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 MARCH 31, 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 May 12,
2003: 599,108,034

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EL PASO CORPORATION

TABLE OF CONTENTS

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

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

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

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

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EL PASO CORPORATION

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

See accompanying notes.

1

EL PASO CORPORATION

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

See accompanying notes.

2

EL PASO CORPORATION

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

See accompanying notes.

3

EL PASO CORPORATION

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

See accompanying notes.

4

EL PASO CORPORATION

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

See accompanying notes.

5

EL PASO CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. BASIS OF PRESENTATION

We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the United States Securities and Exchange Commission. Because
this is an interim period filing presented using a condensed format, it does not
include all of the disclosures required by generally accepted accounting
principles. You should read it along with our 2002 Form 10-K which includes a
summary of our significant accounting policies and other disclosures. The
financial statements as of March 31, 2003, and for the quarters ended March 31,
2003 and 2002, are unaudited. We derived the balance sheet as of December 31,
2002, from the audited balance sheet filed in our 2002 Form 10-K. In our
opinion, we have made all adjustments, all of which are of a normal, recurring
nature (except for the items in Notes 2 through 8), to fairly present our
interim period results. Due to the seasonal nature of our businesses,
information for interim periods may not indicate the results of operations for
the entire year. In addition, prior period information presented in these
financial statements includes reclassifications which were made to conform to
the current period presentation. These reclassifications have no effect on our
previously reported net income or stockholders' equity.

2. SUMMARY OF SIGNIFICANT EVENTS AND ACCOUNTING POLICIES

Liquidity Update

As was discussed more completely in our 2002 Form 10-K, in February 2003,
we announced our 2003 Operational and Financial Plan to address liquidity needs
in our business activities. The objectives of this plan were to:

- Preserve and enhance the value of our core businesses;

- Exit non-core businesses quickly, but prudently;

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

- Aggressively pursue additional cost reductions; and

- Continue to work diligently to resolve litigation and regulatory matters.

So far in 2003, we have accomplished a number of objectives under our plan.
More specifically, we have:

- Completed or announced sales of assets for approximately $2.3 billion
(see Note 3 for a further discussion of these divestitures);

- Completed financing transactions, consisting of loans and debt issuances
totaling $1.9 billion;

- Repaid approximately $2.6 billion of maturing debt and other obligations,
including long-term debt retirements of $294 million, the redemption of
$980 million of obligations under our Trinity River financing
arrangement, the redemption of $297 million of obligations under our
Clydesdale financing arrangement, and the contribution of $1 billion to
Limestone Electron Trust (Limestone), which used the proceeds to repay $1
billion of Limestone's notes (see Notes 12, 13 and 17 for a further
discussion of these actions);

- Entered into a new $3 billion revolving facility that matures in June
2005;

- Purchased the third party equity interest in our Gemstone power
investment for $53 million;

- Restructured the obligations under our Clydesdale financing arrangement
as a term loan that will amortize over the next two years; and

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- Reached an agreement in principle (the Western Energy Settlement) in
March 2003, which was designed to resolve our principal exposure relating
to the western energy crisis while minimizing the impact on our current
liquidity.

In April 2003, we announced the next steps under our plan. These actions
include:

- Targeting additional pre-tax cost savings and business efficiencies of
$250 million, beyond the previously announced savings of $150 million by
the end of 2004;

- Working to recover cash collateral currently committed to our trading,
petroleum, refining and other businesses; and

- Reducing our obligations senior to common stock by at least $2.5 billion
in 2003.

We believe the accomplishments achieved to date demonstrate our ability to
address our liquidity issues and simplify and improve our capital structure.
However, a number of factors could influence the timing and ultimate outcome of
these efforts.

Significant Accounting Policies Update

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

Accounting for Asset Retirement Obligations. On January 1, 2003, we
adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting
for Asset Retirement Obligations. SFAS No. 143 requires that we record a
liability for retirement and removal costs of long-lived assets used in our
business. This liability is recorded at its estimated fair value, with a
corresponding increase to property, plant and equipment. This asset is
depreciated over the remaining useful life of the long-lived asset to which that
liability relates. An ongoing expense is recognized for changes in the value of
the liability as a result of the passage of time, which we 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 $192 million
and non-current 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 the wells. We currently
forecast that these obligations will be met at various times over the next one
hundred years, based on the expected natural gas and oil contained in the wells
and the estimated timing of plugging and abandoning the wells. The net asset
retirement liability as of January 1, 2003 and March 31, 2003, reported in other
non-current liabilities in our balance sheet, and the changes in the net
liability for the quarter ended March 31, 2003, were as follows (in millions):

Liability at January 1, 2003................................ $222
Liability settled in 2003................................... (25)
Accretion expense in 2003................................... 5
Other....................................................... (1)
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Net liability at March 31, 2003........................ $201
====

Had we adopted SFAS No. 143 as of January 1, 2002, our non-current
retirement liabilities would have been approximately $200 million as of January
1, 2002, and our income from continuing operations and net income for the
quarter ended March 31, 2002, would have been lower by $4 million. Basic and
diluted earnings per share for the quarter ended March 31, 2002, would not have
been affected.

Accounting for Costs Associated with Exit or Disposal Activities. On
January 1, 2003, we adopted SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities. SFAS No. 146 requires that we recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. We recognized $31 million of
employee severance costs, less income taxes

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of $8 million, in the first quarter of 2003, of which $21 million had been paid
as of March 31, 2003. We also recognized charges of approximately $44 million,
less income taxes of $12 million, associated with our liquefied natural gas
(LNG) business following our announced plan to minimize our involvement in that
business in February 2003. The costs recorded 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 these costs as operation and maintenance
expenses in our income statement and impacted the results in our Merchant
Energy, Production and Corporate business segments. 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.

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 their fair value when they are issued. There was no
initial financial statement impact of adopting this standard.

Stock-Based Compensation. We account for our stock-based compensation
plans using the provisions of Accounting Principles Board Opinion No. 25 (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 the provisions of APB
No. 25, the income and per share impacts of stock-based compensation on our
financial statements would have been different. The following shows the impact
on net income (loss) and earnings per share had we applied the provisions of
SFAS No. 123:

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3. DIVESTITURES

During 2003, we completed or announced the sale of a number of assets as
part of our 2003 Operational and Financial Plan. These sales transactions
occurred in each of our business segments as follows:

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(1) Amounts do not include asset impairments recognized, if any, at the time we
decide to sell the asset. See Notes 6 and 17 for a discussion of impairments
taken on long-lived asset and investment divestitures.

(2) We did not recognize gains or losses on these completed sales of natural gas
and oil properties because individually they did not significantly alter the
relationship between capitalized costs and proved reserves at the time they
were sold.

(3) Sales that have been announced, but not completed, are subject to customary
regulatory approvals, final sale negotiations and other conditions and are
estimates.

(4) We have entered into a non-binding letter of intent to sell these assets for
estimated net proceeds of $250 million. In the first quarter of 2003, we
recognized an impairment of $350 million on our Eagle Point refinery. See
Note 6 for a discussion of this impairment.

(5) East Coast Power is part of our Chaparral investment. See Note 17 for a
further discussion of Chaparral. Also, see Note 14 for a discussion of
regulatory matters that could impact this transaction.

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

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

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

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

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

To the extent that all of these criteria as well as the other requirements
of SFAS No. 144 are met, we classify an asset as held for sale or, if
appropriate, discontinued operations. For example, our Board of Directors or a
designated subcommittee of the Board of Directors is required to approve asset
dispositions greater than specified thresholds. Unless specific approval is
received by our Board of Directors or their designated subcommittee by the end
of the period to commit to a plan to sell an asset, we would not classify it as
held for sale or discontinued operations even if it is management's stated
intent to sell the asset. In our balance sheet we classified several long-lived
assets as held for sale, including (1) Field Services' midstream assets in the
north Louisiana region and several of its gathering systems and three processing
plants located in Wyoming and (2) Merchant Energy's petroleum asphalt operations
and lease crude business and its Florida petroleum terminals and tug and barge
operations. The total assets held for sale had net book values in property,
plant and equipment of approximately $109 million as of March 31, 2003 and $134
million as of December 31, 2002. These assets were classified as other current
assets as of March 31, 2003 and December 31, 2002, since we plan to sell them in
the next twelve months.

We continue to evaluate assets we may sell in the future. Recently, we
announced that we intend to pursue a sale of our Aruba refinery, our
telecommunications business and domestic power assets. These activities are in
the early stages and no definitive agreements have been received or approved by
our management or Board of Directors. Furthermore, we are not certain what form
these possible divestitures may take (e.g. outright sale or joint venture
arrangement). We believe it is likely that a decision to sell these assets in
the current economic environment will result in future impairments or losses.
The amounts of the losses will be based on an estimate of the expected fair
value of the assets as determined by market data that becomes available to us as
we proceed with the sales process. As of March 31, 2003, our net investment in
the Aruba refinery was approximately $1.2 billion (excluding the Aruba coker
facility which will have a carrying value, following its consolidation in the
second quarter of 2003, of $0.4 billion), and our net investment in our
telecommunications business was $0.4 billion (excluding the Lakeside Technology
Center which will have a carrying value, following its consolidation and
impairment in the second quarter of 2003, of approximately $0.2 billion). See
Note 17 for a discussion of our domestic power business which is primarily
conducted through our investment in Chaparral and Note 12 for a discussion of
our consolidation of Lakeside and the Aruba coker facility.

In March 2002, we sold natural gas and oil properties located in east and
south Texas. Net proceeds from these sales were approximately $500 million. We
did not recognize a gain or loss on these sales because individually at the time
these properties were sold these sales did not significantly alter the
relationship between capitalized costs and proved reserves.

4. WESTERN ENERGY SETTLEMENT

On March 20, 2003, we entered into an agreement in principle 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
(referred to as the Western Energy Settlement). As discussed in our 2002 Form
10-K, the settlement will include payments of cash, the issuance of common stock
and the delivery of natural gas over a period of 20 years.

10

The obligation for the settlement was reflected in our balance sheet at
$899 million as of December 31, 2002, which represented the overall amount of
the settlement of approximately $1,690 million, less a discount (based on a
discount rate of 10 percent) of approximately $791 million. During the first
quarter of 2003, we recorded $17 million of amortization expense on the discount
associated with the settlement obligation, which increased our total obligation
to $916 million as of March 31, 2003. This amortization was reflected in our
operation and maintenance expense in our income statement.

The calculation of our total settlement obligation required us to use
estimates and assumptions based on currently available information. These
estimates included the discount rate, the timing of final settlement and the
timing of payments made to satisfy obligations. As a result, our estimates and
assumptions may change.

5. 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 ended March 31, 2002, we recorded ceiling test charges of
$33 million, including $10 million for our Brazilian full cost pool and $23
million for other international production operations, primarily in Turkey,
based upon the daily posted natural gas and oil prices as of March 31, 2002,
adjusted for oilfield or natural gas gathering hub and wellhead price
differences, as appropriate.

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

6. 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.
During each of the quarters ended March 31, our gain (loss) on long-lived assets
was as follows:

Net Realized Gain

Our net realized gain on sales of long-lived assets for the quarters ended
March 31, 2003 and 2002, was $50 million and $15 million. Our 2003 gains were
primarily related to the sales of the Corpus Christi refinery and the Florida
petroleum terminals and tug and barge operations in our Merchant Energy segment.
Partially offsetting the 2003 gains was a loss on the sale of aircraft in our
Corporate and Other segment. See Note 3 for a further discussion of these
divestitures. Our 2002 gains were primarily related to the sale of pipeline
expansion rights in our Pipelines segment and the sale of non-full cost pool
assets in our Production segment.

Asset Impairments

We are required to test assets for recoverability whenever events or
changes in circumstances indicate that the carrying amount of these assets may
not be recoverable. One triggering event that may indicate an asset's carrying
amount may not be recoverable is the expectation that it is more likely than not
that we will sell or dispose of an asset before the end of its estimated useful
life. Based on our intentions as of

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March 31, 2003, that we will dispose of some of our assets, we tested those
assets for recoverability during the first quarter of 2003 that we believed
would more likely than not be sold. As a result of this assessment, we
recognized an impairment of $350 million on our Eagle Point refinery and several
of our chemical assets in our Merchant Energy segment. We also recorded
impairment charges of approximately $18 million in the first quarter of 2003, $9
million of which related to the impairment of our LNG assets in the Merchant
Energy segment due to our plan to reduce our involvement in this business and $9
million which related to non-full cost assets in Canada in our Production
segment.

7. OTHER EXPENSES

Included in other expenses for the quarter ended March 31, 2003, was an $86
million loss on the impairment of notes receivable from our Milford equity
investment and accruals on contracts related to that investment. See Note 14 for
a further discussion of conditions that led to this impairment. Also included in
other expenses in 2003 was a $33 million foreign currency loss resulting from
the impact of foreign currency fluctuations on our Euro-denominated debt. During
the quarter ended March 31, 2002, other expenses included a $56 million
impairment of investment in our Costanera power plant, a cost-based investment
in Argentina.

8. DISCONTINUED OPERATIONS

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.

