EL PASO CORP/DE - 10-Q Quarterly Report

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

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FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2002

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

Common stock, par value $3 per share. Shares outstanding on August 9,
2002: 584,848,649

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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 (SEC).
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 2001 Annual Report on
Form 10-K which includes a summary of our significant accounting policies and
other disclosures. The financial statements as of June 30, 2002, and for the
quarters and six months ended June 30, 2002 and 2001, are unaudited. We derived
the balance sheet as of December 31, 2001, from the audited balance sheet filed
in our Form 10-K. In our opinion, we have made all adjustments, all of which are
of a normal, recurring nature (except for the items discussed below and in Notes
3, 4, 5, 6 and 7 below), 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.

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

Goodwill and Other Intangible Assets

Our intangible assets consist primarily of goodwill resulting from
acquisitions. On January 1, 2002, we adopted Statement of Financial Accounting
Standards (SFAS) No. 141, Business Combinations, and SFAS No. 142, Goodwill and
Other Intangible Assets. These standards require that we recognize goodwill
separately from other intangible assets. In addition, goodwill and
indefinite-lived intangibles are no longer amortized. Instead, goodwill is
periodically tested for impairment, at least on an annual basis, or whenever an
event occurs that indicates that an impairment may have occurred. SFAS No. 141
requires that any negative goodwill should be written off as a cumulative effect
of an accounting change. Prior to adoption of these standards, we amortized
goodwill and other intangibles using the straight-line method over periods
ranging from 5 to 40 years. As a result of our adoption of these standards on
January 1, 2002, we stopped amortizing goodwill, and recognized a pretax and
after-tax gain of $154 million related to the write-off of negative goodwill. We
have reported this gain as a cumulative effect of an accounting change in our
income statement.

We completed our initial periodic impairment tests during the first quarter
of 2002, and concluded that we did not have any adjustment to our goodwill.
Amortization of goodwill and negative goodwill would have been approximately $7
million and $14 million, net of income taxes, for the quarter and six months
ended June 30, 2002 had we not adopted these standards. In addition, had we
applied the amortization provisions of SFAS No. 141 and 142 on January 1, 2001,
we would have reported the following amounts:

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Asset Impairments

On January 1, 2002, we adopted SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS No. 144 changed the accounting
requirements related to when an asset qualifies as held for sale or as a
discontinued operation and the way in which we evaluate impairments of assets.
It also changes accounting for discontinued operations such that we can no
longer accrue future operating losses in these operations. We applied SFAS No.
144 in accounting for our coal mining operations, which met all of the
requirements to be treated as discontinued operations in the second quarter of
2002. See Note 6 for further information.

Price Risk Management Activities

In the second quarter of 2002, we adopted Derivatives Implementation Group
(DIG) Issue No. C-15, Scope Exceptions: Normal Purchases and Sales Exception for
Certain Option-Type Contracts and Forward Contracts in Electricity. DIG Issue
C-15 requires that if an electric power contract includes terms that are based
upon market factors that are not related to the actual costs to generate the
power, the contract is a derivative that must be recorded at its fair value. An
example is a power sales contract at a natural gas-fired power plant that has
pricing indexed to the price of coal. Our adoption of these rules did not have a
material effect on our financial statements. The accounting for electric power
contracts as derivatives was not clearly addressed when SFAS No. 133, Accounting
for Derivatives and Hedging Activities, was adopted in January 2001. DIG Issue
No. C-15 and other DIG Issues have attempted to resolve inconsistencies in the
accounting for power contracts, and we believe the rules will continue to
evolve. It is possible that our accounting for these contracts may change as new
guidance is issued and existing rules are applied and interpreted.

In the second quarter of 2002, we also adopted DIG Issue No. C-16, Scope
Exceptions: Applying the Normal Purchases and Sales Exception to Contracts that
Combine a Forward Contract and Purchased Option Contract. DIG Issue C-16
requires that if a fixed-price fuel supply contract allows the buyer to
purchase, at their option, additional quantities at a fixed price, the contract
is a derivative that must be recorded at its fair value. One of our
unconsolidated affiliates, the Midland Cogeneration Venture Limited Partnership,
recognized a gain on one fuel supply contract upon adoption of these new rules,
and we recorded a gain of $14 million, net of income taxes, as a cumulative
effect of an accounting change in our income statement for our proportionate
share of this gain.

In June 2002, the Emerging Issues Task Force (EITF) reached a consensus in
EITF Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities, requiring that all mark-to-market gains and losses
related to energy trading contracts, including physical settlements, be recorded
in the income statement on a net basis instead of being reported on a gross
basis as revenues for physically settled sales and expenses for physically
settled purchases. We elected to adopt this consensus issue in the second
quarter, and now report our trading activity on a net basis as a component of
revenues. We have also applied this guidance to all prior periods, which had no
impact on previously reported net income or stockholders' equity. Revenues and
costs that have been netted as a result of adopting this consensus were as
follows:

The EITF continues to evaluate disclosure and valuation issues in its
ongoing deliberations on Issue No. 02-3, and we will monitor and assess the
impact of adopting these issues when and if a consensus is reached.

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Accounting for Power Restructuring Activities. Our Merchant Energy
segment's power restructuring activities involve amending or terminating a power
plant's existing power purchase contract to eliminate the requirement that the
plant provide power from its own generation to the regulated utility and
replacing that requirement with the ability to provide power to the utility from
the wholesale power market. Prior to a restructuring, the power plant and its
related power purchase contract are accounted for at their historical cost,
which is either the cost of construction or, if acquired, the acquisition cost.
Revenues and expenses prior to restructuring are, in most cases, accounted for
on an accrual basis as power is generated and sold to the utility. Following a
restructuring, the accounting treatment for the power purchase agreement changes
because the restructured contract must be marked to its fair value under SFAS
No. 133. In the period the restructuring is completed, the book value of the
restructured contract is adjusted to its fair value, with any change reflected
in income. Since the power plant no longer has the exclusive right to provide
power under the original, dedicated power purchase contract, it operates as a
peaking merchant plant, generating power only when it is economical to do so.
Because of this significant change in its use, in most cases the book value of
the plant is reduced to its fair value through a charge to earnings. These
changes require us to terminate or amend any related fuel supply and steam
agreements associated with the operations of the facility.

We conduct the majority of our power restructuring activities through our
unconsolidated affiliate, Chaparral, and therefore our share of the revenues and
expenses of these activities is recognized through earnings from unconsolidated
affiliates. However, as in the case of the Eagle Point Cogeneration
restructuring completed in the first quarter of 2002, we also conduct these
activities for power assets owned by our consolidated subsidiaries. In
consolidated entities, the restructured power contract is presented in our
balance sheet as an asset from price risk management activities. In our income
statement we present, as revenues, the original adjustment that occurs when the
contract is marked to fair value as a derivative, as well as subsequent changes
in the value of the contract. Costs associated with the restructuring activity,
including adjustments to the underlying power plant's book value and any related
intangible assets, contract termination fees and closing costs, are recorded in
our income statement as costs of products and services. Power restructuring
activities can also involve contract terminations that result in a cash payment
by the utility to cancel the underlying power contract, as in our Mount Carmel
transaction. We also employed the principles of our power restructuring business
in reaching a settlement of the dispute under our Nejapa power contract which
included a cash payment to us. We record these payments as revenues. During the
first six months of 2002, we recognized revenues from power restructuring and
contract termination activities of $1,103 million and corresponding costs of
$539 million, most of which occurred during the first quarter.

2. DIVESTITURES

In December 2001, we announced a plan to strengthen our balance sheet in
order to improve our liquidity in response to changes in market conditions in
our industry. A key component of that plan was the identification and sale of
assets.

In March 2002, we sold natural gas and oil properties located in east and
south Texas. Net proceeds from this sale were approximately $512 million. We did
not recognize a gain or loss on the properties sold since they were not
significant in terms of the total costs or reserves in our full cost pool of
properties.

In April 2002, we sold midstream assets for approximately $735 million to
El Paso Energy Partners, L.P., a publicly traded master limited partnership of
which our subsidiary serves as the general partner. Net proceeds from this sale
were approximately $539 million in cash, common units of El Paso Energy Partners
with a fair value of $6 million and the partnership's interest in the Prince
tension leg platform including its nine percent overriding royalty interest in
the Prince production field with a combined fair value of $190 million. No gain
or loss was recognized on this sale.

In May and June 2002, we completed sales of natural gas and oil properties,
a natural gas gathering system and a natural gas plant. Net proceeds from these
sales were approximately $325 million. We recognized a gain of $10 million, $6
million after taxes, on the natural gas gathering system and the plant. This
gain was recorded on our income statement in net gain on sale of assets.

8

We have also announced the sales of additional assets to El Paso Energy
Partners, L.P., including $782 million of onshore and offshore natural gas and
oil gathering systems, natural gas liquids transportation and fractionation
assets, and $133 million of natural gas and oil production properties and
related contracts and natural gas gathering systems. The sale of the natural gas
and oil production properties was completed in July 2002, and no gain or loss
was recognized. The remaining asset sales are expected to occur by the end of
the fourth quarter of 2002.

3. RESTRUCTURING AND MERGER-RELATED COSTS AND ASSET IMPAIRMENTS

Our organizational restructuring and merger-related costs and asset
impairments for the periods ended June 30 consisted of the following:

Restructuring Costs

In December 2001, we announced a plan to strengthen our balance sheet,
reduce costs and focus our activities on our core natural gas businesses. During
the second quarter of 2002, we incurred $63 million of costs related to these
efforts. In May 2002, we completed an employee restructuring across all of our
operating segments which resulted in a reduction of approximately 353 full-time
positions through terminations. In connection with this, we incurred $23 million
of employee severance and termination costs. As of June 30, 2002, we had paid $8
million of this charge, and the remainder will be paid in the third quarter of
2002. Employee severance costs included severance payments and costs for pension
benefits settled and curtailed under existing benefit plans. We also incurred
fees of $40 million to eliminate stock price and credit rating triggers related
to our Gemstone and Chaparral investments. See Note 15 for further information
on the Chaparral and Gemstone amendments.

Merger-Related Costs

On January 29, 2001, we merged with The Coastal Corporation in a merger
that was accounted for as a pooling of interests. The following are costs we
incurred related to the merger:

Employee severance, retention and transition costs include direct payments
to, and benefit costs for, terminated employees and early retirees that occurred
as a result of our merger-related workforce reduction and consolidation.
Following the Coastal merger, we completed an employee restructuring across all
of our operating segments, reducing 3,285 full-time positions through a
combination of early retirements and terminations. Employee severance costs
include severance payments and costs for pension and post-retirement benefits
settled and curtailed under existing benefit plans as a result of this
restructuring. Retention charges

9

include payments to employees who were retained following the merger and
payments to employees to satisfy contractual obligations. Transition costs
relate to costs to relocate employees and costs for terminated and retired
employees arising after their severance date to transition their job
responsibilities to the ongoing workforce. The amount of employee severance,
retention and transition costs paid and charged against the accrued amount for
the six months ended June 30, 2001, was approximately $342 million. The pension
and post retirement benefits were accrued at the merger date and will be paid
over the applicable benefit periods of the terminated and retired employees. The
rest of the charges were paid during the remainder of 2001.

Also included in employee severance, retention and transition costs for the
six months ended June 30, 2001, was a charge of $278 million resulting from the
issuance of approximately 4 million shares of common stock incurred on the date
of the Coastal merger in exchange for the fair value of Coastal employees' and
directors' stock options.

Transaction costs include investment banking, legal, accounting, consulting
and other advisory fees incurred to obtain federal and state regulatory
approvals and take other actions necessary to complete our merger. All of these
items were expensed as incurred.

Business and operational integration costs include charges to consolidate
facilities and operations of our business segments, such as lease termination
and abandonment charges and incremental fees under software and seismic license
agreements. These charges were accrued at the time we completed our relocations
and closed these offices. The amounts accrued will be paid over the term of the
applicable non-cancelable lease agreement. All other costs were expensed as
incurred.

Merger-related asset impairments relate to write-offs or write-downs of
capitalized costs for duplicate systems, and facilities and assets whose value
was impaired as a result of decisions on the strategic direction of our combined
operations following our merger with Coastal. These charges occurred in our
Merchant Energy, Pipelines and Production segments, and all of these assets have
either had their operations suspended or continue to be held for use. The
charges taken were based on a comparison of the cost of the assets to their
estimated fair value to the ongoing operations based on the change in operating
strategy.

