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
====== ==== ======

19

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 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):

December 31, 2002........................................... $3,255
Redemption of Trinity River............................... (980)
Refinancing and redemptions of Clydesdale................. (950)
Elimination of Gemstone minority interest................. (300)
------
June 30, 2003............................................... $1,025
======

For a further discussion of our debt and credit facilities see Note 16.

Trinity River. In 1999, we entered into the Trinity River financing
arrangement to generate funds for investment and general operating purposes. As
of December 31, 2002, approximately $980 million was outstanding under this
arrangement. In the first quarter of 2003, we redeemed the entire $980 million
of the outstanding preferred interests under the arrangement with a portion of
the proceeds from the issuance of a $1.2 billion two-year term loan (see Note
16).

Clydesdale. In 2000, we entered into the Clydesdale financing arrangement
to generate funds for investment and general operating purposes. As of December
31, 2002, approximately $950 million was outstanding under this arrangement.
During the first quarter of 2003, we retired approximately $189 million of

25

the third-party member interests in Clydesdale and an additional $8 million in
April 2003. Also, on April 16, 2003, we restructured the Clydesdale financing
arrangement whereby the remaining unredeemed preferred member interests of $753
million were converted to a term loan guaranteed by us. The new term loan
amortizes in equal quarterly amounts of $100 million over the next two years.
The term loan remains collateralized by the assets that historically supported
the Clydesdale transaction, consisting of a production payment from us, various
natural gas and oil properties and our equity in CIG, and is guaranteed by us.
We also purchased $10 million of preferred equity of the third party investor,
Mustang Investors, L.L.C., which, when coupled with the guarantee, resulted in
the consolidation of Mustang in the second quarter of 2003. The consolidation of
Mustang resulted in an increase in our long-term debt of approximately $743
million and a reduction in our preferred interests of consolidated subsidiaries
of approximately $753 million. As of June 30, 2003, the balance owed to third
parties under the Clydesdale financing arrangement was $643 million. In August
2003, we made a quarterly principal payment of $100 million on this term loan.

Gemstone. As of December 31, 2002, Gemstone owned $300 million in
preferred securities in two of our consolidated subsidiaries. In the second
quarter of 2003, we acquired 100 percent the holder of these preferred interests
and began consolidating this equity holder. As a result of this consolidation,
we eliminated this minority interest (see Note 3).

18. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Western Energy Settlement. On June 26, 2003, we announced that we had
executed definitive settlement agreements to resolve the principal litigation
and claims against us and our subsidiaries relating to the sale or delivery of
natural gas and/or electricity to or in the Western United States. Parties to
the settlement agreements include private class action litigants in California;
the governor and lieutenant governor of California; the attorneys general of
California, Washington, Oregon and Nevada; the California Public Utilities
Commission; the California Electricity Oversight Board; the California
Department of Water Resources; Pacific Gas and Electric Company (PG&E), Southern
California Edison Company, five California municipalities and six non-class
private plaintiffs. For a discussion of the charges taken in connection with the
Western Energy Settlement (see Note 6).

These definitive settlements were in addition to a structural settlement
announced on June 4, 2003 where we agreed to provide structural relief to the
settling parties. In the structural settlement, we agreed to do the following:

- Subject to the conditions in the settlement, provide 3.29 Bcf/d of
primary firm pipeline capacity on our EPNG system to California delivery
points during a five year period from the date of settlement, and not add
any firm incremental load to our EPNG system that would prevent it from
satisfying its obligation to provide this capacity;

- Construct a new $173 million, 320 million MMcf/d, Line 2000 Power-Up
expansion project, and forgo recovery of the cost of service of this
expansion until EPNG's next rate case before the Federal Energy
Regulatory Commission (FERC);

- Clarify the rights of Northern California shippers to recall some of
EPNG's system capacity (Block II capacity) to serve markets in PG&E's
service area; and

- With limited exceptions, bar any of our affiliated companies from
obtaining additional firm capacity on our EPNG pipeline system during a
five year period from the effective date of the settlement.

In connection with this structural settlement, a Stipulated Judgment was
filed with the United States District Court for the Central District of
California. This Stipulated Judgment provides for the enforcement of some of the
obligations contained in the structural settlement.

26

In the definitive settlement agreements announced on June 26, 2003, we
agreed to the following terms.

- We admitted to no wrongdoing;

- We will make cash payments totaling $95.5 million for the benefit of the
parties to the definitive settlement agreements subsequent to the signing
of these agreements. This amount represents the originally announced $102
million cash payment less credits for amounts that have been paid to
other settling parties;

- We agreed to pay amounts equal to the proceeds from the issuance of
approximately 26.4 million shares of our common stock on behalf of the
settling parties. If this issuance is completed prior to final approval
of the settlement agreements, the proceeds from any sale will be
deposited into an escrow account for the benefit of the settling parties
until final approval is received;

- We will eliminate the originally announced 20-year obligation to pay $22
million per year in cash by depositing $250 million in escrow for the
benefit of the settling parties within 180 days of the signing of the
definitive settlement agreements; this prepayment eliminates any
collateral that might have been required on the $22 million per year
payment over the next 20 years;

- We will pay $45 million in cash per year in semi-annual payments over a
20-year period rather than deliver natural gas as originally
contemplated. This long-term payment obligation is a direct obligation of
El Paso Corporation and El Paso Merchant Energy, L.P. (EPME) and will be
guaranteed by our subsidiary, EPNG. Upon final approval of the Master
Settlement Agreement, 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; and

- EPME will receive reduced payments due under a power supply transaction
with the California Department of Water Resources by a total of $125
million, pro rated on a monthly basis over the remaining 30 month term of
the transaction. The difference between the current payments and the
reduced payments will be placed into escrow for the benefit of the
settling parties on a monthly basis as deliveries are made under the
transaction until final approval of the Master Settlement Agreement. At
that time, the actual payments to EPME for delivered power will be at the
reduced amounts.

The definitive settlement agreements are subject to approval by the
California Superior Court for San Diego County and the structural settlement is
subject to the approval by the FERC. In June 2003, in anticipation of the
execution of the definitive settlement agreements, El Paso, the Public Utilities
Commission of the State of California, PG&E, Southern California Edison Company,
and the City of Los Angeles filed the structural settlement described above with
the FERC in resolution of certain specific proceedings before that agency. The
structural settlement was protested by EPNG's East of California shippers and
certain other shippers requested clarification and/or modification of the
settlement. EPNG and the other settling parties have responded to these protests
and requests for clarification and/or modification and have urged the FERC to
approve the structural settlement as filed. We currently expect final approval
of these settlement agreements in late 2003 or early 2004.

California Lawsuits. We and several of our subsidiaries have been named as
defendants in fifteen purported class action, municipal or individual lawsuits,
filed in California state courts. These suits contend that our entities acted
improperly to limit the construction of new pipeline capacity to California
and/or to manipulate the price of natural gas sold into the California
marketplace. Specifically, the plaintiffs argue that our conduct violates
California's antitrust statute (Cartwright Act), constitutes unfair and unlawful
business practices prohibited by California statutes, and amounts to a violation
of California's common law restrictions against monopolization. In general, the
plaintiffs are seeking (i) declaratory and injunctive relief regarding allegedly
anticompetitive actions, (ii) restitution, including treble damages, (iii)
disgorgement of profits, (iv) prejudgment and postjudgment interest, (v) costs
of prosecuting the actions and (vi) attorney's fees. All fifteen cases have been
consolidated before a single judge, under two omnibus complaints, one of which
has been set for trial in September 2003. All of the class action and municipal
lawsuits and all but one of the individual lawsuits will be resolved upon
finalization and approval of the Western Energy Settlement. As to

27

the remaining individual lawsuit, on May 8, 2003, a settlement agreement between
the plaintiffs and defendants in that case became effective and resolved all
disputes between the parties in return for a single payment by us. Pursuant to
the settlement, the plaintiff's action was dismissed with prejudice.

In November 2002, a lawsuit titled Gus M. Bustamante v. The McGraw-Hill
Companies was filed in the Superior Court of California, County of Los Angeles
by several individuals, including Lt. Governor Bustamante acting as a private
citizen, against us, our subsidiaries EPNG, EPME, and El Paso TGP, as well as
numerous other unrelated entities, alleging the creation of artificially high
natural gas index prices via the reporting of false price and volume
information. This purported class action on behalf of California consumers
alleges various unfair business practices and seeks restitution, disgorgement of
profits, compensatory and punitive damages, and civil fines. This lawsuit will
be resolved upon finalization and approval of the Western Energy Settlement.

In September 2001, we received a civil document subpoena from the
California Attorney General, seeking information said to be relevant to the
department's ongoing investigation into the high electricity prices in
California. We have cooperated in responding to the Attorney General's discovery
requests. This proceeding will be resolved upon finalization and approval of the
Western Energy Settlement.

In May 2002, two lawsuits challenging the validity of long-term power
contracts entered into by the California Department of Water Resources in early
2001 were filed in California state court against 26 separate companies,
including our subsidiary EPME. In general, the plaintiffs allege unfair business
practices and seek restitution damages and an injunction against the enforcement
of the contract provisions. These cases have been removed to federal court. Our
costs and legal exposure related to these lawsuits and claims are not currently
determinable.

In January 2003, a lawsuit titled IMC Chemicals v. EPME, et al. was filed
in California state court against us, EPNG and EPME. The suit arises out of a
gas supply contract between IMC Chemicals (IMCC) and EPME and seeks to void the
Gas Purchase Agreement between IMCC and EPME for gas purchases until December
2003. IMCC contends that EPME and its affiliates manipulated market prices for
natural gas and, as part of that manipulation, induced IMCC to enter into the
contract. In furtherance of its attempt to void the contract, IMCC repeats the
allegations and claims of the California lawsuits described above. EPME intends
to enforce the terms of the contract and counterclaim for contract damages. A
Motion to Stay the Proceedings Pending Arbitration was granted, and the parties
are presently preparing for arbitration. Our costs and legal exposure are not
currently determinable.

Other Energy Market Lawsuits. The state of Nevada and two individuals
filed a class action lawsuit in Nevada state court naming us and a number of our
subsidiaries and affiliates as defendants. The allegations are similar to those
in the California cases. The suit seeks monetary damages and other relief under
Nevada antitrust and consumer protection laws. This lawsuit will be resolved
upon finalization and approval of the Western Energy Settlement.

A purported class action suit was filed in federal court in New York City
in December 2002 alleging that El Paso, EPME, EPNG, and other defendants
manipulated California's natural gas market by manipulating the spot market of
gas traded on the NYMEX. Our costs and legal exposure related to this lawsuit
are not currently determinable.

In March 2003, the State of Arizona sued us, EPNG, EPME and other unrelated
entities on behalf of Arizona consumers. The suit alleges that the defendants
conspired to artificially inflate prices of natural gas and electricity during
2000 and 2001. Making factual allegations similar to those alleged in the
California cases, the suit seeks relief similar to the California cases as well,
but under Arizona antitrust and consumer fraud statutes. Our costs and legal
exposure related to this lawsuit are not currently determinable.

In April 2003, Sierra Pacific Resources and its subsidiary, Nevada Power
Company filed a lawsuit titled Sierra Pacific Resources et al. v. El Paso
Corporation et. al., against us, EPNG, EPTP, EPME and several other non-El Paso
defendants. In the now-amended complaint, the lawsuit alleges that the
defendants conspired to manipulate supplies and prices of natural gas in the
California-Arizona border market from 1996 through 2001. The allegations are
similar to those raised in the several cases that are the subject of the

28

Western Energy Settlement described above. The plaintiffs allege that they
entered into contracts at inappropriately high prices and hedging transactions
because of the alleged manipulated prices. They allege that the defendants'
activities constituted (1) violations of the Sherman Act, California antitrust
statutes and the Nevada Unfair Trade Practices Act; (2) fraud; (3) both a
conspiracy to violate and a violation of Nevada's RICO Act; (4) a violation of
the federal RICO statute; and (5) a civil conspiracy. The complaint seeks
unspecified actual damages from all the defendants, and requests that such
damages be trebled. Our costs and legal exposure related to this lawsuit are not
currently determinable.

On April 28, 2003, a class action suit titled Jerry Egger, et al. v.
Dynegy, Inc., was filed in California state court. It specifically names us and
19 other non-El Paso companies as defendants and alleges a conspiracy to
manipulate electricity prices to consumers in nine states in the West Coast
Energy Market. The complaint seeks damages on behalf of the electricity
end-users in eight of the states, Oregon, Washington, Utah, Nevada, Idaho, New
Mexico, Arizona and Montana. The allegations assert the defendants violated the
California antitrust statute (the Cartwright Act) and committed unfair business
practices in violation of the California Business Code. The complaint seeks
actual and treble damages in an unspecified amount, restitution and pre- and
post-judgement interest. Our costs and legal exposure related to this lawsuit
are not currently determinable.

Shareholder Class Action Suits. Beginning in July 2002, twelve purported
shareholder class action suits alleging violations of federal securities laws
have been filed against us and several of our former officers. Eleven of these
suits are now consolidated in federal court in Houston before a single judge.
The suits generally challenge the accuracy or completeness of press releases and
other public statements made during 2001 and 2002. The twelfth shareholder class
action lawsuit was filed in federal court in New York City in October 2002
challenging the accuracy or completeness of our February 27, 2002 prospectus for
an equity offering that was completed on June 21, 2002. It has since been
dismissed, in light of similar claims being asserted in the consolidated suits
in Houston. Four shareholder derivative actions have also been filed. One
shareholder derivative lawsuit was filed in federal court in Houston in August
2002. This derivative action generally alleges the same claims as those made in
the shareholder class action, has been consolidated with the shareholder class
actions pending in Houston and has been stayed. A second shareholder derivative
lawsuit was filed in Delaware State Court in October 2002, generally alleges the
same claims as those made in the consolidated shareholder class action lawsuit
and also has been stayed. A third shareholder derivative suit was filed in state
court in Houston in March 2002, and a fourth shareholder derivative suit was
filed in state court in Houston in November 2002. The third and fourth
shareholder derivative suits both generally allege that manipulation of
California gas supply and gas prices exposed El Paso to claims of antitrust
conspiracy, FERC penalties and erosion of share value. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

ERISA Class Action Suit. In December 2002, a purported class action
lawsuit was filed in federal court in Houston alleging generally that our direct
and indirect communications with participants in the El Paso Corporation
Retirement Savings Plan included misrepresentations and omissions that caused
members of the class to hold and maintain investments in El Paso stock in
violation of the Employee Retirement Income Security Act (ERISA). Our costs and
legal exposure related to this lawsuit are not currently determinable.

Carlsbad. In August 2000, a main transmission line owned and operated by
EPNG ruptured at the crossing of the Pecos River near Carlsbad, New Mexico.
Twelve individuals at the site were fatally injured. On June 20, 2001, the U.S.
Department of Transportation's Office of Pipeline Safety issued a Notice of
Probable Violation and Proposed Civil Penalty to EPNG. The Notice alleged five
violations of DOT regulations, proposed fines totaling $2.5 million and proposed
corrective actions. EPNG has fully accrued for these fines. The alleged five
probable violations of the regulations of the Department of Transportation's
Office of Pipeline Safety are: (1) failure to develop an adequate internal
corrosion control program, with an associated proposed fine of $500,000; (2)
failure to investigate and minimize internal corrosion, with an associated
proposed fine of $1,000,000; (3) failure to conduct continuing surveillance on
its pipelines and consider, and respond appropriately to, unusual operating and
maintenance conditions, with an associated proposed fine of $500,000; (4)
failure to follow company procedures relating to investigating pipeline failures
and thereby to minimize the chance of recurrence, with an associated proposed
fine of $500,000; and (5) failure to maintain elevation

29

profile drawings, with an associated proposed fine of $25,000. In October 2001,
EPNG filed a response with the Office of Pipeline Safety disputing each of the
alleged violations.

On February 11, 2003, the National Transportation Safety Board (NTSB)
conducted a public hearing on its investigation into the Carlsbad rupture at
which the NTSB adopted Findings, Conclusions and Recommendations based upon its
investigation. In April 2003, the NTSB published its final report. The NTSB
stated that it had determined that the probable cause of the August 19, 2000
rupture was a significant reduction in pipe wall thickness due to severe
internal corrosion, which occurred because EPNG's corrosion control program
"failed to prevent, detect, or control internal corrosion" in the pipeline. The
NTSB also determined that ineffective federal preaccident inspections
contributed to the accident by not identifying deficiencies in EPNG's internal
corrosion control program.

On November 1, 2002, EPNG received a federal grand jury subpoena for
documents related to the Carlsbad rupture. EPNG is cooperating with the grand
jury.

A number of personal injury and wrongful death lawsuits were filed against
EPNG in connection with the rupture. All of these suits have been settled, with
settlement payments fully covered by insurance. In connection with the
settlement of the cases, EPNG contributed $10 million to a charitable foundation
as a memorial to the families involved. The contribution was not covered by
insurance.

Parties to four settled lawsuits have since filed an additional lawsuit
titled Diane Heady et al. v. EPEC and EPNG in Harris County, Texas on November
20, 2002, seeking an additional $85 million based upon their interpretation of
earlier settlement agreements. Parties to another of the settled lawsuits have
filed a lawsuit titled In the Matter of the Appointment of Jennifer Smith in
Eddy County, New Mexico on May 7, 2003, seeking an additional $86 million based
upon their interpretation of earlier agreements. The Jennifer Smith case was
settled with the settlement payment fully covered by insurance. In addition, a
lawsuit entitled Baldonado et. al. v. EPNG was filed on June 30, 2003 in state
court in Eddy County, New Mexico on behalf of about 23 firemen and EMS personnel
who responded to the fire and who allegedly have suffered psychological trauma.
Our costs and legal exposure related to the Heady and Baldonado lawsuits are not
currently determinable. However, we believe these matters will be fully covered
by insurance.

