RELIANT RESOURCES INC - 10-Q Quarterly Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q

(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934.

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934.

For the transition period from ______________ to _______________

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Commission file number 1-16455

RELIANT RESOURCES, INC.
(Exact Name of Registrant as Specified in its Charter)

Delaware 76-0655566
(State or other jurisdiction of incorporation or (I.R.S. Employer Identification No.)
organization)

1111 Louisiana
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)

(713) 497-3000
(Registrant's Telephone Number, Including Area Code)

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Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 125-2 of the Exchange Act). Yes [X] No [ ].

As of August 11, 2003, Reliant Resources, Inc. had 294,337,364 shares of common
stock outstanding, excluding 5,466,636 shares held by the Registrant as treasury
stock.

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RELIANT RESOURCES, INC. AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Statements of Operations (unaudited)
Three and Six Months Ended June 30, 2002 (as restated) and 2003.........................................1

Consolidated Balance Sheets (unaudited)
December 31, 2002 and June 30, 2003 ....................................................................2

Consolidated Statements of Cash Flows (unaudited)
Six Months Ended June 30, 2002 (as restated) and 2003...................................................3

Notes to Unaudited Consolidated Interim Financial Statements............................................4

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations..................56

Item 3. Quantitative and Qualitative Disclosures About Market Risk.............................................88

Item 4. Controls and Procedures................................................................................91

PART II. OTHER INFORMATION

Item 1. Legal Proceedings......................................................................................92

Item 2. Changes in Securities and Use of Proceeds..............................................................92

Item 6. Exhibits, Financial Statement Schedules and Reports on Form 8-K........................................92

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Form 10-Q includes statements concerning expectations, assumptions,
beliefs, plans, projections, objectives, goals, strategies and future events or
performance that are intended as "forward-looking statements." You can identify
our forward-looking statements by the words "anticipates," "believes,"
"continue," "could," "estimates," "expects," "forecasts," "goal," "intends,"
"may," "objective," "plans," "potential," "predicts," "projection," "should,"
"will" and similar words.

We have based our forward-looking statements on management's beliefs and
assumptions based on information available at the time the statements are made.
We caution you that assumptions, beliefs, expectations, intentions and
projections about future events and performance may and often do vary materially
from actual results. Therefore, actual results may differ materially from those
expressed or implied by our forward-looking statements. For more information
regarding the risks and uncertainties that could cause our actual results to
differ materially from those expressed or implied in our forward-looking
statements, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in Item 2 of this Form 10-Q, "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Risk Factors" in
Item 7 of our Form 10-K/A filed on May 1, 2003 and "Management's Discussion and
Analysis of Financial Condition and Results of Operations" for the three months
ended March 31, 2002 and 2003 in our Current Report on Form 8-K filed on July
23, 2003.

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PART I.
FINANCIAL INFORMATION

RELIANT RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)

See Notes to our Unaudited Consolidated Interim Financial Statements

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RELIANT RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
(UNAUDITED)

See Notes to our Unaudited Consolidated Interim Financial Statements

2

RELIANT RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)

See Notes to our Unaudited Consolidated Interim Financial Statements

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

(1) BACKGROUND AND BASIS OF PRESENTATION

In this Quarterly Report on Form 10-Q (Form 10-Q), "Reliant Resources"
refers to Reliant Resources, Inc. (Reliant Resources), and "we", "us" and "our"
refer to Reliant Resources, Inc. and its subsidiaries, unless we specify or the
context indicates otherwise. Included in this Form 10-Q are our interim
consolidated financial statements and notes (interim financial statements). The
interim financial statements are unaudited, omit certain financial statement
disclosures and should be read in conjunction with our consolidated financial
statements and notes in our Current Report on Form 8-K filed on June 30, 2003
(Form 8-K).

Reliant Energy, Incorporated (Reliant Energy) adopted a business separation
plan in response to the Texas Electric Choice Plan (Texas electric restructuring
law) adopted by the Texas legislature in June 1999. The Texas electric
restructuring law substantially amended the regulatory structure governing
electric utilities in Texas in order to allow retail electric competition with
respect to all customer classes beginning in January 2002. Under its business
separation plan filed with the Public Utility Commission of Texas (PUCT),
Reliant Energy transferred substantially all of its unregulated businesses to
Reliant Resources in order to separate its regulated and unregulated operations.
In accordance with the plan, in May 2001, Reliant Resources offered 59.8 million
shares of its common stock to the public at an initial offering price of $30 per
share (IPO) and received net proceeds from the IPO of $1.7 billion. For
additional information regarding the IPO, see notes 3 and 10(a) to our Form 8-K.

CenterPoint Energy, Inc. was formed on August 31, 2002 as the new holding
company of Reliant Energy. We refer to CenterPoint Energy, Inc. and its
predecessor company, Reliant Energy, as "CenterPoint." Unless clearly indicated
otherwise these references to "CenterPoint" mean CenterPoint Energy, Inc. on or
after August 31, 2002 and Reliant Energy prior to August 31, 2002. CenterPoint
is a diversified international energy services and energy delivery company that
owned the majority of Reliant Resources outstanding common stock prior to
September 30, 2002. On September 30, 2002, CenterPoint distributed all of the
240 million shares of our common stock it owned to its common shareholders of
record as of the close of business on September 20, 2002 (Distribution). The
Distribution completed the separation of Reliant Resources and CenterPoint into
two separate publicly held companies.

RESTATEMENT

Subsequent to the issuance of our financial statements for the first three
quarters of 2002, we determined that we had incorrectly calculated the amount of
hedge ineffectiveness for 2001 and the first three quarters of 2002 for hedging
instruments entered into prior to the adoption of the Financial Accounting
Standards Board (FASB) Statement of Financial Accounting Standards (SFAS) No.
133, "Accounting for Derivative Instruments and Hedging Activities," as amended
(SFAS No. 133). These hedging instruments included long-term forward contracts
for the sale of power in the California market through December 2006. The amount
of hedge ineffectiveness for these forward contracts was calculated using the
trade date. However, the proper date for the hedge ineffectiveness calculation
is hedge inception, which for these contracts was deemed to be January 1, 2001,
concurrent with the adoption of SFAS No. 133. This restatement in accounting for
hedge ineffectiveness resulted in a reduction of revenues of $4.2 million and
$5.3 million ($2.7 million and $3.4 million after-tax, respectively) for the
three and six months ended June 30, 2002, respectively.