Other costs include payments made in satisfaction of obligations arising
from the Federal Trade Commission (FTC) approval of our merger with Coastal and
other miscellaneous charges. These items were expensed as incurred.

Asset Impairments

During the first quarter of 2002, we recognized an asset impairment charge
in our Merchant Energy segment of $342 million related to our investments in
Argentina. During the latter part of 2001, economic conditions in Argentina
deteriorated, and the Argentine government defaulted on its public debt
obligations. In the first quarter of 2002, the government changed several
Argentine laws, including:(i) repealing the one-to-one exchange rate for the
Argentine Peso with U.S. dollar; (ii) mandating that all Argentine contracts and
obligations previously denominated in U.S. dollars be re-negotiated and
denominated in Argentine Pesos; and (iii) imposing a tax on crude oil exports.
The Argentine Peso devaluation combined with these new law changes effectively
converted our projects' contracts and sources of revenue from U.S. dollars to
Argentine Pesos and resulted in the impairment charge, which represents the full
amount of each of the investments impacted by these law changes. We have a
remaining investment in a pipeline project in Argentina with an aggregate
investment of approximately $39 million. Should these conditions persist, or if
new unfavorable developments occur, we may also be required to evaluate our
remaining investment for impairment. We continue to monitor the situation
closely, including our rights and remedies under applicable law, treaties and
political risk policies arising from the emergency measures taken in Argentina.

During the second quarter of 2001, we recorded other asset impairment
charges of $107 million. These charges consisted of a $60 million write-down
primarily of our investment in a telecommunications company in Brazil, and
charges of $47 million primarily related to Merchant Energy's impairment of its
East Asia Power investment in the Philippines. These write-downs were a result
of weak economic conditions causing a permanent decline in the value of these
investments. We continue to hold these investments.

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4. CHANGES IN ACCOUNTING ESTIMATES

Included in our operation and maintenance costs for the quarter and six
months ended June 30, 2001, were approximately $203 million in costs related to
changes in estimates. They consist of $159 million of additional environmental
remediation liabilities and a $44 million charge to reduce the value of our
spare parts inventories to reflect changes in the usability of these parts in
our worldwide operations. Both charges arose as a result of an ongoing
evaluation of our operating standards and plans following our merger with
Coastal and our combined operating strategy. These changes in estimates reduced
our after-tax earnings by approximately $138 million.

5. CEILING TEST CHARGES

Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to evaluate 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. As of June 30, 2002, we recorded ceiling test charges of
$267 million, of which $33 million was charged during the first quarter and $234
million during the second quarter. The write-down includes $226 million for our
Canadian full cost pool, $24 million for our Turkish full cost pool, $10 million
for our Brazilian full cost pool and $7 million for Australia and other
international production operations. The charge for the Canadian full cost pool
primarily resulted from a low daily posted price for natural gas at the end of
the second quarter, which was approximately $1.43 per million British thermal
units.

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

6. DISCONTINUED OPERATIONS

In June 2002, our Board of Directors authorized the sale of our coal mining
operations. These operations, which have historically been included in the
operations of our Merchant Energy segment, consist of fifteen active underground
and two surface mines located in Kentucky, Virginia and West Virginia. We expect
to complete the sale of these operations before the end of 2002. Following the
authorization of the sale by our Board of Directors, we compared the carrying
value of the underlying assets to our estimated sales proceeds, net of estimated
selling costs, based on bids received in the sales process. Because this
carrying value was higher than our estimated net sales proceeds, we recorded a
charge of $148 million, which has been included in our total loss from
discontinued operations in the second quarter of 2002.

11

Our coal mining operations have been classified as discontinued operations
in our financial statements for all periods presented. In addition, we
reclassified all of the assets and liabilities of our coal mining operations as
of June 30, 2002, as current assets and liabilities since we plan to sell them
in the next twelve months. The summarized financial results of discontinued
operations are as follows:

7. EXTRAORDINARY ITEMS

Under an FTC order, as a result of our January 2001 merger with Coastal, we
sold our Midwestern Gas Transmission system, our Gulfstream pipeline project,
our 50 percent interest in the Stingray and U-T Offshore pipeline systems, and
our investments in the Empire State and Iroquois pipeline systems. For the
quarter and six months ended June 30, 2001, net proceeds from these sales were
approximately $135 million and $279 million, and we recognized extraordinary net
gains of approximately $41 million and $31 million, net of income taxes of
approximately $23 million and $22 million.

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8. EARNINGS PER SHARE

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

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(1) Due to their antidilutive effect on earnings (loss) per common share, for
2002, we excluded a total of 16 million shares for the assumed conversion of
trust preferred securities and convertible debentures, and for 2001, we
excluded a total of 27 million shares for the assumed conversion of stock
options, restricted stock, FELINE PRIDES(SM), trust preferred securities and
convertible debentures.

13

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

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(1) Due to their antidilutive effect on earnings (loss) per common share, for
2002, we excluded a total of 16 million shares for the assumed conversion of
trust preferred securities and convertible debentures, and for 2001, we
excluded a total of 25 million shares for the assumed conversion of stock
options, restricted stock, preferred stock, FELINE PRIDES(SM), trust
preferred securities and convertible debentures.

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9. 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 June 30, 2002 and
December 31, 2001:

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(1) Trading contracts represent those that qualify for accounting under EITF
Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities.

(2) Non-trading contracts include hedges related to our oil and natural gas
producing activities and derivatives from our power contract restructuring
activities.

(3) We do no recognize gains on the fair value of trading or non-trading
positions beyond ten years unless there is clearly demonstrated liquidity in
a specific market.

Included in other derivatives as of June 30, 2002, are $979 million of
derivative contracts related to the power restructuring activities of our
consolidated subsidiaries. Of this amount, $882 million relates to a power
restructuring that occurred during the first quarter of 2002 at our Eagle Point
Cogeneration power plant, and $97 million relates to a 2001 power restructuring
at our Capitol District Energy Center Cogeneration Associates plant. The
remaining balance in other derivatives, an unrealized loss of $13 million,
relates to derivative positions that no longer qualify as cash flow hedges under
SFAS No. 133 because they were designated as hedges of anticipated future
production on natural gas and oil properties in east and south Texas that were
sold in the first quarter of 2002.

The fair value of the derivatives related to our power restructuring
activities is determined based on the expected cash receipts and payments under
the contracts using future power prices compared to the contractual prices under
these contracts. We discount these cash flows at an interest rate commensurate
with the term of each contract and the credit risk of each contract's
counterparty. We also adjust our valuations for factors such as market
liquidity, market price correlation and model risk, as needed. Future power
prices are based on the forward pricing curve of the appropriate power delivery
and receipt points in the applicable power market. This forward pricing curve is
derived from a combination of actual prices observed in the applicable market,
price quotes from brokers and extrapolation models that rely on actively quoted
prices and historical information. The timing of cash receipts and payments are
based on the expected timing of power delivered under these contracts. The fair
value of our derivatives is updated each period based on changes in actual and
projected market prices, fluctuations in the credit ratings of our
counterparties, significant changes in interest rates, and changes to the
assumed timing of deliveries.

In May 2002, we announced a plan to reduce the volumes of natural gas that
we have hedged for our Production segment. We removed the hedging designation on
derivatives with a fair value loss of $61 million in May 2002. This amount, net
of income taxes of $23 million, is reflected in accumulated other comprehensive
income and will be reclassified to income as the original hedged transactions
are settled through 2004. Of the net loss of $38 million in accumulated other
comprehensive income, we estimate that unrealized gains of $7 million, net of
income taxes, related to these derivatives will be reclassified to income over
the next twelve months.

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10. INVENTORY

Our inventory consisted of the following:

11. DEBT AND OTHER CREDIT FACILITIES

At June 30, 2002, our weighted average interest rate on our commercial
paper and short-term credit facilities was 2.7%, and at December 31, 2001, it
was 3.2%. We had the following short-term borrowings and other financing
obligations:

Our significant borrowing and repayment activities during 2002 are
presented below. These activities do not include borrowings or repayments on our
short-term financing instruments with an original maturity of three months or
less, including our commercial paper programs and short-term credit facilities.

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Issuances

Retirements

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(1) These notes are collateralized solely by the cash flows and contracts of
these consolidated subsidiaries, and are non-recourse to other El Paso
companies. The Mohawk River Funding IV financing relates to our Capitol
District Energy Center Cogeneration Associates restructuring transaction and
the Utility Contract Funding financing relates to our Eagle Point
Cogeneration restructuring transaction.

(2) Represents the U.S. dollar equivalent of 500 million Euros at June 30, 2002,
and includes a $45 million change in value due to a change in the Euro to
U.S. dollar foreign currency exchange rate from the issuance date to June
30, 2002.

(3) These senior notes relate to an offering of 11.5 million 9% equity security
units, which consist of forward purchase contracts on El Paso common stock
to be settled on August 16, 2005. See Note 13 for further discussion.

(4) We have committed to exchange these notes for new registered notes. The form
and terms of the new notes will be identical in all material respects to the
form and terms of these old notes except that the new notes (1) will be
registered with the Securities and Exchange Commission, (2) will not be
subject to transfer restrictions and (3) will not be subject, under certain
circumstances, to an increase in the stated interest rate.

(5) These amounts represent a buyback of our bonds in the open market in July
and August 2002.

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In May 2002, we renewed our $3 billion, 364-day revolving credit and
competitive advance facility. El Paso Natural Gas Company (EPNG) and Tennessee
Gas Pipeline Company (TGP), our subsidiaries, remain designated borrowers under
this facility. This facility matures in May 2003. In June 2002, we amended our
existing $1 billion, 3-year revolving credit and competitive advance facility to
permit us to issue up to $500 million in letters of credit and to adjust pricing
terms. This facility matures in August 2003, and El Paso CGP, EPNG and TGP are
designated borrowers under this facility. The interest rate under both of these
facilities varies based on our senior unsecured debt rating, and as of June 30,
2002, an initial draw would have had a rate of LIBOR plus 0.625%, plus a 0.25%
utilization fee for drawn amounts above 25% of the committed amounts. As of June
30, 2002, there were no borrowings outstanding, and we have issued $450 million
of letters of credit under the $1 billion facility.

12. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

We and several of our subsidiaries were named defendants in eleven
purported class action, municipal or individual lawsuits, filed in California
state courts (a list of the California cases is included in Part II, Item 1,
Legal Proceedings). The eleven 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. The
lawsuits have been consolidated before a single judge and are at the preliminary
pleading stages with trial not anticipated until late 2003 at the earliest. We
and our directors also have been named in a shareholder derivative action,
contending that our directors failed to prevent the conduct alleged in several
of these lawsuits. The derivative suit originally was filed in California, but
was dismissed and refiled in Texas in March 2002. In addition, one of our
subsidiaries also has been named a defendant in two lawsuits challenging the
validity of long-term power contracts entered into by the California Department
of Water Resources in early 2001. Our costs and legal exposure related to these
lawsuits and claims are not currently determinable.

In September 2001, we received a civil document subpoena from the
California Department of Justice, seeking information said to be relevant to the
Department's ongoing investigation into the high electricity prices in
California. We have produced and expect to continue to produce materials under
this subpoena.

Beginning in July 2002, several purported shareholder class action suits
alleging violations of federal securities laws have been filed against us and
several of our officers in federal court in Houston (a list of these suits is
included in Part II, Item 1, Legal Proceedings). The suits generally challenge
the accuracy or completeness of press releases and other public statements made
during 2001 and 2002.

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
Proposed Violation to EPNG. The Notice alleged five probable violations of its
regulations (a list of the alleged five probable violations is included in Part
II, Item 1, Legal Proceedings), proposed fines totaling $2.5 million and
proposed corrective actions. In October 2001, EPNG filed a detailed response
with the Office of Pipeline Safety disputing each of the alleged violations. If
we are required to pay the proposed fines, it will not have a material adverse
effect on our financial position, operating results or cash flows. We are
cooperating with the National Transportation Safety Board in an investigation
into the facts and circumstances concerning the possible causes of the rupture.
In addition, a number of personal injury and wrongful death lawsuits were filed
against us in connection with the rupture. Several of these suits have been
settled, with payments fully covered by insurance. Seven Carlsbad lawsuits
remain, with one of the seven having reached a contingent settlement within
insurance coverage (a list of the remaining Carlsbad lawsuits is included in
Part II, Item 1, Legal Proceedings).

