EL PASO CORP/DE - 10-Q Quarterly Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

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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

COMMISSION FILE NUMBER 1-14365

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EL PASO CORPORATION
(Exact Name of Registrant as Specified in its Charter)

DELAWARE 76-0568816
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
EL PASO BUILDING
1001 LOUISIANA STREET 77002
HOUSTON, TEXAS (Zip Code)
(Address of Principal Executive Offices)

Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com

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

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [X] No [ ]

Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.

Common stock, par value $3 per share. Shares outstanding on August 11,
2003: 600,513,302

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EL PASO CORPORATION

TABLE OF CONTENTS

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Below is a list of terms that are common to our industry and used
throughout this document:

/d = per day
Bbl = barrels
BBtu = billion British thermal units
Bcf = billion cubic feet
MBbls = thousand barrels
MMBtu = million British thermal units
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of gas equivalents
MMcf = million cubic feet

When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl of oil is equal to six Mcf of
natural gas. Also, when we refer to cubic feet measurements, all measurements
are at a pressure of 14.73 pounds per square inch.

When we refer to "us", "we", "our", "ours", or "El Paso", we are describing
El Paso Corporation and/or our subsidiaries.

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
(UNAUDITED)

See accompanying notes.

1

EL PASO CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
(UNAUDITED)

See accompanying notes.

2

EL PASO CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
(UNAUDITED)

See accompanying notes.

3

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)

See accompanying notes.

4

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(IN MILLIONS)
(UNAUDITED)

See accompanying notes.

5

EL PASO CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. BASIS OF PRESENTATION

We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the United States Securities and Exchange Commission. Because
this is an interim period filing presented using a condensed format, it does not
include all of the disclosures required by generally accepted accounting
principles. You should read it along with our 2002 Annual Report on Form 10-K,
which includes a summary of our significant accounting policies and other
disclosures. The financial statements as of June 30, 2003, and for the quarters
and six months ended June 30, 2003 and 2002, are unaudited. We derived the
balance sheet as of December 31, 2002, from the audited balance sheet filed in
our 2002 Form 10-K. In our opinion, we have made all adjustments which are of a
normal, recurring nature to fairly present our interim period results. Due to
the seasonal nature of our businesses, information for interim periods may not
indicate the results of operations for the entire year. Our results for all
periods presented have been reclassified to reflect our petroleum and coal
mining operations as discontinued operations. In addition, prior period
information presented in these financial statements includes reclassifications
which were made to conform to the current period presentation. These
reclassifications have no effect on our previously reported net income or
stockholders' equity.

2. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES

SIGNIFICANT EVENTS

Liquidity Update

In early 2003, following actions taken by rating agencies to downgrade the
credit ratings of our company and many of the largest participants in our
industry, we announced a plan to address the business challenges and liquidity
needs of our company. These initiatives, broadly referred to as our 2003
Operational and Financial Plan, were based upon five key points. The five key
points were:

- Preserve and enhance the value of our core businesses;

- Divest non-core businesses quickly, but prudently;

- Strengthen and simplify our balance sheet, while maximizing liquidity;

- Aggressively pursue additional cost reductions in 2003 and beyond; and

- Work diligently to resolve regulatory and litigation matters.

So far in 2003, our major accomplishments regarding these five business
objectives are as follows:

- Concentrating our capital investment in our core Pipelines, Production
and Field Services segments such that 89 percent of total capital
expenditures were made in these businesses in the first half of 2003;

- Completing or announcing sales of assets and investments of approximately
$2.7 billion (see Note 4);

- Repaying approximately $4.2 billion of maturing debt and other
obligations ($3.8 billion as of June 30, 2003), including:

- Retiring long-term debt of $2.0 billion ($1.6 billion as of June 30,
2003);

- Repaying $980 million of obligations under our Trinity River financing
arrangement;

- Redeeming $197 million of obligations under our Clydesdale financing
arrangement and restructuring that transaction as a term loan that
will amortize over the next two years (see Notes 3 and 17); and

- Contributing $1 billion to the Limestone Electron Trust, which used
the proceeds to repay $1 billion of its notes and purchasing the third
party equity interests in our Gemstone and Chaparral power investments
and consolidating those investments (see Note 3);

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- Refinancing a $1.2 billion two-year term loan issued in March 2003 in
connection with the restructuring of our Trinity River financing
arrangement to eliminate the amortization requirements of that loan in
2004 and 2005;

- Entering into a new $3 billion revolving credit facility that matures in
June 2005 and completing financing transactions of approximately $3.6
billion ($3.2 billion as of June 30, 2003) (see Note 16);

- Identifying an estimated $445 million of cost savings and business
efficiencies to be realized by the end of 2004; and

- Reaching definitive settlement agreements in June 2003, which
substantially resolved our principal exposure relating to the western
energy crisis and funding $347 million of our obligation through the
issuance of senior unsecured notes of El Paso Natural Gas Company (EPNG)
in July 2003 (see Notes 6 and 18).

We believe the accomplishments achieved to date demonstrate our ability to
address our liquidity issues and simplify and improve our capital structure.
However, a number of factors could influence the timing and ultimate outcome of
our efforts, including our ability to raise cash from asset sales, which may be
impacted by our ability to locate potential buyers in a timely fashion and
obtain a reasonable price or by competing asset sale programs by our
competitors, oil and natural gas prices, conditions in the debt and equity
markets, the timely receipt of necessary third party and governmental approvals
and other factors.

Our plans and objectives for the year are discussed more fully in our 2002
Form 10-K.

