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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, 2002
-- OR--
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
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Exact Name of Registrant as Specified in its Charter;
Commission State of Incorporation; Address of Principal I.R.S. Employer
File Number Executive Offices; and Telephone Number Identification No.
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1-11668 TXU US Holdings Company 75-1837355
a Texas Corporation
Energy Plaza, 1601 Bryan Street
Dallas, TX 75201-3411
(214) 812-4600
Securities registered pursuant to Section 12(b) of the Act:
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Name of Each Exchange on
Title of Each Class Which Registered
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Depositary Shares, Series A, each representing 1/4 New York Stock Exchange
of a share of $7.50 Cumulative Preferred Stock,
without par value
Depositary Shares, Series B, each representing 1/4 New York Stock Exchange
of a share of $7.22 Cumulative Preferred Stock,
without par value
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 registrants (1) have 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
registrants were required to file such reports), and (2) have been subject to
such filing requirements for the past 90 days. Yes X No
-- --
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 Securities Exchange Act). Yes No X
-- --
Aggregate market value of TXU US Holdings Common Stock held by
non-affiliates: None
ommon Stock outstanding at March 26, 2003: TXU US Holdings Company -
52,817,862 shares, without par value
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DOCUMENTS INCORPORATED BY REFERENCE - None
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TABLE OF CONTENTS
Page
PART I ----
Items 1. and 2. BUSINESS and PROPERTIES............................................................ 1
TXU US HOLDINGS COMPANY AND SUBSIDIARIES............................................ 1
ELECTRIC RESTRUCTURING.............................................................. 2
COMPETITIVE STRATEGY................................................................ 4
OPERATING SEGMENTS.................................................................. 4
Energy......................................................................... 4
Electric Delivery.............................................................. 4
ENVIRONMENTAL MATTERS............................................................... 12
Item 3. LEGAL PROCEEDINGS.......................................................................... 13
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS........................................ 14
PART II
Item 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.................................................................. 14
Item 6. SELECTED FINANCIAL DATA.................................................................... 14
Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS............................................................... 14
Item 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK................................. 14
Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA................................................ 14
Item 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURE............................................................. 14
PART III
Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF REGISTRANT........................................... 15
Item 11. EXECUTIVE COMPENSATION................................................................... 17
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT........................... 28
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS........................................... 28
Item 14. CONTROLS AND PROCEDURES.................................................................. 29
PART IV
Item 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.......................... 29
APPENDIX A - Financial Information A-1
APPENDIX B - TXU US Holdings Company Exhibits for 2002 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
PART I
Items 1. and 2. BUSINESS and PROPERTIES
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
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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.
Use of the term "US Holdings", unless otherwise noted or indicated by the
context, refers to US Holdings, a holding company, and/or its consolidated
subsidiaries.
US Holdings, through its TXU Energy and Oncor subsidiaries, engages in
power production (electricity generation), wholesale energy sales, retail energy
sales and related services, portfolio management, including risk management and
certain trading activities, and the delivery of electricity. US Holdings is one
of the largest energy services companies in the United States (US) with $8
billion in revenue and $24 billion of assets. US Holdings owns or leases and
operates 19,140 megawatts of power generation and sells 120 terawatt hours of
electricity annually. US Holdings sells energy to over 2.7 million residential,
commercial and industrial customers. At December 31, 2002, US Holdings and its
subsidiaries had approximately 10,021 full-time employees.
Legislation passed during the 1999 session of the Texas Legislature
restructured the electric utility industry in Texas and provided for a
transition to increased competition in the generation and retail sale of
electricity (1999 Restructuring Legislation). As a result, TXU Corp.
restructured certain of its businesses effective January 1, 2002. In order to
satisfy its obligations to unbundle its business pursuant to the 1999
Restructuring Legislation and consistent with its business separation plan as
approved on October 31, 2001 by the Public Utility Commission of Texas
(Commission), as of January 1, 2002, US Holdings transferred:
o its electric transmission and distribution (T&D) operations to Oncor, which
is a utility regulated by the Commission and a wholly-owned subsidiary of
US Holdings,
o its power generation operations to subsidiaries of TXU Energy, which is the
new competitive business and a wholly-owned subsidiary of US Holdings, and
o its retail customers to a subsidiary retail electric provider (REP) of TXU
Energy.
The T&D assets of TXU SESCO Company, a subsidiary of TXU Corp., also were
transferred to Oncor. In addition, as of January 1, 2002, US Holdings acquired
the following businesses from within the TXU Corp. system and transferred them
to TXU Energy: the REP of TXU SESCO Company; operations involving certain risk
management and energy trading activities and the unregulated commercial and
industrial (C&I) retail gas operations of TXU Gas Company (TXU Gas); and the
energy management services businesses and other affiliates of TXU Corp.,
including the fuel procurement and coal mining businesses that service the
generation operations.
See further discussion of the 1999 Restructuring Legislation below.
The following is a description of the business of US Holdings and its
principal subsidiaries.
TXU Energy and Oncor -- US Holdings is a holding company for TXU Energy
and Oncor. TXU Energy serves more than 2.7 million retail electric customers(1)
and owns, or leases and operates 19,140 megawatts of power generating capacity.
Oncor owns and operates 96,847 miles of electric distribution lines and 14,137
miles of electric transmission lines. The businesses transferred to TXU Energy
and Oncor effective January 1, 2002, together comprised the integrated electric
utility business conducted by US Holdings prior to that date. In addition, as of
January 1, 2002, TXU Energy acquired the following businesses from within the
TXU Corp. system: the REP of TXU SESCO Company; operations involving certain
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1 All numbers of electric customers are based on the number of meters.
1
risk management and energy trading activities and the unregulated
commercial/industrial retail gas business of TXU Gas Company (TXU Gas); and the
energy management services businesses and other affiliates of TXU Corp.,
including the fuel supply and coal mining businesses that primarily service the
generation operations. Also, the T&D business of TXU SESCO Company was
transferred to Oncor. The operating assets of TXU Energy and Oncor are located
principally in the north-central, eastern and western parts of Texas.
US Holdings and its subsidiaries operate within the Electric Reliability
Council of Texas (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 electric power systems in Texas and 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.
ELECTRIC RESTRUCTURING
----------------------
Restructuring Legislation -- Under the 1999 Restructuring Legislation
discussed above, each electric utility was required to separate (unbundle) by
January 1, 2002 its business activities into a power generation company (PGC), a
REP, and a T&D utility or separate T&D utilities. Unbundled T&D utilities within
ERCOT, such as Oncor, remain regulated by the Commission.
Beginning January 1, 2002, REPs affiliated with T&D utilities began
charging residential and small commercial customers located in their historical
service territory rates that are 6% less than the rates that were in effect on
January 1, 1999, as adjusted for fuel factor changes ("price-to-beat rate"). TXU
Energy, as a REP affiliated with a T&D utility (Oncor), may not charge prices to
such customers that are different from the price-to-beat rate until the earlier
of January 1, 2005, or the date on which 40% of the electricity consumed by
customers in those respective customer classes is supplied by competing REPs.
Thereafter, TXU Energy may offer rates different from the price-to-beat rate,
but it must also continue to make the price-to-beat, adjusted for fuel factor
changes, available for residential and small commercial customers until January
1, 2007. REPs must be certified by the Commission. TXU Energy has received
appropriate REP certifications from the Commission.
Also, beginning January 1, 2002, PGCs that are affiliated with T&D
utilities may charge unregulated prices in connection with ERCOT wholesale power
transactions. Estimated costs associated with PGC nuclear power plant
decommissioning obligations continue to be recovered as a nonbypassable T&D
charge over the life of the plant. Each affiliated PGC owning 400 megawatts or
more of installed generating capacity must offer each year at auction
entitlements to at least 15% of such capacity. The obligation of an affiliated
PGC to sell capacity entitlements at auction continues until the earlier of
January 1, 2007 or the date on which 40% of the electricity consumed by
residential and small commercial customers of the PGC's affiliated REP is
supplied by competing REPs. PGCs must be registered with the Commission. TXU
Energy has filed appropriate PGC registrations with the Commission.
The 1999 Restructuring Legislation also provided for the recovery of
generation-related regulatory assets (regulatory assets) and generation-related
and purchased power-related costs that are in excess of market value (stranded
costs). It provided means for electric utilities to mitigate stranded costs
during the rate freeze period that preceded unbundling. Unmitigated stranded
costs would be finally determined in a 2004 "true-up" proceeding relying
principally upon market-based asset valuations. Regulatory assets and
unmitigated stranded costs can be recovered through the issuance of transition
(securitization) bonds or imposition of a competition transition charge.
Further, a REP would also be required to reconcile and credit to its
affiliated T&D utility (and the T&D utility to credit T&D customers), as a
so-called retail clawback, any positive difference between the price-to-beat
rate, reduced by the nonbypassable delivery charge, and the prevailing market
price of electricity during the same time period to the extent the price-to-beat
rate exceeded the market price of electricity. This reconciliation is not
required for the applicable customer class if 40% of the electricity consumed by
customers in that class is supplied by competing REPs before January 1, 2004. If
a retail clawback reconciliation is required, the 1999 Restructuring Legislation
provided that the amount credited cannot exceed an amount equal to the number of
residential or small commercial customers served by a T&D utility that are
buying electricity from the affiliated REP at the price-to-beat rate on January
1, 2004, minus the number of new customers obtained outside the historical
service territory, multiplied by $150. (The calculation of this credit was
altered for TXU Energy in connection with the Settlement Plan discussed below.)
2
Regulatory Settlement Plan -- On December 31, 2001, US Holdings filed a
settlement plan (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 (Settlement) provided for in the
Settlement Plan does not remove regulatory oversight of Oncor's business nor
does it eliminate TXU Energy's price-to-beat rates and related fuel adjustments.
The Settlement was approved by the Commission in June 2002. In August 2002, the
Commission issued a financing order, pursuant to the Settlement Plan,
authorizing the issuance of securitization bonds relating to recovery of
regulatory assets. The Commission's order approving the Settlement Plan and the
financing order were appealed by certain nonsettling parties to the Travis
County, Texas, District Court in August 2002. In January 2003, US Holdings
concluded a settlement of these appeals and they were dismissed. Thus, the
Settlement became final.
The major elements of the Settlement are:
Excess Mitigation Credit and Appeals Related to T&D Rates -- In 2002,
Oncor began implementing an excess stranded cost mitigation credit in the amount
of $350 million, plus interest, applied over a two-year period as a reduction to
T&D rates charged to REPs. In June 2001, the Commission had issued an interim
order that addressed Oncor's charges for T&D service when retail competition
would begin. Among other things, that interim order, and subsequent final order
issued in October 2001, required Oncor to reduce rates over the period from
2002-2008. The Commission's decision was appealed by US Holdings to the Travis
County, Texas District Court. Finalization of the Settlement means US Holdings'
appeal has been dismissed. Also, in July 2001, the staff of the Commission had
notified US Holdings and the Commission that it disagreed with US Holdings'
computation of the level of earnings in excess of the regulatory earnings cap
for calendar year 2000. In August 2001, the Commission issued an order adopting
the staff position. US Holdings appealed this matter to the Travis County,
Texas, District Court, which affirmed the Commission's order and US Holdings
then appealed that decision to the Third District Court of Appeals in Austin,
Texas. This appeal has now been dismissed.
Regulatory Asset Securitization -- In October 1999, US Holdings filed an
application with the Commission for a financing order to permit the issuance by
a special purpose entity of $1.65 billion of securitization bonds. In May 2000,
the Commission signed an order rejecting such request and authorized only $363
million of such bonds. US Holdings filed an appeal with the Travis County,
Texas, District Court and in September 2000, the Court issued a judgment that
reversed part of the Commission's order and affirmed other aspects of the
Commission's order. US Holdings and various other parties appealed this judgment
directly to the Supreme Court of Texas, and in June 2001, it issued a ruling; in
October 2001, it remanded the case to the Commission, which consolidated it into
the Settlement Plan proceeding. In accordance with the Settlement, Oncor
received a financing order authorizing it to issue securitization bonds in the
aggregate principal amount of $1.3 billion to recover regulatory assets and
other qualified costs. The Settlement provides that there can be an initial
issuance of securitization bonds in the amount of up to $500 million, followed
by a second issuance of the remainder after 2003. The Settlement resolves all
issues related to regulatory assets and liabilities.
Retail Clawback -- If, as currently expected, TXU Energy retains more than
60% of its historical residential and small commercial customers (representing
such customers of US Holdings and TXU SESCO Company as of January 1, 2002) after
the first two years of competition, the amount of the retail clawback credit
will be equal to the number of residential and small commercial customers
retained by TXU Energy in its historical service territory on January 1, 2004,
less the number of new customers TXU Energy has added outside of its historical
service territory as of January 1, 2004, multiplied by $90. This determination
will be made separately for the residential and small commercial classes. The
credit, if any, will be applied to T&D rates charged by Oncor to REPs, including
TXU Energy, over a two-year period beginning January 1, 2004. Under the
settlement agreement, TXU Energy will make a compliance filing with the
Commission reflecting customer count as of January, 2004. In the fourth quarter
of 2002, TXU Energy recorded a $185 million ($120 million after-tax) charge for
the retail clawback, which represents the current best estimate of the amount to
be funded to Oncor over the two-year period.
Stranded Cost Resolution -- TXU Energy's stranded costs, not including
regulatory assets, are fixed at zero. Accordingly, it will not have to conduct
the stranded cost true-up in 2004 provided for in the 1999 Restructuring
Legislation. The Settlement also precludes recovery by US Holdings of certain
environmental improvement costs. In addition, the Settlement resulted in a
resolution of the regulatory disallowance of amounts related to US Holdings'
repurchase of minority owner interests in the Comanche Peak nuclear generating
station. The Commission's final order in connection with US Holdings' January
1990 rate increase request had been ultimately reviewed by the Supreme Court of
3
Texas, and an aggregate of $909 million of disallowances with respect to US
Holdings' reacquisitions of minority owners' interests in Comanche Peak, which
had previously been recorded as a charge to earnings, was remanded to the
District Court and then to the Commission for reconsideration. As a result of
the Settlement, this remand has been dismissed.
Fuel Cost Recovery -- The Settlement also provides that 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.
Provider of Last Resort -- Through calendar year 2002, TXU Energy was the
provider of last resort (POLR) for residential and small non-residential
customers in those areas of ERCOT where customer choice was available outside
its historical service territory, and was the POLR for large non-residential
customers in its historical service territory. TXU Energy's POLR contract
expired on December 31, 2002. However, in August 2002, the Commission adopted
new rules that significantly changed POLR service. Under the new POLR rules,
instead of being transferred to the POLR, non-paying residential and small
non-residential customers served by affiliated REPs are subject to
disconnection. Non-paying residential and small non-residential customers served
by non-affiliated REPs are transferred to the affiliated REP. Non-paying large
non-residential 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 must decide whether all REPs should be permitted to disconnect all
non-paying customers. The new POLR rules are expected to result in reduced bad
debt expense beginning in 2003.
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 POLR, but was designated POLR through
lottery for small business and residential customers in certain West Texas
service areas and for small business customers in the Houston service area.
COMPETITIVE STRATEGY
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TXU Corp. has developed a strategy designed to achieve operations of
significant scale in selected regions which optimize a portfolio of assets,
capabilities and customer relationships across multiple products and services.
US Holdings plans to enhance its leading position in retail and wholesale
electric sales and related services and electricity transmission and delivery in
Texas. US Holdings' strategy involves establishing upstream positions
(electricity generation through ownership or contracts and pipeline access to
multiple supply sources and storage assets) and downstream retail customer
relationships. US Holdings uses the knowledge gained from and the value of these
positions through effective portfolio management capabilities to manage the risk
and enhance the value of existing positions while adjusting the portfolio as
needed to address market conditions. US Holdings intends to focus on operational
excellence in its current operations, cost reductions, customer retention and
debt reductions to strengthen its balance sheet and support future growth. US
Holdings intends for its electric delivery business to continue to be a leader
in the efficient and reliable transmission and distribution of electricity.
OPERATING SEGMENTS
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Prior to January 1, 2002, US Holdings had no separate reportable
operating segments. As a result of TXU Corp.'s reorganization as of January 1,
2002 (see discussion in Note 1 to Financial Statements under "Business
Restructuring"), US Holdings realigned its operations into two reportable
segments: Energy and Electric Delivery. Prior period amounts have been restated
to conform to the new segments.
Energy - operations, principally in the competitive Texas market,
involving power production, wholesale energy sales, retail energy sales and
services, as well as portfolio management, including risk management and certain
trading activities.
Electric Delivery - regulated operations in Texas involving the
transmission and distribution of electricity.
4
Reasonable allocation methodologies were used to unbundle the financial
statements of US Holdings between its generation and T&D operations. Allocation
of revenues reflected consideration of return on invested capital, which
continues to be regulated for the T&D 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 common expenses,
assets and liabilities between US Holdings' generation and T&D operations.
Interest and other financing costs were determined based upon debt allocated.
Allocations reflected in the financial information for 2001 and 2000 did not
necessarily result in amounts reported in individual line items that are
comparable to actual results in 2002. 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.
ENERGY
The Energy segment was created as a result of the deregulation of the
electric utility industry in Texas, which became effective January 1, 2002. The
Energy segment is an integrated operation that engages in power production,
wholesale energy sales, retail energy sales and related services and portfolio
management activities, primarily in the state of Texas. The Energy segment's
operations are conducted principally through TXU Energy and its following
subsidiaries: TXU Generation Holdings Company LLC; TXU Portfolio Management
Company LP; TXU Energy Retail Company LP; TXU Energy Solutions Company LP; TXU
Fuel Company; and two coal mining subsidiaries.
TXU Energy is one of the largest competitive retailers of energy in the US.
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.
TXU Energy's strategy is to focus on operational excellence, customer
retention and low risk growth from core operations in Texas. TXU Energy intends
to accomplish this through the operation of a single, integrated energy business
managing a portfolio of assets, capabilities and customer relationships. TXU
Energy's portfolio of assets includes 19,140 megawatts of owned or leased power
generating capacity, approximately 2,700 megawatts of power generating capacity
under power purchase contracts and over 2.7 million retail electric customers.
Early in 2002, TXU Energy intended to enhance its significant business portfolio
in Texas through expansion into other regions in North America. However, the
slowed pace of deregulation, the weaker economy, reduced liquidity in power
markets and reduced developmental capital spending have resulted in TXU Energy
delaying those growth objectives until competitive and regulatory environments
develop and economic factors improve. TXU Energy is currently implementing plans
to reduce operating costs.
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 the North Texas market, at competitive production costs.
As part of TXU Energy's integrated business portfolio, much of the low cost
power generation is available to supply the power demands of its retail
customers and other competitive REPs.
TXU Energy's portfolio management operation is responsible for managing
the risks inherent in TXU Energy's portfolio of businesses and providing supply
structuring, pricing and risk management services in connection with TXU
Energy's unregulated retail energy activities. The portfolio management
operation also is responsible for the commodity price risk management of the
fuel supply needs of TXU Energy's generating plants as well as the dispatch and
sale of power from those plants.
Power Production
The power fleet in Texas consists of 22 owned or leased plants with
generating capacity fueled as follows: 2,300 megawatts nuclear; 5,837 megawatts
coal/lignite; and 10,881 megawatts gas/oil. TXU Energy has adequate power
capacity to supply its retail customer base from its power fleet and purchases
from third parties. TXU Energy believes that a key competitive advantage is its
ability to produce electricity at low variable costs. The power generating
plants and other important properties of TXU Energy are located primarily on
land owned in fee simple.
TXU Energy completed the acquisition of the Pedricktown, New Jersey,
co-generation facility and wholesale energy production business in April 2002.
The acquisition included a 122 megawatt combined-cycle power production facility
5
and various contracts, including electric supply and gas transportation
agreements. In May 2002, TXU Energy acquired a 260 megawatt combined-cycle power
production facility in northwest Texas through a settlement agreement which
dismissed a lawsuit previously filed related to the plant. 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 its Handley and Mountain
Creek power generating plants (total plant capacity of 2,334 megawatts). The
Handley plant consists of five natural gas-fueled generating units with a total
plant capacity of 1,441 megawatts. The Mountain Creek plant consists of five
natural gas-fueled generating units with a total plant capacity of 893
megawatts. The transaction included a power purchase and tolling agreement for
TXU Energy to purchase power during the summer months through 2006. TXU Energy
from time to time may sell additional assets to reduce its position in the Texas
market, to provide funds for other investments and to reduce debt.
TXU Energy has been active in adding renewable energy to its portfolio.
TXU Energy is one of the largest purchasers of wind-generated, renewable energy
in Texas and the US. TXU Energy currently purchases renewable energy from over
382 megawatts of wind projects located in West Texas. TXU Energy expects to
continue to add additional renewable supplies as commercial opportunities become
available.
Capacity Auction -- To encourage competition in the ERCOT region, each PGC
with 400 megawatts or more of installed generating capacity that is unbundled
from an integrated electric utility in Texas is required to sell at auction
entitlements to 15% of the output of its installed generating capacity. The
obligation of an affiliated PGC to sell capacity entitlements at auction
continues until the earlier of January 1, 2007 or the date on which 40% of the
electricity consumed by residential and small commercial customers initially
transferred to the PGC's affiliated REP on January 1, 2002 is supplied by
competing REPs. This capacity auction allows market participants to purchase
power either through purchases in the wholesale power markets or through
mandated capacity auctions. A REP cannot purchase entitlements sold by its
affiliated PGC in mandated capacity auctions. The first auction in Texas was
held in September 2001. There was significant interest in the entitlements being
auctioned, and the auction of two-year, one-year and monthly entitlements
required to be sold was successful. The second and third auctions were held in
March and July of 2002, respectively. TXU Energy sold the monthly entitlements
required at each of these auctions. 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 will re-offer these unsold
entitlements in subsequent auctions to be held through 2003.
Nuclear Production Assets -- TXU Energy owns and operates two
nuclear-fueled electricity generating units at the Comanche Peak plant, each of
which is designed for a capacity of 1,150 megawatts.
TXU Energy has on hand, or has contracted for, services it expects to need
for its nuclear units through the years indicated: conversion (2003), enrichment
(2005), and fabrication (2011). TXU Energy is currently negotiating for the
purchase of uranium for 2003, which is readily available on the open market. 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 non-bypassable 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 with the Commission.
Lignite/Coal 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 77% of the fuel used at TXU Energy's lignite plants in 2002 was
supplied from owned or leased lignite.
6
TXU Energy supplements its lignite fuel at Big Brown, Monticello and
Martin Lake with western coal from the Powder River Basin (PRB) in Wyoming. The
coal is purchased from multiple suppliers under contracts of various lengths and
is transported from the PRB to TXU Energy's generating plants by railcar.
Approximately 23% of the fuel used at TXU Energy's lignite plants in 2002 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 Production Assets -- TXU Energy has eighteen gas/oil fueled plants
(including Pedricktown, New Jersey) with a capacity of 11,003 megawatts. Gas/oil
fuel requirements for 2002 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,
2003, TXU Energy had fuel oil storage capacity sufficient to accommodate
approximately 5.5 million barrels of oil and had approximately 0.9 million
barrels of oil in inventory. A significant portion of the gas/oil generating
plants have the ability to switch between gas and fuel oil.
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 to serve US Holdings' generating plants. In keeping with
deregulation principles, this network now offers transportation and storage
service to TXU Energy as well as third parties at a competitive price.
TXU Energy also owns and operates two underground gas storage facilities
with a usable capacity of 14.0 billion cubic feet (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.
Products and Services
On January 1, 2002, all of US Holdings' over 2.7 million retail electric
service customers in Texas who did not choose a different REP automatically
became customers of TXU Energy. TXU Energy's historical service territory is
located in the north-central, eastern and western parts of Texas, with an
estimated population in excess of 7 million, about one-third of the population
of Texas. TXU Energy provides electric service in that service territory to
customers in 92 counties and 370 incorporated municipalities, including Dallas,
Fort Worth, Arlington, Irving, Plano, Waco, Mesquite, Rowlett, Grand Prairie,
Wichita Falls, Odessa, Midland, Carrollton, Tyler, Richardson and Killeen. The
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
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.
TXU Energy's wholesale power sales are conducted through its portfolio
management activities that are designed to integrate a portfolio of assets,
capabilities and customer relationships. See "Portfolio Management" below. In
February 2002, TXU Energy was awarded 1,000 megawatts of load in the New Jersey
Statewide Basic Generation Service Electricity Supply Auction. However, plans
for further expansion outside of Texas have been delayed until competitive and
regulatory environments develop and economic factors improve.
TXU Energy's natural gas operation in Texas includes pipelines, storage
facilities, well-head production contracts, transportation agreements, storage
leases, retail and wholesale customers and supply to gas fired generation
plants. Service is primarily provided to TXU Energy's generation operations.
Third party service, which is expected to increase in coming years, comprised
approximately 15% of revenue for the pipeline system in 2002. TXU Energy's
portfolio management operation integrates various techniques and resources to
maximize value and manage the risks inherent in this natural gas operation. The
main goal of portfolio management, in this regard, is to reduce costs and
improve gross margin associated with the assets through storage, transportation
and exchange and production contracts. Portfolio management must take into
account market pricing, operational constraints and existing obligations in
order to determine the best blend of resources.
7
Portfolio Management
The portfolio management operation integrates, manages and creates value
from TXU Energy's extensive portfolio of retail and production assets,
capabilities and customer relationships. Specifically, portfolio management
ensures supply availability and manages associated operating costs, provides
competitively priced power, and maximizes the value of physical assets, capital
and technological infrastructure to monitor, evaluate and anticipate gas and
electric commodity market trends relating to fundamental supply, market demand
and Texas deregulation. TXU Energy uses these capabilities to optimize the cash
flows and earnings of its deregulated Texas portfolio. TXU Energy also offers
similar portfolio management services to non-affiliated third parties.
TXU Energy enters into both financial contracts as well as contracts that
provide for physical delivery related to the purchase and sale of electricity
and gas primarily in the wholesale markets in Texas and to a limited extent in
selected regions elsewhere in North America. Competitive markets demand that a
number of services be offered, including term contracts with interruptible and
firm deliveries, risk management, aggregation of supply, nominations, scheduling
of deliveries for both gas transportation capacity and gas storage, as well as
power generating facilities. In the course of providing these comprehensive
portfolio management services to its customer base, TXU Energy engages in energy
price risk management activities. TXU Energy 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 TXU Energy's portfolio management
activities.
TXU Energy manages its exposure to price risk from existing contractual
commitments as well as other energy related assets and liabilities within
established transactional policies and limits. TXU Energy ensures 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 the portfolio management 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 Corp. policy requirements. Risk assessment is segregated
and operated separately from compliance and enforcement to ensure independence,
accountability and integrity of actions. TXU Corp. 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. For information
regarding TXU Energy's risk management policies, please read MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -
"Quantitative and Qualitative Disclosures about Market Risk - Risk Oversight."
Competition
Texas -- Deregulation of the electric utility industry in Texas, effective
January 1, 2002, allows retail consumers of independent operating utilities in
the ERCOT region to choose a REP, which purchases its power from competing power
producers. All customer switching is conducted through ERCOT, which acts as a
clearinghouse and enforcement agent. Texas is one of the fastest growing states
in the nation with a diverse and resilient economy and, as a result, has
attracted several 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.
According to the latest data provided by the Commission (September 2002),
customers at over 400,000 locations across ERCOT had elected to switch providers
within their historical service territory. This number represents approximately
7% of all customers in ERCOT areas open to customer choice. Since December 2000,
the Commission has certified a total of 54 REPs, and while some have dropped
out, competition has remained strong.
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 cost of service and billing per customer. TXU Energy emphasizes its
8
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
initial customer base and to add customers.
Because Texas began restructuring its wholesale electricity business in
1995, new generation was encouraged to enter the state. As a result, there have
been approximately 60 new power plants added in the state since that time,
providing the state with ample power resources. Capacity margins for ERCOT,
based upon existing capacity and planned capacity with interconnection
agreements, are expected to be 24% in 2003 and remain at or above 20% for the
next several years. New gas-fired capacity is generally more efficient to
operate than existing gas/oil-fired capacity due to technological advances.
However, base-load nuclear, lignite and coal plants have lower variable
production costs than even new gas-fired plants at current annual average market
gas prices. 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.
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 2.8% per year;
o it is a sizeable market with over 57 gigawatts (GW) of peak demand and
33 GW of average demand; and
o there is no mandatory power pool structure.
Outside Texas -- Deregulation, although proceeding well in Texas, has not
had similar success in other parts of the US. Federal legislation such as the
Public Utility Regulatory Policy Act of 1978 and the Energy Policy Act, as well
as initiatives in various states, were enacted to encourage wholesale
competition among electric utility and non-utility power producers. 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 deregulation. New entry by retailers
as well as by merchant generators in states other than Texas has been slowed.
The continued uncertainty regarding regional transmission organizations, (the
Federal Energy Regulatory Commission's (FERC's) Order 2000) and more recently
FERC's Notice of Proposed Rulemaking regarding Standard Market Design have
delayed the opening of new retail markets and decreased the economic viability
of merchant generation.
Nature of Competition -- The level of competition in the energy industry
is affected by a number of variables, including price, reliability of service,
the cost of energy alternatives, new technologies and governmental regulations.
TXU Energy competes with other energy providers based on the ability to
aggregate supplies at competitive prices from different sources and locations
and to efficiently utilize transportation from third-party pipelines and
9
transmission from electric utilities. These operations also compete against
other energy marketers on the basis of their relative skills, financial position
and credit. Competition means energy customers, wholesale energy suppliers and
transporters may seek financial guarantees and other assurances that their
energy contracts will be satisfied. As pricing information becomes increasingly
available in the energy business and when deregulation in the electricity
markets begins to revive, the power generation and portfolio management
operations of TXU Energy may experience greater competition.
Customers -- There are no individually significant unaffiliated customers
upon which TXU Energy's business or results of operations are highly dependent.
Regulation and Rates
TXU Corp. is a holding company as defined in the Public Utility Holding
Company Act of 1935. However, TXU Corp. 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 subject to various federal, state and local regulations.
(See discussion below under "Environmental Matters".)
TXU Energy is an exempt wholesale generator under the Federal Power Act
and is subject to the jurisdiction of the Nuclear Regulatory Commission (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.
ELECTRIC DELIVERY
The Electric Delivery segment consists primarily of the electricity
transmission and distribution operations of Oncor. Electric Delivery provides
the essential service of delivering electricity safely, reliably and
economically to end-use customers.
Electric Transmission
Oncor's electric transmission business is responsible for the real-time
safe and reliable operations of its transmission network. These responsibilities
consist of the construction and maintenance of transmission facilities and the
monitoring, controlling and dispatching of high-voltage electricity within
Oncor's control area.
Oncor is a member of ERCOT, and the transmission business actively
supports the operation of ERCOT and all market participants. The transmission
business participates with ERCOT and other member utilities to plan, design and
obtain regulatory approval for construction of new transmission lines necessary
to increase bulk power transfer capability and to remove existing limitations
and constraints on the ERCOT transmission grid.
Transmission revenues are provided under tariffs approved by the
Commission and FERC. Network transmission revenues are provided from the use of
the transmission power lines for delivery of power over facilities operating at
60,000 volts and above. Transformation service revenues are provided from the
use of distribution 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.
The principal generating facilities of TXU Energy, certain non-utility
generators and the load centers of Oncor are connected by 4,522 circuit miles of
345-kilovolt (kV) transmission lines and 9,615 circuit miles of 138- and 69-kV
transmission lines.
Oncor is connected by eight 345-kV lines to CenterPoint Energy (formerly
Reliant Energy Inc.); by four 345-kV, eight 138-kV and nine 69-kV lines to
American Electric Power Company; by two 345-kV and eight 138-kV lines to the
Lower Colorado River Authority; by four 345-kV and nine 138-kV lines to the
Texas Municipal Power Agency; by two asynchronous high voltage direct current
interconnections to American Electric Power Company in the Southwest Power Pool;
and at several points with smaller systems operating wholly within Texas.
10
Electric 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 network 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 more than 2%
a year.
The 2.7 million formerly regulated electricity customers (retail customers
who purchase and consume electricity) are free to choose from REPs who compete
for their business. However, the REPs are now Oncor's customers. The changed
character of customers, 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, their
customers, and Oncor. Oncor intends to continue to build on its inherited
tradition of low cost and high performance.
Oncor's distribution system receives electricity from the transmission
system through power distribution substations and distributes electricity to end
users and wholesale customers through 2,914 distribution feeders.
The Oncor distribution network consists of 55,178 miles of overhead
primary conductors, 22,073 miles of overhead secondary and street light
conductors, 12,264 miles of underground primary conductors and 7,332 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. Substantially all of Oncor's transmission and distribution
systems are subject to liens under its mortgage indentures.
Customers
Oncor's transmission customers consist of municipalities, electric
cooperatives and other distribution companies. Oncor's distribution customers
consist of approximately 35 REPs in Oncor's certified service area, including a
subsidiary REP of TXU Energy. For the year ended December 31, 2002, delivery fee
revenues from TXU Energy represented approximately 80% of Oncor's revenues.
There are no individually significant unaffiliated customers upon which Oncor's
business or results are highly dependent.
Regulation and Rates
Regulatory Proceedings Affecting Restructuring -- See "Electric
Restructuring" above for a description of the various regulatory proceedings
relating to the restructuring of the Texas electric industry.
Oncor is subject to various federal, state and local regulations. (See
"Environmental Matters" below for information on environmental matters affecting
Oncor.) 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
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) has prohibited the collection of any rates or charges by a public utility
that does not have the prior approval of the Commission.
Open-Access Transmission -- At the state level, the 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.
11
On January 3, 2002, the Supreme Court of Texas issued a mandate affirming
the judgment of the Court of Appeals which held that the pricing provisions of
the Commission's open access wholesale transmission rules, which had mandated
the use of a particular rate setting methodology, were invalid because they
exceeded the statutory authority of the Commission. On January 10, 2002, Reliant
Energy Incorporated, and the City Public Service Board of San Antonio each filed
lawsuits in the Travis County, Texas, District Court against the Commission and
each of the entities to whom they had made payments for transmission service
under the invalidated pricing rules for the period January 1, 1997 through
August 31, 1999, seeking declaratory orders that, as a result of the application
of the invalid pricing rules, the defendants owe unspecified amounts. US
Holdings and TXU SESCO Company are named defendants in both suits. US Holdings
is unable to predict the outcome of any litigation related to this matter.
ENVIRONMENTAL MATTERS
---------------------
US Holdings and its subsidiaries are subject to various federal, state and
local regulations dealing with air and water quality and related environmental
matters.
Air -- Under the Texas Clean Air Act, the Texas Commission on
Environmental Quality (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 Environmental Protection Agency (EPA) promulgated
under the Federal Clean Air Act, as amended (Clean Air Act), which have also
been adopted by the TCEQ, are applicable to certain generating units. 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) emissions produced by certain generation
plants. In addition to the new source performance standards applicable to SO2,
the Clean Air Act requires that fossil-fueled plants have sufficient SO2
emission allowances and meet certain nitrous oxide (NOx) emission standards. TXU
Energy's generation plants meet the SO2 allowance requirements and NOx emission
rates.
In December 2000, the EPA published a notice that it intends to regulate
the emissions of hazardous air pollutants, including mercury, from fossil
fuel-fired power plants in the future. Regulations on mercury are expected to be
proposed in 2003, issued in 2004 and become effective in 2007. TXU Energy is
unable to predict the effects of these regulations. 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.
The Bush Administration will address greenhouse gas emissions through a
recently announced greenhouse gas emissions intensity reduction policy. The Bush
Administration and the EPA have proposed the Clear Skies Initiative calling for
additional reductions of SO2, NOx, and mercury from electricity generation
facilities over a 15-year period. TXU Energy is unable to predict the impact of
the Bush Administration proposal or related legislation.
Major air pollution control provisions of the 1999 Restructuring
Legislation require a 50% reduction in NOx emissions from "grandfathered"
electric utility generation plants and a 25% reduction in SO2 emissions from
"grandfathered" electric utility generation plants by May 1, 2003. The
"grandfathered" plants must also obtain permits. This legislation also provides
for an "opt-in" of permitted plants as an alternative to achieve the same
reductions, and recovery of reasonable environmental improvement costs as
stranded costs upon approval by the Commission (see Stranded Cost Resolution
within ELECTRIC RESTRUCTURING section above). All permits required by the 1999
Restructuring Legislation have been obtained and TXU Energy has initiated a
construction program to install control equipment to achieve the required
reductions.