18

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. 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.

A number of our subsidiaries were named 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. 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 Quinque
complaint was transferred to the same court handling the Grynberg complaint and
has now been sent back to Kansas State Court for further proceedings. A motion
to dismiss this case is pending.

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 five such lawsuits in New York.
Our costs and legal exposure related to these lawsuits and claims are not
currently determinable.

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

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of June 30, 2002, we had reserves totaling $100 million for all outstanding
legal matters, including $1 million reserved for our discontinued coal mining
operations.

While the outcome of our outstanding legal matters cannot be predicted with
certainty, based on the information known to date 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. As
new information 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.

Environmental Matters

We are subject to extensive federal, state and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require us to remove or remedy the effect on the environment of the
disposal or release of specified substances at current and former operating
sites. As of June 30, 2002, we had a reserve of approximately $521 million,
including approximately $492 million for expected remediation costs and
associated onsite, offsite and groundwater technical studies, which we
anticipate incurring through 2027 and approximately $29 million for related
environmental litigation costs. The reserve includes $15 million for
discontinued coal operations. In addition, we expect to make capital
expenditures for environmental matters of approximately $318 million in the
aggregate for the years 2002 through 2007. These expenditures primarily relate
to compliance with clean air regulations.

Since 1988, our subsidiary, TGP, has been engaged in an internal project to
identify and deal with 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, to ensure that its efforts meet regulatory
requirements. 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

19

remediation activities. TGP is also working with the Pennsylvania and New York
environmental agencies regarding remediation and post-remediation activities at
the Pennsylvania and New York stations.

In 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 agreed orders with the agency to resolve many of the
issues raised in the complaint and received water discharge permits from the
agency for its Kentucky compressor stations. The relevant Kentucky compressor
stations are being characterized and remediated under the 1994 consent order
with the EPA. Despite these remediation efforts, the agency may raise additional
technical issues or require additional remediation work in the future.

In May 1995, following negotiations with its customers, TGP filed an
agreement with the Federal Energy Regulatory Commission (FERC) that established
a mechanism for recovering a substantial portion of the environmental costs
identified in its internal remediation project. The agreement, which was
approved by the FERC in November 1995, provided for a PCB surcharge on firm and
interruptible customers' rates to pay for eligible costs under the PCB
remediation project, with these surcharges to be collected over a defined
collection period. TGP has twice received approval from the FERC to extend the
collection period, which is now currently set to expire in June 2004. The
agreement also provided for bi-annual audits of eligible costs. As of June 30,
2002, TGP has over-collected PCB costs by approximately $113 million for which
it has established a non-current liability. The over-collection will be reduced
by future eligible costs incurred for the remainder of the remediation project.
TGP is required to refund to its customers the over-collection amount to the
extent actual eligible expenditures are less than amounts collected. Presently,
TGP estimates the future refund obligation, at the conclusion of the remediation
process, to be approximately $50 million.

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. 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 New Jersey Department of Environmental Protection has
assessed penalties totaling approximately $1.1 million for these alleged
violations. Our Eagle Point refinery has been granted an administrative hearing
on issues raised by the assessments and, currently, is in negotiations to settle
these assessments.

In February 2002, we received a Notice of Violation from the EPA alleging
noncompliance with the EPA's fuel regulations from 1996 to 1998. The notice
proposes a penalty of $165,000 for these alleged violations. We are
investigating the allegations and have prepared a response.

We have been designated and 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 54 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 CERCLA sites, as appropriate, through indemnification by third
parties and settlements which provide for payment of our allocable share of
remediation costs. As of June 30, 2002, we have estimated our share of the
remediation costs at these sites to be between $31 million and $170 million and
have provided reserves that we believe are adequate for such costs. 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.

20

While the outcome of our outstanding environmental matters cannot be
predicted with certainty, based on the information known to date 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. It is possible that new information or future developments could
require us to reassess our potential exposure related to 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 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. For a further
discussion of specific environmental matters, see Legal Proceedings above.

Rates and Regulatory Matters

In April 2000, the California Public Utilities Commission (CPUC) filed a
complaint with the FERC alleging that the sale of approximately 1.2 billion
cubic feet per day of California capacity by EPNG to El Paso Merchant Energy
Company, both of whom are our wholly-owned subsidiaries, was anticompetitive and
an abuse of the affiliate relationship under the FERC's policies. Other parties
in the proceeding requested that Merchant Energy pay back any profits it earned
under the contract. In March 2001, the FERC established a hearing, before an
administrative law judge, to address the issue of whether EPNG and/or Merchant
Energy had market power and, if so, had exercised it. In October 2001, a FERC
administrative law judge issued a proposed decision finding that El Paso did not
exercise market power and that the market power portion of the CPUC's complaint
should be dismissed. However, the decision did find that El Paso had violated
the FERC's marketing affiliate regulations. In October 2001, the Market
Oversight and Enforcement section of the FERC's Office of the General Counsel
filed comments in this proceeding stating that record development at the trial
was inadequate to conclude that EPNG and Merchant Energy complied with the
FERC's regulations. In December 2001, the FERC remanded the proceeding to the
administrative law judge for a supplemental hearing on the availability of
EPNG's pipeline capacity. The hearing commenced on March 21, 2002, and concluded
on April 4, 2002. Oral arguments were held on April 10, 2002. A post-hearing
briefing was completed on June 5, 2002, and an administrative law judge's ruling
is expected soon.

In late 1999, several of EPNG's customers filed complaints requesting that
the FERC order EPNG to stop selling primary firm delivery point capacity at the
Southern California Gas Company Topock delivery point in excess of the
downstream capacity available at that point and to stop overselling firm
mainline capacity on the east-end of its mainline system. Several conferences
and meetings were held during the summer of 2000. They failed to produce a
settlement. In October 2000, the FERC ordered EPNG to make a one time allocation
of capacity at the Southern California Gas Company Topock delivery point among
affected firm shippers, but deferred action on east-end and system wide capacity
allocation issues. In February 2001, the FERC accepted EPNG's tariff filing
affirming the results of the Topock delivery point allocation process and
directed EPNG to formulate a system-wide capacity allocation methodology to be
addressed in EPNG's Order No. 637 proceeding. In March 2001, EPNG filed its
proposed system-wide allocation methodology with the FERC. In April 2001, the
February 2001 order was appealed by a customer to the U.S. Court of Appeals for
the 9th Circuit, which dismissed the appeal in its entirety on July 22, 2002. In
July 2001 and August 2001, technical conferences were conducted by the FERC on
EPNG's system-wide capacity allocation proposal, after which the parties
submitted position papers to the FERC regarding the appropriate method for
allocating receipt point capacity on EPNG's system.

Two groups of EPNG's customers, those within California and those east of
California, have filed complaints against EPNG with the FERC. In July 2001,
twelve parties composed of California customers, natural gas producers and
natural gas marketers, filed a complaint alleging that EPNG's full requirements
contracts with its east of California customers should be converted to contracts
with specific volumetric entitlements, that EPNG should be required to expand
its interstate pipeline system and that firm shippers who experience reductions
in their nominated gas volumes should be awarded demand charge credits. Also, in
July 2001, ten parties, most of which are east of California full requirements
contract customers, filed a complaint against EPNG with the FERC, alleging that
EPNG violated the Natural Gas Act of 1938 and

21

breached its contractual obligations by failing to expand its system in order to
serve the needs of the full requirements contract shippers. The complainants
requested that the FERC require EPNG to show cause why it should not be required
to augment its system capacity. On May 31, 2002, the FERC issued an order in
which it required, among other things that:

- EPNG's full requirements contracts, except those with its small volume
customers, be converted to contract demand (CD) contracts, i.e.,
contracts with maximum volumetric entitlements;

- CD customers be assigned specific receipt point rights, thereby replacing
system-wide receipt points on EPNG's system;

- EPNG file an application to add compression to its Line 2000 project,
thereby adding up to 320 million cubic feet per day of additional
capacity to its system;

- EPNG allow its California delivery points to be utilized as receipt
points on a secondary firm basis for the benefit of markets east of
California;

- EPNG's 1996 rate settlement remain in effect for the remainder of its
term, except as necessary to effectuate the changes required by the
order;

- EPNG be required to give demand charge credits when EPNG is unable,
except for reasons of force majeure, to schedule confirmed, firm
nominations; and

- EPNG refrain from entering into new firm contracts until it has
demonstrated that it has adequate capacity on its system to do so.

The Order established November 1, 2002, as the date on which the new CD
contracts, demand charge credits, and receipt point entitlements will go into
effect. On July 1, 2002, a number of parties to the proceedings filed requests
for rehearing of various aspects of the order. Also on July 1, 2002, EPNG filed
a request for clarification of the details involved in implementing the
requirements of the order. At its July 17, 2002 open meeting, the FERC
reaffirmed that the parties had until July 31, 2002, to establish capacity
allocation levels among themselves on a voluntary basis and, absent any such
voluntary agreement, the FERC itself will establish capacity levels by customer.
On July 30, 2002, at the request of several parties, the FERC extended the
deadline for the full requirements customers to bid for capacity turned back by
other shippers to August 9, 2002. On that date, we received several bids from
California shippers. The full requirements shippers, however, did not submit
bids, taking the position that the turnback process could not go forward until
the FERC had issued an order resolving disputes regarding the allocation to them
of unsubscribed capacity on the system. In our report to the FERC dated August
1, 2002, we advised the FERC that, in order to move the conversion process from
full requirements to CD service forward, it appears that the FERC will be
required to issue an order establishing entitlements for the full requirements
shippers to our unsubscribed, sustainable capacity. EPNG's customers
subsequently filed responses disputing the basis upon which EPNG believes
capacity on its system must be allocated. Although we and our customers have
worked diligently to achieve an allocation of unsubscribed capacity among the
full requirements shippers who are being required to convert to CD service, the
full requirements shippers and the pipeline continue to hold a different view as
to how this allocation should be accomplished. The needs of the full
requirements shippers can be met through a combination of unsubscribed capacity,
California receipt rights, turnback capacity from other shippers, and an
appropriately sized expansion.

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, at which
interested parties were given an opportunity to comment further on the NOPR.
Following the conference, additional comments were filed by our pipeline
subsidiaries and others. We cannot predict the outcome of the NOPR, but adoption
of the regulations in substantially the form proposed would, at a minimum, place
additional administrative and operational burdens on us.

22

On July 17, 2002, the FERC issued a Notice of Inquiry (NOI) that seeks
comments regarding its policy, established in 1996, 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 undertaking a review
of whether negotiated rates should be capped, whether or not a pipeline's
"recourse rate" (its cost of service based rate) continues to serve as a viable
alternative and safeguard against the exercise of alleged pipeline market power,
as well as other issues related to its negotiated rate program. Comments are due
on September 25, 2002, with reply comments due on October 25, 2002. We cannot
predict the outcome of this NOI.

On August 1, 2002, the FERC issued a NOPR requiring that all arrangements
concerning the 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 must maintain a minimum proprietary capital balance of 30 percent, and
the FERC regulated entity and its parent must maintain investment grade credit
ratings. Comments on the NOPR are due on August 22, 2002. We cannot predict the
outcome of this NOPR.

Also on August 1, 2002, the FERC's Chief Accountant issued, to be effective
immediately, an Accounting Release providing guidance on how jurisdictional
entities should account for money pool arrangements and the types of
documentation that should be maintained for these arrangements. The Accounting
Release sets forth the documentation requirements set forth in the NOPR for
money pool arrangements, but does not address the requirements in the NOPR that
as a condition for participating in money pool arrangements the FERC regulated
entity must maintain a minimum proprietary capital balance of 30 percent and
that the entity and its parent must have investment grade credit ratings.
Requests for rehearing are due on September 3, 2002.

In June 2001, the Western Australia regulators issued a draft rate decision
at lower than expected levels of rates for the Dampier-to-Bunbury pipeline owned
by EPIC Energy Australia Trust, in which we have a 33 percent ownership interest
and a total investment, including financial guarantees, of approximately $198
million. EPIC Energy Australia has appealed a variety of issues related to the
draft decision to the Western Australia Supreme Court. The appeal was heard at
the Western Australia Supreme Court in November 2001, and a decision from the
court is expected in the second half of 2002. If the draft decision rates are
implemented, the new rates will adversely impact future operating results,
liquidity and debt capacity, possibly reducing the value of our investment by up
to $138 million. Additionally, EPIC Energy (WA) Nominees Pty. Ltd. has debt of
approximately AUD$1.8 billion (U.S.$1 billion) maturing in March 2003. Possible
delays in the timing of the Supreme Court decision and uncertainty of the future
rates may impact this refinancing.