Grynberg. In 1997, a number of our subsidiaries were named defendants in
actions brought by Jack Grynberg on behalf of the U.S. Government under the
False Claims Act. Generally, these complaints allege an industry-wide conspiracy
to underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands, which deprived the U.S.
Government of royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and heating value of
natural gas produced from royalty properties been differently measured,
analyzed, calculated and reported, together with interest, treble damages, civil
penalties, expenses and future injunctive relief to require the defendants to
adopt allegedly appropriate gas measurement practices. No monetary relief has
been specified in this case. These matters have been consolidated for pretrial
purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court
for the District of Wyoming, filed June 1997). In May 2001, the court denied the
defendants' motions to dismiss. Discovery is proceeding. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

Will Price (formerly Quinque). A number of our subsidiaries were named as
defendants in Quinque Operating Company, et al. v. Gas Pipelines and Their
Predecessors, et al., filed in 1999 in the District Court of Stevens County,
Kansas. Quinque has been dropped as a plaintiff and Will Price has been added.
This class action complaint alleges that the defendants mismeasured natural gas
volumes and heating content of natural gas on non-federal and non-Native
American lands. The plaintiff in this case seeks certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiff contends these owners should have received
had the volume and heating value of natural gas produced from their properties
been differently measured, analyzed, calculated and reported, together with
prejudgment and postjudgment interest, punitive damages, treble damages,
attorney's fees, costs and expenses, and future injunctive relief to require the
defendants to adopt allegedly appropriate gas measurement practices. No monetary
relief has been specified in this case. Plaintiffs' motion for class
certification was denied on April 10, 2003. Plaintiffs' motion to file another
amended petition to narrow the proposed class to

30

royalty owners in wells in Kansas, Wyoming and Colorado was granted on July 28,
2003. Our costs and legal exposure related to this lawsuit are not currently
determinable.

MTBE. In compliance with the 1990 amendments to the Clean Air Act, we use
the gasoline additive, methyl tertiary-butyl ether (MTBE), in some of our
gasoline. We also produce, buy, sell and distribute MTBE. A number of lawsuits
have been filed throughout the U.S. regarding MTBE's potential impact on water
supplies. We are currently one of several defendants in one such lawsuit in New
York. The plaintiffs seek remediation of their groundwater and prevention of
future contamination, compensatory damages for the costs of replacement water
and for diminished property values, as well as punitive damages, attorney's
fees, court costs, and, in some cases, future medical monitoring. Our costs and
legal exposure related to this lawsuit and claims are not currently
determinable.

In addition to the above matters, we and our subsidiaries and affiliates
are named defendants in numerous lawsuits and governmental proceedings that
arise in the ordinary course of our business.

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of June 30, 2003, we had approximately $1,151 million accrued for all
outstanding legal matters. Approximately $5 million of the accrual was related
to discontinued petroleum operations.

Environmental Matters

We are subject to federal, state and local laws and regulations governing
environmental quality and pollution control. These laws and regulations require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of June 30,
2003, we had accrued approximately $431 million, including approximately $416
million for expected remediation costs at current and former operated sites and
associated onsite, offsite and groundwater technical studies, and approximately
$15 million for related environmental legal costs, which we anticipate incurring
through 2027. Approximately $45 million of the accrual was related to the
discontinued petroleum operations.

The high end of our reserve estimates was approximately $612 million and
the low end was approximately $412 million. The estimate of $412 million
represents a combination of two estimating methodologies. First, where the most
likely outcome can be reasonably estimated, that cost has been accrued ($97
million). Second, where the most likely outcome cannot be estimated, a range of
costs is established ($315 million to $515 million) and the lower end of the
range has been accrued. By type of site, our reserves are based on the following
estimates of reasonably possible outcomes.

Below is a reconciliation of our accrued liability as of June 30, 2003 (in
millions):

Balance as of January 1, 2003............................... $498
Additions/adjustments for remediation activities............ (40)
Payments for remediation activities......................... (31)
Other changes, net.......................................... 4
----
Balance as of June 30, 2003................................. $431
====

31

In addition, we expect to make capital expenditures for environmental
matters of approximately $296 million in the aggregate for the years 2003
through 2008. These expenditures primarily relate to compliance with clean air
regulations. For the remainder of 2003, we estimate that our total remediation
expenditures will be approximately $43 million.

Internal PCB Remediation Project. Since 1988, TGP, our subsidiary, has
been engaged in an internal project to identify and address the presence of
polychlorinated biphenyls (PCBs) and other substances, including those on the
Environmental Protection Agency's (EPA) List of Hazardous Substances (HSL), at
compressor stations and other facilities it operates. While conducting this
project, TGP has been in frequent contact with federal and state regulatory
agencies, both through informal negotiation and formal entry of consent orders.
TGP executed a consent order in 1994 with the EPA, governing the remediation of
the relevant compressor stations and is working with the EPA and the relevant
states regarding those remediation activities. TGP is also working with the
Pennsylvania and New York environmental agencies regarding remediation and
post-remediation activities at the Pennsylvania and New York stations. In May
2003, TGP finalized a new estimate of the cost to complete the PCB/HSL Project.
Over the years, there have been developments that impacted various individual
components, but TGP's ability to estimate a more likely outcome for the total
project has not been possible until recently. The new estimate identified a $31
million reduction in the costs to complete this project. Accruals for these
issues are included in the previously indicated estimates for operating sites.

Kentucky PCB Project. In November 1988, the Kentucky environmental agency
filed a complaint in a Kentucky state court alleging that TGP discharged
pollutants into the waters of the state and disposed of PCBs without a permit.
The agency sought an injunction against future discharges, an order to remediate
or remove PCBs and a civil penalty. TGP entered into interim agreed orders with
the agency to resolve many of the issues raised in the complaint. The relevant
Kentucky compressor stations are being remediated under a 1994 consent order
with the EPA. Despite TGP's remediation efforts, the agency may raise additional
technical issues or seek additional remediation work in the future. Accruals for
these issues are included in the previously indicated estimates for operating
sites.

PCB Cost Recoveries. In May 1995, following negotiations with its
customers, TGP filed an agreement with the FERC that established a mechanism for
recovering a substantial portion of the environmental costs identified in its
internal remediation project. The agreement, which was approved by the FERC in
November 1995, provided for a PCB surcharge on firm and interruptible customers'
rates to pay for eligible costs under the PCB remediation project, with these
surcharges to be collected over a defined collection period. TGP has twice
received approval from the FERC to extend the collection period, which is now
currently set to expire in June 2004. The agreement also provided for bi-annual
audits of eligible costs. As of June 30, 2003, TGP has pre-collected PCB costs
by approximately $117 million. The pre-collection will be reduced by future
eligible costs incurred for the remainder of the remediation project. TGP is
required, to the extent actual expenditures are less than the amounts
pre-collected, to refund to its customers the unused pre-collection amount, plus
carrying charges incurred up to the date of the refunds. As of June 30, 2003,
TGP has recorded a regulatory liability (included in other non-current
liabilities on its balance sheet) of $83 million for future refund obligations.
The obligation increased by $25 million in the second quarter due to the
reduction of TGP's accrual of estimated future environmental remediation and
legal costs.

Coastal Eagle Point. From May 1999 to March 2001, our Coastal Eagle Point
Oil Company received several Administrative Orders and Notices of Civil
Administrative Penalty Assessment from the New Jersey Department of
Environmental Protection (DEP). All of the assessments are related to alleged
noncompliance with the New Jersey Air Pollution Control Act (The Act) pertaining
to excess emissions from the first quarter 1998 through the fourth quarter 2000
reported by our Eagle Point refinery in Westville, New Jersey. The DEP has
assessed penalties totaling approximately $1.3 million for these alleged
violations. The DEP has indicated a willingness to accept a reduced penalty and
a supplemental environmental project. Our Eagle Point refinery has been granted
an administrative hearing on issues raised by the assessments. Subsequently, DEP
assessed an additional $118,000 in penalties for alleged non-compliance with the
act. On February 24, 2003, EPA Region 2 issued a Compliance Order based on a
1999 EPA inspection of the refinery's leak detection and repair (LDAR) program.
Alleged violations include failure to monitor all components, and failure to
timely

32

repair leaking components. During an August 2000 follow-up inspection, the EPA
confirmed our Eagle Point refinery had improved its implementation of the
program. The Compliance Order requires documentation of compliance with the
program. We met with the EPA and DEP in March 2003 to discuss the Order and the
possibility for a global settlement pursuant to the EPA's refinery enforcement
initiative. Global settlements involving other refiners have included civil
penalties and addressed LDAR as well as new source review, the benzene standard,
and the standard for combustion of refinery fuel gas. On April 25, 2003, our
Eagle Point refinery sent a letter to the EPA committing to global settlement
discussions, which are ongoing. Our Eagle Point refinery expects to resolve both
the DEP assessments and the EPA refinery initiative issues.

CERCLA Matters. We have received notice that we could be designated, or
have been asked for information to determine whether we could be designated, as
a Potentially Responsible Party (PRP) with respect to 63 active sites under the
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or
state equivalents. We have sought to resolve our liability as a PRP at these
sites through indemnification by third parties and settlements which provide for
payment of our allocable share of remediation costs. As of June 30, 2003, we
have estimated our share of the remediation costs at these sites to be between
$30 million and $42 million. Since the clean-up costs are estimates and are
subject to revision as more information becomes available about the extent of
remediation required, and because in some cases we have asserted a defense to
any liability, our estimates could change. Moreover, liability under the federal
CERCLA statute is joint and several, meaning that we could be required to pay in
excess of our pro rata share of remediation costs. Our understanding of the
financial strength of other PRPs has been considered, where appropriate, in
estimating our liabilities. Accruals for these issues are included in the
previously indicated estimates for operating sites.

It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe our current
reserves are adequate.

Rates and Regulatory Matters

Wholesale Power Customers' Complaints. In late 2001 and 2002, several
wholesale power customers filed complaints with the FERC against EPME and other
wholesale power marketers. The complaints are listed below. The primary
customers are: Nevada Power Co. and Sierra Pacific Power Co. (NPSP), PacifiCorp,
City of Burbank, the California Public Utilities Commission and the California
Electricity Oversight Board (CPUC/CEOB). In these complaints, the customers have
asked the FERC to reform the contracts they entered into with EPME and other
wholesale power marketers on the grounds that they involve rates and terms that
are "unjust and unreasonable" or "contrary to" the public interest within the
meaning of the Federal Power Act (FPA). In the NPSP matter, the ALJ issued an
initial decision concluding that the contracts at issue should not be modified,
and the complaints should be dismissed. In the CPUC/CEOB matter, the ALJ issued
an initial decision finding the public interest standard applies to the contract
at issue, which finding is consistent with the initial decision of the ALJ in
the NPSP case. In the PacifiCorp matter, the ALJ issued an initial decision
concluding that the complaint filed by PacifiCorp against EPME (and other
respondents) should be dismissed with prejudice. The ALJ's decisions were upheld
by FERC on June 26, 2003. The City of Burbank and EPME reached a settlement of
this case which was approved by the city counsel on May 27, 2003. The complaint
was voluntarily withdrawn from the FERC. The CPUC/CEOB matter will be fully
resolved upon finalization of the Western Energy Settlement. NPSP has petitioned
for review of the FERC decision.

33

CPUC Complaint Proceeding. In April 2000, the California Public Utilities
Commission filed a complaint under Section 5 of the Natural Gas Act (NGA) with
the FERC alleging that the sale of approximately 1.2 Bcf/d of capacity by EPNG
to EPME, both of whom are our wholly owned subsidiaries, raised issues of market
power and violation of FERC's marketing affiliate regulations and asked that the
contracts be voided. In the spring and summer of 2001, two hearings were held
before an ALJ to address the market power issue and the affiliate issue. In
October 2001, the ALJ issued an initial decision on the two issues, finding that
the record did not support a finding that either EPNG or EPME had exercised
market power but finding that EPNG had violated FERC's marketing affiliate rule.

Also in October 2001, the FERC's Office of Market Oversight and Enforcement
filed comments stating that the record at the hearings was inadequate to
conclude that EPNG had complied with FERC regulations in the transportation of
gas to California. In December 2001, the FERC remanded the proceeding to the ALJ
for a supplemental hearing on the availability of capacity at EPNG's California
delivery points. On September 23, 2002, the ALJ issued his initial decision,
again finding that there was no evidence that EPME had exercised market power
during the period at issue to drive up California gas prices and therefore
recommending that the complaint against EPME be dismissed. However, the ALJ
found that EPNG had withheld at least 345 MMcf/d of capacity (and perhaps as
much as 696 MMcf/d) from the California market during the period from November
1, 2000 through March 31, 2001. The ALJ found that this alleged withholding
violated EPNG's certificate obligations and was an exercise of market power that
increased the gas price to California markets. He therefore recommended that the
FERC initiate penalty procedures against EPNG. The FERC has taken no actions in
this proceeding on the ALJ's findings. This proceeding will be resolved upon
finalization and approval of the Western Energy Settlement.

Systemwide Capacity Allocation Proceeding. In July 2001, several of EPNG's
contract demand (CD) customers filed a complaint against EPNG at the FERC
claiming, among other things, that EPNG's full requirements (FR) contracts
(contracts with no volumetric limitations) should be converted to CD contracts,
and that EPNG should be required to expand its system and give demand charge
credits to CD customers when it is unable to meet its full contract demands.
Also in July 2001, several of EPNG's FR customers filed a complaint alleging
that EPNG had violated the NGA and its contractual obligations to them by not
expanding its system, at its cost, to meet their increased requirements.

On May 31, 2002, the FERC issued an order on the complaints in which it
required that (i) FR service, for all FR customers except small volume
customers, be converted to CD service; (ii) firm customers be assigned specific
receipt point rights in lieu of their existing systemwide receipt point rights;
(iii) reservation charge credits be given to all firm customers for failure to
schedule confirmed volumes except in cases of force majeure; (iv) no new firm
contracts be executed until EPNG has demonstrated there is adequate capacity on
the system; and (v) a process be implemented to allow existing CD customers to
turn back capacity for acquisition by FR customers in which process EPNG would
remain revenue neutral. These changes were to be made effective November 1,
2002. The order also stated that the FERC expected EPNG to file for certificate
authority to add compression to Line 2000 to increase its system capacity by 320
MMcf/d without cost coverage until its next rate case (i.e. January 1, 2006) as
EPNG had previously informed the FERC that it was willing to do. In July 2002,
EPNG and other parties filed for clarification and/or rehearing of the May 31
order.

On September 20, 2002, the FERC issued an order postponing the effective
date of the FR conversions until May 1, 2003 and requiring EPNG to allocate
among FR customers (i) the 320 MMcf/d of capacity that will be available from
the addition of compression to Line 2000, and (ii) any firm capacity under
existing contracts that expired between May 31, 2002, and May 1, 2003. In total,
EPNG's FR customers will pay only their current aggregate reservation charges
for existing unsubscribed capacity, for the 230 MMcf/d of capacity made
available in November 2002 by EPNG's Line 2000 project, for the 320 MMcf/d of
capacity from the addition of compression to Line 2000, and for all capacity
subject to contracts expiring before May 1, 2003. On April 14, 2003, the FERC
issued an order resetting the implementation date to September 1, 2003.

34

In October 2002, EPNG filed tariff sheets in compliance with the September
20 order to implement a partial demand charge credit for the period November 1,
2002 to May 6, 2003, and to allow California delivery points to be used as
secondary receipt points to the extent of its backhaul displacement
capabilities. EPNG proposed both a reservation and a usage charge for this
service. On December 26, 2002, the FERC issued an order (i) denying EPNG's
request to charge existing CD customers a reservation rate for California
receipt service for the remaining term of the settlement, i.e., through December
31, 2005; (ii) allowing EPNG to charge its maximum IT rate for the service;
(iii) approving EPNG's proposed usage rate for the service until its next rate
case; and (iv) requiring it to make a showing that capacity is available for any
new shippers utilizing this service.

On July 9, 2003, the FERC issued a rehearing order in the proceeding. The
order denied rehearing of FERC's previous determination that FR contracts must
be converted to CD contracts. The order also declined to postpone the September
1, 2003 implementation date for the conversion of the FR contracts and for the
replacement of systemwide firm receipt rights with firm rights at specific
receipt locations. In ruling on these issues, the FERC found that EPNG had not
violated its certificates, its contractual obligations, including its
obligations under the 1996 Settlement, or its tariff provisions as a result of
the capacity allocations that have occurred on the system since the 1996
Settlement. In addition, the FERC found that EPNG had correctly stated the
capacity that is available on a firm basis for allocation among its shippers and
that EPNG has allocated that capacity consistent with the requirements of the
previous orders in the proceeding. On a prospective basis, the FERC ordered EPNG
to remove the pro rata allocation provisions from its tariff, to set aside a
pool of 110 MMcf/d of capacity for use by the converting FR shippers until the
first phase of the Line 2000 Power-Up (discussed below) goes into service
(estimated to be February 2004, after which the pool of capacity will be reduced
to 50 MMcf/d until the second phase of the Power-Up is in service in mid-2004),
and to pay full reservation charge credits when it is unable to schedule gas
that has been nominated and confirmed by its firm shippers. In cases of force
majeure events and maintenance, EPNG will limit the amount of our reservation
charge credits to the return and associated tax portion of its rates. The
rehearing order also lifted the ban on the resale of firm capacity that comes
back to EPNG, subject only to the 110/50 MMcf/d of capacity that must be
maintained in a pool for the converting FR shippers until the first two phases
of the Line 2000 Power-Up are in service.

On July 18, 2003, the FR shippers filed two appeals of the July 9 order
with the United States Court of Appeals for the D.C. Circuit (Arizona Corp.
Comm'n, et al. v. FERC, Nos. 03-1206, et al,) and subsequently moved the Court
for a stay of the September 1, 2003 conversion date. EPNG has intervened in the
proceedings and will oppose the petitions. The Court denied the stay motion on
August 6, 2003. The final outcome of these appeals cannot be predicted with
certainty.

On August 8, 2003, a number of parties sought further clarification and/or
rehearing of the FERC's July 2003 rehearing order. EPNG sought clarification of
a companion order that addressed tariff sheets implementing the conversions. We
cannot predict the final outcome of FERC's actions on those filings.

Rate Settlement. EPNG's current rate settlement establishes its base rates
through December 31, 2005. Under the settlement, EPNG's base rates began
escalating annually in 1998 for inflation. EPNG has the right to increase or
decrease its base rates if changes in laws or regulations result in increased or
decreased costs in excess of $10 million a year. In addition, all of EPNG's
settling customers participate in risk sharing provisions. Under these
provisions, EPNG received cash payments in total of $295 million for a portion
of the risk EPNG assumed from capacity relinquishments by its customers
(primarily capacity turned back to it by Southern California Gas Company and
Pacific Gas and Electric Company which represented approximately one-third of
the capacity of EPNG's system) during 1996 and 1997. The cash EPNG received was
deferred, and EPNG recognizes this amount in revenues ratably over the risk
sharing period. As of June 30, 2003, EPNG had unearned risk sharing revenues of
approximately $16 million and had $6 million remaining to be collected from
customers under this provision. Amounts received for relinquished capacity sold
to customers, above certain dollar levels specified in EPNG's rate settlement,
obligate it to refund a portion of the excess to customers. Under this
provision, EPNG refunded a total of $46 million of 2002 revenues to customers
during 2002 and the first quarter of 2003. During 2003, EPNG established an
additional refund obligation of

35

$19 million. Both the risk and revenue sharing provisions of the rate settlement
will terminate at the end of 2003.

