estimated accrual for
the value of the commodity consumed from the meter reading date to the end of
the period. The unbilled revenue is estimated at the end of the period based on
estimated daily consumption after the meter read date to the end of the period.
Estimated daily consumption is derived using historical customer profiles
adjusted for weather and other measurable factors affecting consumption.
Electricity delivery revenues are recognized when delivery services are provided
to customers on the basis of periodic cycle meter readings and include an
estimated accrual for the delivery fee value of electricity provided from the
meter reading date to the end of the period.
Realized and unrealized gains and losses (including hedge ineffectiveness)
from transacting in energy-related contracts, principally for the purpose of
hedging margins on sales of energy, are reported as a component of revenues.
A-57
The historical financial statements for 2001 included adjustments made to
revenues for over/under recovered fuel costs. To the extent fuel costs incurred
exceeded regulated fuel factor amounts included in customer billings, US
Holdings recorded revenues on the basis of its ability and intent to obtain
regulatory approval for rate surcharges on future customer billings to recover
such amounts. Conversely, to the extent fuel costs incurred were less than
amounts included in customer billings, revenues were reduced. Following
deregulation of the Texas market on January 1, 2002, any changes to the fuel
factor component of the price-to-beat rates are recognized in revenues when
power is provided to customers.
Other than the purchase of fuel for gas-fired generation, the significant
majority of TXU Energy's physical natural gas purchases and sales represent
economic hedging activities; consequently, such transactions have been reported
net as a component of revenues. As a result of the issuance of EITF 03-11, sales
of natural gas to retail business customers are reported gross effective October
1, 2003.
Accounting for Contingencies - The financial results of US Holdings. may
be affected by judgments and estimates related to loss contingencies. Accruals
for loss contingencies are recorded when management determines that it is
probable that an asset has been impaired or a liability has been incurred and
that such economic loss can be reasonably estimated. These determinations are
based on management's interpretations of current facts and circumstances,
forecasts of future events and estimates of the financial impacts of such
events.
Regulatory Assets and Liabilities -- The financial statements of US
Holdings' regulated businesses, primarily its Texas electricity delivery
operations, reflect regulatory assets and liabilities under cost-based rate
regulation in accordance with SFAS 71. The assumptions and judgments used by
regulatory authorities continue to have an impact on the recovery of costs, the
rate earned on invested capital and the timing and amount of assets to be
recovered by rates. (See discussion in Note 15.)
As a result of the Settlement Plan becoming final and non-appealable, in
2002 US Holdings recorded an extraordinary charge to write down regulatory
assets subject to securitization. See Note 4 for further discussion.
Investments -- Deposits in a nuclear decommissioning trust fund are
carried at fair value in the balance sheet, with the cumulative increase in fair
value recorded as a liability to reflect the statutory nature of the trust.
Investments in unconsolidated business entities over which US Holdings has
significant influence but does not maintain effective control, generally
representing ownership of at least 20% and not more than 50% of common equity,
are accounted for under the equity method. Assets related to employee benefit
plans are held to satisfy deferred compensation liabilities and are recorded at
market value. (See Note 5 - Investments.)
Property, Plant and Equipment -- Properties are stated at original cost.
The cost of electric delivery property additions (and generation property
additions prior to July 1, 1999) includes labor and materials, applicable
overhead and payroll-related costs and an allowance for funds used during
construction. Generation property additions subsequent to July 1, 1999, and
other property, are stated at cost.
Depreciation of US Holdings' property, plant and equipment is calculated
on a straight-line basis over the estimated service lives of the properties.
Depreciation also includes an amount for decommissioning costs for the
nuclear-powered electricity generation plant (Comanche Peak), which is being
accrued over the lives of the units. Consolidated depreciation as a percent of
average depreciable property for US Holdings approximated 2.5% for 2003, 2.8%
for 2002 and 2.7% for 2001. See discussion below under Changes in Accounting
Standards regarding SFAS 143.
Effective April 1, 2003, the estimates of the depreciable lives of the
Comanche Peak nuclear generating plant and several gas generation plants were
extended to better reflect the useful lives of the assets. At the same time,
depreciation rates were increased on lignite and gas generation facilities to
reflect investments in emissions control equipment. The net impact of these
changes was a reduction in depreciation expense of $37 million (pre-tax) and an
increase in net income of $24 million for the year ended December 31, 2003.
A-58
US Holdings capitalizes computer software costs in accordance with SOP
98-1. These costs are being amortized over periods ranging from three to ten
years. (See Note 6 under Intangible Assets for more information.)
Interest Capitalized and Allowance For Funds Used During Construction
(AFUDC) -- AFUDC is a cost accounting procedure whereby amounts based upon
interest charges on borrowed funds and a return on equity capital used to
finance construction are added to utility plant and equipment being constructed.
Prior to July 1, 1999, AFUDC was capitalized for all expenditures for ongoing
construction work in progress and nuclear fuel in process not otherwise included
in rate base by regulatory authorities. As a result of the 1999 Restructuring
Legislation, only interest is capitalized during any generation construction
since 1999. Interest and AFUDC related to debt for businesses that still apply
SFAS 71 are capitalized as a component of projects under construction. Interest
on qualifying projects for businesses that no longer apply SFAS 71 is
capitalized in accordance with SFAS 34. See Note 18 for detail of amounts. AFUDC
capitalized totaled $15 million and $14 million in 2003 and 2002, respectively,
and included interest of $11 million in both years.
Impairment of Long-Lived Assets -- US Holdings evaluates the carrying
value of long-lived assets to be held and used when events and circumstances
warrant such a review. The carrying value of long-lived assets would be
considered impaired when the projected undiscounted cash flows are less than the
carrying value. In that event, a loss would be recognized based on the amount by
which the carrying value exceeds the fair value. Fair value is determined
primarily by available market valuations or, if applicable, discounted cash
flows.
In 2002, TXU Energy recorded an impairment charge of $237 million ($154
million after-tax) for the writedown of two generation plant construction
projects as a result of weaker wholesale electricity market conditions and
reduced planned developmental capital spending. Fair value was determined based
on appraisals of property and equipment. The charge is reported in other
deductions.
Goodwill and Intangible Assets -- US Holdings evaluates goodwill for
impairment at least annually (as of October 1) in accordance with SFAS No. 142.
The impairment tests performed are based on discounted cash flow analyses. Such
analyses require a significant number of estimates and assumptions regarding
future earnings, working capital requirements, capital expenditures, discount
rate, terminal year growth factor and other modeling factors. No goodwill
impairment has been recognized for consolidated reporting units reflected in
results from continuing operations.
Major Maintenance -- Major maintenance outage costs related to nuclear
fuel reloads, as well as the costs of other major maintenance programs, are
charged to expense as incurred.
Amortization of Nuclear Fuel -- The amortization of nuclear fuel in the
reactors is calculated on the units-of-production method and is included in cost
of energy sold.
Defined Benefit Pension Plans and Other Postretirement Benefit Plans-- US
Holdings is a participating employer in the defined benefit pension plan
sponsored by TXU Corp. US Holdings 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. See Note 12 for information regarding retirement plans and
other postretirement benefits.
Franchise and Revenue-Based Taxes -- Franchise and revenue-based taxes
such as gross receipts taxes are not a "pass through" item such as sales and
excise taxes. Gross receipts taxes are assessed to US Holdings and its
subsidiaries by state and local governmental bodies, based on revenues, as a
cost of doing business. US Holdings records gross receipts tax as an expense.
Rates charged to customers by US Holdings are intended to recover the taxes, but
US Holdings is not acting as an agent to collect the taxes from customers.
Income Taxes -- TXU Corp. and its US subsidiaries file a consolidated
federal income tax return, and federal income taxes are allocated to
subsidiaries based upon their respective taxable income or loss. Investment tax
credits are amortized to income over the estimated service lives of the
properties. Deferred income taxes are provided for temporary differences between
A-59
the book and tax basis of assets and liabilities. Certain provisions of SFAS 109
provide that regulated enterprises are permitted to recognize deferred taxes as
regulatory tax assets or tax liabilities if it is probable that such amounts
will be recovered from, or returned to, customers in future rates.
Cash Equivalents -- For purposes of reporting cash and cash equivalents,
temporary cash investments purchased with a remaining maturity of three months
or less are considered to be cash equivalents.
Changes in Accounting Standards -- In October 2002, the EITF, through EITF
02-3, rescinded EITF 98-10, which required mark-to-market accounting for all
trading activities. SFAS 143, regarding asset retirement obligations, became
effective on January 1, 2003. As a result of the implementation of these two
accounting standards, US Holdings recorded a cumulative effect of changes in
accounting principles as of January 1, 2003. (See Note 2 for a discussion of the
impacts of these two accounting standards.)
As a result of guidance provided in EITF 02-3, in 2003 TXU Energy
discontinued recognizing origination gains on energy contracts. For 2002 and
2001, US Holdings recognized $40 million and $88 million in origination gains on
retail sales contracts, respectively. Because of the short-term nature of these
contracts, a portion of these gains would have been recognized on a settlement
basis in the year the origination gain was recorded.
SFAS 146 became effective on January 1, 2003. SFAS 146 requires that a
liability for costs associated with an exit or disposal activity be recognized
only when the liability is incurred and measured initially at fair value. The
adoption of SFAS 146 did not materially impact results of operations for 2003.
FIN 45 was issued in November 2002 and requires recording the fair value
of guarantees upon issuance or modification after December 31, 2002. The
interpretation also requires expanded disclosures of guarantees (see Note 16
under Guarantees). The adoption of FIN 45 did not materially impact results of
operations for 2003.
FIN 46, which was issued in January 2003, provides guidance related to
identifying variable interest entities and determining whether such entities
should be consolidated. On October 8, 2003, the FASB decided to defer
implementation of FIN 46 until the fourth quarter of 2003. This deferral only
applies to variable interest entities that existed prior to February 1, 2003.
The implementation of FIN 46 in the fourth quarter 2003 did not impact results
of operations.
SFAS 149 was issued in April 2003 and became effective for contracts
entered into or modified after June 30, 2003. SFAS 149 clarifies what contracts
may be eligible for the normal purchase and sale exception, the definition of a
derivative and the treatment in the statement of cash flows when a derivative
contains a financing component. Also, EITF 03-11 was issued in July 2003 and
became effective October 1, 2003 and, among other things, discussed the nature
of certain power contracts. As a result of the issuance of SFAS 149 and EITF
03-11, certain commodity contract hedges were replaced with another type of
hedge that is subject to effectiveness testing. The adoption of these changes
did not materially impact results of operations for 2003.
SFAS 150 was issued in May 2003 and became effective June 1, 2003 for new
financial instruments and July 1, 2003 for existing financial instruments. SFAS
150 requires that mandatorily redeemable preferred securities be classified as
liabilities beginning July 1, 2003. In July 2003, TXU Energy exercised its right
to exchange its $750 million 9% Exchangeable Subordinated Notes due 2012 for
exchangeable preferred membership interests with identical economic and other
terms (see Note 9). Because the exchangeability feature of these preferred
securities provides for the holders to exchange the securities with TXU Corp.
for TXU Corp. common stock, the securities are deemed to be mandatorily
redeemable by TXU Energy. Therefore, in accordance with SFAS 150, the December
31, 2003 balance sheet reflects the classification of these securities (net of
$253 million in unamortized discount) as liabilities.
EITF 03-11 also addressed the presentation in the income statement of
physically settled commodity derivatives, providing guidance as to whether such
transactions should be reported on a net or gross (sales and cost of sales)
basis. Effective October 1, 2003, US Holdings began reporting certain retail
sales of natural gas to business customers on a gross basis. The effect of this
change was an increase in revenues and cost of energy sold of $34 million for
the period since that date. Net income was unaffected by the change.
A-60
EITF 01-8 was issued in May 2003 and is effective prospectively for
arrangements that are new, modified or committed to beginning July 1, 2003. This
guidance requires that certain types of arrangements be accounted for as leases,
including tolling and power supply contracts, take-or-pay contracts and service
contracts involving the use of specific property and equipment. The adoption of
this change did not materially impact results of operations for 2003.
In November 2003, the EITF reached a consensus on Issue 03-1 that certain
disclosures should be required for debt and marketable equity securities
classified as available-for-sale or held-to-maturity that are temporarily
impaired at the balance sheet date. See Note 5 under Analysis of Certain
Investments with Unrealized Losses for the required disclosures.
2. CUMULATIVE EFFECT OF CHANGES IN ACCOUNTING PRINCIPLES
The following summarizes the effect on results for 2003 for changes in
accounting principles effective January 1, 2003:
Charge from rescission of EITF 98-10, net of tax effect of
$34 million................................................. $(63)
Credit from adoption of SFAS 143, net of tax effect of $3 million 5
----
Total net charge............................................ $(58)
=====
On October 25, 2002, the EITF, through EITF 02-3, rescinded EITF 98-10,
which required mark-to-market accounting for all trading activities. Pursuant to
this rescission, only financial instruments that are derivatives under SFAS 133
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 US Holdings, 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) US Holdings had
previously recorded as depreciation expense and $26 million (reflected in other
noncurrent liabilities) of unrealized net gains associated with the
decommissioning trusts.
The following table summarizes the impact as of January 1, 2003 of
adopting SFAS 143:
Increase in property, plant and equipment - net......... $488
Increase in other noncurrent liabilities and deferred
credits ............................................... (528)
Increase in accumulated deferred income taxes........... (3)
Increase in regulatory assets - net..................... 48
----
Cumulative effect of change in accounting principles.... $ 5
====
A-61
The asset retirement liability at December 31, 2003 was $599 million,
comprised of a $554 million liability as a result of adoption of SFAS 143, $36
million of accretion during the twelve months of 2003 and $2 million in new
asset retirement obligations, reduced by $19 million in reclamation payments.