SIGNIFICANT ACCOUNTING POLICIES

Our accounting policies are consistent with those discussed in our 2002
Form 10-K, except as follows:

Accounting for Asset Retirement Obligations. On January 1, 2003, we
adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting
for Asset Retirement Obligations. SFAS No. 143 requires that we record a
liability for retirement and removal costs of long-lived assets used in our
business. This liability is recorded at its estimated fair value, with a
corresponding increase to property, plant and equipment. This increase in
property, plant and equipment is then depreciated over the remaining useful life
of the long-lived asset to which that liability relates. An ongoing expense is
also recognized for changes in the value of the liability as a result of the
passage of time, which we also record in depreciation, depletion and
amortization expense in our income statement. In the first quarter of 2003, we
recorded a charge as a cumulative effect of accounting change of approximately
$22 million, net of income taxes related to our adoption of SFAS No. 143. We
also recorded property, plant and equipment of $188 million and non-current
asset retirement obligations of $222 million as of January 1, 2003. Our asset
retirement obligations are associated with our natural gas and oil wells and
related infrastructure in our Production segment and our natural gas storage
wells in our Pipelines segment. We have obligations to plug wells when
production on those wells is exhausted, and we abandon them. We currently
forecast that these obligations will be met at various times, generally over the
next 10 years, based on the expected productive lives of the wells and the
estimated timing of plugging and abandoning those wells. The net asset
retirement liability as of January 1, 2003 and June 30, 2003, reported in other
non-current liabilities in our balance sheet, and the changes in the net
liability for the six months ended June 30, 2003, were as follows (in millions):

Liability at January 1, 2003................................ $222
Liabilities settled in 2003................................. (43)
Accretion expense in 2003................................... 9
Liabilities incurred in 2003................................ 1
Changes in estimate......................................... 8
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Net liability at June 30, 2003......................... $197
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Our changes in estimate represent changes to the expected amount and timing
of payments to settle our asset retirement obligations. These changes primarily
result from obtaining new information about the timing of our obligations to
plug our natural gas wells and the costs to do so. Had we adopted SFAS No. 143
as of January 1, 2002, our non-current retirement liabilities would have been
approximately $200 million as of January 1, 2002, and our income from continuing
operations and net income for the quarter and six months ended June 30, 2002,
would have been lower by $3 million and $7 million. Basic and diluted earnings
per share for the quarter and six months ended June 30, 2002, would not have
been affected.

Accounting for Costs Associated with Exit or Disposal Activities. On
January 1, 2003, we adopted SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities. SFAS No. 146 requires that we recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. We applied the provisions of SFAS
No. 146 in accounting for restructuring costs we incurred during 2003 (see Note
5). As we continue to evaluate our business activities and seek additional cost
savings, we expect to incur additional charges that will be evaluated under this
accounting standard.

Goodwill and Other Intangible Assets

Our goodwill and other intangibles as of December 31, 2002 and June 30,
2003, and the changes in goodwill and other intangibles for the six months ended
June 30, 2003 were as follows (in millions):

Balance, December 31, 2002.................................. $1,367
Impairment of goodwill...................................... (163)
Acquisition of intangibles.................................. 117
Other changes............................................... (45)
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Balance, June 30, 2003...................................... $1,276
======

During 2003, we impaired $163 million of goodwill related to our
telecommunications business in our corporate segment and acquired $117 million
of intangible assets in connection with the acquisition of Chaparral in our
Merchant Energy segment. Chaparral's intangible assets consisted of power
purchase agreements with terms ranging from five to twenty years (see Notes 3
and 8).

Accounting for Guarantees. On January 1, 2003, we adopted Financial
Accounting Standards Board Interpretation (FIN) No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others. FIN No. 45 requires that we record a liability for
guarantees, including financial performance and fair value guarantees, issued
after December 31, 2002, at their fair value when they are issued. There was no
initial financial statement impact of adopting this standard.

Stock-Based Compensation. We account for our stock-based compensation
plans using the provisions of Accounting Principles Board Opinion (APB) No. 25,
Accounting for Stock Issued to Employees, and its related interpretations. Had
we accounted for our stock option grants using SFAS No. 123, Accounting for
Stock-Based Compensation, rather than APB No. 25, the income and per share
impacts of stock-based compensation on our financial statements would have been
different. The following tables show the impact on net income (loss) and
earnings (losses) per share had we applied SFAS No. 123:

3. ACQUISITIONS AND CONSOLIDATIONS

Acquisitions

During the second quarter of 2003, we acquired 100 percent of the third
party interests in our Chaparral and Gemstone investments, which have
historically been accounted for as equity investments. With these acquisitions,
we began consolidating these investments in our financial statements. Each of
these acquisitions is discussed below.

Chaparral. As discussed more completely in our 2002 Form 10-K, we entered
into our Chaparral investment in 1999 to expand our domestic power generation
business. Chaparral owns or has interests in 34 power plants in the United
States that have a total generating capacity of 5,592 megawatts. These plants
are primarily concentrated in the Northeast and Western United States. Chaparral
also owns several companies that own and perform under long-term power
agreements.

As of December 31, 2002, we owned 20 percent of Chaparral, and the
remaining 80 percent was owned by Limestone Electron Trust. We acquired
Limestone's 80 percent interest in Chaparral during 2003 in two transactions.
First, in March 2003, we acquired an additional 70 percent interest in Chaparral
when we purchased a $1 billion interest in Limestone. Limestone used these
proceeds to retire notes that were previously guaranteed by us. Although we
increased our economic interest in Chaparral with the purchase of this interest
in Limestone, we did not obtain any additional voting rights in Chaparral so we
continued to account for our investment in Chaparral using the equity method of
accounting. In May 2003, we paid $175 million to acquire the remaining third
party interest in Limestone, and all of Chaparral's remaining voting rights.
Upon this acquisition, we began consolidating Chaparral's assets and
liabilities. In addition, since we acquired Chaparral in multiple transactions
(also referred to as a step acquisition), we reflected Chaparral's results of
operations in our income statement as though we acquired it on January 1, 2003.
Although this did not change our net income for the previously reported first
quarter of 2003, it did impact the individual components of our income statement
by increasing our revenues by $76 million, operating expenses by $80 million,
other income (expense) by $53 million, interest expense by $67 million and
distributions on preferred interests in subsidiaries by $18 million. Had we
acquired Chaparral effective January 1, 2002, our revenues for the quarter and
six months ended June 30, 2002, would have been higher by $48 million and $84
million, our operating income for the quarter and six months ended June 30,
2002, would have been lower by $35 million and $69 million, and our net income
for the quarter and six months ended June 30, 2002, would have been lower by $28
million and $5 million. For the quarter and six months ended June 30, 2002, our
basic and diluted earnings per share would have been lower by $0.06 and $0.01
per common share.