Line 2000 Project. In July 2000, EPNG applied with the FERC for a
certificate of public convenience and necessity for its Line 2000 project, which
was designed to replace old compression on the system with a converted oil
pipeline, resulting in no increase in system capacity. In response to demand
conditions on its system, however, EPNG filed in March 2001 to amend its
application to convert the project to an expansion project of 230 MMcf/d. In May
2001, the FERC authorized the amended Line 2000 project. EPNG placed the line in
service in November 2002 at a capital cost of $189 million. The cost of the Line
2000 conversion will not be included in EPNG's rates until its next rate case,
which will be effective on January 1, 2006.

In October 2002, pursuant to the FERC's May 31 and September 20 orders in
the systemwide capacity allocation proceeding, EPNG filed with the FERC for a
certificate of public convenience and necessity to add compression to its Line
2000 project to increase the capacity of that line by an additional 320 MMcf/d
at an estimated capital cost of approximately $173 million for all phases.

Marketing Affiliate NOPR. In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct
governing the relationship between interstate pipelines and marketing affiliates
to all energy affiliates. The proposed regulations, if adopted by the FERC,
would dictate how all our energy affiliates conduct business and interact with
our interstate pipelines. We have filed comments with the FERC addressing our
concerns with the proposed rules, participated in a public conference and filed
additional comments. At this time, we cannot predict the outcome of the NOPR,
but adoption of the regulations in their proposed form would, at a minimum,
place additional administrative and operational burdens on us.

Negotiated Rate Policy. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that sought comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. We have entered into those transactions
over the years, and the FERC is now reviewing whether negotiated rates should be
capped, whether or not the "recourse rate" (a cost-of-service based rate)
continues to safeguard against a pipeline exercising market power and other
issues related to negotiated rate programs. El Paso's pipelines and others filed
comments on the NOI.

In July 2003, the FERC issued modifications to its negotiated rate policy
applicable to interstate natural gas pipelines. The new policy has two primary
changes. First, the FERC will no longer permit the pricing of negotiated rates
based on natural gas commodity price indices, although it will permit current
contracts negotiated on that basis to continue until the end of the applicable
contract period. Second, the FERC is imposing new filing requirements on
pipelines to ensure the transparency of negotiated rate transactions.

Interim Rule on Cash Management. In August 2002, the FERC issued a NOPR
proposing, inter alia, that all cash management or money pool arrangements
between a FERC-regulated subsidiary and its non-FERC regulated parent be in
writing and that, as a condition of participating in such an arrangement, the
FERC-regulated entity maintain a minimum proprietary capital balance of 30
percent and both it and its parent maintain investment grade credit ratings.
After receiving written comments and hearing industry participants' concerns at
a public conference in September 2002, the FERC issued an Interim Rule on Cash
Management on June 26, 2003, which did not adopt the proposed limitations on
entry into or participating in cash management programs. Instead, the Interim
Rule requires natural gas companies to maintain up-to-date documentation
authorizing the establishment of the cash management program in which they
participate and supporting all deposits into, borrowings and interest from, and
interest expense paid to such program.

The Interim Rule also seeks comments on a proposed reporting requirement
that a FERC-regulated entity file cash management agreements and any changes
thereto within ten days and that it notify the Commission within five days when
its proprietary capital ratio falls below 30 percent (i.e., its long-term
debt-to-equity ratio rises above 70 percent) and when it subsequently returns to
or exceeds 30 percent. We filed comments on the Interim Rule on August 7, 2003.

36

Pipeline Safety Notice of Proposed Rulemaking. In January 2003, the U.S.
Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines, and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from the enactment of the Pipeline Safety Improvement Act
of 2002, a new bill signed into law in December 2002. Comments on the NOPR were
filed on April 30, 2003. At this time, we cannot predict the outcome of this
rulemaking.

FERC Inquiry. On February 26, 2003, we received a letter from the Office
of the Chief Accountant at the FERC requesting details of our announcement of
2003 asset sales and plans for our subsidiaries, SNG and ANR, to issue a
combined $700 million of long-term notes. The letter requested that we explain
how we intended to use the proceeds from SNG's and ANR's issuance of the notes
and if the notes will be included in the two regulated companies' capital
structure for rate-setting purposes. Our response to the FERC was filed on March
12, 2003. On April 2, 2003, we received an additional request for information,
to which we fully responded on April 15, 2003.

Western Trading Strategies. EPME, our subsidiary, responded on May 22,
2002, to the FERC's May 8, 2002 request in Docket No. PA-02-2, seeking
statements of admission or denial with respect to trading strategies designed to
manipulate western power markets. EPME provided an affidavit stating that it had
not engaged in these trading strategies. On July 10, 2003, EPME filed a
follow-up letter at the request of OMOI further explaining a March 26, 2003 data
response in this proceedings wherein EPME denied any physical withholding of
power by its generating units into the California ISO or Cal PX markets. On
August 1, 2003, the FERC staff issued an initial report on physical withholding
of electric generation in the California markets. The report notified EPME that
its generating unit, San Joaquin Cogen Ltd., was no longer the subject of
further investigation.

Wash Trade Inquiries. In May 2002, the FERC issued data requests in Docket
PA-02-2, including requests for statements of admission or denial with respect
to so-called "wash" or "round trip" trades in western power and gas markets. In
May and June 2002, EPME responded, denying that it had conducted any wash or
round trip trades (i.e., simultaneous, prearranged trades entered into for the
purpose of artificially inflating trading volumes or revenues, or manipulating
prices).

In June 2002, we received an informal inquiry from the SEC regarding the
issue of round trip trades. Although we do not believe any round trip trades
occurred, we submitted data to the SEC in July 2002. In July 2002, we received a
federal grand jury subpoena for documents concerning so-called round trip or
wash trades. We have complied with these requests.

Price Reporting to Indices. On October 22, 2002, the FERC issued a data
request in Docket PA-02-2 to all of the largest North American gas marketers,
including EPME, regarding price reporting of transactional data to the energy
trade press. We engaged an outside firm to investigate the matters raised in the
data request. EPME has provided information regarding its price reporting to
indices to the FERC, the Commodities Futures Trading Commission (CFTC), and to
the U.S. Attorney in response to their requests. The information provided
indicates inaccurate prices were reported to the trade publications. EPME has no
evidence that the reporting to the publications resulted in any unrepresentative
price index. On March 26, 2003, we announced a settlement between EPME and CFTC
of the price reporting matter providing for the payment by EPME of a civil
monetary penalty of $20 million, $10 million of which was paid in the second
quarter of 2003 and $10 million of which is payable within three years, without
admitting or denying the findings made in the CFTC order implementing the
agreement. On April 30, 2003, in a new docket PA03-7, the FERC issued an Order
Directing Submission of Information with Respect to Internal Processes for
Reporting Trading Data, directing certain marketing companies, including EPME,
to show that they have corrected their internal processes for reporting trading
data to the trade press, or that they no longer sell natural gas at wholesale.
The order required the named companies to file within 45 days of the order, to
respond to the following questions 1) that employees who participated in
manipulations have been disciplined; 2) that the company has a code of conduct
in place for reporting price information; 3) all trade data reporting is done by
an entity within the company that does not have a financial interest in the
published index; and

37

4) the company is cooperating with any government agency investigation in past
price reporting practices. EPME filed an affidavit on June 13, 2003, asserting
that its Code of Conduct prohibits the submission of false data and that EPME no
longer reports data to the trade press. The FERC accepted the affidavit as being
in compliance with its order.

Refunds Pricing. On August 13, 2002, the FERC issued a Notice Requesting
Comment on Method for Determining Natural Gas Prices for Purposes of Calculating
Refunds in ongoing California refund proceedings dealing with sales of electric
power in which some of our companies are involved. Referencing a Staff Report
also issued on August 13, 2002, the FERC requested comments on whether it should
change the method for determining the delivered cost of natural gas in
calculating the mitigated market-clearing price in the refund proceeding and, if
so, what method should be used. Comments were filed on October 15, 2002. On
December 12, 2002, the ALJ issued an Initial Decision, setting forth preliminary
calculations of amounts owed. In the aggregate, the ALJ found that $3 billion is
owed to natural gas suppliers, offset by an aggregate refund of $1.2 billion
associated with prices charged in excess of the mitigated market clearing
prices. The FERC issued its order on the Initial Decision on March 26, 2003. The
FERC largely adopted the proposed findings of the ALJ in the Initial Decision,
which for the most part approved the methodology used in calculating refund
liabilities. However, the FERC Commissioners adopted the FERC Staff's findings
and recommendations put forth in this refund proceeding, and changed the method
for calculating the mitigated market clearing price to use published prices from
the production basins, plus fully allocated transport costs, instead of
published California border gas prices. The methodology could increase the
refund liability. EPME filed a request for rehearing of the March 26, 2003
Order. Upon the finalization and approval of the Western Energy Settlement,
claims by many of the claimants in this proceeding for credits against amounts
due EPME will be resolved; however, the specific amount of the adjustment is
indeterminable at this time. We cannot predict the final outcome of this matter.

FERC Order to Show Cause EL03-187. EPME is included as a respondent to an
Order to Show Cause (OSC) issued by the FERC June 25, 2003. The OSC concerns
alleged gaming and/or anomalous market behavior through the use of partnerships,
alliances or other arrangements and directed submission of information. The main
thrust of the order is to address partnership and alliance relationships between
Enron and other entities. The Order also addresses other alleged gaming
partnerships or alliances among other parties. It is in this "other" category
that EPME is identified. Our initial review indicates that the alleged
partnership is a "parking" transaction with Public Service Company of New Mexico
(PNM) which EPME entered into for legitimate business purposes and will so
advise the FERC when it responds to the OSC.

Australia. In May 2003, Western Australia regulators issued a final rate
decision at lower than expected levels for the Dampier to Bunbury pipeline owned
by EPIC Energy Australia Trust (EPIC), in which we have a 33 percent ownership
interest. During the fourth quarter of 2002, the unfavorable regulatory
environment and unanticipated cash requirements made it apparent that a cash
equity infusion would be required to refinance the debt of EPIC Energy (WA)
Nominees Pty. Ltd. that matures and is payable in full during 2003. Given the
other demands on our liquidity, we concluded that we would not contribute any
further equity into our EPIC Western Australian investment. As a result, we
recognized an impairment of $153 million related to this investment in 2002. At
June 30, 2003, our remaining investment in EPIC was approximately $52 million.

Southwestern Bell Proceeding. We are engaged in proceedings with
Southwestern Bell involving disputes regarding our telecommunications
interconnection agreement in our metropolitan transport business. In August
2002, we received a favorable ruling from the administrative law judge in Phase
1 of the proceedings. We currently anticipate a determination from the PUC of
Texas on the administrative law judge's recommendation by the end of the third
quarter of 2003. The PUC issued a draft order for comment in June. The draft
order, if issued, would largely uphold the favorable ruling from the
administrative law judge except with regard to our ability to access
Southwestern Bell's network to interconnect with other carriers. Despite the
favorable ruling from the administrative law judge, the PUC retains the right to
affirm or reject the award and any significant rejection of the award would
negatively impact our metro transport business. An adverse resolution to the
proceeding by the PUC would have a negative impact on our ongoing operations and
prospects in this business.

38

FCC Triennial Review. In this proceeding, the FCC, pursuant to its
Congressional mandate, is reexamining the entire list of Unbundled Network
Elements (UNEs), including high capacity loops and transport and dark fiber, to
determine if any should be removed or qualified. It is possible that the FCC may
either eliminate or set more stringent offering guidelines for some of the
existing UNE's. Although El Paso Global Networks (EPGN), formerly known as El
Paso Communications Company, has no reason to assume that dark fiber or high
capacity loops or transport may be eliminated, any ruling that seriously impairs
its ability to access these UNEs would significantly affect its current business
model. Further, the FCC has indicated that certain packet/switching
technologies/services will not be unbundled. Such a holding, if so ordered,
would increase rates on such routes. EPGN has filed comments and an order is
expected before the end of the third quarter 2003. It is expected that most of
the order will be appealed.

FCC Broadband Docket. The FCC has issued a Notice of Proposed Rule Making
(NPRM) for Broadband Service and asked for general comments on a vast array of
issues. The NPRM indicates that the FCC is inclined to declare high-speed, DSL
internet access service as an information service. This would allow Incumbent
Local Exchange Carriers (ILECs) to stop leasing their DSL internet service to
third party competitors for resale to customers. ILECs have also submitted
proposals that would effectively deregulate all optical level and high-speed
copper based services. If the FCC adopted the NPRM proposal, the results would
critically affect EPGN's business. EPGN filed initial comments, in conjunction
with other ILEC's. EPGN also filed joint reply comments on July 3, 2002,
stressing both the illegality of the proposed finding and the national security
implications. Certain ILECs are advocating the position that all high capacity
copper and fiber lines should be found to be "information services", thereby
exempting them from having to lease their lines to EPGN. We have opposed such a
holding, which we believe would be unlawful. A decision is expected by the end
of 2003.

While the outcome of our outstanding legal matters, environmental matters,
and rates and regulatory matters cannot be predicted with certainty, based on
current information and our existing accruals, we do not expect the ultimate
resolution of these matters to have a material adverse effect on our financial
position, operating results or cash flows. However, it is possible that new
information or future developments could require us to reassess our potential
exposure related to these matters. It is also possible that these matters could
impact our debt rating and credit rating. Further, for environmental matters, it
is also possible that other developments, such as increasingly strict
environmental laws and regulations and claims for damages to property,
employees, other persons and the environment resulting from our current or past
operations, could result in substantial costs and liabilities in the future. As
new information regarding our outstanding legal matters, environmental matters
and rates and regulatory matters becomes available, or relevant developments
occur, we will review our accruals and make any appropriate adjustments. The
impact of these changes may have a material effect on our results of operations,
our financial position, and on our cash flows in the period the event occurs.

Other

Enron Bankruptcy. In December 2001, Enron Corp. and a number of its
subsidiaries, including Enron North America Corp. and Enron Power Marketing,
Inc., (EPMI) filed for Chapter 11 bankruptcy protection in the United States
Bankruptcy Court for the Southern District of New York. We had contracts with
Enron North America, Enron Power Marketing and other Enron subsidiaries for,
among other things, the transportation of natural gas and NGL and the trading of
physical natural gas, power, petroleum and financial derivatives.

Our Merchant Energy positions are governed under a master International
Swap Dealers Association, Inc. agreement, various master natural gas agreements,
a master power purchase and sale agreement, and other commodity agreements. We
terminated most of these trading-related contracts, which we believe was proper
and in accordance with the terms of these contracts. In October 2002, we filed
proofs of claim for our domestic trading positions against Enron trading
entities in an amount totaling approximately $318 million. Also in October 2002,
our European trading business asserted $20 million in claims against Enron
Capital and Trade Resources Limited which is subject to proceedings in the
United Kingdom. In addition, Enron now asserts that Coastal States Trading, Inc.
(CSTI) owes it approximately $3 million related to certain

39

terminated petroleum contracts. CSTI disputes this assertion. After considering
the cash margins Enron has deposited with us as well as the reserves we have
established, our overall Merchant Energy exposure to Enron is $29 million, which
is classified as current accounts and notes receivable. We believe this amount
is reasonable based on offers received to purchase the claims, and on the price
at which we sold a portion of Merchant Energy's claims to a third party.
Merchant Energy's exposure estimate is consistent with the projected
distributions reflected in the disclosure statements recently filed by Enron in
its bankruptcy proceedings. As it currently stands, Enron's Plan of
Reorganization, coupled with the partial claims sale, would result in Merchant
Energy's receipt of approximately $30 million, assuming all of the filed claims
are allowed and the proceeding described immediately below is resolved in our
favor.

In February 2003, Merchant Energy received a letter from EPMI demanding
payment under a March 2001 Power Purchase and Sale Agreement (Agreement) of
approximately $46 million. Merchant Energy responded to the February 2003 demand
letter denying that any sums were due EPMI under the Agreement. In addition,
EPMI has now made demand on us for this sum based on an August 2, 2001 guaranty
agreement. EPMI has now filed a lawsuit against Merchant Energy and El Paso in
the United States Bankruptcy Court for the Southern District of New York seeking
to collect these sums. We have denied liability. This lawsuit has been referred
to mediation. The first joint session with the mediator is currently anticipated
to be in the fourth quarter of 2003. If the court adopts Enron's methodology, it
could also result in a reduction of Merchant Energy's claims against Enron
Capital and Trade Resources Limited described above.

In early May 2003, Enron Broadband Services, Inc. filed a notice of
rejection with respect to an IRU agreement granting El Paso Networks, L.L.C. the
right to use certain dark fiber in the Denver area. El Paso Networks is
currently evaluating what actions it may want to take in response to the notice
of rejection.

In addition, various Enron subsidiaries had transportation contracts on
several of our pipeline systems. Most of these transportation contracts have now
been rejected, and our pipeline subsidiaries have filed proofs of claim totaling
approximately $137 million. EPNG filed the largest proof of claim in the amount
of approximately $128 million, which included $18 million for amounts due for
services provided through the date the contracts were rejected and $110 million
for damage claims arising from the rejection of its transportation contracts.
The September 20, 2002 order in the EPNG capacity allocation proceeding
discussed in Rates and Regulatory Matters above prohibited EPNG from remarketing
Enron capacity that was not remarketed prior to May 31, 2002. We have fully
reserved for the amounts due through the date the contracts were rejected, and
we have not recognized any amounts under these contracts since the rejection
date.

NRG. NRG Power Marketing Inc. (NRG) filed for Chapter 11 bankruptcy
protection in the United States Bankruptcy Court for the Southern District of
New York. EPME had power trading contracts with NRG and additional financial
derivative contracts, which were terminated as a result of NRG's bankruptcy
filing. We believe EPME's termination of these contracts was proper and in
accordance with the contract terms. EPME determined that its aggregated claim,
after it asserted any setoff rights, would be approximately $26 million. EPME
filed the claims based on damages calculated under the various trading
agreements with NRG. Xcel Energy, Inc. guaranteed $12 million of the debt, and
subsequently paid the guaranteed amount to EPME. Accordingly, the net claim
filed by EPME in the bankruptcy case was approximately $14 million. EPME has
entered into settlement negotiations with NRG, and subject to court approval,
has agreed to settle the claim for approximately $13 million.

US Gen. USGen New England, Inc. (USGen) filed for Chapter 11 bankruptcy
protection in the United States Court for the District of Maryland in July 2003.
Our subsidiary, Mohawk River Funding, III, L.L.C. (MRF III) had a power purchase
agreement with USGen that terminated automatically as a result of USGen's
bankruptcy filing. We are in the process of evaluating our damages and
calculating our claim amount as a result of the termination. Although we have
not finalized our claim amount, we believe that we are adequately reserved for
amounts we may not ultimately recover on the claims against USGen.