The asset retirement obligations were adjusted upward by $26 million, or 5%, due
to revisions in estimated cash flows.
With respect to nuclear decommissioning costs, US Holdings believes that
the adoption of SFAS 143 results primarily in timing differences in the
recognition of asset retirement costs that TXU Energy is currently recovering
through the regulatory process.
On a pro forma basis, assuming SFAS 143 had been adopted at the beginning
of the period, earnings for 2002 would have increased by $6.5 million after-tax,
and the liability for asset retirement obligations as of December 31, 2001 and
2002 would have been $522 million and $554 million, respectively. Earnings for
the year ended December 31, 2001 would not have been impacted by the adoption of
SFAS 143.
3. DISCONTINUED OPERATIONS
In December 2003, US Holdings approved a plan to sell its strategic retail
services business, which is engaged principally in providing energy management
services to businesses and other organizations and was reported as part of the
TXU Energy segment. Results of discontinued operations reflect a charge in the
fourth quarter of 2003 of $10.3 million ($6.7 million after-tax) to impair
long-lived assets and accrue liabilities under operating leases from which there
will be no future benefit as a result of the decision to exit the business.
The following summarizes the historical consolidated financial information
of the strategic retail services business to be sold:
Year Ended December 31,
--------------------------------
2003 2002 2001
---- ---- ----
(millions of dollars)
Operating revenues................................................ $ 60 $ 47 $ 54
Operating costs and expenses...................................... 60 122 94
Other deductions - net............................................ 11 - 2
Interest income................................................... (1) - -
Interest expense and related charges.............................. 1 1 1
------- ------ ------
Loss before income taxes.......................................... (11) (76) (43)
Income tax benefit................................................ (4) (27) (15)
Charge related to exit (after-tax)................................ 7 - -
------- ------ ------
Loss from discontinued operations............................ $ (14) $ (49) $ (28)
======== ======= ======
Balance sheet - The following details the assets held for sale:
December 31,
2003
----
Current assets................................................................................... $ 3
Investments...................................................................................... 4
Property, plant and equipment.................................................................... 5
Other noncurrent assets.......................................................................... 2
--------
Assets held for sale....................................................................... $ 14
========
4. EXTRAORDINARY LOSS
As a result of the implementation of SFAS 145, losses related to early
extinguishments of debt that were previously reported as extraordinary items
have been reclassified (see Note 1 under Losses on Extinguishments of Debt).
A-62
In the fourth quarter of 2001, US Holdings and the Commission reached
agreement on the Settlement Plan, which resolved a number of issues related to
transition to retail competition. As a result, US Holdings recorded an
extraordinary loss of $57 million (net of income tax benefit of $63 million).
The loss was classified as an extraordinary item in accordance with SFAS No.
101, "Regulated Enterprises - Accounting for the Discontinuance of the
Application of FASB Statement No. 71." The Settlement Plan addressed, among
other items, unrecovered fuel cost, stranded costs and other generation-related
regulatory assets, and the above-market pricing of certain power purchase
contracts. See also Note 15.
The Settlement Plan also addressed the issuance of securitization bonds to
recover regulatory asset stranded costs. The Commission's financing order
related to the bonds was appealed by certain non-settling parties. In January
2003, the appeals were settled and the financing order became final and
non-appealable. The financing order authorized the issuance of securitization
bonds with a principal amount of up to $1.3 billion. As a result of the appeals
being settled, in the fourth quarter of 2002, US Holdings recorded an
extraordinary loss of $134 million (net of income tax benefit of $72 million)
principally to write down the regulatory assets to$1.7 billion to reflect lower
estimated cash flows to be recovered from REPs to service the principal and
interest of the bonds.
5. INVESTMENTS
The following information is a summary of the investment balance as of
December 31, 2003 and 2002:
December 31,
--------------------
2003 2002
---- ----
Nuclear decommissioning trust................................. $ 323 $ 266
Land.......................................................... 89 90
Assets related to employee benefit plans...................... 69 53
Miscellaneous other........................................... 29 18
------ ------
Total investments........................................... $ 510 $ 427
====== ======
Nuclear Decommissioning Trust -- Deposits in a trust fund for costs to
decommission the Comanche Peak nuclear-powered generation plant are carried at
fair value, with the cumulative increase in fair value recorded as a liability.
(Also see Note 16 - under Nuclear Decommissioning). Decommissioning costs are
being recovered from Oncor's customers as a transmission and distribution charge
over the life of the plant and deposited in the trust fund. Activity in the
trust fund was as follows:
December 31, 2003
------------------------------------------------------------------------
Cost Unrealized gain Unrealized (loss) Fair market value
---- --------------- ----------------- -----------------
Debt securities............ $ 139 $ 6 $ (2) $ 143
Equity securities.......... 126 66 (12) 180
------- ------ ------- -------
$ 265 $ 72 $ (14) $ 323
======= ====== ======= =======
Debt securities held at December 31, 2003 mature as follows: $56 million
in one to five years, $51 million in five to ten years and $36 million after ten
years.
Analysis of Certain Investments with Unrealized Losses at December 31, 2003:
Investments That Have Been in a Continuous Unrealized Loss Position for:
--------------------------------------------------------------------------------
Less than 12 months 12 months or longer Total
------------------------- -------------------------- ---------------------------
Description of Securities Fair Unrealized Fair Unrealized Fair Unrealized
Value Losses Value Losses Value Losses
- --------------------------------------- ----------- ------------- ----------- -------------- ------------ --------------
Nuclear Decommissioning Trust:
Debt Securities............... $ 12 $ -- $ 19 $ (2) $ 31 $ (2)
Equity securities............. 4 (1) 24 (11) 28 (12)
----- ------ ----- ------ ------ -------
Total ................... $ 16 $ (1) $ 43 $ (13) $ 59 $ (14)
===== ====== ===== ====== ====== =======
A-63
The assets that have experienced unrealized losses are all high-quality
securities that are part of the long-term investment strategy and are expected
to recover within a reasonable period of time. Therefore they are not deemed to
be other-than-temporary impairments.
6. GOODWILL AND OTHER INTANGIBLE ASSETS
SFAS 142 became effective for US Holdings on January 1, 2002. SFAS 142
requires, among other things, the allocation of goodwill to reporting units
based upon the current fair value of the reporting units, and the discontinuance
of goodwill amortization. The amortization of US Holdings' existing goodwill
($15 million annually) ceased effective January 1, 2002. SFAS 142 also requires
additional disclosures regarding intangible assets (other than goodwill) that
are amortized or not amortized:
As of December 31, 2003 As of December 31, 2002
----------------------------- -----------------------------
Gross 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............... $ 400 $184 $ 216 $368 $131 $237
Land easements..................... 176 66 110 180 61 119
Mineral rights and other........... 31 22 9 31 20 11
----- ---- ----- ---- ---- ----
Total......................... $ 607 $272 $ 335 $579 $212 $367
===== ==== ===== ==== ==== ====
Aggregate US Holdings amortization expense for intangible assets,
excluding goodwill, for the years ended December 31, 2003, 2002 and 2001 was $62
million, $63 million and $14 million, respectively. At December 31, 2003, the
weighted average useful lives of capitalized software, land easements and
mineral rights noted above were 6 years, 69 years and 40 years, respectively.
Estimated amounts for the next five years are as follows:
Amortization
Year Expense
- ---- -------
2004................................... $ 58
2005................................... 46
2006................................... 41
2007................................... 38
2008................................... 21
Goodwill -- At December 31, 2003 and 2002, goodwill of $558 million was
stated net of previously recorded accumulated amortization of $67 million. In
connection with the transfer of certain businesses from TXU Gas to TXU Energy as
part of the business restructuring disclosed in Note 1, $468 million of goodwill
arising from TXU Corp.'s 1997 acquisition of ENSERCH Corporation was allocated
to these businesses and is reflected in the balance sheet of US Holdings.
7. SHORT-TERM FINANCING
Short-term Borrowings -- At December 31, 2003, US Holdings had outstanding
short-term borrowings consisting of advances from affiliates of $691 million. At
December 31, 2002, outstanding short-term bank borrowings were $1.8 billion and
advances from affiliates were $787 million. Weighted average interest rates on
short-term borrowings were 2.92% and 2.44% at December 31, 2003 and 2002,
respectively.
A-64
Credit Facilities -- At December 31, 2003, credit facilities available to
TXU Corp. and its US subsidiaries were as follows:
At December 31, 2003
--------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
-------- --------------- --------- ----- ------ ---------- ------------
Five-Year Revolving Credit Facility February 2005 US Holdings $ 1,400 $ 44 $ -- $1,356
Revolving Credit Facility February 2005 TXU Energy, Oncor 450 -- -- 450
Three-Year Revolving Credit Facility May 2005 US Holdings (a) 400 -- -- 400
Five-Year Revolving Credit Facility August 2008 TXU Corp. 500 422 -- 78
------- ------ ------ ------
Total $ 2,750 $ 466 $ -- $2,284
======= ====== ====== ======
(a) Previously TXU Corp.
In August 2003, TXU Corp. entered into the $500 million 5-year revolving
credit facility that provides for up to $500 million in letters of credit or up
to $250 million of loans ($500 million in the aggregate).
In April 2003, TXU Energy and Oncor entered into a joint $450 million
revolving credit facility to be used for working capital and other general
corporate purposes. Up to $450 million of letters of credit may be issued under
the facility.
The $1.4 billion facility provides for up to $1.0 billion in letters of
credit.
The US Holdings, TXU Energy and Oncor facilities provide back-up for any
future issuance of commercial paper by TXU Energy and Oncor. At December 31,
2003, there was no such outstanding commercial paper.
In addition to providing back-up of commercial paper issuance by TXU
Energy and Oncor, the credit facilities above are for general corporate and
working capital purposes, including providing collateral support for TXU
Energy's hedging and risk management activities.
Sale of Receivables -- TXU Corp. has established an accounts receivable
securitization program. The activity under this program is accounted for as a
sale of accounts receivable in accordance with SFAS 140. Under the program, US
subsidiaries of TXU Corp. (originators) sell trade accounts receivable to TXU
Receivables Company, a consolidated wholly-owned bankruptcy remote direct
subsidiary of TXU Corp., which sells undivided interests in the purchased
accounts receivable for cash to special purpose entities established by
financial institutions (the funding entities). As of December 31, 2003, the
maximum amount of undivided interests that could be sold by TXU Receivables
Company was $600 million.
All new trade receivables under the program generated by the originators
are continuously purchased by TXU Receivables Company with the proceeds from
collections of receivables previously purchased. Changes in the amount of
funding under the program, through changes in the amount of undivided interests
sold by TXU Receivables Company, are generally due to seasonal variations in the
level of accounts receivable and changes in collection trends. TXU Receivables
Company has issued subordinated notes payable to the originators for the
difference between the face amount of the uncollected accounts receivable
purchased, less a discount, and cash paid to the originators that was funded by
the sale of the undivided interests.
The discount from face amount on the purchase of receivables 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 Company,
a direct subsidiary of TXU Corp. The program fees (losses on sale), which
consist primarily of interest costs on the underlying financing, were $11
million and $21 million for 2003 and 2002, respectively, and approximated 2.6%
and 3.7% for 2003 and 2002, respectively, of the average funding under the
program on an annualized basis; these fees represent the net incremental costs
of the program to US Holdings and are reported in SG&A expenses. The servicing
fee, which totaled $4 million and $7 million for 2003 and 2002, respectively,
compensates TXU Business Services Company for its services as collection agent,
including maintaining the detailed accounts receivable collection records.
A-65
The December 31, 2003 balance sheet reflects $1.0 billion face amount of
trade accounts receivable of TXU Energy and Oncor, reduced by $547 million of
undivided interests sold by TXU Receivables Company. Funding under the program
increased $100 million for the year ended December 31, 2003, primarily due to
the effect of improved collection trends at TXU Energy. Funding under the
program for the year ended December 31, 2002 decreased $15 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 US Holdings for the years
ended December 31, 2003 and 2002 were as follows:
Year Ended December 31,
---------------------
2003 2002
---- ----
(millions of dollars)
Cash collections on accounts receivable........................... $ 7,194 $5,836
Face amount of new receivables purchased.......................... (6,777) (6,534)
Discount from face amount of purchased receivables................ 18 29
Servicing fees paid............................................... (4) (7)
Program fees paid................................................. (11) (21)
Increase (decrease) in subordinated notes payable................. (520) 712
------- ------
Operating cash flows (provided) used under the program....... $ (100) $ 15
======= ======
Activity for 2001 is not shown in the table above since the current sale
of receivables program began in August 2001 and information for the full year is
not available.
Upon termination of the program, cash flows to US Holdings would be
delayed as collections of sold receivables would be used by TXU Receivables
Company to repurchase the undivided interests sold instead of purchasing new
receivables. The level of cash flows would normalize in approximately 16 to 31
days.
In June 2003, the program was amended to provide temporarily higher
delinquency and default compliance ratios and temporary relief from the loss
reserve formula, which allowed for increased funding under the program. The June
amendment reflected the billing and collection delays previously experienced as
a result of new systems and processes in TXU Energy and ERCOT for clearing
customers' switching and billing data upon the transition to competition. In
August 2003, the program was amended to extend the term to July 2004, as well as
to extend the period providing temporarily higher delinquency and default
compliance ratios through December 31, 2003. The higher delinquency and default
compliance ratios were not extended after December 31, 2003 as no relief from
program delinquency and default compliance ratios is expected to be required.
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 TXU Energy and ERCOT for clearing customers' switching and
billing data. The billing delays have been largely resolved. Strengthened credit
and collection policies and practices have brought the ratios into consistent
compliance with the program requirement.