The $175 million we paid to acquire the remaining 10 percent interest in
Limestone along with the remaining voting rights of Chaparral, was negotiated
based, in large part, on the terms of the Chaparral agreements. Under those
terms, we had the option to either provide for a payment to the third party
equity holder in exchange for their remaining interests, or allow the third
party equity holders to liquidate the assets of Chaparral, the proceeds of which
would first be applied to the payment of the agreed amount to them. If we had
elected to allow the third party equity holders to exercise their liquidation
rights, Limestone would have controlled the liquidation process and would not
necessarily have been motivated to achieve the maximum value for the assets. In
order to protect our interests, maximize the recoverable value of the assets and
obtain

9

the flexibility to manage the assets of Chaparral, regardless of whether these
assets are ultimately sold or held and used in our ongoing business, we chose to
redeem the third party equity holder's interests for the agreed upon amount.

During the first quarter of 2003, as a result of our additional investment
in Limestone, coupled with a number of developments including a general decline
in power prices, declines in counterparty credit ratings, the decline in our own
credit ratings, adverse developments at several projects wholly or partially
owned by Chaparral, our exit from the power contract restructuring business and
generally weaker economic conditions in the unregulated power industry, we
evaluated whether the carrying value of our investment in Chaparral was less
than its fair value. We also evaluated whether any declines that resulted from
our analysis would be considered temporary (or expected to turn around within
the next nine to twelve months). Based on our analysis, we determined that the
fair value of Chaparral (based on its discounted expected net cash flows) was
not sufficient to recover the carrying value of our investment. As a result, we
recorded an impairment of our investment in Chaparral of $207 million, before
income taxes, during the quarter ended March 31, 2003.

The following table presents the total assets and liabilities of Chaparral
prior to our consolidation and the elimination of intercompany transactions and
reflects the allocation of our purchase price of $1,175 million, plus our
initial investment of $252 million less our first quarter impairment of $207
million (in millions):

Total assets
Current assets............................................ $ 312
Assets from price risk management activities, current..... 190
Investments in unconsolidated affiliates.................. 1,347
Property, plant and equipment, net........................ 561
Assets from price risk management activities,
non-current............................................ 1,085
Other assets.............................................. 451
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Total assets......................................... 3,946
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Total liabilities
Current liabilities....................................... 906
Liabilities from price risk management activities,
current................................................ 19
Long-term debt, less current maturities................... 1,415(1)
Liabilities from price risk management activities,
non-current............................................ 34
Other liabilities......................................... 352
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Total liabilities.................................... 2,726
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Net assets.................................................. $1,220
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(1) This debt is recourse only to the project or plant to which it relates.

Our initial allocation of the purchase price was based on preliminary
valuations performed by an independent third party consultant. These preliminary
valuations were derived using discounted cash flow analysis and other valuation
methods. In addition, as part of our asset sale program, we are in the process
of obtaining bids from potential buyers for some of the assets we acquired. We
expect to finalize our purchase price allocation when we receive the final
valuation report from our consultant and have evaluated these bids. We believe
this will be completed by the end of 2003.

Gemstone. As discussed more completely in our 2002 Form 10-K, we entered
into the Gemstone investment in 2001 to finance five major power plants in
Brazil. Gemstone had investments in three power projects: Macae, Porto Velho and
Araucaria. These plants have a total generating capacity of 1,788 megawatts.
Gemstone also owned a preferred interest in two of our consolidated power
projects, Rio Negro and Manaus. In January 2003, the third party equity investor
in Gemstone, Rabobank, notified us that it planned to remove us as the manager
of Gemstone. Instead of being removed, we elected to buy out the third party
investor for approximately $50 million in April 2003. The results of Gemstone's
operations have been included in our consolidated financial statements beginning
April 1, 2003. Had the acquisition been effective January 1, 2002, our revenues,
operating income, and net income for the quarter and six months ended June 30,
2002, as well as the quarter ended March 31, 2003 would not have been
significantly different, and basic and diluted earnings per share would have
been unaffected.

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The allocation of the fair value of $50 million to the assets acquired and
liabilities assumed upon our consolidation of Gemstone in April 2003 is as
follows (in millions):

Fair value of assets acquired
Note and interest receivable.............................. $ 122
Investments in unconsolidated affiliates.................. 892
Other assets.............................................. 3
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Total assets........................................... 1,017
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Fair value of liabilities assumed
Note and interest payable................................. 967
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Total liabilities...................................... 967
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Net assets acquired......................................... $ 50
======

Our initial allocation of the purchase price was based on preliminary
valuations performed by an independent third party consultant. These preliminary
valuations were derived using discounted cash flow analysis and other valuation
methods. We will finalize our purchase price allocation when we receive the
final valuation report from our consultant, which we anticipate will be by the
end of the third quarter of 2003.

Prior to our acquisitions of Chaparral and Gemstone, we carried them as
investments in unconsolidated affiliates and had other balances, including loans
and notes with them. These balances were eliminated when we consolidated
Chaparral and Gemstone. As a result, the overall impact on our consolidated
balance sheet from acquiring these investments was different than the individual
assets and liabilities acquired. The impact of these acquisitions on our
consolidated balance sheet was an increase in assets of $2.1 billion, an
increase in liabilities of approximately $2.4 billion, including an increase in
debt of approximately $2.2 billion, and a reduction of preferred interests in
consolidated subsidiaries of approximately $0.3 billion.

Consolidations

During the second quarter of 2003, we amended several financing and other
agreements in connection with our new $3 billion revolving credit agreement (see
Note 16). These amendments were completed to accomplish several objectives,
including simplifying our capital structure by eliminating several "off-balance
sheet" obligations, replacing them with direct obligations, and strengthening
the overall collateral package available to our financial lenders.