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
for operating these facilities.
12
The TCEQ has also adopted revisions to its State Implementation Plan rules
that require an 89% reduction in NOx emissions from electric utility generation
plants in the Dallas-Fort Worth ozone non-attainment area and a 51% reduction in
NOx emissions from electric utility generation plants in East and Central Texas.
The cost of compliance will be reduced due to emission trading provisions in the
rules.
Water -- The TCEQ and the EPA have jurisdiction over water discharges
(including storm water) from all domestic facilities. TXU Energy's and Oncor's
facilities 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 plants and 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 (Texas Act) and at
the federal level under the Resource Conservation and Recovery Act of 1976, as
amended, (RCRA) and the Toxic Substances Control Act (TSCA). The EPA has issued
regulations under the RCRA and TSCA, and the TCEQ has issued regulations under
the Texas Act applicable to TXU Energy and Oncor's facilities. TXU Energy has
registered solid waste disposal sites and has obtained or applied for such
permits as are required by such regulations.
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. No appeal was taken from the denial of the license application, and
that denial is now final. The nature and extent of future efforts by the State
of Texas to provide for a disposal site are presently uncertain. 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.
Item 3. LEGAL PROCEEDINGS
In September 1999, Quinque Operating Company (Quinque) filed suit in the
State District Court of Stevens County, Kansas against over 200 gas pipeline
companies, including TXU Gas (named in the litigation as ENSERCH Corporation).
The suit was removed to federal court; however, a motion to remand the case back
to Kansas State District Court was granted in January 2001, and the case is now
pending in Stevens County, Kansas. The plaintiffs amended their petition to join
TXU Fuel Company (TXU Fuel), a subsidiary of TXU Energy, as a defendant in this
litigation. Quinque has dismissed its claims and a new lead plaintiff has filed
an amended petition in which the plaintiffs seek to represent a class consisting
of all similarly situated gas producers, overriding royalty owners, working
interest owners and state taxing authorities either from whom defendants had
purchased natural gas or who received economic benefit from the sale of such gas
since January 1, 1974. No class has been certified. The petition alleges that
the defendants have mismeasured both the volume and heat content of natural gas
delivered into their pipelines resulting in underpayments to plaintiffs. No
amount of damages has been specified in the petition with respect to TXU Gas or
TXU Fuel. While TXU Gas and TXU Fuel are unable to estimate any possible loss or
predict the outcome of this case, TXU Gas and TXU Fuel believe these claims are
without merit and intend to vigorously defend this suit.
On November 21, 2000, the City of Denton, Texas and other Texas cities
filed suit in the 134th Judicial District Court of Dallas County, Texas against
TXU Gas, US Holdings and TXU Corp. The petition alleges claims for breach of
contract, negligent representation, fraudulent inducement of contract, breach of
duty of good faith and fair dealing and unjust enrichment related to the
13
defendants' alleged exclusion of certain revenues from the cities' franchise fee
base. No specified damages have been alleged. All of the plaintiff cities have
now executed a settlement agreement to settle this suit. Such resolution will
not have a material effect on US Holdings' financial position, results of
operations or cash flows.
Also see discussion above under "Regulation and Rates."
General -- US Holdings and its subsidiaries are involved in various legal
and administrative proceedings the ultimate resolution of which, in the opinion
of each, should not have a material effect upon their financial position,
results of operations or cash flows.
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
All of US Holdings' common stock is owned by TXU Corp. Reference is made
to Note 9 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.
14
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 2003) in May 2003) Other Directorships
- ------------------ ---- ----------------------- --------------------- --------------------------------------
Michael J. McNally 48 None February 16, 1996 Executive Vice President of TXU Corp.
; prior thereto, Executive Vice
President and Chief Financial
Officer of TXU Corp. and Executive
Vice President of US Holdings;
other directorships: Oncor, TXU
Energy, TXU Gas and TXU Europe
Limited.
Erle Nye 65 Chairman of the Board September 17, 1982 Chairman of the Board and Chief
and Chief Executive Executive of TXU Corp., Oncor, TXU
Energy, TXU Gas and US Holdings;
other directorships: TXU Corp.,
Oncor, TXU Energy, TXU Gas and TXU
Europe Limited.
Eric H. Peterson 42 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, TXU Energy and TXU Gas.
R. A Wooldridge 65 None January 1, 2002 Partner in the law firm of Hunton &
Williams; other directorships:
Oncor, TXU Energy, TXU Gas and TXU
Europe Limited.
Directors of US Holdings receive no compensation in their capacity as Directors.
15
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 2003) in May 2003) (Preceding Five Years)
- ---------------- ---- ---------------------- ----------------------- ------------------------------------
Erle Nye 65 Chairman of the Board February 20, 1987 Chairman of the Board and Chief
and Chief Executive Executive of TXU Corp., Oncor,
TXU Energy,TXU Gas and US Holdings.
H. Dan Farell 53 Executive Vice March 26, 2003 Executive Vice President and Chief
President Financial Officer of TXU Corp.
and Executive Vice President of
US Holdings; prior thereto,President
of TXU Gas and TXU Gas Distribution;
prior thereto, President of TXU Gas
Distribution and Oncor Distribution;
prior thereto, Executive Vice President
of TXU Electric,TXU Gas Distribution
and TXU SESCO; prior thereto,Chairman
of the Board of TXU Electricity Limited
and Managing Director of TXU Australia.
Brian N. Dickie 48 President, TXU Energy December 12, 2001 Executive Vice President of TXU
Corp. and President of TXU
Energy; prior thereto, Executive
Vice President of TXU Corp. and
President of TXU Energy Group;
prior thereto, President and
Chief Operating Officer of
Booz Allen & Hamilton, Inc.;
prior thereto, President,
Worldwide Commercial Business of
Booz Allen & Hamilton, Inc.
T. L. Baker 57 Vice Chairman, Oncor November 4, 2002 Executive Vice President of TXU
Corp. and Vice Chairman of Oncor
and TXU Gas; prior thereto,
President of Oncor and TXU Gas;
prior thereto, President of TXU
Electric Company; prior thereto,
President of Electric Service
Division of TXU Electric Company,
TXU Gas Distribution and TXU
SESCO.
M. S. Greene 57 President, Oncor November 4, 2000 President of Oncor; prior thereto,
President of TXU Lone Star
Pipeline and Transmission
Division of Oncor; prior thereto,
Executive Vice President of TXU
Fuel and TXU Mining.
There is no family relationship between any of the above-named Directors and
Executive Officers.
16
Item 11. EXECUTIVE COMPENSATION
US Holdings (the Company) and its affiliates have paid or 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. Accordingly,
amounts reported as Bonus in 2002 reflect performance in 2001 and amounts
reported as LTIP Payouts in 2002 reflect performance for the three years ended
in March 2002. Information relating to compensation provided in 2003 based on
performance in 2002 is contained in the footnotes to the Table and in the
Organization and Compensation Committee Report which follows the footnotes.
SUMMARY COMPENSATION TABLE
Annual Compensation Long-Term Compensation
---------------------------------- --------------------------------------
Awards Payouts
------------------------ ------------
Other Restricted Securities All Other
Annual Stock Underlying LTIP Compen-
Name and Salary Bonus Compen-sation Awards Options/ Payouts sation
Principal Position Year ($) ($) (6) ($) ($) (7) SARs (#) ($) (8) ($) (9)
- ------------------------- ------ ---------- ---------- ------------ ---------- ------------ ------------ -----------
Erle Nye (1) (10).... 2002 1,037,500 1,950,000 --- 236,250 --- 4,286,400 299,985
Chairman of the Board 2001 964,583 475,000 --- 694,375 --- 519,747 222,658
and Chief Executive 2000 950,000 380,000 --- 593,750 --- 399,793 218,101
of the Company
Brian N. Dickie (2) (10) 2002 856,667 625,000 --- 193,500 --- 1,071,600 122,629
President, TXU Energy 2001 823,333 252,500 --- 441,500 --- --- 83,229
2000 779,167 240,000 --- 420,000 --- --- 64,672
Michael J. McNally (3) 2002 581,667 500,000 --- 132,750 --- 1,430,624 90,695
(10)Executive Vice 2001 523,333 200,000 --- 321,500 --- 264,327 62,847
President 2000 466,667 150,000 --- 262,500 --- 190,094 129,159
of the Company
T. L. Baker (4) (10). 2002 495,000 500,000 --- 112,500 --- 1,109,770 119,960
Vice Chairman, Oncor 2001 449,167 125,000 --- 230,750 --- 111,800 89,374
2000 399,167 125,000 --- 219,500 --- 93,968 84,152
M. S. Greene (5) (10) 2002 326,667 200,000 --- 73,800 --- 351,516 82,420
President, Oncor 2001 311,667 81,500 --- 153,500 --- 18,659 62,710
2000 283,333 75,000 --- 142,500 --- 6,021 59,487
- -------------------------
(1) Compensation amounts represent compensation paid by TXU Corp.
(2) Mr. Dickie was elected President of TXU Energy effective December 12,
2001. Compensation amounts represent compensation paid by TXU Energy.
(3) Mr. McNally was elected Executive Vice President of the Company
effective January 1, 2002. Compensation amounts represent compensation
paid by TXU Business Services.
(4) Mr. Baker was elected Vice Chairman of Oncor effective November 4,
2002. Compensation amounts represent compensation paid by Oncor.
(5) Mr. Greene was elected President of Oncor effective November 4, 2002.
Compensation amounts represent compensation paid by Oncor.
(6) 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). Amounts reported for 2002
resulted from performance in 2001; no AIP awards for 2002 performance
were provided in 2003 to any officers. Under the current terms of the
AIP, target incentive awards ranging from 20% to 75% of base salary,
and 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 performance measurement criteria
established in advance by TXU Corp.'s Organization and Compensation
Committee (Committee), as well as the Committee's evaluation of the
participant's and TXU Corp.'s performance. Amounts reported for Mr. Nye
17
as Bonus also include amounts provided in his employment contract as
discussed in footnote (10) and an additional bonus of $750,000 awarded
in February 2002 in recognition of his contributions to TXU Corp.'s
performance in 2001.
(7) 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 deferral 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 (9). 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 Awards and Incentive Awards
made in prior years under DICP provisions that are no longer effective
and dividends reinvested thereon, the number and market value at
December 31, 2002 of such Units (each of which is equal to one share of
common stock) held in the DICP accounts for Messrs. Nye, Dickie,
McNally, Baker and Greene were 61,832 ($1,155,022), 32,994 ($616,328),
23,966 ($447,685), 19,607 ($366,259) and 13,170 ($246,016),
respectively.
(8) Amounts reported as LTIP Payouts in the Summary Compensation Table are
attributable to the vesting and distribution of performance-based
restricted stock awards under the Long-Term Incentive Compensation Plan
(LTICP) and the distribution during the year of earnings on salaries
previously deferred under the DICP.
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, 2002, of
performance-based restricted stock to the named executive officers may
vest at the end of a three-year performance period 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 three-year period compared to the total returns provided by
the companies comprising the Standard & Poor's 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. For 2002,
based on TXU Corp. achieving the 5th highest total return to
shareholders of the returns provided by the companies comprising the
Standard & Poor's Electric Utilities Index over the three-year period
ending March 31, 2002, Messrs. Nye, Dickie, McNally, Baker and Greene
each received 200% of the restricted shares awarded in May of 1999,
which stock was valued at $4,286,400, $1,071,600, $1,393,080,
$1,071,600 and $321,480, respectively.
Amounts reported also include earnings distributed during the year on
salaries previously deferred under the DICP for Messrs. McNally, Baker
and Greene of $37,544, $38,170 and $30,036, respectively.
18
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, 2002 held for Messrs. Nye,
Dickie, McNally, Baker and Greene were 376,431 ($7,031,731), 48,613
($908,091), 86,008 ($1,606,629), 68,207 ($1,274,107) and 22,620
($422,542), 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 those deferred salaries for 2002 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 Performance
Shares, or Other Number of or Other
Units or Period Until Shares, Units Period Until Estimated Future Payouts
Other Maturation or Other Maturation or --------------------------
Name Rights(#) or Payout Right (#) Payout Minimum (#) Maximum (#)
- ----------------- ---------- ------------ ---------- ----------- ----------- -----------
Erle Nye........... 2,877 5 Years 150,000 3 Years 0 300,000
Brian N. Dickie.... 2,356 5 Years 18,000 3 Years 0 36,000
Michael J. McNally. 1,616 5 Years 40,000 3 Years 0 80,000
T. L. Baker........ 1,370 5 Years 40,000 3 Years 0 80,000
M. S. Greene....... 899 5 Years 9,000 3 Years 0 18,000
(9) 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. Currently, 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, Dickie, McNally,
Baker and Greene were $12,000, $9,000, $9,000, $9,000 and $9,000,
respectively, during 2002.
Under the Salary Deferral Plan (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 ($106,030 for the program year
beginning January 1, 2002) 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
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 award. 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 2002, matching awards, which are included
under All Other Compensation in the Summary Compensation Table, were
made for Messrs. Nye, Dickie, McNally, Baker and Greene in the amounts
of $103,000, $85,467, $57,667, $49,200 and $40,733, respectively.
19
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
death benefit of the participants' insurance policies are equal to two,
three or four times their annual Insurance Program compensation
depending on their 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. 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 it has
made 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 2002,
the economic benefit derived by Messrs. Nye, Dickie, McNally, Baker and
Greene from the term insurance coverage provided and the interest
foregone on the remainder of the insurance premiums paid by the Company
amounted to $184,985, $28,162, $24,028, $61,760 and $32,687,
respectively.
(10) TXU Corp. has entered into employment agreements with Messrs. Nye,
Dickie, McNally, Baker and Greene as hereinafter described in this
footnote.
Effective June 1, 2002, TXU Corp. entered into a new employment
agreement with Mr. Nye, which supersedes 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 one-time bonus of $1,000,000 in
consideration for his entering into the new agreement. Such bonus 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 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 bonus annual installment payments; 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 Corp. entered into a new employment agreement with Mr. Dickie,
effective December 3, 2002, which supersedes and replaces his previous
employment agreement. The agreement provides for the continued service
of Mr. Dickie through May 31, 2005 (Term). Under the terms of the
agreement, Mr. Dickie will, during the Term, be entitled to a minimum
annual base salary of $860,000, eligibility for an annual bonus under
the AIP, and minimum annual restricted stock awards of 15,000 shares
under the LTICP. The agreement also provides for certain special
retirement compensation. The agreement provides for certain severance
benefits in the event Mr. Dickie resigns during the Term, including a
payment equal to annual base salary and target bonus, payments for
otherwise forfeited incentive compensation, and health care benefits.
The agreement entitles Mr. Dickie to certain severance benefits in the
event he is terminated without cause during the Term, including a
payment equal to the greater of the base salary and target bonus that
Mr. Dickie would have received for the remainder of the Term or annual
base salary and target bonus; 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. McNally
effective July 1, 2000. The agreement, as amended, provides for the
continued service by Mr. McNally through June 30, 2004 (Term). Under
the terms of the agreement, Mr. McNally will, during the Term, be
entitled to a minimum annual base salary of $500,000, eligibility for
an annual bonus under the terms of the AIP, and minimum annual
restricted stock awards of 20,000 shares under the LTICP. The agreement
entitles Mr. McNally to certain severance benefits in the event he is
terminated without cause during the Term, including a payment equal to
the greater of his annual base salary and target bonus, or the total
20
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. Baker effective
July 1, 2000. The agreement, as amended, provides for the continued
service by Mr. Baker through June 30, 2004 (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, 2004 (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.
TXU Corp. and its participating subsidiaries maintain retirement plans
(Retirement Plan), which are 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 2002 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 Retirement Plan also contains a cash balance component, which
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, during a one-time election period in
21
2001 (and for certain employees covered by collective bargaining agreements,
during other specifically negotiated election periods) 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 plan
during the 2001 election period. 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, 2002, the estimated
annual benefit payable to Mr. Nye under such component at normal retirement age
is $1,138,269. As of December 31, 2002, years of accredited service under the
Retirement Plan for Messrs. Nye, Dickie, McNally, Baker and Greene were 40, 4,
6, 32, and 32, respectively.
TXU 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 defined
benefit component of the Retirement Plan, earnings also include AIP awards (for
2002, 100% of the AIP award, and for 2001 and 2000, 50% of the AIP awards, are
reported under Bonus for the named officers in the Summary Compensation Table).
The table set forth above illustrates the total annual benefit 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.
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. 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 2003 annual meeting of shareholders.
22
ORGANIZATION AND COMPENSATION COMMITTEE REPORT
ON EXECUTIVE COMPENSATION
The Organization and Compensation Committee of the Board of Directors
(Committee) is responsible for reviewing and establishing the compensation of
the executive officers of the Company. The Committee consists of directors of
the Company who are not employees or former employees of the Company 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. 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.
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 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 of any awards of performance-based restricted
shares, if any, 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. As amended in 2001
with respect to awards provided in 2002 and thereafter, 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, 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.
23
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 Electric Utilities Index which are reflected in the
graph on page 21. 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 2002, the Committee has considered officers' compensation matters
at several meetings including those held in February and May of 2002 and in
February of 2003. The results of Committee actions taken in February and May of
2002 are included in the Summary Compensation Table on page 9 of this proxy
statement. Generally speaking, the actions taken at those meetings in 2002
reflected the Company's exemplary performance in 2001 (total return of 12.2%,
the 2nd highest of the 10 largest utilities in the United States) and for the
three years ended in March 2002 (total return of 57.9%, the 5th highest of the
28 companies comprising the Standard & Poor's Electric Utilities Index). Actions
taken at its meeting in February 2003 reflect the Company's recent business
reversals and include freezing executive officers' salaries and not providing
any AIP awards for 2002 performance. Moreover, it is anticipated that awards of
performance-based restricted stock under the Long-Term Plan which were provided
in May 2000 will be forfeited as a result of recent performance, and that awards
provided in 2001 and 2002 may also be completely or partially forfeited
depending on returns during the remainder of the relevant performance periods.
With respect to the base salaries of the officers, at its meeting in
February of 2002, the Committee authorized certain increases in salaries,
including the Chief Executive's. Those increases were intended to reflect
competitive market comparisons and to establish base salaries around the median
of such markets. Increases provided in February 2002 are reflected in the
Summary Compensation Table. As noted earlier, at its meeting in February 2003
the Committee decided not to increase the base pay of any of the executive
officers.
AIP awards provided by the Committee in February 2002 were based upon
the Company's strong performance in 2001 and are reflected in the Summary
Compensation Table. Based upon the Company's performance in 2002, including its
failure to achieve the earnings per share targets established in advance, the
Committee, at its meeting in February 2003, determined not to provide AIP awards
to any officers for 2002 performance. Discretionary cash bonuses were provided
to a limited number of officers in February 2003 as the result of superior
performance in certain business activities and other individual circumstances.
At its meetings in February 2002 and February 2003, the Committee
provided awards of performance-based restricted shares under the Long-Term Plan
to certain officers, including the Chief Executive. Information relating to
awards made to the named executive officers in 2002 is contained in the Table on
page 11 of this proxy statement. The ultimate value of all of the awards, if
any, will be determined by the Company's total return to shareholders over
selected performance periods compared to the total returns for those periods of
the companies comprising the Standard & Poor's 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 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.
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.
Additionally, with respect to the Long-Term Plan, the Committee, at its
meeting in May 2002, considered the performance-based restricted stock awards
provided to certain officers in May 1999. Based upon its review and comparison
24
of the Company's total return to the returns provided by the companies
comprising the Standard & Poor's Electric Utilities Index, the Committee
determined that the Company's performance during the three-year performance
period ending in March 2002 permitted the payment of 200% of such 1999 awards.
As noted earlier, during the three-year performance period ending in March 2002,
the Company's total return of 57.9% was the 5th highest (85th percentile) of the
28 companies comprising the index at that time. Payments of these awards were
made in the form of the Company's stock and cash, and, for Messrs. Nye, Gibbs,
Dickie and McNally and Ms. Curry, the value of such cash and stock at the date
of distribution is included in the LTIP Payouts column of the Summary
Compensation Table on page 9 of this proxy statement.
With respect to the compensation of the Chief Executive, in February
2002 the Committee increased Mr. Nye's base salary as Chief Executive to an
annual rate of $1,050,000 representing a $75,000 or 7.6% increase over the
amount established for Mr. Nye in May of 2001. Based upon the Committee's
evaluation of individual and Company performance in 2001, including the
Company's total return of 12.2% which was the second highest of the 10 largest
utilities in the United States, the Committee provided Mr. Nye with an AIP award
of $1,000,000 and a special bonus award of $750,000 compared to the prior year's
AIP award of $950,000. The Committee also awarded 150,000 shares of
performance-based restricted stock to Mr. Nye. Under the terms of his award, Mr.
Nye can earn from 0% to 200% of the original award, depending on the Company's
total return to shareholders over a three-year period (April 1, 2002 through
March 31, 2005) compared to the total return provided by the companies
comprising the Standard & Poor's Electric Utilities Index. In addition, as
previously noted in this report and based upon the Company's total return of
57.9% for the three years ended in March of 2002, the Committee in May of 2002
approved the payment of 200% of the 1999 performance-based restricted stock
awards under the Long-Term Plan, which for Mr. Nye was 80,000 shares.
Actions taken by the Committee in 2003 with respect to the Chief
Executive's compensation reflect the Company's recent business reversals. In
February 2003, the Committee established Mr. Nye's base salary at an annual rate
of $1,050,000, which is the same rate as established in 2002. In recognition of
the Company's cost reduction efforts, Mr. Nye has 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. Additionally, in 2003 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-year and three-year
performance periods. Under the terms of his 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 Electric Utilities
Index. The level of compensation established for the Chief Executive in 2002 and
in 2003 was based upon the Committee's subjective evaluation of the information
contained in this report consistent with the Committee's policy relating to
total compensation.
As previously reported, the Company has entered into employment
agreements, as approved by the Committee, with certain officers, including the
Chief Executive. Mr. Nye's prior employment agreement was superceded, effective
June 1, 2002, by a new agreement which was approved in May 2002. The terms of
employment agreements with the named executive officers are described in
Footnote 6 to the Summary Compensation Table on pages 12, 13 and 14 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.
25
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. Awards
under the AIP and the Long-Term Plan are expected to be fully deductible. The
DICP and the Salary Deferral Program have been amended to require the deferral
of distributions of maturing amounts until the time when such amounts would be
deductible. A portion of the special bonus amounts provided to Mr. Nye in 2002
are not expected to be deductible but such amounts are not material.
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
Derek C. Bonham Margaret N. Maxey
William M. Griffin Charles R. Perry (retired February 2003)
Kerney Laday Herbert H. Richardson
26
PERFORMANCE GRAPH
The following graph compares the performance of TXU Corp.'s common
stock to the S&P 500 Index and S&P Electric Utilities Index for the last five
years. The graph assumes the investment of $100 at December 31, 1997 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 12/31/02
Line graph inserted here that shows Cumulative Total Returns in dollars
by years 1997-2002.
1997 1998 1999 2000 2001 2002
- --------------------------------------------- ----------- ---------- ------------ ----------- ----------- ----------
TXU Corp................................ 100 118 96 128 143 59
- --------------------------------------------- ----------- ---------- ------------ ----------- ----------- ----------
S&P 500 Index........................... 100 129 156 141 125 97
- --------------------------------------------- ----------- ---------- ------------ ----------- ----------- ----------
S&P Electric Utilities Index............ 100 115 93 143 131 112
- --------------------------------------------- ----------- ---------- ------------ ----------- ----------- ----------
27
Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS
Security ownership of certain beneficial owners at March 17, 2003:
Amount and Nature
Name and Address Of Beneficial
Title of Class of Beneficial Owner Ownership Percent of Class
---------------------- ------------------------- ----------------------- -------------------
Common stock, TXU Corp. 52,293,533 shares 97.78%
without par value, Energy Plaza voting and
of US Holdings 1601 Bryan Street investment power
Dallas, Texas 75201
Common stock without TXU Energy 524,329 shares voting 2.22%
par value of US Industries Company(a) and
Holdings Energy Plaza investment power
1601 Bryan Street
Dallas, Texas 75201
(a) A wholly-owned subsidiary of TXU Corp.
Security ownership of management at March 17, 2003:
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 17,
2003. 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 Deferred Plan (1) Total
---- ------------------ ------------- -----
T. L. Baker....................... 91,588 28,104 119,692
Brian N. Dickie................... 49,682 45,971 95,653
M. S. Greene...................... 30,632 19,127 49,759
Michael J. McNally................ 127,344 33,734 161,078
Erle Nye.......................... 420,366 87,792 508,158
Eric H. Peterson.................. 26,443 0 26,443
R. A. Wooldridge.................. 9,576 0 9,576
All Directors and Executive
Officers as a group (7)......... 755,631 214,728 970,359
- -----------------
(1) Share units held in deferred compensation accounts under the Deferred
and Incentive Compensation Plan. Although this plan allows 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.
Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
R. A. Wooldridge, a Director of US Holdings, is a partner of Hunton &
Williams, which provides legal services to US Holdings.
28
Item 14. 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 within 90 days of
the filing date of this annual report. Based on the evaluation performed, US
Holdings' management, including the principal executive officer and principal
financial officer, concluded that the disclosure controls and procedures were
effective.
There have been no significant changes in US Holdings' controls or in
other factors that could significantly affect these controls subsequent to the
evaluation referenced above.
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 - Consolidated Financial Statistics........................... A-2
Management's Discussion and Analysis of Financial Condition
and Results of Operations...................................................... A-3
Statement of Responsibility........................................................... A-43
Independent Auditors' Report.......................................................... A-44
Statements of Consolidated Income for each of the three years in the
period ended December 31, 2002................................................. A-45
Statements of Consolidated Comprehensive Income for each of the
three years in the period ended December 31, 2002.............................. A-45
Statements of Consolidated Cash Flows for each of the three years in
the period ended December 31, 2002............................................. A-46
Consolidated Balance Sheets, December 31, 2002 and 2001............................... A-47
Statements of Consolidated Shareholders' Equity for each of the three years in
the period ended December 31, 2002............................................. A-48
Notes to Financial Statements......................................................... A-49
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:
Reports on Form 8-K filed since September 30, 2002, are as follows:
Date of Report Item Reported
------------- -------------
November 5, 2002 Item 2. Disposition of Assets.
Item 7. Financial Statements and Exhibits.
November 21, 2002 Item 5. Other Events and Regulation FD Disclosure.
Item 7. Financial Statements and Exhibits.
November 21, 2002 Item 5. Other Events and Regulation FD Disclosure.
Item 7. Financial Statements and Exhibits.
November 22, 2002 Item 5. Other Events and Regulation FD Disclosure.
Item 7. Financial Statements and Exhibits.
November 26, 2002 Item 5. Other Events and Regulation FD Disclosure
Item 7. Financial Statements and Exhibits.
December 17, 2002 Item 5. Other Events and Regulation FD Disclosure
February 26, 2003 Item 5. Other Events and Regulation FD Disclosure
Item 7. Financial Statements and Exhibits.
(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 27, 2003 By: /s/ ERLE NYE
------------------------------
(Erle Nye, 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/ ERLE NYE Principal Executive
- ----------------------------------------------------------- Officer and Director March 27, 2003
(Erle Nye, Chairman of the Board and Chief Executive)
/s/ H. DAN FARELL Principal Financial
- ----------------------------------------------------------- Officer and Director March 27, 2003
(H. Dan Farell)
/s/ BIGGS C. PORTER Principal Accounting
- ----------------------------------------------------------- Officer and Director March 27, 2003
(Biggs C. Porter, Controller)
/s/ MICHAEL J. McNALLY Director March 27, 2003
- -----------------------------------------------------------
(Michael J. McNally)
/s/ ERIC H. PETERSON Director March 27, 2003
- -----------------------------------------------------------
(Eric H. Peterson)
/s/ R. A. WOOLDRIDGE Director March 27, 2003
- -----------------------------------------------------------
(R. A. Wooldridge)
31
TXU US HOLDINGS COMPANY
CERTIFICATION OF CEO
I, Erle Nye, Chairman of the Board and Chief Executive of TXU US Holdings
Company, certify that:
1. I have reviewed this annual report on Form 10-K of TXU US Holdings Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure that material
information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this annual report is being
prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data and
have identified for the registrant's auditors any material weaknesses
in internal controls; and
b. any fraud, whether or not material, that involves management
or other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 27, 2003 /s/Erle Nye
---------------------------
Signature: Erle Nye
Title: Chairman of the Board and Chief Executive
32
TXU US HOLDINGS COMPANY
CERTIFICATION OF PFO
I, H. Dan Farell, Principal Financial Officer of TXU US Holdings Company,
certify that:
1. I have reviewed this annual report on Form 10-K of TXU US Holdings Company;
2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this annual report;
3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this annual report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a. designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is being prepared;
b. evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and
c. presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a. all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data and
have identified for the registrant's auditors any material weaknesses
in internal controls; and
b. any fraud, whether or not material, that involves management
or other employees who have a significant role in the registrant's
internal controls; and
6. The registrant's other certifying officers and I have indicated in this
annual report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: March 27, 2003 /s/H. Dan Farell
------------------------------
Signature: H. Dan Farell
Title: Principal Financial Officer
33
Appendix A
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
INDEX TO FINANCIAL INFORMATION
December 31, 2002
Page
Selected Financial Data - Consolidated Financial Statistics................................. A-2
Management's Discussion and Analysis of Financial Condition and Results of Operations....... A-3
Statement of Responsibility................................................................. A-43
Independent Auditors' Report................................................................ A-44
Financial Statements:
Statements of Consolidated Income and Comprehensive Income............................... A-45
Statements of Consolidated Cash Flows.................................................... A-46
Consolidated Balance Sheets.............................................................. A-47
Statements of Consolidated Shareholders' Equity.......................................... A-48
Notes to Financial Statements............................................................ A-49
A-1
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
SELECTED FINANCIAL DATA
CONSOLIDATED FINANCIAL STATISTICS
Year Ended December 31,
2002 2001 2000 1999 1998
---- ---- ---- ---- ----
(Millions of Dollars, except ratios)
Total assets -- end of year................................... $24,519 $21,838 $23,011 $20,292 $20,897
- ------------------------------------------------------------------------------------------------------------------------
Property, plant and equipment - net-- end of year............. $16,183 $16,156 $15,907 $15,775 $15,913
Capital expenditures...................................... 787 965 781 585 509
- ------------------------------------------------------------------------------------------------------------------------
Capitalization-- end of year
Exchangeable subordinated notes (a) ....................... $ 750 $ - $ - $ - $ -
All other long-term debt, less amounts due currently....... 5,863 5,819 5,264 4,908 5,531
TXU US Holdings Company obligated, mandatorily redeemable,
preferred securities of subsidiary trusts holding solely
junior subordinated debentures of TXU US Holdings Company
(trust securities)........................................ - - 829 824 823
Preferred stock:
Not subject to mandatory redemption....................... 115 115 115 115 115
Subject to mandatory redemption........................... 21 21 21 21 21
Common stock equity......................................... 6,587 7,349 7,336 7,147 7,021
------- ------- ------- ------- -------
Total.................................................. $13,336 $13,304 $13,565 $13,015 $13,511
======= ======= ======= ======= =======
Capitalization ratios-- end of year
Exchangeable subordinated notes (a)........................ 5.6% -% -% -% -%
All other long-term debt, less amounts due currently....... 44.0 43.8 38.8 37.7 40.9
Trust securities........................................... - - 6.1 6.3 6.1
Preferred stock............................................ 1.0 1.0 1.0 1.1 1.0
Common stock equity........................................ 49.4 55.2 54.1 54.9 52.0
------- ------ ------ ------ ------
Total................................................. 100.0% 100.0% 100.0% 100.0% 100.0%
======= ===== ====== ====== =====
- ------------------------------------------------------------------------------------------------------------------------
Embedded interest cost on long-term debt-- end of year (b)..... 6.9% 6.1% 7.5% 7.4% 8.2%
Embedded distribution cost on trust securities-- end of year... - - 8.3% 8.4% 8.4%
Embedded dividend cost on preferred stock--end of year (c)..... 7.5% 7.5% 8.1% 11.0% 13.5%
- ------------------------------------------------------------------------------------------------------------------------
Revenues ...................................................... $8,140 $8,020 $7,621 $6,324 $6,607
Net income available for common stock (d)...................... 352 707 777 724 767
- ------------------------------------------------------------------------------------------------------------------------
Ratio of earnings to fixed charges............................. 2.4 3.3 3.1 2.9 3.1
Ratio of earnings to fixed charges and preferred dividends..... 2.3 3.3 3.0 2.8 3.0
- ------------------------------------------------------------------------------------------------------------------------
(a) Classified as long-term debt.
(b) Represents the annual interest and amortization of any discounts,
premiums, issuance costs and any deferred gains/losses on
reacquisitions divided by the carrying value of the debt plus the
unamortized balance of any discounts, premiums, issuance costs and
gains/losses on reacquisitions at the end of the year.
(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, was
6.7% for 2002, 2001, 2000, 1999 and 1998.
(d) Net income available for common stock includes extraordinary charges
of $134 million (after-tax) and $154 million (after-tax) for 2002 and
2001, respectively.
Certain previously reported financial statistics have been reclassified to
conform to current classifications.
A-2
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
BUSINESS
TXU US Holdings Company (US Holdings) is an energy company that engages in
power production (electricity generation), wholesale energy sales, retail energy
sales and related services, portfolio management, including risk management and
certain trading activities, and the delivery of electricity. US Holdings is a
holding company that conducts its operations through its TXU Energy Company LLC
(TXU Energy) and Oncor Electric Delivery Company (Oncor) subsidiaries.
Use of the term "US Holdings," unless otherwise noted or indicated by the
context, refers to US Holdings, a holding company, and/or its consolidated
subsidiaries.
CRITICAL ACCOUNTING POLICIES
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.
US Holdings' significant accounting policies are detailed in Note 2 to
Financial Statements. US Holdings follows accounting principles generally
accepted in the United States of America. 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 manage market risks related to
changes in commodity prices, including costs of fuel for generation of power, as
well as changes in interest rates. These financial instruments are accounted for
in accordance with Statement of Financial Accounting Standards (SFAS) No. 133,
"Accounting for Derivative Instruments and Hedging Activities" and, prior to
October 26, 2002, Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting
for Contracts Involved in Energy Trading and Risk Management Activities." The
majority of financial instruments entered into by US Holdings are derivatives as
defined in SFAS No. 133.
SFAS No. 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 No. 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. Any
hedge ineffectiveness is recorded in earnings. Amounts are reclassified from
other comprehensive income to earnings as the underlying transactions occur and
realized gains and losses are recognized in earnings. US Holdings has no fair
value hedges.
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 No.
133 for these non-trading transactions, providing the underlying transactions
continue to be forecasted to occur. Effectiveness is assessed based on changes
in cash flows of the hedges as compared to changes in cash flows of the hedged
items.
Pursuant to SFAS No. 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.
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Financial instruments entered into in connection with indebtedness to
manage interest rate risks are generally accounted for as cash flow hedges in
accordance with SFAS No. 133.
EITF Issue No. 98-10 required mark-to-market accounting for energy-related
contracts, whether or not derivatives under SFAS No. 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 Issue No. 98-10 and were therefore marked-to-market. On October
25, 2002, the EITF rescinded EITF Issue No. 98-10. Pursuant to this rescission,
only financial instruments that are derivatives under SFAS No. 133 will be
subject to mark-to-market accounting. See discussion below under "Changes in
Accounting Standards."
In June 2002, in connection with the EITF's consensus on 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", 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. If the commercial and industrial (C&I) retail
contracts that US Holdings enters into do not meet the requirements of the
revised guidance, then income from such contracts will be recognized on a
settlement basis. See discussion below under "Commodity Contracts and
Mark-to-Market Activities."
The majority of financial instruments entered into by US Holdings for the
purpose of managing risk or optimizing margins in meeting the energy demands of
customers are derivatives and will continue to be subject to SFAS No. 133.