A-66
Under terms of the receivables sale program, all the originators are
required to maintain specified fixed charge coverage and leverage ratios (or
supply a parent guarantor that meets the ratio requirements). The failure by an
originator or its parent guarantor, if any, to maintain the specified financial
ratios would prevent that originator from selling its accounts receivable under
the program. If all the originators and the parent guarantor, if any, fail to
maintain the specified financial ratios so that there are no eligible
originators, the facility would terminate. Prior to the August 2003 amendment
extending the program, originator eligibility was predicated on the maintenance
of an investment grade credit rating.
8. LONG-TERM DEBT
Long-Term Debt -- At December 31, 2003 and 2002, the long-term debt of US
Holdings and its consolidated subsidiaries consisted of the following:
December 31, December 31,
2003 2002
---- ----
TXU Energy
----------
Pollution Control Revenue Bonds:
Brazos River Authority:
Floating Taxable Series 1993 due June 1, 2023.................................... $ -- $ 44
3.000% Fixed Series 1994A due May 1, 2029, remarketing date May 1, 2005(a)....... 39 39
5.400% Fixed Series 1994B due May 1, 2029, remarketing date May 1, 2006(a)....... 39 39
5.400% Fixed Series 1995A due April 1, 2030, remarketing date May 1, 2006(a)..... 50 50
5.050% Fixed Series 1995B due June 1, 2030, remarketing date June 19, 2006(a).... 118 118
7.700% Fixed Series 1999A due April 1, 2033...................................... 111 111
6.750% Fixed Series 1999B due September 1, 2034, remarketing date April 1,
2013(a)........................................................................ 16 16
7.700% Fixed Series 1999C due March 1, 2032...................................... 50 50
4.950% Fixed Series 2001A due October 1, 2030, remarketing date April 1, 2004(a). 121 121
4.750% Fixed Series 2001B due May 1, 2029, remarketing date November 1, 2006(a).. 19 19
5.750% Fixed Series 2001C due May 1, 2036, remarketing date November 1, 2011(a).. 274 274
1.250% Floating Series 2001D due May 1, 2033..................................... 271 271
Floating Taxable Series 2001F due December 31, 2036.............................. -- 39
Floating Taxable Series 2001G due December 1, 2036............................... -- 72
Floating Taxable Series 2001H due December 1, 2036............................... -- 31
1.180% Floating Taxable Series 2001I due December 1, 2036(b)..................... 63 63
1.250% Floating Series 2002A due May 1, 2037(b).................................. 61 61
6.750% Fixed Series 2003A due April 1, 2038, remarketing date April 1, 2013(a)... 44 --
6.300% Fixed Series 2003B due July 1, 2032....................................... 39 --
6.750% Fixed Series 2003C due October 1, 2038.................................... 72 --
5.400% Fixed Series 2003D due October 1, 2029, remarketing date October 1,
2014(a)........................................................................ 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
4.000% Fixed Series 2001C due May 1, 2028, remarketing date November 1, 2003(a).. -- 70
Floating Taxable Series 2001D due December 31, 2036.............................. -- 12
Floating Taxable Series 2001E due December 31, 2036.............................. -- 45
5.800% Fixed Series 2003A due July 1, 2022....................................... 12 --
6.150% Fixed Series 2003B due August 1, 2022..................................... 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:
7.000% Fixed Senior Notes - TXU Mining due May 1, 2003........................... -- 72
6.875% Fixed Senior Notes - TXU Mining due August 1, 2005........................ 30 30
9.000% Fixed Exchangeable Subordinated Notes due November 22, 2012............... -- 750
6.125% Fixed Senior Notes due March 15, 2008..................................... 250 --
7.000% Fixed Senior Notes due March 15, 2013 (c)................................. 1,000 --
Capital lease obligations........................................................ 13 10
Other............................................................................ 8 8
Unamortized premium and discount and fair value adjustments...................... 9 (264)
------- -------
Total TXU Energy ............................................................ 3,085 2,451
A-67
December 31, December 31,
2003 2002
---- ----
Oncor
- -----
9.530% Fixed Medium Term Secured Notes due January 30, 2003...................... $ -- $ 4
9.700% Fixed Medium Term Secured Notes due February 28, 2003..................... -- 11
6.750% Fixed First Mortgage Bonds due March 1, 2003.............................. -- 133
6.750% Fixed First Mortgage Bonds due April 1, 2003.............................. -- 70
8.250% Fixed First Mortgage Bonds due April 1, 2004.............................. 100 100
6.250% Fixed First Mortgage Bonds due October 1, 2004............................ 121 121
6.750% Fixed First Mortgage Bonds due July 1, 2005............................... 92 92
7.875% Fixed First Mortgage Bonds due March 1, 2023.............................. -- 224
8.750% Fixed First Mortgage Bonds due November 1, 2023........................... -- 103
7.875% Fixed First Mortgage Bonds due April 1, 2024.............................. -- 133
7.625% Fixed First Mortgage Bonds due July 1, 2025............................... 215 215
7.375% Fixed First Mortgage Bonds due October 1, 2025............................ 178 178
6.375% Fixed Senior Secured Notes due May 1, 2012................................ 700 700
7.000% Fixed Senior Secured Notes due May 1, 2032................................ 500 500
6.375% Fixed Senior Secured Notes due January 15, 2015........................... 500 500
7.250% Fixed Senior Secured Notes due January 15, 2033........................... 350 350
5.000% Fixed Debentures due September 1, 2007.................................... 200 200
7.000% Fixed Debentures due September 1, 2022.................................... 800 800
Unamortized premium and discount................................................. (30) (35)
Oncor Electric Delivery Transition Bond Company LLC(e)
- ------------------------------------------------------
2.260% Fixed Series 2003 Bonds due in bi-annual installments through
February 15, 2007............................................................... 103 --
4.030% Fixed Series 2003 Bonds due in bi-annual installments through
February 15, 2010............................................................... 122 --
4.950% Fixed Series 2003 Bonds due in bi-annual installments through
February 15, 2013............................................................... 130 --
5.420% Fixed Series 2003 Bonds due in bi-annual installments through
August 15, 2015................................................................. 145 --
------- -------
Total Oncor................................................................... 4,226 4,399
US Holdings
- -----------
7.170% Fixed Senior Debentures due August 1, 2007................................. 10 10
9.580% Fixed Notes due in bi-annual installments through December 4, 2019......... 70 73
8.254% Fixed Notes due in quarterly installments through December 31, 2021........ 66 68
1.910% Floating Rate Junior Subordinated Debentures, Series D due
January 30, 2037(d)............................................................. 1 1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037........ 8 8
------- -------
Total US Holdings ............................................................ 155 160
Total US Holdings consolidated........................................................ 7,466 7,010
Less amount due currently........................................................... 249 397
------- -------
Total long-term debt................................................................ $ 7,217 $ 6,613
======= =======
- ------------------------------
(a) These series are in the multiannual mode and are subject to mandatory
tender prior to maturity on the mandatory remarketing date. On such date,
the interest rate and interest rate period will be reset for the bonds.
(b) Interest rates in effect at December 31, 2003. These series are in a
flexible or weekly rate mode and are classified as long-term as they are
supported by long-term irrevocable letters of credit. Series in the
flexible mode will be remarketed for periods of less than 270 days.
(c) Interest rates swapped to floating on $500 million principal amount.
(d) Interest rates in effect at December 31, 2003.
(e) Bond principal amounts total $500 million, and the bonds are nonrecourse
to Oncor.
A-68
New Debt Issuances in 2003:
In August 2003, Oncor issued $500 million aggregate principal amount of
transition (securitization) bonds in accordance with the Settlement Plan. The
bonds were issued in four classes that require bi-annual interest and principal
installment payments beginning in 2004 through specified dates in 2007 through
2015. The bonds bear interest at fixed annual rates ranging from 2.26% to 5.42%.
A second issuance of approximately $790 million is expected to be completed in
the first half of 2004.
In March 2003, TXU Energy issued $1.25 billion aggregate principal amount
of senior unsecured notes in two series in a private placement with registration
rights. One series in the amount of $250 million is due March 15, 2008, and
bears interest at the annual rate of 6.125%, and the other series in the amount
of $1 billion is due March 15, 2013, and bears interest at the annual rate of
7%. In August 2003, TXU Energy entered into interest rate swap transactions
through 2013, which are being accounted for as fair value hedges, to effectively
convert $500 million of the notes to floating interest rates.
Debt Repayments in 2003:
In September 2003, Oncor redeemed the $224 million aggregate principal
amount of its 7 7/8% First Mortgage Bonds due March 1, 2023 and $133 million
principal amount of its 7 7/8% First Mortgage Bonds due April 1, 2024.
In May 2003, $72 million principal amount of the 7% TXU Mining fixed rate
senior notes were repaid at maturity.
In April 2003, Oncor repaid the $70 million principal amount of its First
Mortgage Bonds, 6.75% Series, at the maturity date for par value plus accrued
interest. A restricted cash deposit of $72 million was utilized to fund the
maturity.
In March 2003, Oncor repaid the $133 million principal amount of its First
Mortgage Bonds, 6.75% Series, at the maturity date for par value plus accrued
interest. A restricted cash deposit of $138 million was utilized to fund the
maturity.
In March 2003, Oncor redeemed $103 million principal amount of its First
Mortgage and Collateral Trust Bonds, 8.75% Series due November 1, 2023, at
104.01% of the principal amount thereof, plus accrued interest to the redemption
date.
Oncor's $4 million and $11 million medium term secured notes were repaid
in January and February 2003, respectively, at maturity for par value plus
accrued interest.
Debt Remarketings and Other Activity:
In November 2003, the Brazos River Authority Series 2001D pollution
control revenue bonds (aggregate principal amount of $271 million) were
remarketed and converted from a multiannual mode to a weekly rate mode, and the
Sabine River Authority Series 2001C pollution control revenue bonds (aggregate
principal amount of $70 million) were purchased upon mandatory tender. US
Holdings intends to remarket these bonds in the first half of 2004.
In October 2003, the Brazos River Authority issued $72 million aggregate
principal amount of Series 2003C pollution control revenue bonds and $31 million
aggregate principal amount of Series 2003D pollution control revenue bonds for
TXU Energy. The Series 2003C bonds will bear interest at an annual rate of 6.75%
until maturity in 2038. The Series 2003D bonds will bear interest at an annual
rate of 5.40% until their mandatory tender date in 2014, at which time they will
be remarketed. Proceeds from the issuance of the Series 2003C and Series 2003D
bonds were used to refund the $72 million aggregate principal amount of Brazos
River Authority Taxable Series 2001G and the $31 million aggregate principal
amount of Series 2001H variable rate pollution control revenue bonds, both due
December 1, 2036. The Sabine River Authority also issued $45 million aggregate
principal amount of Series 2003B pollution control revenue bonds for TXU Energy.
The Series 2003B bonds will bear interest at an annual rate of 6.15% until
maturity in 2022, however they become callable in 2013. Proceeds from the
issuance of the Series 2003B bonds were used to refund the $45 million aggregate
principal amount of Sabine River Authority Taxable Series 2001E variable rate
pollution control revenue bonds due December 1, 2036.
A-69
In July 2003, the Brazos River Authority issued $39 million aggregate
principal amount of Series 2003B pollution control revenue bonds for TXU Energy.
The bonds will bear interest at an annual rate of 6.30% until maturity in 2032.
Proceeds from the issuance of the bonds were used to refund the $39 million
aggregate principal amount of Brazos River Authority Taxable Series 2001F
variable rate pollution control revenue bonds due December 31, 2036. The Sabine
River Authority also issued $12 million aggregate principal amount of Series
2003A pollution control revenue bonds for TXU Energy. The bonds will bear
interest at an annual rate of 5.80% until maturity in 2022. Proceeds from the
issuance of these bonds were used to refund the $12 million aggregate principal
amount of Sabine River Authority Taxable Series 2001D pollution control revenue
bonds due December 31, 2036.
In May 2003, the Brazos River Authority Series 1994A and the Trinity River
Authority Series 2000A pollution control revenue bonds (aggregate principal
amount of $53 million) were purchased upon mandatory tender. In July 2003, the
bonds were remarketed and converted from a floating rate mode to a multiannual
mode at an annual rate of 3.00% and 6.25%, respectively. The rate on the 1994A
bonds will remain in effect until their mandatory remarketing date of May 1,
2005. The rate on the 2000A bonds will remain in effect until their maturity in
2028.
In April 2003, the Brazos River Authority Series 1999A pollution control
revenue bonds, with an aggregate principal amount of $111 million, were
remarketed. The bonds now bear interest at a fixed annual rate of 7.70% and are
callable beginning on April 1, 2013 at a price of 101% until March 31, 2014 and
at 100% thereafter.
In March 2003, the Brazos River Authority Series 1999B and 1999C pollution
control revenue bonds (aggregate principal amount of $66 million) were converted
from a floating rate mode to a multiannual mode at an annual rate of 6.75% and a
fixed rate of 7.70%, respectively. The rate on the 1999B bonds will remain in
effect until 2013 at which time they will be remarketed. The rate on the 1999C
bonds is fixed to maturity in 2032, however they become callable in 2013.
In March 2003, the Brazos River Authority issued $44 million aggregate
principal amount of pollution control revenue bonds Series 2003A for TXU Energy.
The bonds will bear interest at an annual rate of 6.75% until the mandatory
tender date of April 1, 2013. On April 1, 2013, the bonds will be remarketed.
Proceeds from the issuance of the bonds were used to repay the $44 million
principal amount of Brazos River Authority Series 1993 pollution control revenue
bonds due June 1, 2023.
The pollution control series variable rate debt of TXU Energy requires
periodic remarketing. Because TXU Energy intends to remarket these obligations,
and has the ability and intent to refinance if necessary, they have been
classified as long-term debt.