We amended an operating lease agreement at our Lakeside telecommunications
facility to add a guarantee to the party who had invested in the lessor and to
allow the third party and certain lenders to share in the collateral package
that was provided to the banks under our new $3 billion revolving credit
facility. This guarantee reduced the investor's risk of loss of its investment,
and therefore resulted in our controlling the lessor. As a consequence, we
consolidated the lessor. The consolidation of Lakeside resulted in an increase
in our property, plant and equipment of approximately $275 million and long-term
debt of approximately $275 million. Additionally, upon the consolidation, we
recorded an asset impairment charge of approximately $127 million representing
the difference between the facility's estimated fair value and the residual
value guarantee under the lease. Prior to its consolidation, this difference was
being periodically expensed as part of operating lease expense over the term of
the lease.

We amended an operating lease at our Aruba facility to provide a full
guarantee to the parties who invested in the lessor and to allow the third party
and certain lenders to share in the collateral package that was provided to the
banks under our new $3 billion revolving credit facility. This guarantee reduced
the investor's risk of loss of its investment, and therefore resulted in our
controlling the lessor. As a result, we consolidated the lessor during the
second quarter of 2003, increasing our total fixed assets by $370 million (prior
to an impairment charge we recorded on these assets of $50 million) and
long-term debt by $370 million. As a result of our intent to exit substantially
all of our petroleum operations, these leased assets and associated debt were
reclassified as discontinued operations.

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We modified our Clydesdale financing arrangement to convert the third party
investor's (Mustang Investors, L.L.C.) preferred ownership in one of our
consolidated subsidiaries into a term loan that matures in equal quarterly
installments through 2005. This change simplified our balance sheet and provided
us with a fixed schedule of payments. We also acquired a $10 million preferred
interest in Mustang and guaranteed all of Mustang's equity holder's obligations.
As a result of this amendment, we were required to consolidate Mustang which
increased our long-term debt by $743 million and decreased our preferred
interests of consolidated subsidiaries by $753 million. Our $10 million
preferred interest in Mustang was eliminated upon its consolidation (see Note
17).

4. DIVESTITURES

During 2003, we completed or announced the sale of a number of assets and
investments in each of our business segments. The gains and losses on these
sales reflected below do not include any asset impairments we may have
recognized at the time we decided to sell the asset or investment. See Notes 8,
11 and 21 for a discussion of impairments on long-lived assets, assets treated
as discontinued operations and investments in unconsolidated affiliates.

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(1) Includes $11 million of net proceeds related to the working capital of the
assets sold. Working capital is reflected in cash flows from operating
activities rather than proceeds from asset sales.

(2) Of this gain, $16 million relates to sales of long-lived assets (included in
gain or loss on long-lived assets), while $30 million relates to sales of
investments (included in earnings or losses from unconsolidated affiliates).

12

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(1) Amounts on sales that have been announced or are under contract for sale are
estimates, subject to customary regulatory approvals, final sale
negotiations and other conditions.

(2) See Note 18 for a discussion of regulatory matters that could impact this
sale.

(3) These sales were completed in July 2003.

(4) We have entered into a non-binding letter of intent to sell these assets.

Each period, we evaluate our potential asset sales to determine if any meet
the criteria as held for sale or as discontinued operations under SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets. The more
significant criteria we evaluate are whether:

- Management, with the authority to approve the sale, commits to a plan to
sell the asset;

- The asset is available for immediate sale in its present condition;

- An active program to locate a buyer and other actions required to
complete the sale have been started; and

- The sale of the asset is probable and is expected to be completed within
one year.

To the extent that all of these criteria as well as the other requirements
of SFAS No. 144 are met, we classify an asset as held for sale or, if
appropriate, discontinued operations. For example, our Board of Directors (or a
designated subcommittee of our Board) is required to approve asset dispositions
greater than specified thresholds. Unless specific approval is received by our
Board (or a designated subcommittee) by the end of a given reporting period to
commit to a plan to sell an asset, we would not classify it as held for sale or
discontinued operations in that reporting period even if it is management's
stated intent to sell the asset. As of December 31, 2002, we had $64 million of
long-lived assets classified as held for sale and reflected in current assets in
our balance sheet, all of which had been sold as of June 30, 2003. We also had
approximately $1.7 billion of assets classified as discontinued operations (see
Note 11).

We continue to evaluate assets we may sell in the future. We have announced
that we intend to pursue the sale of our telecommunications business and
domestic power assets. These activities are in the early stages, and we have not
entered into any definitive agreements. Furthermore, we are not certain what
form these possible divestitures may take (e.g. outright sale or joint venture
arrangement). As specific assets are identified for sale, we will be required to
record them at the lower of fair value or historical cost. This may require us
to assess them for possible impairment. The amounts of the impairment charges,
if any, will generally be based on estimates of the expected fair value of the
assets as determined by market data obtained through the sales process or by
assessing the probability-weighted cash flows of the asset. For a discussion of
impairment charges incurred on our long-lived assets, see Note 8; for
impairments on discontinued operations, see Note 11; and for impairments on our
investments in unconsolidated affiliates, see Note 21.

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In February 2002, we sold CIG Trailblazer Gas Company, L.L.C., a company
which owned pipeline expansion rights, to a third party. Our Pipelines segment
recorded a gain on this sale of approximately $11 million.

In March 2002, we sold natural gas and oil properties located in east and
south Texas. Net proceeds from these sales were approximately $500 million. We
did not recognize a gain or loss on these sales because we apply the full cost
method of accounting for our oil and natural gas operations (which requires that
gains or losses on property sales are only recognized in certain circumstances).