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.). As a matter of
policy, however, US Holdings generally does not recognize any income or loss
from the illiquid periods.
Revenue Recognition -- US Holdings generally records revenues under the
accrual method, with the exception of certain large C&I retail contracts that
are derivatives as defined in SFAS No. 133 and have therefore been
marked-to-market. 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 T&D 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. The accrued
revenue is based on actual daily revenues for the most recent metered period
applied to the number of unmetered days through the end of the period.
As a result of the opening of the Texas market to competition and related
changes in systems and processes within the Electric Reliability Council of
Texas (ERCOT), adjustments are recorded for accounts receivable from or payable
to ERCOT related to system balancing and are recorded net in revenues. Such
balances reflect estimates of volumetric data and are subject to adjustment as
data is reconciled and final settlements are determined. Net accounts receivable
from ERCOT totaled approximately $40 million at December 31, 2002, covering
periods that date back to 2001.
Revenues reflect unrealized gains and losses related to large C&I retail
contracts, including unrealized gains recorded upon inception of these
contracts, as discussed below under "Commodity Contracts and Mark-to-Market
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Activities." Results of wholesale portfolio management activities, which
represent realized and unrealized gains and losses from transacting in
energy-related contracts, are also 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.
The historical financial statements for periods prior to 2002 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 regulatory rate amounts are applied prospectively.
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 debt expense is based on factors such as historical write-off
experience, agings of current 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 effects of provider of last resort (POLR)
rules (as discussed below under "Regulation and Rates"), billing delays due to
new procedures within ERCOT and changes in systems and processes, and customer
churn due to competitor actions has added a level of complexity to the
estimation process. In 2002, US Holdings recorded bad debt expense of $163
million.
In connection with the opening of the Texas market to competition, the
Texas Legislature established a retail clawback provision intended to incent
affiliated retail electric providers (REPs) of utilities to actively compete for
customers outside their historical service territories. As discussed in Note 14
to Financial Statements, a retail clawback liability arises if TXU Energy
retains more than 60% of US Holdings' and TXU SESCO Company's former residential
and small business customers after the first two years of competition. The
amount of the liability is based on the number of such customers as of January
1, 2004 less the number of new customers from outside the historical service
territory multiplied by $90. In 2002, TXU Energy recorded a retail clawback
accrual of $185 million ($120 million after-tax) reported in cost of energy sold
and delivery fees in the statement of income. Over a two-year period beginning
January 1, 2004, the liability would be paid to Oncor, which in turn would pass
the credit to REPs, including TXU Energy, through reduced electricity delivery
rates. The accrual reflects assumptions and estimates regarding the number of
customers expected in and out of territory. The accrual is subject to further
adjustment as the actual measurement date approaches.
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 No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets." 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 current wholesale electricity market conditions and
reduced planned developmental capital spending. Fair value was determined based
on current appraisals of property and equipment. The charge is reported in other
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deductions in the statement of income. As the writedown is based on current
estimates, the remaining carrying value of the projects of $113 million is
subject to further adjustment should estimates of recoverable value change.
Goodwill and Intangible Assets -- US Holdings evaluates goodwill for
impairment at least annually in accordance with SFAS No. 142, "Goodwill and
Other Intangible Assets." US Holdings has performed impairment tests for its
reporting units and no goodwill impairment charges were recorded.
US Holdings primarily uses discounted cash flow analyses to test for
goodwill impairment. 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.
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.
Regulatory Assets and Liabilities -- The financial statements of US
Holdings' regulated business, represented by Oncor operations, reflect
regulatory assets and liabilities under cost-based rate regulation in accordance
with SFAS No. 71, "Accounting for the Effect of Certain Types of Regulation." As
a result of the 1999 Restructuring Legislation, (see Note 14 to Financial
Statements for further description), the electricity generation portion of US
Holdings' business no longer meets the criteria to apply regulatory accounting
principles. Accordingly, application of SFAS No. 71 to the generation portion of
US Holdings' business was discontinued as of June 30, 1999. Oncor's operations
continue to meet the criteria for recognition of regulatory assets and
liabilities. 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 17 to Financial Statements under "Regulatory Assets and
Liabilities.")
In 2002, US Holdings recorded an extraordinary loss of $134 million (net
of income tax benefit of $72 million) principally to write down the regulatory
asset related to securitization bonds to be issued in accordance with US
Holdings' settlement plan with the Public Utility Commission of Texas
(Commission) as described in Note 14 to Financial Statements. The regulatory
asset carrying value is intended to represent the estimated amount of future
cash flows to be recovered from REPs through increased rates; the determination
of such amount is based on estimates. The writedown, which was taken as a result
of the final approval of the settlement plan, reflects the impact of lower
interest rates. As actual interest rates on the bonds may differ from current
estimates, the regulatory asset carrying value, which was $1.7 billion at
December 31, 2002, is subject to further adjustment.
Defined Benefit Pension Plans and Other Postretirement Benefit Plans-- US
Holdings is a participating employer in the TXU Retirement Plan (Retirement
Plan), a defined benefit pension plan sponsored by TXU Corp. US Holdings also
participates 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
from TXU Corp. Reported costs of providing non-contributory defined pension
benefits and other postretirement benefits (see Note 11 to Financial Statements)
are dependent upon numerous factors, assumptions and estimates.
For example, these costs are impacted by actual employee demographics
(including age, compensation levels, and employment periods), the level of
contributions made to the plan, and earnings on plan assets. The Retirement
Plan's assets are primarily made up of equity and fixed income investments.
Changes made to the provisions of the plan may also impact current and future
pension costs. Fluctuations in actual equity market returns as well as changes
in general interest rates may result in increased or decreased pension costs in
future periods. Pension 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 and
pension costs.
In accordance with SFAS No. 87, "Employers' Accounting for Pensions,"
changes in pension obligations associated with these factors may not be
immediately recognized as pension costs on the income statement, but generally
are recognized in future years over the remaining average service period of plan
participants. As such, significant portions of pension costs recorded in any
period may not reflect the actual level of cash benefits provided to plan
participants.
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As of December 31, 2002, key assumptions of the Retirement Plan and other
postretirement benefit plans were revised, including decreasing the expected
return on plan assets from 9% to 8.5% and decreasing the assumed discount rate
from 7.5% to 6.75%. In selecting assumed discount rates, TXU Corp. considered
fixed income security yield rates for AA rated portfolios as reported by
Moody's. In selecting an assumed rate of return on plan assets, TXU Corp.
considered past performance and economic forecasts for the types of investments
held by the plan. The market value of the Retirement Plan assets has been
affected by sharp declines in equity markets since the first quarter of 2000.
Plan asset values have declined $151 million and $49 million in 2002 and 2001,
respectively. The projected benefit obligation has increased by $165 million as
a result of the change in the discount rate. Further, based on the current
assumptions and available information, in 2003 funding requirements for US
Holdings are expected to increase approximately $3 million and pension expense
is expected to increase, as a result of such changed assumptions and other
actions, a total of approximately $29 million over 2002 amounts. Pension cost
and cash funding requirements could increase in future years.
As a result of the Retirement Plan asset return experience, at December
31, 2002, US Holdings was required to recognize its portion of an additional
minimum liability as prescribed by SFAS No. 87 and SFAS No. 132, "Employers'
Disclosures about Pensions and Postretirement Benefits." The liability, which
totaled to $57 million ($37 million after-tax) for US Holdings, was recorded as
a reduction to shareholders' equity through a charge to Other Comprehensive
Income, and did not affect net income for 2002. The charge to Other
Comprehensive Income will be reversed in future periods to the extent the fair
value of trust assets exceeds the accumulated benefit obligation.
The amounts provided above for funding requirements, pension expense and
minimum liability adjustment mentioned above, represent allocations of the TXU
Corp. Retirement Plan to US Holdings.
RESULTS OF OPERATIONS
OVERVIEW
The results of operations and the related management's discussion of those
results for all periods presented reflect the change in format of the statements
of consolidated income and the impact of EITF Issue No. 02-3 as discussed below.
(See Note 2 to Financial Statements for description of new line items.)
Changes in Accounting Standards -- In June 2002, the EITF reached a
consensus on certain aspects of EITF Issue No. 02-3 regarding the presentation
of trading activities in the statement of income. The new rules were effective
on July 1, 2002, and required that all trading contracts (as defined by EITF
Issue No. 98-10), whether or not physically settled, be recorded net upon
settlement, rather than gross as a sale and cost of sale. US Holdings has
historically recorded financial contracts net, but has recorded those contracts
that provide for physical delivery gross upon settlement. Prior period amounts
have been reclassified to conform to this new reporting requirement.
Transactions affected by the new reporting requirements represent contracts that
provided for physical delivery but were settled financially without delivery, as
well as contracts physically settled but classified as trading activities. The
new reporting requirements had no impact on US Holdings' gross margin, net
income or cash provided by operating activities.
The table below summarizes the impact on US Holdings' operating revenues
and costs of energy sold and delivery fees for prior years of the new reporting
rules under EITF Issue No. 02-3.
Years Ended December 31,
------------------------
2001 2000
---- ----
Operating revenues before reclassification....................... $13,179 $12,939
Cost of energy sold and delivery fees netted with revenues....... (5,159) (5,318)
------- -------
Operating revenues after reclassification........................ $ 8,020 $ 7,621
======= =======
Cost of energy sold and delivery fees before reclassification.... $ 8,210 $ 8,510
Cost of energy sold and delivery fees netted with revenues....... (5,159) (5,318)
------ -------
Cost of energy sold and delivery fees after reclassification..... $ 3,051 $ 3,192
====== =======
On October 25, 2002, the EITF rescinded EITF Issue No. 98-10, which
required mark-to-market accounting for all trading activities. Pursuant to this
rescission, only financial instruments that are derivatives under SFAS No. 133
will be subject to mark-to-market accounting. Financial instruments that may not
A-7
be derivatives under SFAS No. 133, but were marked-to-market under EITF Issue
No. 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 approximately $100 million ($65 million after-tax) is
expected to be reported as a cumulative effect of an accounting change in the
first quarter of 2003. The expected cumulative effect adjustment represents net
gains previously recognized for these contracts under mark-to-market accounting.
See Note 2 to Financial Statements for discussion of other changes in
accounting standards.
2002 compared to 2001
Reference is made to comparisons of results by business segment presented
below.
US Holdings' operating revenues increased $120 million, or 1%, to $8.1
billion in 2002. The increase reflected a decline in the Electric Delivery
segment of $320 million and an increase in the Energy segment of $280 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 Electric Delivery segment providing services to unaffiliated
retail electric providers (REPs). The offsetting changes in the segments'
revenues reflected certain activities reported in the Electric Delivery segment
in 2001 that are reflected in the Energy segment's revenues in 2002, due to
changes in responsibility for such activities. Revenues in the Energy segment
reflected significantly higher wholesale sales volumes and a 9% decline in
retail electric 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..................................... $ 8,140 100% $ 8,020 100%
Cost and expenses:
Cost of energy sold and delivery fees............. 3,214 40% 3,051 38%
Operating costs.................................. 1,420 17% 1,300 16%
Depreciation and amortization related to operating
assets........................................ 650 8% 629 8%
------- ----- -------- ------
Gross margin........................................... $ 2,856 35% $ 3,040 38%
======= ===== ======== ======
Gross margin decreased $184 million, or 6%, to $2.9 billion in 2002.
This decline was driven by a $185 million ($120 million after-tax) accrual for
regulatory-related retail clawback (see discussion above under "Accounting for
Contingencies"), as the effect of lower retail electric volumes and higher
operating costs was offset by the effect of lower average electricity costs and
increased wholesale electric sales. Mark-to-market accounting for commodity
contracts reduced revenues and gross margin by $72 million in 2002 (as compared
to accounting on a settlement basis), and increased results by $314 million in
2001. (See discussion below under "Commodity Contracts and Mark-to-Market
Activities.") Operating costs rose $120 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 $67 million, or
11%, to $702 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.
Selling, general and administrative (SG&A) expense increased $289 million,
or 38%, to $1.1 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 that are expected to continue in 2003. Such actions
resulted in $31 million ($21 million after-tax) in severance charges in 2002,
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which contributed to the increase in SG&A expense. In addition, new POLR rules
established by the Commission are expected to result in reduced bad debt
expense. (See discussion in Note 14 to Financial Statements under "Provider of
Last Resort"). With the anticipated lower staffing and related administrative
expenses and reduced bad debts expense, SG&A expenses are expected to decline in
2003.
Franchise and revenue-based taxes decreased $31 million, or 7%, to $411
million in 2002. This decline was due to the effect of lower revenues on which
state and local gross receipts taxes are assessed.
Other income increased $26 million to $38 million in 2002. The 2002
period included $32 million of gains on dispositions of property.
Other deductions increased $127 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 (see discussion above under
"Impairment of Long-Lived Assets"). The 2001 period included 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 $18 million in various asset writedowns.
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 other charges decreased $31 million, or 7%, to $441
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 before extraordinary loss was
28.4% in 2002 compared to 31.3% 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
10 to Financial Statements for an analysis of the effective tax rate.)
Income before extraordinary loss decreased $376 million, or 43%, to $495
million in 2002. This performance reflected a decline of $393 million in the
Energy segment, reflecting the writedown of generation projects of $154 million
after-tax, the accrual of regulatory-related retail clawback of $120 million
after-tax and the severance charges of $21 million after-tax. This decline was
partially offset by growth of $17 million in the Electric Delivery segment.
These performances are discussed below. Net pension and postretirement benefit
costs reduced net income by $38 million in 2002 and $21 million in 2001.
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 related to securitization bonds to be issued in the future in
accordance with the regulatory settlement plan (See discussion in Note 3 to
Financial Statements under "Loss on Settlement") The regulatory asset writedown
reflects the difference between the carrying value of the asset and the cash
flows associated with the securitization bonds expected to be recovered through
higher electricity delivery rates. This difference reflects the decline in
interest rates. The extraordinary loss in 2001 of $154 million (net of income
tax benefit of $115 million) consisted of $97 million (net of $52 million income
tax benefit) of charges related to the early extinguishment of debt under the
debt restructuring and refinancing plan pursuant to the requirements of the 1999
Restructuring Legislation and $57 million (net of $63 million income tax
benefit) of net charges related to the settlement with the Commission to resolve
all major open issues related to the transition to deregulation. (See Notes 3
and 14 to Financial Statements for further information concerning the settlement
of deregulation issues.)
2001 compared to 2000
Reference is made to comparisons of results by business segment presented
below.
US Holdings' operating revenues increased $399 million, or 5%, to $8
billion in 2001. The increase in revenue was primarily driven by higher
recoverable costs in regulated retail electric operations. Electricity sales
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volumes declined 1% due to milder, more normal weather and a slowing economy,
the effects of which were partially offset by 2% growth in the number of
customers.
Gross Margin
Year Ended December 31,
----------------------------------------------
% of % of
2001 Revenue 2000 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 8,020 100% $ 7,621 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 3,051 38% 3,192 42%
Operating costs................................... 1,300 16% 1,224 16%
Depreciation and amortization related to operating
assets........................................ 629 8% 619 8%
------- ----- ------- ------
Gross margin........................................... $ 3,040 38% $ 2,586 34%
======= ===== ======= ======
Gross margin increased $454 million, or 18%, to $3.0 billion in 2001. The
growth was driven by an increase in wholesale portfolio management activity, in
anticipation of the opening of the Texas market to competition, and the higher
revenues in retail electric operations. Mark-to-market accounting for commodity
contracts increased revenues and gross margin by $314 million (as compared to
accounting on a settlement basis). Operating costs rose $76 million, or 6%, to
$1.3 billion reflecting higher generation plant maintenance costs, transmission
costs paid to other utilities and property taxes.
An increase in depreciation and amortization, other than goodwill
(including amounts shown in the gross margin table above) of $14 million, or 2%,
to $635 million was due to investments in computer systems, expansion of office
facilities and normal growth and replacements of operating facilities.
SG&A expense rose $162 million, or 27%, to $766 million in 2001. The
increase was due largely to higher costs to support expanded retail sales and
portfolio management operations, largely in anticipation of the introduction of
competition in the Texas electricity market, as well as higher bad debt expense
driven by the effect on customer electricity billings of higher weather-related
gas costs in late 2000 and early 2001.
Franchise and revenue-related taxes increased $98 million, or 28%, to $442
million in 2001. This increase was driven by higher gross receipts taxes due to
higher revenues on which such taxes are based. As discussed above, higher
weather-related gas costs drove higher electric revenues in late 2000 and early
2001.
Other income decreased $28 million to $12 million in 2001. The 2000 period
included a $28 million gain on sale of land.
Other deductions increased $64 million to $123 million in 2001. The 2001
period includes a $73 million recoverable charge related to regulatory
restructuring of the Texas electricity market, a $22 million non-recoverable
regulatory asset write-off and $18 million in various asset writedowns. The 2000
period includes a $52 million recoverable write-off of regulatory assets.
Interest income increased $32 million to $39 million in 2001. The higher
interest income related primarily to interest on under-recovered fuel costs
under regulation.
Interest expense and other charges decreased $12 million, or 2%, to $472
million in 2001, reflecting a $23 million decrease due to interest rates and a
$12 million decrease due to higher capitalized interest partially offset by a
$23 million increase due to higher debt levels.
The effective tax rate on income before extraordinary loss was 31.3% in
2001 compared to 30.0% in 2000, reflecting higher state income taxes.
Income before extraordinary loss increased $84 million, or 11%, to $871
million in 2001. The increase in earnings reflects an increase of $82 million in
the Energy segment and an increase of $2 million in the Electric Delivery
segment. The analysis of each business segment's performance is presented below.
The extraordinary loss in 2001 of $154 million (net of $115 million income
tax benefit) consisted of $97 million (net of $52 million income tax benefit) of
charges related to the reacquisition of debt under the debt restructuring and
A-10
refinancing plan pursuant to the requirements of the 1999 Restructuring
Legislation and $57 million (net of $63 million income tax benefit) of net
charges related to the settlement with the Commission to resolve all major open
issues related to the transition to deregulation. (See discussion in Note 3 to
Financial Statements under "Loss on Settlement.")
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, 2002 and 2001. The net change in
these assets and liabilities, excluding "other activity" as described below,
represents the net unrealized gains/(losses) recognized under mark-to-market
accounting. Mark-to-market accounting reduced pre-tax earnings by $72 million in
2002 (as compared to accounting on a settlement basis), and increased pre-tax
earnings by $314 million in 2001. There were no material changes in valuation
methodologies in 2002 or 2001.
2002 2001
---- ----
Balance of net commodity contract assets at beginning of year................. $371 $ 27
Settlements of positions included in the opening balance (1) ................. (230) (54)
Unrealized mark-to-market valuations of positions held at end of period (2)... 158 368
Changes in fair value attributable to changes in valuation techniques......... - -
Other activity (3)............................................................ 17 30
---- ----
Balance of net commodity contract assets at end of year ...................... $316 $371
==== ====
--------------------------
(1) Represents unrealized mark-to-market valuations of these positions
recognized in earnings as of the beginning of the year.
(2) Includes unrealized gains recognized upon origination of retail
electric contracts in accordance with SFAS No. 133, as discussed
below, and $14 million in origination gains on nonderivative
wholesale contracts entered into prior to July 1, 2002.
(3) Represents net options paid and a commodity contract transferred
from TXU Gas in the current period. Also includes $71 million of
unsettled liabilities to Enron Corporation reclassified to other
current liabilities in 2002. These activities have no effect on
unrealized mark-to-market valuations.
Origination Gains -- With the implementation of the 1999 Restructuring
Legislation in Texas, retail electric contracts are no longer subject to rate
regulation and are negotiated between the various REPs and the customer. This
has resulted in an especially competitive environment for power contracts with
large C&I customers. The contracts are derivatives as defined in SFAS No. 133
and, therefore, have been marked-to-market upon execution. Origination gains of
$40 million and $88 million were recorded in 2002 and 2001, respectively. The
decline reflected fewer contracts executed in 2002. The average term of a C&I
contract is approximately 18 months.
The C&I contracts are typically standard contracts that provide for the
delivery of power at fixed prices up to the expected load. Within the ERCOT
system, a competitive, liquid wholesale market exists. Given US Holdings'
inherent asset position of base load generation coupled with the ability to
transact competitively in the wholesale market, a "dealer profit" is recognized.
US Holdings is able to validate the forward price curve of the commodity given
the short term nature of the retail contracts and the existence of a wholesale
market in ERCOT. (See discussion in Note 2 to Financial Statements under
"Financial Instruments and Mark-to-Market Accounting.")
Maturity Table -- Of the net commodity contract asset balance above at
December 31, 2002, the amount representing unrealized mark-to-market net gains
that have been recognized in current and prior years' earnings is $336 million.
The remaining $20 million of the December 31, 2002, balance is comprised
principally of amounts representing current and prior years' net payments 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, 2002, scheduled by contractual settlement
dates of the underlying positions.
A-11
Maturity dates of unrealized net mark-to-market balances at December 31, 2002
-----------------------------------------------------------------------------
Maturity Maturity in
less than Maturity of Maturity of 4- Excess of
Source of fair value 1 year 3 years 5 years 5 years Total
---------------------- ---------- ----------- -------------- --------- -----
Prices actively quoted........... $ (4) $- $ - $ - $ (4)
Prices provided by other
external sources............. 125 87 25 6 243
Prices based on models........... 62 25 4 6 97
---- ---- --- --- ----
Total............................ 183 112 29 12 336
Less estimated cumulative effect
of an accounting change -
EITF 98-10 rescission)......... 56 25 9 10 100
---- ---- --- --- -----
Adjusted total................... $127 $87 $20 $ 2 $236
==== ==== === === ====
%- before EITF 98-10 rescission.. 54% 33% 9% 4% 100%
%- after EITF 98-10 rescission.. 54% 37% 8% 1% 100%
As the above table indicates, approximately 91% of the remaining
unrealized mark-to-market valuations at December 31, 2002, as adjusted for the
estimated cumulative effect of an accounting change to be recorded in the first
quarter of 2003 for the rescission of EITF Issue No. 98-10, mature within three
years. This is reflective of the terms of the positions and the methodologies
employed in valuing positions for periods where there is less market liquidity
and visibility. The "prices actively quoted" category reflects only exchange
traded contracts with active quotes available through 2005. The "prices provided
by other external sources" category represents forward commodity positions at
locations for which over-the-counter (OTC) broker quotes are available. OTC
quotes for power and natural gas generally extend through 2005 and 2012,
respectively. This category also includes values of large C&I retail sales
contracts. 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 by US Holdings 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.
Portfolio Management -- The use of commodity contracts to manage risks,
generally referred to as trading activities, is one of several responsibilities
of the "portfolio management" operations of US Holdings. Portfolio management
refers to risk management and value creation activities undertaken to balance
the demand for energy by customers with the supply of energy in an economically
efficient and effective manner. These activities include:
o Managing the utilization of generation assets through "make or buy"
decisions.
o Forecasting volume demands and scheduling supply resources. o Entering
into short- and long-term contracts to balance energy supply and
demand. o Arranging physical sales of energy to wholesale customers.
o Buying and selling energy-related contracts to minimize the cost of
fuel used to generate electricity and to maximize the margin earned on
wholesale and retail sales of energy. These activities are sometimes
broadly characterized as "trading". However, speculative trading,
whereby energy-related financial instruments are bought and sold
outside of the supply/demand balancing process with the objective of
generating profits on anticipated price changes, represents a small
fraction of US Holdings' portfolio management activities.
In this Management's Discussion and Analysis of Financial Condition and
Results of Operations, analyses of revenue and gross margin performance refer to
results of wholesale portfolio management activities. Such results represent net
realized and unrealized gains and losses from transacting in energy-related
contracts as described in the last point above, which are reported as a
component of revenues.
A-12
Energy
- ------
Financial Results
Year Ended December 31,
----------------------------------------
2002 2001* 2000*
---- ---- ----
(Millions of Dollars)
Operating revenues....................................... $7,738 $ 7,458 $ 7,449
------ ------- -------
Costs and expenses:
Cost of energy sold and delivery fees............... 4,803 4,802 5,101
Operating costs..................................... 747 708 673
Depreciation and amortization, other than goodwill.. 438 397 390
Selling, general and administrative expenses........ 842 389 284
Franchise and revenue-based taxes .................. 139 15 16
Other income ....................................... (33) (3) (32)
Other deductions.................................... 254 50 6
Interest income..................................... (29) (71) (52)
Interest expense and other charges ................. 248 237 270
Goodwill amortization............................... -- 14 14
------ ------- -------
Total costs and expenses........................ 7,409 6,538 6,670
------ ------- -------
Income before income taxes and extraordinary loss........ 329 920 779
Income tax expense....................................... 79 277 218
------ ------- -------
Income before extraordinary loss......................... $ 250 $ 643 $ 561
====== ======= =======
- -----------------
The Energy segment includes the electricity generation, wholesale and retail
energy sales, and portfolio management operations of TXU Energy, operating
principally in the competitive Texas market.
* Prior period data is included above for the purpose of providing historical
financial information about the Energy segment after giving effect to the
restructuring transactions and unbundling allocations described in the Notes
to Financial Statements. Allocations reflected in prior period data did not
necessarily result in amounts reported in individual line items that are
comparable to actual results in 2002. Had the Energy segment existed as a
separate segment, its results of operations and financial position could
have differed materially from those reflected above. Additionally, future
results of the Energy segment's operations and financial position could
differ materially from the historical information presented.
A-13
Energy
- ------
Operating Data
Year Ended December 31,
-------------------------------
2002 2001* 2000*
---- ---- ----
Operating statistics:
Retail electric sales volumes (Gigawatt hours-GWh).......... 90,581 99,151 100,493
Wholesale electric sales volumes (GWh)...................... 29,578 6,409 6,154
Retail customers (end of period and in thousands):
Electric (based on number of meters)...................... 2,737 2,728 2,672
Gas....................................................... 2 3 4
------ ------ ------
Total customers........................................ 2,739 2,731 2,676
====== ====== ======
Operating revenues (millions of dollars):
Retail electric:
Residential.............................................. $3,108 $3,255 $3,263
Commercial and industrial ............................... 3,415 3,837 4,025
------ ------- -------
Total................................................. 6,523 7,092 7,288
Wholesale electric ........................................ 845 96 168
Wholesale portfolio management activities.................. 211 258 44
Other revenues............................................. 159 46 254
Mitigation................................................. - (34) (305)
------ ------ ------
Total operating revenues.............................. $7,738 $7,458 $7,449
====== ====== ======
Weather (average for service territory)**
Percent of normal:
Cooling degree days................................... 99.9% 100.5% 119.1%
Heating degree days................................... 101.6% 97.5% 94.6%
- --------------------------
* See footnote on previous page.
** Weather data is obtained from Meteorlogix, a private company that collects
weather data from reporting stations of the National Oceanic and Atmospheric
Administration (a federal agency under the US Department of Commerce).
The financial information for 2001 and 2000 for the Energy segment
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 (T&D) operations. Allocation of revenues reflected consideration of
return on invested capital, which continues to be regulated for the T&D
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 common expenses, assets and liabilities between US
Holdings' generation and T&D operations. Interest and other financing costs were
determined based upon debt allocated. Allocations reflected in the financial
information for 2001 and 2000 did not necessarily result in amounts reported in
individual line items that are comparable to actual results in 2002. 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.
A-14
Effective January 1, 2002, TXU Energy incurs electricity delivery fees
charged by Oncor and other T&D utilities. Rates charged by TXU Energy to its
customers are intended to recover the costs of delivery. Electricity delivery
fees have been included in the Energy segment's revenues and cost of energy for
2001 and 2000. The Energy segment's gross margin for 2001 and 2000 is not
affected by the inclusion of these electricity delivery fees.
2002 compared to 2001
The Energy segment's operating revenues increased $280 million, or 4%, to
$7.7 billion in 2002. Wholesale electric revenues increased $749 million to $845
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 C&I markets. Year-end residential
electric 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 Electric Delivery
segment in 2001, but are included in Energy revenues in 2002.
Gross Margin
Year Ended December 31,
-----------------------------------------------
% of % of
2002 Revenue 2001 Revenue
---- ------- ---- -------
Operating revenues..................................... $ 7,738 100% $ 7,458 100%
Costs and expenses:
Cost of energy sold and delivery fees............. 4,803 62% 4,802 64%
Operating costs.................................. 747 10% 708 10%
Depreciation and amortization related to generation
assets........................................ 396 5% 391 5%
------- ------ ------- -------
Gross margin........................................... $ 1,792 23% $ 1,557 21%
======= ====== ======= =======
Gross margin increased $235 million, or 15%, to $1.8 billion in 2002. The
increase was driven by lower average costs of electricity and delivery fees and
significant growth in wholesale electric sales in the newly deregulated ERCOT
market, partially offset by the effect of lower retail electric volumes. Gross
margin in 2002 was negatively affected by the accrual of $185 million for retail
clawback (see discussion above under "Accounting for Contingencies"), which is
reported in cost of energy sold and delivery fees. Results of wholesale
portfolio management activities were down $47 million from the prior year
primarily due to hedge ineffectiveness. Mark-to-market accounting for wholesale
and retail commodity contracts reduced revenues and gross margin by $72 million
in 2002 (as compared to accounting on a settlement basis), and increased results
in 2001 by $314 million. Operating costs rose $39 million, or 6%, to $747
million primarily due to the costs of refueling two units, compared to one in
2001, at the nuclear-powered generation plant.
The following table analyzes the Energy segment's gross margin between its
realized and unrealized components:
Year Ended December 31,
-----------------------
2002 2001
---- ----
Gross margin................................................ $1,792 $1,557
Noncash items:
Unrealized mark-to-market (gain) loss.................... 72 (314)
Retail clawback accrual.................................. 185 -
Depreciation and amortization related to generation assets 396 391
Cash flow hedge ineffectiveness.......................... 41 (4)
Other noncash items included in cost of energy sold...... (31) 86
Mitigation............................................... - 34
Over-recovered fuel costs................................ - 568
------ ------
Gross margin on a cash basis......................... $2,455 $2,318
====== ======
A-15
An increase in depreciation and amortization, other than goodwill
(including amounts shown in the gross margin table above), of $41 million, or
10%, to $438 million was primarily due to investments in computer systems
required to operate in the newly deregulated market and expansion of office
facilities.
An increase in SG&A expenses of $453 million, or 116%, to $842 million
reflected the effect of retail customer support costs and bad debt expense of
approximately $150 million that were the responsibility of the Electric 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 portfolio management 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 that are expected to continue in 2003.
Such actions resulted in $31 million in severance charges in 2002, which
contributed to the increase in SG&A expense. In addition, new POLR rules
established by the Commission (see discussion in Note 14 to Financial Statements
under "Provider of Last Resort") are expected to result in reduced bad debt
expense. With the anticipated lower staffing and related administrative expenses
and improvement in bad debt experience, SG&A expenses are expected to decline in
2003.
Franchise and revenue-based taxes rose $124 million to $139 million due to
state gross receipts taxes that were the responsibility of the Electric Delivery
segment in 2001. Effective in 2002, state gross receipts taxes related to
electricity revenues are an expense of the Energy segment, while local gross
receipts taxes are an expense of the Electric Delivery segment.
Other income increased by $30 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 $204 million to $254 million, reflecting a
$237 million writedown in 2002 of an investment in two generation plant
construction projects (see discussion above under "Impairment of Long-Lived
Assets"). Amounts in 2001 included a $22 million regulatory asset write-off
pursuant to a regulatory order and $18 million in various asset writedowns.
Interest income declined by $42 million, or 59%, to $29 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 increased $11 million, or 5%, to $248
million. Of the change, $106 million was due to higher rates and an $8 million
decrease in capitalized interest, partially offset by $103 million due to lower
average debt levels.
The effective tax rate decreased to 24.0% in 2002 from 30.1% 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. (See Note 10 to Financial Statements for an analysis of the
effective tax rate.)
Income before extraordinary loss decreased $393 million, or 61%, to $250
million in 2002. The decline was driven by an increase in SG&A expenses, the
impairment charge reported in other deductions and higher franchise and
revenue-based taxes, partially offset by the improved gross margin (net of the
effect of the retail clawback accrual). Net pension and postretirement benefit
costs reduced net income by $21 million in 2002 and $13 million in 2001.
2001 compared to 2000
The Energy segment's operating revenues of $7.5 billion for 2001 were
essentially even with the prior year. This performance reflected lower retail
electricity revenues of approximately $200 million, or 3%, largely offset by
increased wholesale portfolio management activities, due in large part to the
anticipated opening of the Texas market to competition, as well as increased
wholesale activity in markets outside of Texas. Lower retail electricity
revenues reflected both volume declines and lower fuel revenues, due to lower
fuel (primarily natural gas) costs in generation operations, partially offset by
a lower adjustment for earnings in excess of the regulatory earnings cap
(mitigation). Retail electricity volumes declined 1% due to milder, more normal
weather, partially offset by the effect of 2% growth in number of customers.
A-16
Gross Margin
Year Ended December 31,
-----------------------------------------------
% of % of
2001 Revenue 2000 Revenue
---- ------- ---- -------
Operating revenues....................................... $ 7,458 100% $ 7,449 100%
Costs and expenses:
Cost of energy sold and delivery fees.............. 4,802 64% 5,101 69%
Operating costs.................................... 708 10% 673 9%
Depreciation and amortization related to generation
assets.......................................... 391 5% 390 5%
------- ----- ------- -----
Gross margin............................................. $ 1,557 21% $ 1,285 17%
======= ===== ======= =====
Gross margin increased $272 million, or 21%, to $1.6 billion in 2001. The
improved results reflected growth in wholesale portfolio management activities,
arising primarily in anticipation of the opening of the Texas market to
competition, partially offset by an increase in operating costs. Mark-to-market
accounting for commodity contracts increased revenues and gross margin by $314
million in 2001 (as compared to accounting on a settlement basis). This amount
reflects $88 million in origination gains recorded upon execution of retail
contracts with large C&I customers. Such contracts are derivatives and are
marked-to-market in accordance with SFAS No. 133. Operating costs increased $35
million, or 5%, to $708 million in 2001 primarily reflecting higher generation
plant maintenance costs.
The increase in depreciation and amortization, other than goodwill
(including amounts shown in the gross margin table above) of $7 million, or 2%,
to $397 million was primarily due to investments in computer systems and
expansion of office facilities.
The increase in SG&A expense of $105 million, or 37%, to $389 million
reflected higher spending for staffing and computer systems to support expanded
retail sales and portfolio management operations, largely in anticipation of
deregulation of the Texas electricity market, as well as increased bad debt
expense. The increase in bad debts was primarily due to the rise in fuel costs
in late 2000 and early 2001 and the related impact on electricity customer
billings.
Other income decreased by $29 million to $3 million, reflecting a $28
million gain on the sale of land in 2000.
Other deductions increased $44 million to $50 million, reflecting a $22
million write-off of regulatory assets pursuant to a regulatory order and $18
million in various asset writedowns, both in 2001.
Interest income increased $19 million, or 37%, to $71 million primarily
due to interest income on under-recovered fuel costs under regulation.
Interest expense and other charges declined $33 million, or 12%, to $237
million due primarily to lower interest rates and a $9 million increase in
capitalized interest.
The effective tax rate increased to 30.1% in 2001 from 28.0% in 2000,
primarily due to higher state income taxes.
Income before extraordinary loss increased $82 million, or 15%, to $643
million in 2002. The increase was driven by the higher gross margin, partially
offset by higher SG&A expenses.
A-17
Electric Delivery
- -----------------
Financial Results
Year Ended December 31,
----------------------------------------
2002 2001* 2000*
---- ---- ----
Operating revenues....................................... $1,994 $ 2,314 $ 2,081
------ ------- -------
Costs and expenses:
Operating costs...................................... 676 594 551
Depreciation and amortization, other than goodwill... 264 238 231
Selling, general and administrative expenses......... 213 376 320
Franchise and revenue-based taxes ................... 272 427 328
Other income ........................................ (9) (9) (8)
Other deductions..................................... -- 73 53
Interest income ..................................... (49) -- (1)
Interest expense and other charges .................. 265 267 260
Goodwill amortization................................ -- 1 1
------ ------- -------
Total costs and expenses......................... 1,632 1,967 1,735
------ ------- -------
Income before income taxes and extraordinary loss........ 362 347 346
Income tax expense....................................... 117 119 120
------ ------- -------
Income before extraordinary loss......................... $ 245 $ 228 $ 226
====== ======= =======
- ------------------------
The Electric Delivery segment includes the electricity T&D business of Oncor
which is subject to regulation by Texas authorities.
