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 SEPTEMBER 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 November 7,
2003: 599,424,353

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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
Bcfe = billion cubic feet of natural gas equivalents
MBbls = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of natural gas equivalents
MMBtu = million British thermal units
MMcf = million cubic feet
Tcfe = trillion cubic feet of natural gas equivalents
MMWh = million megawatt hours

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 Current Report on Form 8-K dated
September 23, 2003 (which updated the financial statement information originally
presented in our 2002 Form 10-K to reclassify our petroleum markets business as
a discontinued operation), which includes a summary of our significant
accounting policies and other disclosures. The financial statements as of
September 30, 2003, and for the quarters and nine months ended September 30,
2003 and 2002, are unaudited. We derived the balance sheet as of December 31,
2002, from the audited balance sheet filed in our Current Report on Form 8-K
dated September 23, 2003. 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 be indicative of our 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 had 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 at the same time
maximizing liquidity;

- Aggressively pursue additional cost reductions; and

- Work diligently to resolve regulatory and litigation matters.

To date in 2003, our major accomplishments regarding these business objectives
have been as follows:

- We concentrated our capital investment in our core Pipelines, Production
and Field Services segments such that 91 percent of total capital
expenditures have been made in these businesses in the first nine months
of 2003;

- We completed or announced sales of assets and investments of
approximately $3.1 billion (see Note 4);

- We entered into a new $3 billion revolving credit facility that matures
in June 2005 and completed financing transactions of approximately $3.8
billion ($3.6 billion as of September 30, 2003) (see Note 16);

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- We retired approximately $5.8 billion of maturing debt and other
obligations ($4.7 billion as of September 30, 2003), including:

- the retirement of long-term debt of $2.9 billion ($2.2 billion as of
September 30, 2003);

- the net repayment of $650 million of outstanding amounts under our $3
billion revolving credit facility ($250 million as of September 30,
2003);

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

- the redemption of $197 million of obligations under our Clydesdale
financing arrangement, also restructuring that transaction as a term
loan that will mature in equal quarterly payments through 2005 (see
Notes 3 and 17); and

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

- We refinanced 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;

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

- We executed definitive settlement agreements in June 2003, which
substantially resolved our principal exposure relating to the Western
Energy crisis and raised funds of $347 million to satisfy a portion 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 initiated a tender offer in October 2003 to exchange common stock and
cash for our outstanding equity security units which would, if 100
percent of the units were tendered, result in a reduction of up to $575
million in our outstanding debt balances, an increase in stockholders'
equity of up to approximately $475 million and a reduction of cash of up
to approximately $112 million (see Note 16); and

- We initiated a program to supplement our capital spending on natural gas
and oil properties by an additional $350 million.

We believe the accomplishments 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 these
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
Current Report on Form 8-K dated September 23, 2003.

SIGNIFICANT ACCOUNTING POLICIES

Our accounting policies are consistent with those discussed in our Current
Report on Form 8-K dated September 23, 2003, 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

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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 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 September 30, 2003, reported in other current and non-current liabilities in
our balance sheet, and the changes in the net liability for the nine months
ended September 30, 2003, were as follows (in millions):

Liability at January 1, 2003................................ $222
Liabilities settled in 2003................................. (44)
Accretion expense in 2003................................... 13
Liabilities incurred in 2003................................ 1
Changes in estimate......................................... 8
----
Net liability at September 30, 2003.................... $200
====

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 and oil wells and the costs to do so. Had we adopted SFAS
No. 143 as of January 1, 2002, our current and non-current retirement
liabilities on that date would have been approximately $200 million and our
income from continuing operations and net income for the quarter and nine months
ended September 30, 2002, would have been lower by $3 million and $10 million.
Basic and diluted earnings per share for the quarter and nine months ended
September 30, 2002, would not have been materially 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.

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 several
interpretations of the Derivatives Implementation Group (DIG), and also makes
several modifications to the definition of a derivative as it was defined in
SFAS No. 133. SFAS No. 149 affects contracts entered into or modified after June
30, 2003. There was no initial financial statement impact of adopting this
standard, although the FASB and DIG continue to deliberate on the application of
the standard to certain derivative contracts, such as power capacity contracts,
which may impact our financial statements in the future.

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. In
particular, the standard requires that we classify all mandatorily redeemable
securities as liabilities in the balance sheet. We adopted the provisions of
SFAS No. 150 on July 1, 2003, and reclassified $625 million of our Capital Trust
I and

8

Coastal Finance I preferred interests from preferred interests of consolidated
subsidiaries to long-term financing obligations in our balance sheet. We also
began classifying dividends accrued on these preferred interests as interest and
debt expense in our income statement after July 1, 2003. For the quarter and
nine months ended September 30, 2003, total dividends were $10 million and $30
million. The third quarter of 2003 dividends of $10 million were recorded in
interest expense in our income statement. The first and second quarter of 2003
dividends of $20 million were recorded as distributions on preferred interests
in our income statement.

Goodwill. Our goodwill as of December 31, 2002 and September 30, 2003, and
the changes in goodwill for the nine months ended September 30, 2003, were as
follows (in millions):

During 2003, we impaired $163 million of goodwill related to our
telecommunications business in our corporate segment and disposed of $42 million
in goodwill primarily related to the sale of our financial services businesses
in our Merchant Energy segment.

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 all
guarantees, including financial performance and fair value guarantees, issued
after December 31, 2002, at 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:

Accounting for Regulated Operations. Our interstate natural gas pipelines
and storage operations are subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC) in accordance with the Natural Gas Act of 1938 and
Natural Gas Policy Act of 1978. Of our regulated pipelines, four follow the

9

regulatory accounting principles prescribed under SFAS No. 71, Accounting for
the Effects of Certain Types of Regulation, while three discontinued its
application in 1996. As a result of recent changes in our competitive
environment and operating cost structures, we continue to assess the
applicability of the provisions of SFAS No. 71 to our financial statements. The
outcome of this evaluation could result in the restoration of our application of
this accounting in some of our regulated systems or the discontinuance of this
accounting in others. We expect to complete our current evaluation of the
applicability of SFAS No. 71 by the end of the year. For a discussion of
differences in accounting for regulated operations, see our Current Report on
Form 8-K dated September 23, 2003.

3. ACQUISITIONS AND CONSOLIDATIONS

Acquisitions

During the second quarter of 2003, we acquired and began consolidating the
third party interests in our Chaparral and Gemstone investments, which we
historically accounted for as investments in unconsolidated affiliates. Each of
these acquisitions is discussed below.

Chaparral. As discussed more completely in our Current Report on Form 8-K
dated September 23, 2003, 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
3,470 megawatts (based on Chaparral's interest in the plants). These plants are
primarily concentrated in the Northeast and Western United States. Chaparral
also owns several companies that own long-term derivative power agreements.

As of December 31, 2002, we owned 20 percent of Chaparral, and the
remaining 80 percent was owned by Limestone Electron Trust (Limestone). We
acquired Limestone's 80 percent interest in Chaparral during 2003 in two
transactions. First, in March 2003, we acquired an additional 70 percent
economic interest in Chaparral when we invested $1 billion in Limestone.
Limestone used these proceeds to retire notes that were previously guaranteed by
us. Although we increased our economic interest in Chaparral with this
investment in Limestone, we did not obtain any additional voting rights in
Limestone or 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
Limestone's and 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, earnings (losses)
from unconsolidated affiliates by $55 million, interest expense by $67 million
and decreasing distributions on preferred interests in subsidiaries by $18
million and other income (expense) by $2 million. Had we acquired Chaparral
effective January 1, 2002, the net increases (decreases) to our income statement
for the periods ended September 30, 2002, would have been as follows:

The $175 million we paid to acquire the remaining 10 percent interest in
Limestone along with the remaining voting rights of Limestone and Chaparral, was
negotiated based, in large part, on the terms of the original 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

10

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 the flexibility to manage the assets
of Chaparral, regardless of whether these assets were to be 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 our own credit ratings as well as those of our
counterparties, adverse developments at several of Chaparral's projects, our
announced 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 (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 less than our
carrying value of the 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 our initial allocation of the purchase price
of Chaparral to its assets and liabilities prior to its consolidation and prior
to the elimination of intercompany transactions. This allocation reflects the
allocation of (i) our purchase price of $1,175 million; (ii) the carrying value
of our initial investment of $252 million; and (iii) our first quarter 2003
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, contract 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 once we receive the final
valuation report from our consultant and have evaluated the bids we have
received. We believe we will complete our purchase price allocation by the end
of 2003.

Gemstone. As discussed more completely in our Current Report on Form 8-K
dated September 23, 2003, 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) that had a total generating
capacity of 1,788 megawatts (based on Gemstone's interest in the plants).
Gemstone also

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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 Rabobank's interest in Gemstone for
approximately $50 million in April 2003. Gemstone's results of operations have
been included in our consolidated financial statements since April 1, 2003.
Although our net income and basic and diluted earnings per share for the nine
months ended September 30, 2003 would not have been affected, our revenues and
operating income would have been higher by $58 million and $41 million had we
acquired Gemstone effective January 1, 2003. Had the acquisition been effective
January 1, 2002, our net income and our basic and diluted earnings per share
would have been unaffected, but our revenues and operating income would have
been higher by $56 million and $38 million for the quarter ended September 30,
2002, and $123 million and $90 million for the nine months ended September 30,
2002.

Our initial allocation of the $50 million purchase price to the assets
acquired and liabilities assumed upon our consolidation of Gemstone in April
2003 was as follows (in millions):

Fair value of assets acquired
Note and interest receivable.............................. $ 122
Investments in unconsolidated affiliates.................. 892
Other assets.............................................. 3
------
Total assets........................................... 1,017
------

Fair value of liabilities assumed
Note and interest payable................................. 967
------
Total liabilities...................................... 967
------
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 expect to finalize our purchase price allocation once we receive the
final valuation report from our consultant, which we anticipate will be
completed by the end of 2003.

As mentioned above, prior to the acquisition, we recorded our investments
in Chaparral and Gemstone as investments in unconsolidated affiliates. We also
had other balances, including loans and notes with Chaparral and Gemstone, which
were eliminated upon consolidation. 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 overall impact of these
acquisitions on our consolidated balance sheet was an increase in our
consolidated assets of $2.1 billion, an increase in our consolidated liabilities
of approximately $2.4 billion, including an increase in our consolidated debt of
approximately $2.2 billion, and a reduction of our 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 (i) simplifying our capital structure by eliminating several
"off-balance sheet" obligations and replacing them with direct obligations, and
(ii) strengthening the overall collateral package available to our financial
lenders. These amendments are discussed below.

Lakeside. We amended an operating lease agreement at our Lakeside
telecommunications facility to add a guarantee benefiting 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, resulting in our controlling the lessor. As a result, we
consolidated the lessor in the second quarter of 2003. The consolidation of
Lakeside resulted in an increase in our property, plant and equipment of
approximately $275 million and an increase in our long-term debt of
approximately $275 million. Additionally, upon its consolidation, we recorded an
asset

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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.

Aruba. 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, resulting in our
controlling the lessor. As a result, we consolidated the lessor during the
second quarter of 2003, increasing our total property, plant and equipment by
$370 million (prior to an impairment charge we recorded on these assets of $50
million) and increasing our long-term debt by $370 million. As a result of our
intent to exit substantially all of our petroleum markets operations, these
leased assets and associated debt were reclassified as discontinued operations.

Clydesdale. In 2003, we modified our Clydesdale financing arrangement to
convert a third party investor's (Mustang Investors, L.L.C.) preferred ownership
interest in one of our consolidated subsidiaries into a term loan that matures
in equal quarterly installments through 2005. We also acquired a $10 million
preferred interest in Mustang and guaranteed all of Mustang's equity holder's
obligations. As a result, we were required to consolidate Mustang in the second
quarter of 2003 which increased our long-term debt by $743 million and decreased
our preferred interests of consolidated subsidiaries by $753 million. The $10
million preferred interest we acquired in Mustang was eliminated upon its
consolidation (see Notes 16 and 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 and any asset impairments recorded on these assets, investments and
operations are discussed in Notes 8, 11 and 21.

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(1)Excludes $18 million of costs incurred in preparing assets for disposal,
returns of invested capital and cash transferred with assets sold.

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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) These sales were completed in October 2003.

(3) This sale was completed in October 2003 and $70 million of the proceeds were
withheld pending the resolution of regulatory matters discussed further in
Note 18.

(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. To the extent
that all of the criteria 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
$31 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 September
30, 2003. As of September 30, 2003, we had $111 million of long-lived assets
classified as held for sale and reflected in current assets in our balance
sheet. We also had approximately $1.6 billion of assets classified as
discontinued operations as of September 30, 2003 (see Note 11).

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We continue to evaluate assets we may sell in the future, and have
announced that we intend to pursue the divestiture of our telecommunications
business and domestic power assets. These activities are ongoing, 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 divestiture, 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 these
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
divestiture 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.

As of September 30, 2002, we had completed the following asset sales:

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

(1)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.

(2)Excludes $105 million of costs incurred in preparing assets for disposal,
returns of invested capital and cash transferred with the assets sold.

5. RESTRUCTURING CHARGES

For the quarter and nine months ended September 30, 2003, we recognized
restructuring costs totaling $14 million and $114 million. These costs were
incurred as part of our ongoing liquidity enhancement and cost reduction
efforts. Of this amount, $10 million and $66 million related to employee
severance costs from reductions in our work force, of which approximately $51
million had been paid as of September 30, 2003. Through September 30, 2003, we
had eliminated approximately 2,600 full-time positions, including approximately
1,400 full-time positions related to our discontinued operations. Employee
severance costs included severance payments and costs for pension benefits
settled and curtailed under existing benefit plans. For the quarter and nine
months ended September 30, 2003, we also recorded $1 million and $10 million of
employee severance costs related to our discontinued operations, substantially
all of which had been paid as of September 30, 2003. During the first quarter of
2003, we also recognized charges of approximately $44 million 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 expense in our income statement, and these
charges impacted the results in all of our business segments.

For the quarter and nine months ended September 30, 2002, we incurred $1
million and $64 million of restructuring charges. During 2002, we completed an
employee restructuring across all of our operating segments which resulted in
the elimination of approximately 808 full-time positions, including those

15

employees related to our discontinued operations. We incurred and paid $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 date of the settlement. Subject to court and
regulatory approvals, the settlement will include payments of cash, the issuance
of common stock and the reduction in prices under a power supply contract.