Mirant. Mirant Corporation and several affiliates, including its trading
affiliate Mirant Americas Energy Marketing, L.P., filed for Chapter 11
bankruptcy protection in the United States Bankruptcy Court for the Northern
District of Texas, Fort Worth Division on July 15, 2003. EPME immediately
terminated its Master Netting Agreement with Mirant Americas Energy Marketing,
L.P. We are in the process of evaluating

40

amounts owed to Mirant in accordance with the termination provisions of our
Master Netting Agreement. Although we have not finalized these amounts, we
believe the liability we have accrued will be sufficient to provide for our
obligations. Additionally, a subsidiary of Mirant owes us approximately $42
million in installment payments in connection with its purchase from us of the
Pasco, Florida and the West Georgia power plants in 2001. Although we do not
have the right to offset these receivables against amounts owed Mirant Americas
Energy Marketing, L.P., we believe that we are adequately reserved for amounts
we may not ultimately recover on the claims against Mirant. Other El Paso
entities have agreements in place with various Mirant entities that are impacted
by the bankruptcy filings. Except as set forth above, we do not believe we have
a material exposure as a result of the bankruptcy filings.

We continue to actively monitor the creditworthiness of our counterparties
in the energy sector, many of whom have experienced financial distress since the
collapse of Enron. Although we have not experienced significant losses due to
the bankruptcies of our counterparties to date, should there be further
bankruptcies and material contracts with our various subsidiaries are not
assumed by other counterparties, it could have a material adverse effect on our
financial position, operating results or cash flows.

Cogeneration Facilities. On May 2, 2003, the FERC issued an Order
Initiating Investigation into Enron Corporation's ownership of East Coast Power,
LLC, which owned three cogeneration facilities. The three facilities are: Cogen
Technologies Linden Venture, L.P. (Linden), Camden Cogen L.P. (Camden) and Cogen
Technologies NJ Venture (Bayonne). The FERC is investigating whether Enron's
ownership of the facilities violated restrictions contained in the Public
Utility Regulatory Policies Act of 1978 (PURPA) that prohibit an electric
utility from owning more than 50 percent of a Qualifying Facility (QF). The FERC
asserts that Enron was an electric utility at the time of its ownership as a
consequence of its merger with Portland General. We currently believe that from
February 1999 to August 1999, Enron owned less than 50 percent of the interests
in the facilities due to its partnership with the California Public Employees
Retirement System and other third party ownership interests. We currently own
all of the equity interests in Camden and Bayonne and 79.2 percent of the
indirect equity interests in Linden and Enron indirectly owns a 1 percent
non-voting preferred interest in Linden. Chaparral acquired 49 percent of the
interests in the facilities in August 1999 and the remaining interests in
February 2001. If the FERC finds that Enron's ownership of the facilities
violated the ownership restrictions contained in PURPA, it may seek to
redetermine applicable rates that the QFs were entitled to charge their
customers and order refunds for the period of non-compliance or to impose other
penalties within its authority. We intervened in the proceeding before the FERC
to protect our interests. While we do not believe resolution of this proceeding
is a condition to closing, it is possible that this proceeding will delay the
closing of our announced sale of our interests in East Coast Power. The schedule
for the proceeding calls for hearings in November 2003 and a decision from the
presiding Administrative Law Judge in February 2004. The decision of the
Administrative Law Judge could then be appealed to the full Commission. We are
engaged in discussions with the FERC trial staff and the other parties to the
proceeding in an effort to resolve this matter without the need for a hearing.

Broadwing Arbitration. In June 2000, EPGN entered into an agreement with
Broadwing Communications Services (Broadwing) to construct and maintain a fiber
optic telecommunications system from Houston, Texas to Los Angeles, California.
In May 2002, EPGN terminated its agreements with Broadwing due to Broadwing's
failure to meet its contractual obligations. Broadwing disputed EPGN's right to
terminate the agreements. Subsequently, EPGN filed a demand for arbitration and
named its arbitrator. We have also sought and obtained injunctive relief to
require Broadwing to perform maintenance activity and prohibit it from removing
materials or equipment purchased for the project. If it is determined that we
properly terminated the contract, Broadwing is required to return all money paid
by us which is $62 million and transfer all of the work completed to date free
and clear of any liens. The arbitration is scheduled for the fourth quarter of
2003. We have entered into settlement discussions with Broadwing to attempt to
resolve this dispute. In the fourth quarter of 2002, we wrote down the value of
this long-haul route by $104 million, leaving a total investment of $4 million.

41

Economic Conditions of Brazil. We own and have investments in power,
pipeline and production projects in Brazil with an aggregate exposure, including
financial guarantees, of approximately $1.8 billion. During 2002, Brazil
experienced a significant decline in its financial markets due largely to
concerns over the refinancing of Brazil's foreign debt and the presidential
elections which were completed in late November 2002. These concerns have
contributed to significantly higher interest rates on local debt for the
government and private sectors, have significantly decreased the availability of
funds from lenders outside of Brazil and have decreased the amount of foreign
investment in the country. These factors have contributed to a downgrade of
Brazil's foreign currency debt rating and a 24 percent devaluation of the local
currency against the U.S. dollar since the beginning of 2002. The International
Monetary Fund (IMF) announced in the fourth quarter of 2002 a $30 billion loan
package for Brazil; however, the release of the majority of the money will
depend on Brazil meeting specified fiscal targets set by the IMF in 2003. In
addition, Brazil's President or other government representatives may impose or
attempt to impose changes affecting our business, including imposing price
controls on electricity and fuels, attempting to force renegotiation of power
purchase agreements (PPA's) which are indexed to the U.S. dollar, or attempting
to impose other concessions. These developments have delayed and may continue to
delay the implementation of project financings planned and underway in Brazil.
We currently believe that the economic difficulties in Brazil will not have a
material adverse effect on our investment in the country, but we continue to
monitor the economic situation and potential changes in governmental policy, and
are working with the state-controlled utilities in Brazil that are
counterparties under our projects' PPA's to maintain the economic returns we
anticipated when we made our investments. Future developments in Brazil,
including forced renegotiations of our existing PPA's or changes in our
assumptions related to PPA's where we are seeking extension, may cause us to
reassess our exposure and potentially record impairments in the future. Some of
the specific difficulties we are experiencing in Brazil are discussed below.

We own a 60 percent interest in a 484-megawatt gas-fired power project
known as the Araucaria project, located near Curitiba, Brazil. The project
company in which we have an ownership interest has a 20-year PPA with Copel, a
regional utility. Copel is approximately 60 percent owned by the State of
Parana. After the recent elections in Brazil, the new Governor of the State of
Parana publicly characterized the Araucaria project as unfavorable to Copel and
the State of Parana and promised a full review of the transaction. Subsequent to
this announcement, Copel informed us that they will not pay capacity payments
due under the PPA pending that review. Previous payments made under the PPA were
made with a reservation of rights with respect to the enforceability of the
contract. After meetings with the government as well as new management at Copel
to discuss Copel's obligations under the PPA, we were unable to come to a
satisfactory resolution of the current issues under the PPA, and we have
initiated enforcement of our remedies under the contract, including filing an
arbitration proceeding under the International Chamber of Commerce rules in
Paris. If we do not prevail in that proceeding, or are not otherwise able to
enforce our remedies under the contract, we could be required to impair our
investment in the project. Our losses would be limited to our investment. Our
investment in the Araucaria project was $178 million at June 30, 2003.

We own two projects located in Manaus, Brazil. The first project is a
238-megawatt fuel-oil fired plant known as the Manaus Project with a net book
value of plant equipment of $106 million at June 30, 2003 and the second project
is a 158-megawatt fuel-oil fired plant known as the Rio Negro Project with a net
book value of plant equipment of $110 million at June 30, 2003. The Manaus
Project's PPA currently expires in January 2005 and the Rio Negro Project's PPA
currently expires in January 2006. In the first quarter of 2003, we began
experiencing delays in payment from the purchaser of our power, Manaus Energia
S.A. (Manaus Energia). Manaus Energia is an indirect wholly owned subsidiary of
Centrais Electricas Brasileiras S. (Eletrobras), a Brazilian federal utility
holding company. As of June 30, 2003 our total accounts receivable on these
projects is $24 million. In addition, we have filed a lawsuit in the Brazilian
courts against Manaus Energia on the Rio Negro Project regarding a tariff
dispute related to power sales from 1999 to 2001 and have a long-term receivable
of $32 million which is a subject of this lawsuit. In meetings with Manaus
Energia in the second quarter of 2003, Manaus Energia expressed their desire to
renegotiate the current PPAs and have informed us that they view the Manaus
Project's PPA as having expired in January 2003, even though a letter agreement
executed in May 2002 extended this contract until January 2005. We are
continuing negotiations with Manaus Energia in efforts to correct the current
payment default issues, to reaffirm the legal standing of

42

the current PPA, and to renegotiate the PPAs to extend their terms. If we are
unsuccessful in reaching an agreement with Manaus Energia regarding compliance
with the existing contract terms or are unable to reach an agreement on
long-term contract extensions on acceptable terms, we may be required to impair
these projects. Our impairment charge would be limited to the amount of the net
book value of the plant equipment and the amounts of accounts receivable
discussed above as of June 30, 2003.

We own a 50 percent interest in a 409-megawatt dual-fuel-fired power
project known as the Porto Velho Project, located in Porto Velho, Brazil. The
Porto Velho Project sells power to Centrais Electricas do Norte de Brasil S.A.
(Electronorte), a wholly owned subsidiary of Eletrobras. The Porto Velho Project
has two PPA's. The first PPA has a term of ten years and relates to the first
64-megawatt phase of the Porto Velho Project. The second PPA has a term of
twenty years and relates to the second 345-megawatt phase of the Porto Velho
Project (the Phase 2 PPA). We have recently reached an agreement with the
operating management of Eletronorte relating to the Phase 2 PPA, but the senior
management of Eletronorte has yet to approve the agreement and delays in getting
the amendment approved could occur. We will continue to monitor this situation,
and any possibility of having to renegotiate the Porto Velho Project's PPA's. If
we do not obtain approval of the PPA's and are forced to renegotiate the prices,
we could be required to impair our investment in the project. Our losses would
be limited to our investment. Our investment in the Porto Velho project was $281
million at June 30, 2003, including guarantees we have issued related to the
construction of the project.

Economic Conditions in the Dominican Republic. Recent developments in the
economic and financial situation in the Dominican Republic have led to a
devaluation of the Dominican peso of approximately 77 percent versus the U.S.
dollar since January 2003 (through June 30, 2003) and an increase in the local
inflation rate of approximately 25 percent for the same period. A stand-by
agreement with the IMF is expected to receive final approval of the IMF Board in
August. The Dominican government maintains that the accord, which should
hopefully lead to some $1.2 billion in disbursements from multilaterals over the
next 24 months, will serve to restore consumer and investor confidence,
stabilize the exchange rate and pave the way to economic recovery. The initial
disbursement of the funds is not anticipated until early September of 2003.

We have investments in power projects in the Dominican Republic with an
aggregate exposure, including financial guarantees, of approximately $104
million. We own a 48.33 percent interest in a 67 megawatt heavy fuel oil fired
power project known as the CEPP project. We also own a 24.99 percent interest in
a 513 megawatt power generating complex known as Itabo. As a consequence of
economic conditions described above and due to their inability to pass through
higher energy prices to their consumers, the local distribution companies that
purchase the electrical output of these facilities have been delinquent in their
payments to CEPP and Itabo, as well as the other generating facilities in the
Dominican Republic since April 2003. The failure to pay generators has resulted
in the inability of the generators to purchase fuel required for the production
of energy which has caused significant energy shortfalls in the country. We
currently believe that the economic difficulties in the Dominican Republic will
not have a material adverse effect on our investments, but we will continue to
monitor those conditions and are working with the government and the local
distribution companies to resolve these issues.

Meizhou Wan Power Project. We own a 25 percent equity interest in a
734-megawatt, coal-fired power generating project, Meizhou Wan Generating,
located in Fuzhou, People's Republic of China. Our investment in the project was
$57 million at June 30, 2003, and we have also issued $34 million in guarantees
and letters of credit for equity support and debt service reserves for the
project. The project debt is collateralized only by the project's assets and is
non-recourse to us. The project declared that it was ready for commercial
operations in August 2001; however, the provincial government, who also buys all
power generated from the project, has not accepted the project for commercial
operations. In October 2002, we reached an interim agreement to allow the plant
to operate and sell power at reduced rates until March 2003 while a long-term
resolution to existing and past contract terms is negotiated. In March 2003, a
letter was forwarded to the Province requesting that the interim agreement be
extended until such time that a long term agreement can be reached. Although the
Province has indicated that it will continue to pay the tariff provided for
under the Interim Agreement until the new long term tariff is signed, we
received a proposal from the Province in June 2003 for new rates that are
slightly lower than those in our interim agreement. The price the project
currently receives

43

from the sale of power in the interim agreement is expected to be sufficient to
provide for the operating costs and debt service of the project, but does not
provide for a return on investment to the project's owners. We are also seeking
to obtain local financing which will allow us to restructure the project debt on
more favorable terms, and achieve a lower cost structure for the project. If we
are unsuccessful in our ability to reach a long-term agreement with the
provincial government at rates sufficient to recover our investment or refinance
our debt on more favorable terms, we may be required to write-down the value of
our investment.

Milford Power Project. We own a 95 percent equity interest in a
540-megawatt power plant construction project located in Milford, Connecticut.
The project has been financed through equity contributions, construction
financing from lenders that is recourse only to the project and through a
construction management services agreement that we funded. This project has
experienced significant construction delays, primarily associated with
technological difficulties with its turbines including the inability to operate
on both gas and fuel oil or to operate at its designed capacity as specified in
the construction contract. In October 2001, we entered into a construction
management services agreement providing additional funding through October 1,
2002. The construction contractor failed to complete construction of the plant
prior to October 1, 2002, in accordance with the terms and specifications of the
construction contract. As a result, the project was in default under its
construction lending agreement. On October 25, 2002, we entered into a
standstill agreement with the construction lending banks that expired on
December 2, 2002. On March 4, 2003, we provided a notice to Milford declaring an
event of default under the fuel supply agreement between us and Milford due to
non-payment by Milford. On March 6, 2003, Milford received a notice from its
lenders stating that the lenders intended to commence foreclosure on the project
in accordance with the lending agreement within 30 days. The lenders have not
yet exercised this remedy. As a result of the default under the construction
lending agreement, we evaluated our investment and recorded an impairment charge
of $17 million while Chaparral recorded an impairment charge of $44 million in
the fourth quarter of 2002. In April 2003, El Paso's Board of Directors
authorized Milford to enter into settlement negotiations with the lenders to the
facility. Based upon the ongoing negotiations with the lenders and the Board's
authorization to settle these issues, we recorded an additional charge during
the first quarter of 2003 of approximately $86 million. These charges consisted
of advances to Milford and other estimated liabilities related to the project.
We are in the process of finalizing negotiations with the lenders to settle
these issues.

Berkshire Power Project. We own a 56.4 percent direct equity interest in a
261-megawatt power plant located in Massachusetts. The construction contractor
failed to deliver a plant capable of operating on both gas and fuel oil, or
capable of operating at its designed capacity. Berkshire is negotiating with the
contractor with respect to its failure to deliver the project in accordance with
guaranteed specifications. During the third quarter of 2002, the project lenders
asserted that Berkshire was in default on its loan agreement. Berkshire is in
the process of negotiating with its lenders to resolve disputed contract terms.
Failure to reach a satisfactory resolution in these matters could have a
material adverse effect on the value of our investment in the project. At June
30, 2003, we had an investment in Berkshire of $7 million, receivables from
Berkshire of $20 million and derivative contracts with Berkshire of $10 million
associated with a subordinated fuel agreement and a fuel management agreement.
Berkshire continues to discuss settlement opportunities with its construction
contractor. The ultimate resolution of these issues will be considered in the
determination of whether any of these investments in and receivables from
Berkshire will be impaired in the future.

Duke. Our subsidiary, SNG, owns a 50 percent equity investment in Citrus
Corporation.
On March 7, 2003, Citrus Trading Corp. (CTC), a direct subsidiary of Citrus,
filed suit against Duke Energy LNG Sales, Inc. titled Citrus Trading Corp. v.
Duke Energy LNG Sales, Inc. in the District Court of Harris County, Texas
seeking damages for breach of a gas supply contract pursuant to which CTC was
entitled to purchase, through August 2005, up to 30.4 billion cubic feet per
year of regasified liquefied natural gas (LNG). On April 14, 2003, Duke
forwarded to CTC a letter purporting to terminate the gas supply contract
effective April 16, 2003, due to the alleged failure of CTC to increase the
amount of an outstanding letter of credit backstopping its purchase obligations.
On April 16, 2003, Duke filed an answer to the complaint, stating that (1) CTC
had triggered the early termination of the gas supply agreement by allegedly
failing to provide an adequate letter of credit to Duke; (2) CTC had breached
the gas supply contract by allegedly violating certain use restrictions that
required volumes equivalent to those purchased by CTC from Duke to be sold by

44

CTC into the power generation market in the State of Florida; and (3) Duke was
partially excused from performance under the gas supply agreement by reason of
an alleged loss of supply of LNG on January 15, 2002 and would be fully excused
from providing replacement gas upon the earlier of (i) 730 days or (ii) the
incurrence of replacement costs equal to $60 million, escalated by the GNP
implicit price deflator commencing January 1990 (approximately $79 million as of
December 31, 2002). On April 29, 2003, Duke removed the pending litigation to
federal court, based on the existence of foreign arbitration with its supplier
of LNG, Sonatrading Amsterdam B.V., which had allegedly repudiated its supply
contract as of January 27, 2003. On May 1, 2003, CTC notified Duke that it was
in default under the gas supply contract, demanding cover damages for alternate
supplies obtained by CTC beginning April 17, 2003. On May 23, 2003, CTC filed a
motion to remand the case back to state court. On June 2, 2003, CTC gave notice
of early termination to Duke in preparation for the subsequent filing of an
amended petition for monetary damages. The outcome of this litigation is not
currently determinable. However, CTC subsequently invoiced Duke for cover
damages arising from the terminated contract. On July 31, 2003, the federal
court remanded this case back to state court. CTC plans to file its amended
petition for monetary damages on August 19, 2003. We do not expect the ultimate
resolution of this matter to have a material adverse effect on our financial
position, operating results or cash flows.