In April 2002, we sold midstream assets for approximately $752 million to
GulfTerra Energy Partners, L.P. (formerly known as El Paso Energy Partners,
L.P.), a publicly traded master limited partnership of which our subsidiary
serves as the general partner. Net proceeds from this sale were approximately
$556 million in cash, common units of GulfTerra with a fair value of $6 million
and the partnership's interest in the Prince tension leg platform including its
nine percent overriding royalty interest in the Prince production field with a
combined fair value of $190 million. Because most of the assets had recently
been acquired in a purchase transaction and accordingly had been recorded at
fair value, no gain or loss was recognized on this sale.

In May and June 2002, we also completed sales of natural gas and oil
properties, a natural gas gathering system and a natural gas plant. Net proceeds
from these sales were approximately $325 million. We recognized a gain on
long-lived assets of $10 million, $6 million after taxes, on the natural gas
gathering system and the plant. Our 2002 net realized gains also included sales
of non-full cost pool assets in our Production segment and gains and losses on
other sales transactions.

5. RESTRUCTURING CHARGES

During 2003, we incurred restructuring charges in connection with our
ongoing liquidity enhancement and cost saving efforts. For the quarter and six
months ended June 30, 2003, we recognized restructuring costs totaling $31
million and $100 million. Of this amount, $31 million and $56 million related to
employee severance costs from reductions in our work force. Through June 30,
2003, we have terminated approximately 1,860 full-time positions. Approximately
$34 million of these severance costs had been paid as of June 30, 2003. We also
recognized charges of approximately $44 million during the first quarter of
2003, associated with our liquefied natural gas (LNG) business following our
February 2003 announcement to minimize our involvement in that business. This
charge related to amounts paid for canceling our option to charter a fifth ship
to transport LNG from supply areas to domestic and international market centers
and to restructure the remaining charter agreements. We recorded all
restructuring costs as operation and maintenance expenses in our income
statement, and these charges impacted the results of all our business segments.

During the second quarter of 2002, we incurred $63 million of restructuring
charges. In May 2002, we completed an employee restructuring across all of our
operating segments which resulted in the termination of approximately 350
full-time positions. We incurred $23 million of employee severance and
termination costs. Employee severance costs included severance payments and
costs for pension benefits settled and curtailed under existing benefit plans.
We also incurred fees of $40 million to eliminate the stock price and credit
rating triggers related to our Gemstone and Chaparral investments. These
restructuring charges were reflected as operation and maintenance expense in our
income statement.

6. WESTERN ENERGY SETTLEMENT

In June 2003, we entered into two definitive agreements (referred to as the
Western Energy Settlement) with a number of public and private claimants,
including the states of California, Washington, Oregon and Nevada, to resolve
the principal litigation, claims and regulatory proceedings against us and our
subsidiaries relating to the sale or delivery of natural gas and electricity
from September 1996 to the settlement date. Subject to court and regulatory
approvals, the settlement will include payments of cash, the issuance of common
stock and the reduction in prices under two power supply contracts.

14

These definitive settlement agreements modified the agreement in principle
reached on March 20, 2003, as discussed in our 2002 Form 10-K, and resulted in
an additional obligation and a pre-tax charge of $123 million during the second
quarter of 2003. The charge was primarily a result of changes in the timing of
settlement payments and changes in the value of the common stock to be issued in
connection with the definitive settlement agreements. This charge was also in
addition to accretion expense on the originally recorded discounted Western
Energy Settlement obligation and other charges related to the settlement
totaling $24 million, all of which were included as part of operation and
maintenance expense during the second quarter of 2003. For the six months ended
June 30, 2003, these accretion and other charges were approximately $43 million.
As of June 30, 2003, $609 million of the total Western Energy Settlement
obligation of $1,045 million was reflected as a current liability. The current
portion includes a $213 million obligation to issue approximately 26.4 million
shares of our common stock since we estimate the finalization of the settlement
to occur within the next twelve months. The stock obligation will continue to
impact our income statement, either positively or negatively, based on changes
in our stock price until the settling parties elect to have the shares issued on
their behalf. As of June 30, 2003, $10 million of the total obligation had been
paid. Future payments will be reflected in our cash flows from operations. In
addition, in July 2003, EPNG, our subsidiary, issued $355 million of senior
notes, the net proceeds from which will be placed in an escrow account (once
established) to be used to satisfy a portion of the obligation. For a further
discussion of the Western Energy Settlement, see Note 18.

We will be required to provide collateral for this obligation in the form
of oil and gas reserves, other assets to be agreed upon or cash and letters of
credit. The initial collateral requirement will be between $455 million and $592
million depending on the type of collateral posted.

7. CEILING TEST CHARGES

Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to determine whether the carrying
value of natural gas and oil properties exceeds the present value of future net
revenues, discounted at 10 percent, plus the lower of cost or fair market value
of unproved properties, net of related income tax effects.

For the quarter and six months ended June 30, 2003, our ceiling test
charges were less than $1 million. For the six months ended June 30, 2002, we
recorded ceiling test charges of $267 million, of which $33 million was charged
during the first quarter and $234 million during the second quarter. The charges
include $226 million for our Canadian full cost pool, $24 million for our
Turkish full cost pool, $10 million for our Brazilian full cost pool and $7
million for Australia and other international production operations. These
write-downs were based upon the daily posted natural gas and oil prices as of
June 30, 2002, adjusted for oilfield or natural gas gathering hub and wellhead
price differences, as appropriate. The charge for our Canadian full cost pool
primarily resulted from a low daily posted price for natural gas at the end of
the second quarter of 2002, which was approximately $1.43 per MMBtu.

We use financial instruments to hedge against the volatility of natural gas
and oil prices. The impact of these hedges was considered in determining our
ceiling test charges and will be factored into future ceiling test calculations.
The charges for our international cost pools would not have changed had the
impact of these hedges not been included in calculating our 2002 ceiling test
charges since we do not significantly hedge our international production
activities.

15

8. (LOSS) GAIN ON LONG-LIVED ASSETS

Our (loss) gain on long-lived assets from continuing operations consists of
net realized gains and losses on sales of long-lived assets and impairments of
long-lived assets, and was as follows:

- ---------------

(1) These amounts exclude approximately $987 million and $1.3 billion of asset
impairments for the quarter and six months ended June 30, 2003, related to
our petroleum operations that were reclassified as discontinued operations.