These definitive settlement agreements modified an agreement in principle
reached on March 20, 2003, as discussed in our Current Report on Form 8-K dated
September 23, 2003, and resulted in an additional obligation and a pretax 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. During the third quarter of 2003, we recorded a benefit of
approximately $20 million due to changes in our stock price, resulting in a net
charge for the nine months ended September 30, 2003, of $103 million. This net
charge was in addition to accretion expense on the originally recorded
discounted Western Energy Settlement obligation and other charges included as
part of operation and maintenance expense during 2003. For the quarter and nine
months ended September 30, 2003, these accretion and other charges were
approximately $12 million and $55 million. As of September 30, 2003, $616
million of the total Western Energy Settlement obligation of $1,035 million was
reflected as a current liability. The current portion includes a $193 million
obligation to issue approximately 26.4 million shares of our common stock. 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 September 30, 2003, $10
million of the total obligation had been satisfied. 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 overall obligation. For a further discussion of the Western
Energy Settlement, see Note 18.

As further described in Note 18, upon final approval of the settlement
agreements, we will be required to provide collateral for the $45 million per
year, 20-year obligation in the form of natural gas and oil reserves, other
assets to be agreed upon, cash and/or letters of credit. The initial collateral
requirement is estimated to 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 nine months ended September 30, 2003, we recorded a
ceiling test charge of approximately $2 million primarily related to our Turkish
full cost pool. For the nine months ended September 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 2002 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. Our ceiling
test charges were based upon the daily posted natural gas and oil prices at the
end of each period, adjusted for oilfield or natural gas

16

gathering hub and wellhead price differences, as appropriate. The 2002 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.

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 these ceiling test
charges since we do not significantly hedge our international production
activities.

8. GAIN (LOSS) ON LONG-LIVED ASSETS

Our gain (loss) on long-lived assets 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 $1.3 billion of asset impairments for
the nine months ended September 30, 2003, related to our petroleum markets
operations that were reclassified as discontinued operations.

Net Realized Gain (Loss)

Our 2003 net realized gains (losses) were primarily related to the sales of
Mohawk River Funding I in our Merchant Energy segment, 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 (losses) were primarily related to the sales of
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 possible impairment whenever events or
changes in circumstances indicate that the carrying amount of these assets may
not be fully recoverable. One event that triggers this test 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 nine
months of 2003 and recorded the charges indicated in the table above. Our
corporate telecommunications 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. Our Merchant Energy charges were primarily a result of our plan
to reduce our involvement in the LNG business and our power assets, including

17

our turbines classified in long-term assets (see Note 15). For additional asset
impairments on our discontinued operations and investments in unconsolidated
affiliates, see Notes 11 and 21.

9. OTHER EXPENSES

Other expenses for the nine months ended September 30, 2003, were $129
million. These amounts include foreign currency losses of $73 million primarily
on our Euro-denominated debt and a $37 million loss on the early extinguishment
of our $1.2 billion bridge loan (see Note 16).

Other expenses for the quarter and nine months ended September 30, 2002,
were $14 million and $277 million. For the nine months ended September 30, 2002,
we incurred foreign currency losses of $45 million resulting from the impact of
foreign currency fluctuations on our Euro-denominated debt, a $56 million
impairment of our investment in the Costanera power plant, a cost-based
investment in Argentina, and a $90 million contract termination fee paid by our
Eagle Point Cogeneration facility (in our global power division of our Merchant
Energy segment) to our Eagle Point refinery (in the petroleum markets division
classified as discontinued operations). This payment was eliminated in
consolidation since the income associated with the petroleum markets division is
reflected in discontinued operations while the power division's expense is
included in Merchant Energy's operating results. Other expenses also included
$55 million of minority interest in our consolidated subsidiaries.

10. INCOME TAXES

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

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

During the quarters and nine months ended September 30, 2003 and 2002, we
experienced a number of events that have impacted our overall effective tax rate
on continuing operations. These events included the treatment of our coal and
petroleum markets operations as discontinued operations (in which income taxes
are apportioned between continuing and discontinued operations) and the
abandonment of several foreign investments. These events, coupled with
relatively low pretax income in continuing operations, have caused, and may
continue to cause, variations in our effective tax rate.

18

11. DISCONTINUED OPERATIONS

Petroleum Markets Operations

In June 2003, our Board of Directors authorized the sale of substantially
all of our petroleum markets 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 approving the sales of our Eagle Point refinery,
our asphalt business, our Florida terminal, tug and barge 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 pre-tax charges during the first and second quarters of 2003 totaling
$1,366 million related to our petroleum markets assets, which included $929
million related to our Aruba refinery and $252 million related to the impairment
of our Eagle Point refinery. See Note 3 for a discussion of this lease. These
impairments were based on a comparison of the carrying value of our petroleum
markets 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 to be sold, and our established time frame for completing the sales,
among other factors.

19

In the second quarter of 2003, we entered into a product offtake agreement
with Vitol S.A. Inc. (Vitol) for the sale of a number of the products produced
at our Aruba refinery. As a result of this contract, Vitol 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 Vitol'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 recorded impairment
charges of $37 million and $185 million in our loss from discontinued operations
during the third quarter and the nine months ended September 30, 2002.

Our petroleum markets operations and our coal mining operations were
historically included in our Merchant Energy segment, and are classified as
discontinued operations in our financial statements for all of the historical
periods presented. All of the assets and liabilities of the remaining
discontinued businesses are classified as other current assets and liabilities
as of September 30, 2003. The summarized financial results and financial
position data of our discontinued operations were as follows:

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).

21

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 of 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 a 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 September 30:

For the quarter and nine months ended September 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 nine months ended September 30, 2002, a total
of 16 million shares of potentially dilutive securities was excluded based on
our income levels. The excluded securities included

22

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 September 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 contracts at both September 30, 2003
and December 31, 2002 are $165 million and $123 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.

As of September 30, 2003, other derivatives include $1,957 million of
derivative contracts primarily related to power restructuring activities, $1,010
million of which relates to contracts we acquired in connection with our
acquisition of Chaparral in the second quarter of 2003 and $947 million
associated with our power restructuring activities at our Eagle Point
Cogeneration and our Capitol District Energy Center Cogeneration Associates
facilities. As of December 31, 2002, other derivatives include $968 million of
derivative contracts 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 Current Report on Form 8-K dated September 23, 2003. The remaining
balances in other derivatives includes unrealized losses of $3 million and $9
million as of September 30, 2003 and December 31, 2002, that 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.

In September 2003, we entered into several cross-currency fair value hedge
transactions which effectively hedged the currency risk on a portion of our
Euro-denominated debt through 2009. Collectively, these transactions swap E250
million of our fixed rate debt for approximately $275 million of floating rate
debt at a weighted average rate of LIBOR plus 3.6%. In October and November
2003, we entered into several additional cross-currency fair value hedge
transactions which effectively hedged the currency risk on a portion of our Euro
denominated debt through 2009. Collectively, these transactions swap E100
million of our fixed rate debt for approximately $115 million of floating rate
debt at a weighted average rate of LIBOR plus 4.11%. Also in October 2003, we
entered into several fair value hedge transactions which effectively converted
the fixed interest rate of 7.875% on $200 million of our debt to a weighted
average rate of LIBOR plus 4.14% through 2012.

23

15. INVENTORY

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

(1) We recorded these amounts as other non-current assets in our balance sheet.
In September 2003, we negotiated an expected settlement under which we will
transfer our ownership rights and obligations related to $100 million of our
power turbine inventories, resulting in a write-down of $22 million of this
inventory at September 30, 2003.

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 nine 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 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 as of December 31, 2002.................... $18,571
Acquisitions and consolidations:
Clydesdale restructuring.................................. 743
Gemstone acquisition(2)(3)................................ 1,013
Chaparral acquisition(3).................................. 1,565
Bank refinancings:
Lakeside lease............................................ 275
Principal amounts borrowed(4)............................... 4,050
Repayments/retirements of principal(4)...................... (2,989)
Reclassifications of preferred interests as long-term 625
financing obligations.....................................
Elimination of affiliate obligations........................ (326)
Other....................................................... 53
-------
Total debt obligations as of September 30, 2003........... $23,580
=======

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

(1) Does not include $370 million of long-term debt related to our Aruba
refinery that is classified as part of our discontinued operations.

(2) This amount includes $75 million related to Macae which was consolidated as
a consequence of our acquisition of Gemstone.

(3) This is a non-recourse project financing or non-recourse debt related to our
power contract restructuring.

(4) Includes $500 million of borrowings and $750 million of repayments under our
revolving credit agreements.

24

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 proceeds from borrowings in
2003, specifically the $1.2 billion two-year term loan issued in March 2003,
which was then refinanced with the $1.2 billion 10 year loan issued in May 2003.
The Clydesdale financing was converted into a term loan maturing in equal
quarterly installments through 2005. The balance of the term loan was $521
million as of September 30, 2003. In November 2003, we made additional payments
of $107 million on this term loan. Additionally, we reclassified $625 million of
our mandatory redeemable preferred securities of Coastal Finance I and Capital
Trust I as a result of the adoption of SFAS No. 150 (see Notes 2 and 17).

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:

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

(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) The proceeds from the two-year term loan were used to redeem our Trinity
River financing.

(3) Net proceeds were used to repay the $1.2 billion LIBOR based two-year term
loan.

(4) This is a non-recourse project financing or non-recourse debt related to our
power contract restructuring.

(5) This non-recourse project debt was consolidated as a consequence of our
acquisition of Gemstone.

(6) Amount excludes net repayments of $250 million through September 30, 2003,
and additional net repayments of $400 million as of October 31, 2003,
related to our $3 billion revolving credit facility which is classified as
long-term debt based on its maturity date of June 30, 2005.

(7) This debt related to Mohawk River Funding I, L.L.C. was eliminated through
the sale of this entity.

(8) This debt related to East Coast Power, L.L.C. was eliminated through the
sale of this entity.

Other

In October 2003, we initiated a tender offer to exchange our 11.5 million,
9% equity security units (consisting of a senior note and a stock purchase
contract) for our common stock and cash. For each unit tendered, the holder will
receive 2.5063 shares of common stock and cash in the amount of $9.70 per equity
26

security unit. The exchange offer is conditioned upon the valid tender of at
least 50 percent of the equity security units, or 5.75 million equity security
units, which condition may be waived by us at our sole discretion. If 100
percent of the units are tendered, our debt obligations would be reduced by up
to $575 million.

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, Colorado Interstate Gas Company (CIG) cannot
incur incremental debt if the incurrence of this incremental debt would cause
their debt to EBITDA ratio (as defined in the new $3 billion 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 September 30, 2003, we were in compliance with
these covenants.

17. PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Summarized below are our actions during 2003 related to our preferred
interests of consolidated subsidiaries (in millions):

Balance as of December 31, 2002............................. $ 3,255
Redemption of Trinity River............................... (980)
Refinancing and redemptions of Clydesdale................. (950)
Elimination of Gemstone minority interest................. (300)
Reclassification of Capital Trust I and Coastal Finance
I(1)................................................... (625)
-------
Balance as of September 30, 2003............................ $ 400
=======

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(1) These reclassifications were a result of our adoption of SFAS No. 150. See
Note 2 for a discussion of our adoption of this accounting standard.

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 2003, we retired approximately $197 million of the third-party member
interests in Clydesdale, and 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.
Beginning in May 2003, the term loan is being amortized in equal quarterly
amounts of $100 million through 2005. 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 our guarantee, resulted in the consolidation of Mustang in the
second quarter of 2003. The consolidation of Mustang resulted in an increase

27

in our long-term debt of approximately $743 million and a reduction in our
preferred interests of consolidated subsidiaries of approximately $753 million.

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 a 100 percent interest in 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).

Capital Trust I. In March 1998, we formed El Paso Energy Capital Trust I,
a wholly owned subsidiary, to generate funds for investment and general
operating purposes. During the third quarter of 2003, the outstanding amount of
this preferred interest was reclassified as a long-term financing obligation on
our balance sheet as a result of the adoption of SFAS No. 150 (see Notes 2 and
16).

Coastal Finance I. In May 1998, we formed Coastal Finance I, an indirect
wholly owned business trust, to generate funds for investment and general
operating purposes. During the third quarter of 2003, the outstanding amount of
this preferred interest was reclassified as a long-term financing obligation on
our balance sheet as a result of the adoption of SFAS No. 150 (see Notes 2 and
16).

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 (CPUC); 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 earlier in June 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 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 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 will
be filed with the United States District Court for the Central District of
California. This Stipulated Judgment will provide for the enforcement of some of
the obligations contained in the structural settlement.

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

28

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 settlement
agreements, 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 is
estimated to 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 CPUC, PG&E,
Southern California Edison Company, and the City of Los Angeles filed the
structural settlement described above with the FERC in resolution of specific
proceedings before that agency. The structural settlement was protested by
EPNG's east of California shippers and 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 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 in these cases 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) attorneys' fees. All
fifteen cases have been consolidated before a single judge, under two omnibus
complaints. All of the class action and municipal lawsuits and all but one of
the individual lawsuits will be resolved upon approval of the Western Energy
Settlement. As to 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 plaintiffs' 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

29

Bustamante acting as a private citizen, against us, our subsidiaries EPNG, EPME,
and El Paso Tennessee Pipeline Co. (EPTP), 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 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 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. 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 arose out of a gas
supply contract between IMC Chemicals (IMCC) and EPME and sought to void the Gas
Purchase Agreement between IMCC and EPME for gas purchases until December 2003.
IMCC contended 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 repeated the
allegations and claims of the California lawsuits described above. EPME intends
to enforce the terms of the contract and counterclaim for contract damages. El
Paso Corporation was dismissed from the case for lack of personal jurisdiction
on September 9, 2003.

Other Energy Market Lawsuits. In February 2003, 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 approval of the Western Energy Settlement.

A purported class action lawsuit 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.

Two purported class action lawsuits were filed in federal court in New York
City in August 2003 and October 2003 alleging that El Paso, EPME and other
defendants manipulated the price of natural gas futures and option contracts
traded on the NYMEX. Our costs and legal exposure related to these lawsuits 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 allegations similar to those alleged in the California
cases, the suit seeks relief similar to the California cases, 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. The complaint 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 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;

30

(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 lawsuit 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 Western states. 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-judgment 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 lawsuits alleging violations of federal securities laws
have been filed against us and several of our former officers. Eleven of these
lawsuits are now consolidated in federal court in Houston before a single judge.
The twelfth lawsuit was dismissed in light of similar claims being asserted in
the consolidated suits in Houston. The lawsuits generally challenge the accuracy
or completeness of press releases and other public statements made during 2001
and 2002. Two shareholder derivative actions have also been filed which
generally allege the same claims as those made in the consolidated shareholder
class action lawsuits. One was filed in federal court in Houston in August 2002,
has been consolidated with the shareholder class actions pending in Houston, and
has been stayed. The second shareholder derivative lawsuit, 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. Two
other shareholder derivative lawsuits are now consolidated in state court in
Houston. Both generally allege that manipulation of California gas supply and
gas prices exposed us 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.