Debt Issuances and Retirements in 2002:
In 2002, US Holdings and its consolidated subsidiaries issued $2.0 billion
of senior secured notes, $1.0 billion of fixed rate debentures and $750 million
of exchangeable subordinated notes and redeemed $1.0 billion of first mortgage
bonds and $1.5 billion of floating rate debentures.
Maturities -- Sinking fund and maturity requirements for all long-term
debt instruments, excluding capital lease obligations, in effect at December 31,
2003, were as follows:
Year
----
2004....................................................... $ 248
2005....................................................... 163
2006....................................................... 42
2007 ...................................................... 254
2008 ...................................................... 297
Thereafter................................................. 6,470
Unamortized premium and discount and fair value adjustments (21)
Capital lease obligations.................................. 13
-------
Total................................................ $ 7,466
=======
Exchangeable Preferred Membership Interests of TXU Energy -- In July 2003,
TXU 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 preferred membership
interests may be exchanged at the option of the holders, subject to certain
restrictions, at any time for up to approximately 57 million shares of TXU Corp.
A-70
common stock at an exchange price of $13.1242 per share. The number of shares of
TXU Corp. common stock that may be issuable upon the exercise of the exchange
right is determined by dividing the aggregate liquidation value of preferred
membership interests to be exchanged by the exchange price. The exchange price
and the number of shares to be issued are subject to anti-dilution adjustments.
At issuance of the notes that were exchanged for the preferred membership
interests, TXU Energy recognized a capital contribution for 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%. At the time of any exchange of the preferred
membership interests for common stock, the unamortized discount will be
proportionately written off as a charge to earnings. If all the membership
interests had been exchanged into common stock on December 31, 2003, the pre-tax
charge would have been $253 million. These securities are classified as
liabilities in accordance with SFAS 150. See Note 1 under Changes in Accounting
Standards.
The original purchasers of the notes that were exchanged for the preferred
membership interests were granted the right to nominate one member to the board
of directors of TXU Corp., and such nominee has been elected to fill a vacancy.
The original purchasers forfeit this right if they cease to hold at least 30% of
their original investment in the form of common stock and/or preferred
membership interests. In any event, this right expires on the later of (i)
November 2012 or, (ii) the date no membership interests remain outstanding. The
holders of the preferred membership interests are restricted from actions that
would increase their control of TXU Corp.
9. PREFERRED SECURITIES
December 31, 2003 December 31, 2002
----------------- -----------------
Shares(b) Shares(b) Redemption
Outstanding Amount Outstanding Amount Price Per Share
----------- ------ ----------- ------ ---------------
Not Subject to Mandatory Redemption (a):
- ----------------------------------------
$4.00 to $5.08 dividend rate series... 379 $ 38 379 $ 38 $101.79 to $112.00
$7.98 series.......................... -- -- 261 26
$7.50 series ......................... -- -- 308 30
$7.22 series ......................... -- -- 221 21
---- ----
Total ............................. $ 38 $115
==== ====
Subject to Mandatory Redemption(a):
$6.98 series.......................... -- $ -- 107 $ 11
$6.375 series......................... -- -- 100 10
---- ----
$ -- $ 21
==== ====
- --------------------------------
(a) Cumulative, without par value, entitled upon liquidation to $100 per
share; 17,000,000 total shares authorized.
(b) Shares in thousands.
The carrying value of preferred stock subject to mandatory redemption is
being increased periodically to equal the redemption amounts at the
mandatory redemption dates with a corresponding increase in preferred
stock dividends.
Preferred Stock of US Holdings - At December 31, 2003, US Holdings had
379,000 shares of cumulative, preferred stock without par value outstanding with
dividend rates ranging from $4.00 to $5.08 per share. The preferred stock can be
redeemed at prices ranging from $101.70 per share to $112.00 per share. In July
2003, US Holdings redeemed all of the shares of its $7.98 series, $7.50 series
and $7.22 series of preferred stock, which were not subject to mandatory
redemption, and the shares of its $6.98 series of preferred stock subject to
mandatory redemption for an aggregate principal amount of $91 million. In
September 2003, US Holdings called all of its $6.375 mandatorily redeemable
preferred stock for redemption, and on October 1, 2003 all of these shares were
redeemed for an aggregate principal amount of $7 million.
The holders of preferred stock of US Holdings have no voting rights except
for changes to the articles of incorporation that would change the rights or
preferences of such stock, authorize additional shares of stock or create an
equal or superior class of stock. They have the right to vote for the election
of directors only if certain dividend arrearages exist.
A-71
10. SHAREHOLDERS' EQUITY
US Holdings paid cash dividends of $927 million to TXU Corp.in 2002
and $588 million in 2003. US Holdings declared a cash dividend of $212 million
to TXU Corp. in 2003 payable in 2004.
The mortgage of Oncor restricts Oncor's payment of dividends to the amount
of its retained earnings.
11. INCOME TAXES
The components of US Holdings' provision for income taxes for continuing
operations are as follows:
Year Ended December 31,
---------------------------
2003 2002 2001
---- ---- ----
Current:
US Federal............................................................ $ 217 $ 183 $ 468
State................................................................. 9 3 41
Non-US................................................................ -- 1 (5)
----- ----- -----
Total.............................................................. 226 187 504
Deferred:
US Federal............................................................ 141 58 (118)
State................................................................. -- 4 (3)
Non-US................................................................ 1 -- (1)
----- ----- -----
Total.............................................................. 142 62 (122)
Investment tax credits.................................................. (22) (26) (23)
----- ----- -----
Total.............................................................. $ 346 $ 223 $ 359
===== ===== =====
Reconciliation of income taxes computed at the US federal statutory rate
to provision for income taxes:
Year Ended December 31,
-----------------------
2003 2002 2001
---- ---- ----
Income from continuing operations before income taxes, extraordinary loss
and cumulative effect of changes in accounting principles................ $ 1,078 $ 767 $1,161
======= ===== ======
Income taxes at the federal statutory rate of 35%......................... $ 377 $ 268 $ 406
Depletion allowance................................................... (25) (25) (25)
Amortization of investment tax credits................................ (22) (26) (23)
Amortization (under regulatory accounting) of statutory rate changes. (8) (8) (7)
Preferred securities costs............................................ 6 -- --
State income taxes, net of federal tax benefit........................ 6 5 25
Other................................................................. 12 9 (17)
----- ----- ------
Provision for income taxes................................................. $ 346 $ 223 $ 359
===== ===== ======
Effective tax rate (on income before preferred stock dividends)............ 32% 29% 31%
A-72
Deferred income taxes for significant temporary differences based on tax
laws in effect at December 31, 2003 and 2002 balance sheet dates are as follows:
December 31,
---------------------------------------------------------------------
2003 2002
-------------------------------- --------------------------------
Total Current Noncurrent Total Current Noncurrent
----- ------- ---------- ----- ------- ----------
Deferred Tax Assets
Unamortized investment tax credits.... $ 163 $ -- $ 163 $ 172 $ -- $ 172
Impairment of assets.................. 168 -- 168 181 -- 181
Nuclear asset retirement obligation... 150 -- 150 -- -- --
Retail clawback liability............. 61 -- 61 65 -- 65
Alternative minimum tax............... 452 -- 452 417 -- 417
Excess mitigation credit.............. -- -- -- 60 -- 60
Employee benefit liabilities.......... 181 -- 181 174 -- 174
State income taxes.................... 4 -- 4 2 -- 2
Other................................. 270 91 179 249 65 184
----- ----- -------- ------- ----- --------
Total............................... 1,449 91 1,358 1,320 65 1,255
Deferred Tax Liabilities
Depreciation differences and capitalized
construction costs.................. 3,949 -- 3,949 3,684 -- 3,684
Regulatory assets..................... 616 -- 616 615 -- 615
State income taxes.................... 43 -- 43 13 -- 13
Other................................. 171 18 153 170 -- 170
----- ----- -------- -------- ----- -------
Total............................... 4,779 18 4,761 4,482 -- 4,482
----- ----- -------- ------- ----- -------
Net Deferred Tax (Asset) Liability...... $3,330 $ (73) $ 3,403 $3,162 $ (65) $3,227
====== ===== ======== ====== ===== ======
At December 31, 2003, US Holdings had approximately $452 million of
alternative minimum tax credit carryforwards available to offset future tax
payments. These tax credit carryforwards do not have expiration dates.
US Holdings' income tax returns are subject to examination by applicable
tax authorities. The IRS is currently examining the returns of TXU Corp. and its
subsidiaries for the tax years ended 1993 through 2002. In management's opinion,
an adequate provision has been made for any future taxes that may be owed as a
result of any examination.
12. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS
TXU Energy and Oncor are participating employers in the TXU Retirement
Plan (Retirement Plan), a defined benefit pension plan sponsored by TXU Corp.
The Retirement Plan is a qualified pension plan under Section 401(a) of the
Internal Revenue Code of 1986, as amended (Code) and is subject to the
provisions of ERISA. Employees are eligible to participate in the Retirement
Plan upon their completion of one year of service and the attainment of age 21.
All benefits are funded by the participating employers. The Retirement Plan
provides benefits to participants under one of two formulas: (i) a cash balance
formula under which participants earn monthly contribution credits based on
their compensation and a combination of their age and years of service, plus
monthly interest credits, or (ii) a traditional defined benefit formula based on
years of service and the average earnings of the three years of highest
earnings.
All eligible employees hired after January 1, 2002, will participate under
the cash balance formula. Certain employees who, prior to January 1, 2002,
participated under the traditional defined benefit formula, continue their
participation under that formula. Under the cash balance formula, future
increases in earnings will not apply to prior service costs. It is TXU Corp.'s
policy to fund the plans on a current basis to the extent deductible under
existing federal tax regulations. Such contributions, when made, are intended to
provide not only for benefits attributed to service to date, but also those
expected to be earned in the future.
A-73
The allocated net periodic pension cost (benefit) applicable to TXU Energy
and Oncor was $25 million for 2003, ($4) million for 2002 and ($21) million for
2001. Contributions were $17 million, $9 million and $2 million in 2003, 2002
and 2001, respectively. The amounts provided represent allocations of the TXU
Corp. Retirement Plan to TXU Energy and Oncor.
In addition to the Retirement Plan, TXU Energy and Oncor participate with
TXU Corp. and certain other affiliated subsidiaries of TXU Corp. to offer
certain health care and life insurance benefits to eligible employees and their
eligible dependents upon the retirement of such employees. For employees
retiring on or after January 1, 2002, the retiree contributions required for
such coverage vary based on a formula depending on the retiree's age and years
of service. The estimated net periodic postretirement benefits cost other than
pensions applicable to US Holdings was $76 million for 2003, $62 million for
2002 and $52 million for 2001. Contributions paid by TXU Energy and Oncor to
fund postretirement benefits other than pensions were $41 million, $39 million
and $35 million in 2003, 2002 and 2001, respectively.
In addition, TXU Energy and Oncor employees are eligible to participate in
a qualified savings plan, the TXU Thrift Plan (Thrift Plan). This plan is a
participant-directed defined contribution profit sharing plan qualified under
Section 401(a) of the Code, and is subject to the provisions of ERISA. The
Thrift Plan includes an employee stock ownership component. Under the terms of
the Thrift Plan, as amended effective in 2002, employees who do not earn more
than the IRS threshold compensation limit used to determine highly compensated
employees may contribute, through pre-tax salary deferrals and/or after-tax
payroll deductions, the maximum amount of their regular salary or wages
permitted under law. Employees who earn more than such threshold may contribute
from 1% to 16% of their regular salary or wages. Employer matching contributions
are also made in an amount equal to 100% of the first 6% of employee
contributions for employees who are covered under the cash balance formula of
the Retirement Plan, and 75% of the first 6% of employee contributions for
employees who are covered under the traditional defined benefit formula of the
Retirement Plan. Employer matching contributions are invested in TXU Corp.
common stock. TXU Energy's and Oncor's contributions to the Thrift Plan,
aggregated $21 million in 2003, $22 million in 2002, and $12 million in 2001.
13. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and related estimated fair values of US Holdings'
significant financial instruments were as follows:
December 31, 2003 December 31, 2002
----------------- -----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------ ----- ------ -----
On balance sheet liabilities:
Long-term debt (including current maturities) (a)............ $7,453 $9,056 $6,514 $6,593
Exchangeable preferred membership interests of subsidiary,
net of discount (b)....................................... 497 1,580 486 1,076
Preferred stock subject to mandatory redemption.............. -- -- 21 15
Financial guarantees......................................... 2 1 -- --
Off balance sheet liabilities:
Financial guarantees......................................... -- 13 -- 81
(a)Excludes capital leases.
(b)Exchanged for preferred membership interests in 2003.
In accordance with SFAS No. 133, financial instruments that are
derivatives are recorded on the balance sheet at fair value.
The fair values of on balance sheet instruments are estimated at the
lesser of either the call price or the market value as determined by quoted
market prices, where available, or, where not available, at the present value of
future cash flows discounted at rates consistent with comparable maturities with
similar credit risk.
A-74
The fair value of each financial guarantee is based on the difference
between the credit spread of the entity responsible for the underlying
obligation and a financial counterparty applied, on a net present value basis,
to the notional amount of the guarantee.
The carrying amounts for financial assets classified as current assets
and the carrying amounts for financial liabilities classified as current
liabilities approximate fair value due to the short maturity of such
instruments. The fair values of other financial instruments for which carrying
amounts and fair values have not been presented are not materially different
than their related carrying amounts.