* Prior period data is included above for the purpose of providing historical
financial information about the Electric Delivery segment after giving
effect to the restructuring transactions and allocations described in the
Notes to Financial Statements. Allocations reflected in prior period data
did not necessarily result in amounts reported in individual line items that
are comparable to actual results in 2002. Had the Electric Delivery segment
existed as a separate segment, its results of operations and financial
position could have differed materially from those reflected above.
Additionally, future results of the Electric Delivery segment's operations
and financial position could differ materially from the historical
information presented.
A-18
Electric Delivery
- -----------------
Operating Data
Year Ended December 31,
----------------------------
2002 2001* 2000*
---- ---- ----
Operating statistics:
Delivered electricity volumes (GWh)................................. 104,785 99,139 100,545
Electric points of delivery (end of period and in thousands)........ 2,909 2,844 2,796
Operating revenues (millions of dollars):
Electricity delivery:
Energy......................................................... $1,586 $2,314 $2,081
Non-affiliated REPs............................................ 408 - -
------ ------ ------
Total operating revenues............................... $1,994 $2,314 $2,081
====== ====== ======
- --------------------------
* See footnote on previous page.
The financial information for 2001 and 2000 for the electric delivery
operations included in the Electric Delivery segment 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 T&D operations. Allocation of revenues
reflected consideration of return on invested capital, which continues to be
regulated for the T&D 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 T&D operations.
Interest and other financing costs were determined based upon debt allocated.
Allocations reflected in the financial information for 2001 and 2000 did not
necessarily result in amounts reported in individual line items that are
comparable to actual results in 2002. 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.
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 Electric Delivery segment, but in
2002 such revenues and expenses are the responsibility of the Energy segment.
Excluding the impact of such revenues in 2001, electric delivery revenues rose
3% on a 6% increase in electricity volumes delivered. Because the fees to REPs
for their large C&I customers are fixed for specified ranges of volumes, changes
in distribution volumes do not necessarily result in comparable changes in
reported revenues.
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%
======= ===== ======= ======
Gross margin decreased $418 million, or 28% to $1.1 billion in 2002. The
decrease reflects the impact of revenues allocated to the Electric Delivery
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.
A-19
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 now reflected in the Energy
segment. 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
Energy segment in 2002. Effective in 2002, local gross receipts taxes related to
electricity revenue are an expense of the Electric Delivery segment while state
gross receipts taxes are an expense of the 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 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 of interest expense related to the regulatory
liability for the excess mitigation credit to REPs 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 reflecting 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 $17
million in 2002 and $8 million in 2001.
2001 compared to 2000
Operating revenues rose $233 million, or 11%, to $2.3 billion in 2001.
This increase is primarily due to the impact on reported revenues of regulation,
reflecting higher recoverable costs. Electricity volumes delivered in 2001
declined 1% due to milder, more normal weather and a slowing economy, the
effects of which were partially offset by 2% growth in number of customers.
Gross Margin
Year Ended December 31,
-----------------------------------------------
% of % of
2001 Revenue 2000 Revenue
---- ------- ---- -------
Revenues............................................... $ 2,314 100% $ 2,081 100%
Costs and expenses:
Operating expenses.................................. 594 26% 551 27%
Depreciation and amortization (related to transmission
and distribution assets).......................... 238 10% 231 11%
------- ----- ------- ------
Gross margin........................................... $ 1,482 64% $ 1,299 62%
======= ===== ======= ======
Gross margin increased by $183 million, or 14%, to $1.5 billion in 2001.
This increase is primarily due to the higher revenues partially offset by higher
operating expenses and depreciation and amortization. Operating expenses
increased $43 million, or 8%, to $594 million primarily due to higher
transmission costs paid to other utilities and property taxes.
A-20
Depreciation and amortization, other than goodwill (including amounts
shown in the gross margin table above), increased $7 million, or 3%, to $238
million primarily due to normal growth and replacements of delivery facilities.
SG&A expenses increased $56 million, or 18%, to $376 million.
The increase reflected higher bad debt expense, driven by higher fuel charges
to customers in late 2000 and early 2001 and computer systems costs incurred
in 2001 to prepare for the restructuring of the Texas electricity market.
Franchise and revenue-based taxes increased $99 million, or 30%, to $427
million in 2001. The increase reflected higher state and local gross receipts
taxes as a result of the rise in revenues, driven by higher fuel costs, in late
2000 and early 2001.
Other deductions increased by $20 million to $73 million in 2001. The 2001
period included a regulatory-related recoverable charge of $73 million related
to the opening of the Texas market to competition The 2000 period included a
similar recoverable charge of $52 million.
Interest expense and other charges increased $7 million, or 3% to $267
million in 2001 due to higher average debt balances, including advances from
affiliates.
The effective tax rate was 34.3% in 2001 compared to 34.7% in 2000.
Income before extraordinary loss rose $2 million, or 1%, to $228 million
in 2001. The increase was driven by higher gross margin partially offset by
higher franchise and revenue-based taxes and SG&A expenses.
COMPREHENSIVE INCOME
Minimum pension liability adjustments for 2002, 2001 and 2000 were losses
of $57 million ($37 million after-tax), $1 million and none, respectively. The
minimum pension liability represents the difference between the excess of the
accumulated benefit obligation over the pension plans' assets and the liability
reflected in the balance sheet. Further, based on the current assumptions and
available information, funding requirements in 2003 related to the pension plans
are expected to increase by $3 million and pension expense is expected to
increase approximately $29 million over the 2002 amounts. The recording of the
liability did not affect US Holdings financial covenants in any of its credit
agreements.
US Holdings adopted SFAS No. 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. US Holdings has
historically used, and will continue to use, derivative financial instruments
that are highly effective in offsetting future cash flow volatility related to
interest rates and energy commodity prices. The amounts included in other
comprehensive income are expected to offset the impact of future rate or price
changes on related payments. Amounts in other comprehensive income include (i)
the value of the cash flow hedges, 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 forecasted. The effects of the hedge will be recorded in the statement of
income as the hedged transactions are actually settled.
During 2002 and 2001, changes in the fair value of derivatives effective
as cash flow hedges reflected losses of $235 million ($153 million after-tax)
and gains of $25 million ($16 million after-tax), respectively. Losses in 2002
were due to decreases of $135 million ($88 million after-tax) in the fair value
of interest rate hedges because of lower interest rates, and decreases of $100
million ($65 million after-tax) in the fair value of commodity hedges. Gains in
2001 were related to increases in the fair value of commodity hedges.
A-21
During 2002, other comprehensive income hedge gains recognized in income
were $20 million ($13 million after-tax), with $1 million in losses recognized
in 2001, primarily related to commodity hedges.
See also Note 13 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.
Cash Flows -- Cash flows provided by operating activities for the year
ended December 31, 2002 were $1.3 billion compared to $1.8 billion and $1.3
billion for the years ended December 31, 2001 and 2000, respectively. The
decrease in cash flows provided by operating activities in 2002 of $517 million,
or 29%, reflected the effect of a return in 2001 of $227 million in margin
deposits related to portfolio 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 working capital
(accounts receivable, accounts payable and inventories) increase of $395 million
in 2002 was comparable to 2001. However, this performance reflected higher
unbilled retail accounts receivable of approximately $200 million and higher
wholesale accounts receivable, both related to the opening of the Texas
electricity market to competition. Higher accounts receivable balances reflected
the effects of a new ERCOT protocol that allows five days to clear meter-read
data through ERCOT, as well as other changes in billing processes. The higher
accounts receivable was offset by favorable changes in accounts payable,
reflecting more purchases of power (as opposed to power generated by TXU Energy)
and the payments in 2001 for high gas purchase prices experienced in late 2000.
The increase in cash flows in 2001 from 2000 of $497 million reflected
higher cash earnings, including the effect of under-recovered fuel costs,
reflecting high gas prices in 2000 that reduced cash flows in 2000 as the gas
costs were incurred, but increased cash flows in 2001 as the costs were
recovered from customers. The cash flow comparison was favorably affected by the
year-over-year effect of margin deposit payments in 2000 and the return of those
deposits in 2001. However, this effect was largely offset by unfavorable net
working capital changes, reflecting the timing of payments and recoveries
associated with the temporary increase in gas costs in late 2000.
Cash flows provided by financing activities in 2002 were $774 million.
Debt-related activities in 2002 provided cash of $1.7 billion, reflecting
issuances of long-term debt and borrowings under credit facilities, partially
offset by retirements and repayments of long-term debt, net payments of advances
from affiliates and debt-related discounts and costs. Cash distributions to TXU
Corp. totaled $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 $787 million in 2001 and $374 million in 2000, which included
repurchases of common stock from TXU Corp. of $859 million and $802 million in
2001 and 2000, respectively, and the redemption of $837 million in preferred
stock in 2001.
Cash flows used in investing activities totaled $599 million, $994 million
and $893 million during 2002, 2001 and 2000, respectively. Proceeds in 2002 from
the sale of the Handley and Mountain Creek power plants in the Dallas-Fort Worth
area were $443 million. Acquisitions in 2002 included $36 million for a
cogeneration and wholesale production business in New Jersey. Capital
expenditures declined to $787 million in 2002 from $965 million in 2001. Nuclear
fuel spending of $51 million reflected refuelings at the Comanche Peak nuclear
generation plant. 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 for 2002 exceeds the amount reported in the statement of income by
$84 million. This difference reflected $60 million of amortization of nuclear
fuel, which is reported as cost of energy sold in the statement of income
consistent with industry practice, and $24 million of amortization of regulatory
assets, which is reported as operating costs in the statement of income.
A-22
Investing Activities - Acquisitions and Dispositions
Acquisitions -- In May 2002, TXU Energy acquired a 260 megawatt
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.
US Holdings acquired the Pedricktown, New Jersey, power business in April
2002 and accounted for the acquisition as a purchase business combination. The
results of operations of the acquired company is reflected in the consolidated
financial statements from its acquisition date.
In April 2002, TXU Energy completed the sale of its Handley and Mountain
Creek generating plants in the Dallas-Fort Worth area with total plant capacity
of 2,334 megawatts 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.
US Holdings may pursue potential investment opportunities from time to
time when 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 are estimated at
approximately $870 million for 2003, substantially all of which are for
maintenance and organic growth of existing operations, and are expected to be
funded by cash flows from operations. Approximately 62% is planned for the
Electric Delivery segment, and 38% for the Energy segment.
Financing Activities
Capitalization -- US Holdings capitalization consists of common and
preferred stock and long-term debt securities, including exchangeable debt. The
capitalization ratios of US Holdings at December 31, 2002, consisted of 1%
preferred stock, 6% exchangeable subordinated notes, 44% other long-term debt,
less amounts due currently and 49% common stock equity. Not reflected in these
ratios is restricted cash of $210 million included in other investments that is
held in trust for the defeasance of long-term debt.
Exchangeable Subordinated Debt -- In November 2002, TXU Energy issued $750
million of exchangeable subordinated notes in a private placement. The notes
will mature in November 2012, bear interest at the annual rate of 9% and permit
the deferral of interest payments. TXU Corp. has granted the holders the right
to exchange the notes for TXU Corp. common stock. The notes currently may be
exchanged, subject to certain restrictions, at any time for up to approximately
57 million shares of TXU Corp. common stock at an exercise 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 principal
amount of notes to be exchanged by the exercise price. The exercise price and
the number of shares to be issued are subject to anti-dilution adjustments. The
proceeds from the issuance of the notes were used for the repayment of two
standby credit facilities that expired in November 2002. TXU Energy has
recognized a capital contribution from TXU Corp. and a corresponding discount on
the notes of $266 million, for the value of the exchange right as TXU Corp.
granted an irrevocable right to exchange the notes for shares of TXU Corp.
common stock. This discount amount is being amortized to interest expense over
the term of the debt. At the time of any exchange of the notes for common stock,
the unamortized discount will be proportionately written off as a charge to
earnings. (See Note 6 to Financial Statements.)
The exchangeable notes are subordinated in bankruptcy to all other TXU
Energy obligations. TXU Energy has the right until May 2003 to require the
holders of the notes to exchange their interest in the notes for a preferred
A-23
equity interest in TXU Energy with economic and other terms substantially
identical to the notes. The original purchasers of the notes have the right to
nominate one member to the board of directors of TXU Corp., and such member has
been appointed to fill a vacancy. This right exists so long as the original
purchasers hold at least 30% of their original investment in the form of common
stock and/or notes, but no later than November 2012 or, if later, the date no
notes remain outstanding. The holders of the notes are restricted from actions
that would increase their control of TXU Corp. TXU Energy and the holders
characterize the notes as preferred equity interests for federal and state
income tax purposes with the result that TXU Energy is treated as a partnership.
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 (SEC) for offering pursuant to Rule 415 under
the Securities Act of 1933.
Long-Term Debt -- During the year ended December 31, 2002, 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.......................... $ - $1,012
Senior secured notes.......................... 2,050 -
Medium term notes............................. - 73
Fixed rate debentures......................... 1,000 -
TXU Energy:
Exchangeable subordinated notes............... 750 -
Pollution control revenue bonds............... 61 61
Floating rate debentures...................... - 1,500
Other long-term debt.......................... - 122
US Holdings................................... - 4
------ ------
Total........................................ $3,861 $2,772
====== ======
In early 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 of $250 million is due March 15, 2008, and bears
interest at the annual rate of 6.125%, and the other series of $1 billion is due
March 15, 2013, and bears interest at the annual rate of 7%. Net proceeds from
the issuance will be used for general corporate purposes, including the
repayment of advances from affiliates.
See Notes 5, 6, 7 and 9 to Financial Statements for further detail of
debt issuance and retirements, financing arrangements, trust securities and
capitalization.
At December 31, 2002, US Holdings had credit facilities (some of which
provide for long-term borrowings) as follows:
At December 31, 2002
--------------------------------------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
- -------- --------------- --------- ----- ------ ---------- ------------
364-Day Revolving Credit Facility April 2003 US Holdings, TXU
Energy, Oncor $ 1,000 $ 122 $ 878 $ --
364-Day Senior Secured Credit December 2003 Oncor
Facility 150 -- -- 150
Five -Year Revolving Credit Facility February 2005 US Holdings 1,400 474 926 --
------- ------ ------ ------
Total $ 2,550 $ 596 $1,804 $ 150
======= ====== ====== ======
In October 2002, US Holdings, Oncor and TXU Energy borrowed approximately
$2.6 billion in cash against their available credit facilities, the total of
which represented the remaining availability after $549 million was used to
support outstanding letters of credit at that time. Of the borrowings, $800
million was repaid in November 2002 upon expiration of certain facilities. These
funds and other available cash were used, in part, to repay outstanding
commercial paper upon maturity. As of December 31, 2002, the remaining
facilities were fully drawn and were reflected in notes payable-banks on the
balance sheet. Excess cash of approximately $1.5 billion at December 31, 2002,
was invested in liquid short-term marketable securities earning current market
rates. In late March 2003, cash borrowings under the credit facilities totaling
$1.24 billion were repaid.
A-24
In October 2002, Oncor entered into a commitment for a secured credit
facility of up to $1 billion. The facility was intended to fund interim
refinancings of approximately $700 million of maturing secured debt should
market conditions not support a timely, cost effective refinancing. The balance
was to be available for general corporate purposes at Oncor. In December 2002,
Oncor issued $850 million of senior secured notes, reducing the commitment to
$150 million. Oncor subsequently converted the commitment to a $150 million
364-day senior secured credit facility, expiring in December 2003, all of which
was available at December 31, 2002.
In April 2002, US Holdings, TXU Energy and Oncor entered into the joint
$1.0 billion 364-day revolving credit facility with a group of banks that
terminates in April 2003; borrowings outstanding at any time can be extended for
one year. This facility is used for working capital and general corporate
purposes. Up to $1.0 billion of letters of credit may be issued under the
facility.
With respect to the 364-day revolving credit facility in the above table,
US Holdings is pursuing various alternatives for renewing this facility. US
Holdings has the option under the agreement of converting the outstanding
borrowings at expiration to a 364-day term loan.
In the second quarter of 2002, each of TXU Energy and Oncor began issuing
commercial paper to fund its short-term liquidity requirements. The commercial
paper programs allowed each of TXU Energy and Oncor to issue up to $2.4 billion
and $1.0 billion of commercial paper, respectively. The credit facilities
provided back-up for the commercial paper issuances. The TXU Corp. commercial
paper program was discontinued in July 2002, and at that time, TXU Corp. was
removed as a borrower under the $1.4 billion five-year revolving credit
facility. As of December 31, 2002, there was no outstanding commercial paper
under these programs. In October 2002, US commercial paper markets became
inaccessible to TXU Energy and Oncor. Commercial paper borrowings are expected
to resume as market concerns regarding the liquidity of US Holdings and its
subsidiaries are mitigated.
Sale of Receivables -- Certain subsidiaries of TXU Corp. sell trade
accounts receivable to TXU Receivables Company, a wholly-owned bankruptcy remote
subsidiary of TXU Corp., which sells undivided interests in accounts receivable
it purchases to financial institutions. As of December 31, 2002, TXU Energy
(through certain subsidiaries), Oncor and TXU Gas are qualified originators of
accounts receivable under the program. TXU Receivables Company may sell up to an
aggregate of $600 million in undivided interests in the receivables purchased
from the originators under the program. As of December 31, 2002, $1.14 billion
face amount of US Holdings' receivables were sold to TXU Receivables Company
under the program in exchange for cash of $368 million and $744 million in
subordinated notes, with $29 million of losses on sales for the year ended
December 31, 2002, that principally represent the interest costs on the
underlying financing. These losses approximated 5% of the cash proceeds from the
sale of undivided interests in accounts receivable on an annualized basis.
Funding under the program decreased from $579 million at September 30, 2002, to
$368 million at December 31, 2002, primarily due to billing and collection
delays arising from new systems and processes in TXU Energy and ERCOT for
clearing customer switching and billing data, as well as seasonality of the
business.
Upon termination, cash flows to the originators would be delayed as
collections of sold receivables would be used by TXU Receivables Company to
repurchase the undivided interests of the financial institutions instead of
purchasing new receivables. The level of cash flows would normalize in
approximately 16 to 31 days. TXU Business Services Company, a subsidiary of TXU
Corp., services the purchased receivables and is paid a market based servicing
fee by TXU Receivables Company. The subordinated notes receivable from TXU
Receivables Company represent TXU Corp.'s subsidiaries' retained interests in
the transferred receivables and are recorded at book value, net of allowances
for bad debts, which approximates fair value due to the short-term nature of the
subordinated notes, and are included in accounts receivable in the consolidated
balance sheet.
In October 2002, the program was amended to extend the program to July
2003, to provide for reserve requirement adjustments as the quality of the
portfolio changes and to provide for adjustments to reduce receivables in the
program by the related amounts of customer deposits held by originators. In
February 2003, the program was further amended to allow receivables that are
31-90 days past due into the program.
A-25
Contingencies Related to Receivables Program -- Although TXU Receivables
Company expects to be able to pay its subordinated notes from the collections of
purchased receivables, these notes are subordinated to the undivided interests
of the financial institutions in those receivables, and collections might not be
sufficient to pay the subordinated notes. The program may be terminated if
either of the following events occurs:
o the credit rating for the long-term senior debt securities of all
originators and the parent guarantor, if any, declines below BBB- by
S&P or Baa3 by Moody's; or
o 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.
The delinquency and dilution ratios exceeded the relevant thresholds at
various times during 2002 and in January 2003, but waivers were granted. These
ratios were affected by issues related to the transition to deregulation.
Certain billing and collection delays arose due to implementation of new systems
and processes within TXU Energy and ERCOT for clearing customer switching and
billing data. The resolution of these issues as well as the implementation of
new POLR rules by the Commission are expected to bring the ratios in consistent
compliance with the program. (See discussion in Note 15 to Financial Statements
under "Provider of Last Resort.")
Credit Ratings of TXU Corp. and its US Subsidiaries-- The current credit
ratings for TXU Corp., US Holdings, Oncor and TXU Energy are presented below:
TXU Corp. US Holdings Oncor TXU Energy
-------- ------------ ------- ----------
(Senior Unsecured) (Senior Unsecured) (Secured) (Senior Unsecured)
Standard & Poor's (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 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.
Financial Covenants, Credit Rating Provisions and Cross-Default Provisions
- -- The terms of certain financing arrangements of US Holdings and its
consolidated 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 subordinated notes also limit its
incurrence of additional indebtedness unless a leverage ratio and interest
coverage test are met on a pro forma basis. As of December 31, 2002, US Holdings
and its subsidiaries were in compliance with all such applicable covenants.
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
provisions are described below:
A-26
Credit Rating Provisions
------------------------
TXU Energy has provided a guarantee of the obligations under TXU Corp.'s
lease (approximately $140 million at December 31, 2002) 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 $150 million.
In addition, TXU Energy has a number of other contractual arrangements
where the counterparties would have the right to request TXU Energy to post
collateral if its credit rating was downgraded below investment grade by any
specified rating agency. The amount TXU Energy would post under these
transactions depends in part on the value of the contracts at that time. Based
on current market conditions, the maximum TXU Energy would post for these
transactions is $246 million. Of this amount, $190 million relates to an
arrangement that would require TXU Energy to be downgraded to below investment
grade by all three rating agencies before collateral would be required to be
posted.
TXU Energy is also the obligor on leases aggregating $167 million. Under
the terms of those leases, if TXU Energy's credit rating was downgraded to below
investment grade by any specified rating agency, TXU Energy could be required to
sell the assets, assign the leases to a new obligor that is investment grade,
post a letter of credit or defease the leases.
ERCOT also has rules in place to assure adequate credit worthiness for
parties that schedule power on the ERCOT System. Under those rules, if TXU
Energy's credit rating was downgraded to below investment grade by any specified
rating agency, TXU Energy could be required to post collateral of approximately
$31 million.
Under the receivables sale program, all originators are required to
maintain a `BBB-' (S&P) and a `Baa3' (Moody's) rating or better (or supply a
parent guarantee with a similar rating). A downgrade below the required ratings
for an originator would prevent that originator from selling its accounts
receivables under the program. If all originators are downgraded so that there
are no eligible originators, the facility would terminate.
Other agreements of US Holdings and its subsidiaries, including some of
the credit facilities discussed above, contain terms pursuant to which the
interest rates charged under the agreements may be adjusted depending on the
credit ratings of US Holdings or its subsidiaries.
Cross-Default Provisions
------------------------
Certain financing arrangements of US Holdings and its subsidiaries contain
provisions that would result in an event of default if there is a failure under
other financing arrangements to meet payment terms or to observe other covenants
that would result in an acceleration of payments due. Such provisions are
referred to as "cross-default" provisions. Most agreements have a cure period of
up to 30 days from the occurrence of the specified event during which the
company is allowed to rectify or correct the situation before it becomes an
event of default.
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
$1.0 billion joint US Holdings/TXU Energy/Oncor 364-day revolving credit
facility, the $1.4 billion US Holdings 5-year revolving credit facility, two
letter of credit back-up facilities ($68.1 million and $54.2 million currently
outstanding) and the $103 million TXU Mining Company LP senior notes (which have
a $1 million threshold). Under the joint US Holdings/TXU Energy/Oncor $1.0
billion 364-day revolving 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 and US Holdings, but not as to
Oncor. Also, under this credit facility, a default by Oncor or any subsidiary
thereof would cause the maturity of outstanding balances to be accelerated under
such facility as to Oncor and US Holdings, but not as to TXU Energy. Further,
under this credit facility, a default by US Holdings would cause the maturity of
outstanding balances under such facility to be accelerated as to US Holdings,
but not as to Oncor or TXU Energy. Under the Oncor $150 million credit facility,
a default by Oncor or any subsidiary thereof would cause the maturity of
outstanding balances under such facility to be accelerated.
A-27
The accounts receivable program described above contains a cross-default
provision with a threshold of $50 million applicable to each of the originators
under the program. TXU Receivables Company and TXU Business Services Company
each have a cross-default threshold of $50 thousand. If either an originator,
TXU Business Services Company or TXU Receivables Company defaults on
indebtedness of the applicable threshold, the facility could terminate.
TXU Energy has entered into certain mining and equipment leasing
arrangements aggregating $226 million that would terminate upon the default on
any other obligations of TXU Energy owed to the lessor. In the event of a
default by TXU Mining Company LP, a subsidiary of TXU Energy, on indebtedness in
excess of $1 million, a cross default would result under the $31 million TXU
Mining Company LP leveraged lease and the lease would 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 agreements and leases with cross-default provisions, the triggering of
which would not result in a significant effect on liquidity.
Regulatory Asset Securitization -- The regulatory settlement plan
approved by the Commission provides Oncor with a financing order authorizing it
to issue securitization bonds in the aggregate principal amount of $1.3 billion
to monetize and recover generation-related regulatory assets. The settlement
plan provides that there will be an initial issuance of securitization bonds in
2003 in the amount of up to $500 million followed by a second issuance for the
remainder after 2003. (See discussion in Note 14 to Financial Statements under
"Regulatory Asset Securitization.")
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 6, 7 and 15 to Financial Statements for additional
disclosures regarding terms of these obligations).
Payment Due
-------------------------------------------------------------------
Contractual Cash Obligations 2003 2004 2005 2006 2007 Thereafter
- ----------------------------- ---- ---- ---- ---- ---- ----------
Long-term debt.................... $396 $225 $127 $ 6 $216 $6,327
Mandatorily redeemable preferred
securities and preferred
stock of subsidiaries........... 10 10 1 - - -
Capital lease obligations ........ 1 1 2 2 2 6
Operating leases ................. 69 70 75 70 73 535
Capacitypayments-electricity
contracts ...................... 315 163 146 117 17 -
Coal contracts ................... 94 79 23 18 - -
Pipeline transportation and storage
reservation fees................ 14 6 6 6 4 6
---- ---- ---- ---- ---- ------
Total contractual cash obligations $899 $554 $380 $219 $312 $6,874
==== ==== ==== ==== ==== ======
- --------------------------
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 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, 2002, the balance of the indebtedness
was $140 million with maturities of principal and interest extending to December
2021. The indebtedness is secured by a lien on the purchased facilities.
A-28
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, 2002, the aggregate maximum amount of
residual values guaranteed was approximately $275 million with an estimated
residual recovery of approximately $211 million. The average life of the lease
portfolio is approximately nine years.
Shared Saving Guarantees -- US Holdings has guaranteed that certain
customers will realize specified annual savings resulting from energy management
services it has provided. In the aggregate, the average annual savings has
exceeded the annual savings guaranteed. The maximum potential annual payout is
approximately $4 million and the maximum total potential payout is approximately
$19 million. The average remaining life of the portfolio is approximately five
years.
Standby Letters of Credit -- US Holdings has entered into various
agreements that require letters of credit for financial assurance purposes.
Approximately $523 million of letters of credit are outstanding to support
existing floating rate pollution control revenue bond financings on existing
debt of approximately $433 million. The letters of credit are available to fund
the payment of such debt obligations. These letters of credit have expiration
dates in 2003; however, US Holdings intends to provide from either existing or
new facilities for the extension, renewal or substitution of these letters of
credit to the extent required for such floating rate debt or their remarketing
as fixed rate debt.
US Holdings has provided for the posting of letters of credit in the
amount of $183 million to support portfolio management margin requirements in
the normal course of business. As of December 31, 2002, approximately 82% of
the obligations supported by these letters of credit mature within one year,
and substantially all of the remainder mature in the second year.
US Holdings has entered into contracts with public agencies to purchase
cooling water for use in the generation of electric energy and has agreed, in
effect, to guarantee the principal, $16 million at December 31, 2002, 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 5-1/2% 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, of $4 million annually
for 2003, $7 million for 2004 and $1 million for 2005 and 2006. Annual payments
made by US Holdings, net of amounts assumed by a third party under such
contracts, were $4 million for each of the last three years. 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 of US Holdings in connection with $19 million remaining
principal amount of bonds at December 31, 2002, issued for similar purposes,
which had previously been guaranteed by US Holdings. US Holdings is, however,
contingently liable in the unlikely event of default by the municipality.
Off Balance Sheet Arrangements
See discussion above under "Sale of Receivables".
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 factors 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 variables,
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, including cash flow hedges to manage interest rate
risks related to its indebtedness, as well as exchange traded, OTC contracts and
other contractual commitments to manage commodity price risk in its portfolio
management activities.
A-29
Risk Oversight
US Holdings' portfolio management operations manage the market, credit and
operational risk of the unregulated energy business within limitations
established by senior management and in accordance with TXU Corp.'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.
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. Through its portfolio management operations, US Holdings actively
manages its portfolio of owned generation, fuel supply and retail load to
mitigate the impacts of these risks on its results of operations.
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.
VaR Methodology -- A VaR methodology is used to measure the amount of
current and prospective risk that exists within a portfolio under a variety of
market conditions. The VaR process 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 maximum potential loss in value, due to price risk, 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.
2002 2001(a)
---- -------
Year-end VaR.................................. $23.2 $38.7
Average VaR................................... $38.0 $ -
(a) Comparable information on an average VaR basis is not available for the
full year of 2001 because during part of 2001, VaR was calculated
using different assumptions than in 2002 and an average VaR for 2001
would therefore not be comparable.
A-30
Portfolio VaR -- Represents the estimated maximum potential loss in value,
due to price risk, of the entire energy portfolio, including owned assets and
all contractual positions (the portfolio assets). Assumptions in determining
this VaR include using a 95% confidence level and a five-day holding period and
includes both mark-to-market and accrual positions expiring over the next ten
years.
2002 2001(a)
---- ------
Year-end Portfolio VaR...................... $143.5 $ -
(a) Prior to deregulation in Texas, which became effective January 1, 2002,
the portfolio assets included in the Portfolio VaR were regulated
assets and not subject to market risk. As a result, there is no
Portfolio VaR at year-end 2001 and no average Portfolio VaR for either
2001 or 2002.
Other Risk Measures -- The metrics appearing below provide information
regarding the effect of energy price risk on earnings and cash flow.
Earnings at Risk (EaR) -- EaR measures the estimated maximum shortfall in
fiscal year projected margin (revenues less cost of energy sold), due to price
risk. EaR metrics include the portfolio assets except for accrual positions
expected to be settled beyond the fiscal year. Assumptions include using a 95%
confidence level over a five-day holding period under normal market conditions.
As of December 31, 2002, the EaR for TXU Energy was $27.7 million. As this
measure is stated on the last business day of 2002, it represents the EaR
measure for fiscal year 2003.
Cash Flow at Risk (CFaR) -- CFaR measures the estimated maximum shortfall
of projected cash flow over the next six months, due to price risk. CFaR metrics
include all portfolio positions that impact cash flow during the next six
months. Assumptions include using a 99% confidence level over a 125 business-day
holding period under normal market conditions. As of December 31, 2002, the
CFaR, based on a contract settlement period of six months, was $177.5 million.
Interest Rate Risk
The table below provides information concerning US Holdings' financial
instruments as of December 31, 2002 and 2001, that are sensitive to changes in
interest rates, which include debt obligations, interest rate swaps and trust
securities. 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. For trust securities, the
table presents cash flows based on December 31, 2002, book value and the related
weighted average rate by expected redemption date. The weighted average rate is
based on the rate in effect at the reporting date. 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 6 to Financial Statements for a
discussion of changes in debt obligations.
Expected Maturity Date
----------------------------------------------
2002 2001
There- 2002 Fair 2001 Fair
2003 2004 2005 2006 2007 After Total Value Total Value
---- ---- ---- ---- ---- ----- ----- ----- ----- -----
Long-term debt
(including current
maturities)
Fixed rate (a) $ 396 $ 225 $ 127 $ 6 $ 216 $5,893 $6,863 $6,909 $3,875 $3,943
Average interest rate 6.98% 7.19% 6.87% 8.96% 5.21% 6.85% 6.81% -- 6.77% --
Variable rate -- -- -- -- -- $ 434 $ 434 $ 434 $2,334 $2,334
Average interest rate -- -- -- -- -- 1.46% 1.46% -- 3.86% --
Preferred stock of
subsidiary subject to
mandatory redemption
Fixed rate $ 10 $ 10 $ 1 -- -- -- $ 21 $ 15 $ 21 $ 21
Average interest rate 6.68% 6.68% 6.98% -- -- -- 6.69% -- 6.69% --
- ---------------------------------------------------------------------------------------------------------------
(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
6 to Financial Statements for details concerning long-term debt subject to
mandatory tender for remarketing.
A-31
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 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.
Concentration of Credit Risk
US Holdings' gross exposure to credit risk represents trade accounts
receivable, commodity contract assets and derivative assets.
A large share of gross assets subject to credit risk represents accounts
receivable from the retail sale of electricity to residential and small
commercial customers. The risk of material loss from non-performance from these
customers is unlikely based upon historical experience. Reserves for
uncollectible accounts receivable are established for the potential loss from
non-payment by these customers based on historical experience and market or
operational conditions. The restructuring of the electric industry in Texas
effective January 1, 2002, increases the risk profile of US Holdings in relation
to these customers; however, US Holdings has the ability to take actions to
mitigate such customer risk, particularly with the change in the POLR rules (see
discussion in Note 14 to Financial Statements under "Provider of Last Resort").
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 C&I
customers. US Holdings' wholesale commodity contract counterparties include
major energy companies, financial institutions, gas and electric utilities,
independent power producers, oil and gas producers and energy trading companies.
The following table presents the distribution of credit exposure as of
December 31, 2002, for commodity contract assets, and derivative assets and
trade accounts receivable from large C&I customers, by investment grade and
noninvestment grade, credit quality and maturity.
Exposure by Maturity
----------------------------------------
Exposure
before Greater
Credit Credit Less than than 5
Collateral Collateral Net Exposure 2 years 2-5 years years Total
--------- ---------- ------------ --------- --------- ------- ------
Investment grade $ 821 $ (4) $ 817 $ 763 $50 $4 $ 817
Noninvestment grade 518 (151) 367 346 21 - 367
------ ----- ------ ------ --- -- ------
Totals $1,339 $(155) $1,184 $1,109 $71 $4 $1,184
====== ===== ====== ====== === == ======
Investment grade 61% 3% 69%
Noninvestment grade 39% 97% 31%
A-32
The exposure to credit risk from these customers and counterparties,
excluding credit collateral, as of December 31, 2002, is $1.3 billion net of
standardized master netting contracts and agreements which provide the right of
offset of positive and negative credit exposures with individual customers and
counterparties. When considering collateral currently held by US Holdings (cash,
letters of credit and other security interests), the net credit exposure is $1.2
billion. Of this amount, approximately 69% 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 exposure to credit risk to these customers and counterparties on
this basis.
US Holdings had no exposure to any one customer or counterparty greater
than 10% of the net exposure of $1.2 billion at December 31, 2002. Additionally,
approximately 93% of the credit exposure, net of collateral held, has a maturity
date of less than two years. 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.
Regulation and Rates
Restructuring Legislation -- See Note 14 to Financial Statements for a
description of the significant provisions of the legislation passed by the Texas
Legislature regarding the restructuring of the Texas electricity market to
provide for a transition to competition. The opening of the Texas market to
competition was effective January 1, 2002.
TXU Energy -- Under Commission rules, affiliated REPs of utilities were
allowed to petition the Commission twice per year for an increase in the fuel
factor component of their price-to-beat rates if the average price of natural
gas futures increased more than 4% from the level used to set the previous
price-to-beat fuel factor rate. In March 2003, the Commission amended its rules
to require that natural gas prices increase more than 5% (10% if the petition is
filed after November 15 of any year) before allowing petitions for adjustments
to the fuel factor component. On August 23, 2002, the Commission approved TXU
Energy's request to increase the fuel factor component of its price-to-beat
rates. The fuel factor increase went into effect for the billing cycle that
began August 26, 2002. As a result, average monthly residential bills rose
approximately 5%. In January 2003, TXU Energy filed a request with the
Commission to increase the fuel factor component of its price-to-beat rates
based upon significant increases in the market price of natural gas. This
request was approved on March 5, 2003. The fuel factor increase went into effect
for the billing cycle that began March 6, 2003. As a result, average monthly
residential bills will rise approximately 12%.