The consolidated statements of operations and cash flows for the three and
six months ended June 30, 2002 have been restated from amounts previously
reported to correctly account for the amount of hedge ineffectiveness in the
first and second quarters of 2002. The restatement had no impact on previously
reported consolidated total operating, investing and financing cash flows for
the six months ended June 30, 2002. The following is a summary of the principal
effects of the restatement and the revisions for changes in accounting
principles and discontinued operations for the three and six months ended June
30, 2002: (Note - Those line items for which no change in amounts are shown were
not affected by the restatement.)

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(1) Beginning with the quarter ended September 30, 2002, we now report all
energy trading and marketing activities on a net basis as allowed by
Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for
Contracts involved in Energy Trading and Risk Management Activities" (EITF
No. 98-10). Comparative financial statements for prior periods have been
reclassified to conform to this presentation. For information regarding the
presentation of trading and marketing activities on a net basis, see note
2. Revenues, fuel and cost of gas sold expense and purchased power expense
have been reclassified to conform to this presentation.

(2) In February 2003, we signed an agreement to sell our European energy
operations to n.v. Nuon (Nuon), a Netherlands-based electricity
distributor. In the first quarter of 2003, we began to report the results
of our European energy operations as discontinued operations in accordance
with SFAS No. 144, "Accounting for the Impairment or Disposal of Long-Lived
Assets" (SFAS No. 144). Comparative financial statements for prior periods
have been reclassified to conform to this presentation.

(3) During the third quarter of 2002, we completed the transitional impairment
test required by SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS
No. 142), including the review of goodwill for impairment as of January 1,
2002 (see note 7). Based on this impairment test, we recorded an impairment
of our European energy segment's goodwill of $234 million, net of tax. This
impairment loss was recorded retroactively as a cumulative effect of a
change in accounting principle for the quarter ended March 31, 2002.

BASIS OF PRESENTATION

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America (GAAP) requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities, disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.

The interim financial statements reflect all normal recurring adjustments
that are, in the opinion of management, necessary to present fairly the
financial position and results of operations for the respective periods. Amounts
reported in the consolidated statements of operations are not necessarily
indicative of amounts expected for a full year period due to the effects of,
among other things, (a) seasonal fluctuation in demand for energy and energy
services, (b) changes in energy commodity prices, (c) timing of maintenance and
other expenditures, (d) acquisitions and dispositions of businesses, assets and
other interests and (e) changes in interest expense. In addition, some

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amounts from the prior periods have been reclassified to conform to the 2003
presentation of financial statements. These reclassifications do not affect
earnings.

The consolidated statements of operations include all revenues and costs
directly attributable to us, including costs for facilities and costs for
functions and services performed by centralized CenterPoint organizations and
directly charged to us based on usage or other allocation factors prior to the
Distribution. The results of operations for the three and six months ended June
30, 2002, in these interim financial statements also include general corporate
expenses allocated by CenterPoint to us prior to the Distribution. All of the
allocations in the interim financial statements are based on assumptions that
management believes are reasonable under the circumstances. However, these
allocations may not necessarily be indicative of the costs and expenses that
would have resulted if we had operated as a separate entity prior to the
Distribution.

Our financial reporting segments include the following: retail energy,
wholesale energy and other operations. The retail energy segment includes our
retail electric operations and associated supply activities. This segment
provides customized electricity and related energy services to large commercial,
industrial and institutional customers in Texas and, to a lesser extent, in New
Jersey. We also provide standardized electricity and related services to
residential and small commercial customers in Texas. In addition, the retail
energy segment includes our Electric Reliability Council of Texas (ERCOT)
generation facilities. The wholesale energy segment includes our non-ERCOT
portfolio of electric power generation facilities and related fuel delivery and
storage asset positions. The wholesale energy segment procures fuel and markets
energy and energy services to optimize its asset portfolio. The other operations
segment primarily includes unallocated general corporate expenses and
non-operating investments. See note 18 regarding the sale of our European energy
operations and the classification as discontinued operations.

Each of Orion Power New York, LP (Orion NY), Orion Power New York LP, LLC,
Orion Power New York GP, Inc., Astoria Generating Company, L.P., Carr Street
Generating Station, LP, Erie Boulevard Hydropower, LP, Orion Power MidWest, LP
(Orion MidWest), Orion Power Midwest LP, LLC, Orion Power Midwest GP, Inc.,
Twelvepole Creek, LLC and Orion Power Capital, LLC (Orion Capital) is a separate
legal entity and has its own assets.

(2) NEW ACCOUNTING PRONOUNCEMENTS

SFAS No. 142. See note 7 for a discussion regarding our adoption of SFAS
No. 142 on January 1, 2002.

SFAS No. 143. In June 2001, the FASB issued SFAS No. 143, "Accounting for
Asset Retirement Obligations" (SFAS No. 143). On January 1, 2003, we adopted the
provisions of this statement. SFAS No. 143 requires the fair value of a
liability for an asset retirement legal obligation to be recognized in the
period in which it is incurred. When the liability is initially recorded,
associated costs are capitalized by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted to its present
value each period, and the capitalized cost is depreciated over the useful life
of the related asset. SFAS No. 143 requires entities to record a cumulative
effect of a change in accounting principle in the statement of operations in the
period of adoption. Prior to the adoption of SFAS No. 143, we recorded asset
retirement obligations in connection with certain business combinations. These
obligations were recorded at their undiscounted estimated fair values on the
dates of acquisition. Our asset retirement obligations primarily relate to the
required future dismantling of power plants and auxiliary equipment at our
European energy operations. We also have asset retirement obligations related
primarily to future dismantlement of power plants on leased property and
environmental obligations related to ash disposal site closures in our wholesale
energy segment. The impact of the adoption of SFAS No. 143 resulted in a gain of
$19 million, net of tax of $10 million, or $0.06 per share, as a cumulative
effect of an accounting change in our consolidated statement of operations for
the six months ended June 30, 2003. Included in the gain is $16 million, net of
tax of $7 million, related to our European energy operations, which are now
reported as discontinued operations.