SEC Investigation. On October 6, 2003, we announced that the SEC had
authorized the Staff of the Fort Worth Regional Office to conduct an
investigation of certain aspects of our periodic reports filed with the SEC. The
investigation appears to be focused principally on our power plant contract
restructurings and the related disclosures and accounting treatment for the
restructured power contracts, including in particular the Eagle Point
restructuring transaction completed in 2002. We are cooperating with the SEC
investigation.

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 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.

31

After a public hearing conducted by the National Transportation Safety
Board (NTSB) on its investigation into the Carlsbad rupture, the NTSB published
its final report in April, 2003. 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 this
investigation.

A number of personal injury and wrongful death lawsuits were filed against
EPNG in connection with the rupture. All of these lawsuits 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 of the 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 an additional 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 settlement
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 23 firemen and EMS personnel who responded to the fire and who
allegedly have suffered psychological trauma. EPNG filed a motion to dismiss the
Baldonado lawsuit which is pending before the court. 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,
attorneys' 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 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.

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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 ten such lawsuits in New
York, one in New Hampshire, one in Massachusetts, three in Connecticut and one
in Illinois. The plaintiffs generally seek remediation of their groundwater and
prevention of future contamination and a variety of compensatory damages as well
as punitive damages, attorney's fees, and court costs. In the case filed in
Illinois, certification of a national plaintiff's class of certain water
providers is requested. Our costs and legal exposure related to these lawsuits
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 September 30, 2003, we had approximately $1,143 million accrued for all
outstanding legal matters, of which $1,035 million related to our Western Energy
matters. Approximately $5 million of the accrual was related to our discontinued
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 September
30, 2003, we had accrued approximately $429 million, including approximately
$418 million for expected remediation costs at current and former operated sites
and associated onsite, offsite and groundwater technical studies, and
approximately $12 million for related environmental legal costs, which we
anticipate incurring through 2027. Approximately $50 million of the accrual was
related to our discontinued operations.

Our reserve estimates range from approximately $418 million to
approximately $618 million. Our accrual represents a combination of two
estimation methodologies. First, where the most likely outcome can be reasonably
estimated, that cost has been accrued ($98 million). Second, where the most
likely outcome cannot be estimated, a range of costs is established ($320
million to $520 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 September 30, 2003
(in millions):

Balance as of January 1, 2003............................... $498
Additions/adjustments for remediation activities............ (18)
Payments for remediation activities......................... (52)
Other changes, net.......................................... 1
----
Balance as of September 30, 2003............................ $429
====

In addition, we expect to make capital expenditures for environmental
matters of approximately $289 million in the aggregate for the years 2003
through 2008. These expenditures primarily relate to

33

compliance with clean air regulations. For the remainder of 2003, we estimate
that our total remediation expenditures will be approximately $20 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 its Pennsylvania and New York stations. In May
2003 we 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 our 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 our estimated cost to complete the project.

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.

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 remediation costs, 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 September 30, 2003, TGP had pre-collected PCB costs by
approximately $117 million. This pre-collected amount 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 collected,
to refund to its customers the difference, plus carry charges incurred up to the
date of the refunds. As of September 30, 2003, TGP has recorded a regulatory
liability (included in other non-current liabilities on its balance sheet) of
$85 million for future refund obligations. This obligation increased by $25
million in the second quarter due to the reduction of our accrual of estimated
future PCB remediation and legal costs discussed above.

Coastal Eagle Point. 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. The Orders allege
noncompliance with the New Jersey Air Pollution Control Act (the Act) pertaining
to excess emissions reported since 1998 by our Eagle Point refinery in
Westville, New Jersey. On February 24, 2003, EPA Region 2 issued a Compliance
Order alleging violations that included failure to monitor all components and
failure to timely repair leaking components. The alleged violations were
identified during a 1999 EPA audit of the Leak Detection and Repair program. Our
Eagle Point refinery resolved the claims of the United States and the State of
New Jersey in a Consent Decree on September 30, 2003, pursuant to the EPA's
refinery enforcement initiative. We agreed to pay a civil penalty of $1.25
million to the United States and $1.25 million to New Jersey. We will contribute
$1.0 million to an environmentally beneficial project near the refinery. Our
Eagle Point refinery will invest an estimated $3 to $7 million to upgrade the
plant's environmental controls by 2008. This settlement is subject to public
comment and court approval.

34

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 62 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 September 30, 2003,
we have estimated our share of the remediation costs at these sites to be
between $32 million and $43 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 Superfund 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 complaint, 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 council on May 27, 2003. The complaint
was voluntarily withdrawn from the FERC. The CPUC/CEOB matter will be fully
resolved upon approval and finalization of the Western Energy Settlement. NPSP
has petitioned for review of the FERC decision.

CPUC Complaint Proceeding. In April 2000, the CPUC 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

35

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
approval and finalization 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 EPNG 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 by not expanding
its system, at its cost, to meet their increased requirements. Earlier, KN
Marketing, L.P. filed a complaint at the FERC alleging that EPNG had
oversubscribed its firm mainline capacity from the San Juan Basin to the East
End of its system. In the May 31, 2002 order discussed below, the FERC addressed
these complaints. As a result of the FERC's orders in these proceedings, FR
shippers were required to convert to CD service on September 1, 2003.

On May 31, 2002, the FERC issued an order that required (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 system-wide
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 CD customers to turn back capacity for acquisition by FR customers, in
which process EPNG would remain revenue neutral. The order also stated that the
FERC expected EPNG to file for certificate authority to add compression to its
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 it was willing to do. On July 1, 2002, EPNG and other parties
filed for clarification and/or rehearing of the May 31 order.

Following the May 31 order, the FERC issued several additional orders in
this proceeding that, among other things, required EPNG to allocate substantial
volumes of existing and proposed pipeline capacity to its converting FR shippers
at their current aggregate reservation charges, and set the rates that EPNG
could charge for backhaul service from its California delivery points for
existing and new shippers.

On July 9, 2003, the FERC issued a rehearing order in this case. In that
order, the FERC found that EPNG had not violated its certificates, its
contractual obligations, including its obligations under the 1996 Rate
Settlement (discussed below), or its tariff provisions as a result of the
capacity allocations that have occurred on the system since the 1996 Rate
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 it had properly allocated that capacity. On a prospective basis, the FERC
ordered EPNG 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, EPNG will limit the amount of
its reservation charge credits to the return and associated tax portion of its
rates. The rehearing order also lifted the ban established in the May 31 order
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.

36

On July 18, 2003, the FR shippers filed an appeal of the July 9 order with
the D.C. Circuit (Arizona Corporation Comm'n, et al. v. FERC, No. 03-1206) and
subsequently sought a stay of the FERC's orders. The stay was denied by the
Court. Other parties have filed appeals of the FERC's orders and all such
appeals have been consolidated. The final outcome of these appeals cannot be
predicted with certainty.

On August 29, 2003, the FERC issued a further order in this matter that,
among other things, authorized our converted FR shippers to relocate the
delivery points associated with the California turn back capacity they would
receive under the May 31 order from California to their traditional east of
California delivery points. EPNG sought rehearing of that order because it does
not have adequate transfer capacity between its Northern and Southern mainlines
to allow it to comply with the order unless it allocates its limited North/South
capacity among its shippers. EPNG's converted FR shippers requested that the
FERC initiate an enforcement investigation based on EPNG's position. EPNG has
opposed the request. In the August 29 order, FERC also directed that a technical
conference be held to address various concerns expressed by EPNG's shippers.
That conference was held on September 24, 2003 and EPNG filed its comments on
that conference with the FERC. On October 20, 2003, EPNG and the converted FR
Shippers filed an uncontested settlement that if approved by the FERC, will
resolve all issues regarding the administration of the 110 MMcf/d capacity pool.

On October 29, 2003, EPNG's east of California shippers filed a complaint
against it with the FERC claiming that it had not properly implemented the
FERC's orders in the Capacity Allocation Case with respect to its provision of
backhaul transportation service from the California border and requesting that
the FERC issue an order requiring it to properly implement such service. EPNG
will respond to the complaint.

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 September 30, 2003, EPNG had unearned risk sharing
revenues of approximately $8 million and had $3 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 $30 million of which $14 million
has been refunded to customers as of September 30, 2003. 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 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. On June 4, 2003, the
FERC issued an order approving EPNG's certificate application. Requests for
rehearing of the June 4 order are pending at the FERC. The project is currently
under construction and Phase I should be placed in service during the first
quarter of 2004.

37

Marketing Affiliate NOPR. In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR) proposing 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 an order that prospectively prohibits
pipelines from negotiating rates based upon natural gas commodity price indices
and imposes certain new filing requirements to ensure the transparency of
negotiated rate transactions. Requests for rehearing were filed on August 25,
2003 and remain pending. We do not expect that the order on rehearing will have
a material effect on us.

Cash Management Rule. On October 23, 2003, the FERC approved a rule that
requires a FERC-regulated entity to file its cash management agreement with the
FERC, maintain records of transactions involving its participation in the cash
management program, compute its proprietary capital ratio quarterly based on
criteria established by the FERC, and notify the FERC 45 days after the end of a
calendar quarter whether its proprietary capital ratio falls below 30 percent
and subsequently when its proprietary capital ratio returns to or exceeds 30
percent. In the rule, the FERC stated that the requirements imposed by the rule
are not in the nature of a regulation governing participation in cash management
programs and that the rule does not dictate the content or terms for
participating in a cash management program. Although the rule is subject to
rehearing, we do not believe an order on rehearing will have a material effect
on us.

On September 10, 2003, the Office of Executive Director of Regulatory
Audits completed an industry-wide audit of the FERC Form 2 related to cash
management. The audit included EPNG and Mojave Pipeline Company. The audit did
not identify any instances of non-compliance with the FERC's reporting and
recording requirements but recommended that both EPNG and Mojave revise and
update their existing cash management agreements with El Paso. EPNG, Mojave and
our other pipelines are in the process of reviewing and revising their cash
management agreements pursuant to this recommendation.

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. Although we cannot predict the outcome of this
rulemaking, we do not expect the order to have a material effect on us.

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 the issuance of the notes and if the
notes were to be included in SNG's and ANR's 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

38

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 the Office of Market
Oversight and Investigation further explaining a March 26, 2003 data response in
this proceeding 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 also received similar requests from the Commodities Futures
Trading Commission (CFTC), and the U.S. Attorney. 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 CFTC, and
to the U.S. Attorney in response to their requests. The information provided
indicates inaccurate prices were reported to the trade publications. However,
EPME has no evidence that these reported prices to the publications resulted in
any unrepresentative price index in any pricing publication. 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 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) that
respondent confirm that all trade data reporting is done by an entity within the
company that does not have a financial interest in the published index; and 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

39

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, which
was denied in October 2003. 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. In its response to the OSC, EPME stated that the
alleged partnership is a "parking" transaction with Public Service Company of
New Mexico which EPME entered into for legitimate business purposes. On October
3, 2003 the FERC staff filed a motion to dismiss EPME from this proceeding. In
light of the FERC staff's motion to dismiss EPME from this proceeding, on
November 4, 2003, the Chief Administrative Law Judge of the FERC issued an order
stating that EPME is not subject to the litigation process in this proceeding,
pending action by the FERC Commissioners on the FERC staff's motion to dismiss
EPME.

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
September 30, 2003, our remaining investment in EPIC was approximately $53
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. In September 2003, after receiving comments from the
parties, the TPUC issued an interim order that largely upheld 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. The
interim order will not become final until the language set forth in the
interconnect agreement is consistent with the Triennial Review order of the
Federal Communications Commission (FCC) as described below.

FCC Triennial Review. In this proceeding, the FCC, pursuant to its
Congressional mandate, reexamined the entire list of UNEs, including high
capacity loops and transport and dark fiber, to determine if any should be
removed or qualified. The FCC may either eliminate or set more stringent
offering guidelines for some of the existing UNE's. Any ruling that seriously
impairs El Paso Global Networks' (EPGN) ability to access these UNEs would
significantly affect its current business model. An order was issued by the FCC
on August 21, 2003 validating several important issues to the EPGN activities
and plans, such as access to dark fiber loops and transport as UNEs, access to
network information, and splicing of dark fiber. The FCC also affirmed that UNEs
may be used to provide wholesale services to other telecommunication carries.
The Order has been appealed.

40

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" in the same
way that cable modems are listed by the FCC, thereby exempting the ILECs from
having to lease their lines to EPGN. The Court of Appeals for the Ninth Circuit,
on October 9, 2003, reversed the FCC decision that cable modems are purely
information services with no telecommunications service component. No decision
is expected in 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 possible that these matters could
impact our debt rating and credit rating. Further, for environmental matters, it
is 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 our cash flows in the periods these events occur.

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 natural gas liquids
and the trading of physical natural gas, power, petroleum and financial
derivatives.

Our Merchant Energy positions were 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's 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 El Paso Merchant
Energy-Petroleum Company (EPMPC), as successor by merger to Coastal States
Trading, Inc., our subsidiary, owes it approximately $3 million related to
certain terminated petroleum contracts. EPMPC disputes this assertion due to
contractual setoff rights. After considering the cash margins Enron deposited
with us as well as the reserves we have established, our overall Merchant Energy
exposure to Enron is $21 million, which is classified as current accounts and
notes receivable. We believe our reserves are adequate 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 also
consistent with the projected distributions reflected in the disclosure
statements recently filed by Enron in its bankruptcy proceedings.

41

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 demanded 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. If
the court adopts Enron's methodology, it could result in a reduction or
elimination of our claims against Enron Corp. and its subsidiaries described
above.

In early May 2003, Enron Broadband Services, Inc. filed a notice of
rejection with respect to an agreement granting El Paso Networks, L.L.C. the
right to use certain dark fiber in the Denver area. El Paso Networks objected to
the notice of rejection. Enron Broadband Services withdrew its notice of
rejection without waiving its rights to reject the contract in the future.

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. 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 our 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 claim based on damages calculated under the various trading agreements
with NRG. Xcel Energy, Inc., NRG's parent, 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. The court
approved a settlement agreement between EPME and NRG providing for a payment to
EPME of $13 million. We are fully reserved for the difference between the net
claim filed and the settlement amount.