Net Realized Gain

Our 2003 net realized gains were primarily related to the sales of the
north Louisiana and Mid-Continent midstream assets in our Field Services
segment, the Table Rock sulfur extraction facility in our Pipelines segment,
non-full cost pool assets in our Production segment and the sales of assets in
our Corporate segment. Our 2002 net realized gains were primarily related to the
sales of pipeline expansion rights in our Pipelines segment, non-full cost pool
assets in our Production segment and the sale of the Dragon Trail processing
plant in our Field Services segment.

Asset Impairments

We are required to test assets for recoverability whenever events or
changes in circumstances indicate that the carrying amount of these assets may
not be fully recoverable. One triggering event is the expectation that it is
more likely than not that we will sell or dispose of the asset before the end of
its estimated useful life. Based on our intent to dispose of a number of our
assets, we tested those assets for recoverability during the first and second
quarters of 2003. As a result of these assessments, we recognized impairment
charges in our Corporate segment of approximately $396 million related to our
telecommunications business. This charge includes an impairment of our
investment in the wholesale metropolitan transport services, primarily in Texas,
of $269 million (including a writedown of goodwill of $163 million) and an
impairment of our Lakeside Technology Center facility of $127 million based on
probability-weighted scenarios of what the asset could be sold for in the
current market. We also recognized impairments of $31 million in our Merchant
Energy segment as a result of our plan to reduce our involvement in the LNG
business and $14 million in our Production segment related to non-full cost
assets in Canada. For additional asset impairments on our discontinued
operations and investments in unconsolidated affiliates, see Note 11 and Note
21.

9. OTHER EXPENSES

Other expenses for the quarter and six months ended June 30, 2003, were $86
million and $129 million, including foreign currency losses of $33 million and
$46 million resulting from the impact of foreign currency fluctuations on our
Euro-denominated debt in the first and second quarters of 2003. In the second
quarter of 2003, we also incurred a $37 million loss on the early extinguishment
of our $1.2 billion bridge loan (see Note 16).

Other expenses for the quarter and six months ended June 30, 2002, were $58
million and $263 million, including foreign currency losses of $45 million
resulting from the impact of foreign currency fluctuations on our
Euro-denominated debt in the second quarter of 2002. Also included in other
expenses were a $56 million impairment of our investment in the Costanera power
plant, a cost-based investment in Argentina, and a $90 million steam contract
termination fee paid to our Eagle Point refinery (in the petroleum division) by
our Eagle Point Cogeneration facility (in our global power division of our
Merchant Energy segment) in the first

16

quarter of 2002. These amounts were eliminated in consolidation since the income
associated with the petroleum division is reflected in discontinued operations
while the power division's expense is included as part of our Merchant Energy's
segment results. In the first quarter of 2002, other expenses also included $52
million of minority interest in our consolidated subsidiaries.

10. INCOME TAXES

Income taxes included in income (loss) from continuing operations for the
periods ended June 30, 2003 and 2002 were as follows:

For the six months ended June 30, our effective tax rates were different
than the statutory rate of 35 percent due to the following:

11. DISCONTINUED OPERATIONS

Petroleum Operations

In June 2003, our Board of Directors authorized the sale of substantially
all of our petroleum operations, including our Aruba refinery, our Unilube
blending operations, our domestic and international terminalling facilities and
our petrochemical and chemical plants. The Board's actions were in addition to
previous actions taken when they approved the sales of our Eagle Point refinery,
our asphalt business and our lease crude operations. Based on our intent to
dispose of these operations, we were required to adjust these assets to their
estimated fair value. As a result, we recognized a pre-tax charge of
approximately $987 million during the second quarter of 2003 related to our
petroleum and chemical assets, including a $50 million impairment charge related
to the portion of the Aruba refinery we leased under an operating lease. See
Note 3 for a discussion of this lease. Our second quarter charge was in addition
to the $350 million pre-tax impairment charge recognized during the first
quarter of 2003 when we announced our intent to sell our Eagle Point refinery
and several chemical assets. These impairments were based on a comparison of the
carrying value of the underlying assets to their estimated fair value. Our fair
value estimates were based on preliminary market data obtained through the early
stages of the sales process and an analysis of expected discounted cash flows.
The magnitude of these charges was impacted by a number of factors, including
the nature of the assets and our established time frame for completing the
sales, among other factors.

17

In the second quarter of 2003, we entered into a product offtake agreement
for the sale of a number of the products produced at our Aruba refinery. As a
result of this contract, the buyer became the single largest customer of our
Aruba refinery, purchasing approximately 75 percent of the products produced at
that plant. The agreement is for one year with two one-year extensions at the
buyer's option. We have the right to terminate the agreement when the refinery
is sold.

Coal Mining Operations

In the latter part of 2002 and the first quarter of 2003, we sold our coal
mining operations. These operations consisted of fifteen active underground and
two surface mines located in Kentucky, Virginia and West Virginia. Following the
authorization of the sale by our Board of Directors, we compared the carrying
value of the underlying assets to our estimated sales proceeds, net of estimated
selling costs, based on bids received in the sales process. Because this
carrying value was higher than our estimated net sales proceeds, we recorded an
impairment charge of $148 million in our total loss from discontinued operations
in the second quarter of 2002.