The impact of the adoption of SFAS No. 143 for our continuing operations
resulted in a January 1, 2003 cumulative effect of an accounting change to
record (a) a $6 million increase in the carrying values of property, plant and
equipment, (b) a $1 million increase in accumulated depreciation of property,
plant and equipment, (c) a $1 million decrease in asset retirement obligations
and (d) a $3 million increase in deferred income tax liabilities. The net impact
of these items was to record a gain of $3 million, net of tax, as a cumulative
effect of an accounting change in our results of continuing operations upon
adoption on January 1, 2003.

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The following unaudited pro forma financial information has been prepared
to give effect to the adoption of SFAS No. 143 as if it had been adopted on
January 1, 2002:

The following table presents the detail of our asset retirement obligations
for continuing operations, which are included in other long-term liabilities in
our consolidated balance sheet (in millions):

Balance at January 1, 2003 ............. $ 11
Accretion expense ...................... 1
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Balance at June 30, 2003 ............... $ 12
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SFAS No. 144. In August 2001, the FASB issued SFAS No. 144. SFAS No. 144
provides new guidance on the recognition of impairment losses on long-lived
assets to be held and used or to be disposed of and also broadens the definition
of what constitutes a discontinued operation and how the results of a
discontinued operation are to be measured and presented. SFAS No. 144 supercedes
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of," and Accounting Principles Board Opinion
No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal
of a Segment of a Business, and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions," while retaining many of the requirements of
these two statements. One change from the previous standard is that under SFAS
No. 144, assets disposed of or held for sale that meet the definition to be a
"component of an entity" will be included in discontinued operations if the
operations and cash flows will be or have been eliminated from the ongoing
operations of the entity and the entity will not have any significant continuing
involvement in the operations prospectively. SFAS No. 144

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did not materially change the methods used by us to measure impairment losses on
long-lived assets. We adopted SFAS No. 144 on January 1, 2002. In accordance
with SFAS No. 144, our European energy operations are being reflected as
discontinued operations (see note 18). Also, in accordance with SFAS No. 144,
our Desert Basin plant operations will be reflected as discontinued operations
beginning in the third quarter of 2003 (see note 19).

SFAS No. 145. In April 2002, the FASB issued SFAS No. 145, "Rescission of
FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current
requirement that gains and losses on debt extinguishment must be classified as
extraordinary items in the statement of operations. Instead, such gains and
losses will be classified as extraordinary items only if they are deemed to be
unusual and infrequent. SFAS No. 145 also requires sale-leaseback accounting for
certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. The changes related to debt extinguishment will be
effective for fiscal years beginning after May 15, 2002 (which we began to apply
effective January 1, 2003) and the changes related to lease accounting are
effective for transactions occurring after May 15, 2002 (which we began to apply
at that time).

SFAS No. 148. In December 2002, the FASB issued SFAS No. 148, "Accounting
for Stock-Based Compensation - Transition and Disclosure, an amendment to SFAS
No. 123" (SFAS No. 148). This statement provides alternative methods of
transition for a company that voluntarily changes to the fair value method of
accounting for stock-based employee compensation. SFAS No. 148 also amends
disclosure requirements of SFAS No. 123, "Accounting for Stock-Based
Compensation," (SFAS No. 123), to require prominent disclosure in both annual
and interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results.
SFAS No. 148 is effective for annual financial statements for fiscal years
ending after December 15, 2002 and condensed financial statements for interim
periods beginning after December 15, 2002. In addition, on April 22, 2003, the
FASB announced that it plans to require all companies to expense the fair value
of employee stock options. The FASB is still evaluating how to measure "fair
value" and other items. The FASB plans to issue an exposure draft in late 2003
that would become effective in 2004. We have decided not to change to the fair
value method of accounting for stock-based employee compensation in 2003. We
have adopted the disclosure requirements of SFAS No. 148 for our interim
financial statements for 2003.

We apply the intrinsic method of accounting for employee stock-based
compensation plans in accordance with Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" (APB No. 25). Under the intrinsic
value method, no compensation expense is recorded when options are issued with
an exercise price equal to the market price of the underlying stock on the date
of grant. Since our stock options have all been granted with the exercise price
equal to or greater than market value at date of grant, no compensation expense
has been recognized under APB No. 25. We comply with the disclosure requirements
of SFAS No. 123 and SFAS No. 148 and disclose the pro forma effect on net income
(loss) and per share amounts as if the fair value method of accounting had been
applied to all stock awards. Had compensation costs been determined as
prescribed by SFAS No. 123, our net income (loss) and per share amounts would
have approximated the following pro forma results for the three and six months
ended June 30, 2002 and 2003, which take into account the amortization of
stock-based compensation, including performance shares, purchases under the
employee stock purchase plan and stock options, to expense on a straight-line
basis over the vesting periods:

For further information regarding our stock-based compensation plans and
our assumptions used to compute pro forma amounts, see note 12 to our Form 8-K.

SFAS No. 149. In April 2003, the FASB issued SFAS No. 149 "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" (SFAS No. 149).
SFAS No. 149 clarifies when a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS No. 133 and when a
derivative contains a financing component. SFAS No. 149 also amends certain
existing pronouncements, which will result in more consistent reporting of
contracts as either derivative or hybrid instruments. SFAS No. 149 is effective
for contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003 and should be applied
prospectively. Certain paragraphs of this statement that relate to forward
purchases or sales of when-issued securities or other securities that do not yet
exist, should be applied to both existing contracts and new contracts entered
into after June 30, 2003. The provisions of this statement that relate to SFAS
No. 133 implementation issues that have been effective for fiscal quarters that
began prior to June 15, 2003, should continue to be applied in accordance with
their respective effective dates. We are currently assessing the impact that the
prospective guidance in this statement will have on our consolidated financial
statements.

SFAS No. 150. In May 2003, the FASB issued SFAS No. 150, "Accounting for
Certain Financial Instruments with Characteristics of Both Liabilities and
Equity" (SFAS No. 150). This statement requires that an issuer classify a
financial instrument that is within its scope as a liability (or an asset in
some circumstances) because that financial instrument embodies an obligation of
the issuer. SFAS No. 150 is generally effective for financial instruments
entered into or modified after May 31, 2003 and otherwise is effective for us
beginning July 1, 2003. The adoption of SFAS No. 150 will not have a material
impact on our consolidated financial statements.