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Our coal mining operations have been classified in other current assets and
liabilities as discontinued operations in our financial statements for all
periods. The summarized financial results of discontinued operations were as
follows:

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9. EARNINGS PER SHARE

We calculated basic and diluted earnings per common share amounts as
follows for the quarters ended March 31:

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(1) Due to their antidilutive effect on earnings per common share, for 2003, we
excluded a total of 16 million shares for all potentially dilutive
securities, and for 2002, we excluded a total of 8 million shares for the
assumed conversion of convertible debentures.

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10. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

The following table summarizes the carrying value of our trading and
non-trading price risk management assets and liabilities as of March 31, 2003
and December 31, 2002:

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

(2) 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.

Other derivatives include derivative contracts related to the power
restructuring activities of our consolidated subsidiaries of $967 million as of
March 31, 2003 and $968 million as of December 31, 2002. Of this amount, $882
million and $878 million relate to a power restructuring transaction at our
Eagle Point Cogeneration facility as of March 31, 2003 and December 31, 2002,
and $85 million and $90 million relate to a power restructuring transaction at
our Capitol District Energy Center Cogeneration Associates plant as of March 31,
2003 and December 31, 2002. The remaining balances in other derivatives,
unrealized losses of $12 million and $9 million as of March 31, 2003 and
December 31, 2002, relate to derivative positions that no longer qualify as cash
flow hedges under SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, because they were designated as hedges of anticipated future
production on natural gas and oil properties that were sold during 2002.

11. INVENTORY

Our inventory consisted of the following:

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

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12. DEBT AND OTHER CREDIT FACILITIES

Short-Term Debt and Credit Facilities

At March 31, 2003, our weighted average interest rate on our short-term
credit facilities was 2.61%, and at December 31, 2002, it 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 in June 2005. This
facility replaces our previous $3 billion revolving credit facility. Our
existing $1 billion revolving credit facility, which matures in August 2003, and
approximately $1 billion of other financing arrangements (including leases,
letters of credit and other facilities) were also amended to conform our
obligations to the new $3 billion revolving credit facility. Our $3 billion
revolving credit facility, $1 billion revolving credit facility, and the other
financing arrangements are secured by our equity in El Paso Natural Gas Company
(EPNG), Tennessee Gas Pipeline Company (TGP), ANR Pipeline Company (ANR),
Wyoming Interstate Company, ANR Storage Company, and our common and Series C
units in El Paso Energy Partners, L.P. These credit facilities 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 Note 13.

EPNG and TGP remain jointly and severally liable for any amounts
outstanding under the new $3 billion revolving credit facility through August
19, 2003. Also, EPNG and TGP remain jointly and severally liable under our $1
billion revolving credit facility and as such are liable for any amounts under
the facility until its maturity in August 2003. In addition, El Paso CGP Company
is no longer a borrower under the $1 billion credit facility.

The revolving credit facilities have a borrowing cost of LIBOR plus 350
basis points and letter of credit fees of 350 basis points. As of March 31,
2003, we had $1.5 billion outstanding under the $3 billion revolving credit
facility and $500 million outstanding under the $1 billion revolving credit
facility. We have also issued $456 million letters of credit under the $1
billion revolving credit facility.

The availability of borrowings under our credit and borrowing agreements is
subject to specified 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.

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Long-Term Debt Obligations

During the first quarter of 2003, we completed several debt financing
transactions related to our long-term debt obligations:

13. PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Trinity River. In the first quarter of 2003, we redeemed the entire $980
million of Trinity River (also known as Red River) preferred interests.

Clydesdale. During the first quarter of 2003, we retired approximately
$189 million of the third-party member interests in Clydesdale (also known as
Mustang) and an additional $8 million in April 2003. Also, in April 2003, we
restructured the Clydesdale financing arrangement, and guaranteed the third
party equity, which will result in the consolidation of the holder of the
preferred member interests in the second quarter of 2003. Consequently, we
expect to reflect the debt and equity of the holder of the preferred member
interests as debt in our balance sheet and the preferred member interests will
be eliminated. The amount of the obligation at March 31, 2003, was $761 million.
In addition, this obligation was refinanced in April 2003 as a term loan that
will amortize in equal quarterly amounts over the next two years. The term loan
remains collateralized by the assets currently supporting 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 repaid $100
million of this term loan in May 2003.

14. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Western Energy Settlement. On March 20, 2003, we entered into an agreement
in principle (the Western Energy Settlement) with various public and private
claimants, including the states of California, Washington, Oregon, and Nevada,
to resolve the principal litigation, claims, and regulatory proceedings, which
are more fully described below, against us and our subsidiaries relating to the
sale or delivery of natural gas and electricity from September 1996 to the date
of the Western Energy Settlement. The Western Energy Settlement resulted in an
after-tax charge of approximately $650 million in the fourth quarter of 2002.
Among other things, the components of the settlement include:

- a cash payment of $100 million;

- a $2 million cash payment from our officer bonus pool;

- the issuance of approximately 26.4 million shares of El Paso common
stock;

- delivery to the California border of $45 million worth of natural gas
annually for 20 years beginning in 2004;

- a reduction of the pricing of our long-term power supply contracts with
the California Department of Water Resources of $125 million over the
remaining term of those contracts, which run through the end of 2005;

- payments of $22 million per year for 20 years;

- for a period of five years, EPNG will make available at its California
delivery points 3,290 MMcf per day of capacity on a primary delivery
point basis;

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- for a period of five years, our affiliates will be subject to
restrictions in subscribing for new capacity on the EPNG system; and

- no admission of wrongdoing.

The agreement in principle is subject to the negotiation of a formal settlement
agreement, portions of which will then be filed with the courts and the FERC for
approval. Upon approval, the parties will release us from covered claims that
they may have against us and our subsidiaries for the period covered by the
Western Energy Settlement, and the litigation, claims, and regulatory
proceedings against us and our subsidiaries will be dismissed with prejudice.

California Lawsuits. We and several of our subsidiaries have been named as
defendants in fifteen purported class action, municipal or individual lawsuits,
filed in California state courts. These suits contend that our entities acted
improperly to limit the construction of new pipeline capacity to California
and/or to manipulate the price of natural gas sold into the California
marketplace. Specifically, the plaintiffs argue that our conduct violates
California's antitrust statute (Cartwright Act), constitutes unfair and unlawful
business practices prohibited by California statutes, and amounts to a violation
of California's common law restrictions against monopolization. In general, the
plaintiffs are seeking (i) declaratory and injunctive relief regarding allegedly
anticompetitive actions, (ii) restitution, including treble damages, (iii)
disgorgement of profits, (iv) prejudgment and post-judgment interest, (v) costs
of prosecuting the actions and (vi) attorney's fees. All fifteen cases have been
consolidated before a single judge, under two omnibus complaints, one of which
has been set for trial in September 2003. All of the class action and municipal
lawsuits and all but one of the individual lawsuits will be resolved upon
finalization and approval of the Western Energy Settlement. As to the remaining
individual lawsuit, on May 8, 2003, a settlement agreement between the
plaintiffs and defendants in that case became effective and resolved all
disputes between the parties in return for a single payment by us. Pursuant to
the settlement, the plaintiff's action will be dismissed with prejudice.

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

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

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

In January 2003, a lawsuit titled IMC Chemicals v. EPME, et al. was filed
in California state court against us, EPNG and EPME. The suit arises out of a
gas supply contract between IMC Chemicals (IMCC) and EPME and seeks to void the
Gas Purchase Agreement between IMCC and EPME for gas purchases until December
2003. IMCC contends that EPME and its affiliates manipulated market prices for
natural gas and, as part of that manipulation, induced IMCC to enter into the
contract. In furtherance of its attempt to void the contract, IMCC repeats the
allegations and claims of the California lawsuits described above. EPME intends
to enforce the terms of the contract and counterclaim for contract damages. This
case was removed to Federal Court. A hearing was held on April 21, 2003 on the
respective motions of the El Paso

19

defendants to dismiss, as well as IMCC's motions to remand. A decision is
pending. Our costs and legal exposure related to this lawsuit are not currently
determinable.

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

In December 2002, two class action complaints were filed, one in the state
court of Oregon and the other in the federal court in the State of Washington,
naming El Paso and more than forty other unrelated industry entities. In each
case, the complaint makes general allegations that purchasers of natural gas
and/or electricity, within the respective state, were overcharged during the
period 2000 through 2002 by the defendants, who allegedly withheld supplies of
energy, exercised improper control of the energy market and manipulated prices.
These lawsuits have since been voluntarily dismissed.

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

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

In April 2003, Sierra Pacific Resources and its subsidiary, Nevada Power
Company filed a lawsuit titled Sierra Pacific Resources et al. v. El Paso
Corporation et. al., against us, EPNG, EPTP, EPME and four other non-El Paso
defendants. The lawsuit alleges that the defendants conspired to manipulate
supplies and prices of natural gas in the California-Arizona border market from
1996 through 2001. The allegations are similar to those raised in the several
cases that are the subject of the 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) a violation of the Nevada
Unfair Trade Practices Act; (2) fraud; (3) both a conspiracy to violate and a
violation of Nevada's RICO Act; and (4) a civil conspiracy. The complaint seeks
$150 million in actual damages from all the defendants, plus an additional $450
million in trebled damages. The El Paso defendants were served with the
complaint on May 5, 2003.

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

Shareholder Class Action Suits. Beginning in July 2002, twelve purported
shareholder class action suits alleging violations of federal securities laws
have been filed against us and several of our officers. Eleven of these suits
are now consolidated in federal court in Houston before a single judge. The
suits generally challenge the accuracy or completeness of press releases and
other public statements made during 2001 and 2002. The twelfth shareholder class
action lawsuit was filed in federal court in New York City in October 2002
challenging the accuracy or completeness of our February 27, 2002 prospectus for
an equity offering that was completed on June 21, 2002. It has since been
dismissed, in light of similar claims being asserted in the

20

consolidated suits in Houston. Four shareholder derivative actions have also
been filed. One shareholder derivative lawsuit was filed in federal court in
Houston in August 2002. This derivative action generally alleges the same claims
as those made in the shareholder class action, has been consolidated with the
shareholder class actions pending in Houston and has been stayed. A second
shareholder derivative lawsuit was filed in Delaware State Court in October 2002
and generally alleges the same claims as those made in the consolidated
shareholder class action lawsuit. A third shareholder derivative suit was filed
in state court in Houston in March 2002, and a fourth shareholder derivative
suit was filed in state court in Houston in November 2002. The third and fourth
shareholder derivative suits both generally allege that manipulation of
California gas supply and gas prices exposed El Paso to claims of antitrust
conspiracy, FERC penalties and erosion of share value. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

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

Carlsbad. In August 2000, a main transmission line owned and operated by
EPNG ruptured at the crossing of the Pecos River near Carlsbad, New Mexico.
Twelve individuals at the site were fatally injured. On June 20, 2001, the U.S.
Department of Transportation's Office of Pipeline Safety issued a Notice of
Probable Violation and Proposed Civil Penalty to EPNG. The Notice alleged five
violations of DOT regulations, proposed fines totaling $2.5 million and proposed
corrective actions. EPNG has fully accrued for these fines. The alleged five
probable violations of the regulations of the Department of Transportation's
Office of Pipeline Safety are: (1) failure to develop an adequate internal
corrosion control program, with an associated proposed fine of $500,000; (2)
failure to investigate and minimize internal corrosion, with an associated
proposed fine of $1,000,000; (3) failure to conduct continuing surveillance on
its pipelines and consider, and respond appropriately to, unusual operating and
maintenance conditions, with an associated proposed fine of $500,000; (4)
failure to follow company procedures relating to investigating pipeline failures
and thereby to minimize the chance of recurrence, with an associated proposed
fine of $500,000; and (5) failure to maintain elevation profile drawings, with
an associated proposed fine of $25,000. In October 2001, EPNG filed a response
with the Office of Pipeline Safety disputing each of the alleged violations.

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

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

A number of personal injury and wrongful death lawsuits were filed against
EPNG in connection with the rupture. All but one of these suits have been
settled, with settlement payments fully covered by insurance. The remaining case
is Geneva Smith, et al. vs. EPEC and EPNG filed October 23, 2000 in Harris
County, Texas. Trial is set to begin on August 11, 2003. In connection with the
settlement of the cases, EPNG contributed $10 million to a charitable foundation
as a memorial to the families involved. The contribution was not covered by
insurance.

Parties to four settled lawsuits have since filed an additional lawsuit
titled Diane Heady et al. v. EPEC and EPNG in Harris County, Texas on November
20, 2002, seeking an additional $85 million based upon their interpretation of
earlier settlement agreements. Parties to another of the settled lawsuits have
filed a lawsuit titled In the Matter of the Appointment of Jennifer Smith in
Eddy County New Mexico on May 7, 2003,

21

seeking an additional $86 million based upon their interpretation of earlier
agreements. In addition, plaintiffs' counsel for the settled New Mexico state
court cases have notified EPNG that they intend to file suit on behalf of about
twenty-three firemen and EMS personnel who responded to the fire and who
allegedly have suffered psychological trauma. We have not been served with such
a lawsuit. Our costs and legal exposure related to these lawsuits and claims are
not currently determinable. However, we believe these matters will be fully
covered by insurance.