Through calendar year 2002, TXU Energy was the POLR for residential and
small non-residential customers in those areas of ERCOT where customer choice
was available outside its historical service territory and was the POLR for
large non-residential customers in its historical service territory. TXU
Energy's POLR contract expired on December 31, 2002. However, in August 2002,
the Commission adopted new rules that significantly changed POLR service. Under
the new POLR rules, instead of being transferred to the POLR, non-paying
residential and small non-residential customers served by affiliated REPs are
subject to disconnection. Non-paying residential and small non-residential
customers served by non-affiliated REPs are transferred to the affiliated REP.
Non-paying large non-residential 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 must decide whether all REPs should be permitted to disconnect
all non-paying customers. The new POLR rules are expected to result in reduced
bad debt expense beginning in 2003.
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 POLR, but was designated POLR through
lottery for small business and residential customers in certain West Texas
service areas and for small business customers in the Houston service area.
A-33
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.
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 forward-looking statements (see
"Forward-Looking Statements" below), include:
The competitive electric market in Texas is new. US Holdings, the
Commission, ERCOT and other market participants have limited operating history
under the market framework created by the 1999 Restructuring Legislation. ERCOT
is the independent system operator that is responsible for maintaining reliable
operations of the bulk electric power supply system in the ERCOT region. Its
responsibilities include ensuring that information relating to a customer's
choice of REP is conveyed in a timely manner to anyone needing the information.
Some operational difficulties were encountered in the pilot program conducted in
2001 and are currently being experienced. Problems in the flow of information
between ERCOT, the T&D utilities and the REPs have resulted in delays in
switching customers from one REP to another and delays in billings to and
payments from consumers and REPs. While the flow of information is improving,
operational problems in the new system and processes are still being worked out.
Existing laws and regulations governing the market structure in Texas,
including the provisions of the 1999 Restructuring Legislation, could be
reconsidered, revised or reinterpreted, or new laws or regulations could be
adopted.
US Holdings' 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, Texas Gas Utility Regulatory
Act, as amended, Federal Power Act, as amended, Atomic Energy Act, as amended,
Public Utility Regulatory Policies Act of 1978, as amended, and Public Utility
Holding Company Act of 1935, as amended) and changing governmental regulatory
policy and actions (including those of the Public Utility Commission of Texas,
Railroad Commission of Texas, Federal Energy Regulatory Commission, and U.S.
Nuclear Regulatory Commission) 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 is subject to the effects of new, or changes in, income tax
rates or policies and increases in taxes related to property, plant and
equipment and gross receipts and other taxes. Further, US Holdings is subject to
audit and reversal of its tax positions by the Internal Revenue Service and
other taxing authorities.
US Holdings is not guaranteed any rate of return on its capital
investments in its unregulated businesses. US Holdings markets and trades power,
including from its own power 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 markets 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
A-34
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.
Oncor is subject to cost-of service regulation and annual earrings
oversight. Oncor's rates are regulated by the Commission based on an analysis of
Oncro's costs, as reviewed and approved in a regulatory proceeding. As part of
the regulatory settlement plan, US Holdings has agreed not to seek to increase
its distribution rates prior to 2004. Thus, the rates US Holdings is allowed to
charge may or may not match its related costs and allowed return on T&D invested
capital at any given time. While rate regulation is premised on the full
recovery of prudently incurred costs and a reasonable rate of return on invested
capital, there can be no assurance that the Commission will judge all of US
Holdings' T&D 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' T&D costs and the return on invested
capital allowed by the Commission.
Some of the fuel for US Holdings' power production facilities is purchased
under short-term contracts or on the spot market. Prices of fuel, including
natural gas, may also be volatile, and the price US Holdings can obtain for
power sales may not change at the same rate as changes in fuel costs. In
addition, US Holdings markets and trades natural gas and other energy related
commodities, and volatility in these markets may affect US Holdings' costs
incurred in meeting its obligations.
Volatility in market prices for fuel and electricity may result from:
o severe or unexpected weather conditions,
o seasonality,
o changes in electricity usage,
o the current diminished liquidity in the wholesale power markets as
well as any future illiquidity in these or other markets,
o transmission or transportation constraints, inoperability or
inefficiencies,
o availability of competitively priced alternative energy sources,
o changes in supply and demand for energy commodities,
o changes in power production capacity,
o outages at US Holdings' power production facilities or those of its
competitors,
o changes in production and storage levels of natural gas, lignite, coal
and crude oil and refined products,
o natural disasters, wars, sabotage, terrorist acts, embargoes and other
catastrophic events, and
o federal, state, local energy, environmental and other regulation and
legislation.
All but one of US Holdings' facilities for power production are located in
the ERCOT region, a market with limited interconnections to other markets.
Electricity prices in the ERCOT region are related to gas prices because gas
fired plant is the marginal cost plant unit during the majority of the year in
the ERCOT region. Accordingly, the contribution to earnings and the value of US
Holdings' base-load plant is dependent in significant part upon the price of
gas. US Holdings cannot fully hedge the risk associated with dependency on gas
because of the expected useful life of US Holdings' power production assets and
the size of its position relative to market liquidity.
To manage its financial exposure related to commodity price fluctuations,
US Holdings routinely enters into contracts to hedge portions of its purchase
and sale commitments, weather positions, fuel requirements and inventories of
natural gas, lignite, coal, crude oil and refined products, and other
commodities, within established risk management guidelines. As part of this
strategy, US Holdings routinely utilizes fixed-price forward physical purchase
and sales contracts, futures, financial swaps and option contracts traded in the
OTC markets or on exchanges. However, US Holdings cannot cover the entire
A-35
exposure of its assets or its positions to market price volatility, and the
coverage will vary over time. To the extent US Holdings has unhedged positions,
fluctuating commodity prices can impact US Holdings' results of operations and
financial position, either favorably or unfavorably. For additional information
regarding the accounting treatment for US Holdings' hedging and portfolio
management activities, see Notes 2 and 13 to Financial Statements. For
additional information regarding the types of contracts and activities of US
Holdings' wholesale energy sales business and portfolio management operation,
see the discussion above under "Financial Condition, Liquidity and Capital
Resources - Qualitative and Quantitative Disclosures about Market Risk."
Although US Holdings devotes a considerable amount of management time and
effort to the establishment of risk management procedures as well as the ongoing
review of the implementation of these procedures, the procedures it has in place
may not always be followed or may not always work as planned and cannot
eliminate all the risks associated with these activities. As a result of these
and other factors, US Holdings cannot predict with precision the impact that its
risk management decisions may have on its businesses, results of operations or
financial position. For information regarding US Holdings' risk management
policies, see the discussion above under "Financial Condition, Liquidity and
Capital Resources - Quantitative and Qualitative Disclosures about Market Risk -
Risk Oversight."
In connection with US Holdings' portfolio management activities, US
Holdings has guaranteed or indemnified the performance of a portion of the
obligations of its portfolio management subsidiaries. Some of these guarantees
and indemnities are for fixed amounts, others have a fixed maximum amount and
others do not specify a maximum amount. The obligations underlying certain of
these guarantees and indemnities are recorded on US Holdings' consolidated
balance sheet as both current and noncurrent commodity contract liabilities.
These obligations make up a significant portion of these line items. US Holdings
might not be able to satisfy all of these guarantees and indemnification
obligations if they were to come due at the same time.
US Holdings' portfolio management activities are exposed to the risk that
counterparties which owe US Holdings money, energy or other commodities as a
result of market transactions will not perform their obligations. The likelihood
that certain counterparties may fail to perform their obligations has increased
due to financial difficulties, brought on by improper or illegal accounting and
business practices, affecting some participants in the industry. Some of these
financial difficulties have been so severe that certain industry participants
have filed for bankruptcy protection or are facing the possibility of doing so.
Should the counterparties to these arrangements fail to perform, US Holdings
might be forced to acquire alternative hedging arrangements or honor the
underlying commitment at then-current market prices. In such event, US Holdings
might incur losses in addition to amounts, if any, already paid to the
counterparties. For information regarding US Holdings' credit risk, see the
discussion above under "Financial Condition, Liquidity and Capital Resources -
Quantitative and Qualitative Disclosure About Market Risk - Credit Risk" and
Note 17 to Financial Statements.
The current credit ratings for TXU Corp.'s and its subsidiaries' long-term
debt are investment grade, except for Moody's credit rating for long-term debt
of TXU Corp. (the holding company), which is one notch below 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 TXU Corp.'s
and/or its subsidiaries' long-term ratings, particularly below investment grade,
borrowing costs would increase and the potential pool of investors and funding
sources would likely decrease.
Most of US Holdings' large customers, suppliers and counterparties require
sufficient creditworthiness in order to enter into transactions. If US Holdings'
subsidiaries' ratings were to decline to below investment grade, costs to
operate the power business would increase because counterparties may require the
posting of collateral in the form of cash-related instruments, or counterparties
may decline to do business with US Holdings' subsidiaries.
In addition, as discussed elsewhere in this Annual Report on Form 10-K,
the terms of certain financing and other arrangements contain provisions that
are specifically affected by changes in credit ratings and could require the
posting of collateral, the repayment of indebtedness or the payment of other
amounts.
The operation of power production and 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
A-36
significant capital expenditures to keep it operating at peak efficiency. This
equipment is also likely to require periodic upgrading and improvement. The
increased starting and stopping of equipment due to the volatility of the
competitive market is likely to increase maintenance and capital expenditures.
US Holdings is subject to costs associated with any unexpected failure to
produce power, including failure caused by breakdown or forced outage, as well
as repairing damage to facilities due to storms, natural disasters, wars,
terrorist acts and other catastrophic events. Further, US Holdings' ability to
successfully and timely complete capital improvements to existing facilities or
other capital projects is contingent upon many variables and subject to
substantial risks. Should any such efforts be unsuccessful, US Holdings could be
subject to additional costs and/or the write-off of its investment in the
project or improvement.
Insurance, warranties or performance guarantees may not cover any or all
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.
The ownership and operation of nuclear facilities, including US Holdings'
ownership and operation of the Comanche Peak generation plant, involve certain
risks. These risks include: mechanical or structural problems; inadequacy or
lapses in maintenance protocols; the impairment of reactor operation and safety
systems due to human error; the costs of storage, handling and disposal of
nuclear materials; limitations on the amounts and types of insurance coverage
commercially available; and uncertainties with respect to the technological and
financial aspects of decommissioning nuclear facilities at the end of their
useful lives. The following are among the more significant of these risks:
o Operational Risk - Operations at any nuclear power production plant
could degrade to the point where the plant would have to be shut down.
If this were to happen, the process of identifying and correcting the
causes of the operational downgrade to return the plant to operation
could require significant time and expense, resulting in both lost
revenue and increased fuel and purchased power expense to meet supply
commitments. Rather than incurring substantial costs to restart the
plant, the plant may be shut down.
o Regulatory Risk - The NRC may modify, suspend or revoke licenses and
impose civil penalties for failure to comply with the Atomic Energy
Act, the regulations under it or the terms of the licenses of nuclear
facilities. Unless extended, the NRC operating licenses for Comanche
Peak Unit 1 and Unit 2 will expire in 2030 and 2033, respectively.
Changes in regulations by the NRC could require a substantial increase
in capital expenditures or result in increased operating or
decommissioning costs.
o Nuclear Accident Risk - Although the safety record of Comanche Peak and
nuclear reactors generally has been very good, accidents and other
unforeseen problems have occurred both in the US and elsewhere. The
consequences of an accident can be severe and include loss of life and
property damage. Any resulting liability from a nuclear accident could
exceed US Holdings' resources, including insurance coverage.
US Holdings will be required to apply a credit to its electricity delivery
charges (retail clawback) to REPs in Texas beginning in early 2004 unless the
Commission determines that, on or prior to January 1, 2004, 40% or more of the
amount of electric power that was consumed in 2000 by residential or small
commercial customers, as applicable, within its and TXU SESCO Company's
historical service territories is committed to be served by REPs other than TXU
Corp. Under the Settlement Plan, if the 40% test is not met and a credit is
required, the amount of these credits would be $90 multiplied by the number of
residential or small commercial customers, as the case may be, that US Holdings
serves on January 1, 2004, in its and TXU SESCO Company's historical service
territories less the number of new retail electric customers US Holdings serves
in other areas of Texas. As of December 31, 2002, US Holdings had approximately
2.7 million residential and small commercial customers in its and TXU SESCO
Company's historical service territories. Based on assumptions and estimates
regarding the number of customers expected in and out of territory, US Holdings
recorded an accrual for retail clawback in 2002 of $185 million ($120 million
after-tax). This accrual is subject to adjustment as the actual measurement date
approaches.
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
A-37
facilities, and future changes in environmental laws and regulations could
occur, including potential regulatory and enforcement developments related to
air emissions.
US Holdings may not be able to obtain or maintain all required
environmental regulatory approvals. If there is a delay in obtaining any
required environmental regulatory approvals or if US Holdings fails to obtain,
maintain or comply with any such approval, the operation of its facilities could
be stopped or become subject to additional costs. Further, at some of US
Holdings' older facilities it may be uneconomical for US Holdings to install the
necessary equipment, which may cause US Holdings to shut down those facilities.
In addition, US Holdings may be responsible for any on-site liabilities
associated with the environmental condition of facilities that it has acquired
or developed, regardless of when the liabilities arose and whether they are
known or unknown. In connection with certain acquisitions and sales of assets,
US Holdings may obtain, or be required to provide, indemnification against
certain environmental liabilities. Another party could fail to meet its
indemnification obligations to US Holdings.
On January 1, 2002, most retail customers in Texas of investor-owned
utilities, and those of any municipal utility and electric cooperative that
opted to participate in the competitive marketplace, became able to choose their
REP. On January 1, 2002, US Holdings began to provide retail electric services
to all customers who did not take action to select another REP.
US Holdings will not be permitted to offer electricity to residential and
small commercial customers in its and TXU SESCO Company's historical service
territory at a price other than the price-to-beat rate until January 1, 2005,
unless before that date the Commission determines that 40% or more of the amount
of electric power consumed by each respective class of customers in that area is
committed to be served by REPs other than US Holdings. Because US Holdings will
not be able to compete for residential and small commercial customers on the
basis of price in its and TXU SESCO Company's historical service territory, US
Holdings could lose a significant number of these customers to other providers.
In addition, at times, during this period, if the market price of power is lower
than US Holdings' cost to produce power, US Holdings would have a limited
ability to mitigate the loss of margin caused by its loss of customers by
selling power from its power production facilities.
Other REPs will be allowed to offer electricity to US Holdings'
residential and small commercial customers at any price. The margin or
"headroom" available in the price-to-beat rate for any REP equals the difference
between the price-to-beat rate and the sum of delivery charges and the price
that REP pays for power. The higher the amount of headroom for competitive REPs,
the more incentive those REPs should have to provide retail electric services in
a given market.
In addition, US Holdings provides commodity and value-added energy
management services to the large C&I customers who did not take action to select
another REP beginning on January 1, 2002. US Holdings or any other REP can offer
to provide services to these customers at any negotiated price. US Holdings
believes that this market will be very competitive; consequently, a significant
number of these customers may choose to be served by another REP, and any of
these customers that select US Holdings to be its provider may subsequently
decide to switch to another provider.
An affiliated REP is obligated to offer the price-to-beat rate to
requesting residential and small commercial customers in the historical service
territory of its incumbent utility through January 1, 2007. The initial
price-to-beat rates for the affiliated REPs, including US Holdings', were
established by the Commission on December 7, 2001. Pursuant to Commission
regulations, the initial price-to-beat rate for each affiliated REP is 6% less
than the average rates in effect for its incumbent utility on January 1, 1999,
adjusted to take into account a new fuel factor as of December 31, 2001.
The results of US Holdings' retail electric operations in its historical
service territory will be largely dependent upon the amount of headroom
available to US Holdings and the competitive REPs in US Holdings' price-to-beat
rate. Since headroom is dependent, in part, on power purchase costs, US Holdings
does not know nor can it estimate the amount of headroom that it or other REPs
will have in US Holdings' price-to-beat rate or in the price-to-beat rate for
the affiliated REP in each other Texas retail electric market. Headroom may be a
positive or negative number. If the amount of headroom in its price-to-beat rate
is a negative number, US Holdings will be selling power to its price-to-beat
rate customers in its historical service territory at prices below its costs of
purchasing and delivering power to those customers. If the amount of positive
headroom for competitive REPs in its price-to-beat rate is large, US Holdings
may lose customers to competitive REPs.
In April 2002, pursuant to Commission rules, US Holdings filed a request
with the Commission to increase the fuel factor component of its price to beat.
On August 23, 2002, the Commission acted on this request, increasing US
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Holdings' price-to-beat rates for residential and small commercial customers by
slightly less than 5%. In January 2003, US Holdings filed a request with the
Commission to increase the fuel factor component of its price-to-beat rates
based upon significant increases in the market price of natural gas. This
request was approved on March 5, 2003. The fuel factor increase went into effect
for the billing cycle that began March 6, 2003. As a result, average monthly
residential bills will rise approximately 12%. In March 2003, the Commission
amended its rules to require that natural gas prices increase more than 5% (10%
if the petition is filed after November 15 of any year) before allowing
petitions for adjustments to the full factor component. There is no assurance
that US Holdings' price-to-beat rate will not result in negative headroom in the
future, or that future adjustments to its price-to-beat rate will be adequate to
cover future increases in its costs to purchase power to serve its price-to-beat
rate customers.
In most retail electric markets outside its and TXU SESCO Company's
historical service territory, US Holdings' principal competitor may be the local
incumbent utility company or its retail affiliate. The incumbent utilities have
the advantage of long-standing relationships with their customers. In addition
to competition from the incumbent utilities and their affiliates, US Holdings
may face competition from a number of other energy service providers, or other
energy industry participants, who may develop businesses that will compete with
US Holdings in both local and national markets, and nationally branded providers
of consumer products and services. Some of these competitors or potential
competitors may be larger and better capitalized than US Holdings. If there is
inadequate margin in these retail electric markets, it may not be profitable for
US Holdings to enter these markets.
US Holdings depends on T&D facilities owned and operated by other
utilities, as well as its own such facilities, to deliver the electricity it
produces and sells to consumers, as well as to other REPs. If transmission
capacity is inadequate, US Holdings' ability to sell and deliver electricity may
be hindered, it may have to forgo sales or it may have to buy more expensive
wholesale electricity that is available in the capacity-constrained area. In
particular, during some periods transmission access is constrained to some areas
of the Dallas-Fort Worth metroplex. US Holdings expects to have a significant
number of customers inside these constrained areas. The cost to provide service
to these customers may exceed the cost to service other customers, resulting in
lower gross margins. In addition, any infrastructure failure that interrupts or
impairs delivery of electricity to US Holdings' customers could negatively
impact the satisfaction of its customers with its service.
Additionally, in Texas, US Holdings is dependent on unaffiliated T&D
utilities for the reading of its customers' energy meters. US Holdings is
required to rely on the utility or, in some cases, the independent transmission
system operator, to provide it with its customers' information regarding energy
usage, and it may be limited in its ability to confirm the accuracy of the
information.
In connection with any future entry into retail electric markets outside
of Texas, US Holdings may be required under the regulatory structure of the
relevant market to rely on utilities with which it may be competing to perform
billing and collection services, the services and functions described in the
prior paragraph or other services and functions. In addition, US Holdings may be
required to enter into agreements with local incumbent utilities for use of the
local distribution systems and for the creation and operation of functional
interfaces necessary for US Holdings to serve its customers. Any delay in these
negotiations or US Holdings' inability to enter into reasonable agreements could
delay or negatively impact its ability to serve customers in those markets.
US Holdings offers its customers a bundle of services that include, at a
minimum, the electric commodity itself plus transmission, distribution and
related services. To the extent that the prices US Holdings charges for this
bundle of services or for the various components of the bundle, either of which
may be fixed by contract with the customer for a period of time, differ from US
Holdings' underlying cost to obtain the commodities or services, its results of
operations would be adversely affected. US Holdings will encounter similar risks
in selling bundled services that include non-energy-related services, such as
facilities management, and the like. In some cases, US Holdings has little, if
any, prior experience in selling these non-energy-related services.
The 1999 Restructuring Legislation required the Commission to determine
procedures and criteria for designating REPs to serve as the POLR in areas of
the state in which retail competition is in effect. Through calendar year 2002,
US Holdings was the POLR for residential and small non-residential customers in
those areas of ERCOT where customer choice was available outside its and TXU
SESCO Company's historical service territory, and was the POLR for large
non-residential customers in such historical service territory. US Holdings'
POLR contract expired on December 31, 2002. However, in August 2002, the
Commission adopted new rules that significantly changed POLR service. Under the
new POLR rules, instead of being transferred to the POLR, non-paying residential
and small non-residential customers served by affiliated REPs are subject to
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disconnection. Non-paying residential and small non-residential customers served
by non-affiliated REPs are transferred to the affiliated REP. Non-paying large
non-residential 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 must decide whether all REPs should be permitted to disconnect all
non-paying customers. The new POLR rules are expected to result in reduced bad
debt expense beginning in 2003.
Through a competitive bid process, the Commission selected a POLR provider
to serve for a two-year term beginning January 1, 2003, for several areas within
the State. In areas for which no bids were submitted, the Commission selected
the POLR by lottery. US Holdings did not bid to be the POLR in any area, but was
designated POLR through lottery for small business and residential customers in
certain West Texas service areas and for small business customers in the Houston
service area. Under the new rules, as an affiliated REP, US Holdings may have to
temporarily provide electric service to some customers that are unable to pay
their electric bills. If the number of such customers is significant and US
Holdings is delayed in terminating electric service to those customers, its
results of operations may be adversely affected. US Holdings cannot be sure
whether the structure of POLR service and obligations will change further, how
it will change or what effect, if any, any further changes would have on US
Holdings.
The information systems and processes necessary to support risk
management, sales, customer service and energy procurement and supply in
competitive retail markets in Texas and elsewhere are new, complex and
extensive. US Holdings is refining these systems and processes, and they may
prove more expensive to refine than planned and may not work as planned.
Research and development activities are ongoing to improve existing and
alternative technologies to produce electricity, including gas turbines, fuel
cells, microturbines and photovoltaic (solar) cells. It is possible that
advances in these or other alternative technologies will reduce the costs of
electricity production from these technologies to a level that will enable these
technologies to compete effectively with electricity production from traditional
power plants like US Holdings'. While demand for electric energy services is
generally increasing throughout the US, the rate of construction and development
of new, more efficient power production facilities may exceed increases in
demand in some regional electric markets. The commencement of commercial
operation of new facilities in the regional markets where US Holdings has
facilities will likely increase the competitiveness of the wholesale power
market in those regions. In addition, the market value of US Holdings' power
production and/or energy transportation facilities may be significantly reduced.
In addition, electricity demand could be reduced by increased conservation
efforts and advances in technology, which could likewise significantly reduce
the value of US Holdings' facilities. Changes in technology could also alter the
channels through which retail electric customers buy electricity.
US Holdings is subject to employee workforce factors, including loss or
retirement of key executives, availability of qualified personnel, collective
bargaining agreements with union employees or work stoppage.
US Holdings is a holding company and conducts its operations primarily
through wholly owned subsidiaries. Substantially all of US Holdings'
consolidated assets are held by these subsidiaries. Accordingly, US Holdings'
cash flows and ability to meet its obligations are largely dependent upon the
earnings of its subsidiaries and the distribution or other payment of such
earnings to US Holdings in the form of distributions, loans or advances, and
repayment of loans or advances from US Holdings.
Because US Holdings is a holding company, its obligations to its creditors
are structurally subordinated to all existing and future liabilities and
existing and future preferred stock of its subsidiaries. Therefore, US Holdings'
rights and the rights of its creditors to participate in the assets of any
subsidiary in the event that such a subsidiary is liquidated or reorganized are
subject to the prior claims of such subsidiary's creditors and holders of its
preferred stock. To the extent that US Holdings may be a creditor with
recognized claims against any such subsidiary, its claims would still be subject
to the prior claims of such subsidiary's creditors to the extent that they are
secured or senior to those held by US Holdings.
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;
A-40
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 continued delays in billing and payment resulting from delays in
switching customers from one REP to another; and
o the occurrence of material adverse changes in US Holdings' business
that restrict US Holdings' ability to access its liquidity facilities.
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
likely increase its capital costs. Further, concerns on the part of
counterparties regarding US Holdings' liquidity and credit could limit its
portfolio management activities.
A lack of necessary capital and cash reserves could adversely impact US
Holdings' growth plans, its ability to raise additional debt and the evaluation
of its creditworthiness by counterparties and rating agencies.
As a result of the energy crisis in California during 2001, the recent
volatility of natural gas prices in North America, the bankruptcy filing by
Enron Corporation, accounting irregularities of public companies, and
investigations by governmental authorities into energy trading activities,
companies in the regulated and non-regulated utility businesses have been under
a generally increased amount of public and regulatory scrutiny. Accounting
irregularities at certain companies in the industry have caused regulators and
legislators to review current accounting practices and financial disclosures.
The capital markets and ratings agencies also have increased their level of
scrutiny. Additionally, allegations against various energy trading companies of
"round trip" or "wash" transactions, which involve the simultaneous buying and
selling of the same amount of power at the same price and provide no true
economic benefit, power market manipulation and inaccurate power and commodity
price reporting have had a negative effect on the industry. US Holdings believes
that it is complying with all applicable laws, but it is difficult or impossible
to predict or control what effect these events may have on US Holdings'
financial condition or access to the capital markets. Additionally, it is
unclear what laws and regulations may develop, and US Holdings cannot predict
the ultimate impact of any future changes in accounting regulations or practices
in general with respect to public companies, the energy industry or its
operations specifically.
US Holdings is subject to costs and other effects of legal and
administrative proceedings, settlements, investigations and claims.
The issues and associated risks and uncertainties described above are not
the only ones US Holdings may face. Additional issues may arise or become
material as the energy industry evolves. The risks and uncertainties associated
with these additional issues could impair US Holdings' businesses in the future.
Reference is made to the discussion under Liquidity and Capital Resources.
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: (i) prevailing governmental policies and regulatory actions,
including those of the Federal Energy Regulatory Commission, the Commission, the
Nuclear Regulatory Commission, particularly with respect to allowed rates of
return, industry, market and rate structure, purchased power and investment
recovery, operations of nuclear generating facilities, acquisitions and disposal
of assets and facilities, operation and construction of plant facilities,
decommissioning costs, present or prospective wholesale and retail competition,
changes in tax laws and policies and changes in and compliance with
environmental and safety laws and policies, (ii) general industry trends, (iii)
weather conditions and other natural phenomena, and acts of sabotage, wars or
terrorist activities, (iv) unanticipated population growth or decline, and
changes in market demand and demographic patterns, (v) competition for retail
and wholesale customers, (vi) pricing and transportation of crude oil, natural
gas and other commodities, (vii) unanticipated changes in interest rates,
A-41
commodity prices or rates of inflation, (viii) unanticipated changes in
operating expenses, liquidity needs and capital expenditures, (ix) commercial
bank market and capital market conditions, (x) competition for new energy
development opportunities, (xi) legal and administrative proceedings and
settlements, (xii) inability of the various counterparties to meet their
obligations with respect to US Holdings' financial instruments, (xiii) changes
in technology used and services offered by US Holdings, and (xiv) significant
changes in US Holdings' relationship with its employees and the potential
adverse effects if labor disputes or grievances were to occur, (xv) power costs
and availability, (xvi) changes in business strategy, development plans or
vendor relationships, (xvii) availability of qualified personnel, (xviii)
implementation of new accounting standards, (xix) financial and credit market
conditions, and credit rating agency actions and (xx) access to adequate
transmission facilities to meet changing demands.
Any forward-looking statement speaks only as of the date on which such
statement is made, and US Holdings undertakes no obligation to update any
forward-looking statement to reflect events or circumstances after the date on
which such statement is made or to reflect the occurrence of unanticipated
events. New factors emerge from time to time and it is not possible for US
Holdings to predict all of such factors, nor can it assess the impact of each
such factor or the extent to which any factor, or combination of factors, may
cause actual results to differ materially from those contained in any
forward-looking statement.
A-42
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, 2002, 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/ ERLE NYE /s/ T. L. BAKER
- ---------------------------------- -------------------------------------
Erle Nye, Chairman of the Board T. L. Baker, Oncor
and Chief Executive Group President
/s/ BRIAN N. DICKIE /s/ H. DAN FARELL
- ---------------------------------- --------------------------------------
Brian N. Dickie, TXU Energy H. Dan Farell, Executive Vice President
Group President and Principal Financial Officer
/s/ BIGGS C. PORTER
- -----------------------------------
Biggs C. Porter, Controller and
Principal Accounting Officer
A-43
INDEPENDENT AUDITORS' REPORT
TXU US Holdings Company:
We have audited the accompanying consolidated balance sheets of TXU US Holdings
Company (US Holdings) and subsidiaries as of December 31, 2002 and 2001, and
the related statements of consolidated income, comprehensive income,
shareholders' equity and cash flows for each of the three years in the period
ended December 31, 2002. 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, 2002 and 2001, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2002, in
conformity with accounting principles generally accepted in the United States of
America.
As discussed in Note 2 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
February 14, 2003
(March 19, 2003
as to Note 18)
A-44
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
Year Ended December 31,
--------------------------------
2002 2001 2000
---- ---- ----
Millions of Dollars
Operating revenues.......................................... $8,140 $8,020 $7,621
------ ------ ------
Costs and expenses:
Cost of energy sold and delivery fees.................... 3,214 3,051 3,192
Operating costs.......................................... 1,420 1,300 1,224
Depreciation and amortization, other than goodwill....... 702 635 621
Selling, general and administrative expenses............. 1,055 766 604
Franchise and revenue-based taxes........................ 411 442 344
Other income............................................. (38) (12) (40)
Other deductions......................................... 250 123 59
Interest income.......................................... (6) (39) (7)
Interest expense and other charges....................... 441 472 484
Goodwill amortization.................................... - 15 15
------ ----- -----
Total costs and expenses............................. 7,449 6,753 6,496
------ ----- -----
Income before income taxes and extraordinary loss........... 691 1,267 1,125
Income tax expense.......................................... 196 396 338
------ ----- -----
Income before extraordinary loss............................ 495 871 787
Extraordinary loss, net of tax effect....................... (134) (154) -
------ ----- -----
Net income before preferred stock dividends................. 361 717 787
Preferred stock dividends................................... 9 10 10
------ ------ -----
Net income available for common stock....................... $ 352 $ 707 $ 777
====== ====== =====
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
Year Ended December 31,
-----------------------------------
2002 2001 2000
---- ---- ----
Millions of Dollars
Net income.......................................................... $361 $717 $787
---- ---- ----
Other comprehensive income (loss)--
Net change during period, net of tax effects:
Minimum pension liability adjustments (net of tax benefit
of $20 and $-).............................................. (37) (1) -
Cash flow hedges (SFAS No. 133):
Cumulative transition adjustment as of January 1, 2001 - (1) -
Net change in fair value of derivatives (net of tax benefit
of $82 and tax expense of $9).............................. (153) 16 -
Amounts realized in earnings during the year (net
of tax benefit of $7 and $-)............................... (13) 1 -
----- ---- ----
Total.......................................... (203) 15 -
----- ---- ----
Comprehensive income........................................ $ 158 $732 $787
===== ==== ====
See Notes to Financial Statements.
A-45
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
Year Ended December 31,
------------------------------------
2002 2001 2000
---- ---- ----
Millions of Dollars
Cash flows-- operating activities
Net income (before preference stock dividends)................................. $ 361 $ 717 $ 787
Adjustments to reconcile net income to cash provided by operating activities:
Extraordinary loss, net of tax effect........................................ 134 154 -
Depreciation and amortization ............................................... 786 754 832
Deferred income taxes and investment tax credits-- net ...................... 60 (122) 139
Gains from sale of assets.................................................... (32) (2) (30)
Reduction of revenues for earnings in excess of regulatory earnings cap...... - 39 305
Net effect of unrealized mark-to-market valuations of commodity contracts.... 72 (314) 19
Asset impairments and writedowns............................................. 253 - -
Retail clawback accrual...................................................... 185 - -
Over/(under) recovered fuel costs............................................ - 568 (813)
Reduction in regulatory liability............................................ (151) - -
Changes in operating assets and liabilities:
Accounts receivable - trade (including affiliates)......................... (446) 218 (747)
Inventories................................................................ (44) (10) 10
Accounts payable - trade (including affiliates)............................ 95 (605) 939
Margin deposits............................................................ - 227 (225)
Commodity contract assets and liabilities ................................. (11) (31) 25
Other assets............................................................... (100) 52 (11)
Other liabilities.......................................................... 116 150 68
------- ------ ------
Cash provided by operating activities.................................... 1,278 1,795 1,298
------ ------ ------
Cash flows -- financing activities
Issuances of securities:
Exchangeable subordinated notes.............................................. 750 - -
Other long-term debt......................................................... 3,111 3,188 640
Retirements/repurchases of securities:
Long-term debt............................................................... (2,772) (2,507) (677)
Trust securities............................................................. - (837) -
Common stock................................................................. - (859) (802)
Dividends paid to parent........................................................ (927) - -
Net change in advances from affiliates.......................................... (799) 283 490
Capital contributions from parent.............................................. - 150 -
Preferred stock dividends paid.................................................. (9) (10) (10)
Increase (decrease) in notes payable to bank.................................... 1,804 - (8)
Debt premium, discount, financing, reacquisition expenses and
redemption deposits.......................................................... (384) (195) (7)
------ ------ ------
Cash provided by (used in) financing activities............................ 774 (787) (374)
------ ------- -------
Cash flows-- investing activities
Capital expenditures............................................................ (787) (965) (781)
Acquisition of a business....................................................... (36) - -
Nuclear fuel.................................................................... (51) (38) (87)
Proceeds from sale of assets.................................................... 447 - 8
Other........................................................................... (172) 9 (33)
------ ------- ------
Cash used in investing activities.......................................... (599) (994) (893)
------ ------- ------
Net change in cash and cash equivalents........................................... 1,453 14 31
Cash and cash equivalents-- beginning balance...................................... 55 41 10
------ ------- ------
Cash and cash equivalents-- ending balance........................................ $1,508 $ 55 $ 41
====== ======= ======
See Notes to Financial Statements.
A-46
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
ASSETS
December 31,
-------------------
2002 2001
---- ----
Millions of Dollars
Current assets
Cash and cash equivalents............................................................ $ 1,508 $ 55
Accounts receivable-- trade.......................................................... 1,386 940
Inventories ......................................................................... 338 297
Commodity contract assets............................................................ 1,298 848
Other current assets................................................................. 213 155
------- -------
Total current assets........................................................... 4,743 2,295
------- -------
Investments
Restricted cash...................................................................... 278 -
Other investments.................................................................... 491 721
Property, plant and equipment-- net.................................................... 16,183 16,156
Goodwill............................................................................... 558 558
Commodity contract assets.............................................................. 476 389
Regulatory assets...................................................................... 1,630 1,607
Cash flow hedges and other derivative assets........................................... 14 31
Other noncurrent assets................................................................ 146 81
------- -------
Total assets................................................................... $24,519 $21,838
======= =======
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Advances from affiliates......................................................... $ 787 $100
Notes payable - banks............................................................ 1,804 -
Long-term debt due currently......................................................... 397 374
Accounts payable
Affiliates....................................................................... 35 64
Other............................................................................ 785 669
Commodity contract liabilities....................................................... 1,138 630
Accrued taxes........................................................................ 303 309
Other current liabilities............................................................ 724 491
------- -------
Total current liabilities..................................................... 5,973 2,637
------ -------
Accumulated deferred income taxes...................................................... 3,227 3,331
Investment tax credits................................................................. 450 476
Commodity contract liabilities......................................................... 320 236
Cash flow hedges and other derivative liabilities...................................... 150 2
Other noncurrent liabilities and deferred credits...................................... 1,063 652
Advances from affiliates............................................................... - 1,200
Long-term debt, less amounts due currently............................................. 6,613 5,819
Preferred stock subject to mandatory redemption........................................ 21 21
Commitments and contingencies (Note 15)
Shareholders' equity (Note 9).......................................................... 6,702 7,464
------- -------
Total liabilities and shareholders' equity.................................... $24,519 $21,838
======= =======
See Notes to Financial Statements.