Our petroleum operations and our coal mining operations, which were
historically included in our Merchant Energy segment, have been reclassified as
discontinued operations in our financial statements for all of the historical
periods presented. We will also be required to reflect them as discontinued
operations for all historical annual periods previously reported in our 2002
Form 10-K. In addition, we reclassified all of the assets and liabilities of our
remaining petroleum markets business as of June 30, 2003 to other current assets
and liabilities. The summarized financial results and financial position data of
our discontinued operations were as follows:

Financial Position Data

JUNE 30, 2003
Assets of discontinued operations
Accounts and notes receivables..................... $ 423 $ -- $ 423
Inventory.......................................... 435 -- 435
Other current assets............................... 66 -- 66
Property, plant and equipment, net................. 673 -- 673
Other non-current assets........................... 114 -- 114
------- ----- -------
Total assets.................................... $ 1,711 $ -- $ 1,711
======= ===== =======
Liabilities of discontinued operations
Accounts payable................................... $ 394 $ -- $ 394
Other current liabilities.......................... 129 -- 129
Notes payable...................................... 370 -- 370
Environmental remediation reserve.................. 36 -- 36
------- ----- -------
Total liabilities............................... $ 929 $ -- $ 929
======= ===== =======

DECEMBER 31, 2002
Assets of discontinued operations
Accounts and notes receivables...................... $1,229 $ 29 $1,258
Inventory........................................... 635 14 649
Other current assets................................ 80 1 81
Property, plant and equipment, net.................. 1,950 46 1,996
Other non-current assets............................ 65 16 81
------ ---- ------
Total assets..................................... $3,959 $106 $4,065
====== ==== ======
Liabilities of discontinued operations
Accounts payable.................................... $1,154 $ 20 $1,174
Other current liabilities........................... 180 5 185
Environmental remediation reserve................... 86 15 101
Other non-current liabilities....................... 1 -- 1
------ ---- ------
Total liabilities................................ $1,421 $ 40 $1,461
====== ==== ======

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12. CUMULATIVE EFFECT OF ACCOUNTING CHANGES

On January 1, 2003, we adopted SFAS No. 143. As a result, we recorded a
cumulative effect of an accounting change of approximately $22 million, net of
income taxes (see Note 2).

On January 1, 2002, we adopted SFAS No. 141, Business Combinations, and
SFAS No. 142, Goodwill and Other Intangible Assets. As a result of our adoption
of these standards on January 1, 2002, we stopped amortizing goodwill, and
recognized a pretax and after-tax gain of $154 million related to the write-off
of negative goodwill as a cumulative effect on an accounting change in our
income statement.

In the second quarter of 2002, we also adopted DIG Issue No. C-16, Scope
Exceptions: Applying the Normal Purchases and Sales Exception to Contracts that
Combine a Forward Contract and Purchased Option Contract. One of our
unconsolidated affiliates, the Midland Cogeneration Venture Limited Partnership,
recognized a gain on one fuel supply contract upon adoption of this new rule,
and we recorded a gain of $14 million, net of income taxes, as a cumulative
effect of an accounting change in our income statement for our proportionate
share of this gain.

13. EARNINGS PER SHARE

We calculated basic and diluted earnings per common share amounts as
follows for the periods ended June 30:

For the quarter and six months ended June 30, 2003, there were a total of
42 million of potentially dilutive securities excluded from the determination of
average common shares outstanding because we had net losses in these periods.
For the quarter and six months ended June 30, 2002, a total of 16 million shares
of potentially dilutive securities was excluded based on our income levels. The
excluded securities included stock options, restricted stock, equity security
units, shares we are obligated to issue at the direction of the settling
claimants under our Western Energy Settlement, trust preferred securities and
convertible debentures.

14. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

The following table summarizes the carrying value of our price risk
management assets and liabilities as of June 30, 2003 and December 31, 2002:

- ---------------

(1) Trading contracts are derivative contracts that historically have been
entered into for purposes of generating a profit or benefiting from
movements in market prices.

(2) Included in our trading and non-trading activities are $219 million of
intercompany derivative positions that eliminate in consolidation, and have
no impact on our consolidated price risk management activities.

(3) Net assets from price risk management activities include current and
non-current assets and current and non-current liabilities from price risk
management activities on the balance sheet.

21

As of June 30, 2003, other derivatives include $2,199 million of derivative
contracts primarily related to power restructuring activities, $1,239 million of
which relates to contracts we acquired in connection with our acquisition of
Chaparral in the second quarter of 2003 and $960 million associated with our
power restructuring activities at our Eagle Point Cogeneration and our Capitol
District Energy Center Cogeneration Associates facilities. For a further
discussion of our Chaparral acquisition, see Note 3, and for a further
discussion of our power restructuring activities, see our 2002 Form 10-K.
Because of the significant increase in our power contract restructuring
positions as a result of our acquisition of Chaparral, our exposure has
increased related to changes in the discount rates. These rates are used in the
determination of the fair values of these positions. For a discussion of these
interest rate risks, see Item 3, Quantitative and Qualitative Disclosures About
Market Risk. The remaining balances in other derivatives, unrealized losses of
$10 million and $9 million as of June 30, 2003 and December 31, 2002, relate to
derivative positions that no longer qualify as cash flow hedges under SFAS No.
133, Accounting for Derivative Instruments and Hedging Activities, because they
were designated as hedges of anticipated future production on natural gas and
oil properties that were sold during 2002.

15. INVENTORY

- ---------------

(1) As a result of our intent to dispose of our petroleum and chemical assets,
inventory balances totaling $435 million and $635 million as of June 30,
2003 and December 31, 2002, have been reclassified as assets of discontinued
operations (see Note 11).

(2) We recorded these amounts as other non-current assets in our balance sheet.

16. DEBT AND OTHER CREDIT FACILITIES

Our debt and other credit facilities consist of both short and long-term
borrowings and notes with our affiliated companies. During the first six months
of 2003, we entered into a new $3 billion revolving credit facility, acquired
and consolidated a number of entities with existing debt, refinanced
shorter-term obligations

22

with longer-term borrowings and redeemed and eliminated preferred interests in
our subsidiaries. A summary of our actions is as follows (in millions):

Debt obligations, December 31, 2002......................... $18,571
Acquisitions and consolidations:
Clydesdale restructuring.................................. 743
Gemstone acquisition...................................... 1,013
Chaparral acquisition..................................... 1,565(2)
Bank refinancings:
Lakeside lease......................................... 275
Aruba lease(1)......................................... --
Principal amounts borrowed(3)............................... 3,695
Repayments of principal(3).................................. (2,108)
Elimination of affiliate obligations........................ (326)
Other....................................................... 26
-------
Total debt obligations, June 30, 2003..................... $23,454
=======

- ---------------

(1) Included in liabilities of discontinued operations.