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 the 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 14, 2003. EPME immediately
terminated its Master Netting Agreement with Mirant Americas Energy Marketing,
L.P. EPME believes the damages owed to Mirant under the Master Netting Agreement
are $37 million, and provided its calculations to Mirant. Mirant claimed that
EPME defaulted under the terms of the Master Netting Agreement because the
calculations were not commercially reasonable. Mirant asserts that the damages
should be $106 million. The parties are currently preparing to arbitrate the
issue. EPME believes the liability accrued will be sufficient to provide for its
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 may 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

42

entities that are impacted by the bankruptcy filings. We do not believe we have
a material exposure as a result of these 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 in Camden and Bayonne and until October 15, 2003, we owned
79.2 percent of the indirect equity in Linden and Enron indirectly owned 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. A settlement was filed in connection with these
proceedings in October 2003 and discovery has been suspended. The settlement is
subject to approval by the FERC and finds that the prior ownership of Camden,
Bayonne and Linden did not violate PURPA. A decision by FERC is currently
expected in the fourth quarter of 2003. In October 2003, we sold all of our
interest in the Linden facility to an affiliate of The Goldman Sachs Group, Inc.
for approximately $450 million adjusted for distributions after January 1, 2003.
Of this amount, Goldman retained $70 million of the purchase price pending the
FERC's decision related to Linden. On October 24, 2003, the presiding
administrative law judge certified the settlement. We expect the FERC to approve
the settlement in the fourth quarter, at which time we believe these proceeds
will be released.

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. We have entered into settlement discussions with
Broadwing to attempt to resolve this dispute. In the fourth quarter of 2002,
EPGN wrote down the value of this long-haul route by $104 million, leaving a
remaining investment of $4 million.

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 its foreign debt and the presidential elections
which were completed in late November 2002. These concerns contributed to
significantly higher interest rates on local debt for the government and private
sectors, significantly decreased the availability of funds from lenders outside
of Brazil and decreased the amount of foreign investment in the country. These
factors contributed to a downgrade of Brazil's foreign currency debt rating and
a 26 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
43

$30 billion loan package for Brazil and Brazil has met the specified fiscal
targets set by the IMF for 2003. In addition, Brazil's President or other
government representatives may impose or attempt to impose changes that could
affect 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 although we have raised $370
million of non-recourse debt on our Macae project through October 2003. 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 attempt 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 2002 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 would 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. Copel has filed suit in the Brazilian courts, seeking a declaration that
the arbitration clause in the PPA is null and void. If we do not prevail in the
arbitral 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 $179 million at September 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 $105 million at September 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 $109 million at September 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 is an indirect wholly owned subsidiary of Centrais
Electricas Brasileiras S. (Eletrobras), a Brazilian federal utility holding
company. As of September 30, 2003, our total accounts receivable on these
projects is $35 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 an additional
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
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 September 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

44

Brasil S.A. (Eletronorte), 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 project. The second PPA has a term of
twenty years and relates to the second 345-megawatt phase of the project (the
Phase 2 PPA). We have 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 are continuing. 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, which was $289 million at September 30, 2003,
including guarantees we 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 53 percent against the U.S.
dollar during 2003 (through September 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 received final approval of the IMF Board in August. The
Dominican government maintains that the accord could lead to approximately $1.2
billion in disbursements from multilaterals over the next 24 months and will
serve to restore consumer and investor confidence in the banking system and
economic policy framework, stabilize the exchange rate and avoid a liquidity
crisis. An initial disbursement of funds was made in August 2003, but further
disbursements are pending approval by the IMF.

We have investments in power projects in the Dominican Republic with an
aggregate exposure of approximately $100 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
$56 million at September 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 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.

45

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. As a result of the
default under the construction lending agreement, we evaluated our investment
and recorded an impairment charge of $17 million. 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. On September 10, 2003 we entered into an agreement with the
Milford lenders and agreed to their takeover of our interest in the Milford
project upon the satisfaction of certain conditions. In return for a payment of
$10 million by us, the Milford lenders agreed, effective immediately, to allow
us to terminate a fuel purchase agreement that we have with Milford thereby
ending our obligation to provide additional security in the form of $73 million
in fuel subordination. In return for an additional payment of $7 million by us,
the Milford lenders agreed to the termination of various other agreements to be
replaced by a single new agreement. This agreement is subject to receiving all
approvals, including that of FERC. Simultaneously on September 10, 2003, Milford
entered into a settlement with its construction contractor pursuant to which the
contractor shall pay $18 million in delayed liquidated damages, forego $5
million in additional payments, and provide a $10 million credit to be applied
to future operating services as well as post a letter of credit for $17 million
as security for specified obligations. The settlement agreement became effective
on October 20, 2003.

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 negotiated a settlement
with the contractor with respect to its failure to deliver the project in
accordance with guaranteed specifications. Berkshire agreed to settle its claims
against the contractor in exchange for $6 million to be applied to future
operating services and the contractors agreement to perform plant upgrades at no
charge. 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 September 30, 2003, we
had an investment in Berkshire of $4 million, receivables from Berkshire of $30
million and derivative contracts with Berkshire of $11 million associated with a
subordinated fuel agreement and a fuel management agreement. 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
Corp. 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 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
46

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 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. On July 31, 2003, the federal court remanded this case back to state
court. On August 18, 2003, Duke filed a third-party petition against
Sonatrading, its Algerian LNG supplier. CTC opposed the petition since, even in
the event of a failure to receive supplies from Algeria, Duke was required to
furnish supplies to CTC for a stated period of time. On October 6, 2003, the
court ruled that, although Duke may attempt to get service on Sonatrading,
Duke's claim against its supplier will be tried separately (and thus not delay
or otherwise impact this case). Also on October 6, 2003, CTC filed an amended
petition against Duke seeking termination damages of $187 million. 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; Cornerstone
Propane Partners, L.P. v. Reliant Energy Services, et al. filed August 2003 in
the United States District Court, Southern District of New York; Robert E.
Callegracey v. American Electric Power Company, Inc. et al. filed October 2003
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

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*Cases to be dismissed upon finalization and approval of the Western Energy
Settlement.
47

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 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. The
consolidated shareholder derivative action filed in Houston is John Gebhart and
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, William
Wise, Joe Wyatt, Ralph Eads, Brent Austin and John Somerhalder 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 MTBE cases discussed above and filed in New York are: County of Suffolk
and Suffolk County Water Authority v. Amerada Hess Corp., et al., filed on
October 9, 2002, in the Supreme Court of the State of New York, County of
Suffolk, and the following eight cases filed on September 30, 2003 in the
Supreme Court of the State of New York, County of New York: County of Nassau v.
Amerada Hess, et al., Village of Mineola, Inc. and Water Dept. of the Village of
Mineola v. Atlantic Richfield, et al., West Hempstead Water District v. Atlantic
Richfield Co., et al., Carle Place Water District v. Atlantic Richfield Co., et
al., Town of Southampton v. Atlantic Richfield Co., et al., Village of Hempstead
v. Atlantic Richfield Co., et al., Town of East Hampton v. Atlantic Richfield
Co., et al., and Westbury Water District v. Atlantic Richfield Co., et al. The
tenth case Water Authority of Western Nassau v. Atlantic Richfield Co., et al.,
was filed on October 1, 2003 in the Supreme Court of the State of New York,
County of New York.

The MTBE case filed in New Hampshire is State of New Hampshire v. Amerada
Hess Corp. et al., filed in New Hampshire Superior Court, County of Merrimack,
on September 30, 2003.

The MTBE case filed in Massachusetts is Brimfield Housing Authority
(Brimfield, MA), et al. v. Amerada Hess Corporation, et al., filed in
Massachusetts Superior Court, County of Suffolk, on September 30, 2003.

48

The three MTBE cases filed in Connecticut are Childhood Memories v. Amerada
Hess Corporation, et al., filed in Connecticut Superior Court, Judicial District
of Litchfield, on September 30, 2003, Columbia Board of Education, Horace Porter
School v. Amerada Hess Corporation, et al., filed in Connecticut Superior Court,
Judicial District of Tolland, on September 30, 2003, and Canton Board of
Education, Cherry Brook School v. Amerada Hess Corporation, et al., filed in
Connecticut Superior Court, Judicial District of Hartford, on September 30,
2003.

The MTBE case filed in Illinois is Village of East Alton, Individually and
on behalf of all others similarly situated v. Amerada Hess Corporation, et al.,
filed in the Circuit Court, Third Judicial Circuit, Madison County, Illinois, on
September 30, 2003.

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.

Commitments and Purchase Obligations

During 2003, we entered into purchase obligations to acquire pipe and other
equipment that will be used in our Cheyenne Plains Pipeline project. Our total
commitment is approximately $96 million and will be paid during 2004.

19. CAPITAL STOCK

On October 30, 2003, we declared a quarterly dividend of $0.04 per share on
our common stock payable on January 5, 2004, to stockholders of record on
December 5, 2003. During the quarter and nine months ended September 30, 2003,
we paid dividends of $24 million and $178 million to common stockholders. In
addition, El Paso Tennessee Pipeline Co., our subsidiary, paid dividends of
approximately $6 million and $19 million on its Series A cumulative preferred
stock, which is 8 1/4% per annum (2.0625% per quarter).

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. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. 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.
Also, 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.
EBIT may not be comparable to measures used by other companies and should not be
used as a substitute for net income or

49

other performance measures such as operating income or operating cash flow. The
reconciliations of EBIT to income (loss) from continuing operations are
presented below:

The following tables reflect our segment results as of and for the periods
ended September 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.

(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 and a gain
occurs when hedged prices are higher than market prices. Intersegment
revenues represent sales to our marketing affiliate EPME, which is
responsible for marketing our production.

(3) Relates to intercompany activities between our continuing operating segments
and our discontinued petroleum markets operations.

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

50

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(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 and a gain
occurs when hedged prices are higher than market prices. Intersegment
revenues represent sales to our marketing affiliate EPME, which is
responsible for marketing our production.

(3) Relates to intercompany activities between our continuing operating segments
and our discontinued petroleum markets operations.

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

51

Total assets by segment are presented below:

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
a greater than 50 percent interest. Our proportional share of the net income of
the unconsolidated affiliates in which we hold a greater than 50 percent
interest was $1 million and $7 million for the quarters ended, and $6 million
and $21 million for the nine months ended September 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) 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).

52

(2) This impairment resulted from a write-off of notes receivable and accruals
on contracts due to ongoing difficulty at the project level.
(3) This impairment resulted from weak economic conditions in Argentina.
(4) The impairment results from the anticipated loss from the sale of East Coast
Power, L.L.C.

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:

Chaparral and Gemstone

As of December 31, 2002, we held equity investments in Chaparral and
Gemstone. During the second quarter of 2003, we acquired the remaining third
party equity interests and all of the voting rights 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.

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.

As of September 30, 2003, we owned 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 its Series C units. During 2003, we contributed approximately
$2 million of our Series B preference units to GulfTerra in order for us to
maintain our one percent general partner interest as a result of three common
units offerings completed by GulfTerra.

In October 2003, we sold 9.9 percent of the one percent general partner
interest of GulfTerra to Goldman Sachs for $88 million. In addition, GulfTerra
redeemed all of the Series B preference units that we owned for $156 million.
Finally, as part of the overall transaction, GulfTerra released us from our
obligation to repurchase the Chaco processing facility and we contributed
communications assets to GulfTerra. Prior to the transaction, we would have been
obligated to repurchase the facility for approximately $77 million in 2021. As
part of the approval process, we retained an independent financial advisor who
provided us with a fairness opinion related to these transactions. We also
retained an independent third party consultant to assist us in determining the
value of the general partner interest sold to Goldman Sachs. Based on
preliminary valuations performed by this consultant, we estimate that we will
recognize a gain on these transactions in excess of

53

$100 million in the fourth quarter of 2003. We expect to finalize this estimate
once we receive the final valuation report from our consultant in the fourth
quarter of 2003.

Also in October 2003, we sold 590,000 of the partnership's common units
that we owned for approximately $23 million. Following these transactions, we
own the remaining 90.1 percent of the general partner interest, 19.0 percent of
the partnership's common units and all of GulfTerra's Series C units.

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
Current Report on Form 8-K dated September 23, 2003.

22. NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

As of September 30, 2003, there were several 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.

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. On October 9, 2003, the FASB issued FASB Staff Position, FSP
FIN No. 46-6, Effective Date of FASB Interpretation No. 46, Consolidation of
Variable Interest Entities. This staff position deferred our required adoption
date of FIN No. 46 to the fourth quarter of 2003.

Upon adoption of this standard, 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 other current and
non-current assets of approximately $30 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.

54

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 Current Report on Form 8-K dated
September 23, 2003, 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 at the same time
maximizing liquidity;

- Aggressively pursue additional cost reductions; and

- Work diligently to resolve regulatory and litigation matters.

To date in 2003, our major accomplishments regarding these business objectives
have been as follows:

- We concentrated our capital investment in our core Pipelines, Production
and Field Services segments such that 91 percent of total capital
expenditures have been made in these businesses in the first nine months
of 2003;

- We completed or announced sales of assets and investments of
approximately $3.1 billion;

- We entered into a new $3 billion revolving credit facility that matures
in June 2005 and completed financing transactions of approximately $3.8
billion ($3.6 billion as of September 30, 2003);

- We retired approximately $5.8 billion of maturing debt and other
obligations ($4.7 billion as of September 30, 2003), including:

- the retirement of long-term debt of $2.9 billion ($2.2 billion as of
September 30, 2003);

- the net repayment of $650 million of outstanding amounts under our $3
billion revolving credit facility ($250 million as of September 30,
2003);

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

- the redemption of $197 million of obligations under our Clydesdale
financing arrangement, also restructuring that transaction as a term
loan that will amortize over the next two years; and

- the contribution of $1 billion to the Limestone Electron Trust, which
used the proceeds to repay $1 billion of its notes and the purchase
and consolidation of the third party equity interests in our Gemstone
and Chaparral power investments;

- We refinanced 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;

- We identified an estimated $445 million of costs savings and business
efficiencies to be realized by the end of 2004;

- We executed definitive settlement agreements in June 2003, which
substantially resolved our principal exposure relating to the Western
Energy crisis and raised funds of $347 million to satisfy a portion of
our obligation through the issuance of senior unsecured notes of EPNG in
July 2003;

55

- We initiated a tender offer in October 2003 to exchange common stock and
cash for our outstanding equity security units which would, if 100
percent of the units were tendered, result in a reduction of up to $575
million in our outstanding debt balances, an increase in stockholders'
equity of up to approximately $475 million and a reduction of cash of up
to approximately $112 million; and

- We initiated a program to supplement our capital spending on natural gas
and oil properties by an additional $350 million.