14. DERIVATIVE FINANCIAL INSTRUMENTS
For derivative instruments designated as cash flow hedges, US Holdings
recognized a net unrealized ineffectiveness gain of $6 million ($4 million
after-tax) in 2003 and a net loss of $41 million ($27 million after-tax) in
2002. The ineffectiveness gains and losses in 2003 and 2002 related to commodity
hedges and were reported as a component of revenues. In 2001, US Holdings
experienced net hedge ineffectiveness of $4 million ($3 million after-tax),
recorded as $1 million in interest expense and a $5 million ($3 million
after-tax) increase in revenues.
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 $36 million in net gains in 2003 and $41
million in net losses in 2002.
The maximum length of time US Holdings hedges its exposure to the
variability of future cash flows for forecasted energy-related transactions is
approximately four years.
Cash flow hedge amounts reported in accumulated other comprehensive income
will be recognized in earnings as the related forecasted transactions are
settled or are deemed to be no longer probable of occurring. No amounts were
reclassified into earnings in 2003, 2002, or 2001 as a result of the
discontinuance of cash flow hedges because of the probability a hedged
forecasted transaction would not occur.
As of December 31, 2003, US Holdings expects that $43 million ($28 million
after-tax) in accumulated other comprehensive loss will be recognized in
earnings over the next twelve months. This amount represents the projected value
of the hedges over the next twelve months relative to what would be recorded if
the hedge transactions had not been entered into. The amount expected to be
reclassified is not a forecasted loss incremental to normal operations, but
rather it demonstrates the extent to which volatility in earnings (which would
otherwise exist) is mitigated through the use of cash flow hedges. The following
table summarizes balances currently recognized in accumulated other
comprehensive gain/(loss):
Accumulated
Other Comprehensive Loss
Year Ended December 31, 2003
----------------------------
Treasury Commodity Total
-------- --------- -----
Dedesignated hedges (amounts fixed)................. $ 79 $ 30 $ 109
Hedges subject to market price fluctuations......... -- 11 11
------ ------- -------
Total.......................................... $ 79 $ 41 $ 120
======= ======= =======
15. RATES AND REGULATION
Restructuring Legislation
As a result of the 1999 Restructuring Legislation, on January 1, 2002, US
Holdings and certain other electric utilities in Texas disaggregated (unbundled)
their business activities into a power generation company, a retail electric
provider and a transmission and distribution (electricity delivery) utility.
Unbundled electricity delivery utilities within ERCOT, such as Oncor, remain
regulated by the Commission.
A-75
Effective January 1, 2002, REPs affiliated with electricity delivery
utilities are required to charge "price-to-beat" rates established by the
Commission to residential and small business customers located in their
historical service territories. TXU Energy, as a REP affiliated with an
electricity delivery utility, could not charge prices to customers in either of
those classes in the historical service territory that are different from the
price-to-beat rate, adjusted for fuel factor changes, until the earlier of
January 1, 2005 or the date on which 40% of the electricity consumed by
customers in a class is supplied by competing REPs. Thereafter, TXU Energy may
offer rates different from the price-to-beat rate to customers in that class,
but it must also continue to make the price-to-beat rate available for
residential and small business customers until January 1, 2007. Twice a year,
TXU Energy may request that the Commission adjust the fuel factor component of
the price-to-beat rate up or down based on changes in the market price of
natural gas. In March and August of 2003, the Commission approved price-to-beat
rate increases requested by TXU Energy.
In December 2003, the Commission found that TXU Energy had met the 40%
requirement to be allowed to offer alternatives to the price-to-beat rate for
small business customers in the historical service territory.
Also, effective January 1, 2002, power generation companies affiliated
with electricity delivery utilities may charge unregulated prices in connection
with ERCOT wholesale power transactions.
Regulatory Settlement Plan
On December 31, 2001, US Holdings filed a Settlement Plan with the
Commission. It resolved all major pending issues related to US Holdings'
transition to competition pursuant to the 1999 Restructuring Legislation. The
Settlement Plan does not remove regulatory oversight of Oncor's business nor
does it eliminate TXU Energy's price-to-beat rates and related fuel adjustments.
The Settlement Plan became final and non-appealable in January 2003.
The major elements of the Settlement Plan are:
Excess Mitigation Credit -- Over the two-year period ended December 31,
2003, Oncor implemented a stranded cost excess mitigation credit in the amount
of $389 million (originally estimated to be $350 million), plus $26 million in
interest, applied as a reduction to delivery fees charged to all REPs, including
TXU Energy. The credit was funded by TXU Energy in the form of a note payable to
Oncor.
Regulatory Asset Securitization -- US Holdings received a financing order
authorizing the issuance of securitization bonds in the aggregate principal
amount of up to $1.3 billion to recover regulatory asset stranded costs and
other qualified costs. Accordingly, Oncor Electric Delivery Transition Bond
Company LLC, a bankruptcy remote financing subsidiary of Oncor, issued an
initial $500 million of securitization bonds in 2003, with terms of up to 12
years, (see Note 8) and is expected to issue $790 million in the first half of
2004. The principal and interest payments of the bonds are recoverable through a
delivery fee surcharge (transition charge) to all REPs including TXU Energy.
Retail Clawback -- The Settlement Plan provides that a retail clawback
credit will be implemented unless 40% of the electricity consumed by residential
and small business customers in the historical service territory is supplied by
competing REPs after the first two years of competition. This threshold was
reached for small business customers, as discussed above, but not for
residential customers. The amount of the credit is equal to the number of
residential customers retained by TXU Energy in the historical service territory
as of January 1, 2004, less the number of new customers TXU Energy has added
outside of the historical service territory as of January 1, 2004, multiplied by
$90. The credit, which will be funded by TXU Energy, will be applied to delivery
fees charged by Oncor to REPs, including TXU Energy, over a two-year period
beginning January 1, 2004. In 2002, TXU Energy recorded a charge to cost of
energy sold of $185 million ($120 million after-tax) to accrue an estimated
retail clawback liability. In 2003, TXU Energy reduced the liability to $173
million, with a credit to earnings of $12 million ($8 million after-tax) to
reflect the calculation of the estimated liability applicable only to
residential customers in accordance with the Settlement Plan. As the amount of
the credit will be based on number of customers over the related two-year
period, the liability is subject to future adjustments.
A-76
Stranded Costs and Fuel Cost Recovery -- TXU Energy's stranded costs, not
including regulatory assets, are fixed at zero. US Holdings will not seek to
recover its unrecovered fuel costs which existed at December 31, 2001. Also, it
will not conduct a final fuel cost reconciliation, which would have covered the
period from July 1998 until the beginning of competition in January 2002.
See Note 4 for a discussion of extraordinary charges recorded in 2002 and
2001 in connection with the Settlement Plan.
Transmission Rates -- In May 2003, the Commission approved an increase in
Oncor's wholesale transmission tariffs (rates) charged to distribution utilities
that became effective immediately. In March and August 2003 and March 2004, the
Commission approved increases in the transmission cost recovery component of
Oncor's distribution rates charged to REPs. The combined effect of these four
increases in both the transmission and distribution rates is an estimated $62
million of incremental revenues to Oncor on an annualized basis. With respect to
the impact on US Holdings' consolidated results, the higher distribution rates
result in reduced margin on TXU Energy's sales to those retail customers with
pricing that does not provide for recovery of higher delivery fees, principally
price-to-beat customers.
Open-Access Transmission -- At the state level, the Texas Public Utility
Regulatory Act, as amended, requires owners or operators of transmission
facilities to provide open access wholesale transmission services to third
parties at rates and terms that are non-discriminatory and comparable to the
rates and terms of the utility's own use of its system. The Commission has
adopted rules implementing the state open access requirements for utilities that
are subject to the Commission's jurisdiction over transmission services, such as
Oncor.
On January 3, 2002, the Supreme Court of Texas issued a mandate affirming
the judgment of the Court of Appeals that held that the pricing provisions of
the Commission's open access wholesale transmission rules, which had mandated
the use of a particular rate setting methodology, were invalid because they
exceeded the statutory authority of the Commission. On January 10, 2002, Reliant
Energy Incorporated and the City Public Service Board of San Antonio each filed
lawsuits in the Travis County, Texas, District Court against the Commission and
each of the entities to whom they had made payments for transmission service
under the invalidated pricing rules for the period January 1, 1997, through
August 31, 1999, seeking declaratory orders that, as a result of the application
of the invalid pricing rules, the defendants owe unspecified amounts. US
Holdings and TXU SESCO Company are named defendants in both suits. Effective as
of October 3, 2003, a global settlement among all parties to these lawsuits was
reached. The settlement was not material to US Holdings financial position or
results of operation, and requires that these suits be dismissed with prejudice.
Summary -- Although US Holdings cannot predict future regulatory or
legislative actions or any changes in economic and securities market conditions,
no changes are expected in trends or commitments, other than those discussed in
this report, which might significantly alter its basic financial position,
results of operations or cash flows.
16. COMMITMENTS AND CONTINGENCIES
Information 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
Company LP to energy industry publications. The request seeks information for
the period from January 1, 1999 to the present. TXU Corp. has cooperated with
the CFTC, and is in the process of completing its response to such information
request. TXU Corp. believes that TXU Portfolio Management Company LP has not
engaged in any reporting of price or volume information that would in any way
justify any action by the CFTC.
Clean Air Act -- The Federal Clean Air Act, as amended (Clean Air Act)
includes provisions which, among other things, place limits on SO2 and NOx
emissions produced by electricity generation plants. TXU Energy's capital
requirements have not been significantly affected by the requirements of the
Clean Air Act. In addition, all permits required for the air pollution control
provisions of the 1999 Restructuring Legislation have been applied for and TXU
Energy has initiated a construction program to install control equipment to
achieve the required reductions.
A-77
Power Purchase Contracts -- Certain contracts to purchase electricity
provide for capacity payments to ensure availability and provide for adjustments
based on the actual power taken under the contracts. Capacity payments paid
under these contracts for the years ended December 31, 2003, 2002 and 2001 were
$230 million, $296 million and $196 million, respectively.
Expected future capacity payments under existing agreements are estimated
as follows:
2004....................................................... $238
2005....................................................... 162
2006....................................................... 117
2007....................................................... 18
2008....................................................... -
Thereafter................................................. -
-----
Total capacity payments.............................. $535
====
At December 31, 2003, TXU Energy had commitments for pipeline
transportation and storage reservation fees as shown in the table below:
2004....................................................... $24
2005....................................................... 7
2006....................................................... 6
2007....................................................... 4
2008....................................................... 1
Thereafter................................................. 6
--
Total pipeline transportation and storage reservation
fees................................................. $48
===
On the basis of TXU Energy's current expectations of demand from its
electricity customers as compared with its capacity payments, management does
not consider it likely that any material payments will become due for
electricity not taken beyond capacity payments.
Coal Contracts -- TXU Energy has coal purchase agreements and coal
transportation agreements. Commitments under these contracts for the next five
years and thereafter are as follows:
2004............................................................ $78
2005............................................................ 23
2006............................................................ 18
2007............................................................ -
2008............................................................ -
Thereafter...................................................... -
---
Total ........................................................ $119
====
Leases -- TXU Energy and Oncor have entered into operating leases covering
various facilities and properties including generation plant facilities,
combustion turbines, transportation equipment, mining equipment, data processing
equipment and office space. Certain of these leases contain renewal and purchase
options and residual value guarantees. Lease costs charged to operating expense
totaled $143 million, $152 million, and $132 million for 2003, 2002 and 2001,
respectively (including amounts paid by TXU Corp. and charged to TXU Energy and
Oncor).
A-78
As of December 31, 2003, future minimum lease payments under both capital
leases and operating leases (with initial or remaining noncancellable lease
terms in excess of one year) were as follows:
Capital Operating
Year Lease Leases
- ---- ----- ------
2004............................................... $ 2 $ 71
2005............................................... 2 76
2006............................................... 3 71
2007............................................... 3 75
2008............................................... 2 73
Thereafter......................................... 5 474
--- ----
Total future minimum lease payments.............. 17 $840
====
Less amounts representing interest................. 2
---
Present value of future minimum lease payments..... 15
Less current portion............................... 2
---
Long-term capital lease obligation................. $13
===
Guarantees -- US Holdings has entered into contracts that contain
guarantees to outside parties that could require performance or payment under
certain conditions. These guarantees have been grouped based on similar
characteristics and are described in detail below.
Project development guarantees -- In 1990, US Holdings repurchased an
electric co-op's minority ownership interest in the Comanche Peak nuclear
generation plant and assumed the co-op's indebtedness to the US government for
the facilities. US Holdings is making principal and interest payments to the
co-op in an amount sufficient for the co-op to make payments on its
indebtedness. US Holdings guaranteed the co-op's payments, and in the event that
the co-op fails to make its payments on the indebtedness, the US government
would assume the co-op's rights under the agreement, and such payments would
then be owed directly by US Holdings. At December 31, 2003, the balance of the
indebtedness was $136 million with maturities of principal and interest
extending to December 2021. The indebtedness is secured by a lien on the
purchased facilities.
Residual value guarantees in operating leases -- US Holdings is the lessee
under various operating leases that obligate it to guarantee the residual values
of the leased facilities. At December 31, 2003, the aggregate maximum amount of
residual values guaranteed was approximately $266 million with an estimated
residual recovery of approximately $198 million. The average life of the lease
portfolio is approximately six years.
Debt obligations of the parent -- TXU Energy has provided a guarantee of
the obligations under TXU Corp.'s financing lease (approximately $130 million at
December 31, 2003) for its headquarters building.
Shared saving guarantees -- As part of the operations of the strategic
retail services business, which TXU Energy intends to sell, TXU 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 $8 million and the maximum total
potential payout is approximately $56 million. The fair value of guarantees
issued during the year ended December 31, 2003 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 an expected transaction for the sale of strategic retail services
operations.
Letters of credit -- TXU 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 December 31, 2003 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 have expiration dates in 2008.