We are engaged in arbitration 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 anticipate a
determination from the Public Utilities Commission (PUC) of Texas on the
administrative law judge's recommendation in the fourth quarter of 2002. 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 impact our metro transport business. An adverse resolution to
the arbitration proceeding by the PUC could have a negative impact on our
ongoing operations and prospects in this business.

El Paso Merchant Energy L.P. (EPME), our subsidiary, responded on May 22,
2002 to the FERC's May 8, 2002 request for statements of admission or denial
with respect to trading strategies designed to manipulate California power
markets. EPME provided an affidavit stating that it had not engaged in these
trading strategies.

On May 21 and 22, 2002, the FERC issued additional data requests, including
requests for statements of admission or denial with respect to so-called "wash"
or "round trip" trades in western power and gas markets.
23

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 grand jury subpoena for documents concerning round trip or wash
trades. We are conducting due diligence and plan to cooperate fully with these
requests.

While the outcome of our rates and regulatory matters cannot be predicted
with certainty, based on the information known to date 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. As new information 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.

Other Commercial Commitments

In 2001, we entered into agreements to time-charter four separate ships to
secure transportation for our developing LNG business. In May 2002, we entered
into amendments to three of the initial four time charters to reconfigure the
ships with onboard regasification technology and to secure an option for an
additional time charter for a fifth ship. The exercise of the option for the
fifth ship will represent a commitment of $522 million over the term of such
charter. However, we are obligated to pay a termination fee of $24 million in
the event the option is not exercised by April 2003. The agreements provide for
deliveries of vessels between 2003 and 2005. Each time charter has a twenty-year
term commencing when the vessels are delivered with the possibility of two
five-year extensions. The total commitment under the five time-charter
agreements is approximately $2.5 billion over the term of the time charters. We
are party to an agreement with an unaffiliated global integrated oil and gas
company under which the third party agrees to bear 50 percent of the risk
incidental to the initial $1.8 billion commitment made for the first four time
charters.

Other Matters

In December 2001, Enron Corp. and a number of its subsidiaries, including
Enron North America Corp. and Enron Power Marketing, Inc., filed for Chapter 11
bankruptcy protection in the United States Bankruptcy Court for the Southern
District of New York. We had contracts with Enron North America, Enron Power
Marketing and other Enron subsidiaries for, among other things, the
transportation of natural gas and natural gas liquids, the trading of physical
gas, power, petroleum and financial derivatives. We established reserves for
potential losses related to the receivables from our transportation contracts,
as well as the positions and receivables under our marketing and trading
contracts that we believe are adequate. In addition, we have terminated most of
our trading-related contracts, and Enron has rejected many of its capacity
contracts on our pipeline systems. We believe our termination of the trading
contracts was proper and in accordance with the terms of these contracts. We,
like other creditors, are discussing with Enron the extent of our damage claims
against various Enron entities.

Affiliates of Enron hold both short-term and long-term capacity on several
of our pipeline systems. While some transportation contracts between various
Enron entities with EPNG or TGP have been rejected, we are uncertain as to
Enron's intent to maintain or release capacity associated with contracts on
other El Paso pipeline entities and also Enron's ability to honor the terms of
their contracts. The Court has established August 19, 2002, as the deadline for
Enron to assume or reject contracts with some of our subsidiaries. Future
revenue related to these capacity contracts will depend upon the outcome of
Enron's bankruptcy proceedings and our pipelines' ability to re-market or
otherwise maximize the value of the rejected or released capacity. We do not
presently know the precise values that will be received by our pipelines as a
result of these efforts.

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

24

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.

In May 2002, due to the contracting party's failure to meet its contractual
obligations, El Paso Global Networks Company (EPGN) terminated a series of
agreements with a third party, which provided for construction and maintenance
of a fiber optic telecommunications system. The third party disputed EPGN's
right to terminate the agreements. Subsequently, EPGN notified the third party
of its intent to arbitrate a resolution to the agreements. Arbitration hearings
are expected to commence in the third quarter of 2002. Although the outcome of
the arbitration or any subsequent litigation is uncertain, the final result
could have a material impact on the value of our fiber optic route from Houston,
Texas to Los Angeles, California, in which we had invested capital of $109
million at June 30, 2002.

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 the second quarter
of 2002, Brazil experienced a significant decline in its financial markets due
largely to concerns over the refinancing of Brazil's foreign debt and the
upcoming presidential election. These concerns have contributed to 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 22% devaluation of the local currency against the U.S. dollar during the
second quarter of 2002. These developments are likely to delay the
implementation of project financings underway in Brazil. The International
Monetary Fund recently announced a $30 billion loan package for Brazil, however
the release of the majority of the money will depend on Brazil committing to
specified fiscal targets in 2003. We currently believe that the economic
difficulties in Brazil will not have a material adverse effect on our financial
position, results of operations or cash flows. However, we will continue to
monitor the economic situation, and it is possible that future developments in
Brazil could cause us to reassess our exposure.

13. CAPITAL STOCK

Common Stock

In May 2002, we increased our authorized capitalization to 1.5 billion
shares of common equity. In June 2002, we issued approximately 51.8 million
additional shares of common stock for approximately $1 billion, net of issuance
costs of approximately $31 million.

Equity Security Units

In June 2002, we issued 11.5 million, 9% equity security units. Equity
security units consist of two securities: i) a purchase contract that requires
its holder to buy El Paso common stock to be settled on August 16, 2005, and ii)
a senior note due August 16, 2007, with a principal amount of $50 per unit, and
on which we will pay quarterly interest payments at an annual rate of 6.14%
beginning August 16, 2002. Total notes issued had a total principal value of
$575 million and are pledged to secure the obligation to purchase shares of our
common stock under the purchase contracts.

When the purchase contracts are settled in 2005, we will issue El Paso
common stock. The proceeds will be allocated between common stock and additional
paid-in capital. The number of common shares issued will depend on the prior
20-trading day average closing price of our common stock determined on the third
trading day immediately prior to the stock purchase date. We will issue a
minimum of approximately 24 million shares and up to a maximum of 28.8 million
shares on the settlement date, depending on our average stock price. In June
2002, we recorded $45 million of other non-current liabilities to reflect the
present value of the quarterly contract adjustment payments that we will be
required to make on these units at an annual rate of 2.86% of the stated amount
of $50 per purchase contract with an offsetting reduction in additional paid-in
capital. The quarterly contract adjustment payments will be allocated between
the liability recognized at the date of issuance and additional paid-in capital
based on a constant rate over the term of the purchase contracts.

25

Fees and expenses incurred in connection with the equity security unit
offering were allocated between the senior notes and the purchase contracts
based on their respective fair values on the issuance date. The amount allocated
to the senior notes will be recognized as interest expense over the term of the
senior notes. The amount allocated to the purchase contracts was recorded as
additional paid-in capital.

Other

In August 2002, we will be required to issue 12,184,480 shares of our
common stock under our FELINE PRIDES(SM) program. The proceeds from this stock
issuance will consist of a combination of cash and the return of our existing
senior debentures that were issued in 1999 and are currently outstanding. Total
proceeds will be approximately $460 million, of which approximately $25 million
is estimated to be cash. The proceeds will be recorded as common stock and
additional paid in capital.

Preferred Stock

As part of our balance sheet enhancement plan announced in December 2001,
we completed amendments to our Chaparral and Gemstone agreements which reduced
the number of Series B Mandatorily Convertible Single Reset Preferred Stock
issued in connection with the Chaparral third party notes to 40,000 shares in
April 2002, and eliminated all of the Series C Mandatorily Convertible Single
Reset Preferred Stock issued in connection with the Gemstone third party notes
in May 2002.

14. SEGMENT INFORMATION

We segregate our business activities into four distinct operating segments:
Pipelines, Production, Merchant Energy and Field Services. 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
and marketing strategies. During the quarter, we reclassified our historical
coal mining operations from our Merchant Energy segment to discontinued
operations in our financial statements. All periods were restated to reflect
this change. We measure segment performance using earnings before interest
expense and income taxes (EBIT). The following are our segment results as of and
for the periods ended June 30:

- ---------------
(1) Includes our Corporate and telecommunication activities, eliminations of
intercompany transactions and in 2001, our retail business.

(2) Merchant Energy revenues take into account the adoption of EITF Issue No.
02-3, which requires us to report all physical sales of energy commodities
on a net basis. See Note 1 regarding the adoption of this Issue.

The reconciliations of EBIT to income (loss) from continuing operations
before extraordinary items and cumulative effect of accounting changes and total
assets are presented below:

27

15. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS

We hold investments in various 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 a less than 50 percent interest as well as those in which we hold
a greater than 50 percent interest. Our proportional shares of the
unconsolidated affiliates in which we hold a greater than 50 percent interest
had net income of $6 million and $9 million for the quarters ended, and $16
million and $25 million for the six months ended June 30, 2002 and 2001.

Consolidation of Investments

As of December 31, 2001, we had investments in Eagle Point Cogeneration
Partnership, Capitol District Energy Center Cogeneration Associates and Mohawk
River Funding IV. During 2002, we obtained additional rights from our partners
in each of these investments and also acquired an additional one percent
ownership interest in Capitol District Energy Center Cogeneration Associates and
Mohawk River Funding IV. As a result of these actions, we began consolidating
these investments effective January 1, 2002.

Gemstone

In November 2001, we issued debt securities to Gemstone with a principal
balance of $462 million that carry a fixed annual interest rate of 5.25%. As of
June 30, 2002 and December 31, 2001, the outstanding balance on these
securities, plus accrued interest, was $132 million and $350 million.

In May 2002, we completed amendments to the Gemstone agreements by
eliminating the stock price and credit rating triggers and eliminating $950
million of mandatorily convertible preferred stock that was held in a share
trust we control. In connection with the elimination of these triggers, we
issued a direct guarantee supporting Gemstone's notes in the amount of $950
million.

Chaparral

We have a credit facility with Chaparral that allows Chaparral to borrow up
to $925 million from us at a variable interest rate for their capital programs
and working capital needs. The outstanding balance, plus accrued interest, owed
to us under this credit facility was $788 million and $552 million at June 30,
2002 and December 31, 2001. The interest rate on the facility is based on LIBOR
plus a margin, and was 2.3% and 2.6% at June 30, 2002 and December 31, 2001.

In April 2002, we completed amendments to the Chaparral agreements by
eliminating the stock price and credit rating triggers and reducing the value of
mandatorily convertible preferred stock that was held in a share trust. In
connection with the elimination of these triggers, we issued a direct guarantee
supporting Chaparral's notes totaling approximately $1 billion.

El Paso Energy Partners

In April 2002, we sold midstream assets to El Paso Energy Partners for
total consideration of $735 million. Net proceeds were approximately $539
million in cash, common units of El Paso Energy Partners with a fair value of $6
million, and the partnership's interest in the Prince tension leg platform

28

including its nine percent overriding royalty interest in the Prince production
field with a combined fair value of $190 million.

In July 2002, we entered into a letter of intent with El Paso Energy
Partners for the proposed sale of an estimated $782 million for a series of
midstream assets including:

- substantially all of our natural gas gathering, processing and treating
assets in the San Juan Basin of New Mexico;

- a 35-mile, 20-inch natural gas pipeline and a 16-mile, 12-inch oil
pipeline originating on the Chevron/BHP "Typhoon" platform in the Green
Canyon area of the Gulf of Mexico; and

- over 500 miles of NGL pipelines and a related fractionation facility in
Texas.

This proposed sale was approved by both our and El Paso Energy Partners'
Boards of Directors, which included the approval of El Paso Energy Partners'
special conflicts committee. Both our Board and El Paso Energy Partners' Board
also received fairness opinions on the transaction. This transaction is subject
to customary regulatory review and approval. The closing of the sale is
anticipated by the end of 2002.

16. MINORITY INTERESTS

Clydesdale and Trinity River. In July 2002, we completed the amendments to
the Clydesdale (also known as Mustang) agreements to remove the rating trigger
that could have required us to liquidate the assets supporting the transaction
in the event we were downgraded to below investment grade by both S&P and
Moody's. We completed a similar amendment for our Trinity River (also known as
Red River) agreements in March 2002.