56

LIQUIDITY AND CAPITAL RESOURCES

OVERVIEW OF CASH FLOW ACTIVITIES FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2003

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

During the nine months ended September 30, 2003, our cash and cash
equivalents increased by approximately $52 million to approximately $1.6
billion. We generated cash from several sources, including from our principal
continuing operations as well as through our discontinued operations, sales of
assets and issuances of long-term debt. We used a major portion of that cash to
fund our capital expenditures, purchase additional investments in subsidiaries
and redeem preferred interests of minority interest holders. Overall, our cash
sources and uses are summarized as follows (in billions):

Cash inflows
Cash flows from continuing operations (before working and
non-working capital changes)........................... $1.2
Working capital and non-working capital changes........... 0.6
Net proceeds from the sale of assets and investments...... 1.4
Net proceeds from the issuance of long-term debt.......... 3.4
Borrowings under revolving credit facility................ 0.5
Net discontinued operations activity...................... 0.4
----
Total cash inflows..................................... 7.5
----
Cash outflows
Additions to property, plant and equipment................ 2.0
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......................... 2.1
Payments on revolving credit facilities................... 0.7
Dividends paid to common stockholders..................... 0.2
Other..................................................... 0.1
----
Total cash outflows.................................... 7.4
----
Net increase in cash................................. $0.1
====

57

As of October 31, 2003, we had available cash on hand and borrowing
capacity under our revolving credit facility totaling $2.7 billion. 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 was $1.8
billion for the first nine months of 2003 versus $1.3 billion in the same period
of 2002. We have generated approximately $1.2 billion in cash from operations
(net income from continuing operations adjusted for non-cash income items) in
the first nine months of 2003 before working capital and non-working capital
changes, as compared to $1.5 billion in 2002. The decline in 2003 was primarily
a result of the impact on cash of sales of operating assets during both 2002 and
2003 and the effects of lower capital spending in our Production segment.
Working capital sources were $0.6 billion in 2003 as compared to $0.2 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. Since the beginning of 2003,
volatility in natural gas prices has caused the amounts that we are required to
post as collateral for margin calls and other credit requirements to be at
approximately the same level as those requirements at the beginning of the year,
despite an overall reduction in the number of contracts requiring collateral.
However, we recovered cash in 2003 by substituting letters of credit under our
new revolving credit facilities for actual cash on deposit, and as a result, our
2003 margin activity has been a source of cash of approximately $0.4 billion.

Cash From Continuing Investing Activities

Net cash used in our continuing investing activities was $1.9 billion for
the nine months ended September 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.............................................. $1.3
Pipeline expansion, maintenance and integrity projects...... 0.5
Net cash paid to acquire Chaparral and Gemstone............. 1.1
Other (primarily power projects)............................ 0.1
----
Total capital expenditures and additional
investments....................................... $3.0
====

Cash received from our investing activities includes $1.4 billion from the
sale of assets and investments, including the sale of natural gas and oil
properties located in western Canada, Texas, Louisiana, 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 $0.5 billion.

Cash From Continuing Financing Activities

Net cash provided by our continuing financing activities was $0.2 billion
for the nine months ended September 30, 2003. Cash provided from our financing
activities included the net proceeds from the issuance of long-term debt of $3.4
billion, $0.4 billion of cash contributed by our discontinued operations and
other financing activities of $0.1 billion. Cash used in our financing
activities included net repayments of $0.2 billion on revolving credit
facilities and $2.1 billion of payments made to retire third party long-term
debt. We also paid $1.2 billion to fully redeem our Trinity River preferred
securities and partially redeem our Clydesdale preferred securities and paid
dividends to common stockholders of $0.2 billion.

Cash from Discontinued Operations

During the first nine months of 2003, our discontinued operations generated
$0.4 billion of cash through sales of inventories at our refineries and asset
sales which raised $0.5 billion, offset by capital expenditures of $0.1 billion.
These net cash inflows were distributed to our continuing operations.

58

FINANCING AND COMMITMENTS

Our Current Report on Form 8-K dated September 23, 2003, 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 that
Form 8-K.

During the first nine months of 2003, we completed a number of actions
intended to simplify our financial and capital structure, refinance shorter term
obligations and reduce guarantees and other "off-balance sheet" obligations,
replacing 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 as of
December 31, 2002................................ 21,991
-------
Acquisitions and consolidations:
Chaparral and Gemstone(1)(2).............................. 2,578
Operating leases and refinanced securities of
subsidiaries........................................... 1,018
Elimination of affiliated obligations..................... (326)
Principal amounts borrowed(3)............................... 4,050
Repayments/retirements of principal(3)...................... (2,989)
Reclassifications of preferred interests as long-term
financing obligations(4).................................. 625
Redemptions and eliminations of securities of
subsidiaries.............................................. (2,955)
Other....................................................... 53
-------
Total debt and securities of subsidiaries as of
September 30, 2003............................... $24,045(5)
=======

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

(1) This is a non-recourse project financing or contract debt.

(2) This amount includes $75 million related to Macae which was consolidated as
a consequence of our acquisition of Gemstone.

(3) Includes $500 million of borrowings and $750 million of repayments under our
revolving credit agreements.

(4) Relates to our adoption of SFAS No. 150. See Item 1, Notes 2, 16 and 17.

(5) Does not include $370 million of long-term debt related to our Aruba
refinery that is classified as part of our discontinued operations.

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.
Our $3 billion revolving credit facility has a borrowing cost of LIBOR plus 350
basis points, letter of credit fees of 350 basis points and commitment fees of
75 basis points

59

on unused amounts of the facility. This facility replaced our previous $3
billion revolving credit facility. Approximately $1 billion of our other
financing arrangements (including the leases discussed in Item 1, Notes 3 and
11, letters of credit and other facilities) were also amended to conform the
provisions of those obligations to our $3 billion revolving credit facility. The
$3 billion revolving credit facility and those other financing arrangements are
secured by our equity in EPNG, TGP, ANR, WIC, ANR Storage Company, Southern Gas
Storage Company and our Series A and Series C units in GulfTerra. The $3 billion
revolving 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.

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 September 30,
2003, we were in compliance with these covenants.

As of September 30, 2003, there were $1.3 billion of borrowings outstanding
and $1.0 billion of letters of credit issued under the $3 billion revolving
credit facility, all of which was borrowed by or issued on behalf of us. Amounts
outstanding under the $3 billion revolving credit facility as of September 30,
2003, were classified as non-current in our balance sheet, based on the maturity
date which is June 30, 2005. Subsequent to September 30, 2003, we repaid an
additional $400 million under our revolving credit facility. In addition, in
October 2003, we liquidated a portion of the collateral that supports the
revolver and related financing arrangements. The proceeds from the liquidation
will be used to reduce commitments and repay amounts outstanding under the $3
billion revolving credit facility and related financing arrangements. As a
result, there will be a $17 million reduction of the borrowing availability
under our $3 billion revolving credit facility.

We also maintained a $1 billion revolving credit facility, which expired on
August 4, 2003. EPNG and TGP were also borrowers under this facility.

The availability of borrowings under our $3 billion revolving credit
facilities and other 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.

Other

In October 2003, we initiated a tender offer to exchange our 11.5 million,
9% equity security units (consisting of a senior note and a stock purchase
contract) for our common stock and cash. For each unit tendered, the holder will
receive 2.5063 shares of common stock and cash in the amount of $9.70 per equity
security unit. The exchange offer is conditioned upon the valid tender of at
least 50 percent of the equity security units, or 5.75 million equity security
units, which condition may be waived by us at our sole discretion. If 100
percent of the units are tendered, our debt obligations would be reduced by up
to $575 million.

60

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) The proceeds from the two-year term loan were used to redeem our Trinity
River financing.
(3) Net proceeds were used to repay the $1.2 billion LIBOR based two-year term
loan.
(4) This is a non-recourse project financing or non-recourse debt related to our
power contract restructuring.
(5) This non-recourse project debt was consolidated as a consequence of our
acquisition of Gemstone.
(6) Amount excludes net repayments of $250 million through September 30, 2003,
and additional net repayments of $400 million as of October 31, 2003,
related to our $3 billion revolving credit facility which is classified as
long-term debt based on its maturity date of June 30, 2005.
(7) This debt related to Mohawk River Funding I, L.L.C. was eliminated through
the sale of this entity.
(8) This debt related to East Coast Power, L.L.C. was eliminated through the
sale of this entity.

Notes Payable to Affiliates

Our notes payable to unconsolidated affiliates as of September 30, 2003,
were $9 million versus $390 million as of December 31, 2002. The decrease was
primarily due to retirements of $45 million of

61

Chaparral debt securities in the first quarter of 2003 and the consolidation of
$123 million of Gemstone and $203 million of Chaparral debt securities in the
second quarter of 2003.

Minority Interests and Preferred Interests of Consolidated Subsidiaries

The total amount outstanding for securities of subsidiaries and preferred
stock of consolidated subsidiaries was $0.5 billion at September 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. Additionally, we
retired an additional $753 million of Clydesdale preferred member interests,
converting it into a loan that matures in equal quarterly installments through
2005. We also eliminated the entire $300 million of Gemstone's minority member
interest following our acquisition and consolidation of Gemstone and
reclassified $625 million of our Capital Trust I and Coastal Finance I
consolidated trusts as long-term financing obligations related to our adoption
of SFAS No. 150. See Item 1, Notes 2, 16 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 September 30, 2003, we had outstanding letters of credit of
approximately $1.2 billion (including $131 million related to our discontinued
petroleum markets operations) compared to $852 million (including $170 million
related to our discontinued petroleum markets operations) 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
businesses. Of the outstanding letters of credit, $148 million was supported
with cash collateral.

62

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. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. 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.
Also, 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.
EBIT may not be comparable to measures 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 to our EBIT and our EBIT to our net income (loss) for the
periods ended September 30:

63

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 owns and operates our interstate transmission
businesses. For a further discussion of the business activities of our Pipelines
segment, see our Current Report on Form 8-K dated September 23, 2003. Results of
our Pipelines segment operations were as follows for the periods ended September
30:

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

(1) Throughput volumes for the quarter and nine months ended September 30, 2002,
exclude 199 BBtu/d and 210 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.

64

Third Quarter 2003 Compared to Third Quarter 2002

Operating revenues for the quarter ended September 30, 2003, were $13
million lower than the same period in 2002. The decrease was due to a $14
million favorable resolution of measurement issues at a processing plant serving
the TGP system in 2002, $8 million from lower natural gas recovered in excess of
amounts used in operations and $6 million due to capacity contracts that have
expired which EPNG is prohibited from remarketing due to various FERC orders in
EPNG's systemwide capacity allocation proceeding. For a further discussion of
these orders, see Item 1, Note 18. These decreases were offset by $15 million
from higher revenues due to completed system expansions and new transportation
contracts.

Operating expenses for the quarter ended September 30, 2003, were $21
million lower than the same period in 2002 primarily due to the revaluation of
the stock portion of the Western Energy Settlement of $20 million. For a further
discussion of the settlement see Item 1, Note 6.

Other income for the quarter ended September 30, 2003, was $9 million lower
than the same period in 2002 primarily due to lower equity earnings of $6
million resulting from the sale of our interests in the Alliance pipeline system
completed in the first quarter of 2003 and $4 million from our investment in
Citrus.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Operating revenues for the nine months ended September 30, 2003, were $26
million higher than the same period in 2002. The increase was due to higher
revenues of $33 million due to completed system expansions and new
transportation contracts, $32 million from higher volumes and prices on natural
gas recovered in excess of amounts used in operations, $25 million from
increased transportation revenues due to higher throughput in 2003 as a result
of colder winter weather, $17 million from higher realized prices in 2003 on the
resale of natural gas purchased from the Dakota gasification facility which was
partially offset by $5 million from lower gas resales due to a FERC approved
buyout of the Dakota gas purchase contract effective August 1, 2003, $13 million
from higher sales under natural gas purchase contracts and a $9 million increase
in liquid revenues resulting from higher liquid prices. These increases were
offset by $48 million from lower revenues due to CIG's sale of the Panhandle
field and other production properties in July 2002, a $34 million revenue
reduction from capacity contracts that have expired which EPNG is prohibited
from remarketing due to various FERC orders and $18 million from the favorable
resolution of measurement issues at a processing plant serving the TGP system in
2002.

Operating expenses for the nine months ended September 30, 2003, were $156
million higher than the same period in 2002. The increase was primarily due to
$138 million from charges related to EPNG's portion of the Western Energy
Settlement. Also contributing to the increase were $16 million from higher
prices on natural gas purchased at the Dakota gasification facility along with
the impact of the FERC approved gas purchase contract buyout of $6 million which
was partially offset by $5 million from lower gas purchases following the
termination of the Dakota contract, $22 million of lower general and
administrative costs in 2002 versus 2003, an $11 million gain on the sale of
pipeline expansion rights in February 2002, $8 million from higher system supply
purchases in 2003 resulting from higher prices and volumes in 2003, and $7
million from higher depreciation due to a revision in depreciation expense for a
TGP facility that is being depreciated at an incremental rate of 6.67% per year
instead of the general system rate of 1.62% per year. These increases were
offset by a $27 million decrease in operating costs due to CIG's sale of its
Panhandle field and other production properties, $22 million from lower
environmental remediation and legal costs and a $12 million decrease due to bad
debt expense recorded in 2002 related to the bankruptcy of Enron Corp.

Other income for the nine months ended September 30, 2003, was $19 million
lower than the same period in 2002. The decrease was due to $16 million from
lower equity earnings due to the sale of our interest in the Alliance pipeline
system completed in the first quarter of 2003 and $11 million from the favorable
resolution of uncertainties in 2002 associated with the sale of our interests in
the Iroquois and Empire State pipeline systems and Gulfstream pipeline project
in 2001. These decreases were offset by $11 million from a higher allowance for
equity funds used during construction in 2003.

65

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 a low total cost level.

Since December 31, 2001, we have sold over 2.5 Tcfe of proved reserves in
multiple sales transactions with various third parties. The cumulative amount of
the reserves sold represented over 38 percent of our year end 2001 total reserve
base, and generated total cash proceeds of approximately $2.0 billion. These
sales were conducted as part of our overall efforts to reduce debt and improve
our liquidity position. These sales, which included proved developed producing
reserves, combined with normal production declines, mechanical failures on
certain producing wells and higher finding and development costs, have resulted
in our total equivalent production levels declining each quarter since the first
quarter of 2002. For the first nine months of 2003, our total equivalent
production has declined approximately 122 Bcfe or 27 percent as compared to the
same period in 2002. Future trends in production will be dependent upon the
amount of capital allocated to our Production segment, the level of success in
our drilling programs and any future sales activities relating to our proved
reserves.

As further described in our Current Report on Form 8-K dated September 23,
2003, 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 September 30, 2003, we
have hedged approximately 54 million MMBtu's of our remaining anticipated
natural gas production for 2003 at a NYMEX Henry Hub price of $3.38 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 this year, coupled with a lower
reserve base due to the asset sales mentioned above. For the fourth quarter of
2003, we expect our domestic unit of production depletion rate to be
approximately $1.84 per Mcfe.