FIN No. 45. In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Direct Guarantees of Indebtedness of Others," (FIN No. 45) which increases the
disclosure requirements for a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued. It
clarifies that a guarantor's required disclosures, for guarantees of obligations
of unconsolidated entities, include the nature of the guarantee, the maximum
potential undiscounted payments that could be required, the current carrying
amount of the liability, if any, for the guarantor's obligations (including the
liability recognized under SFAS No. 5, "Accounting for Contingencies"), and the
nature of any recourse provisions or available collateral that would enable the
guarantor to recover amounts paid under the guarantee. It also requires a
guarantor to recognize, at the inception of a guarantee issued after December
31, 2002, a liability for the fair value of the obligation undertaken in issuing
the guarantee, including its ongoing obligation to stand ready to perform over
the term of the guarantee in the event that specified triggering events or
conditions occur. We adopted the reporting requirements of FIN No. 45 on January
1, 2003. The adoption of FIN No. 45 had no impact to our historical interim
financial statements, as existing guarantees are not subject to the measurement
provisions. The adoption of FIN No. 45 did not have a material impact on our
consolidated financial position or results of operations as of and for the three
and six months ended June 30, 2003 as the fair value of guarantees entered into
after December 31, 2002 was nominal on the date in which the guarantee was
entered. See note 13(c).

FIN No. 46. In January 2003, the FASB issued FASB Interpretation No. 46
"Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51"
(FIN No. 46). The objective of FIN No. 46 is to achieve more consistent
application of consolidation policies to variable interest entities and to
improve comparability between enterprises engaged in similar activities. FIN No.
46 states that an enterprise must consolidate a variable interest entity if the
enterprise has a variable interest that will absorb a majority of the entity's
expected losses if they occur, receives a majority of the entity's expected
residual returns if they occur, or both. If one enterprise absorbs a majority of
a

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variable interest entity's expected losses and another enterprise receives a
majority of that entity's expected residual returns, the enterprise absorbing a
majority of the losses shall consolidate the variable interest entity and will
be called the primary beneficiary. FIN No. 46 is effective immediately for
variable interest entities created after January 31, 2003, and for variable
interest entities in which an enterprise obtains an interest after that date.
For enterprises that acquired variable interests prior to February 1, 2003, the
effective date is for fiscal years or interim periods beginning after June 15,
2003. FIN No. 46 requires entities to either (a) record the effects
prospectively with a cumulative effect adjustment as of the date on which FIN
No. 46 is first applied or (b) restate previously issued financial statements
for the years with a cumulative effect adjustment as of the beginning of the
first year being restated. We adopted FIN No. 46 on January 1, 2003. Results for
the three and six months ended June 30, 2003, include the cumulative effect of
accounting change of $1 million loss, net of tax, effective January 1, 2003
related to the prospective adoption of FIN No. 46. See note 13(a).

As of December 31, 2002, we had variable interests in three power
generation projects that were being constructed by off-balance sheet special
purpose entities under construction agency agreements, which pursuant to this
guidance required consolidation upon adoption. As of January 1, 2003, these
special purpose entities had property, plant and equipment of $1.3 billion, net
other assets of $3 million and secured debt obligations of $1.3 billion. These
special purpose entities' financing agreement, the construction agency
agreements and the related guarantees were terminated as part of the refinancing
in March 2003. For information regarding these special purpose entities and the
refinancing, see notes 10 and 13(a).

EITF No. 02-03. In June 2002, the EITF had its initial meeting regarding
EITF No. 02-03 and reached a consensus that all mark-to-market gains and losses
on energy trading contracts should be shown net in the statement of operations
whether or not settled physically. In October 2002, the EITF issued a consensus
that superceded the June 2002 consensus. The October 2002 consensus required,
among other things, that energy derivatives held for trading purposes be shown
net in the statement of operations. This new consensus was effective for fiscal
periods beginning after December 15, 2002. However, consistent with the new
consensus and as allowed under EITF No. 98-10, beginning with the quarter ended
September 30, 2002, we report all energy trading and marketing activities on a
net basis in the consolidated statements of operations. Comparative financial
statements for prior periods have been reclassified to conform to this
presentation.

The adoption of net reporting resulted in reclassifications of revenues,
fuel and cost of gas sold, purchased power expense for the three and six months
ended June 30, 2002 as follows:

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(1) These amounts do not reflect the adjustments due to the restatement as
discussed in note 1.

(2) Some amounts from the previous period have been reclassified to conform to
the presentation of our consolidated statements of operations for the three
and six months ended June 30, 2003. These reclassifications do not affect
operating income or net income.

Furthermore, in October 2002, under EITF No. 02-03, the EITF reached a
consensus to rescind EITF No. 98-10. All new contracts that would have been
accounted for under EITF No. 98-10, and that do not fall within the scope of
SFAS No. 133 should no longer be marked-to-market through earnings beginning
October 25, 2002. In addition, mark-to-market accounting is no longer applied to
inventories used in the trading and marketing operations. This transition was
effective for us for the first quarter of 2003. We recorded a cumulative effect
of a change in accounting principle of $42 million loss, net of tax of $22
million, or $0.14 per diluted share, effective January 1, 2003, related to EITF
No. 02-03 for the six months ended June 30, 2003. During the three months ended
June 30, 2003, we recorded an adjustment to our cumulative effect of accounting
changes of $862,000 gain, net of tax. The cumulative effect reflects the fair
value, as of January 1, 2003, of certain contracts that had been marked to
market under EITF No. 98-10 and do not meet the definition of a derivative under
SFAS No. 133. Additionally, beginning

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in January 2003, we began applying the "normal" purchase and sale exception of
SFAS No. 133 to a substantial portion of our retail large commercial, industrial
and institutional sales contracts that had previously been recorded under
mark-to-market accounting under EITF No. 98-10. Under the "normal" purchase and
sale exception, we utilize accrual accounting for these contracts because they
represent physical power sales in the normal course of business.