Coastal Oil & Gas Resources Preferred Stock. In July 2002, we repurchased
from an unaffiliated investor, 50,000 shares representing all outstanding
preferred stock in Coastal Oil & Gas Resources, Inc., our wholly owned
subsidiary, for $50 million plus accrued and unpaid dividends.

Coastal Limited Ventures Preferred Stock. In July 2002, we repurchased
from an unaffiliated investor, 150,000 shares representing all outstanding
preferred stock in Coastal Limited Ventures, Inc., our wholly owned subsidiary,
for $15 million plus accrued and unpaid dividends.

Consolidated Partnership. In July 2002, we repurchased the limited
partnership interest, from an unaffiliated investor, in a partnership formed
with Coastal Limited Ventures, Inc. The payment of approximately $285 million to
the unaffiliated investor was equal to the sum of the limited partner's
outstanding capital plus unpaid priority returns.

17. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Accounting for Asset Retirement Obligations

In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 143, Accounting for Asset Retirement Obligations. This statement requires
companies to record a liability for the estimated retirement and removal costs
of assets used in their business. The liability is recorded at its present
value, and the same amount is added to the recorded value of the asset and is
amortized over the asset's remaining useful life. The provisions of SFAS No. 143
are effective for fiscal years beginning after June 15, 2002. We are currently
evaluating the effects of this statement.

Reporting Gains and Losses from the Early Extinguishment of Debt

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement addresses how to report gains or losses resulting
from the early extinguishment of debt. Under current accounting rules, our
non-rate regulated entities report any gains or losses on early extinguishment
of debt as extraordinary items. When we adopt SFAS No. 145, we will be required
to evaluate whether the debt extinguishment is truly extraordinary in

29

nature. If we routinely extinguish debt early, the gain or loss will be included
in income from continuing operations. This statement will be effective for our
2003 year-end reporting.

Accounting for Costs Associated with Exit or Disposal Activities

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement will require us to recognize
costs associated with exit or disposal activities when they are incurred rather
than when we commit to an exit or disposal plan. Examples of costs covered by
this guidance include lease termination costs, employee severance costs that are
associated with a restructuring, discontinued operations, plant closings or
other exit or disposal activities. The provisions of this statement are
effective for fiscal years beginning after December 31, 2002 and will impact any
exit or disposal activities initiated after January 1, 2003.

30

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS(1)

The information contained in Item 2 updates, and you should read it in
conjunction with, information disclosed in our Annual Report on Form 10-K filed
March 15, 2002, in addition to the financial statements and notes presented in
Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

RECENT DEVELOPMENTS

In December 2001, we announced a plan to strengthen our capital structure
and enhance our liquidity, and in May 2002, we announced a plan to limit our
investment in, and exposure to energy trading and to focus our activities and
investment in core natural gas businesses. Since the announcement of these
plans, we have:

- sold or contracted to sell, approximately $2.5 billion of assets;

- issued approximately $2.5 billion of common stock and equity security
units;

- eliminated or renegotiated approximately $4 billion of rating triggers;

- reduced annual operating expenses by $300 million; and

- implemented working capital and credit limits on our trading business.

In addition to these steps, beginning in 2003, we intend to fund our
capital expenditures with operating cash flow from our core businesses, reduce
2003 capital spending and sell up to $2 billion in non-strategic assets to
further reduce our debt.

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 of these 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.

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

(1)Below is a list of terms that are common to our industry and used throughout
our Management's Discussion and Analysis:

/d = per day MMBtu = million British thermal units
Bbl = barrel Mcf = thousand cubic feet
BBtu = billion British thermal units MMcf = million cubic feet
BBtue = billion British thermal unit equivalents MTons = thousand tons
Btu = British thermal unit MMWh = thousand megawatt hours
MBbls = thousand barrels

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 is equal to six Mcf of natural
gas. Also, when we refer to cubic feet measurements, all measurements are at
14.73 pounds per square inch.

31

RESULTS OF OPERATIONS

Our results of operations, along with the impact by segment of the
restructuring and merger-related costs, asset impairments and other charges, are
presented below. Pro-forma amounts should not be used as a substitute for
amounts reported under generally accepted accounting principles. They are
presented solely to improve the understanding of the impact of the charges
reported during the periods presented. The results are as follows (in millions):

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

(1) Charges include restructuring and merger-related costs, asset impairments,
ceiling test charges, changes in accounting estimates, discontinued
operations, extraordinary items, cumulative effect of accounting changes,
foreign exchange loss and other non-recurring gains. See Item 1, Financial
Statements, for further discussions of these charges.

32

SEGMENT RESULTS

Our four segments: Pipelines, Production, Merchant Energy and Field
Services are strategic business units that offer a variety of different energy
products and services; each requires different technology and marketing
strategies. We evaluate our segment performance based on EBIT. Operating
revenues and expenses by segment include intersegment revenues and expenses
which are eliminated in consolidation. Because changes in energy commodity
prices have a similar impact on both our operating revenues and cost of products
sold from period to period, we believe that gross margin (revenue less cost of
sales) provides a more accurate and meaningful basis for analyzing operating
results for the trading and refining portions of Merchant Energy and for the
Field Services segment. We have reclassified our historical coal mining
operations from Merchant Energy to discontinued operations in our financial
statements. All periods have been adjusted to reflect these changes. For a
further discussion of our individual segments, see Item 1, Financial Statements,
Note 14, as well as our Annual Report on Form 10-K for the year ended December
31, 2001. The segment EBIT results for the periods ended June 30 presented below
include the charges discussed above:

PIPELINES

Our Pipelines segment holds our interstate transmission businesses.
Pipeline results are relatively stable, but can be subject to variability from a
number of factors, such as weather conditions, including those conditions that
may impact the amount of power produced by natural gas fired turbines compared
to power generated by less costly hydro-electric methods, as well as gas supply
availability which can displace the pipeline's delivery capabilities to the
markets they serve. Results can also be impacted by the ability to market excess
fuel which is influenced by a pipeline's rate of recovery for fuel for use and
efficiencies of the pipeline's compression equipment. Future revenues may also
be impacted by expansion projects in our service areas, competition by other
pipelines for those expansion needs and regulatory impacts on rates. Results of
our Pipelines segment operations were as follows for the periods ended June 30:

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

(1) Throughput volumes for 2001 exclude those related to pipeline systems sold
in connection with FTC orders related to our Coastal merger including the
Midwestern Gas Transmission system and investments in the Empire State and
Iroquois pipelines. Throughput volumes also exclude intrasegment activities.

Second Quarter 2002 Compared to Second Quarter 2001

Operating revenues for the quarter ended June 30, 2002, were $23 million
lower than the same period in 2001. The decrease was primarily due to the impact
of lower prices on natural gas and liquids sales, including natural gas produced
in our pipeline operations, and sales of excess natural gas recovered, in excess
of the amounts used in operations. Also contributing to the decrease were the
favorable resolution of regulatory issues related to natural gas purchase
contracts in 2001 and lower throughput to California and other western states
and to the northeast due to lower electric generation demand and milder weather
in these areas in 2002. Additionally, lower transportation revenues from
capacity sold under short-term contracts and the sale of our Midwestern Gas
Transmission system in April 2001 contributed to the decrease. These decreases
were partially offset by revenues from transmission system expansion projects
placed in service in 2001 and 2002, higher reservation revenues on the EPNG
system as a result of a larger portion of its capacity sold at maximum tariff
rates compared to the same period in 2001 and revenues from the Elba Island
liquefied natural gas (LNG) facility which was placed in service in December
2001.

Operating expenses for the quarter ended June 30, 2002, were $266 million
lower than the same period in 2001 primarily as a result of 2001 merger-related
charges of $226 million related to our merger with Coastal and a 2001 change in
estimate of $20 million for additional environmental remediation liabilities.
Also contributing to the decrease were lower corporate overhead allocations in
the second quarter of 2002, and lower compressor operating costs on the EPNG
system resulting from lower electric prices. The decrease was partially offset
by additional 2002 accruals on estimated liabilities to assess and remediate our
environmental exposure due to an ongoing evaluation of our operating facilities,
higher operating expenses due to the Elba Island LNG facility being in service
in 2002 and increases to our reserve for bad debts in 2002 related to the
bankruptcy of Enron Corp.

Other income for the quarter ended June 30, 2002, was $11 million higher
primarily due to the resolution of uncertainties associated with the sales of
our interests in the Empire State and Iroquois pipeline systems and our
Gulfstream pipeline project in 2001. Also contributing to the increase were
gains from the sales of non-pipeline assets in 2002.

Six Months Ended 2002 Compared to Six Months Ended 2001

Operating revenues for the six months ended June 30, 2002, were $112
million lower than the same period in 2001. The decrease was primarily due to
the impact of lower prices on sales of excess natural gas recovered, in excess
of the amounts used in operations, natural gas and liquids sales, including
sales of natural gas produced. Also contributing to the decrease were lower
transportation revenues from capacity sold under short-term contracts and lower
throughput to California and other western states and to the northeast due to
lower electric generation demand and milder weather in these areas in 2002.
Additionally, the favorable resolution of regulatory issues related to natural
gas purchase contracts in 2001 and the sale of our Midwestern

34

Gas Transmission system in April 2001 contributed to the decrease. These
decreases were partially offset by higher reservation revenues on the EPNG
system as a result of a larger portion of its capacity sold at maximum tariff
rates compared to the same period in 2001, revenues from transmission system
expansion projects placed in service in 2001 and 2002 and revenues from the Elba
Island LNG facility which was placed in service in December 2001.

Operating expenses for the six months ended June 30, 2002, were $406
million lower than the same period in 2001 primarily as a result of 2001
merger-related charges related to our merger with Coastal of $315 million and a
2001 change in estimate of $20 million for additional environmental remediation
liabilities. Also contributing to the decrease were lower compressor operating
costs on the EPNG system resulting from lower electric prices, lower corporate
overhead allocations and lower employee benefit costs in 2002, as well as lower
operating expenses due to cost efficiencies following the merger with Coastal.
The decrease was partially offset by increases to our reserve for bad debts in
2002 related to the bankruptcy of Enron Corp., additional 2002 accruals on
estimated liabilities to assess and remediate our environmental exposure due to
an ongoing evaluation of our operating facilities, and higher operating expenses
due to the Elba Island LNG facility being placed in service in 2002.

Other income for the six months ended June 30, 2002, was $26 million higher
primarily due to a gain on the sale of pipeline expansion rights in February
2002, the resolution of uncertainties associated with the sales of our interests
in the Empire State and Iroquois pipeline systems and our Gulfstream pipeline
project in 2001, as well as gains from the sales of non-pipeline assets in 2002.

PRODUCTION

Our Production segment conducts our natural gas and oil exploration and
production activities. In the past, our stated goal was to hedge approximately
75 percent of our anticipated current year production, approximately 50 percent
of our anticipated succeeding year production and a lesser percentage
thereafter. As a component of our strategic repositioning plan in May 2002, we
modified this hedging strategy. We now expect to hedge approximately 50 percent
or less of our anticipated production for a rolling 12-month forward period.
This modification of our hedging strategy will increase our exposure to changes
in commodity prices which could result in significant volatility in our reported
results of operations, financial position and cash flows from period to period.
Results of our Production segment operations were as follows for the periods
ended June 30:

- ---------------
(1) Net of transportation costs.

Second Quarter 2002 Compared to Second Quarter 2001

For the quarter ended June 30, 2002, operating revenues were $28 million
lower than the same period in 2001 due to a decline in natural gas volumes in
2002 when compared to the same period of 2001. The decline in natural gas
volumes is primarily a result of the first quarter 2002 sale of properties in
Texas and Colorado. Partially offsetting the decrease was an increase in volumes
for oil, condensate and liquids in 2002 when compared to the same period of
2001.

Transportation and net product costs for the quarter ended June 30, 2002,
were $14 million higher than the same period in 2001 primarily due to a higher
percentage of gas volumes subject to transportation fees.

Operating expenses for the quarter ended June 30, 2002, were $240 million
higher than the same period in 2001 due to higher depletion expense in 2002 as a
result of additional capital spending on assets in the full cost pool, increased
oilfield services costs and non-cash full cost ceiling test charges totaling
$234 million incurred in 2002, primarily for our Canadian full cost pool. The
charge for the Canadian full cost pool resulted from a low daily posted price
for natural gas of approximately $1.43 per MMBtu at the end of the second
quarter. Partially offsetting these increases were write-downs in 2001 totaling
$7 million of materials and supplies resulting from the ongoing evaluation of
our operating standards and plans following the Coastal merger and lower
severance and other taxes in 2002.