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

Will Price (formerly Quinque). A number of our subsidiaries were named as
defendants in Quinque Operating Company, et al. v. Gas Pipelines and Their
Predecessors, et al., filed in 1999 in the District Court of Stevens County,
Kansas. Quinque has been dropped as a plaintiff and Will Price has been added.
This class action complaint alleges that the defendants mismeasured natural gas
volumes and heating content of natural gas on non-federal and non-Native
American lands. The plaintiff in this case seeks certification of a nationwide
class of natural gas working interest owners and natural gas royalty owners to
recover royalties that the plaintiff contends these owners should have received
had the volume and heating value of natural gas produced from their properties
been differently measured, analyzed, calculated and reported, together with
prejudgment and postjudgment interest, punitive damages, treble damages,
attorney's fees, costs and expenses, and future injunctive relief to require the
defendants to adopt allegedly appropriate gas measurement practices. No monetary
relief has been specified in this case. Plaintiffs' motion for class
certification was denied on April 10, 2003. Our costs and legal exposure related
to this lawsuit are not currently determinable.

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

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

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of March 31, 2003, we had approximately $1,033 million accrued for all
outstanding legal matters.

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 March 31,
2003, we had accrued approximately $471 million, including approximately $452
million for expected remediation costs

22

at current and former operated sites and associated onsite, offsite and
groundwater technical studies, and approximately $19 million for related
environmental legal costs, which we anticipate incurring through 2027.

The high end of our reserve estimates was approximately $674 million and
the low end was approximately $470 million, and our accrual at March 31, 2003,
was based on the estimated likely reasonable amount of liability. 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 March 31, 2003 (in
millions):

In addition, we expect to make capital expenditures for environmental
matters of approximately $294 million in the aggregate for the years 2003
through 2008. These expenditures primarily relate to compliance with clean air
regulations. For 2003, we estimate that our total remediation expenditures will
be approximately $41 million, of which $1 million we estimate will be for
capital related expenditures. In addition, approximately $33 million of this
amount will be expended under government directed clean-up plans. The remaining
$7 million will be self-directed or in connection with facility closures.

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, at
compressor stations and other facilities it operates. While conducting this
project, TGP has been in frequent contact with federal and state regulatory
agencies, both through informal negotiation and formal entry of consent orders.
TGP executed a consent order in 1994 with the EPA, governing the remediation of
the relevant compressor stations and is working with the EPA and the relevant
states regarding those remediation activities. TGP is also working with the
Pennsylvania and New York environmental agencies regarding remediation and
post-remediation activities at the Pennsylvania and New York stations.

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 costs under the PCB remediation project, with these
surcharges to be collected over a defined collection period. TGP has twice
received approval from the FERC to extend the collection period, which is now
currently set to expire in June 2004. The agreement also provided for bi-annual
audits of eligible costs. As of March 31, 2003, TGP has

23

pre-collected PCB costs by approximately $116 million. The pre-collection will
be reduced by future eligible costs incurred for the remainder of the
remediation project. TGP is required, to the extent actual expenditures are less
than the amounts pre-collected, to refund to its customers the unused
pre-collection amount, plus carrying charges incurred up to the date of the
refunds. As of March 31, 2003, TGP has recorded a regulatory liability (included
in other non-current liabilities on our balance sheet) for future refund
obligations of approximately $57 million.

Coastal Eagle Point. From May 1999 to March 2001, our Coastal Eagle Point
Oil Company received several Administrative Orders and Notices of Civil
Administrative Penalty Assessment from the New Jersey Department of
Environmental Protection (DEP). All of the assessments are related to alleged
noncompliance with the New Jersey Air Pollution Control Act pertaining to excess
emissions from the first quarter 1998 through the fourth quarter 2000 reported
by our Eagle Point refinery in Westville, New Jersey. The DEP has assessed
penalties totaling approximately $1.3 million for these alleged violations. The
DEP has indicated a willingness to accept a reduced penalty and a supplemental
environmental project. Our Eagle Point refinery has been granted an
administrative hearing on issues raised by the assessments. On February 24,
2003, EPA Region 2 issued a Compliance Order based on a 1999 EPA inspection of
the refinery's leak detection and repair (LDAR) program. Alleged violations
include failure to monitor all components, and failure to timely repair leaking
components. During an August 2000 follow-up inspection, the EPA confirmed our
Eagle Point refinery had improved its implementation of the program. The
Compliance Order requires documentation of compliance with the program. The
Company met with the EPA and DEP in March 2003 to discuss the Order and the
possibility for a global settlement pursuant to the EPA's refinery enforcement
initiative. Global settlements involving other refiners have included civil
penalties and addressed LDAR as well as new source review, the benzene standard,
and the standard for combustion of refinery fuel gas. On April 25, 2003, our
Eagle Point refinery sent a letter to the EPA committing to global settlement
discussions. Our Eagle Point refinery expects to resolve both the DEP
assessments and the EPA refinery initiative issues.

CERCLA Matters. We have received notice that we could be designated, or
have been asked for information to determine whether we could be designated, as
a Potentially Responsible Party (PRP) with respect to 60 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 March 31, 2003, we
have estimated our share of the remediation costs at these sites to be between
$29 million and $41 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
determining our estimated liabilities.

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 (a list of the complaints is included below for which
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). These customers entered into
contracts with EPME and other

24

wholesale power suppliers for the purchase of power to be delivered in the
future. 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). EPME and other respondents believe the allegations in the complaint are
without merit and have asked the FERC to dismiss these complaints although no
assurances of the outcome can be given. In the NPSP matter, the ALJ issued an
initial decision concluding that the contracts at issue should not be modified,
and the complaints should be dismissed. On April 23, 2003, the FERC held oral
argument on the exceptions to the ALJ's initial decision noted by NPSP and the
other complainants. 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.
Oral argument was held on May 15, 2003 on the merits of this complaint and the
CPUC/CEOB's exceptions to the ALJ's initial decision concluding the public
interest standard of review applied to the complaint. The CPUC/CEOB matter will
be fully resolved upon finalization and approval of the Western Energy
Settlement. 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 decisions of the ALJs for
these matters will be submitted to the FERC for its review. On March 11, 2003,
the City of Burbank matter was set for hearing, but then that hearing was held
in abeyance pending FERC-directed settlement talks before a specially appointed
ALJ.

CPUC Complaint Proceeding. In April 2000, the Public Utilities Commission
of the State of California (CPUC) filed a complaint under Section 5 of the
Natural Gas Act (NGA) with the FERC alleging that the sale of approximately 1.2
billion cubic feet per day 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. Although
the FERC held that EPNG did not violate its marketing affiliate requirements, it
established a hearing before an ALJ to address the market power issue. In the
spring and summer of 2001, two hearings were held before the ALJ to address the
market power issue and, at the request of the ALJ, 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 and that accordingly the market power claims should be dismissed.
The ALJ found, however, that EPNG had violated FERC's marketing affiliate rule.
EPNG and other parties filed briefs on exceptions and briefs opposing exceptions
to the October initial decision.

Also in October 2001, the FERC's Office of Market Oversight and Enforcement
filed comments stating that the record at the hearings was inadequate to
conclude that EPNG had complied with FERC regulations in the transportation of
gas to California. In December 2001, the FERC remanded the proceeding to the ALJ
for a supplemental hearing on the availability of capacity at EPNG's California
delivery points. On September 23, 2002, the ALJ issued his initial decision,
again finding that there was no evidence that EPME had exercised market power
during the period at issue to drive up California gas prices and therefore
recommending that the complaint against EPME be dismissed. However, the ALJ
found that EPNG had withheld at least 345 MMcf/d of capacity (and perhaps as
much as 696 MMcf/d) from the California market during the period from November
1, 2000 through March 31, 2001. The ALJ found that this alleged withholding
violated EPNG's certificate obligations and was an exercise of market power that
increased the gas price to California markets. He recommended that the FERC
initiate penalty procedures against EPNG. EPNG and others filed briefs on
exceptions to the initial decision on October 23, 2002; briefs opposing
exceptions were filed on November 12, 2002. This proceeding will be resolved
upon finalization and approval of the Western Energy Settlement.

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

25

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

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

On April 14, 2003, the FERC issued an order granting a motion by the FR
shippers for deferral of the May 1 implementation date pending FERC review of
the Western Energy Settlement. The order reset the implementation date to
September 1, 2003. Beginning on that date and subject to the substantive
requirements of the September 20, 2002 order, EPNG will be required to pay
reservation charge credits when it is unable to schedule confirmed volumes
except in cases of force majeure. Until September 1, 2003, it is required to pay
partial reservation charge credits to CD customers when it is unable to schedule
95 percent of their monthly confirmed volumes except for reasons of force
majeure and provided that there is no capacity available from other supply
basins on its system.

Several pleadings have been filed in response to the September 20 order,
including rehearing requests and requests by several customers to modify the
order based on the ALJ's decision in the CPUC Complaint Proceeding discussed
above. All such pleadings remain pending before the FERC.

On October 7, 2002, EPNG filed tariff sheets in compliance with the
September 20 order to implement a partial demand charge credit for the period
November 1, 2002 to May 6, 2003, and to allow California delivery points to be
used as secondary receipt points to the extent of its backhaul displacement
capabilities. EPNG proposed both a reservation and a usage charge for this
service. On December 26, 2002, the FERC issued an order (i) denying EPNG's
request to charge existing CD customers a reservation rate for California
receipt service for the remaining term of the settlement, i.e., through December
31, 2005; (ii) allowing EPNG to charge its maximum IT rate for the service;
(iii) approving EPNG's proposed usage rate for the service until its next rate
case; and (iv) requiring it to make a showing that capacity is available for any
new shippers utilizing this service. EPNG made a revised tariff filing on
January 10, 2003, in compliance with the December 26 order. On January 27, 2003,
EPNG filed a request for rehearing on certain aspects of the December 26 order.
That request is pending.

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

26

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 March 31, 2003, EPNG had unearned risk sharing
revenues of approximately $24 million and had $10 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 $10 million. Both the risk and
revenue sharing provisions of the rate settlement extend through 2003.

Line 2000 Project. On July 31, 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. On May
7, 2001, the FERC authorized the amended Line 2000 project. EPNG placed the line
in service in November 2002 at an approximate capital cost of $185 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.

On October 3, 2002, pursuant to the FERC's May 31 and September 20 orders
in the systemwide capacity allocation proceeding, EPNG filed with the FERC for a
certificate of public convenience and necessity to add compression to its Line
2000 project to increase the capacity of that line by an additional 320 MMcf/d
at an estimated capital cost of approximately $173 million for all phases. That
application has been protested, and remains pending. In EPNG's request for
clarification of the September 20 order, EPNG asked for assurances from the FERC
that it will be able to begin cost recovery for this project at the time its
next rate case becomes effective. That request remains pending.

Marketing Affiliate NOPR. In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct
governing the relationship between interstate pipelines and marketing affiliates
to all energy affiliates. The proposed regulations, if adopted by the FERC,
would dictate how all our energy affiliates conduct business and interact with
our interstate pipelines. In December 2001, we filed comments with the FERC
addressing our concerns with the proposed rules. A public hearing was held on
May 21, 2002, providing an opportunity to comment further on the NOPR. Following
the conference, additional comments were filed by our pipeline subsidiaries and
others. 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 NOI. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that seeks comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. Several of our pipelines have entered
into these 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. On September
25, 2002, our pipelines and others filed comments. Reply comments were filed on
October 25, 2002. At this time, we cannot predict the outcome of this NOI.

Cash Management NOPR. On August 1, 2002, the FERC issued a NOPR requiring
that all cash management or money pool arrangements between a FERC regulated
subsidiary and a non-FERC regulated parent must be in writing, and set forth the
duties and responsibilities of cash management participants and administrators;
the methods of calculating interest and for allocating interest income and
expenses; and the restrictions on deposits or borrowings by money pool members.
The NOPR also requires specified documentation for all deposits into, borrowings
from, interest income from, and interest expenses related to, these
arrangements. Finally, the NOPR proposed that as a condition of participating in
a cash management or money pool arrangement, the FERC regulated entity maintain
a minimum proprietary capital balance of 30 percent, and the FERC regulated
entity and its parent maintain investment grade credit ratings. On August 28,
2002, comments were filed. The FERC held a public conference on September 25,
2002, to discuss the issues raised in the comments. Representatives of companies
from the gas and electric industries

27

participated on a panel and uniformly agreed that the proposed regulations
should be revised substantially and that the proposed capital balance and
investment grade credit rating requirements would be excessive. At this time, we
cannot predict the outcome of this NOPR.

Also on August 1, 2002, the FERC's Chief Accountant issued an Accounting
Release which was effective immediately. The Accounting Release provides
guidance on how companies should account for money pool arrangements and the
types of documentation that should be maintained for these arrangements.
However, it did not address the proposed requirements that the FERC regulated
entity maintain a minimum proprietary capital balance of 30 percent and that the
entity and its parent have investment grade credit ratings. Requests for
rehearing were filed on August 30, 2002. The FERC has not yet acted on the
rehearing requests.