Prior to 2003, our retail energy segment's contracted electricity sales to
large commercial, industrial and institutional customers and the related energy
supply contracts for contracts entered into prior to October 25, 2002 were
accounted for under the mark-to-market method of accounting pursuant to EITF No.
98-10. Under the mark-to-market method of accounting, these contractual
commitments were recorded at fair value in revenues on a net basis upon contract
execution. The net changes in their fair values were recognized in the
consolidated statements of operations as revenues on a net basis in the period
of change through 2002. Effective January 1, 2003, we no longer mark to market
in earnings a substantial portion of these electricity sales contracts and the
related energy supply contracts in connection with the implementation of EITF
No. 02-03. The related revenues and purchased power are now recorded on a gross
basis in our results of operations. Due to the implementation of EITF No. 02-03,
the results of operations related to our contracted electricity sales to large
commercial, industrial and institutional customers and the related energy supply
contracts for contracts entered into prior to October 25, 2002 are not
comparable between the three and six months ended June 30, 2002 and 2003. During
the three and six months ended June 30, 2002, our retail energy segment
realized $12 million and $14 million, respectively, of previously unrealized net
losses related to its contracted electricity sales to large commercial,
industrial and institutional customers and the related energy supply contracts.
During the three and six months ended June 30, 2003, volumes were delivered
under contracted electricity sales to large commercial, industrial and
institutional customers and the related energy supply contracts for which $14
million and $31 million, respectively, was previously recognized as unrealized
earnings in prior periods. As of June 30, 2003, our retail energy segment has
unrealized gains that have been previously recorded in our results of operations
of $62 million that will be realized when the electricity is delivered to our
customers ($35 million in the remainder of 2003 and $27 million in 2004 and
beyond). These unrealized gains of $62 million are recorded in non-trading
derivative assets/liabilities in our consolidated balance sheet as of June 30,
2003 and the related contracts are accounted for as cash flow hedges or "normal"
sales contracts under SFAS No. 133.

The EITF has not reached a consensus on whether recognition of dealer
profit or unrealized gains and losses at inception of an energy trading contract
is appropriate in the absence of quoted market prices or current market
transactions for contracts with similar terms. In the June 2002 EITF meeting and
again in the October 2002 EITF meeting, the FASB staff indicated that until such
time as a consensus is reached, the FASB staff will continue to hold the view
that previous EITF consensuses do not allow for recognition of dealer profit,
unless evidenced by quoted market prices or other current market transactions
for energy trading contracts with similar terms and counterparties. During the
three and six months ended June 30, 2002, we recorded $26 million and $46
million, respectively, of fair value at the contract inception related to
trading and marketing activities. For the three and six months ended June 30,
2003, we did not recognize any gains at inception. Inception gains are recorded
only when evidenced by quoted market prices and other current market
transactions for energy trading contracts with similar terms and counterparties.

(3) HISTORICAL RELATED PARTY TRANSACTIONS

The interim financial statements include significant transactions between
CenterPoint and us. Some of these transactions involve services, including
various corporate support services (including accounting, finance, investor
relations, planning, legal, communications, governmental and regulatory affairs
and human resources), information technology services and other shared services
such as corporate security, facilities management, accounts receivable, accounts
payable and payroll, office support services and purchasing and logistics. The
costs of services have been directly charged or allocated to us using methods
that management believes are reasonable. These methods include negotiated usage
rates, dedicated asset assignment, and proportionate corporate formulas based on
assets, operating expenses and employees. These charges and allocations are not
necessarily indicative of what would have been incurred had we been an
unaffiliated entity. Amounts charged and allocated to us for these services for
the three and six months ended June 30, 2002, were $5 million and $10 million,
respectively, and are included primarily in operation and maintenance expenses
and general and administrative expenses. Some of our subsidiaries have entered
into office rental agreements with CenterPoint. During the three and six months
ended June 30, 2002, we incurred $8 million and $16 million, respectively, of
rent expense to CenterPoint. Net interest income related to various net
receivables representing transactions between us and CenterPoint or its
subsidiaries was $1 million and $4 million, respectively, during the three and
six months ended June 30, 2002.

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We purchased natural gas, natural gas transportation services, electric
generation energy and capacity, and electric transmission services from,
supplied natural gas to, and provided marketing and risk management services to
affiliates of CenterPoint. Purchases and sales related to our trading and
marketing activities are recorded net in trading margins in the consolidated
statements of operations. Purchases of electric generation energy and capacity
and electric transmission services from CenterPoint and its subsidiaries were
$674 million and $854 million, respectively, for the three and six months ended
June 30, 2002. During the three and six months ended June 30, 2002, the net
purchases and sales and services from/to CenterPoint and its subsidiaries
related to our trading and marketing operations totaled $216 million and $145
million, respectively. In addition, during the three and six months ended June
30, 2002, other sales and services to CenterPoint and its subsidiaries totaled
$13 million. Sales and purchases to/from CenterPoint subsequent to the
Distribution are not reported as affiliated transactions.

We have purchased entitlements to some of the generation capacity of
electric generation assets of Texas Genco, LP, which is a wholly-owned
subsidiary of Texas Genco Holdings, Inc. (Texas Genco), a majority-owned
subsidiary of CenterPoint. We purchased these entitlements in capacity auctions
conducted by Texas Genco and pursuant to rights granted to us under the Master
Separation Agreement, see note 4(b) to our Form 8-K. As of June 30, 2003, we had
purchased entitlements to capacity of Texas Genco averaging 6,390 megawatts (MW)
per month in 2003, 715 MW per month in 2004 and 298 MW per month in 2005. Our
anticipated capacity payments related to these capacity entitlements are $214
million for the remainder of 2003, $148 million for 2004 and $57 million for
2005.

During the three months ended June 30, 2002 and 2003, CenterPoint made no
equity contributions to us. During the six months ended June 30, 2002 and 2003,
CenterPoint made equity contributions to us of $0 and $47 million, respectively.
The contributions in 2003 primarily related to the non-cash conversion to equity
of accounts payable to CenterPoint.