TXU Energy has outstanding letters of credit in the amount of $37 million
to support hedging and risk management margin requirements in the normal course
of business. As of December 31, 2003, approximately 82% 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.
A-79
Surety bonds -- US Holdings has outstanding surety bonds of approximately
$32 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.
Other -- US Holdings has entered into contracts with public agencies to
purchase cooling water for use in the generation of electric energy and has
agreed, in effect, to guarantee the principal, $12 million at December 31, 2003,
and interest on bonds issued by the agencies to finance the reservoirs from
which the water is supplied. The bonds mature at various dates through 2011 and
have interest rates ranging from 5.50% to 7%. US Holdings is required to make
periodic payments equal to such principal and interest, including amounts
assumed by a third party and reimbursed to US Holdings. In addition, US Holdings
is obligated to pay certain variable costs of operating and maintaining the
reservoirs. US Holdings has assigned to a municipality all its contract rights
and obligations in connection with $8 million remaining principal amount of
bonds at December 31, 2003, issued for similar purposes, which had previously
been guaranteed by US Holdings. US Holdings is, however, contingently liable in
the event of default by the municipality.
Nuclear Insurance -- With regard to liability coverage, the Price-Anderson
Act (Act) provides financial protection for the public in the event of a
significant nuclear power plant incident. The Act sets the statutory limit of
public liability for a single nuclear incident at $10.6 billion currently and
requires nuclear power plant operators to provide financial protection for this
amount. The Act is being considered by the United States Congress for
modification and extension. The terms of a modification, if any, are not
presently known and therefore TXU Corp. is unable, at this time, to determine
any impact it may have on nuclear liability coverage. As required, TXU Corp.
provides this financial protection for a nuclear incident at Comanche Peak
resulting in public bodily injury and property damage through a combination of
private insurance and industry-wide retrospective payment plans. As the first
layer of financial protection, TXU Corp. has $300 million of liability insurance
from American Nuclear Insurers (ANI), which provides such insurance on behalf of
a major stock insurance company pool, Nuclear Energy Liability Insurance
Association. The second layer of financial protection is provided under an
industry-wide retrospective payment program called Secondary Financial
Protection (SFP).
Under the SFP, each operating licensed reactor in the US is subject to an
assessment of up to $100.6 million, subject to increases for inflation every
five years, in the event of a nuclear incident at any nuclear plant in the US.
Assessments are limited to $10 million per operating licensed reactor per year
per incident. All assessments under the SFP are subject to a 3% insurance
premium tax, which is not included in the above amounts.
With respect to nuclear decontamination and property damage insurance, NRC
regulations require that nuclear plant license-holders maintain not less than
$1.1 billion of such insurance and require the proceeds thereof to be used to
place a plant in a safe and stable condition, to decontaminate it pursuant to a
plan submitted to and approved by the NRC before the proceeds can be used for
plant repair or restoration or to provide for premature decommissioning. TXU
Corp. maintains nuclear decontamination and property damage insurance for
Comanche Peak in the amount of $3.4 billion, above which TXU Corp. is
self-insured. The primary layer of coverage of $500 million is provided by
Nuclear Electric Insurance Limited (NEIL), a nuclear electric utility industry
mutual insurance company. The remaining coverage includes premature
decommissioning coverage and is provided by NEIL in the amount of $2.25 billion
and $610 million from other insurance markets and foreign nuclear insurance
pools. TXU Corp. is subject to a maximum annual assessment from NEIL of $26.7
million.
TXU Corp. maintains Extra Expense Insurance through NEIL to cover the
additional costs of obtaining replacement power from another source if one or
both of the units at Comanche Peak are out of service for more than twelve weeks
as a result of covered direct physical damage. The coverage provides for weekly
payments of $3.5 million for the first fifty-two weeks and $2.8 million for the
next 110 weeks for each outage, respectively, after the initial twelve-week
period. The total maximum coverage is $490 million per unit. The coverage
amounts applicable to each unit will be reduced to 80% if both units are out of
service at the same time as a result of the same accident. Under this coverage,
TXU Corp. is subject to a maximum annual assessment of $8.6 million.
A-80
There have been some revisions made to the nuclear property and nuclear
liability insurance policies regarding the maximum recoveries available for
multiple terrorism occurrences. Under the NEIL policies, if there were multiple
terrorism losses occurring within a one-year time frame, NEIL would make
available one industry aggregate limit of $3.24 billion plus any amounts it
recovers from other sources up to the limits for each claimant. If terrorism
losses occurred beyond the one-year period, a new set of limits and resources
would apply. Under the ANI liability policy, the liability arising out of
terrorist acts will be subject to one industry aggregate limit of $300 million
which could be reinstated at ANI's option depending on prevailing risk
circumstances and the balance in the Industry Credit Rating Plan reserve fund.
Under the US Terrorism Risk Insurance Act of 2002, the US government provides
reinsurance with respect to acts of terrorism in the US for losses caused by an
individual or individuals acting on behalf of foreign parties. In such
circumstances, the NEIL and ANI terrorism aggregates would not apply.
Nuclear Decommissioning -- Through December 31, 2001, decommissioning
costs were recovered from consumers based upon a 1992 site-specific study
through rates placed in effect under TXU Corp.'s January 1993 rate increase
request. Effective January 1, 2002, decommissioning costs are recovered through
a tariff charged to REPs by Oncor based upon a 1997 site-specific study,
adjusted for trust fund assets, as a component of delivery fees effective under
TXU Corp.'s 2001 Unbundled Cost of Service filing. Amounts recovered through
regulated rates are deposited in external trust funds (see Note 5 under
Investments). With the adoption of FAS 143, the liability for the
decommissioning costs was recorded at discounted net present value.
See Note 1 (under Changes in Accounting Standards) for a discussion of the
impact of SFAS 143 on accounting for nuclear decommissioning costs.
Also see Note 1 (under Property, Plant and Equipment) for a discussion of
an extension of the nuclear plant license.
Legal Proceedings -- On July 7, 2003, a lawsuit was filed by Texas
Commercial Energy (TCE) in the United States District Court for the Southern
District of Texas, Corpus Christi Division, against TXU Energy and certain of
its subsidiaries, as well as various other wholesale market participants doing
business in ERCOT, claiming generally that defendants engaged in market
manipulation, in violation of antitrust and other laws, primarily during the
period of extreme weather conditions in late February 2003. An amended complaint
was filed on February 3, 2004 that joined additional, unaffiliated defendants.
Three retail electric providers have 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. US Holdings believes that it has not committed any violation of the
antitrust laws and the Commission's investigation of the market conditions in
late February 2003 has not resulted in any findings adverse to TXU Energy.
Accordingly, US Holdings believes that TCE's and the interveners' claims against
TXU Energy and its subsidiary companies are without merit and TXU Energy and its
subsidiaries intend to vigorously defend the lawsuit. US Holdings is unable to
estimate any possible loss or predict the outcome of this action.
On April 28, 2003, a lawsuit was filed by a former employee of TXU
Portfolio Management in the United States District Court for the Northern
District of Texas, Dallas Division, against TXU Corp., TXU Energy and TXU
Portfolio Management. Plaintiff asserts claims under Section 806 of
Sarbanes-Oxley arising from plaintiff's employment termination and claims for
breach of contract relating to payment of certain bonuses. Plaintiff seeks back
pay, payment of bonuses and alternatively, reinstatement or future compensation,
including bonuses. TXU Corp. believes the plaintiff's claims are without merit.
The plaintiff was terminated as the result of a reduction in force, not as a
reaction to any concerns the plaintiff had expressed, and plaintiff was not in a
position with TXU Portfolio Management such that he had knowledge or information
that would qualify the plaintiff to evaluate TXU Corp.'s financial statements or
assess the adequacy of TXU Corp.'s financial disclosures. Thus, TXU Corp. does
not believe that there is any merit to the plaintiff's claims under
Sarbanes-Oxley. Accordingly, TXU Corp., TXU Energy and TXU Portfolio Management
intend to vigorously defend the litigation. While TXU Corp., TXU Energy and TXU
Portfolio Management dispute the plaintiff's claims, TXU Corp. is unable to
predict the outcome of this litigation or the possible loss in the event of an
adverse judgment.
A-81
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 has been transferred to the
Beaumont Division of the Eastern District of Texas. This action is brought by an
individual, alleged to be a retail consumer of electricity, on behalf of herself
and as a proposed representative of a putative class of retail purchasers of
electricity that are similarly situated. On September 15, 2003, defendants filed
a motion to dismiss the lawsuit and a motion to transfer the case to the
Northern District of Texas, Dallas Division. TXU Corp. believes that the
plaintiff lacks standing to assert any antitrust claims against TXU Corp. or TXU
Portfolio Management, and that defendants have not violated antitrust laws or
other laws as claimed by the plaintiff. Therefore, TXU Corp. believes that
plaintiff's claims are without merit and plans to vigorously defend the lawsuit.
TXU Corp. is unable to estimate any possible loss or predict the outcome of this
action.
US Holdings is involved in various legal and administrative proceedings in
the normal course of business the ultimate resolution of which should not have a
material effect upon its financial position, results of operations or cash
flows.
17. SEGMENT INFORMATION
US Holdings has two reportable business segments: TXU Energy and Oncor.
TXU Energy- consists of operations, which are principally in the
competitive Texas market, involving power production (electricity generation)
and retail and wholesale energy sales of electricity and natural gas. TXU Energy
engages in hedging and risk management activities to mitigate commodity price
risk.
Oncor - consists of operations, which are largely regulated, involving the
transmission and distribution of electricity in Texas.
The 2001 financial information for the TXU Energy segment and the Oncor
segments includes information derived from the historical financial statements
of US Holdings. Reasonable allocation methodologies were used to disaggregate
the financial statements of US Holdings between its generation and transmission
and distribution (delivery) operations. Allocation of revenues reflected
consideration of return on invested capital, which continues to be regulated for
the delivery operations. US Holdings maintained expense accounts for each of its
component operations. Costs of energy sold, operating costs and depreciation and
amortization, as well as assets, such as property, plant and equipment,
materials and supplies and fuel, were specifically identified by component
operation and disaggregated. Various allocation methodologies were used to
disaggregate revenues, common expenses, assets and liabilities between US
Holdings' generation and delivery operations. Further, certain financial
information was deemed to be not reasonably allocable because of the changed
nature of Oncor's and TXU Energy's operations subsequent to the opening of the
market to competition, as compared to US Holdings' previous operations. Such
activities and related financial information consisted primarily of costs
related to retail customer support activities, including billing and related bad
debts expense, as well as regulated revenues associated with these costs.
Financial information related to these activities was reported in Oncor's
results of operations for the 2001 period. Interest and other financing costs
were determined based upon debt allocated. Allocations reflected in the
financial information for 2001 did not necessarily result in amounts reported in
individual line items that are comparable to actual results in 2002 and 2003.
Had the unbundled operations of US Holdings actually existed as separate
entities in a deregulated environment, their results of operations could have
differed materially from those included in the historical financial statements
included herein.
The accounting policies of the segments are the same as those described in
the summary of significant accounting policies. US Holdings evaluates
performance based on income from continuing operations before extraordinary
items and cumulative effect of changes in accounting principles. US Holdings
accounts for intersegment sales and transfers as if the sales or transfers were
to third parties, that is, at current market prices.
Certain of the business segments provide services or sell products to each
other. Such sales are made at prices comparable with those received from
nonaffiliated customers for similar products or services. No customer provided
more than 10% of consolidated revenues.
Effective with reporting for 2003, results for the Energy segment exclude
expenses incurred by the US Holdings parent company in order to present the
segment on the same basis as the results of the business are evaluated by
management. Prior year amounts are presented on this revised basis.
A-82
TXU
Energy Oncor Other Eliminations Consolidated
------ ----- ----- ------------ ------------
Operating Revenues
2003.......................... 7,995 2,087 -- (1,500) 8,582
2002.......................... 7,691 1,994 -- (1,592) 8,093
2001.......................... 7,404 2,314 -- (1,752) 7,966
Regulated Revenues - Included in
Operating Revenues
2003.......................... -- 2,087 -- (1,488) 599
2002.......................... -- 1,994 -- (1,582) 412
2001.......................... 7,044 2,314 -- (1,752) 7,606
Affiliated Revenues - Included in
Operating Revenues
2003.......................... 11 1,489 -- (1,500) --
2002.......................... 6 1,586 -- (1,592) --
2001.......................... -- 1,752 -- (1,752) --
Depreciation and Amortization -
Including Goodwill Amortization
2003.......................... 409 297 -- -- 706
2002.......................... 450 264 -- -- 714
2001.......................... 409 239 -- -- 648
Equity in Earnings (Losses) of
Subsidiaries -
Unconsolidated Subsidiaries
2003.......................... (1) -- -- -- (1)
2002.......................... (2) -- -- -- (2)
2001.......................... (4) -- -- -- (4)
Interest Income
2003.......................... 8 52 20 (61) 19
2002.......................... 10 49 44 (97) 6
2001.......................... 38 -- 33 (32) 39
Interest Expense and Related Charges
2003.......................... 323 300 43 (61) 605
2002.......................... 215 265 57 (97) 440
2001.......................... 224 267 14 (32) 473
Income Tax Expense(Benefit)
2003.......................... 229 126 (9) -- 346
2002.......................... 117 117 (11) -- 223
2001.......................... 242 119 (2) -- 359
Income from continuing operations
before extraordinary loss and
cumulative effect of changes
in accounting principles
2003.......................... 493 258 (19) -- 732
2002.......................... 319 245 (20) -- 544
2001.......................... 577 228 (3) -- 802
Investment in Equity Investees
2003.......................... 1 -- -- -- 1
2002.......................... 3 -- -- -- 3
2001.......................... 7 -- -- -- 7
Total Assets
2003.......................... 14,572 9,316 592 (987) 23,493*
2002.......................... 15,789 9,022 967 (901) 24,877*
2001.......................... 18,205 10,780 -- (6,899) 22,086*
Capital Expenditures
2003.......................... 163 543 -- -- 706
2002.......................... 284 513 -- -- 797
2001.......................... 327 635 -- -- 962
- -------------------------------
* Assets by segment exclude investments in affiliates.