Emergency Reconstruction of Interstate Natural Gas Facilities NOPR. On
January 17, 2003, the FERC issued a NOPR proposing, in emergency situations, to
(1) expand the scope of construction activities authorized under a pipeline's
blanket certificate to allow replacement of mainline facilities; (2) authorize a
pipeline to commence reconstruction of the affected system without a waiting
period; and (3) authorize automatic approval of construction that would be above
the normal cost ceiling. Comments on the NOPR were filed on February 27, 2003.
At this time, we cannot predict the outcome of this rulemaking.

Pipeline Safety Notice of Proposed Rulemaking. On January 28, 2003, the
U.S. Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines, and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from the enactment of the Pipeline Safety Improvement Act
of 2002, a new bill signed into law in December 2002. Comments on the NOPR were
filed on April 30, 2003. At this time, we cannot predict the outcome of this
rulemaking.

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

Western Trading Strategies. EPME, our subsidiary, responded on May 22,
2002, to the FERC's May 8, 2002 request in Docket No. PA-02-2, seeking
statements of admission or denial with respect to trading strategies designed to
manipulate western power markets. EPME provided an affidavit stating that it had
not engaged in these trading strategies.

Wash Trade Inquiries. On May 21 and 22, 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).

On June 7, 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 on July 15, 2002. On July 12, 2002, we
received a federal grand jury subpoena for documents concerning so-called round
trip or wash trades. We have complied with these requests.

Price Reporting to Indices. On October 22, 2002, the FERC issued a data
request in Docket PA-02-2 to all of the largest North American gas marketers,
including EPME, regarding price reporting of transactional data to the energy
trade press. We engaged an outside firm to investigate the matters raised in the
data request. EPME has provided information regarding its price reporting to
indices to the FERC, the Commodities Futures Trading Commission (CFTC), and to
the U.S. Attorney in response to their requests. The information provided
indicates inaccurate prices were reported to the trade publications. EPME has no

28

evidence that the reporting to the publications resulted in any unrepresentative
price index. On March 26, 2003, we announced a settlement between EPME and CFTC
of the price reporting matter providing for the payment by EPME of a civil
monetary penalty of $20 million, $10 million of which is payable within three
years, without admitting or denying the findings made in the CFTC order
implementing the agreement. On April 30, 2003, in a new docket PA03-7, the FERC
issued an Order Directing Submission of Information with Respect to Internal
Processes for Reporting Trading Data, directing certain marketing companies,
including EPME, to show that they have corrected their internal processes for
reporting trading data to the trade press, or that they no longer sell natural
gas at wholesale. The order required the named companies to file within 45 days
of the order, to respond to the following questions 1) that employees who
participated in manipulations have been disciplined; 2) that the company has a
code of conduct in place for reporting price information; 3) all trade data
reporting is done by an entity within the company that does not have a financial
interest in the published index; and 4) the company is cooperating with any
government agency investigation in past price reporting practices. EPME is
preparing its response.

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

Australia. In June 2001, the Western Australia regulators issued a draft
rate decision at lower than expected levels for the Dampier-to-Bunbury pipeline
owned by EPIC Energy Australia Trust, in which we have a 33 percent ownership
interest. EPIC Energy Australia appealed a variety of issues related to the
draft decision to the Western Australia Supreme Court. The court directed the
regulator to review its position and comply with applicable regulatory law.
During the fourth quarter of 2002, events in the business of Epic Energy
Australia, including unanticipated cash requirements, made it apparent that a
cash equity infusion would be required to refinance the debt of Epic Energy(WA)
Nominee Pty. that matures and is payable in full in 2003. With our fourth
quarter credit downgrades by the rating agencies and the demands on our
liquidity, we concluded that we would not contribute any further equity into our
Epic Energy Western Australian investment. As a result, we recognized an
impairment of $153 million related to our investment in Epic Energy's
Dampier-to-Bunbury pipeline in the fourth quarter of 2002, resulting in an
investment of approximately $50 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 July 2002,
we received a favorable ruling from the administrative law judge in Phase 1 of
the proceedings. We currently anticipate a determination from the PUC of Texas
on the administrative law judge's recommendation no later than July 2003.
Despite the favorable ruling from the administrative law judge, the PUC retains
the right to affirm or reject the award and any significant rejection of the
award could negatively

29

impact our metro transport business. An adverse resolution to the proceeding by
the PUC could have a negative impact on our ongoing operations and prospects in
this business.

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

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

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

Other

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

Our Merchant Energy positions are governed under a master International
Swap Dealers Association, Inc. agreement, various master natural gas agreements,
a master power purchase and sale agreement, and other commodity agreements. We
terminated most of these trading-related contracts, which we believe was proper
and in accordance with the terms of these contracts. In October 2002, we filed
proofs of claim for our domestic trading positions against Enron trading
entities in an amount totaling approximately $318 million. Also in October 2002,
our European trading business asserted $20 million in claims against Enron
Capital and

30

Trade Resources Limited which is subject to proceedings in the United Kingdom.
In addition, Enron now asserts that Coastal States Trading, Inc. (CSTI) owes
them approximate to $3.3 million related to certain terminated petroleum
contracts. CSTI disputes this assertion. After considering the cash margins
Enron has deposited with us as well as the reserves we have established, our
overall Merchant Energy exposure to Enron is $29 million, which is classified as
current accounts and notes receivable. We believe this amount is reasonable
based on offers received to purchase the claims.

In February 2003, Merchant Energy received a letter from EPMI demanding
payment under a March 2001 Power Purchase and Sale Agreement (Agreement) of
approximately $46 million. Merchant Energy responded to the February 2003 demand
letter denying that any sums were due EPMI under the Agreement. In addition,
EPMI has now made demand on us for this sum based on an August 2, 2001 guaranty
agreement. EPMI has now filed a lawsuit against Merchant Energy and El Paso in
the United States Bankruptcy Court for the Southern District of New York seeking
to collect these sums. We have denied liability. This lawsuit has been referred
to mediation.

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

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

As a result of current circumstances surrounding the energy sector, the
creditworthiness of several industry participants has been called into question.
We have taken actions to mitigate our exposure to these participants; however,
should several industry participants file for Chapter 11 bankruptcy protection
and 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. Our affiliate,
Chaparral, currently owns all of the equity interests in Camden and Bayonne and
79.2 percent of the indirect equity interests in Linden and Enron indirectly
owns a 1 percent non-voting preferred interest in Linden. Chaparral acquired 49
percent of the interests in the facilities in August of 1999 and the remaining
interests in February of 2001. If the FERC finds that Enron's ownership of the
facilities violated the ownership restrictions contained in PURPA, it may seek
to redetermine applicable rates that the QFs were entitled to charge their
customers and order refunds for the period of non-compliance or to impose other
penalties within its authority. We intervened in the proceeding before the FERC
to protect our interests. It is likely that this proceeding will delay the
closing of our announced sale of our interests in East Coast Power.

31

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

Economic Conditions of Brazil. We have investments in power, pipeline and
production projects in Brazil, including an investment in Gemstone, with an
aggregate exposure, including financial guarantees, of approximately $1.8
billion. During 2002, Brazil experienced a significant decline in its financial
markets due largely to concerns over the refinancing of Brazil's foreign debt
and the presidential elections which were completed in late November 2002. These
concerns have contributed to significantly higher interest rates on local debt
for the government and private sectors, have significantly decreased the
availability of funds from lenders outside of Brazil and have decreased the
amount of foreign investment in the country. These factors have contributed to a
downgrade of Brazil's foreign currency debt rating and a 45 percent devaluation
of the local currency against the U.S. dollar since the beginning of 2002. The
International Monetary Fund (IMF) announced in the fourth quarter of 2002 a $30
billion loan package for Brazil; however, the release of the majority of the
money will depend on Brazil meeting specified fiscal targets set by the IMF in
2003. In addition, Brazil's President or other government representatives may,
impose or attempt to impose changes affecting our business, including imposing
price controls on electricity and fuels, attempting to force renegotiation of
power purchase agreements (PPA's) which are indexed to the U.S. dollar, or
attempting to impose other concessions. These developments have delayed and are
likely to continue to delay the implementation of projects planned and underway
in Brazil. We currently believe that the economic difficulties in Brazil will
not have a material adverse effect on our investment in the country, but we
continue to monitor the economic situation and potential changes in governmental
policy, and are working with the state-controlled utilities in Brazil that are
counterparties under our projects' PPA's to maintain the economic returns we
anticipated when we made our investments. Future developments in Brazil
including forced renegotiations of our existing PPA's or changes in our
assumptions related to PPA's where we are seeking extension, may cause us to
reassess our exposure and potentially record impairments in the future.

Gemstone, our affiliate, owns a 60 percent interest in a 484 megawatts
gas-fired power project, known as the Araucaria project, located near Curitiba,
Brazil. Our investment in the Araucaria project was $180 million at March 31,
2003. The project company in which we have an ownership interest has a 20-year
PPA with Copel, a regional utility. Copel is approximately 60 percent owned by
the State of Parana. After the recent elections in Brazil, the new Governor of
the State of Parana publicly characterized the Araucaria project as unfavorable
to Copel and the State of Parana and promised a full review of the transaction.
Subsequent to this announcement, Copel informed us that they will not pay
capacity payments due under the PPA pending that review. Previous payments made
under the PPA were made with a reservation of rights with respect to the
enforceability of the contract. After meetings with the government as well as
new management at Copel to discuss Copel's obligations under the PPA, proved
unsuccessful, we were unable to come to a satisfactory resolution of the current
issues under the PPA, and we have initiated enforcement of our remedies under
the contract, including filing an arbitration proceeding under the International
Chamber of Commerce rules in Paris. If we do not prevail in that proceeding, or
are not otherwise able to enforce our remedies under the contract, we could be
required to impair our investment in the project. Our losses would be limited to
our investment. In addition, in the second quarter, we will analyze the fair
market value of this investment in conjunction with our acquisition of the third
party equity and the consolidation of Gemstone.

32

We own and consolidate two projects located in Manaus, Brazil in which
Gemstone has an indirect minority interest. The first project is a 238 megawatts
fuel-oil fired plant known as the Manaus Project with a net book value of plant
equipment of $107 million at March 31, 2003 and the second project is a 158
megawatts fuel-oil fired plant known as the Rio Negro Project with a net book
value of plant equipment of $111 million at March 31, 2003. The Manaus Project's
PPA currently expires in January 2005 and the Rio Negro Project's PPA currently
expires in January 2006. In the first quarter of 2003, we began experiencing
delays in payment from the purchaser of our power, Manaus Energia S.A. (Manaus
Energia). Manaus Energia is an indirect wholly owned subsidiary of Centrais
Electricas Brasileiras S. (Eletrobras), a Brazilian federal utility holding
company. As of March 31, 2003 our total accounts receivable on these projects is
$18 million. In addition, we have filed a lawsuit in the Brazilian courts
against Manaus Energia on the Rio Negro Project related to a tariff dispute
related to power sales from 1999 to 2001 and have a long-term receivable of $32
million related to this lawsuit. In meetings with Manaus Energia early 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
being 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 by up to seventeen years. If we are unsuccessful in reaching
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 March 31,
2003.

Gemstone, our affiliate, owns a 50 percent interest in a 409 megawatts
dual-fuel-fired power project, known as the Porto Velho Project, located in
Porto Velho, Brazil. Our investment in the Porto Velho project was $280 million
at March 31, 2003, including guarantees we have issued related to the
construction of the project. The Porto Velho Project sells power to Centrais
Electicas do Norte do Brasil S.A. (Eletronorte), a wholly owned subsidiary of
Eletrobras. The Porto Velho Project has two PPA's. The first PPA is for a term
of ten years and relates to the first 64 megawatts phase of the Porto Velho
Project. The second PPA is for a term of twenty years and relates to the second
345 megawatts phase of the Porto Velho Project (the Phase 2 PPA). We have
recently reached an agreement with the operating management of Eletronorte
contained in the Phase 2 PPA, but the senior management of Electronorte has yet
to approve the agreement and delays in getting the amendment approved could
occur. We will continue to monitoring 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. In addition, in the second quarter, we will analyze the fair
market value of this investment in conjunction with our acquisition of the third
party equity and consolidation of Gemstone.

Meizhou Wan Power Project. We own a 25 percent equity interest in a 734
megawatts, coal-fired power generating project, Meizhou Wan Generating, located
in Fuzhou, People's Republic of China. Our investment in the project was $56.5
million at March 31, 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. 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. The price the
project 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. If the project is unable to reach a long-term agreement with the
provincial government, with higher rates than in the interim agreement, we could
be required to impair our investment in the project, since cash flows from the
project would not be sufficient to

33

provide us with a return of our investment, and we may incur additional losses
if our guarantees and letters of credit are called upon.

Milford Power Project. We own a 25 percent direct equity interest in a 540
megawatts power plant construction project located in Milford, Connecticut.
Chaparral, our affiliate, owns an additional 70 percent interest in this
project. 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. We continue to negotiate with the contractor and
with the lending banks to attempt to reach agreements on contract disputes,
including resolution of liquidated damages that are due to the project under the
terms of the construction contract and for successful completion of plant
construction, and with the lenders in connection with our obligations under the
loan documents. On March 4, 2003, we provided a notice to Milford declaring an
event of default under the fuel supply agreement between us and Milford due to
non-payment by Milford. On March 6, 2003, Milford received a notice from its
lenders stating that the lenders intended to commence foreclosure on the project
in accordance with the lending agreement within 30 days. The lenders have not
yet exercised this remedy. As a result of the default under the construction
lending agreement, we evaluated our investment and recorded an impairment charge
of $17 million while Chaparral recorded an impairment charge of $44 million in
the fourth quarter of 2002. In April 2003, El Paso's Board of Directors
authorized it 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.