For 2003, we expect to spend $1.4 billion on capital expenditures. During
the nine months ended September 30, 2003, we spent approximately $1.2 billion on
capital expenditures. In October 2003, we entered into agreements with a wholly
owned subsidiary of Lehman Brothers (Lehman), an investment bank, and a wholly
owned subsidiary of Nabors Industries Ltd. (Nabors) that will collectively
result in an additional $350 million of drilling activity over the next nine to
12 months. Lehman will contribute 50 percent of an estimated $500 million total
cost to develop two specified packages of wells in exchange for a 50 percent net
profits interest (cash proceeds available after royalties and operating costs
have been paid), and Nabors will contribute 20 percent in exchange for a 20
percent net profits interest in such packages of wells. Once a specified payout
is achieved, Lehman's and Nabors' net profits interests will convert to an
overriding royalty interest in the wells for the remainder of the wells'
productive lives. We will contribute the remaining 30 percent of the $500
million of capital as part of our existing 2003 and 2004 capital budget. Under
the terms of the agreements, all parties have a right to cease further
investment with 30 days notice.

As of January 1, 2003, our reserve estimates were prepared internally by
our Production segment and reviewed by Huddleston & Co., Inc. During the fourth
quarter of 2003, we appointed Ryder Scott Co. as our primary reservoir engineer.

66

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

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

(2) Prices are stated before transportation costs.

Third Quarter 2003 Compared to Third Quarter 2002

Operating revenues for the quarter ended September 30, 2003, were $89
million lower than the same period in 2002. Our natural gas revenues, including
the impact of hedges, were $71 million lower in the third quarter of 2003. Our
2003 natural gas production volumes decreased by 33 percent, resulting in a $133
million decrease in revenues versus the same period in 2002. Realized natural
gas prices rose in 2003 by 23 percent, resulting in a $62 million increase in
revenues when compared to the same period in 2002. The overall decline in
natural gas volumes was due to the sales of production properties in New Mexico,
Oklahoma, Utah, offshore Gulf of Mexico and western Canada as well as normal
production declines and mechanical failures in certain producing wells. Our oil,
condensate and liquids revenues, including the impact of hedges, were $20
million lower in the third quarter of 2003. Our 2003 oil, condensate and liquids
volumes decreased by 27 percent, resulting in a $25 million decrease in revenues
versus the same period in 2002. Realized oil, condensate and liquids prices rose
in 2003 by 8 percent, resulting in a $5 million increase in revenues when
compared to the same period in 2002. The declines in volumes were primarily due
to the property sales, production declines and mechanical failures mentioned
above.

67

Transportation and net product costs for the quarter ended September 30,
2003, were $9 million lower than the same period in 2002 primarily due to a
lower percentage of gas volumes subject to transportation fees and lower fees
incurred in 2003 to meet minimum payments on pipeline agreements.

Operating expenses for the quarter ended September 30, 2003, were $2
million lower than the same period in 2002 primarily due to lower oilfield
service costs of $4 million, as a result of asset dispositions which reduced
labor and production processing fees, and lower severance and other taxes of $2
million. Partially offsetting these decreases were higher general and
administrative costs of $3 million. While overall depletion expense remained
level, there was a $53 million increase due to higher depreciation, depletion
and amortization (DD&A) rates in 2003 and costs of $4 million related to the
accretion of our liability for asset retirement obligations in 2003, offset by a
$57 million decrease due to lower production volumes in 2003. The higher
depletion rate resulted from increased finding and development costs coupled
with a lower reserve base due to asset sales.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Operating revenues for the nine months ended September 30, 2003, were $112
million lower than the same period in 2002. Our natural gas revenues, including
the impact of hedges, were $87 million lower in 2003. Our 2003 natural gas
production volumes decreased by 25 percent, resulting in a $334 million decrease
in revenues versus the same period in 2002. Realized natural gas prices rose in
2003 by 25 percent, resulting in a $247 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, offshore Gulf of Mexico, 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 $43 million lower in
2003. Our 2003 oil, condensate and liquids volumes decreased by 34 percent,
resulting in a $97 million decrease in revenues versus the same period in 2002.
Realized oil, condensate and liquids prices rose in 2003 by 28 percent,
resulting in a $54 million increase in revenues when compared to the same period
in 2002. The declines in volumes were primarily due to the property sales,
production declines and mechanical failures mentioned above. Partially
offsetting the decrease in revenues was a positive mark-to-market adjustment of
$16 million in 2003 compared to 2002 related to hedges of anticipated future
production that no longer qualified for hedge accounting when we sold those
properties in March 2002.

Transportation and net product costs for the nine months ended September
30, 2003, were $9 million lower than the same period in 2002 primarily due to a
lower percentage of gas volumes subject to transportation fees.

Operating expenses for the nine months ended September 30, 2003 were $244
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 in 2003 of $38 million, primarily due to asset
dispositions which resulted in lower labor and production processing fees, and a
$5 million gain in 2003 on the sales of non-full cost pool assets. Partially
offsetting these decreases was higher depletion expense of $5 million,
consisting of a $143 million increase due to higher DD&A rates in 2003 and costs
of $14 million related to the accretion of our liability for asset retirement
obligations, partially offset by a $152 million decrease due to lower production
volumes in 2003. The higher depletion rate in 2003 resulted from increased
finding and development costs coupled with a lower reserve base due to asset
sales. Also offsetting these decreases were higher general and administrative
costs of $24 million in 2003, higher severance and other taxes of $16 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 nine months ended September 30, 2003, was $12 million
higher than in 2002 primarily due to higher earnings in 2003 from Pescada, an
equity investment in Brazil.

68

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 the one percent general partner interest. In October 2003, we sold 9.9
percent of our interest in the general partner to Goldman Sachs. We continue to
own the remaining 90.1 percent interest in the general partner. In addition,
GulfTerra redeemed all of the Series B preference units that we owned and
released us from our obligation to repurchase the Chaco gathering facility in
exchange for our contribution of communications assets to GulfTerra. Total
proceeds from this transaction were $244 million. Also in October 2003, we sold
590,000 of the partnership's common units that we owned for $23 million. For a
further discussion of these transactions, see Item 1, Note 21. Our ownership in
the partnership's common units decreased from 26.5 percent as of December 31,
2002 to 23.1 percent as of September 30, 2003 as a result of common unit
offerings by GulfTerra during the second and third quarters of 2003, and it
further decreased as a result of October 2003 unit offerings by GulfTerra and
our sale of 590,000 common units. As a result, in addition to our general
partner interest, we currently own, through various subsidiaries, 19.0 percent
of the partnership's common units and all of its Series C units.

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
also receive management fees pursuant to an agreement to provide various
operational and administrative services to the partnership. These management
fees have increased as a result of GulfTerra's asset acquisitions in 2002. We
expect these fees will continue to increase as additional services are provided.
In addition, we are reimbursed for other costs paid directly by us on the
partnership's behalf. During the quarter and nine months ended September 30,
2003, we received approximately $22 million and $68 million related to expenses
incurred on behalf of the partnership. During the quarter and nine months ended
September 30, 2002, we received approximately $15 million and $38 million
related to expenses incurred. Our earnings and cash distributions received from
GulfTerra were as follows:

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

(1) Our earnings and distributions will be reduced proportionately due to the
sale of 9.9 percent of our interest in the general partner and our sale of
590,000 of the partnership's common units. Additionally, due to the
redemption of our Series B units in October 2003, we will no longer receive
earnings on these units.

(2) The partnership was 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.

69

As a result of our asset sales and the resulting decline in our gathering
and processing activities, our EBIT has decreased significantly. However, the
increases in earnings from our interests in GulfTerra have partially offset
these decreases primarily because some of the assets were sold to GulfTerra. For
a further discussion of the business activities of our Field Services segment,
see our Current Report on Form 8-K dated September 23, 2003. Results of our
Field Services segment operations were as follows for the periods ended
September 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.

Third Quarter 2003 Compared to Third Quarter 2002

Total gross margins for the quarter ended September 30, 2003, were $47
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 sales of our San
Juan Basin assets in November 2002 and our Mid-Continent and north Louisiana
midstream assets in the second quarter of 2003. The sales of these assets
decreased gathering margins by $31 million and processing margins by $10
million. Processing margins also decreased $4 million in the third quarter of
2003 primarily 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 September 30, 2003, were $19
million lower than the same period in 2002 primarily due to the asset sales
discussed above, resulting in lower operating costs of $9 million and lower
depreciation expense of $4 million. Also contributing to the decrease were lower
operating expenses as a result of cost reductions of $6 million and higher fees
received of $4 million from GulfTerra for administrative and other services to
operate their assets. The increase in fees received was a direct result of
GulfTerra's asset acquisitions in 2002. These decreases were partially offset by
an additional legal reserve of $3 million in 2003 and $5 million of additional
costs related to higher maintenance requirements.

Other income for the quarter ended September 30, 2003, was $72 million
higher than the same period in 2002 primarily due to increased earnings of $23
million from our investment in GulfTerra, as well as a loss of $47 million
recorded in September 2002 related to the sale of our investment in the Aux
Sable natural gas liquids plant.

70

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Total gross margins for the nine months ended September 30, 2003, were $180
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 sales of our
Texas and New Mexico assets in April 2002, our San Juan Basin assets in November
2002, and our Mid-Continent and north Louisiana midstream assets in the second
quarter of 2003. The sales of these assets decreased gathering margins by $122
million and processing margins by $26 million. Processing margins also decreased
$13 million in the first nine months of 2003 primarily 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 of 2002.

Operating expenses for the nine months ended September 30, 2003, were $62
million lower than the same period in 2002 primarily due to the asset sales
discussed above, resulting in lower operating costs of $37 million and lower
depreciation expense of $21 million. Also contributing to the decrease in
operating expenses were 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 fees received of $14 million from GulfTerra to provide administrative
and other services to operate their assets. The increase in fees received was a
direct result of GulfTerra's asset acquisitions in 2002. In addition, our 2002
cost reduction plan, initiated mid-2002, resulted in $10 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 general and administrative costs of $8 million in 2003,
$10 million of purchase price adjustments in 2003 to gains from asset sales
during 2002, an additional legal reserve of $6 million in 2003 and $5 million
related to higher maintenance requirements.

Other income for the nine months ended September 30, 2003, was $30 million
higher than the same period in 2002 due to increased earnings of $60 million
from our investment in GulfTerra, as well as a loss of $47 million recorded in
September 2002 related to the sale of our investment in the Aux Sable natural
gas liquids plant. Partially offsetting the increase was $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.

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 markets division, but in June 2003, our Board of
Directors approved the sale of substantially all of these operations. As a
result, the petroleum markets division was reclassified as discontinued
operations for all periods presented. For a further discussion of our petroleum
markets operations, see Item 1, Note 11. The petroleum markets division
previously included our LNG business activities and equity earnings on a gas
processing plant and investments in several crude oil pipelines. These
operations are now included in the "Other" division in the tables below.
Merchant Energy's operating results and an analysis of those results for the
periods ended September 30 are presented below:

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

(1) Gross margin for our global power division consists of revenues from our
power plants and the initial net gains and losses incurred in connection
with the restructuring of power contracts, as well as the subsequent
revenues, cost of electricity purchases and changes in fair value of those
contracts. The cost of fuel used in the power generation process is included
in operating expenses. Gross margin for our energy trading division and
other division consists of revenues from commodity trading and origination
activities less the costs of commodities sold, including changes in the fair
value of our derivative contracts.

Global Power

Our global power division includes the ownership and operation of domestic
and international power generating facilities, including consolidated plants and
equity investments. Our Current Report on Form 8-K dated September 23, 2003,
includes a description of the various power activities included in global power.

Our domestic operations primarily include contracted operations, merchant
operations and the results of our power restructuring business. Our contracted
operations include our power plants that have dedicated power contracts with
customers. The results of our contracted operations include the income related
to the generation of power to meet long-term power commitments to electric
utilities. Typically, the fixed price long-term sales contracts and the fixed
price long-term fuel contracts in these operations are recorded on an accrual
basis. However, some of our contracted operations have derivative fuel supply
contracts that are subject to mark-to-market changes. Therefore, the operating
results from our contracted operations may vary from period to period due to
changes in the fair value of the these derivative fuel supply contracts.

Our merchant operations include power plants that serve their customers
during peak periods without dedicated power contracts. The results of our
merchant operations include income related to the generation of power for sale
into the open market. Generally, the merchant power plants operate when the
price of power in a market exceeds the variable costs of generating power. Many
of our merchant operations have contractual obligations, such as transportation
capacity contracts, that represent fixed costs for the plant. Our ability to
recover the fixed operating costs depends on electricity demand and the volume
of power generated as well as the margins that can be realized.

In 2003, our power restructuring business includes the results of managing
our existing restructured power contracts. In 2002, our results include the
impact of the power contract restructurings transactions that

72

we completed in 2002, in addition to the results of managing these contracts. As
a result of our credit downgrade and economic changes in the power market, we
are no longer pursuing additional power contract restructuring activities. On an
ongoing basis, the results of our power restructuring business will primarily
consist of the physical sales and purchases of electricity as well as changes in
fair value of the derivative contracts from period to period, including
accretion of the discounted value as well as changes in commodity prices and
discount rates. Changes in the discount rate used to calculate the fair value of
our derivatives can significantly impact our earnings. See Item 3, Quantitative
and Qualitative Disclosures About Market Risk.

Because of changes in our business strategy, we are pursuing the sale of
our domestic power operations. The future results in our domestic power
operations will be impacted by the timing of the potential sales of our power
assets and the related operating results from those facilities.

Our international operations primarily include contracted plants and
pipelines located primarily in Brazil, Latin America, Asia, Mexico and Europe.
For a description of the political and foreign risks and related contingencies
that affect our international facilities, see Item 1, Note 18.

Results of our global power division were as follows:

In the second quarter of 2003, we acquired the remaining interests in our
Chaparral and Gemstone investments. For a discussion of the acquisition of
Chaparral and Gemstone, see Item 1, Note 3. Upon the acquisitions of these
remaining interests, we consolidated these investments, which had been
previously reported using the equity method of accounting. This change in
accounting for our Chaparral and Gemstone investments created significant
variances in our gross margin, operating expenses and other income (expense)
when comparing the quarter and nine months ended September 30, 2003 to the same
periods in 2002. Additionally, we completed significant power restructurings in
2002, which created significant variances in our gross margin and operating
expenses from 2003 to 2002. Finally, impairments and sales of some of our power
assets and investments in 2002 and 2003 also caused significant variances in our
operating expenses from 2003 to 2002. The following table and discussion
provides an analysis of the performance within our domestic and international
power operations, which is our basis for evaluating the performance of our
global power business. We believe that our evaluation at the EBIT level is an
effective way of managing overall performance due to the differing nature of
each of the power activities described above and because our global operations
include both equity and consolidated investments. The EBIT for our global power
division, segregated between our domestic and international power operations,
was as follows:

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

(1) Other consists of the indirect general and administrative costs
associated with our domestic and international operations, including
legal, finance, and engineering costs. Direct general and administrative
expenses of our domestic and international operations are included in
EBIT of those operations.