Cases

The California cases discussed above are five filed in the Superior Court
of Los Angeles County (Continental Forge Company, et al v. Southern California
Gas Company, et al, filed September 25, 2000*; Berg v. Southern California Gas
Company, et al, filed December 18, 2000*; County of Los Angeles v. Southern
California Gas Company, et al, filed January 8, 2002*; The City of Los Angeles,
et al v. Southern California Gas Company, et al and The City of Long Beach, et
al v. Southern California Gas Company, et al, both filed March 20, 2001*); two
filed in the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso
Merchant Energy; and John Phillip v. El Paso Merchant Energy, both filed
December 13, 2000*); and two filed in the Superior Court of San Francisco
County(Sweetie's et al v. El Paso Corporation, et al, filed March 22, 2001*; and
California Dairies, Inc., et al v. El Paso Corporation, et al, filed May 21,
2001); and one filed in the Superior Court of the State of California, County of
Alameda (Dry Creek Corporation v. El Paso Natural Gas Company, et al, filed
December 10, 2001*); and five filed in the Superior Court of Los Angeles
County(The City of San Bernardino v. Southern California Gas Company, et al; The
City of Vernon v. Southern California Gas Company; The City of Upland v.
Southern California Gas Company, et al; Edgington Oil Company v. Southern
California Gas Company, et al; World Oil Corporation, et al. v. Southern
California Gas Company, et al, filed December 27, 2002*). The two long-term
power contract lawsuits are James M. Millar v. Allegheny Energy Supply Company,
et al. filed May 13, 2002 in the Superior Court, San Francisco County,
California and Tom McClintock et al. v. Vikram Budhrajaetal filed May 1, 2002 in
the Superior Court, Los Angeles County, California. The cases referenced in
Other Energy Market Lawsuits are: The State of Nevada, et al. v. El Paso
Corporation, El Paso Natural Gas Company, El Paso Merchant Energy Company, et
al. filed November 2002 in the District Court for Clark County, Nevada*; Henry
W. Perlman, et al. v. San Diego Gas & Electric et al. filed December 2002, in
the United States District Court, Southern District of New York; State of
Arizona v El Paso Corporation, El Paso Natural Gas Company, El Paso Merchant
Energy Company, et al. filed March 10, 2003 in the Superior Court, Maricopa
County, Arizona; Sierra Pacific Resources et. al. v. El Paso Corporation et.
al., filed April 21, 2003 in the United States District Court for the District
of Nevada; and Jerry Egger, et. al. v. Dynegy, Inc., filed April 28, 2003 in the
Superior Court for the County of San Diego, California.

The purported shareholder class actions filed in the U.S. District Court
for the Southern District of Texas, Houston Division, are: Marvin Goldfarb, et
al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine,
filed July 18, 2002; Residuary Estate Mollie Nussbacher, Adele Brody Life
Tenant, et al v. El Paso Corporation, William Wise, and H. Brent Austin, filed
July 25, 2002; George S. Johnson, et al v. El Paso Corporation, William Wise,
and H. Brent Austin, filed July 29, 2002; Renneck Wilson, et al v. El Paso
Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August
1, 2002; and

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

*Cases to be dismissed upon finalization and approval of the Western Energy
Settlement.

45

Sandra Joan Malin Revocable Trust, et al v. El Paso Corporation, William Wise,
H. Brent Austin, and Rodney D. Erskine, filed August 1, 2002; Lee S. Shalov, et
al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine,
filed August 15, 2002; Paul C. Scott, et al v. El Paso Corporation, William
Wise, H. Brent Austin, and Rodney D. Erskine, filed August 22, 2002; Brenda
Greenblatt, et al v. El Paso Corporation, William Wise, H. Brent Austin, and
Rodney D. Erskine, filed August 23, 2002; Stefanie Beck, et al v. El Paso
Corporation, William Wise, and H. Brent Austin, filed August 23, 2002; J. Wayne
Knowles, et al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney
D. Erskine, filed September 13, 2002; The Ezra Charitable Trust, et al v. El
Paso Corporation, William Wise, Rodney D. Erskine and H. Brent Austin, filed
October 4, 2002. The purported shareholder action filed in the Southern District
of New York is IRA F.B.O. Michael Conner et al v. El Paso Corporation, William
Wise, H. Brent Austin, Jeffrey Beason, Ralph Eads, D. Dwight Scott, Credit
Suisse First Boston, J.P. Morgan Securities, filed October 25, 2002.

The shareholder derivative actions filed in Houston are Grunet Realty Corp.
v. William A. Wise, Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James
Gibbons, Anthony Hall Jr., Ronald Kuehn Jr., J. Carleton MacNeil Jr., Thomas
McDade, Malcolm Wallop, Joe Wyatt and Dwight Scott, filed August 22, 2002. John
Gebhart v. Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James Gibbons,
Anthony Hall Jr., Ronald Kuehn Jr., J. Carleton MacNeil Jr., Thomas McDade,
Malcolm Wallop, Joe Wyatt and William Wise, filed March 2002; Marilyn Clark v.
El Paso Natural Gas, El Paso Merchant Energy, Byron Allumbaugh, John Bissell,
Juan Carlos Braniff, James Gibbons, Anthony Hall Jr., Ronald Kuehn, Jr., J.
Carleton MacNeil, Jr., Thomas McDade, Malcolm Wallop, Joe Wyatt and William Wise
filed in November 2002. The shareholder derivative lawsuit filed in Delaware is
Stephen Brudno et al v. William A. Wise et al filed in October 2002.

The ERISA Class Action Suit is William H. Lewis III v. El Paso Corporation,
H. Brent Austin and unknown fiduciary defendants 1-100.

The customer complaints filed at the FERC against EPME and other wholesale
power marketers are: Nevada Power Company and Sierra Pacific Power Company vs.
El Paso Merchant Energy, L.P.; California Public Utilities Commission vs.
Sellers of Long-Term Contracts to the California Department of Water and
California Electricity Oversight Board vs. PacifiCorp vs. El Paso Merchant
Energy, L.P., and City of Burbank, California vs. Calpine Energy Services, L.P.,
Duke Energy Trading and Marketing, LLC, El Paso Merchant Energy.

19. CAPITAL STOCK

On August 1, 2003, we declared a quarterly dividend of $0.04 per share on
our common stock payable on October 6, 2003, to stockholders of record on
September 5, 2003. During the quarter and six months ended June 30, 2003, we
paid dividends of $24 million and $154 million to common stockholders. In
addition, El Paso Tennessee Pipeline Co., our subsidiary, paid dividends of
approximately $6 million and $12 million on its Series A cumulative preferred
stock, which is 8 1/4% per annum (2.0625% per quarter).

46

20. SEGMENT INFORMATION

We segregate our business activities into four operating segments:
Pipelines, Production, Field Services and Merchant Energy. These segments are
strategic business units that provide a variety of energy products and services.
They are managed separately as each business unit requires different technology,
operational and marketing strategies. We reclassified our historical coal mining
operation in the second quarter of 2002 and our petroleum and chemical
operations in the second quarter of 2003 from our Merchant Energy segment to
discontinued operations in our financial statements. Merchant Energy's operating
results for all periods presented reflect this change.

We use earnings before interest expense and income taxes (EBIT) to assess
the operating results and effectiveness of our business segments. We define EBIT
as net income (loss) adjusted for (i) items that do not impact our income (loss)
from continuing operations, such as extraordinary items, discontinued operations
and the impact of accounting changes, (ii) income taxes, (iii) interest and debt
expense and (iv) distributions on preferred interests of consolidated
subsidiaries. We exclude interest and debt expense and distributions on
preferred interests of consolidated subsidiaries so that investors may evaluate
our operating results without regard to our financing methods or capital
structure. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. As a result, we
believe EBIT, which includes the results of both these consolidated and
unconsolidated operations, is useful to our investors because it allows them to
more effectively evaluate the performance of all of our businesses and
investments. This measurement may not be comparable to measurements used by
other companies and should not be used as a substitute for net income or other
performance measures such as operating income or operating cash flow. The
reconciliations of EBIT to income (loss) from continuing operations are
presented below:

47

The following tables reflect our segment results as of and for the periods
ended June 30 (in millions):

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

(1) Includes our Corporate and telecommunication activities and eliminations of
intercompany transactions. Our intersegment revenues, along with our
intersegment operating expenses, were incurred in the normal course of
business between our operating segments. We record an intersegment revenue
elimination, which is the only elimination included in the "Other" column,
to remove intersegment transactions. Losses reflected in our Corporate
activities include approximately $396 million related to the impairment of
our telecommunication business in the second quarter of 2003, inclusive of a
write-down of goodwill of $163 million. See Note 8 for an additional
discussion of this impairment.

(2) Revenues from external customers include gains and losses related to our
hedging of price risk associated with our natural gas and oil production. A
loss occurs when hedged prices are lower than market prices. Intersegment
revenues represent sales to our marketing affiliate EPME, which is
responsible for marketing our production.

(3) Includes restructuring charges in connection with our ongoing liquidity
enhancement and cost saving efforts (see Note 5).

(4) Merchant Energy revenues were restated on July 1, 2002, due to the adoption
of a consensus reached on Emerging Issues Task Force (EITF) Issue No. 02-3,
Issues Related to Accounting for Contracts Involved in Energy Trading and
Risk Management Activities, which requires us to report all physical sales
of energy commodities in our energy trading activities on a net basis as a
component of revenues. See our 2002 Form 10-K regarding the adoption of EITF
Issue No. 02-3.

48

21. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS

We hold investments in affiliates which we account for using the equity
method of accounting. During the second quarter of 2003, we consolidated two of
our larger equity investments, Chaparral and Gemstone. See Note 3 for a further
discussion of these transactions. Summarized financial information of our
proportionate share of unconsolidated affiliates below includes affiliates in
which we hold an interest of 50 percent or less, and affiliates in which we hold
greater than 50 percent interest. Our proportional share of the net income
(loss) of the unconsolidated affiliates in which we hold a greater than 50
percent interest was $(2) million and $5 million for the quarters ended, and $5
million and $14 million for the six months ended June 30, 2003 and 2002.

Our income statement reflects our earnings (losses) from unconsolidated
affiliates. This amount includes income or losses directly attributable to the
net income or loss of our equity investments as well as impairments and other
adjustments to income we record as follows:

- ---------------
(1) The impairment results from the anticipated loss from the sale of our
interests in these investments.
(2) This impairment resulted from other than temporary declines in the
investment's fair value based on developments in our power business and the
power industry (see Note 3).
(3) This impairment resulted from a write-off of notes receivable and accruals
on contracts due to ongoing difficulty at the project level.
(4) This impairment resulted from weak economic conditions in Argentina.

50

We enter into a number of transactions with our unconsolidated affiliates
in the ordinary course of conducting our business. The following table shows
revenues, income and expenses incurred between us and our unconsolidated
affiliates for the periods ended June 30:

Chaparral and Gemstone

As of December 31, 2002, we held equity investments in both Chaparral and
Gemstone. During the second quarter of 2003, we acquired the remaining third
party equity interests in both of these entities and began consolidating them in
our consolidated financial statements. The following tables summarize our
overall investments in Chaparral and Gemstone as of December 31, 2002. For the
impact of these consolidations on our financial results, see Note 3.

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(1) These facilities earned interest at variable rates based on LIBOR. This rate
was 1.8 percent at March 31, 2003 and 1.9 percent at December 31, 2002.

51

GulfTerra Energy Partners

A subsidiary in our Field Services segment serves as the general partner of
GulfTerra, a master limited partnership that has limited partnership units that
trade on the New York Stock Exchange.

We currently own 11,674,245 of the partnership's common units, the one
percent general partner interest, all of the Series B preference units and all
of the Series C units. During the first half of 2003, we contributed
approximately $2 million of our Series B preference units to GulfTerra. This
contribution was made in order for us to maintain our one percent general
partner interest as a result of three common unit offerings completed by the
partnership.

Our segments also conduct transactions in the ordinary course of business
with GulfTerra, including sales of natural gas and operational services. Below
is the summary of our transactions with GulfTerra.

For a further discussion of our relationships with GulfTerra, see our 2002
Form 10-K.

52

22. NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

As of June 30, 2003, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.

Amendment of Statement 133 on Derivative Instruments and Hedging Activities

In April 2003, the Financial Accounting Standards Board (FASB) issued SFAS
No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging
Activities. This statement amends SFAS No. 133, Accounting for Derivative
Instruments and Hedging Activities to incorporate the interpretations of the
Derivatives Implementation Group (DIG), and also makes several minor
modifications to the definition of a derivative as it was defined in SFAS No.
133. SFAS No. 149 is effective for contracts entered into or modified after June
30, 2003. We do not believe there will be any initial impact of adopting this
standard.

Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity

In May 2003, the FASB issued SFAS No. 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity. This statement
provides guidance on the classification of financial instruments as equity, as
liabilities, or as both liabilities and equity. The provisions of SFAS No. 150
are effective for all financial instruments entered into or modified after May
31, 2003, and otherwise is effective at the beginning of the first interim
period beginning July 1, 2003. Based on our preliminary assessment of the
standard, we believe its provisions will require us to reclassify our Capital
Trust I and Coastal Finance I preferred interests (both currently classified as
preferred interests of consolidated subsidiaries) as liabilities beginning July
1, 2003. As of June 30, 2003, the Capital Trust I balance was $325 million and
the Coastal Finance I balance was $300 million.

Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51

In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities, an Interpretation of ARB No. 51. This interpretation defines
a variable interest entity as a legal entity whose equity owners do not have
sufficient equity at risk and/or a controlling financial interest in the entity.
This standard requires a company to consolidate a variable interest entity if it
is allocated a majority of the entity's losses and/or returns, including fees
paid by the entity. The provisions of FIN No. 46 are effective for all variable
interest entities created after January 31, 2003, and are effective on July 1,
2003, for all variable interest entities created before January 31, 2003.

Upon adoption of this standard on July 1, 2003, we will be required to
consolidate the preferred equity holder of one of our consolidated subsidiaries,
Coastal Securities Company Limited. The impact of this consolidation will be an
increase in long-term debt and a decrease in preferred interests in consolidated
subsidiaries by $100 million. We will also be required to consolidate Rondonia
Power Company, an equity investment that holds our Porto Velho power project in
Brazil. The impact of this consolidation will be an increase in property, plant
and equipment of approximately $244 million, an increase to current assets of
approximately $20 million and a decrease in notes receivable from affiliates by
approximately $274 million. We also continue to evaluate our other joint venture
and financing arrangements to assess the impact, if any, of FIN No. 46 on those
arrangements.

53

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The information contained in Item 2 updates, and you should read it in
conjunction with, information disclosed in our 2002 Annual Report on Form 10-K
and the financial statements and notes presented in Item 1 of this Form 10-Q.

OVERVIEW

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;

- 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; 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;

- 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);

- Identifying an estimated $445 million of costs 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 in July
2003.

54

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW OF CASH FLOW ACTIVITIES FOR THE SIX MONTHS ENDED JUNE 30, 2003

For the six months ended June 30, 2003 and 2002, our cash flows are
summarized as follows:

During the six months ended June 30, 2003, our cash and cash equivalents
increased by approximately $0.2 billion to approximately $1.8 billion. We
generated cash from several sources, including cash flows from our principal
continuing as well as discontinued operations, sales of assets and issuances of
long-term debt. We used a major portion of that cash to fund our capital
expenditures, to purchase additional investments in subsidiaries and to redeem
preferred interests of minority interest holders. Overall, our cash sources and
uses were summarized as follows (in billions):

Cash inflows
Cash flows from continuing operations (before working and
non-working capital changes)........................... $ 0.8
Working capital and non-working capital changes........... 0.1
Net proceeds from the sale of assets and investments...... 1.3
Net proceeds from the issuance of long-term debt.......... 3.1
Borrowings under revolving credit facility................ 0.5
Net discontinued operations activity...................... 0.4
Other..................................................... 0.1
-----
Total cash inflows..................................... 6.3
-----
Cash outflows
Additions to property, plant and equipment................ 1.3
Net cash paid to acquire Chaparral and Gemstone........... 1.1
Payments to redeem preferred interests of consolidated
subsidiaries........................................... 1.2
Payments to retire long-term debt......................... 1.6
Payments on short-term revolving credit facilities........ 0.5
Dividends paid to common stockholders..................... 0.2
Other..................................................... 0.2
-----
Total cash outflows.................................... 6.1
-----
Net increase in cash................................. $ 0.2
=====

55

A more detailed analysis of our cash flows from operating, investing and
financing activities follows.

Cash From Continuing Operating Activities

Overall, cash generated from continuing operating activities for the six
months ended June 30, 2003, was $0.9 billion versus $0.7 billion in the same
period of 2002. We generated approximately $0.8 billion in cash from operations
(net income from continuing operations adjusted for non-cash income items) in
2003 before working capital and non-working capital changes, as compared to $1.2
billion in 2002. The decline in 2003 was primarily a result of asset sales
during both 2002 and 2003. Working capital uses were $0.1 billion in 2003 as
compared to a use of cash of $0.4 billion in 2002. During 2002, we used a
significant amount of working capital due to increases in natural gas prices and
the resulting changes in margins outstanding against our hedged natural gas
production. So far in 2003, we have experienced higher margin calls due to
continued increases in gas prices and collateral demands on us due to the
reduction in our credit ratings, offset by recoveries of collateral through the
use of letters of credit under our new revolving credit facilities. As a result,
our 2003 margin activity has been relatively flat.

Cash From Continuing Investing Activities

Net cash used in our continuing investing activities was $1.3 billion for
the six months ended June 30, 2003. Our investing activities consisted primarily
of capital expenditures and additional investments, primarily in Chaparral and
Gemstone as follows (in billions):

Production exploration, development and acquisition
expenditures.............................................. $0.9
Pipeline expansion, maintenance and integrity projects...... 0.3
Net cash paid to acquire Chaparral and Gemstone............. 1.1
Other (primarily power projects)............................ 0.1
----
Total capital expenditures and additional
investments....................................... $2.4
====

Cash received from our investing activities includes $1.3 billion from the
sale of assets and investments, including the sale of natural gas and oil
properties located in western Canada, New Mexico, Oklahoma and the Gulf of
Mexico for $0.7 billion, the sale of an equity investment in CE Generation for
$0.2 billion and the sale of other pipeline, power, and processing assets of
$0.4 billion.

Cash From Continuing Financing Activities

Net cash provided by our continuing financing activities was $0.6 billion
for the six months ended June 30, 2003. Cash provided from our financing
activities included the net proceeds from the issuance of long-term debt of $3.1
billion, $0.4 billion of cash contributed by our discontinued operations and
other financing activities of $0.1 billion. Cash used by our financing
activities included payments made to retire third party long-term debt of $1.6
billion. We also paid $1.2 billion to fully redeem the Trinity River preferred
securities and partially redeem Clydesdale preferred securities previously
issued by our subsidiaries and paid dividends of $0.2 billion to common
stockholders.