Berkshire Power Project. We own a 25 percent direct equity interest in a
261 megawatts power plant located in Massachusetts. Chaparral, our affiliate,
owns an additional 31.4 percent interest in this project. The construction
contractor failed to deliver a plant capable of operating on both gas and fuel
oil, or capable of operating at its designed capacity. Berkshire is negotiating
with the contractor with respect to its failure to deliver the project in
accordance with guaranteed specifications, including fuel oil firing capability.
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 March 31, 2003, we had an
investment in Berkshire of $7 million, receivables from Berkshire of $28 million
and derivatives with Berkshire of $17 million associated with a subordinated
fuel agreement and management services agreement. At March 31, 2003, Chaparral's
investment was $4 million. We continue to discuss settlement opportunities with
our construction contractor. The ultimate resolution of these issues will be
considered in the determination of whether any of these investments in and
receivables from Berkshire will be impaired in the future.

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,

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

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

34

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*; Sharon
Lynn Lodewick v. Dynegy, Inc. et al. filed December 16, 2002 in the Circuit
Court for the County of Multnomah, State of Oregon; Nick A. Symonds v. Dynegy,
Inc. et al. filed December 20, 2002 in the United States District Court for the
Western District of Washington, Seattle; Henry W. Perlman, et al. v. San Diego
Gas & Electric et al. filed December 2002, in the United States District Court,
Southern District of New York. State of Arizona v El Paso Corporation, El Paso
Natural Gas Company, El Paso Merchant Energy Company, et al. filed March 10,
2003 in the Superior Court, Maricopa County, Arizona. Sierra Pacific Resources
et. al. v. El Paso Corporation et. al., filed April 21, 2003 in the United
States District Court for the District of Nevada.

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

The 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

35

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.

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

15. CAPITAL STOCK

On April 29, 2003, we declared a quarterly dividend of $0.04 per share on
our common stock, payable on July 7, 2003, to stockholders of record on June 6,
2003. Also, during the quarter ended March 31, 2003, we paid dividends of $130
million to common stockholders, and El Paso Tennessee Pipeline Co., our
subsidiary, paid dividends of approximately $6 million on its Series A
cumulative preferred stock, which is 8 1/4% per annum (2.0625% per quarter).

16. 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. In the second quarter of 2002, we
reclassified our historical coal mining operations from our Merchant Energy
segment to discontinued operations in our financial statements. Merchant
Energy's results for the period ended March 31, 2002, were restated to 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 operating income, adjusted for several items, including: equity earnings from
unconsolidated affiliates, minority interests of consolidated, but less than
wholly owned operating subsidiaries and other miscellaneous non-operating items.
Items that are not included in this measure are financing costs, including
interest and debt expense, return on preferred interests of consolidated
subsidiaries, income taxes, discontinued operations and the impact of accounting
changes. We believe this measurement is useful to our investors because it
allows them to evaluate the effectiveness of our businesses and operations and
our investments from an operational perspective. This measurement may not be
comparable to measurements used by other companies and should not be used as a
substitute for net income or other performance measures such as operating income
or operating cash flow. The reconciliations of EBIT to income (loss) from
continuing operations are presented below:

36

The following are our segment results as of and for the quarters ended
March 31:

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

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

17. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS

We hold investments in affiliates which we account for using the equity
method of accounting. Summarized financial information of our proportionate
share of unconsolidated affiliates below includes affiliates in which we hold an
interest of 50 percent or less, as well as those in which we hold greater than a
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 $9 million and $10 million for the quarters ended March 31, 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. For the quarters ended March 31, 2003 and 2002,
we recorded losses from unconsolidated affiliates of $99 million and $223
million, which were net of impairment charges related to our investments in
unconsolidated affiliates and gains and losses on sale of investments of $217
million in 2003 and $286 million in 2002. In the first quarter of 2003, we
recorded an impairment charge of $207 million related to our Chaparral
investment. See our discussion of the events that led to this impairment under
Chaparral below. In the first quarter of 2002, we recorded impairment charges of
$286 million related to our Agua del Cajon and CAPSA/CAPEX investments due to
weak economic conditions in Argentina. See Note 7 for a discussion of an
impairment on our cost-based investment in Argentina.

38

We enter into a number of transactions with our unconsolidated affiliates
in the ordinary course of conducting our business. The following table shows
revenues, income and expenses incurred between us and our unconsolidated
affiliates for the quarters ended March 31:

Gemstone

As discussed more completely in our 2002 Form 10-K, we entered into the
Gemstone investment in 2001 to finance five major power plants in Brazil. The
following summarizes our overall investment in Gemstone:

We have a credit facility with Gemstone that allows us to borrow amounts
from Gemstone related to project financings obtained by Gemstone. We owed
Gemstone $75 million as of March 31, 2003 under this facility, which carries a
variable interest rate that was 1.8 percent at March 31, 2003.

We accounted for our investment in Gemstone using the equity method of
accounting as of March 31, 2003, since we did not have the ability to exercise
control over the entity. In April 2003, we purchased all of Rabobank's third
party equity interest in Gemstone for approximately $53 million. As a result, we
will begin consolidating Gemstone during the second quarter of 2003. At that
time, we will record the acquired assets and liabilities at their fair values.
Any excess of the amounts paid over the fair values of the net assets acquired
will be reflected in our balance sheet as goodwill. Goodwill is not amortized,
but is tested periodically for impairment. Had we consolidated Gemstone in our
balance sheet as of March 31, 2003, our total assets would have been higher by
$0.6 billion, our total liabilities would have been higher by $0.9 billion,
(including debt of $1.0 billion, other liabilities of $0.1 billion and a
reduction of net intercompany payables of $0.2 billion,) and our minority
interest of consolidated subsidiaries would have been lower by $0.3 billion.
These amounts are based on the carrying value of Gemstone's assets and
liabilities as of March 31, 2003. The actual amounts recorded as fair values for
the individual assets and liabilities when we consolidate Gemstone will be based
on a number of factors, including economic conditions in Brazil and events
specific to each of our projects and could be significantly different than the
amounts presented above. These conditions are discussed more fully in Note 14.

Chaparral

As discussed more completely in our 2002 Form 10-K, we entered into our
Chaparral investment (also referred to as Electron) in 1999 to expand our
domestic power generation business. As of December 31, 2002, we owned 20 percent
of Chaparral, with the remaining 80 percent owned by Limestone. In March 2003,
we contributed $1 billion to Limestone. Limestone then used these proceeds to
pay off notes that Limestone had

39

issued to originally invest in Chaparral. These notes matured on March 17, 2003.
Following our $1 billion investment, our effective ownership interest in
Chaparral (both direct ownership and indirectly through our ownership interest
in Limestone) increased to 90 percent. The following summarizes our overall
investment in Chaparral (including our Limestone investment):

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

(1) This facility earns interest at a variable rate based on LIBOR. This rate
was 1.8 percent at March 31, 2003 and 1.9 percent at December 31, 2002.

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

We continue to account for our investment in Chaparral and in Limestone
using the equity method of accounting since we do not have the ability to
exercise control over either entity. This accounting did not change when we
acquired the additional interest in Limestone because, despite our higher
ownership interest, our rights versus those of the third party investor did not
change. In March 2003, we notified Limestone's certificate holders that we would
exercise our rights under the partnership agreement to purchase all of the
remaining third party equity in Limestone for a negotiated price of $175
million. We expect that this transaction will occur during the second quarter of
2003. The price we will pay the third party equity holder is based on the terms
of the Limestone agreements. Under the terms of these agreements, 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 sell the assets of Chaparral, the proceeds of which would first be applied to
the payment of the agreed amount to them. If we had elected to allow the third
party equity to exercise their liquidation rights, Limestone would control the
liquidation process and would not necessarily have been motivated to achieve
that 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 are ultimately sold or
held and used in our ongoing business, we chose to redeem the third party equity
holder's interests for the agreed amount.

Upon our acquisition of the remaining interest in Limestone, we will
effectively own 100 percent of Chaparral and will control all of its activities.
As a result, we will consolidate Chaparral at that time. Upon consolidation, we
will record the acquired assets and liabilities at their fair values. Any excess
of the amounts paid over the fair values of the net assets acquired will be
reflected in our balance sheet as goodwill. Goodwill is not amortized, but is
tested periodically for impairment. Had we consolidated Chaparral in our balance
sheet as of March 31, 2003, our total assets would have been higher by $1.6
billion, and our total liabilities would have been higher by $1.6 billion,
including project debt of $1.5 billion. These amounts are based on the

40

carrying value of Chaparral's assets and liabilities as of March 31, 2003,
considering also the impairment charge we took during the first quarter of 2003,
assuming it was allocated to Chaparral's assets and liabilities. The fair values
of the individual assets and liabilities when we consolidate Chaparral will be
based on a number of factors, including economic conditions in the power
industry at that time, interest rates and estimated future natural gas and power
market prices, and will be affected by other events that occur between now and
that date. As a result, the actual impact to our financial statements will be
different than the amounts presented above. Additionally, the estimation of fair
value may not reflect the ultimate sales price of any of these assets and, as a
result, future gains or losses may arise upon the disposition of these assets.
For a discussion of events that could impact the Linden facility that is owned
by Chaparral, see Note 14.

We have entered into a number of transactions with Chaparral and its
subsidiaries, including providing management and administrative services,
capital contributions and being a party to a number of commercial contracts.
These transactions are more fully described in our 2002 Form 10-K.

El Paso Energy Partners

A subsidiary in our Field Services segment serves as the general partner of
El Paso Energy Partners, a master limited partnership that has limited
partnership units that trade on the New York Stock Exchange. On May 1, 2003, El
Paso Energy Partners announced that it will begin doing business effective May
15, 2003, as GulfTerra Energy Partners, L.P.

We currently own 11,674,245 of the partnership's common units, the one
percent general partner interest, all of the Series B preference units and all
of the Series C units. At March 31, 2003, our common units had a market value of
$362 million, our preference units had a liquidation value of $161 million, and
our Series C units had a value of $347 million. In April 2003, we contributed
approximately $1 million of our Series B preference units to El Paso Energy
Partners. This contribution was made in order for us to maintain our one percent
general partner interest as a result of a common unit offering completed by the
partnership.

Our segments also conduct transactions in the ordinary course of business
with El Paso Energy Partners, including sales of natural gas and operational
services. During the quarter ended March 31, 2003, our Field Services segment
recognized revenues from El Paso Energy Partners of $5 million. In the first
quarters of 2003 and 2002, Field Services also recognized cost of sales of $17
million and $14 million and was reimbursed $24 million and $9 million for
expenses incurred on behalf of the partnership. In addition, during the quarters
ended March 31, 2003 and 2002, our Merchant Energy segment recognized revenues
of $10 million and $7 million, and cost of sales of $11 million and $3 million
related to transactions with El Paso Energy Partners. In the first quarter of
2002, our Production segment also recognized revenues of $1 million and
recognized cost of sales of $2 million in the first quarter of 2003 and $1
million in the first quarter of 2002. For a further discussion of our
relationships with El Paso Energy Partners, see our 2002 Form 10-K.

18. NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

In January 2003, the Financial Accounting Standards Board 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 that companies
consolidate a variable interest entity if it is allocated a majority of the
entity's losses and/or returns, including fees paid by the entity. The
provisions of FIN No. 46 are effective for all variable interest entities
created after January 31, 2003, and are effective on July 1, 2003, for all
variable interest entities created before January 31, 2003.

We currently have interests in and consolidate several entities in which
third party investors hold preferred interests. The preferred interests held by
the third party investors are reflected in our balance sheet as preferred
interests of consolidated subsidiaries. The third party investors are
capitalized with five percent equity, which is held by banks in these
arrangements, and 95 percent debt. We believe we would consolidate these third
party investors under these arrangements because (i) the equity investment in
these third party investors is less than the specified 10 percent of total
capitalization of the investors and (ii) the rights of the third party investors
to expected residual returns from these arrangements is limited. When we
consolidate

41

these third party investors, the minority interest that is currently classified
as preferred interests of consolidated subsidiaries will be classified as
long-term debt. At this time, we believe the holder of the preferred stock of
our consolidated subsidiary, Coastal Securities Company Limited, will be
impacted by this standard. We believe the impact on our financial statements as
a result of implementing this standard will be (in millions):

Decrease in preferred interests of consolidated
subsidiaries.............................................. $100
Increase in long-term debt.................................. $100

We have a number of other financial interests that would have been affected
by this standard, but as a result of actions taken during the first quarter of
2003, or actions we will take in the second quarter of 2003, including amending
and restructuring the underlying agreements, these financial interests will be
consolidated prior to our required adoption of this standard. The financial
interests affected by these actions include:

- Operating leases with residual value guarantees for the Lakeside
Technology Center and a facility at our Aruba refinery (see Note 12);

- Preferred interests in our Trinity River and Clydesdale financing
arrangements (see Note 13); and

- Equity investments in Chaparral and Gemstone and the related preferred
interest in Gemstone (see Note 17).