73

Third Quarter 2003 Compared to Third Quarter 2002

Our domestic operations, which consist of both contracted and merchant
operations as well as our power restructuring activities, generated EBIT during
the quarter ended September 30, 2003, of $4 million compared to $66 million
during the quarter ended September 30, 2002. The $62 million decrease in
domestic operations EBIT was primarily attributable to a $69 million decrease in
EBIT from our domestic operations other than our Chaparral operations offset by
a $7 million increase in EBIT from Chaparral.

The $69 million decrease in the EBIT of our domestic operations other than
Chaparral included a $22 million charge associated with an expected settlement
involving two turbines included in our inventory, which will eliminate a future
cash obligation of $78 million. Also contributing to the decrease was a $13
million loss on one of our equity investments that experienced a decrease in the
fair value of its derivative fuel supply contracts and $12 million of decreased
equity earnings due to the sale of our investment in CE Generation in early
2003. The remaining decrease relates to our decision not to operate our merchant
plants since electricity demands and margins were lower, making it uneconomical
to run the plants, as well as mechanical difficulties with one of the turbines
at our Eagle Point merchant facility in 2003.

The $7 million increase in EBIT attributable to our Chaparral operations
includes a $92 million increase in EBIT related to our investment in Chaparral
primarily due to our increased ownership and consolidation of Chaparral, offset
by a $46 million decrease in our management fees earned from Chaparral that we
received in 2002 but not in 2003, and $39 million of impairments and losses
related to the sales of some of the Chaparral power assets in 2003. The $39
million of impairments include a $29 million impairment of our East Coast Power
facility generated by its sale completed in October 2003, and a $10 million loss
on the sale of Mohawk River Funding I, one of our power restructuring entities.

For the quarter ended September 30, 2003, EBIT from our international
operations was $30 million higher than the same period in 2002, which was
primarily due to $15 million of interest expense and foreign taxes that was
recorded in EBIT through equity earnings before the consolidation of Gemstone in
2003 but which was excluded from EBIT following the consolidation. We also
benefited from an increase in EBIT of $23 million primarily from two Brazilian
power plants that increased their generating capacity in 2003. These increases
were offset by $6 million of legal fees related to arbitration proceedings on
two of our Asian equity investments in 2003.

For the quarter ended September 30, 2003, our other global power
operations' indirect general and administrative costs decreased by $3 million
compared to the same period in 2002, primarily due to support personnel
reductions resulting from the sales of power plants during 2002 and 2003 and a
reduction of our business development activities as we pursue the sale of our
domestic power operations.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

For the nine months ended September 30, 2003, our domestic operations
generated an EBIT loss of $109 million compared to EBIT earnings of $491 million
for the same period in 2002. The $600 million decrease in EBIT was primarily
attributable to a $188 million decrease in EBIT from Chaparral and a $412
million decrease in EBIT from our domestic operations other than Chaparral.

The $188 million decrease in EBIT attributable to Chaparral includes $246
million of impairments and losses related to the sales of some of the Chaparral
power assets in 2003. Of the $246 million, $207 million of the charges was
attributable to an impairment of our Chaparral investment, $29 million is
associated with the sale of our East Coast Power facility which closed in
October 2003, and $10 million relates to a loss on the sale of Mohawk River
Funding I, one of our power restructuring entities. We also experienced a $139
million decrease in our management fees earned from Chaparral that we received
in 2002 but not in 2003. Offsetting these decreases was a $197 million increase
in earnings related to our investment in Chaparral primarily due to our
increased ownership and consolidation of Chaparral.

We also experienced a net $412 million decrease in the EBIT of our domestic
operations other than Chaparral, which included an $88 million impairment
associated with our Milford power project and a $22 million charge associated
with an expected settlement involving two turbines included in our inventory
74

that will eliminate a future cash obligation of $78 million. Also contributing
to the decrease was $331 million of net gains related to our power
restructurings in 2002 on our Eagle Point Cogeneration and Mount Carmel power
plants, which includes 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 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 markets division reflected in discontinued
operations). For a further description of our 2002 power contract
restructurings, see our Current Report on Form 8-K dated September 23, 2003.
Also contributing to the decrease were lower equity earnings of $16 million due
to the sale of our investment in CE Generation in early 2003. Partially
offsetting these decreases were $63 million of increases in the fair value of
our power restructuring contracts primarily resulting from income accretion for
nine months in 2003 compared to less than nine months in 2002, on contracts
restructured in the first quarter of 2002. The remaining decrease relates
primarily to our decision not to operate our merchant plants since electricity
demands and margins were lower, making it uneconomical to run the plants, as
well as mechanical difficulties with one of the turbines of our Eagle Point
merchant facility in 2003.

For the nine months ended September 30, 2003, our international operations
generated EBIT earnings of $221 million compared to an EBIT loss of $165 million
for the same period in 2002. Our 2002 EBIT loss includes a $342 million
impairment of our Argentina investments and a turbine forfeiture fee of $19
million related to a project that was cancelled offset by a $77 million gain
from the termination of a power purchase agreement at our Nejapa power facility.
The remaining increase in EBIT of $102 million includes a $24 million gain on
the sale of our Argentina investment in 2003, $23 million of interest expense
and foreign taxes that were recorded in EBIT through equity earnings before the
consolidation of Gemstone in 2003, which was excluded from EBIT following the
consolidation of Gemstone, a $61 million increase in EBIT primarily from two
Brazilian power plants that increased their generating capacity in 2003 and a
$12 million reduction in Brazil's direct general and administrative costs due to
personnel reductions resulting from completion of construction activities on our
power plants. These EBIT increases were offset by $12 million of legal fees
related to arbitration proceedings on two of our Asian equity investments in
2003.

Our other global power operations' indirect general and administrative
costs decreased by $21 million compared to the same period in 2002, primarily
due to support personnel reductions resulting from the sales of power plants
during 2002 and 2003 and a reduction of our business development activities as
we pursue the sale of our domestic power operations.

Energy Trading

In November 2002, we announced that we would exit the 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 liquidating
approximately 40,000 transactions in our trading portfolio, of which
approximately 21,000 transactions remained as of September 30, 2003. We
anticipate that we will liquidate approximately 9,000 transactions in the fourth
quarter of 2003 and approximately 5,000 transactions in 2004 under existing
contractual terms, resulting in an anticipated 7,000 transactions remaining as
of December 31, 2004. We define a transaction as all of the settlements required
by a contract within a calendar year (e.g. a contract that extends five years is
counted as five transactions).

Despite our intention to liquidate our trading portfolio by the end of
2004, we may retain certain contracts because (i) they are either uneconomical
to sell or terminate in the current environment due to their contractual terms
or credit concerns of the counterparty, (ii) a sale would require an
acceleration of cash demands, or (iii) they represent hedges associated with
activities reflected in other segments of our business including our Production
segment and our global power division. We have taken different strategies to
liquidate or retain these transactions to achieve the most favorable economic
results for us. Changes to our liquidation strategy may impact the cash flow and
the financial results of the energy trading division.

75

Our trading portfolio is grouped into categories, as described below, that
include contracts with third parties and affiliates that require physical
delivery of a commodity or financial settlement. Each category may include
transactions that are accounted for differently depending on whether they are
derivative or non-derivative contracts. Derivative contracts are recorded on our
balance sheet at their fair value with changes to the fair value recorded in our
income statement. Non-derivative contracts are recorded on an accrual basis,
which means the associated income or expense is recognized when the underlying
commodities or services are delivered or received, and the fair value of the
contracts is not carried on our balance sheet as price risk management
activities.

Our natural gas contracts include long-term obligations to deliver natural
gas to power plants. We currently have seven significant physical natural gas
contracts with power plants. These contracts have various expiration dates
ranging from 2007 to 2028, with obligations under individual contracts ranging
from 30,000 MMBtu/d to 142,000 MMBtu/d. Also included in our natural gas
portfolio are other contracts that we use to manage the risk associated with our
long-term supply obligations. Our natural gas contracts include both derivative
and non-derivative contracts.

Our power contracts include long-term obligations to provide power to our
power contract restructuring affiliates. We currently have four power supply
contracts related to our power contract restructuring business, with the largest
of these being for approximately 1.7 MMWh per year extending through 2016. We
also have other contracts that require the physical delivery of power or are
used to manage the risk associated with our obligations to supply power.
Substantially all of our power contracts are accounted for as derivatives. The
results of our affiliated contracts are eliminated in consolidation.

We have tolling arrangements that provide us with the right to require a
counterparty to convert natural gas into electricity. Under these arrangements,
we supply the natural gas used in the underlying power plants and sell the
electricity produced by the power plant. In exchange for this right, we pay a
monthly fixed fee and a variable fee based on the quantity of electricity
produced. We currently have two unaffiliated physical tolling contracts, both of
which are accounted for as derivatives with the largest of these being in the
Midwest having a contractual expiration date of 2019 and annual capacity charges
of approximately $30 million. Changes in the fair value of these derivatives may
significantly impact our gross margins on a quarterly basis and historically we
have seen high volatility in the relationship between the natural gas and power
prices that impact this contract. We also have other physical and financial
positions that are impacted by changes in the relationship between natural gas
and electricity prices.

We have long-term natural gas transportation contracts that give us the
right to transport natural gas using pipeline capacity for a fixed demand charge
plus variable transportation costs. Our natural gas transportation contracts
have contractual expiration dates through 2028. Through September 30, 2003, we
have sold transportation capacity equal to 2.5 Bcf/d of the 4.4 Bcf/d that
existed at the end of 2002. Of our remaining 1.9 Bcf/d of capacity as of
September 30, 2003, we are retaining 1.5 Bcf/d to meet our gas supply
commitments and we are actively attempting to market 0.4 Bcf/d to third parties.
In the third quarter of 2003, we incurred approximately $41 million of gross
demand charges on transportation contracts and we have utilized approximately 65
percent of the available capacity through delivery to customers or release.
Demand charges for transportation services are recognized on an accrual basis as
they are incurred. Depending on natural gas prices at different locations, we
may be able to recover some of these demand charges through the margin earned on
purchasing and selling natural gas using these transportation services, but we
cannot be assured that we will be able to recover all of these demand charges in
the future. Our ability to utilize our transportation capacity is dependent on
various factors including the difference in natural gas prices at receipt and
delivery locations along the pipeline system and the amount of capital required
to support credit demands from our gas suppliers.

Similar to the transportation contracts described above, we also have
natural gas storage contracts that give us the ability to store natural gas in
various locations. We are actively attempting to release all of our storage
capacity. Through September 30, 2003, we have liquidated storage capacity equal
to 105 Bcf of the 125 Bcf that existed at the end of 2002. We currently control
storage capacity totaling 20 Bcf as of

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September 30, 2003 with contractual terms that currently extend through 2007. We
incurred $4 million of gross storage demand charges during the third quarter of
2003.

We have executed financial contracts, primarily fixed for floating swaps
that effectively hedge 350 Bcf of our Production segment's anticipated natural
gas sales through 2007. These derivatives do not impact the trading division's
operating results since we have offsetting positions with our Production
segment. However, our third party counterparties require us to provide
collateral equal to the fair value of these hedges, effectively prepaying the
anticipated settlement amount. The $442 million of the collateral we have posted
for these positions is included in margin and other deposits on energy trading
activities in our balance sheet and will be returned to us as these transactions
are settled.

As we pursue the liquidation of our portfolio, the value we ultimately
receive in settlement of these derivative contracts may be less than our
estimates of fair value. Additionally, we have non-derivative contracts that are
not recorded on our balance sheet, which, if sold, could result in an
acceleration of the recognition of gains or losses on these contracts.

During 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, in the
fourth quarter of 2002, we implemented new accounting rules (EITF Issue No.
02-3, Issues Related to Accounting for Contracts Involved in Energy Trading and
Risk Management Activities) that impacted the values of our portfolios starting
in the fourth quarter of 2002. Many contracts which were accounted for as
derivative contracts in 2002 are accounted for as non-derivative, accrual-based
contracts in 2003. All of these factors reduce the comparability of our
operating results between periods. Results of our energy trading division were
as follows:

Third Quarter 2003 Compared to Third Quarter 2002

For the quarter ended September 30, 2003, gross margin improved by $127
million compared to the same period in 2002. We incurred a $33 million loss in
gross margin in 2003, which includes a $21 million loss related to settlements
of non-derivative contracts primarily related to our natural gas transportation
demand charges and a $12 million loss resulting from gains or losses on early
settlements of contracts and net changes in the fair value of derivative
positions. For the quarter ended September 30, 2002, we incurred a $160 million
loss in gross margin, which primarily resulted from a decrease in the fair value
on our transportation and storage contracts, which were recorded at fair value
in 2002 and on an accrual basis in 2003. This decrease in fair value in 2002
resulted from a continued decline in volatility, decreased liquidity in the
marketplace and our decision to manage our portfolio to increase cash flow.
These losses were partially offset by an increase of $22 million in the value of
our net trading price risk management assets and receivables resulting from the
improved credit of several of our counterparties in the third quarter of 2002.

Operating expenses for the quarter ended September 30, 2003, were $11
million higher than in the same period in 2002. This increase relates primarily
to $10 million of restructuring costs incurred in 2003 related to the closing of
our London office, which is comprised of a $6 million charge to fund the deficit
of our United Kingdom pension plan upon its termination and a $4 million
provision for the London office's remaining lease obligation through June 2006,
net of a sublease arrangement. Also contributing to this increase was $11
million of accretion expense related to our California settlement obligation
recognized in 2003 and a

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$7 million increase in depreciation expense resulting from a decrease in the
economic life of our fixed assets. These increases were offset by a $8 million
decrease in personnel costs due to the reduction in the number of employees and
$5 million of bad debt expense recorded in the third quarter of 2002 related to
the Enron bankruptcy.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

For the nine months ended September 30, 2003, gross margin decreased by $49
million compared to the same period in 2002. We incurred a $230 million loss in
gross margin in 2003, which includes a $38 million loss on settlement of
non-derivative contracts primarily related to our natural gas transportation
demand charges that we were unable to recover through release or utilization,
$47 million of net losses on early termination of contracts and a $145 million
loss resulting primarily from a decline in the fair value of our natural gas
derivative positions during 2003. This decline 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 portfolio. For the nine months ended September 30,
2002, we incurred a $181 million loss in gross margin, which primarily resulted
from a decrease in the fair value on our derivative transportation and storage
contracts. This decrease in fair value resulted from a continued decline in
volatility, decreased liquidity in the marketplace and our decision to manage
our portfolio to increase cash flow. These losses were partially offset by an
increase of $22 million in the value of our net trading price risk management
assets and receivables resulting from the improved credit of several of our
counterparties in the third quarter of 2002.