Six Months Ended 2002 Compared to Six Months Ended 2001

For the six months ended June 30, 2002, operating revenues were $49 million
lower than the same period in 2001. The decrease was primarily due to a loss on
derivative positions that no longer qualify as cash flow hedges under SFAS No.
133 because they were designated as hedges of anticipated future production from
natural gas and oil properties that were sold in March 2002. Also contributing
to the decrease was a decline in natural gas volumes and average realized oil,
condensate and liquids prices in 2002 when compared to the same period of 2001.
The decline in natural gas volumes is primarily a result of the first quarter
2002 sale of properties in Texas and Colorado. Partially offsetting the decrease
was an increase in volumes for oil, condensate and liquids in 2002 when compared
to the same period of 2001.

Operating expenses for the six months ended June 30, 2002, were $249
million higher than the same period in 2001 due to higher depletion expense in
2002 as a result of additional capital spending on assets in the full cost pool
and non-cash full cost ceiling test charges totaling $267 million incurred in
2002 for our Canadian full cost pool and other international properties
principally in Brazil, Turkey and Australia. Also contributing to the increase
were increased oilfield services costs and higher corporate overhead
allocations. Partially offsetting these increases were merger-related costs and
other charges of $63 million incurred in 2001 related to our combined production
operations, write-downs totaling $7 million of materials and supplies recognized
in 2001 resulting from the ongoing evaluation of our operating standards and
lower severance and other taxes in 2002.

Other income for the six months ended June 30, 2002, was $6 million higher
than the same period in 2001 primarily due to a gain on the sale of non-full
cost pool assets in south and east Texas in March 2002 and higher earnings in
2002 from Pescada, an equity investment in Brazil.

36

MERCHANT ENERGY

Our customer origination and trading activities, as well as our power,
refining and chemical activities are conducted through our Merchant Energy
segment. As part of the power operations of our Merchant Energy segment, we
engage in power contract restructuring activities. These power contract
restructurings are usually conducted through our unconsolidated affiliate,
Chaparral, or other joint ventures. However, they may also involve restructuring
of power plant facilities and related assets that are consolidated in our
financial statements, as in the case of our Eagle Point Cogeneration and Mount
Carmel restructuring transactions discussed in results of operations below.

In May 2002, we announced a strategic repositioning plan in order to
respond to the changing market conditions in the wholesale energy marketing
industry. The key elements of the plan for our Merchant Energy segment include:

- downsizing of our trading and risk management activities;

- a reduction of personnel to achieve $150 million of annualized cost
savings; and

- limiting cash working capital investments for trading activities to $1
billion

As a result of current circumstances surrounding the wholesale energy
markets we have experienced weaker market fundamentals resulting in an
elimination of industry participants and the disorderly liquidation of their
trading portfolios. Additionally, changes in credit requirements have left
several market participants less creditworthy, requiring greater use of credit
support actions. These factors have resulted in lower trading profitability
which we expect to continue for the remainder of 2002 and into 2003. In
addition, our refining business has been adversely impacted over the past twelve
months by the declining spreads between the lighter crudes, which are typically
more expensive than the heavy crudes processed at our Aruba refinery. We expect
this trend to continue into 2003.

Power Contract Restructuring Activities

Many of our domestic power plants, and the power plants owned by Chaparral,
have long-term power sales contracts with regulated utilities that were entered
into under the Public Utility Regulatory Policies Act of 1978 (PURPA). The power
sold to the utility under these PURPA contracts is required to be delivered from
a specified power generation plant at power prices that are usually
significantly higher than the cost of power in the wholesale power market. Our
cost of generating power at these PURPA power plants is typically higher than
the cost we would incur by obtaining the power in the wholesale power market,
principally because the PURPA power plants are less efficient than newer power
generation facilities.

Typically, in a power contract restructuring, the PURPA power sales
contract is amended so that the power sold to the utility does not have to be
provided from the specific power plant. Because we are able to buy lower cost
power in the wholesale power market, we have the ability to reduce the cost paid
by the utility, thereby inducing the utility to enter into the power contract
restructuring transaction. Following the contract restructuring, the power plant
operates on a merchant basis, which means that it is no longer dedicated to one
buyer and will operate only when power prices are high enough to make operations
economical. In addition, we may assume, and in the case of Eagle Point
Cogeneration we did assume, the business and economic risks of supplying power
to the utility to satisfy the delivery requirements under the restructured power
contract over its term. When we assume this risk, we manage these obligations by
entering into transactions to buy power from third parties that mitigate our
risk over the life of the contract. These activities are reflected as part of
our trading activities and reduce our exposure to changes in power prices from
period to period. Power contract restructurings generally result in a higher
return in our power generation business because we can deliver reliable power at
lower prices than our cost to generate power at these PURPA power plants. In
addition, we can use the restructured contracts as collateral to obtain
financing at a cost that is comparable to, or lower than, our existing financing
costs. The manner in which we account for these activities is discussed in Item
1, Financial Statements, Note 1, of this Form 10-Q.

37

Power restructuring transactions are often extensively negotiated and can
take a significant amount of time to complete. In addition, there are a limited
number of facilities to which the restructuring process applies. Our ability to
successfully restructure a power plant's contracts and the future financial
benefit of that effort is difficult to determine, and may vary significantly
from period to period. Since we began these activities in 1999, we have
completed eleven restructuring transactions, including contract terminations, of
varying financial significance, and we have additional facilities which we will
consider for restructuring in the future.

Energy-Related Price Risk Management Activities

As of June 30, 2002, the net fair value of our energy contracts was $1.7
billion. Of this amount, the net fair value of our trading-related energy
contracts was $1.1 billion. Our trading activities generated margins during the
six months ended June 30, 2002 and 2001 totaling $64 million and $477 million.

The following table details the net fair value of our energy contracts by
year of maturity and valuation methodology as of June 30, 2002:

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

(1) Non-trading energy contracts include derivatives from our power contract
restructuring activities of $979 million and derivatives related to our
natural gas and oil producing activities of $(336) million. Earnings related
to the natural gas and oil producing activities are included in our
Production segment results.

38

A reconciliation of our trading and non-trading energy contracts for the
six months ended June 30, 2002, is as follows:

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

(1) The initial recorded value of new contracts for trading primarily comes from
completing our Snohvit LNG supply contract in the second quarter of 2002 and
for non-trading primarily comes from our Eagle Point Cogeneration
restructuring transaction completed in the first quarter of 2002. See the
discussion of these transactions under results of operations below.

Included in "Changes in fair value attributable to changes in valuation
techniques" in our trading price risk management activities is a first quarter
charge of approximately $61 million related to our revised estimate of the fair
value of long-term trading positions. Specifically, we have experienced
diminished liquidity in the marketplace for natural gas and power transactions
in excess of ten years. Because we do not expect this condition to change in the
foreseeable future, we do not recognize gains from the fair value of trading or
non-trading positions beyond ten years unless there is clearly demonstrated
liquidity in a specific market. Included in "Other" are option premiums and
storage capacity transactions.

Results of Operations

Below are Merchant Energy's operating results and an analysis of these
results for the periods ended June 30:

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

(1) Volumes include those traded in our origination and trading activities, as
well as those generated or produced at our consolidated power plants and
refineries.

Trading and refining gross margins consist of revenues from commodity
trading and origination activities less the cost of commodities sold, the impact
of power contract restructuring activities and revenues from refineries and
chemical plants, less the costs of feedstocks used in the refining and
production processes.

39

Second Quarter 2002 Compared to Second Quarter 2001

During the quarter ended June 30, 2002, we completed two significant
transactions, one related to our Nejapa power facility and the other related to
a long-term LNG supply contract. In March 2002, an arbitration award panel
approved the termination of the power purchase agreement between Comision
Ejecutiva Hydroelectrica del Rio Lempa and the Nejapa Power Company, one of our
consolidated subsidiaries, in exchange for a cash payment of $90 million. The
award was finalized and paid to Nejapa in the second quarter of 2002. We
recorded, as revenue, a $90 million gain and also recorded $13 million in other
expense for the minority owner's share of this gain. We applied the proceeds of
the award to retire a portion of Nejapa's debt. In May 2002, we received final
approval from the Norwegian and United States governments on an LNG purchase and
sale agreement signed in October 2001 with a consortium of natural gas
production companies led by Statoil ASA. The consortium will develop the Snohvit
Project in northern Norway, and we will receive LNG shipments equivalent to an
estimated 91 billion cubic feet per year of natural gas during the 17-year term
of the agreement with the possibility of a 3-year extension. The first delivery
is scheduled to occur between October 2005 and October 2006. The Snohvit
agreement is a derivative under SFAS No. 133, which we were required to mark to
its fair value when it was finalized. As a result, we recorded a $59 million
gain in the second quarter of 2002 from this transaction.

For the quarter ended June 30, 2002, trading and refining gross margins
were $311 million lower than the same period in 2001. The decrease was due to
lower trading margins primarily due to a weaker trading environment and lower
price volatility in the natural gas and power markets in the second quarter of
2002, partially offset by the $59 million gain on the Snohvit transaction. Also
contributing to the overall decrease were lower refining margins resulting from
the lease of our Corpus Christi refinery and related assets to Valero in June
2001, lower spreads between the sales prices of refined products and underlying
feedstock costs and lower throughput at the Aruba refinery. Lower revenues from
our marine operations resulting from lower freight rates, a decrease in vessels
owned and on charter and lower throughput at our marine terminals also
contributed to the overall decrease in trading and refining margins.

Operating and other revenues consist of revenues from domestic and
international power generation facilities and investments, including our
management fee from Chaparral, and revenues from EnCap and the other financial
services businesses. For the quarter ended June 30, 2002, operating and other
revenues were $158 million higher than the same period in 2001. The increase
resulted from revenues from domestic and international power facilities that
were consolidated in the fourth quarter of 2001 and the first quarter of 2002,
$90 million of revenues from the termination of the Nejapa power contract and
higher management fees from Chaparral.

Operating expenses for the quarter ended June 30, 2002, were $108 million
lower than the same period in 2001. The decrease was primarily a result of
merger-related costs, changes in accounting estimates and asset impairments of
$130 million recorded in the second quarter of 2001 associated with combining
operations with Coastal. The decrease was partially offset by the consolidation
of international and domestic power-related entities in the fourth quarter of
2001 and the first quarter of 2002 as well as higher operating expenses
resulting from the expansion of our LNG business in 2002 and more extensive
operations in Europe and Mexico in 2002 as compared to 2001.

Other income for the quarter ended June 30, 2002, was $32 million lower
than the same period in 2001. The decrease was primarily the result of
marketing, agency and technical services fees related to the development of the
Macae power project in Brazil which were recorded in the second quarter of 2001
as well as the minority owner's interest in the gain from the termination of the
Nejapa power contract of $13 million. Also, we had an increase in equity
earnings from unconsolidated power projects in the second quarter of 2002.

Six Months Ended 2002 Compared to Six Months Ended 2001

During the six months ended June 30, 2002, we completed power
restructurings or contract terminations at our Eagle Point Cogeneration, Mount
Carmel and Nejapa power plants. The Eagle Point Cogeneration restructuring
transaction, completed in March 2002, was our most significant power
restructuring transaction to date.
40

The Eagle Point restructuring involved several steps. First, we amended the
existing PURPA power sales contract with Public Service Electric and Gas (PSEG)
to eliminate the requirement that power be delivered specifically from the Eagle
Point power plant. This amended contract has fixed prices with stated increases
over the 14-year term that range from $85 per MWh to $126 per MWh. We entered
into the amended power sales contract through a consolidated subsidiary, Utility
Contract Funding, L.L.C. (UCF). UCF was created to hold and execute the terms of
the restructured power sales contract, to enter into a supply contract to meet
the requirements of the restructured agreement and to monetize the value of
these contracts by issuing debt. In keeping with its purpose, UCF entered into a
power supply agreement with El Paso Merchant Energy L.P. (EPME), our trading
company. The terms of the EPME power supply contract were identical to the
restructured power contract, with the exception of price, which was set at $37
per MWh over its 14-year term.