42

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

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

OVERVIEW

As was discussed more completely in our 2002 Form 10-K, in February 2003,
we announced our 2003 Operational and Financial Plan to address liquidity needs
in our business activities. The objectives of this plan were to:

- Preserve and enhance the value of our core businesses;

- Exit non-core businesses quickly, but prudently;

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

- Aggressively pursue additional cost reductions; and

- Continue to work diligently to resolve litigation and regulatory matters.

So far in 2003, we have accomplished a number of objectives under our plan.
More specifically, we have:

- Completed or announced sales of assets for approximately $2.3 billion
(see Note 3 for a further discussion of these divestitures);

- Completed financing transactions, consisting of loans and debt issuances
totaling $1.9 billion;

- Repaid approximately $2.6 billion of maturing debt and other obligations,
including long-term debt retirements of $294 million, the redemption of
$980 million of obligations under our Trinity River financing
arrangement, the redemption of $297 million of obligations under our
Clydesdale financing arrangement, and the contribution of $1 billion to
Limestone, which used the proceeds to repay $1 billion of Limestone's
notes (see Item 1, Financial Statements, Notes 12, 13 and 17 for a
further discussion of these actions);

- Entered into a new $3 billion revolving facility that matures in June
2005;

- Purchased the third party equity interest in our Gemstone power
investment for $53 million;

- Restructured the obligations under our Clydesdale financing arrangement
as a term loan that will amortize over the next two years; and

- Reached an agreement in principle (the Western Energy Settlement) in
March 2003, which was designed to resolve our principal exposure relating
to the western energy crisis while minimizing the impact on our current
liquidity.

In April 2003, we announced the next steps under our plan. These actions
include:

- Targeting additional pre-tax cost savings and business efficiencies of
$250 million, beyond the previously announced savings of $150 million by
the end of 2004;

- Working to recover cash collateral currently committed to our trading,
petroleum, refining and other businesses; and

- Reducing our obligations senior to common stock by at least $2.5 billion
in 2003.

To achieve our planned objectives, we expect to:

- Purchase the third party equity in our Chaparral investment for $175
million in the second quarter of 2003, resulting in the consolidation of
the assets and liabilities of that entity; and

43

- Repay the $1.2 billion two-year term loan issued in February 2003 through
the issuance of long-term debt in the capital markets in the second or
third quarter of 2003 to eliminate the amortization requirements of that
financing in 2004 and 2005.

OVERVIEW OF CASH FLOW ACTIVITIES FOR THE QUARTER ENDED MARCH 31, 2003

For the quarters ended March 31, 2003 and 2002, our cash flows are
summarized as follows:

During the quarter ended March 31, 2003, our cash and cash equivalents
increased by approximately $0.2 billion to approximately $1.8 billion. We
generated cash from several sources, including cash flows from our principal
operations, sales of assets and issuances of long-term debt. We used a major
portion of that cash to fund our capital expenditures, including additional
investments in unconsolidated subsidiaries, to purchase preferred shares of
minority interest holders and to meet the increased demand for cash collateral
as a result of market price changes and the downgrade in our credit rating early
in the quarter. Overall, our cash sources and uses were summarized as follows
(in billions):

Cash inflows
Cash flows from operations (before working and non-working
capital changes)....................................... $0.6
Net proceeds from the sale of assets and investments...... 1.5
Net proceeds from the issuance of long-term debt.......... 1.8
Net borrowings under revolving credit facility............ 0.5
Other..................................................... 0.1
----
Total cash inflows..................................... $4.5
----
Cash outflows
Working capital and other demands......................... $0.7
Additions to property, plant and equipment................ 0.7
Investment in Limestone................................... 1.0
Restricted cash demands................................... 0.2
Dividends paid to common stockholders..................... 0.1
Payments to redeem preferred interests of consolidated
subsidiaries........................................... 1.2
Payments to retire long-term debt......................... 0.3
Other..................................................... 0.1
----
Total cash outflows.................................... $4.3
----
Net change in cash................................... $0.2
====

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

44

Cash From Operating Activities

We generated approximately $0.6 billion in cash from operations in 2003
before working and non-working capital changes, as compared to $0.7 billion in
2002. Net cash used in operating activities was $(0.1) billion for the quarter
ended March 31, 2003, compared to net cash provided by operating activities of
$0.1 billion for the same period in 2002. We used a significant amount of cash
to meet working capital demands in both 2003 and 2002. The downgrade in our
credit rating in late 2002 and early 2003 along with increases in natural gas
prices at levels above hedged production prices resulted in margin calls of
approximately $0.4 billion. Similarly, we used about $0.7 billion of cash for
margin calls and option premiums in 2002. Additionally, our price risk
management activities generated $0.4 billion less cash in 2003 compared to 2002
because of our decision in November 2002 to exit the energy trading business
which resulted in a decrease in cash settlements.

Cash From Investing Activities

Net cash used in our investing activities was $0.5 billion for the quarter
ended March 31, 2003. Our investing activities consisted primarily of capital
expenditures and equity investments of $1.7 billion offset by net proceeds from
sale of assets and investments of $1.5 billion. Our capital expenditures and
equity investments included the following (in billions):

Production exploration, development and acquisition
expenditures.............................................. $0.5
Pipeline expansion, maintenance and integrity projects...... 0.1
Investment in Limestone..................................... 1.0
Other (primarily petroleum and power projects).............. 0.1
----
Total capital expenditures and equity
investments....................................... $1.7
====

Cash received from our investing activities includes $1.5 billion from the
sale of assets and investments. Our asset sales proceeds were primarily
attributable to the sale of natural gas and oil properties located in western
Canada, New Mexico, Oklahoma and the Gulf of Mexico for $0.7 billion, the sale
of an equity investment in CE Generation for $0.2 billion, the sale of the
Corpus Christi refinery, the Florida Petroleum terminals and the tug and barge
operations for $0.4 billion, and the sale of other pipeline, power, petroleum
and processing assets of $0.2 billion.

Cash From Financing Activities

Net cash provided by our financing activities was $0.8 billion for the
quarter ended March 31, 2003. Cash provided from our financing activities
included the net proceeds from the issuance of long-term debt of $1.8 billion
and $0.5 billion of short-term borrowings under our revolving credit facility.
Further, we received $0.1 billion from notes payable to affiliates. Cash used by
our financing activities included payments made to retire third party long-term
debt of $0.3 billion. We also paid $1.2 billion to fully redeem the Trinity
River preferred securities and partially redeem Clydesdale preferred securities
previously issued by our subsidiaries. Further, during the quarter ended March
31, 2003, we paid dividends of $0.1 billion to common stockholders.

Cash Flow Outlook

For the remainder of 2003, we expect to recover approximately $1.5 billion
in working capital. The sources of our expected working capital include:

- Substitution of letters of credit for cash deposits;

- Sale of inventory associated with petroleum assets; and

- Recovery of posted margins through settlement of positions for trading as
well as production hedges.

We also anticipate that we will sell additional assets during the remainder
of 2003, which could generate up to approximately $1.5 billion in proceeds.
Through a combination of working capital recoveries and asset sales, we
anticipate we could reduce our long-term debt by as much as $3.0 billion.

45

FINANCING AND COMMITMENTS

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

Short-Term Debt and Credit Facilities

At March 31, 2003, our weighted average interest rate on our short-term
credit facilities was 2.61%, and at December 31, 2002, it was 2.69%. We had the
following short-term borrowings and other financing obligations:

Long-Term Debt Obligations

During the first quarter of 2003, we completed several debt financing
transactions related to our long-term debt obligation:

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

(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 general corporate and
investment purposes.

(2) We have collateralized this term loan with natural gas and oil reserves of
approximately 2.3 trillion cubic feet of gas equivalents. The minimum LIBOR
rate is 3.5%. This term loan has scheduled payments of $300 million in each
of June 2004 and September 2004 and the $600 million balance in March 2005.
Additionally, the loan facility requires us to pay a facility fee equal to
2% per annum on the average daily aggregate outstanding principal amount of
the loan. Funds from the term loan were primarily used to retire the Trinity
River financing arrangement.

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 in June 2005. This
facility replaces our previous $3 billion revolving credit facility. Our
existing $1 billion revolving credit facility, which matures in August 2003, and
approximately $1 billion of other financing arrangements (including leases,
letters of credit and other facilities) were also amended to conform our
obligations to the new $3 billion revolving credit facility. Our $3 billion
revolving credit facility, $1 billion revolving credit facility, and the other
financing arrangements are secured by our equity in EPNG, TGP, ANR, Wyoming
Interstate Company, ANR Storage Company, and our common and Series C units in El
Paso Energy Partners, L.P. These credit facilities and other financing
arrangements are also collateralized

46

by our equity in the companies that own the assets that collateralize our
Clydesdale financing arrangement. For a discussion of Clydesdale, see Item 1,
Financial Statements, Note 13.

EPNG and TGP remain jointly and severally liable for any amounts
outstanding under the new $3 billion revolving credit facility through August
19, 2003. Also, EPNG and TGP remain jointly and severally liable under our $1
billion revolving credit facility and as such are liable for any amounts under
the facility until its maturity in August 2003. In addition, El Paso CGP Company
is no longer a borrower under the $1 billion credit facility.

The revolving credit facilities have a borrowing cost of LIBOR plus 350
basis points and letter of credit fees of 350 basis points. In addition, the
covenant relating to subsidiary debt requirements was removed under the new and
amended agreements. Also, EPNG, TGP, ANR, and upon the maturity of the
Clydesdale financing transaction, CIG cannot incur incremental debt if the
incurrence of the incremental debt would cause their debt to EBITDA ratio (as
defined in the new revolving credit facility) for that particular company to
exceed 5 to 1. As of the date of this filing, we were in compliance with these
covenants. As of March 31, 2003, we had $1.5 billion outstanding under the $3
billion revolving credit facility and $500 million outstanding under the $1
billion revolving credit facility. We have also issued $456 million letters of
credit under the $1 billion revolving credit facility.

The availability of borrowings under our credit and borrowing agreements is
subject to specified 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.

Notes Payable to Affiliates

Our notes payable to unconsolidated affiliates as of March 31, 2003, were
$410 million versus $390 million as of December 31, 2002. The increase was
primarily due to the issuance of a $75 million revolving note to a subsidiary of
Diamond Power Ventures, LLC, which is owned by us and Gemstone with a variable
interest rate based on 90-day LIBOR plus 0.50%. This increase was partially
offset by the retirement of $45 million of Chaparral debt securities.

Minority and Preferred Interests of Consolidated Subsidiaries

The total amount outstanding for securities of subsidiaries and preferred
stock of consolidated subsidiaries was $2.3 billion at March 31, 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 $189 million of preferred
member interests in Clydesdale in the first quarter of 2003. In April 2003, we
restructured our Clydesdale financing arrangement as a term loan that will
amortize over the next two years. See Item 1, Financial Statements, Note 13, 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 March 31, 2003, we had outstanding letters of credit of
approximately $807 million and $852 million as of December 31, 2002. At March
31, 2003, $456 million of our outstanding letters of credit were issued on our
revolving credit facility, and $183 million was supported with cash collateral.

Financial Position Impact of Consolidations

As a result of actions we have taken since the end of the first quarter of
2003, we will consolidate the following entities during the second quarter:

- Chaparral;

- Gemstone;

- The owner and lessor of the Lakeside Technology Center;

47

- The owner and lessor of a facility at our Aruba refinery; and

- The preferred member interest holder of Clydesdale.

These steps were all taken to simplify our financial structure and
refinance existing arrangements, thereby enabling us to better manage our
liquidity requirements. Had we consolidated these entities on March 31, 2003,
our financial position, including the estimated impact of consolidating these
entities would have been as follows:

The impact above is based on the carrying values of the entities we will
consolidate. The actual impact will be based on the fair values of the
individual assets and liabilities and economic considerations at the time they
are consolidated. At this time, the allocation of those fair values is not
complete and as a result, the estimated amounts presented above will change.

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 operating income, adjusted for several items, including: equity earnings from
unconsolidated affiliates, minority interests of consolidated, but less than
wholly owned operating subsidiaries and other miscellaneous non-operating items.
Items that are not included in this measure are financing costs, including
interest and debt expense, return on preferred interests of consolidated
subsidiaries, income taxes, discontinued operations and the impact of accounting
changes. The following is a reconciliation of our operating income to our EBIT
and our EBIT to our income (loss) from continuing operations for the quarters
ended March 31:

We believe EBIT is a useful measurement for our investors because it allows
them to evaluate the effectiveness of our businesses and operations and our
investments from an operational perspective. This measurement may not be
comparable to measurements used by other companies and should not be used as a
substitute for net income or other performance measures such as operating income
or operating cash flow.

48

OVERVIEW OF RESULTS OF OPERATIONS

Below are our results of operations (as measured by EBIT) by segment for
the quarters ended March 31. A reconciliation of operating income to EBIT is
provided below for each 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. These
segment results include the impacts of asset impairments, gains and losses on
long-lived assets and other charges, which are discussed further in Item 1,
Financial Statements, Notes 2, 4, 5, 6, 7 and 17.