A-83
18. SUPPLEMENTARY FINANCIAL INFORMATION
Regulated Versus Unregulated Operations --
Year Ended December 31,
2003 2002 2001
------- ------- -------
Operating revenues
Regulated............................................... $ 2,087 $ 1,994 $ 9,358
Unregulated............................................. 7,995 7,691 360
Intercompany sales eliminations - regulated............. (1,488) (1,582) (1,752)
Intercompany sales eliminations - unregulated........... (12) (10) --
------- ------- -------
Total operating revenues........................... 8,582 8,093 7,966
Costs and operating expenses
Cost of energy sold and delivery fees - regulated*...... -- -- 3,013
Cost of energy sold and delivery fees - unregulated*.... 3,627 3,194 36
Operating costs - regulated............................. 709 676 1,229
Operating costs - unregulated........................... 689 698 34
Depreciation and amortization, other than goodwill
- regulated 297 264 629
Depreciation and amortization, other than goodwill
- unregulated 409 450 4
Selling, general and administrative expenses - regulated 207 213 483
Selling, general and administrative expenses - unregulated 636 775 229
Franchise and revenue-based taxes - regulated........... 250 272 441
Franchise and revenue-based taxes - unregulated......... 125 138 --
Goodwill amortization - regulated....................... -- -- 15
Goodwill amortization - unregulated..................... -- -- --
Other income............................................ (52) (38) (11)
Other deductions........................................ 21 250 269
Interest income......................................... (19) (6) (39)
Interest expense and other charges...................... 605 440 473
------- ------- -------
Total costs and expenses........................... 7,504 7,326 6,805
------- ------- -------
Income from continuing operations before income taxes,
extraordinary loss and cumulative effect of changes
in accounting principles................................ $ 1,078 $ 767 $ 1,161
======= ======= =======
*Includes cost of fuel consumed of $1,465 million (unregulated) in 2003,
$1,413 million (unregulated) in 2002 and $1,847 million (largely regulated) in
2001. The balance represents energy purchased for resale and delivery fees.
The operations of the Energy segment are included above as unregulated, as
the Texas market is now open to competition. However, retail pricing to
residential customers in the historical service territory continues to be
subject to certain price controls as discussed in Note 15.
Other Income and Deductions --
Year Ended December 31,
-----------------------
2003 2002 2001
------- ------- -------
Other income
Gain on sale of properties.......................... $ 45 $ 32 $ 1
Allowance for equity funds used during construction. 4 3 5
Other............................................... 3 3 5
------- ------- -------
Total other income............................. $ 52 $ 38 $ 11
======= ======= =======
Other deductions
Loss on sale of properties.......................... $ -- $ 2 $ 8
Loss on retirement of debt.......................... 3 -- 149
Regulatory asset write-offs......................... -- -- 95
Asset impairment.................................... 2 237 --
Expenses related to impaired construction projects.. 6 7 7
Premium on redemption of preferred stock............ 3 -- --
Other............................................... 7 4 10
------- ------- -------
Total other deductions......................... $ 21 $ 250 $ 269
======= ======= =======
A-84
Credit Risk -- Credit risk relates to the risk of loss associated with
non-performance by counterparties. US Holdings maintains credit risk policies
with regard to its counterparties to minimize overall credit risk. These
policies require an evaluation of a potential counterparty's financial
condition, credit rating, and other quantitative and qualitative credit criteria
and specify authorized risk mitigation tools, including but not limited to use
of standardized agreements that allow for netting of positive and negative
exposures associated with a single counterparty. US Holdings has standardized
documented processes for monitoring and managing its credit exposure, including
methodologies to analyze counterparties' financial strength, measurement of
current and potential future credit exposures and standardized contract language
that provides rights for netting and set-off. Credit enhancements such as
parental guarantees, letters of credit, surety bonds and margin deposits are
also utilized. Additionally, individual counterparties and credit portfolios are
managed to preset limits and stress tested to assess potential credit exposure.
This evaluation results in establishing credit limits or collateral requirements
prior to entering into an agreement with a counterparty that creates credit
exposure to US Holdings. Additionally, US Holdings has established controls to
determine and monitor the appropriateness of these limits on an ongoing basis.
Any prospective material adverse change in the payment history or financial
condition of a counterparty or downgrade of its credit quality will result in
the reassessment of the credit limit with that counterparty. This process can
result in the subsequent reduction of the credit limit or a request for
additional financial assurances.
Credit Exposure -- US Holdings' gross exposure to credit risk as of
December 31, 2003 was $2.2 billion, represents trade accounts receivable (net of
allowance of uncollectible accounts receivable of $53 million), as well as
commodity contract assets and other derivative assets that arise primarily from
hedging activities.
A large share of gross assets subject to credit risk represents accounts
receivable from the retail sale of electricity and gas to residential and small
business customers. The risk of material loss (after consideration of
allowances) from non-performance by these customers is unlikely based upon
historical experience. Allowances for uncollectible accounts receivable are
established for the potential loss from non-payment by these customers based on
historical experience and market or operational conditions. In addition, Oncor
has exposure to credit risk as a result of non-performance by nonaffiliated
REPs.
Most of the remaining trade accounts receivable are with large business
customers and hedging counterparties. These counterparties include major energy
companies, financial institutions, gas and electric utilities, independent power
producers, oil and gas producers and energy trading companies.
The exposure to credit risk from these customers and counterparties,
excluding credit collateral, as of December 31, 2003, is $1.1 billion net of
standardized master netting contracts and agreements that provide the right of
offset of positive and negative credit exposures with individual customers and
counterparties. When considering collateral currently held by US Holdings (cash,
letters of credit and other security interests), the net credit exposure is $965
million. Of this amount, approximately 86% of the associated exposure is with
investment grade customers and counterparties, as determined using publicly
available information including major rating agencies' published ratings and US
Holdings' internal credit evaluation process. Those customers and counterparties
without an S&P rating of at least BBB- or similar rating from another major
rating agency are rated using internal credit methodologies and credit scoring
models to estimate an S&P equivalent rating. US Holdings routinely monitors and
manages its credit exposure to these customers and counterparties on this basis.
US Holdings had no exposure to any one customer or counterparty greater
than 10% of the net exposure of $965 million at December 31, 2003. Additionally,
approximately 71% of the credit exposure, net of collateral held, has a maturity
date of two years or less. US Holdings does not anticipate any material adverse
effect on its financial position or results of operations as a result of
non-performance by any customer or counterparty.
A-85
Interest Expense and Related Charges --
Year Ended December 31,
-----------------------
2003 2002 2001
---- ---- ----
Interest....................................................... $ 585 $ 434 $ 410
Interest on long-term debt held by subsidiary trusts........... -- - 61
Amortization of debt discounts and issuance costs.............. 31 17 21
Allowance for borrowed funds used during construction
and capitalized interest.................................... (11) (11) (19)
------ ------ ------
Total interest expense and related charges.......... $ 605 $ 440 $ 473
====== ====== ======
FIN 46 and SFAS 150 have affected the balance sheet presentation of
mandatorily redeemable securities. However, there has been no effect on the
presentation of related interest charges on the income statement.
Regulatory Assets and Liabilities --
December 31,
-------------------
2003 2002
---- ----
Regulatory Assets
Generation-related regulatory assets recoverable by securitization bonds............ $1,654 $1,652
Securities reacquisition costs...................................................... 121 124
Recoverable deferred income taxes-- net............................................. 96 76
Other regulatory assets............................................................. 95 46
------ ------
Total regulatory assets.......................................................... 1,966 1,898
Regulatory Liabilities
Liability related to excess mitigation credit....................................... -- 170
Investment tax credit and protected excess deferred taxes........................... 88 98
Over-collection of transition bond (securitization) revenues........................ 6 --
------ ------
Total regulatory liabilities..................................................... 94 268
------ ------
Net regulatory assets............................................................... $1,872 $1,630
====== ======
Included in net regulatory assets are assets of $121 million at both
December 31, 2003 and 2002 that are earning a return. The regulatory assets,
other than those subject to securitization, have a remaining recovery period of
15 to 47 years.
Included in other regulatory assets as of December 31, 2003 was $29
million related to nuclear decommissioning liabilities.
Restricted Cash -- At December 31, 2003, the Oncor Electric Delivery
Transition Bond Company LLC had $12 million of restricted cash, representing
collections from customers that secure its securitization bonds, which may be
used only to service its debt and pay its expenses and $12 million recorded in
investments, that is restricted to be used for expenses not covered by customer
collections. As of December 31, 2003, all of the restricted cash of $210 million
from the net proceeds of Oncor's issuance of senior secured notes in December
2002 had been used to pay the interest and principal of Oncor's first mortgage
bonds due March 1 and April 1, 2003. Other restricted cash in 2002 included $68
million as collateral for letters of credit issued.
Affiliate Transactions -- The following represent significant affiliate
transactions of US Holdings:
Average daily short-term advances from affiliates during 2003 and 2002
were $699 million and $821 million, respectively, and interest expense incurred
on the advances was $20 million and $23 million, respectively. The average
interest rate was 2.79% and 2.63% for 2003 and 2002, respectively.
A-86
TXU Business Services Company, a subsidiary of TXU Corp., charges US
Holdings for certain financial, accounting, information technology,
environmental, procurement and personnel services and other administrative
services at cost. For 2003, 2002 and 2001, these costs totaled $331 million,
$428 million and $435 million, respectively, and are included in selling,
general and administrative expenses.
US Holdings charges TXU Gas Company, a subsidiary of TXU Corp., for
customer and administrative services. For 2003, 2002 and 2001 these charges
totaled $56 million, $57 million and $43 million, respectively, and are largely
reported as a reduction in operation and maintenance expenses.
Accounts Receivable -- At December 31, 2003 and 2002, accounts receivable
of $1.0 billion and $1.4 billion are stated net of allowance for uncollectible
accounts of $53 million and $72 million, respectively. During 2003, bad debt
expense was $119 million, account write-offs were $125 million and other
activity decreased the allowance for uncollectible accounts by $13 million.
During 2002, bad debt expense was $160 million, account write-offs were $101
million and other activity decreased the allowance for uncollectible accounts by
$14 million. Allowances related to receivables sold are reported in current
liabilities and totaled $40 million and $19 million at December 31, 2003 and
2002, respectively.
Accounts receivable included $411 million and $505 million of unbilled
revenues at December 31, 2003 and 2002, respectively.
Commodity Contract Assets -- At December 31, 2003 and 2002, current and
noncurrent commodity contract assets totaling $1.1 billion and $1.8 billion,
respectively are stated net of applicable credit (collection) and performance
reserves totaling $18 million and $43 million, respectively. Performance
reserves are provided for direct, incremental costs to settle the contracts.
Inventories by Major Category --
December 31,
-----------------
2003 2002
---- ----
Materials and supplies...................................................... $254 $264
Fuel stock.................................................................. 79 70
Gas stored underground...................................................... 83 57
---- ----
Total inventories................................................... $416 $391
==== ====
Inventories at December 31, 2003, reflect a $22 million reduction as a
result of the rescission of EITF 98-10 as discussed in Note 2.
Property, Plant and Equipment --
December 31,
----------------
2003 2002
---- ----
In service
Generation............................................................. $15,900 $15,675
Transmission........................................................... 2,349 2,176
Distribution........................................................... 6,676 6,376
Other assets........................................................... 1,195 894
------- -------
Total............................................................... 26,120 25,121
Less accumulated depreciation.......................................... 9,938 9,217
------- -------
Net of accumulated depreciation..................................... 16,182 15,904
Construction work in progress............................................. 379 373
Nuclear fuel (net of accumulated amortization of: 2003-- $934 and 2002-- $847) 131 137
Held for future use....................................................... 22 22
------- -------
Net property, plant and equipment................................... $16,714 $16,436
======= =======
As of December 31, 2003, substantially all of Oncor's electric utility
property, plant and equipment (with a net book value of $6.3 billion) is pledged
as collateral on Oncor's first mortgage bonds and senior secured notes.
A-87
Supplemental Cash Flow Information --
Year Ended December 31,
----------------------------
2003 2002 2001
---- ---- ----
Cash payments (receipts):
Interest.................................................... $ 523 $ 401 $ 482
Income taxes................................................ $ 100 $ 127 $ 396
Non-cash investing and financing activities:
Discount related to exchangeable subordinated preferred
membership recorded interests recorded to paid-in-capital.... $ -- $ 266 $ -
See Note 2 for the affects of adopting SFAS 143, which were noncash in
nature.
See Note 8 for discussion for the exchange of TXU Energy subordinated
notes for preferred membership interests, which was noncash in nature.
Quarterly Information (unaudited) -- The results of operations by quarter
are summarized below and reflect the discontinuance of the strategic retail
services operations. In the opinion of US Holdings, all other adjustments
(consisting of normal recurring accruals) necessary for a fair statement of such
amounts have been made. Quarterly results are not necessarily indicative of a
full year's operations because of seasonal and other factors.