Operating expenses for the nine months ended September 30, 2003, were $14
million higher than in the same period in 2002. This increase relates primarily
to a $17 million of expenses incurred in connection with our California
settlement obligation, which includes $36 million of accretion expense
recognized on the obligation, $6 million of legal and other costs related to the
resolution of the California lawsuit, offset by a $25 million reduction in our
accrual of our obligation as a result of the finalization of a definitive
agreement which changed the timing of the estimated payments. Also contributing
to this increase was $10 million of restructuring costs incurred in the third
quarter of 2003 related to closing of our London office, including a $6 million
charge required to fund the deficit of our United Kingdom pension plan upon
termination of the plan and a $4 million provision for the London office's
remaining lease obligation through June 2006, net of a sublease arrangement.
Also contributing to the increase was a $15 million increase in depreciation
expense resulting from the acceleration of the depreciation of assets of the
trading division upon the decision to exit trading thus resulting in a shorter
economic life. These increases were offset by a $20 million decrease in
personnel costs due to the reduction in the number of employees and $5 million
of bad debt expense recorded in the third quarter of 2002 related to the Enron
bankruptcy.

Other

This division includes our LNG business and the results of operations of
our equity investment in a gas processing plant and our investment in several
crude pipelines. Historically, our LNG business included supply agreements,
terminal capacity arrangements, the development of regasification 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 and have incurred charges in 2003 to
reduce our involvement and future exposure under our ship chartering
arrangements. We are currently pursuing the sale of the supply and terminal
capacity arrangements which include derivative and nonderivative contracts. In
November 2003, we entered into an agreement to assign to a third party our Elba
Island LNG contracts and our capacity rights at the Elba Island LNG terminal. We
expect to complete this transaction in December 2003, subject to conditions
precedent and customary approvals.

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Results of our other division were as follows for the periods ended
September 30:

Third Quarter 2003 Compared to Third Quarter 2002

For the quarter ended September 30, 2003, we incurred a $4 million net
decrease in the fair value of our derivative LNG supply contracts. For the
quarter ended September 30, 2002, we had a $25 million increase in the fair
value of our Snohvit derivative LNG contract. This contract was subsequently
sold in the fourth quarter of 2002.

For the quarter of 2003, operating expenses increased by $9 million
compared to the same period in 2002 primarily due to a $10 million impairment of
a crude oil pipeline in 2003 due to a decline in the expected reserves of a
crude oil field from which the pipeline is used to transport crude oil to a
common gathering point.

Other expense for the quarter ended September 30, 2003 was $5 million
higher than the same period in 2002. The increase was primarily due to $4
million of bad debt expense recorded in 2003 related to disputed interest income
on advances we have incurred in connection with our Elba Island terminal
facility that we do not expect will be collected.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

For the nine months ended September 30, 2003, we incurred a gross margin
loss of $8 million attributable to net decreases in the fair value of our
derivative LNG contracts. For the nine months ended September 30, 2002, we
incurred a $58 million gross margin gain, which was primarily the result of a
$59 million gain in 2002 to record the initial fair value of our Snohvit LNG
contract and a $25 million increase in the fair value of that contract through
the end of the third quarter of 2002. The Snohvit contract was sold in the
fourth quarter of 2002. The gains in 2002 from the Snohvit contract were offset
by a $26 million net decrease in the fair value of our other LNG derivative
contracts in 2002.

Operating expenses for the nine months ended September 30, 2003 were $86
million higher than the same period in 2002. The increase was primarily due to
impairments and other charges we incurred in 2003 in connection with our
decision to reduce our involvement in the LNG business, including the
development of onshore and offshore terminaling activity. The onshore business
included the development of various LNG terminals for which we had asset
impairments of $9 million in 2003. The offshore business included the
development of the Energy Bridge technology for which we had $25 million in
asset impairments of a regasification testing facility and $44 million in ship
charter cancellation costs in 2003. Also contributing to the increase was a $10
million impairment of a crude oil pipeline in 2003 due to a decline in the
expected reserves of a crude oil field from which the pipeline is used to
transport crude oil to a common gathering point. Offsetting these increases were
lower general and administrative expenses of $8 million related to our reduced
involvement in our LNG business.

Other expense for the nine months ended September 30, 2003, was $15 million
higher than the same period in 2002. The increase was primarily due to a $10
million charge in 2003 associated with one of our onshore LNG terminals that, we
no longer anticipate utilizing and $5 million lower equity earnings from our
investment in the Javelina gas processing plant in 2003 due to an increase in
feedstock costs as a result of higher natural gas prices.

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FAIR VALUE OF PRICE RISK MANAGEMENT CONTRACTS

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 September 30, 2003. We classify 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, and the effects of these contracts are included in
our trading division and other division's operating results. All other
derivative-related activities, including those related to power restructuring
and hedging activities, are classified as non-trading price risk management
activities, and the financial effects of these contracts are included in our
global power division and Production segment's operations.

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

(1) Exchange-traded positions 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 contracts include derivatives from our power contract
restructuring activities of $1,957 million, and derivatives related to our
natural gas and oil producing activities of $(539) million. Earnings related
to our natural gas and oil producing derivative activities are included in
our Production segment results.

A reconciliation of these trading and non-trading activities for the period
ended September 30, 2003, is as follows:

During the second quarter of 2003, we acquired derivative contracts with a
fair value of approximately $1.2 billion as of the acquisition date, 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 our power restructuring 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 restructuring
contracts. The fair value of contract settlements includes physical

80

or financial settlement terminations due to counterparty bankruptcies and the
sale of derivative contracts through early termination or through the sale of
consolidated subsidiaries that own derivative contracts.

CORPORATE AND OTHER

Corporate and other operations include general and administrative functions
as well as the operations of our telecommunications and other miscellaneous
businesses. For the quarter ended September 30, 2003, operating results were
breakeven, compared to income of $33 million during the same period in 2002.
During 2002, we recognized a $21 million gain on the early extinguishment of
debt and $20 million of income from the favorable resolution of a non-operating
contingent obligation in the third quarter of 2002.

Corporate and other expenses for the nine months ended September 30, 2003,
were $571 million, compared to $50 million during the same period in 2002. In
the second quarter of 2003, we recorded impairment charges of approximately $396
million in our telecommunications business, including a write-down of goodwill
of $163 million. Also, we recognized a $37 million loss on the early retirement
of our $1.2 billion bridge loan in 2003 and a $21 million gain on the early
extinguishment of debt in 2002. In addition, we recorded $73 million of foreign
currency losses in 2003 versus $45 million of foreign currency losses in 2002 on
our Euro-denominated debt, and $20 million of income from the favorable
resolution of non-operating contingent obligations in the third quarter of 2002.
Partially offsetting these increases were lower business restructuring costs in
the Corporate area in 2003 compared to those costs incurred in 2002.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter and nine months ended September
30, 2003, was $131 million and $400 million higher than the same periods in
2002. Below is an analysis of our interest expense for the periods ended
September 30:

Third Quarter 2003 Compared to Third Quarter 2002

Interest expense on long-term debt for the quarter ended September 30,
2003, was $106 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 $6.1 billion from debt issuances and acquisitions and
consolidations of companies with debt, which increased our interest on long-term
debt by approximately $122 million. Of this increase, $48 million related to
issuances of new debt or changes in rates on existing debt, while $74 million
related to debt consolidated or acquired by us. In addition, we experienced $10
million of interest due to the reclassification of $625 million of preferred
securities as long-term financial obligations in the third quarter as a result
of the adoption of a new accounting standard SFAS No. 150. See Note 2 for a
discussion of this accounting change. Also contributing to the increase was $3
million of additional interest related to various debt issuances during 2002
that were outstanding during all of 2003. Partially offsetting these increases
was the retirement of approximately $1.4 billion of long-term debt during 2002
and 2003 with an average effective interest rate of 6.90%, reducing interest
expense by approximately $24 million.

Interest expense on revolving credit facilities for the quarter ended
September 30, 2003, was $33 million higher than the same period in 2002 due to
higher average borrowings under these facilities in December 2002

81

and in 2003. Our average revolving credit balances, which were based on daily
ending balances, were approximately $1.5 billion, with an average interest rate
of 4.64% during 2003.

Interest expense on commercial paper for the quarter ended September 30,
2003, was $3 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 September 30, 2003, was $5 million
lower than the same period in 2002 primarily due to a $3 million decrease in
interest resulting from the retirement of other financing obligations.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Interest expense on long-term debt for the nine months ended September 30,
2003, was $362 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 $7.3 billion (including $1.2 billion of bridge loan that was paid
in May 2003), which increased interest by approximately $301 million. Of this
increase, $109 million related to issuances of new debt or changes in rates on
existing debt, while $192 million related to debt consolidated or acquired by
us. Also contributing to the increase was $125 million of additional interest
related to debt issuances during 2002 that were outstanding during the first
nine months of 2003 and an increase of $10 million due to the reclassification
of $625 million of preferred securities as a result of the adoption of SFAS No.
150. Partially offsetting these increases was the retirement of approximately
$2.0 billion of long-term debt during 2002 and 2003 with an average effective
interest rate of 6.61%, decreasing interest expense by approximately $67
million.

Interest expense on revolving credit facilities for the nine months ended
September 30, 2003, was $81 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 $1.7
billion, with an average interest rate of 3.88% during 2003.

Interest expense on commercial paper for the nine months ended September
30, 2003, was $25 million lower than the same period in 2002 due to the
discontinuation of commercial paper activities in 2003.

Other interest for the nine months ended September 30, 2003, was $24
million lower than the same period in 2002. The decrease was primarily due to a
$12 million reduction in affiliated interest expense on notes we had with
Chaparral and Gemstone which were eliminated as a result of the consolidation of
these investments in the second quarter of 2003, a $12 million decrease
resulting from the retirement of other financing obligations and a $4 million
decrease due to the reduction in our power and trading activities in 2003. These
decreases were partially offset by a $7 million increase as a result of the
write-off of unamortized financing costs due to retirement of the Trinity River
financing arrangement in 2003.

Capitalized interest for the nine months ended September 30, 2003, was $6
million lower than the same period in 2002 primarily due to lower average
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 nine months ended September 30, 2003, were $29 million and $75
million lower than the same periods in 2002 primarily due to the redemptions or
elimination in 2002 and 2003 of a number of our preferred interests in
consolidated subsidiaries, including those 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 and
due to the reclassification of our Capital Trust I and Coastal Finance I
mandatorily redeemable preferred securities to long-term financing obligations
as a result of the adoption of SFAS No. 150. The decreases were also due to
lower interest rates in 2003. 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.

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INCOME TAXES

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

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

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

- foreign income taxed at different rates;

- abandonment of foreign investments;

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

- minority interest preferred dividends.

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

- 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.

During the quarters and nine months ended September 30, 2003 and 2002, we
experienced a number of events that have impacted our overall effective tax rate
on continuing operations. These events included the treatment of our coal and
petroleum markets operations as discontinued operations (in which income taxes
are apportioned between continuing and discontinued operations) and the
abandonment of several foreign investments for tax purposes. These events,
coupled with relatively low pretax income in continuing operations, have caused,
and may continue to cause, variations in our effective tax rate.

For a further discussion of our effective tax rates, see Item 1, Note 10.

DISCONTINUED OPERATIONS

During the nine months ended September 30, 2003, our after-tax loss from
discontinued operations was $1,187 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 markets business, approximately $929 million of which related to the
impairment of our Aruba refinery and approximately $252 million of which related
to the impairment of our Eagle Point refinery.

We also incurred $23 million of net losses on our refinery operations
during the nine months ended September 30, 2003 which included losses from our
Aruba refinery of $73 million and earnings from our Eagle Point refinery of $55
million. The Aruba refinery losses primarily related to lower throughput due to
a significant turnaround maintenance activities during the third quarter of
2003. We expect our Eagle Point refinery's volumes to be lower in the fourth
quarter of 2003 due to scheduled turnaround maintenance activities.

The income tax benefit related to discontinued operations for the nine
months ended September 30, 2003, was $229 million resulting in an effective tax
rate for discontinued operations of 16 percent. This effective rate was
different than the statutory rate of 35 percent primarily due to state income
taxes and foreign income taxed at different rates.

83

In the second quarter of 2003, we entered into a product offtake agreement
with Vitol S.A. Inc., for the sale of a number of the products produced at our
Aruba refinery. As a result of this contract, Vitol 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 Vitol'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.

84

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 Current Report on Form 8-K dated September 23,
2003.

85

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

This information updates, and you should read it in conjunction with,
information disclosed in our Current Report on Form 8-K dated September 23,
2003, in addition to the information presented in Item 1 and 2 of this Quarterly
Report on Form 10-Q.

There are no material changes in our quantitative and qualitative
disclosures about market risks from those reported in our Current Report on Form
8-K dated September 23, 2003, 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 the derivative and non-derivative contracts in
our trading portfolio included in continuing operations and discontinued
operations on a daily basis using a Value-at-Risk model. We measure our
Value-at-Risk using a 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 $7 million and $11 million as of September 30, 2003 and
December 31, 2002, and represents our potential one-day unfavorable impact on
the fair values of our trading contracts. As we liquidate our trading portfolio,
our Value-at-Risk may vary from period to period.

INTEREST RATE RISK

As of September 30, 2003, included in our non-trading derivatives not
designated as hedges (see Item 1, Note 14), we had $1.7 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 credit spread specific to the contract's counterparty.
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. Since September 30,
2002, in order to provide for market risk, we have not reflected the increase in
value that would result from decreases in U.S. Treasury rates because we believe
the resulting increase in the value of these non-trading derivatives could not
be realized in a current transaction between willing parties. Had we reflected
the actual U.S. Treasury yields as of September 30, 2003 in our valuation, the
value of our third party non-trading derivatives would have been higher by
approximately $143 million. To the extent there is commodity price risk
associated with these derivative contracts, it is included in our Value-at-Risk
calculation discussed above, but our exposure to changes in interest rates and
credit spreads has not been included in our Value-at-Risk calculation since
these risks are managed separately from the other derivative positions included
in our Value-at-Risk model. As of September 30, 2003, a ten percent increase or
decrease in the discount rate used to value these positions would result in a
change in the fair value of these derivative contracts of $(58) million and $62
million.

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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.

87

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

None.

ITEM 5. OTHER INFORMATION

None.

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.

b. Reports on Form 8-K

We also furnished information to the SEC on Current Reports on Form 8-K
under Item 9, Regulation FD and Item 12, Results of Operation and Financial
Condition. 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, but
are filed to provide full disclosure under Regulation FD.

90

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: November 12, 2003 /s/ D. Dwight Scott
------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

Date: November 12, 2003 /s/ Jeffrey I. Beason
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

91

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.