A-47
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED SHAREHOLDERS' EQUITY
Year Ended December 31,
-------------------------------------
2002 2001 2000
---- ---- ----
Millions of Dollars
Preferred stock -- not subject to mandatory redemption:
Balance at end of year (1,376,561 shares)......................... $ 115 $ 115 $ 115
------- ------ -------
Common stock without par value -- authorized shares -- 180,000,000:
Balance at beginning of year...................................... 2,248 3,107 3,831
Common stock repurchased and retired (2002-none, 2001--
28,627,000 shares; 2000-- 24,125,100 shares).................... - (859) (724)
Non-cash capital contribution related to issuance of
exchangeable subordinated debt................................. 266 - -
------- ------ -------
Balance at end of year (2002-- 52,817,862 shares;
2001-- 52,817,862 shares; and 2000-- 81,444,862 shares)........ 2,514 2,248 3,107
------- ------ -------
Stock of parent held for long-term incentive plan trust:
Balance at beginning of year...................................... - - (10)
Change during the year.......................................... - - 10
------- ------ -------
Balance at end of year............................................ - - -
------- ------ -------
Retained earnings:
Balance at beginning of year...................................... 5,086 4,229 3,530
Net income...................................................... 361 717 787
Capital contributions of parent................................. - 150 -
Common stock repurchased and retired............................ - - (78)
Common stock dividends paid and declared........................ (1,177) - -
Dividends declared on preferred stock........................... (9) (10) (10)
------- ------ ------
Balance at end of year............................................ 4,261 5,086 4,229
------- ------ ------
Accumulated other comprehensive income (loss), net of tax effects:
Minimum pension liability adjustment:
Balance at beginning of year...................................... (1) - -
Change during the year.......................................... (37) (1) -
------ ------ ------
Balance at end of year............................................ (38) (1) -
------ ------ ------
Cash flow hedges (SFAS No. 133):
Balance at beginning of year...................................... 16 - -
Change during the year.......................................... (166) 16 -
------ ------ ------
Balance at end of year............................................ (150) 16 -
------ ------ ------
Total accumulated other comprehensive income (loss)............. (188) 15 -
------ ------ ------
Total common stock equity........................................... 6,587 7,349 7,336
------ ------ ------
Shareholders' equity................................................ $6,702 $7,464 $7,451
====== ====== ======
See Notes to Financial Statements.
A-48
TXU US HOLDINGS COMPANY AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
1. BUSINESS, ACQUISITIONS AND DISPOSITIONS
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.
Use of the term "US Holdings", unless otherwise noted or indicated by the
context, refers to US Holdings, a holding company, and/or its consolidated
subsidiaries.
Business Restructuring - Legislation passed during the 1999 session of the
Texas Legislature restructured the electric utility industry in Texas and
provided for a transition to increased competition in the generation and retail
sale of electricity (1999 Restructuring Legislation). As a result, TXU Corp.
restructured certain of its United States (US) businesses as of January 1, 2002.
In order to satisfy its obligations to unbundle its business pursuant to the
1999 Restructuring Legislation and consistent with its business separation plan
as approved by on October 31, 2001, by the Public Utility Commission of Texas
(Commission), as of January 1, 2002, US Holdings transferred:
o its electric transmission and distribution (T&D) assets to Oncor,
which is a utility regulated by the Commission and a wholly owned
subsidiary of US Holdings,
o its power generation assets to subsidiaries of TXU Energy, which is
the new competitive business and a wholly owned subsidiary of US
Holdings, and
o its retail customers to a subsidiary retail electric provider (REP) of
TXU Energy.
The T&D assets of TXU SESCO Company, a subsidiary of TXU Corp., also
were transferred to Oncor. In addition, as of January 1, 2002, US Holdings
acquired the following businesses from within the TXU Corp. system and
transferred them to TXU Energy: the REP of TXU SESCO Company; operations
involving certain risk management and energy trading activities and the
unregulated commercial and industrial (C&I) retail gas operations of TXU Gas
Company (TXU Gas); and the energy management services businesses and other
affiliates of TXU Corp., including the fuel procurement and coal mining
businesses that service the generation operations.
The relationships of the entities affected by the restructuring 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.
A settlement of outstanding issues and other proceedings related to
implementation of the 1999 Restructuring Legislation received final approval in
January 2003. See Note 14 for further discussion.
Concurrent with the reorganization as of January 1, 2002, US Holdings
realigned its operations into two reportable segments: Energy and
Electric Delivery. (See Note 16 for further information concerning reportable
business segments.)
A-49
Business Changes
Business Acquisition -- 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 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 the results of the business have been included in the
consolidated financial statements from the acquisition date.
Generation Plant Acquisition and Disposition -- In May 2002, TXU Energy
acquired a 260 megawatt 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 its Handley and Mountain
Creek generating plants in the Dallas-Fort Worth area with total plant capacity
of 2,334 megawatts 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 pre-tax 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.
2. SIGNIFICANT ACCOUNTING POLICIES
Basis of Presentation -- In accordance with accounting principles
generally accepted in the United States of America (US GAAP), the business
restructuring transactions discussed above have been accounted for as a change
in reporting entity. As such, the consolidated financial statements of US
Holdings give retroactive effect to those transactions, which have been
accounted for in a manner similar to that in a pooling of interests. The
retroactive restatement resulting from the change in reporting entity decreased
net income of US Holdings by $11 million and $108 million for 2001 and 2000,
respectively. The consolidated financials of US Holdings and its subsidiaries
have been prepared in accordance with US GAAP. All intercompany items and
transactions have been eliminated in consolidation.
Included in the balance sheet of TXU Gas at December 31, 2001 was $773
million of goodwill, net of amortization, arising from TXU Corp.'s 1997
acquisition of ENSERCH Corporation. As a result of the transfer to TXU Energy of
certain operations from TXU Gas, which were originally part of ENSERCH
Corporation, and the adoption of Statement of Financial Accounting Standards
(SFAS) No. 142, "Goodwill and Other Intangible Assets", $468 million of
goodwill, net of $56 million of accumulated amortization, was allocated to these
operations and reflected in the December 31, 2002, balance sheet of US Holdings.
US Holdings has two reportable business segments: Energy and Electric Delivery
(See Note 16).
In the opinion of management, all adjustments (consisting of normal
recurring accruals) necessary for a fair presentation of the results of
operations and financial position have been included therein. All dollar amounts
in the financial statements and tables in the notes are stated in millions of US
dollars unless otherwise indicated.
US Holdings has adopted a new income statement format. Certain previously
reported amounts have been reclassified to conform to current classifications.
The following summarizes the components of the new line items:
Cost of energy sold and delivery fees -- Includes costs of nuclear, coal
and gas fuel used by generation plants, energy purchased for resale and delivery
fees paid to electricity delivery businesses.
Operating costs -- Includes all labor and overhead costs incurred to
perform activities directly related to power generation and the transmission and
distribution of electricity.
A-50
Selling, general and administrative expenses -- Includes all labor and
related overhead costs incurred to perform support services such as finance,
accounting, portfolio management, meter reading, customer billing, customer
service, collections, marketing, information technology, legal, regulatory,
environmental and corporate facilities.
Franchise and revenue-based taxes -- Includes state and local gross
receipts taxes and franchise taxes.
Presentation of Revenues -- In June 2002, the Emerging Issues Task Force
(EITF) reached a consensus on certain aspects of 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" regarding
the presentation of trading activities in the statement of income. The new rules
were effective on July 1, 2002, and required that all trading contracts (as
defined by EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities"), whether or not physically settled, be
recorded net upon settlement, rather than gross as a sale and cost of sale. US
Holdings has historically recorded financial contracts net, but has recorded
those contracts that provide for physical delivery gross upon settlement. Prior
period amounts have been reclassified to conform to this new reporting
requirement. Transactions affected by the new reporting requirements represent
contracts that provided for physical delivery but were settled financially
without delivery, as well as contracts physically settled but classified as
trading activities. With the rescission of EITF Issue No. 98-10 (see discussion
below under "Financial Instruments and Mark-to-Market Accounting"), the EITF
modified Issue No. 02-3 to apply to financial instruments that are derivatives
and entered into for trading purposes effective January 1, 2003. The new
reporting requirements have no impact on US Holdings' gross margin, net income
or cash provided by operating activities. (Also see "Changes in Accounting
Standards" below.)
The table below summarizes the impact on US Holdings' operating revenues
and cost of energy sold and delivery fees for prior years of the new reporting
rules under EITF Issue No. 02-3.
Years Ended December 31,
----------------------
2001 2000
---- ----
Operating revenues before reclassification....................... $13,179 $12,939
Cost of energy sold and delivery fees netted with revenues....... (5,159) (5,318)
------- --------
Operating revenues after reclassification........................ $ 8,020 $ 7,621
======= ========
Cost of energy sold and delivery fees before reclassification... $ 8,210 $ 8,510
Cost of energy sold and delivery fees netted with revenues....... (5,159) (5,318)
------- --------
Cost of energy sold and delivery fees after reclassification..... $ 3,051 $ 3,192
======= ========
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 to previous estimates 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 market risks related to
changes in commodity prices, including cost of fuel for generation of power, as
well as changes in interest rates. These financial instruments are accounted for
in accordance with SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities" and, prior to October 26, 2002, EITF Issue No. 98-10. The
majority of financial instruments entered into by US Holdings are derivatives as
defined in SFAS No. 133.
A-51
SFAS No. 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 No. 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.
Any hedge ineffectiveness is recorded in earnings. Amounts are reclassified from
other comprehensive income to earnings as the underlying transactions occur and
realized gains and losses are recognized in earnings. US Holdings has no fair
value hedges.
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 No.
133 for these non-trading transactions, providing the underlying transactions
continue to be forecasted to occur. Effectiveness is assessed based on changes
in cash flows of the hedges as compared to changes in cash flows of the hedged
items.
Pursuant to SFAS No. 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.
Financial instruments entered into in connection with indebtedness to
manage interest rate risks are generally accounted for as cash flow hedges in
accordance with SFAS No. 133.
EITF Issue No. 98-10 required mark-to-market accounting for energy-related
contracts, whether or not derivatives under SFAS No. 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 Issue No. 98-10 and were therefore marked to market. On October
25, 2002, the EITF rescinded EITF Issue No. 98-10. Pursuant to this rescission,
only financial instruments that are derivatives under SFAS No. 133 will be
subject to mark-to-market accounting. See discussion below under "Changes in
Accounting Standards."
In June 2002, in connection with the EITF's consensus on Issue No. 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. If the C&I retail contracts that US Holdings enters into do not
meet the requirements of the revised guidance, then income from such contracts
will be recognized on a settlement basis.
The majority of financial instruments entered into by US Holdings for the
purpose of managing risk or optimizing margins in meeting the energy demands of
customers are derivatives and will continue to be subject to SFAS No. 133.
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.). As a matter of
policy, however, US Holdings generally does not recognize any income or loss
from the illiquid periods.
Revenue Recognition -- US Holdings generally records revenues under the
accrual method, with the exception of certain large C&I retail contracts that
are derivatives as defined in SFAS No. 133 and have therefore been
A-52
marked-to-market. 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 T&D 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. The accrued
revenue is based on actual daily revenues for the most recent metered period
applied to the number of unmetered days through the end of the period.
As a result of the opening of the Texas market to competition and related
changes in systems and processes within ERCOT, adjustments are recorded for
accounts receivable from or payable to ERCOT related to system balancing and are
recorded net in revenues. Such balances reflect estimates of volumetric data and
are subject to adjustment as data is reconciled and final settlements are
determined.
Revenues reflect unrealized gains and losses related to large C&I retail
contracts, including unrealized gains recorded upon inception of these
contracts. Results of wholesale portfolio management activities, which represent
realized and unrealized gains and losses from transacting in energy-related
contracts, are also reported as a component of revenues. Also see discussion of
"Financial Instruments and Mark-to-Market Accounting" above.
The historical financial statements for periods prior to 2002 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 regulatory rate amounts are applied prospectively.
Regulatory Assets and Liabilities --The financial statements of US
Holdings' regulated business, the electricity transmission and distribution
operations of Oncor, reflect regulatory assets and liabilities under cost-based
rate regulation in accordance with SFAS No. 71, "Accounting for the Effect of
Certain Types of Regulation." As a result of the 1999 Restructuring Legislation,
the electricity generation portion of US Holdings' business no longer meets the
criteria to apply regulatory accounting principles. Accordingly, application of
SFAS No. 71 to the generation portion of US Holdings' business was discontinued
as of June 30, 1999. Oncor's operations continue to meet the criteria for
recognition of regulatory assets and liabilities.
In 2002, US Holdings recorded an extraordinary loss of $134 million (net
of income tax benefit of $72 million) principally to write down the regulatory
asset related to securitization bonds to be issued in accordance with US
Holdings' settlement plan with the Public Utility Commission of Texas
(Commission) as described in Note 14 to Financial Statements. The carrying value
of the regulatory asset is intended to represent the amount of future cash flows
related to the bonds to be recovered from REPs through increased electricity
delivery rates; the determination of such amount is based on estimates. The
writedown, which was taken as a result of the final approval of the settlement
plan, reflects the impact of lower interest rates. As actual interest rates on
the bonds may differ from current estimates, the regulatory asset carrying
value, which was $1.7 billion at December 31, 2002, is subject to further
adjustment.
Investments -- Deposits in an external trust fund for nuclear
decommissioning 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 nonutility properties are
primarily assets held for future development and are carried at cost, subject to
periodic impairment valuation. 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 equity interest, are accounted for under the equity method.
(See Note 4 - "Investments")
A-53
Goodwill and Intangible Assets -- Goodwill represents the excess of the
purchase price paid over the estimated fair value of the assets acquired and
liabilities assumed for each company acquired and was amortized over a range of
20 to 40 years.
SFAS No. 142 became effective for US Holdings on January 1, 2002. SFAS No.
142 requires, among other things, the allocation of goodwill to reporting units
based upon the current fair value of the reporting units, and the discontinuance
of goodwill amortization. The amortization of US Holdings' goodwill ($15 million
annually) ceased effective January 1, 2002.
In addition, SFAS No. 142 required completion of a transitional goodwill
impairment test within six months from the date of adoption. It established a
new method of testing goodwill for impairment on an annual basis, or on an
interim basis if an event occurs or circumstances change that would reduce the
fair value of a reporting unit below its carrying value. US Holdings completed
the transitional impairment test in the second quarter of 2002, the results of
which indicated no impairment of goodwill at that time. No impairment resulted
from the additional evaluation performed in 2002 as of October 1, which has been
selected as the annual impairment test date.
The table below reflects what reported income before extraordinary loss
and net income would have been in the 2001 and 2000 periods, exclusive of
goodwill amortization expense recognized in those periods compared to the 2002
periods.
Years Ended December 31,
-------------------------------
2002 2001 2000
---- ---- ----
Reported income before extraordinary loss.................... $ 495 $ 871 $ 787
Add back: goodwill amortization............................. - 15 15
------- ------- -------
Adjusted income before extraordinary loss.................... 495 886 802
Extraordinary loss, net of tax effect........................ (134) (154) -
------- ------- -------
Adjusted net income before preferred stock dividends......... 361 732 802
Preferred stock dividends.................................... 9 10 10
------- ------- -------
Adjusted net income available for common stock............... $ 352 $ 722 $ 792
======= ======= =======
SFAS No. 142 also requires additional disclosures regarding intangible assets (other than goodwill):
As of December 31, 2002 As of December 31, 2001
--------------------------- ----------------------------
Gross Gross
Carrying Accumulated Carrying Accumulated
Amount Amortization Net Amount Amortization Net
-------- ------------ --- --------- ------------- ----
Amortized intangible assets
Capitalized software.............. $371 $131 $240 $231 $ 72 $159
Land easements.................... 180 60 120 173 63 110
Mineral rights.................... 31 20 11 31 19 12
---- ---- ---- ---- ---- ----
Total....................... $582 $211 $371 $435 $154 $281
Amortized intangible asset balances are classified as property, plant and
equipment in the balance sheet.
A-54
Aggregate US Holdings amortization expense for intangible assets,
excluding goodwill, for the years ended December 31, 2002, 2001 and 2000 was $63
million, $14 million and $16 million, respectively; estimated amounts for the
next five years are as follows:
Amortization
Year Expense
---- ------------
2003............................................... $52
2004............................................... 47
2005............................................... 47
2006............................................... 44
2007............................................... 27
At December 31, 2002 and 2001, goodwill of $558 million was stated net of
accumulated amortization of $67 million.
Property, Plant and Equipment -- The cost of T&D 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 (described below). Generation property additions
subsequent to July 1, 1999, and other property are stated at cost; generation
additions in periods prior to that date are stated at cost less certain
regulatory disallowances.
Depreciation of Property, Plant and Equipment -- Depreciation of US
Holdings' property, plant and equipment is generally 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 2.7% for 2002, 2001 and
2000. See discussion below under "Changes in Accounting Standards"
regarding SFAS No. 143.
US Holdings capitalizes computer software costs in accordance with
American Institute of Certified Public Accountants Statement of Position 98-1,
"Accounting for the Cost of Computer Software Developed or Obtained for Internal
Use." These costs are being amortized over periods ranging from three to ten
years.
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 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,
effective July 1, 1999, recording of AFUDC ceased on construction work in
progress of generation assets and only interest was capitalized during
construction. Interest and AFUDC related to debt for subsidiaries that still
apply SFAS No. 71 are capitalized as a component of projects under construction.
Interest on qualifying projects for subsidiaries that no longer apply SFAS No.
71, is capitalized in accordance with SFAS No. 34, "Capitalization of Interest
Cost."
Valuation 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. (See
discussion below under "Changes in Accounting Standards" regarding SFAS No.
144.)
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 current wholesale electricity market conditions and
reduced planned developmental capital spending. Fair value was determined based
on current appraisals of property and equipment. The charge is reported in other
deductions in the statement of income. As the writedown is based on current
estimates, the remaining carrying value of the projects of $113 million is
subject to further adjustment should estimates of recoverable value change.
A-55
Major Maintenance -- Major maintenance outage costs related to nuclear
fuel reloads are charged to expense as incurred.
Amortization of Nuclear Fuel -- The amortization of nuclear fuel in the
reactors (net of regulatory disallowances) is calculated on the
units-of-production method and is reported in cost of energy sold.
Franchise and Revenue-Based Taxes -- Franchise and revenue-based taxes
such as gross receipts taxes are generally 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 a substantial majority of 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 the book and tax basis of assets and liabilities.
Certain provisions of SFAS No. 109, "Accounting for Income Taxes", provide that
regulated enterprises are permitted to recognize the expense associated with
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.
Gains/Losses on Extinguishments of Debt -- Gains and losses on reacquired
debt are recognized in the statement of income as incurred and reported as
extraordinary items in accordance with SFAS No. 4, "Reporting Gains and Losses
from Extinguishment of Debt", unless these costs will be recovered from
customers through regulated cash flows. In that case, these gains or losses are
deferred and recorded as a regulatory asset and amortized to interest expense
over the period approved for ratemaking purposes. (See discussion below under
"Changes in Accounting Standards" regarding SFAS No. 145.)
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 -- On October 25, 2002, the EITF rescinded
EITF Issue No. 98-10 which required mark-to-market accounting for all trading
activities. Pursuant to this rescission, only financial instruments that are
derivatives under SFAS No. 133 will be subject to mark-to-market accounting.
Financial instruments that may not be derivatives under SFAS No. 133 but were
marked-to-market under EITF Issue No. 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
approximately $100 million ($65 million after-tax) is expected to be reported as
a cumulative effect of an accounting change in the first quarter of 2003. The
expected cumulative effect adjustment represents the net gains previously
recognized for these contracts under mark-to-market accounting.
SFAS No. 143, "Accounting for Asset Retirement Obligations", became
effective on January 1, 2003. SFAS No. 143 requires entities to record the fair
value of a legal liability for an asset retirement obligation in the period in
which it is incurred. When a new liability is recorded beginning in 2003, the
entity will capitalize the net present value of the liability by increasing the
carrying amount of the related long-lived asset. The liability is accreted each
period, and the capitalized cost is depreciated over the useful life of the
related asset. Legal liabilities identified by US Holdings relate primarily to
nuclear decommissioning and reclamation of lands mined for lignite.
Prior to January 2003, US Holdings recorded liabilities for nuclear
decommissioning and for land reclamation in accumulated depreciation. Upon
adoption of SFAS No. 143, US Holdings will reclassify $271 million previously
recorded in accumulated depreciation and record the related liability. US
Holdings has not previously recorded costs of any other asset retirement
obligations that require recognition upon adoption.
A-56
With respect to nuclear decommissioning costs, US Holdings believes that
the adoption of SFAS No. 143 results primarily in timing differences in the
recognition of legal asset retirement costs that TXU Energy is currently
recovering, as Oncor recovers decommissioning fees from REPs on behalf of TXU
Energy, and will be deferring such differences through the regulatory process as
described in Note 14. The impact of adopting SFAS No. 143 is not expected to be
significant to US Holdings' earnings and financial condition.
SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets," became effective January 1, 2002. SFAS No. 144 establishes a single
accounting model, based on the framework established in SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of," for long-lived assets to be disposed of by sale, resolves
significant implementation issues related to SFAS No. 121 and establishes new
rules for reporting of discontinued operations.
SFAS No. 145, "Rescission of FASB Statements No. 4, 44 and 64, Amendment
of FASB Statement No. 13, and Technical Corrections," was issued in April 2002
and will be effective on January 1, 2003. One of the provisions of this
statement is the rescission of SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt." Any gain or loss on the early extinguishment of debt
that was classified as an extraordinary item in prior periods in accordance with
SFAS No. 4 will be reclassified if it does not meet the criteria of an
extraordinary item as defined by Accounting Principles Board Opinion 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."
SFAS No. 146, "Accounting for Costs Associated with Exit or Disposal
Activities," was issued in June 2002 and became effective on January 1, 2003.
SFAS No. 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.
SFAS No. 148, "Accounting for Stock-Based Compensation -- Transition and
Disclosure" was issued in December 2002. US Holdings adopted the disclosure
requirements of SFAS No. 148 effective December 31, 2002. This statement
requires that the pro forma information related to stock based compensation, for
companies that do not use fair value accounting, be presented in a table in the
accounting policies footnote. It also provides other transition alternatives
when companies adopt fair value accounting for stock based compensation. US
Holdings does not currently issue stock options.
Financial Accounting Standards Board Interpretation (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" was issued in
November 2002 and became effective for disclosures made in December 31, 2002,
financial statements. The interpretation requires expanded disclosures of
guarantees (see Note 15 to Financial Statements - "Guarantees"). In addition,
the interpretation requires recording the fair value of guarantees upon issuance
or modification after January 1, 2003.
FIN No. 46, "Consolidation of Variable Interest Entities" was issued in
January 2003. FIN No. 46 provides guidance related to identifying variable
interest entities and determining whether such entities should be consolidated.
This guidance will be effective for the quarter ending September 30, 2003.
For accounting standards not yet adopted or implemented,
including recent EITF rules regarding recognition of gains and losses at the
inception of a derivative contract, US Holdings is evaluating the potential
impact on its financial position and results of operations.
3. EXTRAORDINARY LOSS
As a result of debt restructuring and refinancings in the fourth quarter
of 2001, US Holdings recorded an extraordinary loss of $97 million (net of
income tax benefit of $52 million) for the early reacquisition of debt related
to TXU Energy by US Holdings.
A-57
Loss on Settlement -- As a result of the settlement plan (Settlement Plan)
submitted to the Commission for approval of outstanding unbundling issues (see
Note 14), US Holdings recorded an extraordinary loss of $57 million (net of
income tax benefit of $63 million) in the fourth quarter of 2001 to reflect the
effect of settlement items that are no longer probable of recovery. The
settlement-related items include unrecovered fuel cost, all remaining
generation-related regulatory assets and regulatory liabilities that are not
subject to recovery through the issuance of securitization bonds, and the excess
cost over market of certain purchased power contracts.
In August 2002 the regulatory Settlement Plan was approved and a financing
order was issued by the Commission, authorizing the issuance of transition
(securitization) bonds with a principal amount of $1.3 billion. (See Note 14.)
With the final approval of the settlement plan in January 2003, US Holdings may
proceed with the issuance of securitization bonds as provided in the Commission
financing order. In the fourth quarter of 2002, US Holdings recorded an
extraordinary loss of $134 million (after-taxes of $72 million) principally
reflecting a writedown of regulatory assets. The writedown reflects the effect
of lower expected cash flows associated with the securitization bonds due to the
decline in interest rates.
4. INVESTMENTS
The following information is a summary of the investment balance as of
December 31, 2002 and 2001:
December 31,
-----------------------
2002 2001
---- ----
Equity method investments in entities......................... $ 3 $ 7
Nuclear decommissioning trust................................. 266 276
Nonutility property........................................... 143 347
Assets related to certain employee benefit plans.............. 54 44
Notes receivable from unconsolidated entities................. 8 26
Miscellaneous other........................................... 17 21
------ ------
Total investments....................................... $ 491 $ 721
======= =======
Nuclear Decommissioning Trust -- Deposits in an external trust fund for
nuclear decommissioning costs are carried at fair value ($266 million and $276
million at December 31, 2002 and 2001, respectively), with the cumulative
increase in fair value recorded as a liability, reflecting the statutory nature
of the trust (see Note 15 - "Nuclear Decommissioning"). Decommissioning costs
are being recovered from Oncor's customers as a non-bypassable T&D charge over
the life of the plant and deposited in the external trust fund. As of December
31, 2002 and 2001, the composition of the external trust fund for
decommissioning of the Comanche Peak nuclear power generating station was as
follows:
December 31, 2002
--------------------------------------------------------------------------------
Cost Unrealized gain Unrealized (loss) Fair market value
Debt securities............ $ 128 $ 10 $ (1) $ 137
Equity securities.......... 111 37 (19) 129
------- ------ ------ -------
$ 239 $ 47 $ (20) $ 266
======= ====== ====== =======
December 31, 2001
--------------------------------------------------------------------------------
Cost Unrealized gain Unrealized (loss) Fair market value
Debt securities............ $ 120 $ 5 $ - $ 125
Equity securities.......... 99 61 (9) 151
------- ------ ------ -------
$ 219 $ 66 $ (9) $ 276
======= ====== ======- =======
Debt securities held at December 31, 2002 mature as follows: $48 million
in one to five years, $28 million in five to ten years and $61 million after ten
years.
Nonutility Property -- Nonutility property primarily represents the fair
value of land and equipment related to two lignite-fueled generation plant
construction projects in Texas with a carrying value of $113 million at December
31, 2002. (See discussion in Note 2 under "Valuation of Long-Lived Assets.")
A-58
5. SHORT-TERM FINANCING
At December 31, 2002, US Holdings had outstanding short-term borrowings
consisting of bank borrowings of $1.8 billion. During the years 2002 and 2001,
US Holdings' average amounts outstanding for short-term borrowings were $1.0
billion. Weighted average interest rates on short-term borrowings were 2.44% and
3.08% at December 31, 2002 and 2001, respectively.
At December 31, 2002, US Holdings had credit facilities (some of which
provide for long-term borrowings) as follows:
At December 31, 2002
--------------------------------------------------
Authorized Facility Letters of Cash
Facility Expiration Date Borrowers Limit Credit Borrowings Availability
- -------- --------------- --------- ----- ------ ---------- ------------
364-Day Revolving Credit Facility April 2003 US Holdings, TXU
Energy, Oncor $ 1,000 $ 122 $ 878 $ --
364-Day Senior Secured Credit December 2003 Oncor
Facility 150 -- -- 150
Five-Year Revolving Credit Facility February 2005 US Holdings 1,400 474 926 --
------- ------ ------ ------
Total $ 2,550 $ 596 $1,804 $ 150
======= ====== ====== ======
In October 2002, US Holdings, Oncor and TXU Energy borrowed approximately
$2.6 billion in cash against their available credit facilities, the total of
which represented the remaining availability after $549 million was used to
support outstanding letters of credit at that time. Of the borrowings, $800
million was repaid in November 2002 upon expiration of certain facilities. These
funds and other available cash were used, in part, to repay outstanding
commercial paper upon maturity. As of December 31, 2002, the remaining
facilities were fully drawn and were reflected in notes payable-banks on the
balance sheet. Excess cash of approximately $1.5 billion at December 31, 2002,
was invested in liquid short-term marketable securities earning current
market rates.
In October 2002, Oncor entered into a commitment for a secured credit
facility of up to $1 billion. The facility was intended to fund interim
refinancings of approximately $700 million of maturing secured debt should
market conditions not support a timely, cost effective refinancing. The balance
was to be available for general corporate purposes at Oncor. In December 2002,
Oncor issued $850 million of senior secured notes, reducing the commitment to
$150 million. Oncor subsequently converted the commitment to a $150 million
364-day senior secured credit facility, expiring in December 2003, all of which
was available at December 31, 2002.
In April 2002, US Holdings, TXU Energy and Oncor entered into the joint
$1.0 billion 364-day revolving credit facility with a group of banks that
terminates in April 2003; borrowings outstanding at any time can be extended for
one year. This facility is used for working capital and general corporate
purposes. Up to $1.0 billion of letters of credit may be issued under the
facility.
In the second quarter of 2002, each of TXU Energy and Oncor began issuing
commercial paper to fund its short-term liquidity requirements. The commercial
paper programs allowed each of TXU Energy and Oncor to issue up to $2.4 billion
and $1.0 billion of commercial paper, respectively. The credit facilities
provided back-up for the commercial paper issuances. The TXU Corp. commercial
paper program was discontinued in July 2002, and at that time, TXU Corp. was
removed as a borrower under the $1.4 billion five-year revolving credit
facility. As of December 31, 2002, there was no outstanding commercial paper
under these programs. In October 2002, US commercial paper markets became
inaccessible to US Holdings, TXU Energy and Oncor. Commercial paper borrowings
are expected to resume as market concerns regarding the liquidity of US Holdings
and its subsidiaries are mitigated.
With respect to the 364-day revolving credit facility in the above table,
US Holdings is pursuing various alternatives for renewing this facility. US
Holdings has the option under the agreement of converting the outstanding
borrowings at expiration to a 364-day term loan.
A-59
Sale of Receivables -- Certain subsidiaries of TXU Corp. sell trade
accounts receivable to TXU Receivables Company, a wholly owned bankruptcy remote
subsidiary of TXU Corp., which sells undivided interests in accounts receivable
it purchases to financial institutions. As of December 31, 2002, TXU Energy
(through certain subsidiaries), Oncor and TXU Gas are qualified originators of
accounts receivable under the program. TXU Receivables Company may sell up to an
aggregate of $600 million in undivided interests in the receivables purchased
from the originators under the program. As of December 31, 2002, $1.14 billion
face amount of US Holdings' receivables were sold to TXU Receivables Company
under the program in exchange for cash of $368 million and $744 million in
subordinated notes, with $29 million of losses on sales for the year ended
December 31, 2002 that principally represents the interest costs on the
underlying financing. These losses approximated 5% of the cash proceeds from the
sale of undivided interests in accounts receivable on an annualized basis.
Funding under the program decreased from $579 million at September 30, 2002 to
$368 million at December 31, 2002, primarily due to billing and collection
delays arising from new systems and processes in TXU Energy and ERCOT for
clearing customers switching and billing data, as well as seasonality of the
business.
Upon termination, cash flows to the originators would be delayed as
collections of sold receivables would be used by TXU Receivables Company to
repurchase the undivided interests of the financial institutions instead of
purchasing new receivables. The level of cash flows would normalize in
approximately 16 to 31 days. TXU Business Services Company, a subsidiary of TXU
Corp., services the purchased receivables and is paid a market based servicing
fee by TXU Receivables Company. The subordinated notes receivable from TXU
Receivables Company represent US Holdings' subsidiaries' retained interests in
the transferred receivables and are recorded at book value, net of allowances
for bad debts, which approximates fair value due to the short-term nature of the
subordinated notes, and are included in accounts receivable in the consolidated
balance sheet.
In October 2002, the program was amended to extend the program to July
2003, to provide for reserve requirement adjustments as the quality of the
portfolio changes and to provide for adjustments to reduce receivables in the
program by the related amounts of customer deposits held by originators. In
February 2003, the program was further amended to allow receivables that are
31-90 days past due into the program.
Contingencies Related to Receivables Program -- Although TXU Receivables
Company expects to be able to pay its subordinated notes from the collections of
purchased receivables, these notes are subordinated to the undivided interests
of the financial institutions in those receivables, and collections might not be
sufficient to pay the subordinated notes. The program may be terminated if
either of the following events occurs:
1) the credit rating for the long-term senior debt securities of all
originators and the parent guarantor, if any, declines below BBB- by
Standard & Poor's (S&P) or Baa3 by Moody's; or
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.
The delinquency and dilution ratios exceeded the relevant thresholds at
various times during 2002 and in January 2003, but waivers were granted. These
ratios were affected by issues related to the transition to deregulation.
Certain billing and collection delays arose due to implementation of new systems
and processes within TXU Energy and ERCOT for clearing customer switching and
billing data. The resolution of these issues as well as the implementation of
new POLR rules by the Commission (see Note 14) are expected to bring the ratios
in consistent compliance with the program.
Under the receivables sale program, all originators are required to
maintain a 'BBB-' (S&P) and a 'Baa3' (Moody's) rating or better (or supply a
parent guarantee with a similar rating). A downgrade below the required ratings
for an originator would prevent that originator from selling its accounts
receivable under the program. If all originators are downgraded so that there
are no eligible originators, the facility would terminate.
The accounts receivable program also contains a cross-default provision
with a threshold of $50 million applicable to each of the originators under the
program. TXU Receivables Company and TXU Business Services Company each have a
cross-default threshold of $50 thousand. If either an originator, TXU Business
Services Company or TXU Receivables Company defaults on indebtedness of the
applicable threshold, the facility could terminate.