For credit enhancement purposes, in anticipation of the financing
transaction associated with the restructuring, UCF terminated the EPME supply
contract in the second quarter of 2002 and replaced it with a supply contract
with a Morgan Stanley affiliate. UCF entered into the Morgan Stanley contract
solely for the purpose of reducing the cost of debt UCF would issue. Morgan
Stanley then entered into a supply contract with EPME. While the Morgan Stanley
contract does not obligate Morgan Stanley to acquire power only from EPME, the
net effect of these two transactions is that EPME is obligated to supply power
to meet the obligations to PSEG under the restructured power contract.

EPME separately entered into power purchase transactions with a number of
third parties to economically hedge its price risk for substantially all of the
notional quantity of power supply requirements over the entire term of the
supply agreement in accordance with its risk management policies. The time
periods between purchase and delivery of power under the third party contracts
differ. As a result, there may be variability in future margins. However, since
the power market in which these transactions occurred is highly liquid and
prices in this market have historically been highly correlated between periods,
we do not expect these timing differences to have a significant impact on our
ongoing operating results.

As a result of the various steps we have taken to accomplish this
restructuring, we have been able to improve the expected margin associated with
the original PURPA contract by replacing the high-cost of the power generated
from the Eagle Point plant, which had averaged over $75 per MWh, with power that
we have purchased in the open market at an average cost of $31 per MWh. We have
also shifted the collection and credit risk to a third party over the term of
the restructured power sales agreement.

From an accounting standpoint, the actions taken to restructure the
contract required us to mark the contract to its fair value under SFAS No. 133.
As a result, we recorded non-cash revenue representing the estimated fair value
of the derivative contract of approximately $978 million in our first quarter
results. We also amended or terminated other ancillary agreements associated
with the cogeneration facility, such as gas supply and transportation
agreements, a steam contract and existing financing agreements. In the second
quarter, we paid $103 million to the utility to terminate the original PURPA
contract. Also included in the first quarter results were a $98 million non-cash
charge to adjust the Eagle Point Cogeneration plant to fair value based on its
new status as a peaking merchant plant and a non-cash charge of $230 million to
write off the book value of the original PURPA contract. Based on these amounts,
and including closing and other costs, our first quarter results reflected a net
benefit from the Eagle Point Cogeneration restructuring transaction of $438
million. The Morgan Stanley and EPME supply contracts are derivatives and must
be accounted for at their fair values, with changes in value recorded in
earnings. The third party power purchase transactions which were entered into to
hedge our price risk associated with the power supply requirements are also
accounted for at fair value since they are also derivatives, but the effects of
these transactions have not been included in the determination of the
restructuring gain since they are included in our trading results. Total
operating cash flows from this transaction amounted to approximately $110
million of cash paid to the utility to amend the original contract and other
miscellaneous closing costs. In July 2002, UCF completed the restructuring
transaction by monetizing the contract with PSEG and issuing $829 million of
7.944% senior notes secured solely by the contracts and cash flows of UCF. The
proceeds of the monetization will be reported as financing cash flow in the
third quarter of 2002.

41

We also employed the principles of our power restructuring business in
completing two contract terminations in the period -- in the second quarter, the
Nejapa transaction as discussed above, and in the first quarter, the Mount
Carmel transaction. The Mount Carmel restructuring, which occurred in the first
quarter of 2002, involved the termination of the existing PURPA power purchase
contract for a fee from the utility of $50 million. In addition, we recorded a
non-cash adjustment to reflect fair value of the Mount Carmel facility of $25
million, resulting in a total net benefit on the restructuring transaction of
$25 million.

For the six months ended June 30, 2002, trading and refining gross margins
were $159 million lower than the same period in 2001. Contributing to this
decrease was a decline in our marketing and trading activities primarily in
natural gas and power principally resulting from a weaker trading environment
and lower price volatility in the natural gas and power markets in the first
half of 2002. The decrease in our trading activity was offset by the Eagle Point
Cogeneration and Mount Carmel power contract restructurings described above and
a $59 million gain from our Snohvit LNG transaction. Also contributing to the
overall decrease were lower refining margins resulting from the lease of our
Corpus Christi refinery and related assets to Valero in June 2001, lower spreads
between the sales prices of refined products and underlying feedstock costs and
lower throughput at our Aruba refinery, lower revenues from vessels owned and on
charter, and lower throughput at our marine terminals.

For the six months ended June 30, 2002, operating and other revenues were
$187 million higher than the same period in 2001. The increase resulted from
revenues from domestic and international power facilities that were consolidated
in the fourth quarter of 2001 and the first quarter of 2002, $90 million of
revenues from the termination of the Nejapa power contract in the second quarter
of 2002 and higher management fees from Chaparral.

Operating expenses for the six months ended June 30, 2002, were $130
million higher than the same period in 2001. The increase resulted from a $342
million impairment of our power investments in Argentina in the first quarter of
2002, the consolidation of international and domestic power-related entities in
the fourth quarter of 2001 and the first quarter of 2002, and higher operating
expenses resulting from the expansion of our LNG business in 2002 and more
extensive operations in Europe and Mexico in 2002 as compared to 2001. The
increase was partially offset by merger-related costs, changes in accounting
estimates and asset impairments of $264 million recorded in the second quarter
of 2001 associated with combining operations with Coastal as well as lower fuel
costs in our refining operations resulting from lower gas prices and the lease
of our Corpus Christi refinery and related assets to Valero in June 2001.

Other income for the six months ended June 30, 2002, was $139 million lower
than the same period in 2001. The decrease was primarily the result of
marketing, agency and technical services fees related to the development of the
Macae power project in Brazil which were recognized in the second quarter of
2001, the minority owner's interest in the gain on the termination of the Nejapa
power contract of $13 million and Chaparral's minority ownership interest in
income earned on our Eagle Point Cogeneration restructuring transaction. Also
contributing to the decrease were lower equity earnings on domestic power
projects consolidated in the fourth quarter of 2001 and the first quarter of
2002. The power projects we consolidated in the fourth quarter of 2001 and the
first quarter of 2002 are not wholly-owned by us. As a result, the minority
owners interest in the income earned from these facilities, which we classify as
other income, also reduced other income in the first six months of 2002.

FIELD SERVICES

Our Field Services segment conducts our midstream activities. As part of
our plan to strengthen our capital structure and enhance our liquidity, we
identified several midstream assets to be sold. Once completed, these
transactions should generate over $1 billion in cash proceeds, which will be
used to reduce our outstanding debt.

During 2002, we have entered into transactions to sell midstream assets to
El Paso Energy Partners, of which we have an approximate 27 percent ownership
interest. In April 2002, we sold gathering and processing assets to the
partnership, including the intrastate pipeline system we acquired in our
acquisition of PG&E's midstream operations in December 2000. These assets
generated EBIT of $52 million during the year ended
42

December 31, 2001. We also announced in July 2002, the proposed sale of
substantially all our natural gas gathering, processing and treating assets in
the San Juan Basin to El Paso Energy Partners. We expect this transaction to be
completed by the end of 2002. The San Juan Basin assets generated EBIT of $102
million during the year ended December 31, 2001.

With the completion of these sales, we will have sold a substantial portion
of our midstream business to El Paso Energy Partners. As a result, we expect our
future EBIT to decrease considerably due to a decline in our gathering and
treating activities. However, we expect the increase in earnings from our
interest in the partnership to offset, in part, the anticipated decrease in
EBIT.

After the sale of the San Juan Basin assets, the remaining assets in our
Field Services segment will consist primarily of processing facilities in the
Rockies, south Texas and south Louisiana regions, as well as our interest in El
Paso Energy Partners. A majority of our processing contracts are
percentage-of-proceeds and make-whole contracts. Accordingly, under these types
of contracts we may have more sensitivity to price changes during periods when
natural gas and natural gas liquids prices are volatile.

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

Second Quarter 2002 Compared to Second Quarter 2001

Total gross margins for the quarter ended June 30, 2002, were $61 million
lower than the same period in 2001. Gathering and treating margins decreased by
$33 million primarily due to our sale of assets to El Paso Energy Partners in
April 2002. The decrease in our processing margins was attributable to the sale
of the Indian Basin processing plant to El Paso Energy Partners in April 2002
and lower natural gas and NGL prices in 2002 which unfavorably impacted our
processing volumes and margins in the Rockies, south Louisiana and south Texas
regions. Also contributing to the decrease in processing margins were higher
processing costs associated with a processing arrangement at the Chaco
processing facility entered into in the fourth quarter of 2001 with El Paso
Energy Partners and the sale of our Dragon Trail processing plant in May 2002.

Operating expenses for the quarter ended June 30, 2002, were $47 million
lower than the same period of 2001. The decrease was primarily due to $26
million of reduced operating and depreciation expenses largely attributable to
our sale of assets to El Paso Energy Partners in April 2002, and $9 million in
merger-related costs in 2001. Also contributing to the decrease was lower
amortization of goodwill of $4 million due to the implementation of SFAS No. 142
in 2002.

Other income for the quarter ended June 30, 2002, was $13 million higher
than the same period in 2001 primarily due to a $10 million gain recognized on
the sale of our Dragon Trail processing plant and higher

43

earnings in 2002 from our interest in El Paso Energy Partners, partially offset
by an $8 million gain resulting from the sale of our 1.01 percent non-managing
interest in the partnership in May 2001.

Six Months Ended 2002 Compared to Six Months Ended 2001

Total gross margins for the six months ended June 30, 2002, were $86
million lower than the same period in 2001. Gathering and treating margins
decreased primarily due to our sale of assets to El Paso Energy Partners in
April 2002. Excluding the impact of asset sales, gathering and treating margins
were higher compared to last year due to the favorable resolution of fuel, rate
and volume matters in the first quarter of 2002 and higher realized
transportation rates in the first quarter of 2002 from the pipeline system
acquired in our acquisition of PG&E's midstream operation in December 2000. This
pipeline system was one of the assets sold to El Paso Energy Partners in April
2002. Partially offsetting these increases were lower natural gas prices in the
San Juan Basin in 2002. Processing margins declined due to the sale of the
Indian Basin processing plant to El Paso Energy Partners in April 2002 and lower
natural gas and NGL prices in 2002 which unfavorably impacted our processing
volumes and margins in the Rockies, south Louisiana and south Texas regions.
Also contributing to the decrease in processing margins were higher processing
costs associated with a new processing arrangement at the Chaco processing
facility entered into in the fourth quarter of 2001 with El Paso Energy Partners
and the sale of our Dragon Trail processing plant in May 2002.

Operating expenses for the six months ended June 30, 2002, were $90 million
lower than the same period of 2001. The decrease was primarily due to $35
million of reduced operating and depreciation expenses largely attributable to
our sale of assets to El Paso Energy Partners in April 2002 and in October 2001.
Also contributing to the decrease were $38 million in merger-related costs in
2001 which include payments to El Paso Energy Partners related to FTC ordered
sales of assets owned by the partnership, merger-related employee severance and
relocation expenses following our merger with Coastal, as well as a decrease in
goodwill amortization of $8 million in 2002 due to the implementation of SFAS
No. 142.

Other income for the six months ended June 30, 2002, was $10 million higher
than the same period in 2001 primarily due to a $10 million gain recognized on
the sale of our Dragon Trail processing plant and higher earnings in 2002 from
our interest in El Paso Energy Partners.

CORPORATE AND OTHER, NET

Corporate and other expenses, which include general and administrative
activities as well as the operations of our telecommunications and other
miscellaneous businesses, for the quarter and six months ended June 30, 2002,
were $364 million and $1,238 million lower than the same periods in 2001. The
decrease was primarily a result of $248 million and $1,152 million in
merger-related charges for the quarter and six months ended June 30, 2001, in
connection with our merger with Coastal, and additional costs for the quarter
and six months ended June 30, 2001 of $90 million related to increased estimates
of environmental remediation and reductions in the fair value of spare parts
inventories to reflect changes in usability of spare parts inventories in our
corporate operations based on an ongoing evaluation of our operating standards
and plans following the Coastal merger. Also contributing to the decrease was a
write-down of $60 million for our investment in a telecommunications company in
Brazil in the second quarter of 2001. Partially offsetting the decrease were
charges of $50 million for severance payments related to our second quarter 2002
employee restructuring and costs associated with the elimination of rating and
stock-price triggers in the second quarter of 2002 for the Gemstone and
Chaparral indentures.