Cash from Discontinued Operations

During the first six months of 2003, our discontinued operations generated
$0.4 billion of cash which were distributed to our continuing operations.
Operating cash flow was approximately $0.1 billion, which was generated
primarily through sales of inventories at our refineries. Cash from investing
activities was $0.3 billion which was generated through asset sales of $0.4
billion, offset by capital expenditures of $0.1 billion.

56

FINANCING AND COMMITMENTS

Our 2002 Form 10-K includes a detailed discussion of our liquidity,
financing activities, contractual obligations and commercial commitments. The
information presented below updates, and you should read it in conjunction with,
the information disclosed in our 2002 Form 10-K.

During the first six months of 2003, we completed a number of actions
intended to simplify our financial and capital structure, refinance shorter term
obligations and eliminate guarantees and other "off-balance sheet" obligations
and replace them with direct financial obligations. These actions included
entering into a new $3 billion revolving credit facility, acquiring and
consolidating a number of entities with existing debt, refinancing shorter-term
obligations with longer-term borrowings and redeeming and eliminating preferred
interests in our subsidiaries as follows (in millions):

Short-term financing obligations, including current
maturities................................................ $ 2,075
Notes payable to affiliates................................. 390
Long-term financing obligations............................. 16,106
Securities of subsidiaries.................................. 3,420
-------
Total debt and securities of subsidiaries,
December 31, 2002................................ 21,991
-------
Acquisitions and consolidations:
Chaparral and Gemstone.................................... 2,578
Operating leases and refinanced securities of
subsidiaries........................................... 1,018
Elimination of affiliated obligations..................... (326)
Principal amounts borrowed.................................. 3,695
Repayments of principal..................................... (2,108)
Redemptions and eliminations of securities of
subsidiaries.............................................. (2,330)
Other....................................................... 26
-------
Total debt and securities of subsidiaries, June
30, 2003......................................... $24,544
=======

Our financing activities are discussed in greater detail below:

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 as discussed in Item 1, 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, TGP, ANR,
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 Item 1, 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

57

EPNG and TGP will be 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 our
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.

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.

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.

Notes Payable to Affiliates

Our notes payable to unconsolidated affiliates as of June 30, 2003, were
$16 million versus $390 million as of December 31, 2002. The decrease was
primarily due to the consolidation of $122 million of Gemstone and $203 million
of Chaparral debt securities in the second quarter of 2003. Also contributing to
the decrease was the retirement of $45 million of Chapparal debt securities in
the first quarter of 2003.

Minority and Preferred Interests of Consolidated Subsidiaries

The total amount outstanding for securities of subsidiaries and preferred
stock of consolidated subsidiaries was $1.1 billion at June 30, 2003, versus
$3.4 billion at December 31, 2002. The decrease was due to the retirements of
$980 million of Trinity River preferred interests and $197 million of preferred
member interests in Clydesdale in 2003. In the second quarter of 2003, we
retired an additional $753 million of Clydesdale preferred member interests,
converting it into a loan that matures in equal installments through 2005, and
also eliminated the entire $300 million of Gemstone's minority member interest
following our acquisition and consolidation of Gemstone. See Item 1, Notes 3 and
17 for a further discussion of preferred interests of our consolidated
subsidiaries.

Letters of Credit

We enter into letters of credit in the ordinary course of our operating
activities. As of June 30, 2003, we had outstanding letters of credit of
approximately $1.5 billion and $852 million as of December 31, 2002. The
increase was primarily due to issuing letters of credit under our revolving
credit facilities in lieu of cash to support our petroleum and trading business.
Of the outstanding letters of credit, $146 million was supported with cash
collateral.

59

SEGMENT RESULTS

We use earnings before interest expense and income taxes (EBIT) to assess
the operating results and effectiveness of our business segments. We define EBIT
as net income (loss) adjusted for (i) items that do not impact our income (loss)
from continuing operations, such as extraordinary items, discontinued operations
and the impact of accounting changes, (ii) income taxes, (iii) interest and debt
expense and (iv) distributions on preferred interests of consolidated
subsidiaries. We exclude interest and debt expenses and distributions on
preferred interests of consolidated subsidiaries so that investors may evaluate
our operating results without regard to our financing methods or capital
structure. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. As a result, we
believe EBIT, which includes the results of both these consolidated and
unconsolidated operations, is useful to our investors because it allows them to
more effectively evaluate the performance of all of our businesses and
investments. This measurement may not be comparable to measurements used by
other companies and should not be used as a substitute for net income or other
performance measures such as operating income or operating cash flow. The
following is a reconciliation of our operating income (loss) to our EBIT and our
EBIT to our net income (loss) for the periods ended June 30:

60

OVERVIEW OF RESULTS OF OPERATIONS

Below are our results of operations (as measured by EBIT) by segment. Our
four operating segments -- Pipelines, Production, Field Services and Merchant
Energy -- provide a variety of energy products and services. They are managed
separately as each business unit requires different technology, operational and
marketing strategies. We reclassified our historical coal mining operation in
the second quarter of 2002 and our petroleum and chemical operations in the
second quarter of 2003 from our Merchant Energy segment to discontinued
operations in our financial statements. Merchant Energy's results for all
periods presented reflect this change. For a further discussion of charges and
other income and expense items impacting the results below, see Item 1, Notes 2
through 9 and 21.

PIPELINES

Our Pipelines segment holds our interstate transmission businesses. For a
further discussion of the business activities of our Pipelines segment, see our
2002 Form 10-K. Results of our Pipelines segment operations were as follows for
the periods ended June 30:

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

(1) Throughput volumes for the quarter and six months ended June 30, 2002,
exclude 208 BBtu/d and 216 BBtu/d related to our equity investment in the
Alliance pipeline system which was sold in November 2002 and March 2003.
Throughput volumes also exclude volumes transported between entities within
the Pipelines segment. Prior period volumes have been restated to reflect
current year presentation which includes billable transportation throughput
volume for storage injection and withdrawal.

61

Second Quarter 2003 Compared to Second Quarter 2002

Operating revenues for the quarter ended June 30, 2003, were $9 million
lower than the same period in 2002. The decrease was primarily due to lower
revenues of $27 million due to CIG's sale of the Panhandle field and other
production properties in July 2002 and a decrease of $13 million due to capacity
contracts that have expired which EPNG is prohibited from remarketing due to its
September 20, 2002 FERC order. See Item 1, Note 18 for a further discussion of
this order. These decreases were partially offset by the impact of higher prices
in 2003 on natural gas recovered in excess of amounts used in operations of $12
million, increased transportation usage revenues of $8 million due to higher
contract rates in 2003 and increased revenues of $11 million due to system
expansion projects and new transportation contracts.

Operating expenses for the quarter ended June 30, 2003, were $156 million
higher than the same period in 2002. The increase was primarily due to charges
related to EPNG's portion of the Western Energy Settlement of $154 million (see
Item 1, Notes 6 and 18 for a discussion of this settlement). Also contributing
to the increase were lower corporate overhead allocations in 2002 versus 2003 of
$27 million. These increases were offset by lower environmental and legal costs
of $25 million in 2003 versus 2002 as a result of changes in our estimated
future environmental remediation and legal costs and a $14 million reduction in
operating costs due to CIG's sale of its Panhandle field and other production
properties.

Other income for the quarter ended June 30, 2003, was $13 million lower
than the same period in 2002. The decrease was due to lower equity earnings of
$6 million due to the sale of our interests in the Alliance pipeline system
completed in the first quarter of 2003, lower earnings of $5 million from our
investment in Citrus and the favorable resolution of uncertainties associated
with the 2002 sale of our interest in the Iroquois pipeline system of $4
million.

Six Months Ended 2003 Compared to Six Months Ended 2002

Operating revenues for the six months ended June 30, 2003, were $39 million
higher than the same period in 2002. The increase was due to higher volumes and
prices in 2003 on natural gas recovered in excess of amounts used in operations
of $40 million, increased transportation revenues of $24 million due to higher
throughput volumes in 2003 resulting from colder winter weather, increased
revenues of $18 million due to system expansion projects and new transportation
contracts, $14 million from higher realized prices in 2003 on the resale of
natural gas purchased from the Dakota gasification facility and higher sales
under natural gas purchase contracts of $11 million. These increases were offset
primarily by lower revenues of $47 million due to CIG's sale of its Panhandle
field and other production properties and a $28 million revenue reduction from
capacity contracts that have expired which EPNG is prohibited from remarketing
due to its FERC order.

Operating expenses for the six months ended June 30, 2003, were $177
million higher than the same period in 2002. The increase was primarily due to
charges related to EPNG's portion of the Western Energy Settlement of $158
million. Also contributing to the increase were lower corporate overhead
allocations in 2002 versus 2003 of $27 million, higher prices on natural gas
purchased at the Dakota gasification facility of $13 million, higher fuel and
system supply purchases in 2003 of $12 million resulting from higher prices and
volumes and an $11 million gain on the sale of pipeline expansion rights in
February 2002. These increases were offset primarily by a $26 million decrease
in operating costs due to CIG's sale of its Panhandle field and other production
properties, lower environmental remediation and legal costs of $24 million and a
$12 million decrease due to bad debt expense recorded in 2002 related to the
bankruptcy of Enron Corp.

Other income for the six months ended June 30, 2003, was $10 million lower
than the same period in 2002. The decrease was due to lower equity earnings of
$11 million due to the sale of our interest in the Alliance pipeline system
completed in the first quarter of 2003, the favorable resolution of
uncertainties in 2002 of $8 million associated with the sale of our interests in
the Iroquois and Empire State pipeline systems and the Gulfstream pipeline
project in 2001. The decreases were offset by higher equity earnings in 2003
from our investment in Citrus of $8 million.

62

PRODUCTION

Our Production segment conducts our natural gas and oil exploration and
production activities. Our operating results are driven by a variety of factors
including the ability to locate and develop economic natural gas and oil
reserves, extract those reserves with minimal production costs, sell the
products at attractive prices and operate at the lowest total cost level
possible.

As further described in our 2002 Form 10-K, Production has historically
engaged in hedging activities on its natural gas and oil production to stabilize
cash flows and to reduce the risk of downward commodity price movements on its
sales. As of June 30, 2003, we have hedged approximately 108 million MMBtu's of
our remaining anticipated natural gas production for 2003 at a NYMEX Henry Hub
price of $3.45 per MMBtu before regional price differentials and transportation
costs.

Our depletion rate is determined under the full cost method of accounting.
We expect a higher depletion rate in future periods as a result of higher
finding and development costs experienced in the first half of 2003, coupled
with a lower reserve base due to asset sales. For the third quarter of 2003, we
expect our domestic unit of production depletion rate to be approximately $1.76
per Mcfe.

Results of our Production segment operations were as follows for the
periods ended June 30:

- ---------------
(1) Include production costs, depletion, depreciation and amortization, ceiling
test charges, asset impairments, gain and loss on long-lived assets,
corporate overhead, general and administrative expenses and severance and
other taxes.

(2) Prices are stated before transportation costs.

63

Second Quarter 2003 Compared to Second Quarter 2002

Operating revenues for the quarter ended June 30, 2003, were $68 million
lower than the same period in 2002. Our natural gas revenues, including the
impact of hedges, were $26 million lower in the second quarter of 2003. Our 2003
natural gas production volumes were lower by 19 percent, resulting in an $85
million decrease in revenues, from the same period in 2002. Realized natural gas
prices rose in 2003 by 17 percent, resulting in a $59 million increase in
revenues, when compared to the same period in 2002. The overall decline in
natural gas volumes was due to sales of production properties in Colorado, New
Mexico, Oklahoma, Utah, Texas and western Canada as well as normal production
declines and mechanical failures on certain producing wells. Our oil, condensate
and liquids revenues, including the impact of hedges, were $47 million lower in
the second quarter of 2003. Our 2003 oil, condensate and liquids volumes
decreased by 46 percent, resulting in a $55 million decrease in revenues, from
the same period in 2002. Realized oil, condensate and liquids prices rose in
2003 by 13 percent, resulting in an $8 million increase in revenues, when
compared to the same period in 2002. The declines in volumes were primarily due
to the property sales and production declines mentioned above.

Transportation and net product costs for the quarter ended June 30, 2003,
were $9 million lower than the same period in 2002 primarily due to lower
natural gas volumes subject to transportation fees.

Operating expenses for the quarter ended June 30, 2003, were $218 million
lower than the same period in 2002 primarily due to a second quarter of 2002
non-cash full cost ceiling test charge of $234 million incurred primarily in our
Canadian full cost pool. Also contributing to the decrease were lower oilfield
service costs of $20 million primarily due to asset dispositions which resulted
in lower labor and production processing fees and a $5 million gain on the sales
of non-full cost pool assets. Partially offsetting these decreases were higher
depletion expenses of $7 million, comprised of a $49 million increase due to
higher depletion rates in 2003 and costs of $5 million related to the accretion
of our liability for asset retirement obligations, partially offset by a $47
million decrease due to lower production volumes in 2003. The higher depletion
rate resulted from higher capitalized costs in the full cost pool coupled with a
lower reserve base. In addition, these decreases were offset by higher corporate
overhead allocations of $16 million, higher severance and other taxes of $12
million in 2003 and intangible asset impairments of $5 million in 2003 related
to non-full cost assets in Canada. The increase in severance taxes was primarily
due to tax credits taken in 2002 for qualified natural gas wells.

Other income for the quarter ended June 30, 2003, was $2 million higher
than the same period in 2002 primarily due to higher earnings in 2003 from
Pescada, an equity investment in Brazil.

Six Months Ended 2003 Compared to Six Months Ended 2002

Operating revenues for the six months ended June 30, 2003, were $23 million
lower than the same period in 2002. Our natural gas revenues, including the
impact of hedges, were $16 million lower in 2003. Our 2003 natural gas
production volumes were lower by 22 percent, resulting in a $199 million
decrease in revenues, from the same period in 2002. Realized natural gas prices
rose in 2003 by 25 percent, resulting in a $183 million increase in revenues,
when compared to the same period in 2002. The decline in natural gas volumes was
due to sales of production properties in Colorado, New Mexico, Oklahoma, Utah,
Texas and western Canada as well as normal production declines and mechanical
failures on certain producing wells. Our oil, condensate and liquids revenues,
including the impact of hedges, were $23 million lower in 2003. Our 2003 oil,
condensate and liquids volumes decreased by 36 percent, resulting in a $71
million decrease in revenues, from the same period in 2002. Realized oil,
condensate and liquids prices rose in 2003 by 38 percent, resulting in a $48
million increase in revenues, when compared to the same period in 2002. The
declines in volumes were primarily due to the property sales and production
declines mentioned above. Partially offsetting the decrease was a higher
mark-to-market loss of $15 million in 2002 compared to 2003 related to hedges of
anticipated future production that no longer qualified for hedge accounting when
we sold those properties in March 2002.

64

Operating expenses for the six months ended June 30, 2003, were $242
million lower than the same period in 2002 primarily due to a 2002 non-cash full
cost ceiling test charge of $267 million for our international properties in
Canada, Turkey, Brazil and Australia. Also contributing to the decrease were
lower oilfield service costs of $35 million primarily due to asset dispositions
which resulted in lower labor and production processing fees and a $5 million
gain on the sales of non-full cost pool assets. Partially offsetting the
decreases were higher depletion expenses of $5 million, comprised of a $90
million increase due to higher depletion rates in 2003 and costs of $10 million
related to the accretion of our liability for asset retirement obligations,
partially offset by a $95 million decrease due to lower production volumes in
2003. The higher depletion rate resulted from higher capitalized costs in the
full cost pool coupled with a lower reserve base. In addition, these decreases
were offset by higher corporate overhead allocations of $21 million, higher
severance and other taxes of $19 million in 2003, intangible asset impairments
of $14 million in 2003 on non-full cost assets in Canada and employee severance
costs of $4 million in 2003. The increase in severance taxes was primarily due
to tax credits taken in 2002 for qualified natural gas wells.

Other income for the six months ended June 30, 2003, was $10 million higher
than the same period in 2002 primarily due to higher earnings in 2003 from our
Pescada investment.

FIELD SERVICES

Our Field Services segment conducts our midstream activities. A subsidiary
in our Field Services segment serves as the general partner of GulfTerra and
owns a one percent general partner interest. In April 2003, we announced we may
sell between five and ten percent of our one percent general partner interest.
In addition to our general partner interest, we currently own, through various
subsidiaries, 23.5 percent of the partnership's common units, all of its Series
B preference units and all of its Series C units. We may also sell some of our
common unit holdings, and 2,000,000 of our common units have been registered for
possible sale. We recognize earnings and receive cash from the partnership in
several ways, including through a share of the partnership's cash distributions
and through our ownership of limited, preferred and general partner interests.
We are also reimbursed for costs we incur to provide various operational and
administrative services to the partnership. In addition, we are reimbursed for
other costs paid directly by us on the partnership's behalf. During the quarter
and six months ended June 30, 2003, we were reimbursed approximately $22 million
and $46 million for expenses incurred on behalf of the partnership. During the
quarter and six months ended June 30, 2002, we were reimbursed approximately $15
million and $23 million for expenses incurred. Our earnings and cash from
GulfTerra were as follows:

- ---------------
(1) The partnership is not obligated to pay cash distributions on these units
until 2010.

In the second quarter of 2003, we sold our midstream assets in the
Mid-Continent and north Louisiana regions. Our Mid-Continent assets primarily
included our Greenwood, Hugoton, Keyes and Mocane natural gas gathering systems,
our Sturgis, Mocane and Lakin processing plants and our processing arrangements
at three additional processing plants. Our north Louisiana assets primarily
included our Dubach processing plant and Gulf States interstate natural gas
transmission system. These assets generated EBIT of approximately $10 million
during the year ended December 31, 2002. Our remaining assets now consist
primarily of our investment in GulfTerra and processing facilities in the south
Texas, south Louisiana and Rocky Mountain regions.

65

As a result of our asset sales and the resulting decline in our gathering
and treating activities, our EBIT has decreased significantly. However, the
increases in earnings from our interests in GulfTerra have partially offset this
decrease in EBIT primarily because some of the assets were sold to the
partnership. For a further discussion of the business activities of our Field
Services segment, see our 2002 Form 10-K. Results of our Field Services segment
operations were as follows for the periods ended June 30:

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

(1) Gross margins consist of operating revenues less cost of products sold. We
believe this measurement is more meaningful for analyzing our Field Services
operating results because commodity costs play such a significant role in
the determination of profit from our midstream activities.
(2) Includes equity earnings from our investment in GulfTerra.