A-60
6. LONG-TERM DEBT
US Holdings' long-term debt consists of the following:
Entity December 31,
- ------ --------------------
2002 2001
TXU Energy ---- ----
- ----------
Pollution Control Revenue Bonds:
Brazos River Authority:
1.390% Floating Taxable Series 1993 due June 1, 2023(c).......................... $ 44 $ 69
4.900% Fixed Series 1994A due May 1, 2029(b)..................................... 39 39
5.400% Fixed Series 1994B due May 1, 2029(b)..................................... 39 39
5.400% Fixed Series 1995A due April 1, 2030(b)................................... 50 50
5.050% Fixed Series 1995B due June 1, 2030(b).................................... 118 118
4.800% Fixed Series 1999A due April 1, 2033(b)................................... 111 111
1.150% Floating Series 1999B due September 1, 2034(c)............................ 16 16
1.450% Floating Series 1999C due March 1, 2032(c)................................ 50 50
4.950% Fixed Series 2001A due October 1, 2030(b)................................. 121 121
4.750% Fixed Series 2001B due May 1, 2029(b)..................................... 19 19
5.750% Fixed Series 2001C due May 1, 2036(b)..................................... 274 274
4.250% Fixed Series 2001D due May 1, 2033(b)..................................... 271 271
1.940% Floating Taxable Series 2001E due December 31, 2036....................... -- 36
1.700% Floating Taxable Series 2001F due December 31, 2036(c).................... 39 39
1.700% Floating Taxable Series 2001G due December 31, 2036(c).................... 72 72
1.470% Floating Taxable Series 2001H due December 31, 2036(c).................... 31 31
1.420% Floating Taxable Series 2001I due December 31, 2036(c).................... 63 63
1.650% Floating Series 2002A due May 1, 2037(a).................................. 61 --
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(b)..................................... 91 91
5.750% Fixed Series 2001B due May 1, 2030(b)..................................... 107 107
4.000% Fixed Series 2001C due May 1, 2028(b)..................................... 70 70
1.700% Floating Taxable Series 2001D due December 31, 2036(c).................... 12 12
1.470% Floating Taxable Series 2001E due December 31, 2036(a).................... 45 45
Trinity River Authority of Texas:
4.900% Fixed Series 2000A due May 1, 2028(b)..................................... 14 14
5.000% Fixed Series 2001A due May 1, 2027(b)..................................... 37 37
Other:
7.000% Fixed Senior Notes - TXU Mining Company LLP due May 1, 2003............... 72 125
3.410% Floating Rate Debentures due May 20, 2003................................. -- 1,500
6.875% Fixed Senior Notes - TXU Mining Company LLP due August 1, 2005............ 30 100
9.000% Fixed Exchangeable Subordinated Notes due November 22, 2012............... 750 --
Capital Lease obligations........................................................ 10 --
Other............................................................................ 8 8
Unamortized premium and discount................................................. (264) (1)
----------- -----------
Total TXU Energy............................................................. 2,451 3,577
----------- -----------
TXU US Holdings
- ---------------
7.170% Fixed Senior Debentures due August 1, 2007................................ 10 10
9.556% Fixed Notes due in bi-annual installments through December 4, 2019........ 73 75
8.254% Fixed Notes due in quarterly installments through December 31, 2021....... 68 70
2.507% Floating Rate Junior Subordinated Debentures, Series D due January 30,
2037(a).......................................................................... 1 1
8.175% Fixed Junior Subordinated Debentures, Series E due January 30, 2037....... 8 8
----------- -----------
Total TXU US Holdings ....................................................... 160 164
----------- -----------
A-61
December 31,
-------------------
2002 2001
---- -----
Oncor
- -----
9.320% Fixed Medium Term Secured Notes due January 15, 2002...................... -- 10
9.680% Fixed Medium Term Secured Notes due February 25, 2002..................... -- 20
9.700% Fixed Medium Term Secured Notes due March 1, 2002......................... -- 25
6.470% Fixed Medium Term Secured Notes due November 13, 2002..................... -- 3
6.560% Fixed Medium Term Secured Notes due November 20, 2002..................... -- 10
6.580% Fixed Medium Term Secured Notes due November 20, 2002..................... -- 5
9.530% Fixed Medium Term Secured Notes due January 30, 2003...................... 4 4
9.700% Fixed Medium Term Secured Notes due February 28, 2003..................... 11 11
8.125% Fixed First Mortgage Bonds due February 1, 2002........................... -- 150
8.000% Fixed First Mortgage Bonds due June 1, 2002............................... -- 147
6.750% Fixed First Mortgage Bonds due March 1, 2003.............................. 132 194
6.750% Fixed First Mortgage Bonds due April 1, 2003.............................. 69 95
2.426% Floating Rate Series C First Mortgage Bonds due June 15, 2003............. -- 400
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
8.875% Fixed First Mortgage Bonds due February 1, 2022........................... -- 112
7.875% Fixed First Mortgage Bonds due March 1, 2023.............................. 224 224
8.750% Fixed First Mortgage Bonds due November 1, 2023........................... 103 103
7.875% Fixed First Mortgage Bonds due April 1, 2024.............................. 133 133
8.500% Fixed First Mortgage Bonds due August 1, 2024............................. -- 115
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 --
7.000% Fixed Senior Secured Notes due May 1, 2032................................ 500 --
6.375% Fixed Senior Secured Notes due January 15, 2015........................... 500 --
7.250% Fixed Senior Secured Notes due January 15, 2033........................... 350 --
5.000% Fixed Debentures due September 1, 2007.................................... 200 --
7.000% Fixed Debentures due September 1, 2022.................................... 800 --
Unamortized premium and discount and fair value adjustments...................... (33) (15)
----------- -----------
Total Oncor ................................................................. 4,399 2,452
----------- -----------
Total US Holdings Consolidated................................................... 7,010 6,193
Less amount due currently........................................................ 397 374
----------- -----------
Total Long-Term Debt............................................................. $ 6,613 $ 5,819
=========== ===========
NOTES:
(a) Interest rates in effect at December 31, 2002.
(b) These series are in the multiannual mode. These bonds are subject to
mandatory tender prior to maturity on the mandatory remarketing date.
On such date, a new interest rate and interest rate period will be
reset for the bonds.
(c) Interest rates in effect at December 31, 2002. These series are in a
flexible or weekly rate mode and are supported by an irrevocable
letter of credit. Series in the flexible mode will be remarketed for
periods of less than 270 days.
In February 2003, Oncor gave notice of its intent to redeem on March 5,
2003, all ($103 million principal amount) of its First Mortgage and Collateral
Trust Bonds, 8 3/4% Series due November 1, 2023, at 104.01% of the principal
amount thereof, plus accrued interest to the redemption date. The notice is
subject to receipt of the redemption funds by the trustee on or before the
redemption date.
In December 2002, Oncor issued $850 million principal amount of its senior
secured notes in two series in a private placement with registration rights. One
series of $500 million bears interest at the annual rate of 6.375% and matures
in 2015, and the other series of $350 million bears interest at the annual rate
of 7.250% and matures in 2033. Each series is initially secured by a lien on an
equal principal amount of Oncor's first mortgage bonds and the lien of the
indenture under which the senior secured notes were issued; however, the lien of
those bonds may be released in certain circumstances. The net proceeds were used
by Oncor for the repurchase and retirement of $61 million principal amount of
Oncor's 6.75% First Mortgage Bonds due in March 2003 and the defeasance of the
remaining $133 million principal amount, and the repurchase and retirement of
$25 million principal amount of Oncor's 6.75% First Mortgage Bonds due April
2003 and the defeasance of the remaining $70 million principal amount. The
remaining net proceeds were used for general corporate purposes, including the
A-62
repayment of short-term advances from affiliates. The short-term advances
represented amounts previously borrowed to redeem $400 million principal amount
of Oncor's First Mortgage Bonds floating rate Series C due June 15, 2003.
The defeasance amounts (approximately $210 million at December 31, 2002)
were deposited with the trustee for such bonds with irrevocable instructions
from Oncor to apply such deposited proceeds to the payment of principal and
interest on such bonds through maturity or the earliest redemption date. These
deposits are reflected in restricted cash on the balance sheet.
In August 2002, Oncor issued $1.0 billion aggregate principal amount of
unsecured debentures in two series in a private placement with registration
rights. One series of $200 million is due September 1, 2007 and bears interest
at the rate of 5%, and the other series of $800 million is due September 1,
2022, and bears interest at the rate of 7%. Proceeds from the issuance were used
by Oncor to repay advances from affiliates and commercial paper.
In August 2002, Oncor redeemed all of its 8.5% First Mortgage Bonds due
August 1, 2024 and all of its 8.875% First Mortgage Bonds due February 1, 2022
in aggregate principal amounts of $115 million and $112 million, respectively.
In June 2002, Oncor redeemed all of its 8% First Mortgage Bonds due June 1, 2002
in the aggregate principal amount of $147 million, and in February 2002, Oncor
redeemed all of its 8.125% First Mortgage Bonds due February 1, 2002 in the
aggregate principal amount of $150 million. In July 2002, TXU Energy redeemed at
par the remaining $635 million principal amount of its floating rate debentures
due May 20, 2003. Oncor and TXU Energy funded the redemptions through the
issuance of commercial paper, advances from affiliates and cash from operations.
In May 2002, Oncor issued $1.2 billion aggregate principal amount of
senior secured notes in two series in a private placement with registration
rights. One series of $700 million is due May 1, 2012, and bears interest at the
annual rate of 6.375%, and the other series of $500 million is due May 1, 2032
and bears interest at the annual rate of 7%. Each series is initially secured by
an equal principal amount of Oncor's first mortgage bonds; however, the lien of
those bonds may be released in certain circumstances. Proceeds from the issuance
were used by Oncor to repay advances from US Holdings. US Holdings used the
repayments from Oncor to repay advances from TXU Energy and TXU Corp. TXU Energy
used the repayments to redeem $865 million principal amount of floating rate
debentures due May 20, 2003.
Also in May 2002, the Brazos River Authority issued $61 million principal
amount of weekly reset floating rate pollution control revenue refunding bonds
for TXU Energy, the proceeds of which were used to refund a similar principal
amount of pollution control revenue bonds.
During the first quarter of 2002, TXU Mining Company LP redeemed $70
million of its 6.875% senior notes due 2005 and $53 million of its 7.0% senior
notes due 2003.
As of December 31, 2002, the aggregate secured long-term debt of US
Holdings and its consolidated subsidiaries consisted of $3.4 billion of Oncor's
first mortgage bonds and senior secured notes that are secured by a lien on
substantially all of its tangible electric T&D property, and $15 million of
various other long-term debt secured by liens on utility plant and other assets.
US Holdings' long-term debt obligations are not guaranteed or secured by
affiliates.
2001 Debt Restructuring and Refinancing Plan -- On January 1, 2002,
US Holdings' business was restructured into a regulated T&D utility
business and an unregulated energy business. In connection with the
restructuring, the generation assets transferred to TXU Energy were released
from the lien of US Holdings' mortgage. Upon transfer of the T&D assets to
Oncor, Oncor assumed US Holdings' mortgage and the first mortgage bonds
outstanding thereunder. Substantially all of Oncor's T&D assets are subject to
liens under its mortgage indentures.
Under the debt restructuring and refinancing plan, US Holdings' pollution
control bond obligations were assumed by TXU Energy.
The debt restructuring process resulted in an extraordinary charge of $97
million (net of income tax benefit of $52 million) in the fourth quarter of
2001. (See Note 3.) In connection with the refinancing, $73 million in
A-63
additional pre-tax losses from the reacquisition of debt and trust securities
was allocated to Oncor and was written off in the fourth quarter of 2001; the
charge is reported in other deductions in the statement of income.
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.
Exchangeable Subordinated Debt -- In November 2002, TXU Energy issued $750
million of exchangeable subordinated notes in a private placement. The notes
will mature in November 2012, bear interest at the annual rate of 9% and permit
the deferral of interest payments. TXU Corp. has granted the holders the right
to exchange the notes for TXU Corp. common stock. The notes currently may be
exchanged, subject to certain restrictions, at any time for up to approximately
57 million shares of TXU Corp. common stock at an exercise 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 principal
amount of notes to be exchanged by the exercise price. The exercise price and
the number of shares to be issued are subject to anti-dilution adjustments. The
proceeds from the issuance of the notes were used for the repayment of two
standby credit facilities that expired in November 2002. TXU Energy has
recognized a capital contribution from TXU Corp. and a corresponding discount on
the notes of $266 million, for the value of the exchange right as TXU Corp.
granted an irrevocable right to exchange the notes for shares of TXU Corp.
common stock. This discount amount is being amortized to interest expense over
the term of the debt. (The unamortized balance was $264 million as of December
31, 2002.) As a result, the effective interest rate on the notes is 16.2%. At
the time of any exchange of the notes for common stock, the unamortized discount
will be proportionately written off as a charge to earnings.
The exchangeable notes are subordinated in bankruptcy to all other TXU
Energy obligations. TXU Energy has the right until May 2003 to require the
holders of the notes to exchange their interest in the notes for a preferred
equity interest in TXU Energy with economic and other terms substantially
identical to the notes. The original purchasers of the notes have the right to
nominate one member to the board of directors of TXU Corp., and such member has
been appointed to fill a vacancy. This right exists so long as the original
purchasers hold at least 30% of their original investment in the form of common
stock and/or notes, but no later than November 2012 or, if later, the date no
notes remain outstanding. The holders of the notes are restricted from actions
that would increase their control of TXU Corp. TXU Energy and the holders
characterize the notes as preferred equity interests for federal and state
income tax purposes with the result that TXU Energy is treated as a
partnership.
Maturities -- Sinking fund and maturity requirements for all long-term
debt instruments, excluding capital lease obligations, in effect at December 31,
2002, were as follows:
Year
----
2003......................................................... $ 396
2004......................................................... 225
2005......................................................... 127
2006......................................................... 6
2007 ........................................................ 216
Thereafter................................................... 6,327
Unamortized premium and discount and fair value adjustments.. (297)
Capital lease obligations.................................... 10
------
Total.................................................... $7,010
======
Financial Covenants, Credit Rating Provisions and Cross-Default
Provisions -- The terms of certain financing arrangements of US Holdings and its
consolidated 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 subordinated notes also limit its
incurrence of additional indebtedness unless a leverage ratio and interest
coverage test are met on a pro forma basis. As of December 31, 2002, US Holdings
and its subsidiaries were in compliance with all such applicable covenants.
A-64
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
provisions are described below.
Other agreements of US Holdings and its subsidiaries, including some of
the credit facilities discussed above, contain terms pursuant to which the
interest rates charged under the agreements may be adjusted depending on the
credit ratings of US Holdings or its subsidiaries.
Cross-Default Provisions
Certain financing arrangements of US Holdings and its subsidiaries contain
provisions that would result in an event of default if there is a failure under
other financing arrangements to meet payment terms or to observe other covenants
that would result in an acceleration of payments due. Such provisions are
referred to as "cross-default" provisions. Most agreements have a cure period of
up to 30 days from the occurrence of the specified event during which the
company is allowed to rectify or correct the situation before it becomes an
event of default.
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
$1.0 billion joint US Holdings/TXU Energy/Oncor 364-day revolving credit
facility, the $1.4 billion US Holdings 5-year revolving credit facility, two
letter of credit back-up facilities ($68.1 million and $54.2 million currently
outstanding) and the $103 million TXU Mining Company LP senior notes (which have
a $1 million threshold). Under the joint US Holdings/TXU Energy/Oncor $1.0
billion 364-day revolving 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 and US Holdings, but not as to
Oncor. Also, under this credit facility, a default by Oncor or any subsidiary
thereof would cause the maturity of outstanding balances to be accelerated under
such facility as to Oncor and US Holdings, but not as to TXU Energy. Further,
under this credit facility, a default by US Holdings would cause the maturity of
outstanding balances under such facility to be accelerated as to US Holdings,
but not as to Oncor or TXU Energy. Under the Oncor $150 million credit facility,
a default by Oncor or any subsidiary thereof would cause the maturity of
outstanding balances under such facility to be accelerated.
7. US HOLDINGS OBLIGATED, MANDATORILY REDEEMABLE, PREFERRED SECURITIES OF
SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR SUBORDINATED DEBENTURES OF US HOLDINGS
(TRUST SECURITIES)
Statutory business trusts had been established as wholly owned financing
subsidiaries (Trusts) of US Holdings for the purpose of issuing trust securities
and holding Junior Subordinated Debentures issued by US Holdings (Debentures).
The only assets of each Trust were Debentures of US Holdings having a principal
amount set forth under "Trust Assets" in the table below. The interest on Trust
assets matched the distributions on the Trust Securities. Each Trust used
interest payments received on the Debentures it held to make cash distributions
on the Trust Securities it had issued.
The Trust Securities were subject to mandatory redemption upon payment of
the Debentures at maturity or upon redemption. The Debentures were subject to
redemption, in whole or in part at the option of US Holdings, at 100% of their
principal amount plus accrued interest, after an initial period during which
they could not be redeemed and at any time upon the occurrence of certain
events. The carrying value of the Trust Securities was increased periodically to
equal the redemption amounts at the mandatory redemption dates with a
corresponding increase in Trust Securities distributions.
In December 2001, in connection with the restructuring and refinancing
plans of US Holdings to comply with the 1999 Restructuring Legislation, the TXU
Electric Capital I and Capital III Trust Securities, with liquidation
preferences of $25 per unit, were redeemed for $141 million and $194 million,
respectively. In addition, US Holdings redeemed $99 million of the $100 million
of outstanding TXU Electric Capital IV Trust Securities and $392 million of the
$400 million outstanding amount of its TXU Electric Capital V Trust Securities,
both of which had a liquidation preference of $1,000 per unit. Following the
completion of the redemption, the Capital IV and V Trusts were liquidated. The
capital securities held by the security holders were refinanced by proceeds of
junior subordinated debentures of US Holdings, which are classified on the
balance sheet as other long-term debt.
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The statutory business trust subsidiaries of US Holdings had Trust
Securities outstanding and Trust Assets as follows at December 31:
Trust Securities
------------------------------------------------- Trust Assets
Units (OOO's) Amount Amount Maturity
---------------------- --------------------- ----------------------- -------
2002 2001 2000 2002 2001 2000 2002 2001 2000
---- ---- ---- ---- ---- ---- ---- ---- ----
TXU Electric Capital I
(8.25% Series)........ - - 5,871 - - $ 141 - - $ 155 2030
TXU Electric Capital III
(8.00% Series)........ - - 8,000 - - 194 - - 206 2035
TXU Electric Capital IV
(Floating Rate Trust
Securities).......... - - 100 - - 98 - - 103 2037
TXU Electric Capital V
(8.175% Series)....... - - 400 - - 396 - - 412 2037
--- --- ------ --- --- ----- --- --- -----
Total ................ - - 14,371 - - $ 829 - - $ 876
--- --- ------ --- --- ----- ---- --- -----
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8. PREFERRED STOCK
Shares Outstanding Amount
December 31, December 31, Redemption Price Per Share
2002 and 2001 2002 and 2001 December 31, 2002
----------------------- --------------- -------------------------
(thousands of shares)
Not Subject to Mandatory Redemption:
- ------------------------------------
US Holdings (a):
$4.00 to $5.08 dividend rate series.. 379 $ 38 $101.79 to $112.00
$7.98 series......................... 261 26 (c)
$7.50 series (b)..................... 308 30 (c)
$7.22 series (b)..................... 221 21 (c)
----
Total........................... $115
====
Subject to Mandatory Redemption:
- --------------------------------
US Holdings (a):
$6.98 series......................... 107 $ 11 (d)
$6.375 series........................ 100 10 (d)
----
Total........................... $ 21
====
- -----------------
(a) Cumulative, without par value, entitled upon liquidation to $100 per
share; 17,000,000 total shares authorized.
(b) The preferred stock series is the underlying preferred stock for
depositary shares that were issued to the public. Each depositary
share, at $25 per share, represents one quarter of a share of
underlying preferred stock.
(c) Not redeemable at December 31, 2002.
(d) US Holdings was required to redeem at a price of $100 per share plus
accumulated dividends a specified minimum number of shares annually or
semi-annually. As of December 31, 2002, US Holdings has met its
sinking fund requirements on these securities and has no further
mandatory redemption requirements. US Holdings may annually call for
redemption, at its option, an aggregate of up to twice the number of
shares shown below for each series at a price of $100 per share plus
accumulated dividends on the following dates.
Redeemable
Series Shares Date of Redemption
----------------------------- ------------------
$ 6.980 50,000 annually July 1
$ 6.375 50,000 annually October 1
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.
The holders of preferred stock 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
while certain dividend arrearages exist. The holders of preferred trust
securities have no voting rights.
9. SHAREHOLDERS' EQUITY
US Holdings issued 1,695,262 shares of its common stock to TXU Corp. on
January 1, 2002 in connection with the transfer of businesses described in Note
1 under "Business Restructuring." Such share issuance has been reflected
retroactively to the beginning period presented as discussed in Note 2 under
"Basis of Presentation."
On March 6, 2002, US Holdings declared a cash dividend of $250 million
which was paid to TXU Corp. on April 1, 2002. On May 8, 2002, US Holdings
declared cash dividends of $177 million and $250 million which were paid to TXU
Corp. on May 17, 2002, and July 1, 2002, respectively. On August 7, 2002, US
Holdings declared a cash dividend of $250 million which was paid to TXU Corp. on
October 1, 2002. On November 15, 2002, US Holdings declared a cash dividend of
$250 million which was paid to TXU Corp. on January 2, 2003.
A-67
The mortgage of Oncor restricts Oncor's payment of dividends to the amount
of its retained earnings. At December 31, 2002, there were no restrictions on
the payment of dividends under these provisions.
10. INCOME TAXES
The components of income tax expense (benefit) are as follows:
Year Ended December 31,
------------------------------
2002 2001 2000
---- ---- ----
Current:
US Federal.................................................... $132 $482 $185
State......................................................... 3 41 13
Non-US........................................................ 1 (5) 1
---- ---- ----
Total.................................................... 136 518 199
---- ---- ----
Deferred:
US Federal.................................................... 83 (95) 182
State......................................................... 4 (3) (20)
Non-US........................................................ (1) (1) -
---- ---- ----
Total.................................................... 86 (99) 162
---- ---- ----
Investment tax credits......................................... (26) (23) (23)
---- ---- ----
Total.................................................... $196 $396 $338
==== ==== ====
Reconciliation of income taxes computed at the US federal statutory rate
to income tax expense:
Year Ended December 31,
-------------------------------
2002 2001 2000
---- ---- ----
Income before income taxes and extraordinary loss........................ $ 691 $1,267 $1,125
----- ------ ------
Income taxes (benefit) at the federal statutory rate of 35%.............. $ 242 $ 443 $ 394
Depletion allowance.................................................... (25) (25) (24)
Amortization of investment tax credits................................. (26) (23) (23)
Amortization (under regulatory accounting) of statutory rate changes.. (8) (7) (9)
State income taxes, net of federal tax benefit......................... 5 25 (6)
Other.................................................................. 8 (17) 6
----- ------ ------
Income tax expense........................................................ $ 196 $ 396 $ 338
===== ====== ======
Effective tax rate (on income before preferred stock dividends
of subsidiaries)....................................................... 28% 31% 30%
A-68
Deferred income taxes provided by the liability method for significant
temporary differences based on tax laws in effect at December 31, 2002 and 2001
balance sheet dates are as follows:
December 31,
---------------------------------------------------------------------
2002 2001
--------------------------------- -------------------------------
Total Current Noncurrent Total Current Noncurrent
----- ------- ---------- ----- ------- ----------
Deferred Tax Assets
Unamortized investment tax credits............ $ 172 $ - $ 172 $ 181 $ - $ 181
Impairment of assets.......................... 133 - 133 135 - 135
Regulatory disallowance....................... 80 - 80 93 - 93
Alternative minimum tax....................... 417 - 417 343 - 343
Regulatory liability.......................... 60 - 60 124 - 124
Employee benefits............................. 174 - 174 144 - 144
Other......................................... 282 65 217 159 85 74
------ ----- ------ ----- ---- ------
Total deferred federal income tax asset. 1,318 65 1,253 1,179 85 1,094
------ ----- ------ ----- ---- ------
Deferred state income taxes................. 2 - 2 13 - 13
------ ----- ------ ----- ---- ------
Total deferred income tax asset......... $1,320 $ 65 $1,255 $1,192 $ 85 $1,107
------ ----- ------ ------ ---- ------
Deferred Tax Liabilities
Depreciation differences and capitalized
construction costs........................ $3,684 $ - $3,684 $3,620 $ - $3,620
Redemption of long-term debt................ 44 - 44 40 - 40
Securitizable regulatory asset.............. 571 - 571 633 - 633
Other....................................... 170 - 170 120 - 120
------ ----- ------ ------ --- ------
Total deferred federal income
tax liability......................... 4,469 - 4,469 4,413 - 4,413
Deferred state income taxes................. 13 - 13 25 - 25
------ ----- ------ ------ ---- ------
Total deferred income tax liability..... 4,482 - 4,482 4,438 - 4,438
------ ----- ------ ------ ---- ------
Net Deferred Income Tax Liability(Asset).... $3,162 $ (65) $3,227 $3,246 $(85) $3,331
====== ===== ====== ====== ==== ======
At December 31, 2002, US Holdings had approximately $417 million of
alternative minimum tax credit carryforwards available to offset future tax
payments.
The tax effect of the components included in accumulated other
comprehensive income for the year ended December 31, 2002, was a net benefit of
$109 million.
TXU Corp.'s income tax returns are subject to examination by applicable tax
authorities. The Internal Revenue Service (IRS) is currently examining the tax
years ended 1993 through 1997 for certain of TXU Corp.'s subsidiaries and 1994
through 1996 for other subsidiaries. In management's opinion, an adequate
provision has been made for any future taxes that may be owed as a result of any
examination. To the extent that adjustments to income tax accounts of acquired
businesses for periods prior to their acquisition are required as a result of an
examination, the adjustment will be added to or deducted from goodwill.
11. RETIREMENT PLANS AND OTHER POSTRETIREMENT BENEFITS
US Holdings is a participating employer 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 the
Employee Retirement Income Security Act of 1974, as amended (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 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.
A-69
All eligible employees hired after January 1, 2002 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.
The allocated net periodic pension cost (benefit) applicable to US
Holdings was ($4) million for 2002, ($21) million for 2001 and ($22) million for
2000. Estimated accrued pension cost applicable to US Holdings as of December
31, 2002 and 2001 was $99 million and $52 million, respectively. Contributions
were $9 million, $2 million and $1 million in 2002, 2001 and 2000, respectively.
The amounts provided represent allocations of the TXU Corp. Retirement Plan to
US Holdings.
In addition, US Holdings' 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 January 1, 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 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 employee contributions up to 6% of
regular salary or wages for employees who participate under the cash balance
formula of the Retirement Plan, and 75% of employee contributions up to 6% of
regular salary or wages for employees who participate under the traditional
defined benefit formula of the Retirement Plan. Employer matching contributions
are invested in TXU Corp. common stock. Contributions to the Thrift Plan by TXU
Corp. aggregated $30 million for 2002, $16 million for 2001 and $15 million for
2000. US Holdings' portion of such contributions was $22 million in 2002, $12
million in 2001 and $11 million in 2000.
In addition to the Retirement Plan and the Thrift Plan, US Holdings
participates 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 $62 million for 2002, $52
million for 2001 and $50 million for 2000. Contributions paid by US Holdings to
fund postretirement benefits other than pensions were $39 million, $37 million
and $33 million in 2002, 2001 and 2000, respectively.
12. FAIR VALUE OF FINANCIAL INSTRUMENTS
The carrying amounts and related estimated fair values of US Holdings'
significant financial instruments were as follows:
December 31, 2002 December 31, 2001
----------------- ----------------
Carrying Fair Carrying Fair
Amount Value Amount Value
--------- ----- -------- -----
On balance sheet liabilities:
Long-term debt (including current maturities)*................ $7,000 $7,343 $6,193 $6,277
Preferred stock subject to mandatory redemption............... 21 15 21 21
Off balance sheet liabilities:
Financial guarantees.......................................... -- 84 -- --
*Excludes capital leases.
With the implementation of SFAS No. 133, on January 1, 2001, financial
instruments that are derivatives are now recorded on the balance sheet at fair
value.
A-70
The carrying value of securities held in external trusts for nuclear
decommissioning are based on quoted market prices. (See Note 4.) The remaining
investments are not considered to be financial instruments and are recorded at
cost.
The fair values of long-term debt and preferred stock subject to mandatory
redemption 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. The fair value
of trust securities is based on quoted market prices.
The fair value of the guarantees 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.
13. DERIVATIVE FINANCIAL INSTRUMENTS
During 2002, certain of US Holding's cash flow hedges related to
anticipated sales from baseload generation became less effective due to changes
in ERCOT market rules and conditions. US Holdings experienced total net hedge
ineffectiveness related to these contracts of $41 million ($27 million
after-tax) in 2002, which has been recognized as a charge to revenues. In 2001,
US Holdings experienced net hedge ineffectiveness of $4 million ($3 million
after-tax) recorded as a credit to revenues.
As of December 31, 2002, the maximum length of time US Holdings had hedged
its exposure to the variability of future cash flows for forecasted
transactions, excluding the payment of variable interest on existing
indebtedness, was two years. During 2002, US Holdings entered into certain cash
flow hedges related to future forecasted interest payments. These hedges were
terminated later in 2002, and $133 million ($86 million after-tax) was recorded
as a charge to other comprehensive income. These losses are being amortized to
earnings over a period of up to thirty years, as transactions are still
forecasted.
As of December 31, 2002, US Holdings expects that $80 million ($52 million
after-tax) in 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 other comprehensive loss by type of
derivatives:
Other Comprehensive Loss
Year Ended December 31, 2002
-----------------------------
Treasury Commodity Total
-------- --------- -----
Dedesignated hedges (amounts fixed)................. $ 86 $ 24 $ 110
Hedges subject to market price fluctuations......... -- 40 40
------ ------ ------
Total.......................................... $ 86 $ 64 $ 150
====== ====== ======
14. REGULATIONS AND RATES
Restructuring Legislation -- The 1999 Restructuring Legislation
restructured the electric utility industry in Texas and provided for a
transition to increased competition in the generation and retail sale of
electricity. Under the 1999 Restructuring Legislation, each electric utility was
required to separate (unbundle) by January 1, 2002, its business activities into
a power generation company (PGC), a REP, and a T&D utility or separate T&D
utilities. Unbundled T&D utilities within ERCOT, such as Oncor, remain regulated
by the Commission.
A-71
Beginning January 1, 2002, REPs affiliated with T&D utilities began
charging residential and small commercial customers located in their historical
service territories rates that are 6% less than the rates that were in effect on
January 1, 1999, as adjusted for fuel factor changes ("price-to-beat rate"). TXU
Energy, as a REP affiliated with a T&D utility, may not charge prices to such
customers that are different from the price-to-beat rate until the earlier of
January 1, 2005, or the date on which 40% of the electricity consumed by
customers in those respective customer classes is supplied by competing REPs.
Thereafter, TXU Energy may offer rates different from the price-to-beat rate,
but it must also continue to make the price-to-beat rate, adjusted for fuel
factor changes, available for residential and small commercial customers until
January 1, 2007. REPs must be certified by the Commission. TXU Energy has
received appropriate REP certifications from the Commission.
Also, beginning January 1, 2002, PGCs that are affiliated with T&D
utilities may charge unregulated prices in connection with ERCOT wholesale power
transactions. Estimated costs associated with PGC nuclear power plant
decommissioning obligations continue to be recovered as a nonbypassable T&D
charge over the life of the plant. Each affiliated PGC owning 400 megawatts or
more of installed generating capacity must offer each year at auction
entitlements to at least 15% of such capacity. The obligation of an affiliated
PGC to sell capacity entitlements at auction continues until the earlier of
January 1, 2007, or the date on which 40% of the electricity consumed by
residential and small commercial customers of the PGC's affiliated REP is
supplied by competing REPs. PGCs must be registered with the Commission. TXU
Energy has filed appropriate PGC registrations with the Commission.
The 1999 Restructuring Legislation also provided for the recovery of
generation-related regulatory assets (regulatory assets) and generation-related
and purchased power-related costs that are in excess of market value (stranded
costs). It provided a means for electric utilities to mitigate stranded costs
during the rate freeze period that preceded unbundling. Unmitigated stranded
costs would be finally determined in a 2004 "true-up" proceeding relying
principally upon market-based asset valuations. Regulatory assets and
unmitigated stranded costs can be recovered through the issuance of transition
(securitization) bonds or imposition of a competition transition charge.
Further, a REP would also be required to reconcile and credit to its
affiliated T&D utility (and the T&D utility to credit T&D customers), as a
so-called retail clawback, any positive difference between the price-to-beat
rate, reduced by the nonbypassable delivery charge, and the prevailing market
price of electricity during the same time period to the extent the price-to-beat
rate exceeded the market price of electricity. This reconciliation is not
required for the applicable customer class if 40% of the electricity consumed by
customers in that class is supplied by competing REPs before January 1, 2004. If
a retail clawback reconciliation is required, the 1999 Restructuring Legislation
provided that the amount credited cannot exceed an amount equal to the number of
residential or small commercial customers served by a T&D utility that are
buying electricity from the affiliated REP at the price-to-beat rate on January
1, 2004, minus the number of new customers obtained outside the historical
service territory, multiplied by $150. (The calculation of this credit was
altered for TXU Energy in connection with the settlement plan discussed below.)
Regulatory Settlement Plan -- On December 31, 2001, US Holdings filed a
settlement plan (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 (Settlement) provided for in the
Settlement Plan does not remove regulatory oversight of Oncor's business nor
does it eliminate TXU Energy's price-to-beat rates and related fuel adjustments.
The Settlement was approved by the Commission in June 2002. In August 2002, the
Commission issued a financing order, pursuant to the Settlement Plan,
authorizing the issuance of securitization bonds relating to recovery of
regulatory assets. The Commission's order approving the Settlement Plan and the
financing order were appealed by certain nonsettling parties to the Travis
County, Texas, District Court in August 2002. In January 2003, US Holdings
concluded a settlement of these appeals and they were dismissed. Thus the
Settlement became final.
The major elements of the Settlement are:
Excess Mitigation Credit and Appeal Related to T&D Rates -- In 2002,
Oncor began implementing an excess stranded cost mitigation credit in the amount
of $350 million, plus interest, applied over a two-year period as a reduction to
T&D rates charged to REPs. In June 2001, the Commission had issued an interim
A-72
order that addressed Oncor's charges for T&D service when retail competition
would begin. Among other things, that interim order, and subsequent final order
issued in October 2001, required Oncor to reduce rates over the period from
2002-2008. The Commission's decision was appealed by US Holdings to the Travis
County, Texas, District Court. Finalization of the Settlement means US Holdings'
appeal has been dismissed. Also, in July 2001, the staff of the Commission had
notified US Holdings and the Commission that it disagreed with US Holdings'
computation of the level of earnings in excess of the regulatory earnings cap
for calendar year 2000. In August 2001, the Commission issued an order adopting
the staff position. US Holdings appealed this matter to the Travis County,
Texas, District Court, which affirmed the Commission's order and US Holdings
then appealed that decision to the Third District Court of Appeals in Austin,
Texas. This appeal has now been dismissed.
Regulatory Asset Securitization -- In October 1999, US Holdings filed an
application with the Commission for a financing order to permit the issuance by
a special purpose entity of $1.65 billion of securitization bonds. In May 2000,
the Commission signed an order rejecting such request and authorized only $363
million of such bonds. US Holdings filed an appeal with the Travis County,
Texas, District Court and in September 2000, the Court issued a judgment that
reversed part of the Commission's order and affirmed other aspects of the
Commission's order. US Holdings and various other parties appealed this judgment
directly to the Supreme Court of Texas, and in June 2001, it issued a ruling; in
October 2001, it remanded the case to the Commission, which consolidated it into
the Settlement Plan proceeding. In accordance with the Settlement, Oncor
received a financing order authorizing it to issue securitization bonds in the
aggregate principal amount of $1.3 billion to recover regulatory assets and
other qualified costs. The Settlement provides that there can be an initial
issuance of securitization bonds in the amount of up to $500 million, followed
by a second issuance of the remainder after 2003. The Settlement resolves all
issues related to regulatory assets and liabilities.
Retail Clawback -- If, as currently expected, TXU Energy retains more than
60% of its historical residential and small commercial customers (representing
such customers of US Holdings and TXU SESCO Company as of January 1, 2002) after
the first two years of competition, the amount of the retail clawback credit
will be equal to the number of residential and small commercial customers
retained by TXU Energy in its historical service territory on January 1, 2004,
less the number of new customers TXU Energy has added outside of its historical
service territory as of January 1, 2004, multiplied by $90. This determination
will be made separately for the residential and small commercial classes. The
credit, if any, will be applied to T&D rates charged by Oncor to REPs, including
TXU Energy, over a two-year period beginning January 1, 2004. Under the
settlement agreement, TXU Energy will make a compliance filing with the
Commission reflecting customer count as of January 2004. In the fourth quarter
of 2002, TXU Energy recorded a $185 million ($120 million after-tax) charge for
the retail clawback, which represents the current best estimate of the amount to
be funded to Oncor over the two-year period.
Stranded Cost Resolution -- TXU Energy's stranded costs, not including
regulatory assets, are fixed at zero. Accordingly, it will not have to conduct
the stranded cost true-up in 2004 provided for in the 1999 Restructuring
Legislation. The Settlement also precludes recovery by US Holdings of certain
environmental improvement costs. In addition, the Settlement resulted in a
resolution of the regulatory disallowance of amounts related to US Holdings'
repurchase of minority owner interests in the Comanche Peak nuclear generating
station. The Commission's final order in connection with US Holdings' January
1990 rate increase request had been ultimately reviewed by the Supreme Court of
Texas, and an aggregate of $909 million of disallowances with respect to US
Holdings' reacquisitions of minority owners' interests in Comanche Peak, which
had previously been recorded as a charge to earnings, was remanded to the
District Court and then to the Commission for reconsideration. As a result of
the Settlement, this remand has been dismissed.
Fuel Cost Recovery -- The Settlement also provides that 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.