PIPELINES

Our Pipelines segment holds our interstate transmission businesses. For a
further discussion of the business activities of our Pipelines segment, see our
2002 Form 10-K. Results of our Pipelines segment operations were as follows for
the quarters ended March 31:

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

(1) Throughput volumes for 2002 exclude 224 BBtu/d related to the sale of our
equity investment in the Alliance pipeline system which was completed in
March 2003. Throughput volumes also exclude intersegment activities. Prior
period volumes have been restated to reflect current year presentations
which include billable transportation throughput volume for storage
injection and withdrawal.

Operating revenues for the quarter ended March 31, 2003, were $51 million
higher than the same period in 2002. This increase was due to the impact of
higher prices in 2003 on natural gas recovered in excess of amounts used in
operations of $33 million, an increase in transportation revenues of $17 million
resulting from increased throughput volumes as a result of colder winter
weather, higher sales under natural gas purchase

49

contracts of $8 million and increased revenues of $8 million due to system
expansion projects placed in service in the latter part of 2002. Also
contributing to the increase were $4 million related to a rate settlement in
2003, storage gas sales of $3 million which commenced in the fourth quarter of
2002, an increase of $3 million in natural gas liquids revenues resulting from
higher prices and a $3 million increase in reservation revenues due to an
increase in contracted volumes on the WIC system. These increases were partially
offset by a $20 million decrease in revenues due to CIG's sale of the Panhandle
field and other production properties in July 2002, a decrease of $15 million
due to capacity contracts that have expired which EPNG is prohibited from
remarketing due to its September 20, 2002 FERC order (for further discussion of
this order, see Item 1, Financial Statements, Note 14) and a $6 million fuel
settlement resulting from our Mojave Pipeline rate case settled in the first
quarter of 2002.

Operating expenses for the quarter ended March 31, 2003, were $24 million
higher than the same period in 2002. The increase was due to an $11 million gain
on the sale of pipeline expansion rights in February 2002, higher fuel and
system supply purchases in 2003 of $11 million resulting from higher prices and
volumes in 2003, lower benefit costs in 2002 of $6 million, $4 million of
amortization expense related to EPNG's portion of the Western Energy Settlement
and $2 million of higher depreciation related to transmission system expansion
projects placed in service in 2002. These increases were partially offset by a
$12 million decrease in operating expenses due to CIG's sale of Panhandle field
and other production properties in July 2002 and a $9 million decrease due to
bad debt expense recorded in 2002 related to the bankruptcy of Enron Corp.

Other income for the quarter ended March 31, 2003, was $3 million higher
than the same period in 2002. The increase was primarily due to higher equity
earnings from our investment in Citrus Corporation of $13 million. Offsetting
this increase were lower equity earnings of $5 million from Alliance Pipeline
due to the sale of our interests in fourth quarter of 2002 and a charge of $4
million related to the partial termination of a hedging obligation for Blue Lake
Gas Storage Company, an investment in which we have a 75 percent ownership
interest.

50

PRODUCTION

Our Production segment conducts our natural gas and oil exploration and
production activities. For a further discussion of the business activities of
our Production segment, see our 2002 Form 10-K. Results of our Production
segment operations were as follows for the quarters ended March 31:

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

(2) Prices are stated before transportation costs.

For the quarter ended March 31, 2003, operating revenues were $45 million
higher than the same period in 2002. Our natural gas revenues, including the
impact of hedges, were $10 million higher in the first quarter of 2003. Realized
natural gas prices rose in 2003 by 34 percent, resulting in a $124 million
increase in revenues, when compared to the same period in 2002. Our 2003 natural
gas volumes decreased by 24 percent, resulting in a $114 million decrease in
revenues, from the same period in 2002. These declines were due largely to the
sale of properties in Colorado, Utah, Texas, and western Canada during 2002 as
well as normal production declines. Our oil, condensate and liquids revenues,
including the impact of hedges, were $24 million higher in the first quarter of
2003. Realized oil, condensate and liquids prices rose in 2003 by 71 percent,
resulting in a $44 million increase in revenues, when compared to the same
period in 2002. Our 2003 oil, condensate and liquids volumes decreased by 25
percent, resulting in a $20 million decrease in revenues, from the same period
in 2002. These declines were again due largely to the sale of properties and
normal declines mentioned above. Further increasing operating revenues was an
additional loss of $13 million in 2002 resulting from a mark-to-market
adjustment of derivative positions that no longer qualify as cash flow hedges.
These hedges no longer qualify for hedge accounting treatment since they were
designated as hedges of anticipated future production from natural gas and oil
properties that were sold in March 2002.

51

Transportation and net product costs for the quarter ended March 31, 2003,
were $9 million higher than the same period in 2002 primarily due to a higher
percentage of natural gas volumes subject to transportation fees and higher
costs incurred to meet minimum payment obligations under pipeline agreements.

Operating expenses for the quarter ended March 31, 2003, were $24 million
lower than the same period in 2002 due to a non-cash full cost ceiling test
charge of $33 million incurred in the first quarter of 2002 for our
international properties in Brazil and Turkey. Depletion expense was lower by $2
million comprised of a $49 million decrease due to lower production volumes in
2003, partially offset by a $42 million increase resulting from higher depletion
rates in 2003 and costs of $5 million related to retirement obligations from our
adoption in 2003 of SFAS No. 143. The higher depletion rate resulted from higher
capitalized costs in the full cost pool coupled with a lower reserve base. Also
contributing to the decrease in 2003 operating expenses were decreased oilfield
service costs of $14 million due primarily to asset dispositions which reduced
labor and production processing fees. Partially offsetting the decrease in
expenses were asset impairments of $9 million related to non-full cost assets in
Canada, higher corporate overhead allocations of $5 million and employee
severance costs of $3 million in 2003. In addition, the decrease in expenses was
offset by $6 million of higher severance and other taxes in 2003 and a $2
million gain on non-full cost pool assets recognized in 2002. The severance
taxes increase was due to higher commodity prices in 2003 and tax credits taken
in 2002 for qualified natural gas wells.

Other income for the quarter ended March 31, 2003, was $8 million higher
than the same period in 2002 primarily due to higher earnings in 2003 from
Pescada, an equity investment in Brazil.

FIELD SERVICES

Our Field Services segment conducts our midstream activities. A subsidiary
in our Field Services segment serves as the general partner of El Paso Energy
Partners, L.P. and owns a one percent general partner interest. On May 1, 2003,
El Paso Energy Partners announced that it will begin doing business effective
May 15, 2003, as GulfTerra Energy Partners, L.P. In April 2003, we announced we
may sell between five and ten percent of our one percent general partner
interest. In addition to our general partner interest, we currently own through
various subsidiaries 24.6 percent of the partnership's common units, all of the
Series B preference units and all of the 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 are also reimbursed for costs we
incur to provide various operational and administrative services to the
partnership. In addition, we are reimbursed for other costs paid directly by us
on the partnership's behalf. During the first quarter of 2003, we were
reimbursed approximately $24 million for expenses incurred on behalf of the
partnership. At March 31, 2003, our common units had a market value of $362
million, our preference units had a liquidation value of $161 million, and our
Series C units had a value of $347 million. During the first quarter of 2003,
our earnings and cash from El Paso Energy Partners were as follows:

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

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

For a further discussion of the business activities of our Field Services
segment, see our 2002 Form 10-K. In March 2003, we received approval from our
Board of Directors to sell our assets in the Mid-Continent and north Louisiana
regions. Our Mid-Continent assets primarily include our Greenwood, Hugoton,
Keyes and Mocane natural gas gathering systems, our Sturgis, Mocane and Lakin
processing plants and our processing

52

arrangements at three additional processing plants. Our north Louisiana assets
primarily include our Dubach processing plant and Gulf States interstate natural
gas transmission system. We expect to complete the sales of these assets by the
end of the second quarter of 2003. These assets generated EBIT of approximately
$10 million during the year ended December 31, 2002. Once this sale is
completed, our remaining assets will consist primarily of our investment in El
Paso Energy Partners and processing facilities in the south Texas, south
Louisiana and Rocky Mountain regions.

As a result of our asset sales and the resulting decline in our gathering
and treating activities, we expect our future EBIT to decrease considerably.
However, we expect the increase in earnings from our interests in El Paso Energy
Partners to partially offset the anticipated decrease in EBIT primarily because
some of the assets we sold were to the partnership. For a further discussion of
the business activities of our Field Services segment, see our 2002 Form 10-K.
Results of our Field Services segment operations were as follows for the
quarters ended March 31:

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

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

Total gross margins for the quarter ended March 31, 2003, were $78 million
lower than the same period in 2002, primarily a result of asset sales. The table
below presents the gross margins earned by these assets in the first quarter of
2002 (in millions):

Texas and New Mexico midstream assets (sold in April
2002)(1).................................................. $38
San Juan Basin gathering, treating and processing assets
(sold in November 2002)(1)................................ 29
Dragon Trail processing plant (sold in May 2002)............ 3
Wyoming gathering assets (sold in January 2003)............. 2
Natural Buttes and Ouray gathering systems (sold in December
2002)..................................................... 1
---
Total............................................. $73
===

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

(1) Sold to El Paso Energy Partners.

Gross margins also decreased due to the favorable resolution of fuel, rate
and volume matters of $13 million in the first quarter of 2002. Partially
offsetting these decreases was an $8 million increase due to higher natural gas
prices and natural gas liquids prices in 2003, which favorably impacted our
processing margins.

Operating expenses for the quarter ended March 31, 2003, were $40 million
lower than the same period in 2002. The decrease was primarily due to the sales
of assets discussed above, resulting in lower operating costs

53

of $21 million and lower depreciation expense of $9 million. Also contributing
to this decrease were higher reimbursements of $6 million from El Paso Energy
Partners to provide administrative and other activities to operate their assets.
The increase in reimbursements is a direct result of our operation of the
additional assets that El Paso Energy Partners currently owns. In addition, our
2002 cost reduction plan, initiated mid-2002, resulted in $3 million of lower
operating costs.

Other income for the quarter ended March 31, 2003, was $14 million higher
than the same period in 2002 due to increased earnings from our investment in El
Paso Energy Partners. In November 2002, we received 10,937,500 Series C units
issued by El Paso Energy Partners as part of the proceeds from the sale of San
Juan Basin assets to the partnership, and these units are allocated earnings on
an equal basis with the common units.

MERCHANT ENERGY

Our Merchant Energy segment consists of three divisions: global power,
petroleum and energy trading. Below are Merchant Energy's operating results and
an analysis of those results for the quarters ended March 31:

Global Power

Our global power division includes the ownership and operation of domestic
and international power generating facilities. We announced in April 2003 our
intent to pursue a sale of additional domestic power generation facilities. In
this regard, we have commenced a process to sell most of our domestic power
generation facilities. For a further discussion of our global power division,
see our 2002 Form 10-K. For a discussion of our Chaparral and Gemstone
investments, see Item 1, Financial Statements, Note 17. Results of our global
power division operations were as follows for the quarters ended March 31:

54

Gross margin consists of revenues from our power plants and the net results
from our power restructuring activities. The cost of fuel used in the power
generation process is included in operating expenses. For the quarter ended
March 31, 2003, our gross margin was $497 million lower than the same period in
2002. The decrease was due primarily to power contract restructurings for our
Eagle Point Cogeneration and Mount Carmel power plants that we completed in the
first quarter of 2002, which contributed $434 million to our gross margin in
2002, including an $80 million loss on a power supply agreement that we entered
into with our energy trading division in the first quarter of 2002 associated
with the Eagle Point Cogeneration restructuring transaction. The effects of this
power supply agreement were eliminated from Merchant Energy's consolidated
results. Contributing to the decrease in gross margin was a decrease of $33
million in 2003 power generation revenues primarily due to the shutdown of our
Eagle Point Cogeneration facility for maintenance in the first quarter of 2003.
Also contributing to the decrease was a $46 million management fee we received
from Chaparral in the first quarter of 2002. As a result of our planned
acquisition of the third party equity and resulting consolidation of Chaparral
in 2003, we will not receive management fees from Chaparral in 2003.

Operating expenses for the quarter ended March 31, 2003, were $59 million
lower than the same period in 2002. The decrease was due primarily to $19
million in turbine forfeiture fees we paid in 2002 as plans for future
construction of new power plants were reduced in 2002 and a decrease of $13
million in payroll, development and overhead costs resulting primarily from the
sale of power plants in 2002. Also contributing to this decrease was a $6
million decrease in operating costs related to the shutdown of our Eagle Point
Cogeneration facility for maintenance in 2003 and a $6 million decrease in
depreciation expense in 2003 primarily due to lower depreciation on our Eagle
Point Cogeneration facility.

Other expense for the quarter ended March 31, 2003, was $231 million lower
than the same period in 2002. This decrease was primarily due to impairment
charges on our Agua del Cajon, CAPSA/CAPEX and Costanera investments in
Argentina of $342 million in 2002. Also contributing to this decrease was a $90
million contract termination fee we paid to our petroleum division associated
with the termination of a steam contract between our Eagle Point Cogeneration
facility and the Eagle Point refinery in 2002 that was eliminated from Merchant
Energy's consolidated results. Further contributing to this decrease was an
increase in equity earnings of $12 million from Gemstone and $10 million from
Chaparral in 2003 and $52 million of minority interest expense recorded
primarily on our power contract restructurings during the first quarter of 2002.
Partially offsetting this decrease was a $207 million impairment we recorded on
our equity investment in Chaparral in the first quarter of 2003. Also partially
offsetting this decrease was a $86 million loss we recorded in the first quarter
of 2003 on the impairment of notes from our Milford equity investment and loss
accruals related to other associated contracts. These amounts are based on the
ongoing settlement negotiations related to this investment.