Quarter Ended
-------------
March 31 June 30 Sept. 30 Dec. 31
-------- ------- -------- -------
2003:
Operating revenues .............................................. $ 1,917 $ 2,152 $ 2,611 $ 1,902
Income from continuing operations before extraordinary loss and
cumulative effect of changes in accounting principles.......... $ 88 $ 201 $ 371 $ 72
Income (loss) from discontinued operations, net of tax effect ... $ 1 $ -- $ -- $ (15)
Cumulative effect of changes in accounting principles, net of tax
benefit ....................................................... $ (58) $ -- $ -- $ --
Net income before preferred stock dividends ..................... $ 31 $ 201 $ 371 $ 57
Net income available for common stock ........................... $ 29 $ 199 $ 370 $ 57
2002:
Operating revenues .............................................. $ 1,868 $ 2,107 $ 2,527 $ 1,591
Income (loss) from continuing operations before extraordinary loss $ 256 $ 259 $ 335 $ (306)
Income (loss) from discontinued operations, net of tax effect ... $ (3) $ (15) $ (15) $ (16)
Extraordinary loss, net of tax effect............................ $ -- $ - $ - $ (134)
Net income (loss) before preferred stock dividends............... $ 253 $ 244 $ 320 $ (456)
Net income (loss) available for common stock .................... $ 251 $ 241 $ 318 $ (458)
Included in fourth quarter 2002 results were a $237 million ($154 million
after-tax) writedown of an investment in generation plant construction projects
and a $185 million ($120 million after-tax) accrual for regulatory-related
retail clawback, as discussed in Notes 1 and 15.
A-88
Reconciliation of Previously Reported Quarterly Information -- The
following table presents the changes to previously reported quarterly amounts to
reflect discontinued operations (see Note 3). Net income was not affected by
this change.
Quarter Ended
--------------------------------------------
March 31 June 30 Sept. 30 Dec. 31
-------- ------- -------- -------
Increase (Decrease) from Previously Reported
2003:
Revenues-- from discontinued operations................... $ (15) $ (28) $ (11) $ --
Income from continuing operations and cumulative effect of
changes in accounting principles........................ $ (1) $ -- $ -- $ --
Income from discontinued operations, net of tax effect ... $ 1 $ -- $ -- $ --
2002:
Revenues-- from discontinued operations................... $ (9) $ (12) $ (9) $ (17)
Income from continuing operations before extraordinary loss $ 3 $ 15 $ 15 $ 16
Loss from discontinued operations, net of tax effect ..... $ (3) $ (15) $ (15) $ (16)
A-89
TXU US HOLDINGS COMPANY EXHIBITS FOR 2002 FORM 10-K
APPENDIX B
Previously Filed*
With File As
Exhibits Number Exhibit
-------- ------ -------
(2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession.
2(a) 1-12833 2 -- Master Separation Agreement by and
Form 8-K among Oncor, TXU Generation
(filed January 16, Holdings Company LLC, TXU Merger Energy
2002) Trading Company LP, TXU SESCO Company,
TXU SESCO Energy Services Company,
TXU Energy Retail Company LP and
TXU US Holdings,dated as of December 14, 2001.
3(i) Articles of Incorporation.
3(a) 1-11668 3(c) -- Amended and Restated Articles of
Form 10-Q Incorporation of TXU US Holdings Company
(Quarter ended effective as of August 31, 2003
September 30, 2003)
(filed November 13, 2003)
3(ii) By-laws
3(b) 1-11668 3(b) -- Restated By-laws of TXU US
Form 10-Q Holdings Company, January 1,2002.
(Quarter ended March
31, 2002) (filed May
15, 2002)
(4) Instruments Defining the Rights of Security Holders, Including Indentures.**
TXU US Holdings
4(a) 33-55408 99(a) -- Agreement, dated as of January 30, 1990,
between TXU US Holdings Company and
Tex-La Electric Cooperative of Texas, Inc.
4(b) 0-11442 4(f) -- Indenture (for Unsecured Subordinated Debt
Form 10-K (1995) Securities relating to Trust Securities),
(filed March 5, dated as of December 1, 1995, between TU Electric
1996) and the Bank of New York, as trustee.
4(c) 1-03591 4(v) -- Officer's Certificate, dated as of January 30, 1997,
Form 10-K (1996) establishing the terms of the Floating Rate Junior
(filed March 13, Subordinated Debentures, Series D.
1997)
4(d) 1-03591 4(z) -- Officer's Certificate, dated as of January 30, 1997,
Form 10-K (1996) establishing the terms of the 8.175% Junior Subordinated
(filed March 13, Debentures, Series E.
1997)
4(e) 0-11442 4(a) -- Indenture (For Unsecured Debt Securities), dated as of
Form 10-Q August 1, 1997, between TXU US Holdings and The Bank of
(Quarter ended New York, Trustee.
Sept. 30, 1997)
(filed November 14,
1997)
B-1
Previously Filed*
With File As
Exhibits Number Exhibit
-------- ------ -------
4(f) 0-11442 4(b) -- Officers' Certificate, dated August 18, 1997, establishing
Form 10-Q terms of TXU US Holdings 7.17% Debentures due August 1, 2007.
(Quarter ended
Sept. 30, 1997)
(filed November 14,
1997)
Oncor Electric Delivery Company
4(g) 2-90185 4(a) -- Mortgage and Deed of Trust, dated as of December 1, 1983,
Form S-3 (files between Oncor and The Bank of New York, as Trustee.
March 27, 1984)
4(g)(1) -- Supplemental Indentures to Mortgage and Deed of Trust:
Number Dated as of
------ -----------
2-90185 4(b) First April 1, 1984
Form S-3 (filed
March 27, 1984)
33-24089 4(a)-1 Fifteenth July 1, 1987
Form S-3 (filed
August 30, 1988)
33-30141 4(a)-3 Twenty-second January 1, 1989
Form S-3 (filed
July 26, 1989)
33-35614 4(a)-3 Twenty-fifth December 1, 1989
Form, S-3 (filed
June 27, 1990)
33-39493 4(a)-2 Twenty-eighth October 1, 1990
Form S-3 (filed
March 29, 1991)
33-49710 4(a)-1 Thirty-fourth April 1, 1992
Form S-3 (filed
July 17, 1992)
33-57576 4(a)-3 Fortieth November 1, 1992
Form S-3 (filed
January 29, 1993)
33-60528 4(a)-1 Forty-second March 1, 1993
Form S-3 (filed
April 2, 1993)
33-64692 4(a)-2 Forty-fourth April 1, 1993
Form S-3 (filed
June 18, 1993)
33-68100 4(a)-1 Forty-sixth July 1, 1993
Form S-3
(Amendment No. 1)
(filed September 2,
1994)
33-68100 4(a)-3 Forty-seventh October 1, 1993
Form S-3
(Amendment No. 1)
(filed September 2,
1994)
1-12833 4(2)(1) Sixty-third January 1, 2002
Form 10-K
(2001) (filed March
14, 2002)
1-12833 4 Sixty-fourth May 1, 2002
Form 10-Q
(Quarter ended March
31, 2002) (filed May
15, 2002)
333-100240 4(f)(2) Sixty-fifth December 1, 2002
Form S-4 (filed
January 6, 2003)
B-2
Previously Filed*
With File As
Exhibits Number Exhibit
-------- ------ -------
4(h) 333-100240 4(a) -- Indenture and Deed of Trust, dated as May 1, 2002,
Form S-4 between Oncor and The Bank of New York, as of Trustee.
(filed October 2,
2002)
4(i) 333-100240 4(c) -- Form of Oncor Electric Delivery Company 6.375% Exchange
Form S-4 Senior Secured Notes due 2012.
(filed October 2,
2002)
4(j) 333-100240 4(d) -- Form of Oncor Electric Delivery Company 7% Exchange Senior
Form S-4 Secured Notes due 2032.
(filed October 2,
2002)
4(k) 333-106894 4(d) -- Form of Oncor Electric Delivery Company 6.375% Exchange
Form S-4 Senior Secured Notes due 2015.
(filed July 9, 2003)
4(l) 333-106894 4(e) -- Form of Oncor Electric Delivery Company 7.250% Exchange
Form S-4 Senior Secured Notes due 2033.
(filed July 9, 2003)
(10) Material Contracts.
Credit Agreements.
10(a) 1-12833 10(c) -- $400,000,000 Three-Year Amended and Restated Revolving
Form 8-K/A Credit Agreement, dated as of April 22, 2003, among TXU US
(filed May 1, 2003) Holdings Company, as Borrower, TXU Corp., as Exiting
Borrower, certain bankslisted therein and Citibank, N.A.,
as Administrative Agent.
10(b) 1-12833 10(d) -- Amendment No. 1, dated as of July 10, 2003 to the
Form 10-Q (Quarter $400,000,000 Three-Year Amended and Restated Revolving
ended September 30, Credit Agreement, dated as of April 22, 2003, among TXU US
2003) (filed Holdings, TXU Corp., certain banks listed therein and
November 12, 2003) Citibank, N.A., as Administrative Agent.
10(c) 1-12833 10(b) -- 364 Day Competitive Advance and Revolving Credit Facility
Form 10-Q Agreement, dated as of April 24, 2002 among TXU Energy,
(Quarter ended March Oncor and US Holdings, Chase Manhattan Bank of Texas,
31, 2002) (filed May National Association, as Administrative Agent, and certain
15, 2002) banks listed therein and The Chase Manhattan Bank, as
Competitive Advance Facility Agent. (Expired April 23,
2003).
10(d) 1-12833 10(b) -- $1,400,000,000 Five-Year Third Amended and Restated
Form 10-Q Competitive Advance and Revolving Credit Facility Agreement,
(Quarter ended dated as of July 31, 2002, among TXU US Holdings Company,
June 30, 2002) JPMorgan Chase Bank, as Administrative Agent and Competitive
(filed August 14, Advance Facility Agent, J.P. Morgan Securities, Inc., Bank
2002) of America, N.A. and Citibank, N.A.
10(e) 1-12833 10(d) -- Amendment, dated as of April 22, 2003, to $1,400,000,000
Form 8-K/A Five-Year Third Amended and Restated Competitive Advance and
(filed May 1, 2003) Revolving Credit Facility Agreement, dated as of July 31,
2002, among TXU US Holdings Company, certain banks listed
therein and JPMorgan Chase Bank, as Competitive Advance
Facility Agent, Administrative Agent and Fronting Bank.
10(f) 1-12833 10(e) -- $450,000,000 Revolving Credit Agreement, dated as of April
Form 8-K/A (filed 22, 2003, among Oncor, TXU Energy and certain banks listed
May 1, 2003) therein, and JPMorgan Chase Bank, as Administrative Agent.
B-3
Previously Filed*
With File As
Exhibits Number Exhibit
-------- ------ -------
10(g) 1-12833 10(e) -- Amendment No. 1, dated August 29, 2003, to the $450,000,000
Form 10-Q (Quarter Revolving Credit Agreement, dated as of April 22, 2003,
ended September 30, among TXU Energy, Oncor, certain banks listed therein and JP
2003) (filed Morgan Chase Banks as Administrative Agent and Fronting Bank.
November 12, 2003)
Other Material Contracts.
10(h) 333-100240 10(c) -- Generation Interconnection Agreement, dated December 14,
Form S-4 2001, between Oncor and TXU Generation Company LP.
(filed October 2,
2002)
10(i) 333-100240 10(d) -- Generation Interconnection Agreement, dated December 14,
Form S-4 2001, between Oncor and TXU Generation Company LP, for
(filed October 2, itself and as Agent for TXU Big Brown Company LP, TXU
2002) Mountain Creek Company LP, TXU Handley Company LP, TXU
Tradinghouse Company LP and TXU DeCordova Company LP
(Interconnection Agreement).
10(j) 333-100240 10(e) -- Amendment No. 1 to Interconnection Agreement, dated May 31,
Form S-4 2002.
(filed October 2,
2002)
10(k) 333-100240 10(f) -- Standard Form Agreement between Oncor and Competitive
Form S-4 Retailer Regarding Terms and Conditions of Delivery of
(filed October 2, Electric Power and Energy.
2002)
10(l) 333-100240 10(c) -- $150,000,000 Senior Secured Credit Agreement, dated December
(Pre-Effective 20, 2002, among Oncor and certain banks listed therein, and
Amendment No. 1) Credit Suisse First Boston, as Administrative Agent.
Form S-4 (filed
January 6, 2003)
10(m) 1-12833 10(w) -- Stipulation and Joint Application for Approval of Settlement
Form 10-K (2002) as approved by the PUC in Docket Nos. 21527 and 24892.
(filed March 12,
2003)
(12) Statement Regarding Computation of Ratios.
12 -- Computation of Ratio of Earnings to Fixed Charges, and Ratio
of Earnings to Combined Fixed Charges and Preference
Dividends.
(21) Subsidiaries of the Registrant.
21 -- Subsidiaries of TXU US Holdings Company.
(23) Consents of Experts and Counsel.
23 -- Consent of Deloitte & Touche LLP, Independent Auditors for
TXU US Holdings Company.
B-4
Previously Filed*
With File As
Exhibits Number Exhibit
-------- ------ -------
(31) Rule 13a - 14(a)/15d - 14(a) Certifications.
31(a) -- Certification of C. John Wilder, principal executive officer of
TXU US Holdings Company, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
31(b) -- Certification of H. Dan Farell, principal financial officer
of TXU US Holdings Company, pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002.
(32) Section 1350 Certifications.
32(a) -- Certification of C. John Wilder, principal executive officer of
TXU US Holdings Company, pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
32(b) -- Certification of H. Dan Farell, principal financial officer
of TXU US Holdings Company, pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002.
- ------------------------------------------
* Incorporated herein by reference.
** Certain instruments defining the rights of holders of long-term debt of
the registrant's subsidiaries included in the financial statements
filed herewith have been omitted because the total amount of securities
authorized thereunder does not exceed 10 percent of the total assets of
the registrant and its subsidiaries on a consolidated basis. Registrant
hereby agrees, upon request of the Securities and Exchange Commission,
to furnish a copy of any such omitted instrument.
B-5