(4) AGREEMENTS RELATING TO TEXAS GENCO

Texas Genco owns the Texas generating assets formerly held by CenterPoint's
electric utility division. Texas Genco, as the affiliated power generator of
CenterPoint, is required by law to sell at auction 15% of the output of its
installed generating capacity. These auction obligations will continue until
January 2007, unless at least 40% of the electricity consumed by residential and
small commercial customers in CenterPoint's service territory is being served by
retail electric providers other than us. Under its agreement with us, Texas
Genco must auction all of its capacity that remains subsequent to the capacity
auctions mandated under PUCT rules and after certain other adjustments. We have
the option to purchase 50% of such remaining capacity at the prices established
in such auctions. We also have the right to participate directly in such
auctions, without any restrictions on our level of participation. Texas Genco's
obligation to auction its capacity and our associated rights terminate (a) if we
do not exercise our option to acquire CenterPoint's ownership interest in Texas
Genco by January 24, 2004 or (b) if we exercise our option to acquire
CenterPoint's ownership interest in Texas Genco, on (i) the closing of the
acquisition or (ii) if the closing has not occurred, the last day of the
sixteenth month after the month in which the option is exercised.

On October 1, 2002, we entered into a master power purchase contract with
Texas Genco covering, among other things, our purchases of capacity and/or
energy from Texas Genco's generating units, under an unsecured line of credit.
This contract was amended in connection with our March 2003 refinancing. This
amendment granted Texas Genco a security interest in the accounts receivable and
related assets of certain of our subsidiaries and removed many of the
restrictive covenants contained in the agreement. The liens on the accounts
receivable and related assets are junior to certain permitted prior financing
arrangements and senior to the liens granted to the lenders under the March
2003 credit facilities. In July 2003, the agreement was further amended to
facilitate the transfer of the junior lien in the accounts receivable and the
related assets to the collateral trustee to ratably secure the senior secured
notes and the March 2003 credit facilities.

In January 2003, CenterPoint distributed approximately 19% of the common
stock of Texas Genco to CenterPoint shareholders. CenterPoint has granted us an
option to purchase all of the remaining shares of common stock of Texas Genco
held by CenterPoint. The option must be exercised between January 10, 2004 and
January 24, 2004. Subject to the exercise price of the option, market
conditions, available financing and our due diligence investigation of Texas
Genco, we may elect to exercise the Texas Genco option. The per share exercise
price under the option will be set as the average daily closing price on the
national exchange for publicly held shares of common stock of Texas Genco for
the 30 consecutive trading days with the highest average closing price during
the 120 trading days ending January 9, 2004, plus a control premium, up to a
maximum of 10%, to the extent a control premium is included in the valuation
determination made by the PUCT. The exercise price is also subject to

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adjustment based on the difference between the per share dividends paid during
the period there is a public ownership interest in Texas Genco and Texas Genco's
per share earnings during that period. In the event that we exercise the option,
we have the right to rescind our exercise within 45 days if we are unable to
secure financing for the purchase of the Texas Genco shares on reasonable terms.
We have agreed that if we exercise the Texas Genco option, we will also purchase
all notes and other receivables from Texas Genco then held by CenterPoint, at
their principal amount, plus accrued interest. Similarly, if Texas Genco holds
notes or receivables from CenterPoint, we will, upon exercise of the Texas Genco
option, assume CenterPoint's obligations in exchange for a payment to us by
CenterPoint of an amount equal to the principal, plus accrued interest. See note
10 for discussion of our Texas Genco option and the related impacts from our
various credit facilities and notes.

We have entered into a support agreement with CenterPoint, pursuant to
which we provide engineering and technical support services and environmental,
safety and industrial health services to support operations and maintenance of
Texas Genco's facilities. We also provide systems, technical, programming and
consulting support services and hardware maintenance (but excluding
plant-specific hardware) necessary to provide dispatch planning, dispatch,
settlement and communication with the independent system operator. The fees we
charge for these services are designed to allow us to recover our fully
allocated direct and indirect costs and reimbursement of out-of-pocket expenses.
Expenses associated with capital investment in systems and software that benefit
both the operation of Texas Genco's facilities and our facilities in other
regions are allocated on an installed MW basis. The term of this agreement will
end on the first to occur of (a) the closing date of our possible acquisition of
Texas Genco under the option, (b) CenterPoint's sale of Texas Genco, or all or
substantially all of the assets of Texas Genco, if we do not exercise the Texas
Genco option, or (c) May 31, 2005 if we do not exercise the option; however,
Texas Genco may extend the term of this agreement until December 31, 2005.

(5) COMPREHENSIVE INCOME (LOSS)

The following tables summarize the components of total comprehensive income
(loss):

(6) BUSINESS ACQUISITIONS

In February 2002, we acquired all of the outstanding shares of common stock
of Orion Power Holdings, Inc. (Orion Power) for an aggregate purchase price of
$2.9 billion and assumed debt obligations of $2.4 billion. We funded the Orion
Power acquisition with a $2.9 billion credit facility (see note 10) and $41
million of cash on hand. As a result of the acquisition, our consolidated debt
obligations also increased by the amount of Orion Power's debt obligations. As
of February 19, 2002, Orion Power's debt obligations were $2.4 billion ($2.1
billion net of restricted cash pursuant to debt covenants). Orion Power is an
electric power generating company with a diversified portfolio of generating
assets, both geographically across the states of New York, Pennsylvania, Ohio
and West Virginia, and by fuel type, including gas, oil, coal and hydro. The
primary reason for the acquisition was to enhance our then current domestic
power generation position by combining our domestic generation capacity and
Orion Power's domestic generation capacity. The Orion Power acquisition expanded
our market presence into the New York and East Central Area Reliability
Coordinating Counsel power markets. As of February 19, 2002, Orion Power had 81
generating facilities with a total generating capacity of 5,644 MW and two
development projects with an additional

14

804 MW of capacity under construction. During 2002, both projects under
construction reached commercial operation.

We accounted for the acquisition as a purchase with assets and liabilities
of Orion Power reflected at their estimated fair values. Our fair value
adjustments primarily included adjustments in property, plant and equipment,
contracts, severance liabilities, debt, unrecognized pension and postretirement
benefits liabilities and related deferred taxes. We finalized these fair value
adjustments in February 2003, after receiving final valuations of property,
plant and equipment, intangible assets and other assets and obligations.