Petroleum

We announced in 2003 our intent to reduce our involvement in the LNG
business and exit substantially all of our petroleum businesses. We also
recently announced our intent to pursue the sale of our Aruba refinery, in which
we have a net investment of approximately $1.2 billion, excluding an operating
lease for a support facility that will be consolidated in the second quarter of
2003. It is likely that if we pursue a sale of Aruba in the near term, we will
not recover our full investment and could recognize an impairment or loss on the
sale. For a further discussion of our petroleum division, see our 2002 Form
10-K. Results of our petroleum division operations were as follows for the
quarters ended March 31:

55

Gross margin consists of revenues from our refineries and commodity trading
activities, less costs of the feedstocks used in the refining process and the
costs of commodities sold. For the quarter ended March 31, 2003, our gross
margin was $75 million higher than the same period in 2002. This increase
included higher refining margins of $37 million at our Aruba refinery due to
higher spreads between the sales prices of refined products and underlying
feedstock costs and $48 million at our Eagle Point refinery due to increased
processing volumes and higher spreads between the sales prices of refined
products and underlying feedstock costs. Also contributing to this increase was
a $7 million increase in the fair value of our LNG supply contract derivatives
compared to a $26 million decrease in the fair value of those contracts in 2002.
These increases were partially offset by lower petroleum trading margins of $41
million on domestic crude and products resulting from the decision to exit our
petroleum-related trading operations during 2003.

Operating expenses for the quarter ended March 31, 2003, were $389 million
higher than the same period in 2002. The increase was primarily due to a $350
million impairment of our Eagle Point refinery and our chemical assets in the
first quarter of 2003 resulting from our announced expectation that we will
dispose of these assets. Also contributing to this increase were $53 million of
costs incurred in 2003 associated with the reduction of our involvement in the
LNG business. Also contributing to this increase was a $28 million increase in
non-routine maintenance and other operating costs, primarily at our Aruba
facility, and $11 million of employee severance costs incurred in 2003.
Partially offsetting this increase was $56 million of net gains primarily from
the sale of our Corpus Christi refinery and Florida petroleum terminals and tug
and barge operations completed in 2003.

Other income for the quarter ended March 31, 2003, was $97 million lower
than the same period in 2002. This decrease was primarily due to a $90 million
contract termination fee we received from our global power division associated
with the restructuring of a steam contract between our Eagle Point refinery and
the Eagle Point Cogeneration facility in 2002, which was eliminated from
Merchant Energy's consolidated results.

Energy Trading

In November 2002, we announced that we would exit the energy trading
business due to the increasing and volatile cash demands inherent in that
business, which were magnified by our credit downgrade. In late 2002, we began
actively liquidating our trading portfolio and anticipate that this effort will
continue through 2004. During the first quarter of 2003, we liquidated
approximately 13,000, or 33 percent of the total number of forward positions
outstanding at December 31, 2002. We have also liquidated 96 Bcf of the 125 Bcf
of natural gas storage rights and 2.2 Bcf/day of our 4.4 Bcf/day of
transportation capacity that we owned in 2002. We also have completed the
liquidation of our European portfolio.

For a further discussion of our energy trading division, see our 2002 Form
10-K. Results of our energy trading division operations were as follows for the
quarters ended March 31:

Gross margin consists of revenues from commodity trading and origination
activities less the costs of commodities sold, including changes in the fair
value of our energy trading portfolio. For the quarter ended March 31, 2003,
gross margin was $209 million lower than the same period in 2002. This decrease
was due primarily to $107 million of losses we incurred in the first quarter of
2003 related to continued demand charges and hedges on our natural gas
transportation and storage capacity contracts and trading losses on our forward
trading portfolio. During the first quarter of 2003, we focused on managing our
energy trading portfolio to

56

lessen our exposure to cash collateral requirements. As a consequence, we did
not fully use contracted capacity on these transportation and storage contracts.
We also recorded $34 million of losses in 2003 associated with the early
termination of transactions related to our efforts to liquidate our energy
trading portfolio. Also contributing to this decrease was an $80 million gain
during 2002 on a power supply agreement that we entered into with our global
power division in the first quarter of 2002 associated with the Eagle Point
Cogeneration restructuring, which was eliminated from Merchant Energy's
consolidated results.

Operating expenses for the quarter ended March 31, 2003, were $8 million
higher than the same period in 2002 primarily due to $12 million of amortization
expense we recorded in the first quarter of 2003 associated with our Western
Energy Settlement.

Other income for the quarter ended March 31, 2003, was $14 million lower
than the same period in 2002. This decrease was primarily due to lower interest
income in 2003 resulting from lower average interest bearing balances in 2003.

FAIR VALUE OF PRICE RISK MANAGEMENT CONTRACTS AS OF MARCH 31, 2003

The following table details the net estimated fair value of our derivative
energy contracts (both trading and non-trading) by year of maturity and
valuation methodology as of March 31, 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. We classify all other derivative-related activities, including
those related to power restructuring and hedging activities, as non-trading
price risk management activities.

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

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

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

(3) Non-trading energy contracts include derivatives from our power contract
restructuring activities of $967 million and derivatives related to our
natural gas and oil producing activities of $(619) million. Earnings related
to the natural gas and oil producing derivative activities are included in
our Production segment results.

57

The income impacts of both our trading and non-trading price risk
management activities are included in all of the divisions of our Merchant
Energy segment and in our Production segment. A reconciliation of these trading
and non-trading activities for the quarter ended March 31, 2003, is as follows:

Our trading portfolio is reflected at its estimated fair value, which is
the amount at which the contracts in our portfolio could be bought or sold in a
current transaction between willing buyers and sellers. However, the value we
ultimately receive in settlement of our trading activities may be less than our
estimates. As discussed above, we are actively liquidating our trading
portfolio, which includes approximately 27,000 positions as of March 31, 2003.
We believe the net realizable value of our trading portfolio, if liquidated in
the timeframe set out in our exit plan, may be less than its currently estimated
fair value. Our belief is based on recent transactions completed at values below
estimated fair value and bids received on positions that were also below their
fair value. Additionally, a portion of the transactions that we plan to
liquidate are accounted for under the accrual method and are not recorded on our
balance sheet.

CORPORATE AND OTHER

Corporate and other net expenses, which include general and administrative
activities as well as the operations of our telecommunications and other
miscellaneous businesses, for the quarter ended March 31, 2003, were $62 million
higher than the same period in 2002. The increase was due to a $33 million
foreign currency loss resulting from the impact of foreign currency fluctuations
on our Euro-denominated debt in 2003 and employee severance costs of $13 million
in 2003. Also contributing to the increase were losses on the Lakeside
Technology Center facility in our telecommunications business, including an $8
million contingent loss in the first quarter of 2003 and a $3 million decrease
in rental revenue due to the loss of a significant tenant at the facility in
2002. Recently we announced our intent to sell or otherwise divest of our
telecommunications business in which we have a $375 million investment,
excluding the Lakeside Technology Center. It is likely that if we pursue a sale
or other arrangement to divest of this business in the near term, we will not
recover our full investment and we could incur an impairment or loss on the
sale. For a further discussion of our telecommunications business, see our 2002
Form 10-K. An $8 million loss on the sale of aircraft in the first quarter of
2003 also contributed to the increase.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter ended March 31, 2003, was $345
million, or $38 million higher than the same period in 2002. Below is an
analysis of our interest expense for the quarters ended March 31:

58

Interest expense on long-term debt for the quarter ended March 31, 2003,
was $53 million higher than the same period in 2002 due to higher average debt
balances. During 2003, we issued long-term debt of approximately $1.9 billion,
with an average interest rate of 11.1%, including the issuance of the $1.2
billion two-year term loan in March 2003. These issuances increased interest on
long-term debt by approximately $13 million. Also contributing to the increase
was $59 million of interest related to various debt issuances during 2002 that
were outstanding during the first quarter of 2003. Partially offsetting these
increases were our retirements of approximately $1.5 billion of long-term debt
during 2002 with an average interest rate of 6.8%, resulting in lower interest
expense of approximately $20 million.

Interest expense on short-term debt for the quarter ended March 31, 2003,
was $8 million higher than the same period in 2002. The increase was due to our
borrowings under the revolving credit facilities in December 2002 and in
February 2003. At March 31, 2003, our average revolving credit balance, which
was based on daily ending balances, was approximately $1.8 billion, with an
average interest rate of 2.7%. This increase was partially offset by the
discontinuation of commercial paper activities in 2003.

Other interest for the quarter ended March 31, 2003, was $26 million lower
than the same period in 2002. The decrease was due to the following: $14 million
related to a decrease in balances for various notes; $11 million resulting from
retirements of our other financing obligations; and an $8 million decrease due
to the reduction in trading activities and the elimination of the receivables
factoring program in the fourth quarter of 2002. These decreases were partially
offset by a $7 million increase as a result of write-off of unamortized issue
costs due to the retirement of the Trinity River financing arrangement in 2003.

Capitalized interest for the quarter ended March 31, 2003, was $3 million
lower than the same period in 2002 primarily due to the lower interest rates in
the first quarter of 2003 than the same period in 2002.

INCOME TAXES

Income tax benefit for the quarter ended March 31, 2003, was $133 million
resulting in an effective tax rate of 26 percent. Income tax expense for the
quarter ended March 31, 2002, was $118 million resulting in effective tax rate
of 32 percent. Our effective tax rates were different than the statutory rate of
35 percent primarily due to the following:

- state income taxes;

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

- foreign income taxed at different rates.

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Statements, Note 14, which is incorporated herein by
reference.

NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

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

59

CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS

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

- earnings per share;

- capital and other expenditures;

- dividends;

- financing plans;

- capital structure;

- liquidity and cash flow;

- credit ratings;

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

- future economic performance;

- operating income;

- management's plans; and

- goals and objectives for future operations.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

COMMODITY PRICE RISK

We measure risks on our portfolio of commodity and energy-related contracts
on a daily basis using a Value-at-Risk model. We no longer separately manage and
evaluate the Value-at-Risk associated with our trading and non-trading commodity
and energy-related contracts. We measure our portfolio's Value-at-Risk using the
historical simulation technique and we prepare it based on a confidence level of
95 percent and a one-day holding period. Our portfolio's Value-at-Risk was $15
million and $11 million as of March 31, 2003 and December 31, 2002, and
represents our potential one-day unfavorable impact on the fair values of our
commodity and energy-related contracts. The $4 million increase in our portfolio
Value-at-Risk was related to higher natural gas price volatility and our efforts
in the first quarter of 2003 to mitigate the cash flow impact of rising gas
prices on our trading portfolio. As we liquidate our trading portfolio, our
Value-at-Risk may vary more than in historical periods when we more actively
managed our positions using Value-at-Risk. As a result, our Value-at-Risk could
increase as we continue to exit this business.

60

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 (Internal Controls) within 90 days of the filing date of
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. 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. Further, 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, and there can be no assurance that any
design will succeed in achieving its stated goals under all potential future
conditions; over time, control may become inadequate because of changes in
conditions, or the degree of compliance with the policies or procedures may
deteriorate. Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be detected.

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, from the date of the controls evaluation to the date of this
Quarterly Report, there have been no significant changes in Internal Controls or
in other factors that could significantly affect Internal Controls, including
any corrective actions with regard to significant deficiencies and material
weaknesses.

Effectiveness of Disclosure Controls. Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that, subject to the limitations discussed above, 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, particularly during the
period when our periodic reports are being prepared.

61

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 herein, or as Exhibits to this
Quarterly Report, as appropriate.

62

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item 1, Financial Statements, Note 14, 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.

64

b. Reports on Form 8-K

We also furnished information to the SEC under Item 9, Regulation FD,
Current Reports on Form 8-K. Current Reports on Form 8-K under Item 9 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."

66

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: May 15, 2003 /s/ D. Dwight Scott
------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

Date: May 15, 2003 /s/ Jeffrey I. Beason
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

67

CERTIFICATION

I, Ronald L. Kuehn, Jr., certify that:

1. I have reviewed this quarterly report on Form 10-Q of El Paso
Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ RONALD L. KUEHN, JR.
--------------------------------------
Ronald L. Kuehn, Jr.
Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)
El Paso Corporation

Date: May 15, 2003

68

CERTIFICATION

I, D. Dwight Scott, certify that:

1. I have reviewed this quarterly report on Form 10-Q of El Paso
Corporation;

2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this quarterly
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this quarterly report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its consolidated
subsidiaries, is made known to us by others within those entities,
particularly during the period in which this quarterly report is being
prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of this
quarterly report (the "Evaluation Date"); and

c) presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to record,
process, summarize and report financial data and have identified for the
registrant's auditors any material weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's internal
controls; and

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ D. DWIGHT SCOTT
--------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)
El Paso Corporation

Date: May 15, 2003

69

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.