Second Quarter 2003 Compared to Second Quarter 2002

Total gross margins for the quarter ended June 30, 2003, were $55 million
lower than the same period in 2002, primarily as a result of our asset sales in
2002 and 2003, the most significant of these being the sale of the San Juan
Basin assets in November 2002. The sale of these assets decreased gathering
margins by $28 million and processing margins by $4 million. Processing margins
also decreased $7 million in the second quarter of 2003 largely due to higher
natural gas prices relative to NGL prices, which reduced our margin per unit
processed and caused us to minimize the amount of NGLs that were extracted by
our natural gas processing facilities in Texas.

Operating expenses for the quarter ended June 30, 2003, were $3 million
lower than the same period in 2002 primarily due to the asset sales discussed
above, resulting in lower operating costs of $8 million and lower depreciation
expenses of $8 million. Also contributing to the decrease in operating expenses
was a net gain of $14 million from the sale of our Mid-Continent and north
Louisiana midstream assets in the second quarter of 2003 and higher
reimbursements of $4 million from GulfTerra for administrative and other
services to operate their assets. The increase in reimbursements was a direct
result of the additional assets that GulfTerra currently owns. These decreases
were partially offset by a $10 million gain in the second quarter of 2002 from
the sale of our Dragon Trail processing plant, an increase in corporate overhead
allocations of $10 million in 2003, $8 million of purchase price adjustments in
2003 to gains from asset sales during 2002 and an additional legal reserve of $5
million in 2003.

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Other expense for the quarter ended June 30, 2003, included $80 million in
impairment charges on our Dauphin Island Gathering Partners and Mobile Bay
Processing Partners investments. The impairment was recorded based on an
expected loss from the anticipated sale of our interests in these investments.
Partially offsetting the impact of this impairment were increased earnings of
$12 million from our investment in GulfTerra, as well as a $12 million gain
resulting from GulfTerra's issuance of common units in the second quarter. As
GulfTerra issues common units, we may recognize gains or losses to the extent
our proportionate share of GulfTerra's equity increases or decreases.

Six Months Ended 2003 Compared to Six Months Ended 2002

Total gross margins for the six months ended June 30, 2003, were $133
million lower than the same period in 2002 primarily as a result of our asset
sales in 2002 and 2003, the most significant of these being the sale of the
Texas and New Mexico assets in April 2002 and the San Juan Basin assets in
November 2002. The sale of these assets decreased gathering margins by $85
million and processing margins by $15 million. Processing margins also decreased
$9 million in the first six months of 2003 largely due to higher natural gas
prices relative to NGL prices, which reduced our margin per unit processed and
caused us to minimize the amount of NGLs that were extracted by our natural gas
processing facilities in Texas. Gathering margins were also lower in 2003 by $13
million due to the favorable resolutions of fuel, rate and volume matters in the
first quarter 2002.

Operating expenses for the six months ended June 30, 2003, were $43 million
lower than the same period in 2002 primarily due to the asset sales discussed
above, resulting in lower operating costs of $29 million and lower depreciation
expenses of $17 million. Also contributing to the decrease in operating expenses
was a net gain of $14 million from the sale of our Mid-Continent and north
Louisiana midstream assets in the second quarter of 2003 and higher
reimbursements of $10 million from GulfTerra to provide administrative and other
services to operate their assets. The increase in reimbursements was a direct
result of the additional assets that GulfTerra currently owns. In addition, our
2002 cost reduction plan, initiated mid-2002, resulted in $6 million of lower
operating costs in 2003. These decreases were partially offset by a $10 million
gain in the second quarter of 2002 from the sale of our Dragon Trail processing
plant, an increase in corporate overhead allocations of $10 million in 2003, $9
million of purchase price adjustments in 2003 to gains from asset sales during
2002 and an additional legal reserve of $5 million in 2003.

Other expense for the six months ended June 30, 2003, included $80 million
in impairment charges on our Dauphin Island Gathering Partners and Mobile Bay
Processing Partners investments. Partially offsetting the impact of this
impairment were increased earnings of $26 million from our investment in
GulfTerra, as well as a $12 million gain resulting from GulfTerra's issuance of
common units in the second quarter as described above.

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MERCHANT ENERGY

Our Merchant Energy segment consists of three divisions: global power,
energy trading and other. Historically, our Merchant Energy segment also
included our petroleum division. In June 2003, we announced that the Board of
Directors had approved the sale of substantially all of our petroleum
operations. As a result, the petroleum operations were reclassified as
discontinued operations for all the historical periods presented. For a further
discussion of our petroleum operations, see Item 1, Note 11. The petroleum
division previously included our LNG business activities and equity earnings on
a gas processing plant. These operations are now included in the "Other"
division in the tables below. Below are Merchant Energy's operating results and
an analysis of those results for the periods ended June 30:

Global Power

Our global power division includes the ownership and operation of domestic
and international power generating facilities. Our 2002 Form 10-K includes a
description of the various power activities included in global power. Our global
power division has undergone significant changes in 2002 and 2003 in our
business strategies. For example, in 2002 we were involved in restructuring
power contracts as more fully described in our 2002 Form 10-K. Due to a decline
in our credit rating in late 2002 and early 2003, we no longer pursue those
restructuring activities and are considering selling our domestic power
operations.

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Many of our domestic and international power projects have been held in
Chaparral and Gemstone. During 2003, we obtained control of these two entities,
acquiring the remaining third party equity interests and consolidating their
operations. For a discussion of the acquisition of Chaparral and Gemstone, see
Item 1 Note 3. In 2002, Chaparral and Gemstone were accounted for as
unconsolidated equity investments. Because of the changes in our business
strategies and differences in our accounting methods, the operating results of
our power operations between 2003 and 2002 are not necessarily comparable.

Additionally, because of the substantial increase in our non-trading power
restructuring derivative instruments that we acquired through Chaparral, we
increased our exposure to changes in the fair value of these instruments. This
exposure relates to changes in the underlying rates used to discount the
expected cash flows associated with these contracts as more fully explained in
Item 3, Quantitative and Qualitative Disclosures About Market Risk.

Results of our global power division were as follows for the periods ended
June 30:

Second Quarter 2003 Compared to Second Quarter 2002

Gross margin consists of revenues from our power plants and the net results
from our power restructuring activities. The cost of fuel in the power
generation process is included in operating expenses. For the quarter ended June
30, 2003, our gross margin was $16 million higher than the same period in 2002.
The increase was primarily due to $145 million of gross margins earned by power
plants we consolidated in the second quarter of 2003 associated with the
consolidation of Chaparral and Gemstone and an increase of $26 million due to
increases in the fair values of our power restructuring contracts during 2003.
These increases were partially offset by a $90 million gain recorded in 2002 on
the termination of a power purchase agreement at our Nejapa power facility,
lower power generation revenues of $27 million due to the partial shutdown of
our Eagle Point Cogeneration facility during the first six months of 2003 for
maintenance needed to convert the power plant to a merchant power plant and a
$46 million management fee we received from Chaparral in the second quarter of
2002 that we did not receive in 2003.

Operating expenses for the quarter ended June 30, 2003, were $46 million
higher than the same period in 2002. The increase was primarily due to $93
million of operating expenses incurred by power plants we consolidated in the
second quarter of 2003 associated with the consolidation of Chaparral and
Gemstone, partially offset by $16 million of decreased operating costs for power
facilities converted to a merchant basis as a result of restructuring activities
in 2002. In 2003, we also experienced $20 million of lower payroll expenses
associated with our employee reductions.

Other income for the quarter ended June 30, 2003, was $22 million higher
than the same period in 2002. This increase was primarily due to a gain on the
sale of our CAPSA/CAPEX investments in Argentina for $24 million in 2003 and $13
million of minority interest expense recorded in 2002 associated with the
termination of a power purchase agreement at our Nejapa power facility. These
increases were partially offset by a net $7 million decrease in equity earnings
due to the consolidation of Chaparral and Gemstone in the second quarter of
2003.

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Six Months Ended 2003 Compared to Six Months Ended 2002

For the six months ended June 30, 2003, our gross margin was $401 million
lower than the same period in 2002. The decrease was primarily due to power
contract restructurings for our Eagle Point Cogeneration, Mount Carmel and
Nejapa power plants that we completed in 2002, which contributed $562 million to
our gross margin in 2002, including an $80 million loss on a power supply
agreement that we entered into with our energy trading division in the first
quarter of 2002 associated with the Eagle Point Cogeneration power contract
restructuring transaction. The effects of this power supply agreement were
eliminated from Merchant Energy's consolidated results. Contributing to the
decrease in gross margin was a decrease of $63 million in 2003 power generation
revenues primarily due to the partial shutdown of our Eagle Point Cogeneration
facility during the first six months of 2003 for maintenance needed to convert
the power plant to a merchant power plant. Also contributing to the decrease was
$92 million in management fees we received from Chaparral in 2002 that we did
not receive in 2003. Partially offsetting these decreases were $226 million of
gross margins earned by power plants we consolidated in 2003 associated with the
consolidation of Chaparral and Gemstone and increases in the fair values of our
power restructuring contracts of $44 million during 2003.

Operating expenses for the six months ended June 30, 2003, were $72 million
higher than the same period in 2002. The increase was primarily due to $178
million of operating expenses incurred by power plants we consolidated in 2003
associated with the consolidation of Chaparral and Gemstone, partially offset by
$40 million of decreased operating costs resulting primarily from converting
several of our power plants to merchant plants in conjunction with our power
restructuring activities in 2002 and a $19 million turbine forfeiture fee paid
in 2002 as plans for future construction of new power plants were reduced.
Additionally, our payroll, and related employee costs were lower by $32 million
due to a reduction in the number of employees.

Other expenses for the six months ended June 30, 2003, were $309 million
lower than the same period in 2002. This decrease was primarily due to $342
million of impairment charges in 2002 on our Agua del Cajon, CAPSA/CAPEX and
Costanera investments in Argentina, $13 million of minority interest expense
recorded in 2002 associated with the termination of a power purchase agreement
at our Nejapa power facility and a $90 million contract termination fee we paid
in 2002 to our petroleum division associated with the termination of a steam
contract between our Eagle Point Cogeneration facility and the Eagle Point
refinery (which is included in our petroleum division reflected in discontinued
operations). Also contributing to the decrease in other expenses was a $130
million increase in equity earnings due to the consolidation of Chaparral and
Gemstone in 2003 and a $24 million gain on the sale of our CAPSA/CAPEX
investments in Argentina in 2003. The decrease in other expenses were primarily
offset by a $207 million impairment we recorded on our Chaparral investment in
2003 and an additional $86 million loss on the impairment of notes from our
Milford equity investment and loss accruals related to other associated
contracts in 2003. Milford's losses are based on ongoing settlement negotiations
related to this investment.

Energy Trading

In November 2002, we announced that we would exit the energy trading
business due to the increasing and volatile cash demands inherent in that
business, which were magnified by our credit downgrade. In late 2002, we began
actively liquidating our trading portfolio and anticipate that this effort will
continue through 2004. Through June 30, 2003, we have liquidated approximately
15,000, or 38 percent of the total number of forward positions outstanding at
December 31, 2002. We have also liquidated 97 Bcf of the 125 Bcf of natural gas
storage rights and 2.5 Bcf/d of our 4.4 Bcf/d of transportation capacity that we
owned in 2002. The remaining capacity will be liquidated as these capacity
agreements expire or are sold. Some of our transportation capacity agreements
are being utilized to serve customers and will not be actively marketed until
the underlying transactions are terminated. We completed the liquidation of our
European portfolio and expect to close that operation in the third quarter of
2003. We also liquidated miscellaneous activities including our interest rate
and coal portfolios. We anticipate we will have 12,000 transactions remaining by
the end of 2003, after normal settlements. Our portfolio may include
transactions that benefit other segments of our business, which in future
periods may be transferred to those segments. Our liquidation activities have
and will continue to prevent comparability of our earnings on a period to period
basis.

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During the second quarter of 2003, our trading business continued to
operate in a challenging environment with reduced liquidity, lower credit
standing of participants and a general decline in the number of trading
counterparties. Additionally, we implemented new accounting rules that impacted
the values of our portfolios starting in the fourth quarter of 2002. All of
these factors reduce the comparability of our operating results between periods.

Results of our energy trading division were as follows for the periods
ended June 30:

Second Quarter 2003 Compared to Second Quarter 2002

Gross margin consists of revenues from commodity trading and origination
activities less the costs of commodities sold, including changes in the fair
value of our energy trading portfolio. For the quarter ended June 30, 2003,
gross margin increased by $33 million compared to the same period in 2002. We
incurred an $89 million loss in gross margin during the second quarter of 2002,
which primarily resulted from a decline in option valuations that decreased the
fair value of our trading portfolio in 2002. We incurred a $56 million gross
margin loss in the second quarter of 2003, which partially resulted from $6
million of net losses incurred on the early termination and liquidation of
contracts in our trading portfolio. The remaining loss in 2003 resulted
primarily from the fact that we experienced narrowing of the differential
between gas and power prices that caused a decrease in the fair value of our
power-related derivatives and transportation and storage demand charges we were
unable to fully recover through the use of the capacity due to our focus on
conserving working capital.

Operating expenses for the quarter ended June 30, 2003, were $5 million
lower than the same period in 2002. This decrease was primarily the result of a
$25 million net reduction in the accrual for the California settlement
obligation as a result of the finalization of the definitive settlement
agreement which encompasses changes in the timing of payment and a $4 million
net decrease in personnel costs due to a reduction in the number of employees.
These decreases in expenses were offset by increases, including $12 million of
amortization of our debt discount on the California settlement obligation, $4
million of legal and other costs related to the resolution of the California
lawsuits as described in Item 1, Notes 6 and 18 and $4 million as a result of
accelerating the depreciation of the assets of the trading division upon the
decision to exit trading thus resulting in a shorter economic life.

Other income for the quarter ended June 30, 2003, was $14 million higher
than 2002, primarily as a result of lower overhead allocations in 2002 and $5
million of foreign exchange gains recognized in 2003 primarily due to the
Canadian dollar strengthening against the U.S. dollar during the quarter.

Six Months Ended 2003 Compared to Six Months Ended 2002

For the six months ended June 30, 2003, gross margin was $176 million lower
than the same period in 2002. We incurred a $197 million gross margin loss
during the first six months of 2003, which partially resulted from $40 million
of net losses incurred on the early termination and liquidation of our contracts
in our trading portfolio. The remaining loss in 2003 resulted primarily from an
increase in the basis differentials of natural gas prices, primarily in the
northeastern United States and decreasing trading volumes as a result of our
decision to exit the trading business. We incurred a $21 million loss in gross
margin during the first six months of 2002, which primarily resulted from a
decline in the fair value of our trading portfolio in 2002, offset

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by an $80 million gain on a power supply agreement that we entered into with our
global power division in the first quarter of 2002 associated with the Eagle
Point Cogeneration restructuring transaction. The effects of this power supply
agreement were eliminated from Merchant Energy's consolidated results.

Operating expenses for the six months ended June 30, 2003, were $3 million
higher than the same period in 2002. In 2003, we recognized a net $5 million of
costs related to the settlement of our California lawsuits as described in Item
1, Notes 6 and 18. This net increase in costs includes $24 million of debt
amortization on our settlement obligation and $6 million of legal and other
costs, offset by a $25 million reduction in our estimate of our expected
obligation as a result of the execution of a definitive agreement which
encompassed changes in the timing of payments. Depreciation expense increased by
$8 million as a result of accelerating the depreciation of the assets of the
trading division upon the decision to exit trading resulting in a shorter
economic life, offset by $10 million net decrease in personnel costs due to a
reduction in the number of employees.

Other income for the six months ended June 30, 2003, was at the same level
as the previous year. While the impact was flat, we did experience foreign
currency gains of approximately $7 million primarily due to the strengthening of
the Canadian dollar against the U.S. dollar offset by a decrease in interest
income due to the collection or termination of interest bearing assets.

Other

This division includes our LNG business and the results of operations of
our equity investment in a gas processing plant. Historically, our LNG business
included supply agreements, terminal capacity arrangements, the development of
regassification technology (the Energy Bridge project) and options to charter
ships to supply LNG to domestic and international market centers. In 2003, we
announced our intent to reduce our involvement in the LNG business. We are
currently pursuing the sale of the supply and terminal capacity arrangements.
Additionally, in the first quarter of 2003, we incurred charges of $44 million
in connection with reducing future exposure under our ship chartering
arrangements. In the second quarter 2003, we expensed $19 million of costs
related to the testing facility used in the development of the regasification
technology since we are not actively pursuing further technology development.
Results of our other division were as follows for the periods ended June 30:

Second Quarter 2003 Compared to Second Quarter 2002

Gross margin consists of revenues from LNG commodity trading and
origination activities, less the costs of commodities sold. For the quarter
ended June 30, 2003, our gross margin was $71 million lower than the same period
in 2002. The decrease relates primarily to a gain of $59 million on the Sno/hvit
LNG contract in 2002. Also contributing to the decrease was a $12 million
reduction in the fair value of our LNG supply contracts in 2003.

Operating expenses for the quarter ended June 30, 2003, were $19 million
higher than the same period in 2002. The increase was primarily due to a $20
million impairment of our LNG assets in the second quarter of 2003 associated
with Energy Bridge technology development costs previously capitalized that were
no longer considered recoverable due to our reduced involvement in the LNG
business.

72

Six Months Ended 2003 Compared to Six Months Ended 2002

For the six months ended June 30, 2003, our gross margin was $38 million
lower than the same period in 2002. The decrease relates primarily to the $59
million gain on the Sno/hvit LNG contract in 2002, partially offset by a $21
million decrease in the fair value of our remaining LNG supply contracts in
2003.

Operating expenses for the six months ended June 30, 2003, were $77 million
higher than the same period in 2002. This increase included $55 million of ship
charter cancellation costs incurred in 2003 associated with our reduced
involvement in our LNG business and $5 million of employee severance costs.
Also, contributing to the increase was a $20 million impairment of our LNG
assets in the second quarter of 2003 associated with Energy Bridge technology
development costs previously capitalized that were no longer considered
recoverable due to our reduced involvement in the LNG business. Partially
offsetting this increase was a decrease in outside consulting fees for 2003.

Other income for the six months ended June 30, 2003, was $10 million lower
than the same period in 2002. The decrease was due primarily to a $10 million
impairment of costs associated with one of our LNG terminals that we no longer
anticipate using and a $3 million in equity losses from our joint venture in the
Javelina gas processing facility.