Provider of Last Resort -- Through calendar year 2002, TXU Energy was the
POLR for residential and small non-residential customers in those areas of ERCOT
where customer choice was available outside its historical service territory and
was the POLR for large non-residential customers in its historical service
territory. TXU Energy's POLR contract expired on December 31, 2002. However, in
August 2002, the Commission adopted new rules that significantly changed POLR
service. Under the new POLR rules, instead of being transferred to the POLR,
non-paying residential and small non-residential customers served by affiliated
REPs are subject to disconnection. Non-paying residential and small
non-residential customers served by non-affiliated REPs are transferred to the
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affiliated REP. Non-paying large non-residential 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 must decide whether all REPs should be permitted to
disconnect all non-paying customers. The new POLR rules are expected to result
in reduced bad debt expense beginning in 2003.
Open-Access Transmission -- At the state level, the Texas Public Utility
Regulatory Act, as amended, requires owners or operators of transmission
facilities to provide open access wholesale transmission services to third
parties at rates and terms that are non-discriminatory and comparable to the
rates and terms of the utility's own use of its system. The Commission has
adopted rules implementing the state open access requirements for utilities that
are subject to the Commission's jurisdiction over transmission services, such as
Oncor.
On January 3, 2002, the Supreme Court of Texas issued a mandate affirming
the judgment of the Court of Appeals that held that the pricing provisions of
the Commission's open access wholesale transmission rules, which had mandated
the use of a particular rate setting methodology, were invalid because they
exceeded the statutory authority of the Commission. On January 10, 2002, Reliant
Energy Incorporated and the City Public Service Board of San Antonio each filed
lawsuits in the Travis County, Texas, District Court against the Commission and
each of the entities to whom they had made payments for transmission service
under the invalidated pricing rules for the period January 1, 1997, through
August 31, 1999, seeking declaratory orders that, as a result of the application
of the invalid pricing rules, the defendants owe unspecified amounts. US
Holdings and TXU SESCO Company are named defendants in both suits. US Holdings
is unable to predict the outcome of any litigation related to this matter.
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.
15. COMMITMENTS AND CONTINGENCIES
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 generating units. US Holdings' 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.
Power Purchase Contracts -- US Holdings has entered into contracts to
purchase power through the year 2007 with certain wind power contracts for a
longer period. These contracts, except for the wind power contracts, provide for
capacity payments subject to performance standards and energy payments based on
the actual power taken under the contracts. Capacity payments paid under these
contracts for the years ended December 31, 2002, 2001 and 2000 were $296
million, $189 million and $186 million, respectively.
Assuming operating standards are achieved, future capacity payments under
existing agreements are estimated as follows:
2003.................................................... $315
2004.................................................... 163
2005.................................................... 146
2006.................................................... 117
2007.................................................... 17
Thereafter.............................................. -
---
Total capacity payments........................... $758
===
A-74
Gas Contracts -- US Holdings buys gas under various types of long-term and
short-term contracts and arranges for gas storage and transportation under
various contracts in order to assure reliable supply to, and to help meet the
expected needs of, its generation plants and its wholesale and retail customers.
Many of these gas purchase contracts require minimum purchases ("take-or-pay")
of gas under which the buyer agrees to pay for a minimum quantity of gas in a
year. At December 31, 2002, US Holdings had minimal commitments under long-term
gas purchase contracts. At December 31, 2002, US Holdings had commitments for
pipeline transportation and storage reservation fees as shown in the table
below:
2003..................................................... $14
2004..................................................... 6
2005..................................................... 6
2006..................................................... 6
2007..................................................... 4
Thereafter............................................... 6
--
Total pipeline transportation and storage reservation
fees............................................... $42
===
On the basis of US Holdings' current expectations of demand from its
electricity and gas customers as compared with its capacity payments or
take-or-pay obligations under such purchase contracts, management does not
consider it likely that any material payments will become due from US Holdings
for electricity or gas not taken.
Coal Contracts -- US Holdings has coal purchase agreements and coal
transportation agreements. Commitments under these contracts for the next five
years and thereafter are as follows:
2003.................................................... $94
2004.................................................... 79
2005.................................................... 23
2006.................................................... 18
---
Total ............................................. $214
====
Leases -- US Holdings has entered into operating leases covering various
facilities and properties including generating plants, combustion turbines,
transportation, 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 for 2002, 2001 and 2000
were $152 million, $132 million, and $107 million, respectively (including
amounts paid by TXU Corp. and charged to US Holdings).
Future minimum lease payments under capital leases, together with the
present value of such minimum lease payments, and future minimum lease
commitments under operating leases that have initial or remaining noncancellable
lease terms in excess of one year as of December 31, 2002, were as follows:
Capital Operating
Year Leases Leases
- --- -------- --------
2003................................................... $ 1 $ 69
2004................................................... 1 70
2005................................................... 2 75
2006................................................... 2 70
2007................................................... 2 73
Thereafter............................................. 6 535
--- ----
Total future minimum lease payments................... 14 $892
====
Less amounts representing interest..................... 4
---
Present value of future minimum lease payments......... 10
Less current portion................................... 1
---
Long-term capital lease obligation..................... $ 9
===
A-75
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 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, 2002, the balance of the indebtedness
was $140 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, 2002, the aggregate maximum amount of
residual values guaranteed was approximately $275 million with an estimated
residual recovery of approximately $211 million. The average life of the lease
portfolio is approximately nine years.
Shared saving guarantees -- US Holdings has guaranteed that certain
customers will realize specified annual savings resulting from energy management
services it has provided. In aggregate, the average annual savings has exceeded
the annual savings guaranteed. The maximum potential annual payout is
approximately $4 million and the maximum total potential payout is approximately
$19 million. The average remaining life of the portfolio is approximately five
years.
Standby letters of credit -- US Holdings has entered into various
agreements that require letters of credit for financial assurance purposes.
Approximately $523 million of letters of credit are outstanding to support
existing floating rate pollution control revenue bond financings on existing
debt of approximately $433 million. The letters of credit are available to fund
the payment of such debt obligations. These letters of credit have expiration
dates in 2003; however, US Holdings intends to provide from either existing or
new facilities for the extension, renewal or substitution of these letters of
credit to the extent required for such floating rate debt or their remarketing
as fixed rate debt.
US Holdings has provided for the posting of letters of credit in the
amount of $183 million to support portfolio management margin requirements in
the normal course of business. As of December 31, 2002, approximately 82% of
the obligations supported by these letters of credit mature within one year,
and substantially all of the remainder mature in the second year.
US Holdings has entered into contracts with public agencies to purchase
cooling water for use in the generation of electric energy and has agreed, in
effect, to guarantee the principal, $16 million at December 31, 2002, 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 5-1/2% 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 of $4 million annually
for 2003, $7 million for 2004 and $1 million for 2005 and 2006. Annual payments
made by US Holdings, net of amounts assumed by a third party under such
contracts, were $4 million for each of the last three years. 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 of US Holdings in connection with $19 million remaining
principal amount of bonds at December 31, 2002, issued for similar purposes,
which had previously been guaranteed by US Holdings. US Holdings is, however,
contingently liable in the unlikely event of default by the municipality.
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 $9.6 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 US Holdings is unable, at this time, to determine
any impact it may have on nuclear liability coverage. As required, US Holdings
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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, US Holdings 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 $88 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,
Nuclear Regulatory Commission (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. US Holdings maintains nuclear
decontamination and property damage insurance for Comanche Peak in the amount of
$3.5 billion, above which US Holdings 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 $737 million from Lloyds of London,
other insurance markets and foreign nuclear insurance pools. US Holdings is
subject to a maximum annual assessment from NEIL of $26.6 million.
US Holdings 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,
US Holdings is subject to a maximum annual assessment of $8.7 million.
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 reinsurance or 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 -- Under current regulatory licenses,
decommissioning activities are projected to begin in 2030 for Comanche Peak Unit
1 and 2033 for Unit 2 and common facilities. Through December 31, 2001,
decommissioning costs were recovered from consumers based upon a 1992
site-specific study through rates placed in effect under US Holdings' January
1993 rate increase request. Effective January 1, 2002, decommissioning costs
will be recovered through a non-bypassable charge to REPs by Oncor based upon a
1997 site-specific study, adjusted for trust fund assets, through rates placed
in effect under US Holdings' 2001 Unbundled Cost of Service filing. US Holdings
accrued $14 million of decommissioning costs for 2002 and $18 million for each
of the years ended December 31, 2001 and 2000. Amounts recovered through
regulated rates are deposited in external trust funds (see Note 4).
A-77
See Note 2 (under "Changes in Accounting Standards") for a discussion of
the impact of SFAS No. 143 on accounting for nuclear decommissioning costs.
Legal Proceedings -- In September 1999, Quinque Operating Company
(Quinque) filed suit in the State District Court of Stevens County, Kansas
against over 200 gas pipeline companies, including TXU Gas (named in the
litigation as ENSERCH Corporation). The suit was removed to federal court;
however, a motion to remand the case back to Kansas State District Court was
granted in January 2001, and the case is now pending in Stevens County, Kansas.
The plaintiffs amended their petition to join TXU Fuel Company (TXU Fuel), a
subsidiary of TXU Energy, as a defendant in this litigation. Quinque has
dismissed its claims and a new lead plaintiff has filed an amended petition in
which the plaintiffs seek to represent a class consisting of all similarly
situated gas producers, overriding royalty owners, working interest owners and
state taxing authorities either from whom defendants had purchased natural gas
or who received economic benefit from the sale of such gas since January 1,
1974. No class has been certified. The petition alleges that the defendants have
mismeasured both the volume and heat content of natural gas delivered into their
pipelines resulting in underpayments to plaintiffs. No amount of damages has
been specified in the petition with respect to TXU Gas or TXU Fuel. While TXU
Gas and TXU Fuel are unable to estimate any possible loss or predict the outcome
of this case, TXU Gas and TXU Fuel believe these claims are without merit and
intend to vigorously defend this suit.
On November 21, 2000, the City of Denton, Texas and other Texas cities
filed suit in the 134th Judicial District Court of Dallas County, Texas against
TXU Gas, US Holdings and TXU Corp. The petition alleges claims for breach of
contract, negligent representation, fraudulent inducement of contract, breach of
duty of good faith and fair dealing and unjust enrichment related to the
defendants' alleged exclusion of certain revenues from the cities' franchise fee
base. No specified damages have been alleged. All of the plaintiff cities have
now executed a settlement agreement to settle this suit. Such resolution will
not have a material effect on US Holdings' financial position, results of
operations or cash flows.
Also see discussion in Note 14 under "Open-Access Transmission."
US Holdings is involved in various legal and administrative proceedings
the ultimate resolution of which should not have a material effect upon its
financial position, results of operations or cash flows.
16. SEGMENT INFORMATION
Concurrent with TXU Corp.'s reorganization as of January 1, 2002, US
Holdings realigned its operations into two reportable business segments: Energy
and Electric Delivery.
Energy - operations, principally in the competitive Texas market,
involving the generation and wholesale sales of electricity, retail energy sales
and services and portfolio management, including risk management and certain
trading activities.
Electric Delivery - regulated operations in Texas involving the
transmission and distribution of electricity.
The prior year financial information for the Energy segment and the
Electric Delivery segment 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 T&D operations. Allocation of revenues reflected consideration of return on
invested capital, which continues to be regulated for the T&D 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 common expenses, assets and liabilities between US Holdings'
generation and T&D operations. Interest and other financing costs were
determined based upon debt allocated. Allocations reflected in the financial
information for 2001 and 2000 did not necessarily result in amounts reported in
individual line items that are comparable to actual results in 2002. 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.
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Effective January 1, 2002, TXU Energy incurs electricity delivery fees
charged by Oncor and other T&D utilities, which TXU Energy includes in billings
to its large C&I customers. For residential and small business customers, the
price-to-beat rates include a delivery component, but such billed amounts are
not necessarily equivalent to delivery fees incurred by TXU Energy. These fees
are reflected in TXU Energy's revenues and cost of energy for the year ended
December 31, 2002. Electricity delivery fees have been included in the Energy
segment's revenues and cost of energy for the year ended December 31, 2001 and
2000. The Energy segment's gross margin is not affected by the inclusion of
these electricity delivery fees.
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
loss. US Holdings accounts for intersegment sales and transfers as if the sales
or transfers were to third parties, that is, at current market prices.
The business segments provide services or sell products to each other.
Generally, 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.
A-79
Electric
Energy Delivery Eliminations Consolidated
----- ------- ------------ ------------
Operating Revenues
2002................. $7,738 $1,994 $(1,592) $8,140
2001................. 7,458 2,314 (1,752) 8,020
2000................. 7,449 2,081 (1,909) 7,621
Regulated Revenues - Included in
Operating Revenues
2002................. - 1,994 (1,592) 402
2001................. 7,044 2,314 (1,752) 7,606
2000................. 7,287 2,081 (1,909) 7,459
Affiliated Revenues - Included in
Operating Revenues
2002................. 6 1,586 (1,592) -
2001................. - 1,752 (1,752) -
2000................. - 1,909 (1,909) -
Depreciation and Amortization -
Including Goodwill Amortization
2002................. 438 264 - 702
2001................. 411 239 - 650
2000................. 404 232 - 636
Equity in Earnings (Losses) of
Unconsolidated Subsidiaries
2002................. (2) - - (2)
2001................. (4) - - (4)
2000................. - - - -
Interest Income
2002................. 29 49 (72) 6
2001................. 71 - (32) 39
2000................. 52 1 (46) 7
Interest Expense and Other Charges
2002................. 248 265 (72) 441
2001................. 237 267 (32) 472
2000................. 270 260 (46) 484
Income Tax Expense
2002................. 79 117 - 196
2001................. 277 119 - 396
2000................. 218 120 - 338
Income Before Extraordinary Loss
2002................. 250 245 - 495
2001................. 643 228 - 871
2000................. 561 226 - 787
Investment in Equity Investees
2002................. 3 - - 3
2001................. 7 - - 7
2000................. 20 - - 20
Total Assets
2002................. 16,401 9,031 (913) 24,519
2001................. 17,957 10,780 (6,899) 21,838
2000................. 18,514 8,875 (4,378) 23,011
Capital Expenditures
2002................. 274 513 - 787
2001................. 330 635 - 965
2000................. 264 517 - 781
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17. SUPPLEMENTARY FINANCIAL INFORMATION
Regulated Versus Unregulated Operations --
Year Ended December 31,
---------------------------
2002 2001 2000
---- ---- ----
Operating revenues
Regulated....................................................... $ 1,994 $9,358 $ 9,368
Unregulated..................................................... 7,738 414 162
Intercompany sales eliminations-regulated....................... (1,592) (1,752) (1,909)
------ ------ -------
Total operating revenues................................... 8,140 8,020 7,621
------ ------ -------
Costs and operating expenses
Cost of energy sold and delivery fees - regulated*.............. - 3,013 3,079
Cost of energy sold and delivery fees - unregulated*............ 3,214 38 113
Operating costs - regulated..................................... 676 1,229 1,206
Operating costs - unregulated................................... 744 71 18
Depreciation and amortization, other than goodwill-regulated.... 264 629 618
Depreciation and amortization, other than goodwill-unregulated.. 438 6 3
Selling, general and administrative expenses - regulated........ 213 483 413
Selling, general and administrative expenses - unregulated...... 842 283 191
Franchise and revenue-based taxes - regulated................... 272 441 344
Franchise and revenue-based taxes - unregulated................. 139 1 -
Goodwill amortization - regulated............................... - 15 15
Goodwill amortization - unregulated............................. - - -
Other income.................................................... (38) (12) (40)
Other deductions................................................ 250 123 59
Interest income................................................. (6) (39) (7)
Interest expense and other charges.............................. 441 472 484
----- ------ ------
Total costs and expenses................................... 7,449 6,753 6,496
----- ------ ------
Income before income taxes and extraordinary loss .................. $ 691 $1,267 $1,125
===== ====== ======
*Includes cost of fuel consumed of $1,486 million (unregulated) in 2002
and $1,900 million and $2,341 million (both largely regulated) in 2001 and 2000,
respectively. 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 and small business customers continues to be subject to certain
price controls as discussed in Note 14.
Other Income and Deductions --
Year Ended December 31,
-----------------------------
2002 2001 2000
------- ------- -------
Other income
Gain on sale of properties.......................... $ 32 $ 2 $ 30
Other............................................... 6 10 10
------- ------- -------
Total other income............................. $ 38 $ 12 $ 40
======= ======= =======
Other deductions
Loss on sale of properties.......................... $ 2 $ 8 $ 1
Equity in losses of unconsolidated entities......... 3 4 -
Asset impairment.................................... 237 - -
Regulatory asset write-offs......................... - 95 52
Other............................................... 8 16 6
------- ------- -------
Total other deductions......................... $ 250 $ 123 $ 59
======= ======= =======
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.
A-81
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 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.
Concentration of Credit Risk -- US Holdings' gross exposure to credit risk
as of December 31, 2002 was $3.2 billion, representing trade accounts
receivable, commodity contract assets and derivative assets.
A large share of gross assets subject to credit risk represents accounts
receivable from the retail sale of electricity to residential and small
commercial customers. The risk of material loss from non-performance from these
customers is unlikely based upon historical experience. Reserves for
uncollectible accounts receivable are established for the potential loss from
non-payment by these customers based on historical experience and market or
operational conditions. The restructuring of the electric industry in Texas
effective January 1, 2002, increases the risk profile of US Holdings in relation
to these customers; however, US Holdings has the ability to take actions to
mitigate such customer risk, particularly with the changes in the POLR rules
(see Note 14). 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 C&I
customers. US Holdings' wholesale commodity contract counterparties include
major energy companies, financial institutions, gas and electric utilities,
independent power producers, oil and gas producers and energy trading companies.
The exposure to credit risk from these customers and counterparties, excluding
credit collateral, as of December 31, 2002, is $1.3 billion, net of standardized
master netting contracts and agreements which provide the right of offset of
positive and negative credit exposures with individual customers and
counterparties. When considering collateral currently held by US Holdings (cash,
letters of credit and other security interests), the net credit exposure is $1.2
billion.
US Holdings had no exposure to any one customer or counterparty greater
than 10% of the net exposure of $1.2 billion at December 31, 2002. Additionally,
approximately 93% of the credit exposure, net of collateral held, has a maturity
date of less than 2 years. 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.
Regulatory Assets and Liabilities --
December 31,
-------------------
2002 2001
---- ----
Regulatory Assets
Generation-related regulatory assets subject to securitization.............. $1,652 $1,841
Securities reacquisition costs.............................................. 124 117
Recoverable deferred income taxes-- net..................................... 76 74
Other regulatory assets..................................................... 46 36
------ ------
Total regulatory assets................................................. 1,898 2,068
------ ------
Regulatory Liabilities
Liability to be applied to stranded generation assets....................... 170 355
ITC and protected excess deferred taxes..................................... 98 106
------ ------
Total regulatory liabilities............................................ 268 461
------ ------
Net regulatory assets................................................... $1,630 $1,607
====== ======
Included in net regulatory assets are assets of $1.8 billion at December
31, 2002, and $1.9 billion at December 31, 2001, that were not earning a return.
Of the assets not earning a return, $1.7 billion is expected to be recovered
over the term of the securitization bonds pursuant to the Settlement Plan
approved by the Commission. (See Note 14 for further discussion of the
Settlement Plan.) The remaining regulatory assets have a remaining recovery
period of 14 to 31 years.
A-82
Restricted Cash -- At December 31, 2002, approximately $210 million of the
net proceeds from Oncor's issuance of senior secured notes on December 20, 2002
was deposited in a trust to be used to pay interest and redeem First Mortgage
Bonds of Oncor due in March and April 2003, and is reported in investments on
the balance sheet. Other restricted cash included $68 million as collateral for
letters of credit issued.
Related Party Transactions -- The following represent significant
affiliate transactions of US Holdings:
Average daily short-term advances from affiliates during 2002 were $821
million, and interest expense incurred on the advances was $25 million. The
average interest rate for 2002 was 2.3%.
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 2002, 2001 and 2000, these costs totaled $428 million,
$435 million and $309 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 2002, 2001 and 2000 these charges
totaled $57 million, $43 million and $72 million, respectively, and are largely
reported as a reduction in operation and maintenance expenses.
Accounts Receivable -- At December 31, 2002 and 2001, accounts receivable
of $1.4 billion and $940 million are stated net of allowance for uncollectible
accounts of $72 million and $28 million, respectively. During 2002, bad debt
expense was $163 million, account write-offs were $104 million and other
activity decreased the allowance for uncollectible accounts by $15 million.
Accounts receivable included $505 million and $338 million of unbilled
revenues at December 31, 2002 and 2001, respectively.
Commodity Contracts -- At December 31, 2002 and 2001, current and
noncurrent commodity contract assets totaling $1.8 billion and $1.2 billion are
stated net of applicable credit (collection) and performance reserves totaling
$43 million and $25 million, respectively. Performance reserves are provided for
direct, incremental costs to settle the contracts.
Inventories by Major Category --
December 31,
----------------
2002 2001
---- ----
Materials and supplies............................ $211 $ 186
Fuel stock........................................ 70 62
Gas stored underground............................ 57 49
---- ----
Total inventories.............................. $338 $ 297
==== =====
Inventories are carried at average costs, except for gas inventories
managed as part of portfolio management activities, which are carried at spot
rates through December 31, 2002. Inventories recorded at spot rates at December
31, 2002 and 2001 were $54 million and $18 million, respectively. As part of the
rescission of EITF Issue No. 98-10, such inventories will be adjusted to average
costs as part of the cumulative adjustment to be recorded in the first quarter
of 2003.
A-83
Property, Plant and Equipment --
December 31,
--------------------
2002 2001
---- ----
In service
Production............................................................. $15,675 $ 15,791
Transmission........................................................... 2,176 1,979
Distribution........................................................... 6,376 6,110
Other assets........................................................... 917 672
------- -------
Total............................................................... 25,144 24,552
Less accumulated depreciation.......................................... 9,493 9,074
------- -------
Net of accumulated depreciation..................................... 15,651 15,478
Construction work in progress............................................. 373 510
Nuclear fuel (net of accumulated amortization of $847 and $787)........... 137 146
Held for future use....................................................... 22 22
------- -------
Net property, plant and equipment................................... $16,183 $16,156
======= =======
As of December 31, 2002, substantially all of Oncor's electric utility
property and equipment (with a net book value of $6.1 billion) is pledged as
collateral on Oncor's first mortgage bonds and senior secured notes.
Interest Expense and Other Charges --
Year Ended December 31,
-------------------------------
2002 2001 2000
---- ---- ----
Interest...................................................... $ 435 $ 411 $ 404
Distributions on trust securities.............................. - 61 69
Amortization of deferred debt costs............................ 17 21 20
Allowance for borrowed funds used during construction
and capitalized interest.................................... (11) (21) (9)
------ ------ ------
Total interest expense and other related charges.... $ 441 $ 472 $ 484
====== ====== ======
Supplemental Cash Flow Information --
Year Ended December 31,
-----------------------------
2002 2001 2000
---- ---- ----
Cash payments (receipts):
Interest (net of amounts capitalized)....................... $401 $482 $467
Income taxes................................................ $127 $396 $148
Non-cash investing and financing activities:
Note receivable from sale of assets......................... $ - $ - $ 23
Discount related to exchangeable subordinated notes recorded
to paid-in-capital.................................... $266 $ - $ -
A-84
Quarterly Information (unaudited) -- The results of operations by quarter
are summarized below and reflect the effect of EITF Issue No. 02-3 to report
certain trading activities on a net basis. Net income was not affected by the
accounting rule change as the decrease in revenues was offset in cost of energy
sold. 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
-------- ------- -------- -------
2002:
Operating revenues .............................................. $ 1,877 $ 2,119 $ 2,536 $ 1,608
Income (loss) before extraordinary loss ........................ $ 253 $ 244 $ 320 $ (322)
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)
2001:
Operating revenues .............................................. $ 1,887 $ 2,017 $ 2,398 $ 1,718
Income before extraordinary loss ................................ $ 148 $ 221 $ 381 $ 121
Extraordinary loss, net of tax effect............................ $ - $ - $ - $ (154)
Net income (loss) before preferred stock dividends............... $ 148 $ 221 $ 381 $ (33)
Net income (loss) available for common stock .................... $ 146 $ 218 $ 379 $ (36)
A-85
Also 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 2 and 14.
Reconciliation of Previously Reported Quarterly Information -- The
following table presents the changes to previously reported quarterly amounts to
report certain trading activities on a net basis (see Note 2). Net income was
not affected by this change.
Quarter Ended
--------------------
March 31 June 30
-------- -------
Increase (Decrease)
from Previously Reported
2002:
Operating revenues as previously reported................. $ 3,580 $ 3,643
Cost of energy sold and delivery fees netted with revenues (1,703) (1,524)
-------- --------
Operating revenues after reclassification ................ $ 1,877 $ 2,119
======== ========
2001:
Operating revenues as previously reported................. $ 4,120 $ 3,057
Cost of energy sold and delivery fees netted with revenues (2,233) (1,040)
-------- --------
Operating revenues after reclassification ................ $ 1,887 $ 2,017
======== ========
18. SUBSEQUENT EVENTS
In early 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 of $250 million is due March 15, 2008, and bears
interest at the annual rate of 6.125%, and the other series of $1 billion is due
March 15, 2013, and bears interest at the annual rate of 7%. In late March 2003,
cash borrowings under US Holdings' credit facilities totaling $1.24 billion
were repaid.
A-86
TXU US HOLDINGS EXHIBITS FOR 2002 FORM 10-K
APPENDIX B
Previously Filed*
-----------------
With File As
Exhibits Number Exhibit
-------- -------- -------
2 1-12833 2 -- Master Separation Agreement by and among Oncor, TXU
Form 8-K Generation Holdings Company LLC, TXU Merger Energy Trading
(filed January 16, Company LP, TXU SESCO Company, TXU SESCO Energy Services
2002) Company, TXU Energy Retail Company LP and TXU US Holdings,
dated as of December 14, 2001.
3(a) 0-11442 4(a) Restated Articles of Incorporation of TXU Electric Company
Form 10-Q (Quarter (now TXU US Holdings)
ended June 30, 1997
3(b) 0-11442 3(a) -- Articles of Amendment, effective January 1, 2002 to the
Form 10-K Articles of Incorporation of TXU US Holdings.
(2001)
3(c) 0-11442 -- By-laws of TXU US Holdings, as restated August 1, 1999.
Form 10-Q
(Quarter ended
June 30, 1999)
4(a) 2-90185 4(a) -- Mortgage and Deed of Trust, dated as of December 1, 1983,
between Oncor and Irving Trust Company (now The Bank of New
York), Trustee.
4(a)(1) -- Supplemental Indentures to Mortgage and Deed of Trust:
Number Date
----- ----
2-90185 4(b) First April 1, 1984
33-24089 4(a)-1 Fifteenth July 1, 1987
33-30141 4(a)-3 Twenty-second January 1, 1989
33-35614 4(a)-3 Twenty-fifth December 1, 1989
33-39493 4(a)-2 Twenty-eighth October 1, 1990
33-49710 4(a)-1 Thirty-fourth April 1, 1992
33-57576 4(a)-3 Fortieth November 1, 1992
33-60528 4(a)-1 Forty-second March 1, 1993
33-64692 4(a)-2 Forty-fourth April 1, 1993
33-68100 4(a)-1 Forty-sixth July 1, 1993
33-68100 4(a)-3 Forty-seventh October 1, 1993
1-12833 4(2)(1) Sixty-third January 1, 2002
Form 10-K
(2001)
1-12833 4 Sixty-fourth May 1, 2002
Form 10-Q
(Quarter ended
March 31, 2002)
333-100240 4(f)(2) Sixty-fifth December 1, 2002
B-1
Previously Filed*
-----------------
With File As
Exhibits Number Exhibit
-------- -------- -------
4(b) -- Agreement to furnish certain debt instruments.
4(c) 33-68104 4(b)-17 -- Deposit Agreement between TXU US Holdings and Chemical Bank,
dated as of August 4, 1993.
4(d) 0-11442 4(e) -- Deposit Agreement between TXU US Holdings and Chemical Bank,
Form 10-K dated as of October 14, 1993.
(1993)
4(e) 0-11442 4(a) -- Indenture (For Unsecured Debt Securities), dated as of
Form 10-K August 1, 1997, between TXU US Holdings and The Bank of New
(Quarter ended York.
Sept. 30, 1997)
4(f) 0-11442 4(b) -- Officers' Certificate establishing TXU US Holdings 7.17%
Form 10-K Debentures due August 1, 2007.
(Quarter ended
Sept. 30, 1997)
4(g) 1-12833 4(a) -- TXU Energy's 9% Exchangeable Subordinated Notes due 2012,
Form 8-K (filed dated as of November 22, 2002.
November 25, 2002)
4(h) 1-12833 10(a) -- Exchange Agreement, dated as of November 22, 2002, among TXU
Form 8-K (filed Corp., TXU Energy and UXT Holdings LLC and UXT Intermediary
November 25, 2002) LLC.
4(i) 1-12833 10(c) -- Registration Rights Agreement, dated as of November 22,
Form 8-K (filed 2002, among TXU Corp. and UXT Holdings LLC and UXT
November 25, 2002) Intermediary LLC.
4(j) 1-12833 4(uu) -- Amendment to Registration Rights Agreement, dated
Form 10-K as of December 19, 2002, among TXU Corp. and UXT
(2002) Holdings LLC and UXT Intermediary LLC.
4(k) 1-12833 4(vv) -- Indenture and Deed of Trust, dated as of May 1, 2002,
Form 8-K (filed between Oncor and The Bank of New York, as Trustee.
November 25, 2002)
4(l) 333-100240 4(c) -- Officer's Certificate, dated May 6, 2002, establishing the
forms of the Oncor Senior Secured Notes of the 6.375% Series
due 2012 and the 7.000% Series due 2032.
4(m) 333-100240 4(c) -- Officer's Certificate, dated December 20, 2002, establishing
(Pre-Effective the forms of the Oncor Senior Secured Notes of the 6.375%
Amendment No. 1) Series due 2015 and the 7.250% Series due 2033.
4(n) 333-100242 4(a) -- Indenture (for Unsecured Debt Securities), dated as of
August 1, 2002, between Oncor and The Bank of New York, as
trustee.
4(o) 333-100242 4(b) -- Officer's Certificate, dated as of August 30, 2002,
establishing the forms of Oncor's 5% Debentures due 2007 and
7% Debentures due 2022.
B-2
Previously Filed*
-----------------
With File As
Exhibits Number Exhibit
-------- -------- -------
10(a) 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 TXU US Holdings, Chase Manhattan Bank of Texas,
31, 2002) National Association, as Administrative Agent, and certain
banks listed therein and The Chase Manhattan Bank, as
Competitive Advance Facility Agent.
10(b) 1-12833 10(b) -- $1,400,000,000 Five-Year Third Amended and Restated
Form 10-Q Competitive Advance and Revolving Facility Agreement, dated
(Quarter ended as of July 31, 2002, among TXU Holdings Company, JP Morgan
June 30, 2002) Chase Bank, as Administrative Agent and Competitive Advance
Facility Agent, J.P. Morgan Securities, Inc., Bank of
America, N.A. and Citibank, N.A.
10(c) 333-100240 10(c) -- Credit Agreement, dated December 20, 2002, among Oncor and
certain banks listed therein, and Credit Suisse First
Boston, as Administrative Agent.
10(d) 333-100240 10(c) -- Generation Interconnection Agreement, dated December 14,
2001, between Oncor and TXU Generation Company LP.
10(e) 333-100240 10(d) -- Generation Interconnection Agreement, dated December 14,
2001, between Oncor and TXU Generation Company LP, for
itself and as Agent for TXU Big Brown Company LP, TXU
Mountain Creek Company LP, TXU Handley Company LP, TXU
Tradinghouse Company LP and TXU DeCordova Company LP
(Interconnection Agreement).
10(f) 333-100240 10(e) -- Amendment to Interconnection Agreement, dated May 31, 2002.
10(g) 333-100240 10(f) -- Standard Form Agreement between Oncor and Competitive
Retailer Regarding Terms and Conditions of Delivery of
Electric Power and Energy.
10(h) 1-12833 10(w) -- Stipulation and Joint Application for Approval of Settlement
Form 10-K as approved by the PUC in Docket Nos. 21527 and 24892.
(Year ended
December 31, 2002)
12 -- Computation of Ratio of Earnings to Fixed Charges and to Fixed
Charges and Preferred Dividends for TXU US Holdings.
21 -- Subsidiaries of TXU US Holdings.
23 -- Consent of Deloitte & Touche LLP, Independent Auditors' for
TXU US Holdings.
99(a) 33-55408 99(a) -- Agreement, dated as of July 5, 1988, between TXU US Holdings
and Tex-La Electric Cooperative of Texas, Inc.
99(b) 33-23532 4(c)(i) -- Trust Indenture, Security Agreement and Mortgage, dated as
of December 1, 1987, as supplemented by Supplement No. 1
thereto dated as of May 1, 1988 among the Lessor, TXU US
Holdings and the Trustee.
99(c) 33-24089 4(c)-1 -- Supplement No. 2 to Trust Indenture, Security Agreement and
Mortgage, dated as of August 1, 1988.
B-3
Previously Filed*
-----------------
With File As
Exhibits Number Exhibit
-------- -------- -------
99(d) 33-24089 4(c)-1 -- Supplement No. 3 to Trust Indenture, Security Agreement and
Mortgage, dated as of August 1, 1988.
99(e) 0-11442 99(c) -- Supplement No. 4 to Trust Indenture, Security Agreement and
Form 10-Q Mortgage, including form of Secured Facility Bond, 1993
(Quarter ended Series.
June 30, 1993)
99(f) 33-23532 4(d) -- Lease Agreement, dated as of December 1, 1987 between the
Lessor and TXU US Holdings as supplemented by supplemented
by Supplement No. 1 thereto dated as of May 20, 1988 between
the Lessor and TXU US Holdings.
99(g) 33-24089 4(f) -- Lease Agreement Supplement No. 2, dated as of August 18,
1988.
99(h) 33-24089 4(f)-1 -- Lease Agreement Supplement No. 3, dated as of August 25,
1988.
99(i) 33-63434 4(d)(iv) -- Lease Agreement Supplement No. 4, dated as of December 1,
1988.
99(j) 33-63434 4(d)(v) -- Lease Agreement Supplement No. 5, dated as of June 1, 1989.
99(k) 0-11442 99(d) -- Lease Agreement Supplement No. 6, dated as of July 1, 1993.
Form 10-Q
(Quarter ended
June 30, 1993)
99(l) 33-23532 4(e) -- Participation Agreement dated as of December 1, 1987, as
amended by a Consent to Amendment of the Participation
Agreement, dated as of May 20, 1988, each among the Lessor,
the Trustee, the Owner Participant, certain banking
institutions, Capcorp, Inc. and TXU US Holdings.
99(m) 33-24089 4(g) -- Consent to Amendment of the Participation Agreement, dated
as of August 18, 1988.
99(n) 33-24089 4(g)-1 -- Supplement No. 1 to the Participation Agreement, dated as of
August 18, 1988.
99(o) 33-24089 4(g)-2 -- Supplement No. 2 to the Participation Agreement, dated as of
August 18, 1988.
99(p) 33-63434 4(e)(v) -- Supplement No. 3 to the Participation Agreement, dated as of
December 1, 1988.
99(q) 0-11442 99(e) -- Supplement No. 4 to the Participation Agreement, dated as of
Form 10-Q June 17, 1993.
(Quarter ended
June 30, 1993)
99(r) 0-11442 4(b) -- Supplement No. 1, dated October 25, 1995, to Trust
Form 10-Q Indenture, Security Agreement and Mortgage, dated as of
(Quarter ended December 1, 1989, among the Owner Trustee, TXU US Holdings
March 31, 1996) and the Indenture Trustee.
B-4
Previously Filed*
-----------------
With File As
Exhibits Number Exhibit
-------- -------- -------
99(s) 0-11442 4(c) -- Supplement No. 1, dated October 19, 1995, to Amended and
Form 10-Q Restated Participation Agreement, dated as of November 28,
(Quarter ended 1989, among the Owner Trustee, The First National Bank of
March 31, 1996) Chicago, As Original Indenture Trustee, the Indenture
Trustee, the Owner Participant, Mesquite Power Corporation
and TXU US Holdings.
99(t) -- Chief Executive Officer Certification
99(u) -- Chief Financial Officer Certification
* Incorporated herein by reference.
B-5