(2) This debt is project-related debt that is non-recourse to us.

(3) Includes $500 million of borrowings and repayments under our revolving
credit agreements.

As discussed further in Note 17, our Clydesdale and Trinity River
financings were restructured in 2003 resulting in their reclassification from
preferred interests of consolidated subsidiaries to long-term debt. The Trinity
River financing was redeemed with a portion of the $3.7 billion of principal
borrowings, specifically the $1.2 billion two-year term loan issued in March
2003.

Short-Term Debt and Credit Facilities

At December 31, 2002, our weighted average interest rate on our short-term
credit facilities was 2.69%. We had the following short-term borrowings and
other financing obligations:

Credit Facilities

In April 2003, we entered into a new $3 billion revolving credit facility,
with a $1.5 billion letter of credit sublimit, which matures on June 30, 2005.
This facility replaces our previous $3 billion 364-day revolving credit
facility. In addition, approximately $1 billion of other financing arrangements
(including the leases discussed in Notes 3 and 11, letters of credit and other
facilities) were amended to conform our obligations to the new $3 billion
revolving credit facility. Our $3 billion revolving credit facility and these
other financing arrangements are secured by our equity in EPNG, Tennessee Gas
Pipeline Company (TGP), ANR Pipeline Company (ANR), Wyoming Interstate Company
Ltd. (WIC), ANR Storage Company, Southern Gas Storage Company and our common and
Series C units in GulfTerra. This credit facility and other financing
arrangements are also collateralized by our equity in the companies that own the
assets that collateralize our Clydesdale financing arrangement. For a discussion
of Clydesdale, see Notes 3 and 17. EPNG and TGP remain jointly and severally
liable for any amounts outstanding under the new $3 billion revolving credit
facility through August 19, 2003. Except for the following conditions, after
that date EPNG and TGP will be

23

liable only for the amounts they borrow under the $3 billion revolving credit
facility. If, on August 19, 2003, (1) an event of default is continuing with
respect to the $3 billion revolving credit facility or (2) we, or any of the
subsidiary guarantors under the facility or any of the restricted subsidiaries
(each as defined in the $3 billion revolving credit facility) are subject to a
bankruptcy or similar proceeding, then EPNG and TGP will continue to be jointly
and severally liable for any amounts outstanding under the $3 billion revolving
credit facility until none of the events described in (1) or (2) above exists.
As of August 11, 2003, none of these conditions existed. Once EPNG's and TGP's
joint and several liabilities expire on August 19, 2003, there are no
circumstances in which EPNG and TGP could again become liable under our $3
billion facility except for amounts borrowed by them under the $3 billion
revolving credit facility.

The $3 billion revolving credit facility has a borrowing cost of LIBOR plus
350 basis points and letter of credit fees of 350 basis points. As of June 30,
2003, we had $1.5 billion outstanding and $1.1 billion of letters of credit
issued under the $3 billion revolving credit facility. The amounts borrowed were
classified as non-current in our balance sheet as of June 30, 2003.

We also maintained a $1 billion revolving credit facility, which expired on
August 4, 2003. EPNG and TGP were also borrowers under this facility. As of June
30, 2003, no amounts were outstanding, and $132 million of letters of credit
were issued. The $132 million of letters of credit expired or were reissued
under the $3 billion revolving credit facility prior to August 4, 2003.

The availability of borrowings under our credit facilities and borrowing
agreements is subject to conditions, which we currently meet. These conditions
include compliance with the financial covenants and ratios required by those
agreements, absence of default under the agreements, and continued accuracy of
the representations and warranties contained in the agreements.

Long-Term Debt Obligations

During 2003, we have entered into, consolidated and retired several debt
financing obligations:

- ---------------

(1) Net proceeds were primarily used to repay maturing long-term debt, redeem
preferred interests of consolidated subsidiaries, repay short-term
borrowings and other financing obligations and for other general corporate
and investment purposes.

(2) Net proceeds from the May 2003 issuance were used to repay the $1.2 billion
LIBOR based two-year term loan. The proceeds from the two-year term loan
were used to repay our Trinity River financing.

(3) This debt is project-related debt that is non-recourse to us.

24

- ---------------

(1) Net proceeds from the May 2003 issuance were used to repay the $1.2 billion
LIBOR based two-year term loan. The proceeds from the two-year term loan
were used to repay our Trinity River financing.

Restrictive Covenants

As part of our new $3 billion revolving credit facility, several of our
significant covenants changed. Our ratio of debt to capitalization (as defined
in the new revolving credit facility) cannot exceed 75 percent, instead of the
previous maximum of 70 percent (as was defined in the prior credit facility
agreement). For purposes of this calculation, we are allowed to add back to
equity non-cash impairments of long-lived assets and exclude the impact of
accumulated other comprehensive income, among other items. Additionally, in
determining debt under the agreements, we are allowed to exclude certain
non-recourse project financings, among other items. The covenant relating to
subsidiary debt was removed. Also, EPNG, TGP, ANR, and upon the maturity of the
Clydesdale financing transaction, CIG cannot incur incremental debt if the
incurrence of this incremental debt would cause their debt to EBITDA ratio (as
defined in the new revolving credit facility agreement) for that particular
company to exceed 5 to 1. Additionally, the proceeds from the issuance of debt
by the pipeline company borrowers can only be used for maintenance and expansion
capital expenditures or investments in other FERC-regulated assets, to fund
working capital requirements, or to refinance existing debt. As of June 30,
2003, we were in compliance with these covenants.

17. PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

As further described below, we restructured our Trinity River and
Clydesdale financing arrangements as well as eliminated the preferred interests
in our subsidiaries held by Gemstone during 2003. A summary of our actions is as
follows (in millions):