FAIR VALUE OF PRICE RISK MANAGEMENT CONTRACTS AS OF JUNE 30, 2003

The following table details the net estimated fair value of our derivative
energy contracts (both trading and non-trading) by year of maturity and
valuation methodology as of June 30, 2003. We have historically classified as
trading activities those derivative price risk management activities that we
enter into with the objective of generating profits or benefiting from exposure
to shifts or changes in market prices. All other derivative-related activities,
including those related to power restructuring and hedging activities, have
historically been classified as non-trading price risk management activities.

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

(1) Exchange-traded positions include positions that are traded on active
exchanges such as the New York Mercantile Exchange, International Petroleum
Exchange and London Clearinghouse.

(2) Non-exchange traded positions include those positions that are valued based
on exchange prices, third party pricing data and valuation techniques that
incorporate specific contractual terms, statistical and simulation analysis
and present value concepts.

(3) Non-trading energy contracts include derivatives from our power contract
restructuring activities of $2,199 million, and derivatives related to our
natural gas and oil producing activities of $(757) million. Earnings related
to the natural gas and oil producing derivative activities are included in
our Production segment results.

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The income impacts of both our trading and non-trading price risk
management activities are included in the divisions of our Merchant Energy
segment and in our Production segment. A reconciliation of these trading and
non-trading activities for the period ended June 30, 2003, is as follows:

During the second quarter of 2003, we acquired derivative contracts with a
fair value as of June 30, 2003, of approximately $1.2 billion, in conjunction
with our acquisition of Chaparral. The majority of the value of the derivative
contracts acquired are for power purchase agreements and power supply agreements
related to power restructuring activities conducted at Chaparral. The changes in
the fair value of these derivatives can be significantly impacted by changes in
interest rates. See Item 3, Quantitative and Qualitative Disclosures About
Market Risk, for a sensitivity analysis of the impact of a 10 percent change in
interest rates on our power related contracts.

Our trading portfolio is reflected at its estimated fair value, which is
the amount at which the contracts in our portfolio could be bought or sold in a
current transaction between willing buyers and sellers. However, the value we
ultimately receive in settlement of our trading activities may be less than our
estimates. As discussed above, we are actively liquidating our trading
portfolio, which includes approximately 25,000 positions as of June 30, 2003. We
believe the net realizable value of our trading portfolio, if liquidated in the
timeframe set out in our exit plan, may be less than its currently estimated
fair value. Our belief is based on recent transactions completed at values below
estimated fair value and bids received on positions that were also below their
fair value. Additionally, a portion of the transactions that we plan to
liquidate is accounted for under the accrual method and is not recorded on our
balance sheet.

CORPORATE AND OTHER

Corporate and other expenses, which include general and administrative
activities as well as the operations of our telecommunications and other
miscellaneous businesses, for the quarter ended June 30, 2003, were $501
million, $424 million higher than the same period in 2002. In the second quarter
of 2003, we recorded impairment charges of approximately $269 million in our
telecommunications business, inclusive of a write-down of goodwill of $163
million due to our announced exit of this business and an impairment of our
Lakeside Technology Center facility of $127 million due to the decline in the
estimated fair value of that facility. The second quarter 2003 increase was also
due to a $37 million loss on the early extinguishment of our $1.2 billion bridge
loan. Partially offsetting these cost increases were $40 million of 2002 costs
related to eliminating rating and stock-price triggers in our Gemstone and
Chaparral investments.

Corporate and other expenses for the six months ended June 30, 2003, were
$571 million, an increase of $488 million over those costs during the same
period in 2002. These increases were due to the same reasons discussed in the
second quarter analysis above, including impairment charges in our
telecommunications business of $396 million, inclusive of a write-down of
goodwill of $163 million, and the $37 million loss on our extinguishment of
debt, along with $33 million of higher foreign currency losses on our
Euro-denominated debt during 2003. Partially offsetting these increases were
lower business restructuring costs in 2003, versus those costs incurred in 2002.

74

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter and six months ended June 30,
2003, was $159 million and $269 million higher than the same period in 2002.
Below is an analysis of our interest expense for the periods ended June 30:

Second Quarter 2003 Compared to Second Quarter 2002

Interest expense on long-term debt for the quarter ended June 30, 2003, was
$148 million higher than the same period in 2002. The increase was due to higher
average debt balances. During 2003, our long-term debt increased by
approximately $6.9 billion from debt issuances and acquisitions and
consolidations of companies with debt, which increased our interest on long-term
debt by approximately $112 million. Also contributing to the increase was $54
million of additional interest related to various debt issuances during 2002
that were outstanding during 2003. Partially offsetting these increases was the
retirement of approximately $1.3 billion of long-term debt during 2002 and 2003
with an average effective interest rate of 7.46%, decreasing interest expense by
approximately $23 million.

Interest expense on revolving credit facilities for the quarter ended June
30, 2003, was $29 million higher than the same period in 2002 due to higher
borrowings under the revolving credit facilities in December 2002 and in 2003.
Our average revolving credit balances, which were based on daily ending
balances, were approximately $1.7 billion, with an average interest rate of 4.3%
during 2003.

Interest expense on commercial paper for the quarter ended June 30, 2003,
was $11 million lower than the same period in 2002 due to the discontinuation of
commercial paper activities in 2003 following our credit rating downgrades.

Other interest for the quarter ended June 30, 2003, was $10 million lower
than the same period in 2002. The decrease was primarily due to an $8 million
decrease in interest resulting from the retirement of other financing
obligations and a $3 million decrease due to the reduction in trading activities
in 2003.

Capitalized interest for the quarter ended June 30, 2003, was $3 million
lower than the same period in 2002 primarily due to lower interest rates in the
second quarter of 2003 than in 2002.

Six Months Ended 2003 Compared to Six Months Ended 2002

Interest expense on long-term debt for the six months ended June 30, 2003,
was $256 million higher than the same period in 2002. The increase was due to
higher average debt balances. Long-term debt increased in 2003 by approximately
$6.9 billion, which increased interest by approximately $178 million. Also
contributing to the increase was $122 million of additional interest related to
debt issuances during 2002 that were outstanding during 2003. Partially
offsetting these increases was the retirement of approximately $1.7 billion of
long-term debt during 2002 and 2003 with an average effective interest rate of
6.99%, decreasing interest expense by approximately $45 million.

75

Interest expense on revolving credit facilities for the six months ended
June 30, 2003, was $48 million higher than the same period in 2002 due to higher
borrowings under these facilities in 2003. Our average revolving credit
balances, which were based on daily ending balances, were approximately $1.8
billion, with an average interest rate of 3.5% during 2003.

Interest expense on commercial paper for the six months ended June 30,
2003, was $22 million lower than the same period in 2002 due to the
discontinuation of commercial paper activities in 2003.

Other interest for the six months ended June 30, 2003, was $19 million
lower than the same period in 2002. The decrease was primarily due to a $12
million decrease resulting from the retirement of our other financing
obligations, a $7 million decrease due to the consolidation of Chaparral and
Gemstone and a $9 million decrease due to the reduction in trading activities in
2003. These decreases were partially offset by a $7 million increase as a result
of the write-off of unamortized costs due to retirement of the Trinity River
financing arrangement in 2003.

Capitalized interest for the six months ended June 30, 2003, was $6 million
lower than the same period in 2002 primarily due to lower interest rates in 2003
than in 2002.

DISTRIBUTIONS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Distributions on preferred interests of consolidated subsidiaries for the
quarter and six months ended June 30, 2003, were $27 million and $46 million
lower than the same periods in 2002 primarily due to the redemptions or
elimination of over $2.2 million of preferred interests related to the Gemstone,
El Paso Oil & Gas Associates, Coastal Limited Ventures, El Paso Oil & Gas
Resources, Trinity River, Clydesdale and El Paso Energy Capital Trust IV
financing transactions. The decreases were also due to lower interest rates in
2003 and the impact of the consolidation of Chaparral and Gemstone as a result
of our acquisition of these investments. Most of our preferred distributions are
based on variable short-term rates, which were lower on average in 2003 than the
same periods in 2002.

INCOME TAXES

Income taxes from continuing operations and our effective tax rates for the
periods ended June 30 were as follows:

Our effective tax rates were different than the statutory tax rate of 35
percent in 2003 primarily due to the following:

- state income taxes, net of federal income tax benefit;

- foreign income taxed at different rates;

- abandonment of foreign investment;

- earnings from unconsolidated affiliates where we anticipate receiving
dividends; and

- minority interest preferred dividends.

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Our effective tax rates were different than the statutory tax rate of 35
percent in 2002 primarily due to the following:

- state income taxes, net of federal income tax benefit;

- foreign income taxed at different rates; and

- earnings from unconsolidated affiliates where we anticipate receiving
dividends.

For a further discussion of our effective tax rates, see Note 10.

DISCONTINUED OPERATIONS

During the six months ended June 30, 2003, our after-tax loss from
discontinued operations was $1,138 million. During this period, we recorded
pre-tax charges of $1,366 million related to impairments of long-lived assets
and investments triggered by our decision to sell substantially all of our
petroleum business, approximately $929 million of which related to the second
quarter impairment of our Aruba refinery and approximately $252 million of which
related to the first quarter impairment of our Eagle Point refinery.

We also incurred losses on our refinery operations during the second
quarter of 2003 of $74 million which primarily related to lower pricing in the
second quarter and lower crude throughput at our Aruba facility. Year to date
operating results for our refineries were slightly positive at $5 million.

The income tax benefit related to discontinued operations for the six
months ended June 30, 2003, was $226 million resulting in an effective tax rate
for discontinued operations of 17 percent. This effective rate was different
than the statutory rate of 35 percent primarily due to state income taxes and
foreign income taxes at different rates.

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.

COMMITMENTS AND CONTINGENCIES

See Item 1, Note 18, which is incorporated herein by reference.

NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

See Item 1, Note 22, which is incorporated herein by reference.

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CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS

We have made statements in this document that constitute forward-looking
statements, as that term is defined in the Private Securities Litigation Reform
Act of 1995. Forward-looking statements include information concerning possible
or assumed future results of operations. The words "believe," "expect,"
"estimate," "anticipate" and similar expressions will generally identify
forward-looking statements. These statements may relate to information or
assumptions about:

- earnings per share;

- capital and other expenditures;

- dividends;

- financing plans;

- capital structure;

- liquidity and cash flow;

- credit ratings;

- pending legal proceedings, claims and governmental proceedings, including
environmental matters;

- future economic performance;

- operating income;

- management's plans; and

- goals and objectives for future operations.

Forward-looking statements are subject to risks and uncertainties. While we
believe the assumptions or bases underlying the forward-looking statements are
reasonable and are made in good faith, we caution that assumed facts or bases
almost always vary from the actual results, and these variances can be material,
depending upon the circumstances. We cannot assure you that the statements of
expectation or belief contained in the forward-looking statements will result or
be achieved or accomplished. Important factors that could cause actual results
to differ materially from estimates or projections contained in forward-looking
statements are described in our 2002 Form 10-K.

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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

There are no material changes in our quantitative and qualitative
disclosures about market risks from those reported in our 2002 Form 10-K, except
as presented below:

MARKET RISK

We are exposed to a variety of market risks in the normal course of our
business activities, including commodity price, foreign exchange and interest
rate risks. We measure risks on our portfolio of commodity and energy-related
contracts on a daily basis using a Value-at-Risk model. We measure our trading
and hedging activities included in our non-trading portfolio's Value-at-Risk
using the historical simulation technique, and we prepare it based on a
confidence level of 95 percent and a one-day holding period. This Value-at-Risk
was $16 million and $11 million as of June 30, 2003 and December 31, 2002, and
represents our potential one-day unfavorable impact on the fair values of our
commodity and energy-related contracts. The $5 million increase in our portfolio
Value-at-Risk was related to higher natural gas price volatility and our efforts
in the first six months of 2003 to mitigate the cash flow impact of rising gas
prices on our trading portfolio. As we liquidate our trading portfolio, our
Value-at-Risk may vary more than in historical periods when we more actively
managed our positions using Value-at-Risk. As a result, our Value-at-Risk could
increase.

INTEREST RATE RISK

As of June 30, 2003, included in the $2.2 billion of our non-trading
derivatives not designated as hedges, we had $1.2 billion of third party
long-term power purchase and power supply contracts. These contracts are
associated with our power restructuring business and are valued using estimated
future market power prices and a discount rate that considers the appropriate
U.S. Treasury rate plus a specific counterparty credit spread. We make
adjustments to this discount rate when we believe that market changes in the
rates result in changes in value that can be realized. While the commodity price
risk associated with these derivative instruments has been incorporated into our
Value-at-Risk model discussed above, our exposure to changes in interest rates
and credit spreads has not been included in our Value-at-Risk since it is
managed separately from our other derivative positions included in our
Value-at-Risk model. As of June 30, 2003, a ten percent increase or decrease in
the discount rate utilized would result in a change in the fair value of these
derivative instruments of $(63) million and $66 million, respectively.

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ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Controls and Procedures. Under the supervision and with the
participation of management, including our principal executive officer and
principal financial officer, we have evaluated the effectiveness of the design
and operation of our disclosure controls and procedures (Disclosure Controls)
and internal controls over financial reporting (Internal Controls) as of the end
of the period covered by this Quarterly Report pursuant to Rules 13a-15 and
15d-15 under the Securities Exchange Act of 1934 (Exchange Act).

Definition of Disclosure Controls and Internal Controls. Disclosure
Controls are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported, within
the time periods specified under the Exchange Act. Disclosure Controls include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by us in the reports that we file under the Exchange
Act is accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure. Internal Controls are procedures
which are designed with the objective of providing reasonable assurance that (1)
our transactions are properly authorized; (2) our assets are safeguarded against
unauthorized or improper use; and (3) our transactions are properly recorded and
reported, all to permit the preparation of our financial statements in
conformity with generally accepted accounting principles.

Limitations on the Effectiveness of Controls. El Paso's management,
including the principal executive officer and principal financial officer, does
not expect that our Disclosure Controls and Internal Controls will prevent all
errors and all fraud. The design of a control system must reflect the fact that
there are resource constraints, and the benefits of controls must be considered
relative to their costs. Because of the inherent limitations in all control
systems, no evaluation of controls can provide absolute assurance that all
control issues and instances of fraud, if any, within the company have been
detected. These inherent limitations include the realities that judgments in
decision-making can be faulty, and that breakdowns can occur because of simple
errors or mistakes. Additionally, controls can be circumvented by the individual
acts of some persons, by collusion of two or more people, or by management
override of the controls. The design of any system of controls also is based in
part upon certain assumptions about the likelihood of future events. Therefore,
a control system, no matter how well conceived and operated, can provide only
reasonable, not absolute, assurance that the objectives of the control system
are met. Our Disclosure Controls and Internal Controls are designed to provide
such reasonable assurances of achieving our desired control objectives, and our
principal executive officer and principal financial officer have concluded that
our Disclosure Controls and Internal Controls are effective in achieving that
level of reasonable assurance.

No Significant Changes in Internal Controls. We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in El
Paso's Internal Controls, or whether the company had identified any acts of
fraud involving personnel who have a significant role in El Paso's Internal
Controls. This information was important both for the controls evaluation
generally and because the principal executive officer and principal financial
officer are required to disclose that information to our Board's Audit Committee
and our independent auditors and to report on related matters in this section of
the Quarterly Report. The principal executive officer and principal financial
officer note that there has not been any change in Internal Controls during the
period covered by this Quarterly Report that has materially affected, or is
reasonably likely to materially affect, Internal Controls.

Effectiveness of Disclosure Controls. Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that the Disclosure Controls are effective to ensure that material information
relating to El Paso and its consolidated subsidiaries is made known to
management, including the principal executive officer and principal financial
officer, on a timely basis.

Officer Certifications. The certifications from the principal executive
officer and principal financial officer required under Sections 302 and 906 of
the Sarbanes-Oxley Act of 2002 have been included as Exhibits to this Quarterly
Report.

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PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item 1, Note 18, which is incorporated herein by reference.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

We held our annual meeting of stockholders on June 17, 2003. Proposals we
presented for a stockholders' vote included the election of twelve directors,
two amendments to our Certificate of Incorporation, ratification of the
appointment of PricewaterhouseCoopers LLP as independent certified public
accountants for the fiscal year 2003 and three stockholder proposals. Proposals
were also presented by Selim Zilkha, a stockholder, which included the
nomination for election of a nine director slate, three amendments to El Paso's
By-laws and a proposal regarding the presentation of proposals at the annual
meeting.

Each of the twelve incumbent directors nominated by El Paso was elected
with the following voting results:

The Zilkha slate of directors received the following votes:

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The appointment of PricewaterhouseCoopers LLP as El Paso's independent
certified public accountants for the fiscal year 2003 was ratified with the
following voting results:

There were no broker non-votes for the ratification of
PricewaterhouseCoopers LLP.

Two management proposals were presented for a stockholder vote. One
proposal was to amend the Certificate of Incorporation to eliminate Article 12,
and the other was to eliminate our Series A Junior Participating Preferred
Stock.

Selim Zilkha presented four proposals including three amendments to El
Paso's By-laws and one regarding the sequence for the presentation of proposals
at the annual meeting with the following voting results:

Three proposals submitted by stockholders were presented for a stockholder
vote. One proposal called for stockholder approval of a report on pay disparity,
the second proposal called for stockholder approval of indexed options for
senior executives and the third proposal called for stockholder approval
regarding shareholder approval of any adoption of poison pills. The first and
second stockholder proposals were not approved, and the third proposal was
approved with the following voting results.

ITEM 5. OTHER INFORMATION

On July 16, 2003, we announced that Douglas L. Foshee was elected our new
President and Chief Executive Officer.

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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

a. Exhibits

Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an "*"; all
exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" represent management
contracts or compensatory plans or arrangements.

Undertaking

We hereby undertake, pursuant to Regulation S-K, Item 601(b),
paragraph (4)(iii), to furnish to the U.S. Securities and Exchange
Commission, upon request, all constituent instruments defining the rights
of holders of our long-term debt not filed herewith for the reason that the
total amount of securities authorized under any of such instruments does
not exceed 10 percent of our total consolidated assets.

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b. Reports on Form 8-K

We also furnished information to the SEC on Current Reports on Form 8-K
under Item 9 and Item 12. Current Reports on Form 8-K under Item 9 and Item 12
are not considered to be "filed" for purposes of Section 18 of the Securities
and Exchange Act of 1934 and are not subject to the liabilities of that section.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.

EL PASO CORPORATION

Date: August 14, 2003 /s/ D. Dwight Scott
------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

Date: August 14, 2003 /s/ Jeffrey I. Beason
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

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EXHIBIT INDEX

Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an "*"; all
exhibits not so designated are incorporated herein by reference to a prior
filing as indicated. Exhibits designated with a "+" represent management
contracts or compensatory plans or arrangements.