The following factors contributed to the recognized goodwill of $1.3
billion: commercialization value attributable to our marketing and trading
capabilities, commercialization and synergy value associated with fuel
procurement in conjunction with existing generating plants in the region, entry
into the New York power market, general and administrative cost synergies with
existing Pennsylvania-New Jersey-Maryland power market generating assets and
headquarters, and risk diversification value due to increased scale, fuel supply
mix and the nature of the acquired assets. Of the resulting goodwill, all but
$105 million is not deductible for United States income tax purposes. The $1.3
billion of goodwill was assigned to the wholesale energy segment. See note 7 for
a discussion of possible impairments of our wholesale energy segment's goodwill.

Our results of operations include the results of Orion Power for the period
beginning February 19, 2002. The following tables present selected financial
information and unaudited pro forma information for the six months ended June
30, 2002, as if the acquisition had occurred on January 1, 2002.

These unaudited pro forma results, based on assumptions we deem
appropriate, have been prepared for informational purposes only and are not
necessarily indicative of the amounts that would have resulted if the
acquisition of Orion Power had occurred on January 1, 2002. Purchase-related
adjustments to the results of operations include the effects on revenues, fuel
expense, depreciation and amortization, interest expense, interest income and
income taxes. Adjustments that affected revenues and fuel expense were a result
of the amortization of contractual rights and obligations relating to the
applicable power and fuel contracts that were in existence at January 1, 2002,
as applicable. Such amortization included in the pro forma results above was
based on the fair value of the contractual rights and obligations at February
19, 2002. The amounts applicable to 2002 were retroactively applied to January
1, 2002 through February 19, 2002 to arrive at the pro forma effect on those
periods. The unaudited pro forma condensed interim financial information
presented above reflects the acquisition of Orion Power in accordance with SFAS
No. 141 and SFAS No. 142.

(7) GOODWILL AND INTANGIBLES

In July 2001, the FASB issued SFAS No. 142, which states that goodwill and
certain intangibles with indefinite lives will not be amortized into results of
operations, but instead will be reviewed periodically for impairment and charged
to results of operations in periods in which the recorded value of goodwill and
certain intangibles with indefinite lives exceeds their fair values. We adopted
the provisions of the statement effective January 1, 2002, and discontinued
amortizing goodwill into our results of operations.

As of March 31, 2002, we completed our assessment of intangible assets and
no intangible assets with indefinite lives were identified, except for $1
million of air emissions regulatory allowances. No related impairment losses
were recorded in the first quarter of 2002 and no changes were made to the
expected useful lives of our intangible assets as a result of this assessment.

15

During the third quarter of 2002, we completed the transitional goodwill
impairment test required by SFAS No. 142, including the review of goodwill for
impairment as of January 1, 2002. A goodwill impairment test is performed in two
steps. The initial step is designed to identify potential goodwill impairment by
comparing an estimate of the fair value of the applicable reporting unit to its
carrying value, including goodwill. If the carrying value exceeds the fair
value, a second step is performed, which compares the implied fair value of the
applicable reporting unit's goodwill with the carrying amount of that goodwill,
to measure the amount of the goodwill impairment, if any. Based on our
transitional impairment test, we recorded an impairment of our European energy
segment's goodwill of $234 million, net of tax. This impairment loss was
recorded retroactively as a cumulative effect of a change in accounting
principle for the quarter ended March 31, 2002. Based on the first step of this
goodwill impairment test, no goodwill was impaired for our other reporting
units.

The circumstances leading to the goodwill impairment of our European energy
segment included a significant decline in electric margins attributable to the
deregulation of the European electricity market in 2001, lack of growth in the
wholesale energy trading markets in Northwest Europe, continued regulation of
certain European fuel markets and the reduction of proprietary trading in our
European operations (which activity was subsequently discontinued in its
entirety in the third quarter of 2002). Our measurement of the fair value of the
European energy segment was based on a weighted-average approach considering
both an income approach, using future discounted cash flows, and a market
approach, using acquisition multiples, including price per MW, based on publicly
available data for recently completed European transactions.

SFAS No. 142 requires goodwill to be tested annually and between annual
tests if events occur or circumstances change that would "more likely than not"
reduce the fair value of a reporting unit below its carrying amount. Our annual
test for indications of goodwill impairment is currently performed as of
November 1, in conjunction with our annual planning process. In estimating the
fair value of our European energy segment for the annual impairment test as of
November 1, 2002, we considered the sales price in the agreement that we signed
in February 2003 to sell our European energy operations to a Netherlands-based
electricity distributor (see note 18). We concluded that the sales price
reflects the best estimate of fair value of our European energy segment as of
November 1, 2002, to use in such impairment test. Our annual impairment test
determined that the full amount of our European energy segment's net goodwill of
$482 million was impaired and such impairment was recorded in the fourth quarter
of 2002. For additional information regarding this transaction and its impacts,
see note 18.

Our annual impairment test identified no other impairments of goodwill for
our other reporting units. This annual goodwill impairment test indicated that
the fair value of our wholesale energy reporting unit exceeded its carrying
value by approximately five percent.

Our goodwill impairment analysis estimates the fair value of our reporting
units using a combination of approaches, including an income approach based on
internal plans, a market approach based on transactions in the marketplace for
comparable types of assets, and a comparable public company approach. The income
approach used in our analysis is a discounted cash flow analysis based on our
internal plans and contains numerous assumptions made by management, any of
which if changed could significantly affect the outcome of the analysis. We
believe that the income approach is the most subjective of the approaches.

Our historical impairment analyses for our wholesale energy reporting unit
included numerous assumptions, including but not limited to:

o increases in demand for power that will result in the tightening of
supply surpluses and additional capacity requirements over the next
three to eight years, depending on the region;

o improving prices in electric energy, ancillary services and existing
capacity markets as the power supply surplus is absorbed; and

o our expectation that more balanced, fair market rules will be
implemented, which provide for the efficient operations of unregulated
power markets, including capacity markets or similar mechanisms in
regions where they currently do not exist.

The internal cash flow analyses used in our November 1, 2002 impairment
analysis for our wholesale energy reporting unit was over a period of 15 years
with an assumed terminal value for the value of our operations at the end of the
analysis of an EBITDA (earnings from continuing operations before depreciation
and amortization,

16

interest expense, interest income and income taxes) multiple of primarily 7.5.
For our annual impairment test as of November 1, 2002, these after-tax cash
flows (excluding interest) were discounted back to the date of the analysis at
an appropriate risk-adjusted discount rate of primarily 9% in order to determine
the fair value of the reporting unit under the income approach. The income
approach was weighted along with the other two approaches to determine the fair
value of the reporting unit. Our November 1, 2002 analyses for our wholesale
energy reporting unit assumed that the demand for power would rise at an annual
rate of approximately 2% over the next several years. This growth over time was
assumed to result in decreased reserve margins in the areas where we operate. As
reserve margins decrease, power generation margins were assumed to rise over
time to a level sufficient to attract new capacity (estimated to be in 2007 and
2008). We assumed that this level of margins would be such that companies would
build new generation facilities and these new facilities would be able to cover
all of their operating expenses and yield an internal rate of return on their
investment of 9%.

These assumptions are consistent with the view that long run market prices
will reach levels sufficient to support an adequate rate of return on the
construction of new power generation, which we believe will be required to meet
increased demand for power. This view is currently being challenged in certain
markets as market rules unfold that provide more favorable returns to new
capacity entering the market than is provided to existing capacity.

Evaluation of Goodwill Related to our Wholesale Energy Segment. On July 9,
2003, we entered into a definitive agreement to sell our 588-megawatt Desert
Basin plant (see note 19). This anticipated sale of our Desert Basin plant
operations requires us, in accordance with SFAS No. 142, to allocate a portion
of the goodwill in the wholesale energy reporting unit to the Desert Basin plant
operations on a relative fair value basis as of July 2003 in order to compute
the gain or loss on disposal. SFAS No. 142 also requires us to test the
recoverability of goodwill in our remaining wholesale energy reporting unit as
of July 2003. After the allocation of goodwill to the Desert Basin plant
operations, our wholesale energy segment's remaining goodwill is estimated to be
approximately $1.4 billion, which is being tested for impairment effective July
2003. The assessment of goodwill requires developing an updated estimate of the
fair value of our wholesale energy reporting unit, which is expected to be
completed by the end of the third quarter of 2003.

In response to continued depressed prices for electric energy, capacity and
ancillary services across much of the United States and our current judgments
regarding the state of the wholesale electricity markets, we are in the process
of evaluating our short-term and long-term strategies and activities. During the
first quarter of 2003, we decided to exit our proprietary trading activities. We
are presently evaluating, and may soon implement, (a) further reductions in
commercial, operational and support groups to reduce costs, (b) further changes
in our market strategies, (c) mothballing or retiring certain power generation
facilities, (d) deferring and/or materially reducing maintenance expenditures at
power generation facilities and (e) divesting of certain assets. Also, we are
evaluating the method of projecting future cash flows from our wholesale energy
segment operations. In connection with this effort, our future cash flow
projections and plans may be significantly revised.

If the assumptions and estimates underlying our July 2003 goodwill
impairment evaluation for our wholesale energy reporting unit differ adversely
from the assumptions previously used due to changes in our wholesale energy
market outlook, strategies and activities, it is possible that goodwill might be
impaired and any such impairment would be reflected in the third quarter of
2003.

Our July 2003 impairment analysis will reconsider the assumptions discussed
above and others, including: estimates of future market prices for power and
fuel, valuation of plant and equipment, growth, regulation of wholesale power
markets, market structure, competition and many other factors as of the
determination date. The resulting impairment analysis is highly dependent on
these underlying assumptions.

In addition, if our wholesale energy market outlook and views change
further in future periods and the current weak environment is prolonged or if
current conditions decline further, we could have impairments of our property,
plant and equipment in future periods which, in turn, could have a material
adverse effect on our results of operations.

(8) DERIVATIVE FINANCIAL INSTRUMENTS

Effective January 1, 2001, we adopted SFAS No. 133, which establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts and for hedging activities.
This statement requires that derivatives be recognized at fair value in the
balance sheet and that changes

17

in fair value be recognized either currently in earnings or deferred as a
component of accumulated other comprehensive income (loss), net of applicable
taxes, depending on the intended use of the derivative, its resulting
designation and its effectiveness. If certain conditions are met, an entity may
designate a derivative instrument as hedging (a) the exposure to changes in the
fair value of an asset or liability (fair value hedge), (b) the exposure to
variability in expected future cash flows (cash flow hedge) or (c) the foreign
currency exposure of a net investment in a foreign operation. For a derivative
not designated as a hedging instrument, the gain or loss is recognized in
earnings in the period it occurs. During the three and six months ended June 30,
2002 and 2003, we did not enter into any fair value hedges and as of December
31, 2002 and June 30, 2003, we had no fair value hedges. For a discussion of our
hedge of foreign currency exposure of our anticipated net proceeds from the sale
of our European energy operations, see note 18.

Cash Flow Hedges. During the three months ended June 30, 2002, the amount
of hedge ineffectiveness recognized in revenues from derivatives that are
designated and qualify as cash flow hedges, including interest rate derivative
instruments (see note 10(b)), was a gain of $8 million. During the three months
ended June 30, 2003, the gain or loss related to ineffectiveness for these cash
flow hedges was immaterial. During the six months ended June 30, 2002 and 2003,
the amount of hedge ineffectiveness recognized in revenues from derivatives that
are designated and qualify as cash flow hedges, including interest rate
derivative instruments, was a gain of $7 million and a loss of $20 million,
respectively. For the three and six months ended June 30, 2002 and 2003, no
component of the derivative instruments' gain or loss was excluded from the
assessment of effectiveness. If it becomes probable that an anticipated
transaction will not occur, we recognize in net income (loss) the deferred gains
and losses recognized in accumulated other comprehensive income (loss). Should
any forecasted interest payments become probable of not occurring, any
applicable deferred amounts will be recognized immediately as an expense. During
the three and six months ended June 30, 2002 and 2003, there were no deferred
gains or losses recognized in earnings as a result of the discontinuance of cash
flow hedges because it was probable that the forecasted transaction would not
occur. Once the anticipated transaction occurs, the accumulated deferred gain or
loss recognized in accumulated other comprehensive loss is reclassified and
included in