We continue to evaluate the impact of the continuing decline in the
telecommunications industry on our telecommunications business. These conditions
and the credit and liquidity standing of many of the telecommunications industry
participants have impacted our Chicago-based telecommunications facility, which
we lease under an operating lease that has a residual value guarantee of $237
million. In the second quarter of 2002, we reached a final settlement of a lease
agreement in this facility with Global Crossing, which recently filed for
bankruptcy. Although we received some consideration, the settlement resulted in
the termination of the lease and the loss of a significant tenant at the
facility. Although the operating results from this facility are still positive,
due to this event and the continuing decline in the financial condition of the

44

remaining tenants, we have retained a consultant to assist us in determining the
fair value of the building and its real estate potential. To the extent we
determine the expected fair value of the facility at the end of the lease
financing term is less than the residual value guarantee, the difference will be
amortized over the remaining term of the financing. Despite the continued
decline in the industry, our Texas-based metro transport business continues to
show steady growth. Additionally, we received a favorable outcome in an
arbitration proceeding with Southwestern Bell, although the arbitration ruling
is still subject to the Texas PUC approval. Although we believe there is no
current impairment in our metro business, we will continue to evaluate this
business on a quarterly basis. At June 30, 2002, our net investment in the
telecommunications business was $527 million.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter and six months ended June 30,
2002, was $68 million and $80 million higher than the same periods in 2001. The
increase was a result of higher long-term borrowings for ongoing capital
projects, investment programs and operating requirements. Also contributing to
the increase was a foreign currency loss of $45 million related to changes in
value of our Euro notes issued in May 2002 based on changes in the foreign
currency exchange rate. This increase was partially offset by repayment of
short-term credit facilities and lower interest rates on short-term borrowings.
We anticipate interest and debt expenses will continue to exceed last year's
levels throughout the remainder of 2002.

MINORITY INTEREST

Minority interest expense for the quarter and six months ended June 30,
2002, was $13 million and $35 million lower than the same periods in 2001,
primarily due to lower interest rates in 2002, partially offset by increased
minority interest expense on Gemstone which was formed in November 2001.

INCOME TAXES

Income tax expense for the quarter and six months ended June 30, 2002, was
$1 million and $119 million, resulting in effective tax rates of 11 percent and
32 percent. The quarter ended June 30, 2002, income tax expense was net of a tax
benefit of approximately $2 million associated with taxes related to, and
reclassified as, discontinued operations. The effective tax rate excluding the
reclassification for the quarter ended June 30, 2002, was 32 percent. Our
effective tax rates were different than the statutory rate of 35 percent
primarily due to the following:

- state income taxes; and

- foreign income taxed at different rates.

Income tax benefit for the quarter and six months ended June 30, 2001, was
$63 million and $98 million, resulting in effective tax rates of 32 percent and
16 percent. The six months ended June 30, 2001 benefit was net of $110 million
of tax expense associated with non-deductible merger charges and changes in our
estimates of additional tax liabilities. The majority of these estimated
additional liabilities were paid in 2001 and are being contested by us. The
effective tax rate excluding these charges for the six months ended June 30,
2001 was 33 percent. Other differences between the effective tax rates and the
statutory tax rate of 35 percent were primarily due to the following:

- state income taxes;

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

- foreign income taxed at different rates.

45

LIQUIDITY AND CAPITAL RESOURCES

GENERAL

During the six months ended June 30, 2002, our cash and cash equivalents
increased by $1.5 billion to approximately $2.7 billion. During the period, we
generated an estimated $5.6 billion through a combination of cash-based earnings
of $1.1 billion and the issuances of $3.5 billion long-term debt and $1.0
billion common stock. In addition, we generated approximately $1.3 billion
through sales of natural gas and oil properties and midstream assets. From these
cash inflows, we invested approximately $2.0 billion in fixed assets and
investments, paid $1.5 billion on maturing debt issues, paid $0.9 billion, net,
on short-term debt, paid $0.2 billion in dividends, and funded working capital
needs of approximately $0.7 billion, principally related to margins and option
premiums in our price risk management activities. Our operating cash flow from
period to period is significantly impacted, either positively or negatively, by
movements in commodity prices. For the remainder of 2002, we expect to meet our
cash investing and financing needs, including the payment of dividends, through
cash generated from earnings in our operating businesses, through additional
financing transactions and through asset sales, as needed. However, our working
capital inflows or outflows for the remainder of 2002 will be dependent on
fluctuations in commodity prices as well as strategies we may implement to
offset the impact of commodity price fluctuations on our cash flows. Other
sources of liquidity at June 30, 2002, include our 364 day bank revolver of $3.0
billion and multiple-year bank revolver of $1.0 billion which are discussed
below.

CASH FROM OPERATING ACTIVITIES

Net cash provided by operating activities was $0.3 billion for the six
months ended June 30, 2002, compared to net cash provided by operating
activities of $2.7 billion for the same period in 2001. The decrease was
primarily due to less cash generated through liquidations of price risk
management assets in 2002, as well as more cash used to fund broker and
over-the-counter margins. Our operating cash flow reductions also related to
higher petroleum inventory in 2002. Partially offsetting these decreases were
payments in 2001 related to the merger with Coastal.

CASH FROM INVESTING ACTIVITIES

Net cash used in our investing activities was $626 million for the six
months ended June 30, 2002, of which $7 million was used in investing activities
by discontinued operations. Our investing activities consisted primarily of
additions to property, plant, and equipment, including expenditures for
developmental drilling and expansion and construction projects. Our additions to
investments consisted mostly of short-term notes from unconsolidated affiliates,
primarily related to a subsidiary of Chaparral. Cash inflows from
investment-related activities included net proceeds from the sale of natural gas
and oil properties located in east and south Texas and Colorado, the sale of
midstream assets to El Paso Energy Partners, L.P., as well as the sale of a
natural gas gathering system and a natural gas processing plant.

CASH FROM FINANCING ACTIVITIES

Net cash provided by our financing activities was $1.8 billion for the six
months ended June 30, 2002, of which $31 million was used in financing
activities by discontinued operations. Cash provided from our financing
activities included the issuance of long-term debt and issuances of common stock
and equity security units. Cash used by our financing activities included
payments made to retire long-term debt and other financing obligations, as well
as repayments under our commercial paper and short-term credit facilities.

On July 17, 2002, we declared a quarterly dividend of $0.2175 per share on
our common stock, payable on October 7, 2002, to stockholders of record on
September 6, 2002. Also, during the six months ended
June 30, 2002, El Paso Tennessee Pipeline Co., our subsidiary, paid dividends of
$12 million on our Series A cumulative preferred stock, which is 8 1/4% per
annum (2.0625% per quarter).

46

LIQUIDITY

Our 2001 Annual Report on 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 2001 Annual Report on Form
10-K.

Financing Activities

Our significant borrowing and repayment activities during 2002 are
presented below. These amounts do not include borrowings or repayments on our
short-term financing instruments with an original maturity of three months or
less, including our commercial paper programs and short-term credit facilities.

Issuances

Retirements

INTEREST NET
DATE COMPANY TYPE RATE PRINCIPAL PAYMENTS DUE DATE
- --------------------- ------------------ -------------------- -------- --------- ----------- ---------
(IN MILLIONS)

2002
January SNG Long-term debt 7.85% $ 100 $ 100 2002
January EPNG Long-term debt 7.75% 215 215 2002
March El Paso CGP Long-term debt Variable 400 400 2002
April Field Services Long-term debt 8.78% 25 25 2002
May SNG Long-term debt 8.625% 100 100 2002
June El Paso CGP Crude oil Variable 300 300 2002
prepayment
June El Paso CGP Long-term debt Variable 90 90 2002
Jan.-June El Paso Natural gas LIBOR+ 216 216 2002-2005
Production production payment 0.372%
Jan.-June El Paso CGP Long-term debt Variable 75 75 2002
Jan.-June Various Long-term debt Various 28 28 2002
July El Paso CGP Long-term debt Variable 55 55 2002
July El Paso(6) Long-term debt 7.00% 15 10 2011
July El Paso(6) Long-term debt 7.875% 10 7 2012
August El Paso(6) Long-term debt 7.875% 15 12 2012
August El Paso(6) Long-term debt 7.00% 5 4 2011
August El Paso(6) Long-term debt 6.75% 5 4 2009
August El Paso(6) Long term debt 7.625% 5 4 2011
July-Aug. El Paso CGP Long-term debt Variable 44 44 2010-2028

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

(1) Net proceeds were primarily used to repay maturing long-term debt,
short-term borrowings and for general corporate purposes.

47

(2) These notes are collateralized solely by the cash flows and contracts of
these consolidated subsidiaries, and are non-recourse to other El Paso
companies. The Mohawk River Funding IV financing relates to our Capitol
District Energy Center Cogeneration Associates restructuring transaction and
the Utility Contract Funding financing relates to our Eagle Point
Cogeneration restructuring transaction.

(3) Represents the U.S. dollar equivalent of 500 million Euros at June 30, 2002,
and includes a $45 million change in value due to a change in the Euro to
U.S. dollar foreign currency exchange rate from the issuance date to June
30, 2002.

(4) These senior notes relate to an offering of 11.5 million 9% equity security
units, which consist of forward purchase contracts on El Paso common stock
to be settled on August 16, 2005.

(5) We have committed to exchange these notes for new registered notes. The form
and terms of the new notes will be identical in all material respects to the
form and terms of these old notes except that the new notes (1) will be
registered with the Securities and Exchange Commission, (2) will not be
subject to transfer restrictions and (3) will not be subject, under certain
circumstances, to an increase in the stated interest rate.

(6) These amounts represent a buyback of our bonds in the open market in July
and August 2002.

In June 2002, we issued 51.8 million shares of our common stock at a public
offering price of $19.95 per share. Net proceeds from the offering were
approximately $1.0 billion and will be used to repay short-term borrowings and
other financing obligations and for general corporate purposes.

In July 2002, UCF issued $829 million of 7.944% senior secured notes due in
2016. This financing is non-recourse to other El Paso companies, as it is
independently supported only by the cash flows and contracts of UCF including
obligations of PSEG under a restructured power contract and of Morgan Stanley
under a power supply agreement. In connection with the credit enhancement
provided by Morgan Stanley's participation, we paid them $36 million in
consideration for entering into the supply agreement in addition to their
underwriting fee of $6 million. We believe the benefits to us of Morgan
Stanley's participation exceed the cost paid to them. The proceeds from the debt
issuance were used to pay off the costs of the restructuring transaction and for
general corporate purposes.

In August 2002, we will be required to issue 12,184,480 shares of our
common stock under our FELINE PRIDES(SM) program. The proceeds from this stock
issuance will consist of a combination of cash and the return of our existing
senior debentures that were issued by El Paso CGP in 1999 and are currently
outstanding. Total proceeds will be approximately $460 million, of which
approximately $25 million is estimated to be cash. The proceeds will be recorded
as common stock and additional paid in capital.

Credit Facilities and Available Capacity

In February 2002, we filed a new shelf registration statement with the
Securities and Exchange Commission that allows us to issue up to $3 billion in
securities. Under this registration statement, we can issue a combination of
debt, equity and other instruments, including trust preferred securities of two
wholly-owned trusts, El Paso Capital Trust II and El Paso Capital Trust III. If
we issue securities from these trusts, we will be required to issue full and
unconditional guarantees on these securities. As of June 30, 2002 we had $818
million remaining capacity under this shelf registration statement.

In May 2002, we renewed our $3 billion, 364-day revolving credit and
competitive advance facility. EPNG and TGP remain designated borrowers under
this facility. This facility matures in May 2003. In June 2002, we amended our
existing $1 billion, 3-year revolving credit and competitive advance facility to
permit us to issue up to $500 million in letters of credit and to adjust pricing
terms. This facility matures in August 2003, and El Paso CGP, EPNG and TGP are
designated borrowers under this facility. The interest rate under both of these
facilities varies based on our senior unsecured debt rating, and as of June 30,
2002, an initial draw would have had a rate of LIBOR plus 0.625%, plus a 0.25%
utilization fee for drawn amounts above 25% of the committed amounts. As of June
30, 2002, there were no borrowings outstanding, and we have issued $450 million
of letters of credit under the $1 billion facility.

Notes Payable to Affiliates

Our notes payable to unconsolidated affiliates as of June 30, 2002, were
$555 million versus $872 million as of December 31, 2001. The decrease is
primarily due to the partial repayment of Gemstone debt securities.

48

Securities of Subsidiaries and Minority Interests

Total amounts outstanding for securities of subsidiaries and minority
interests were $4,154 million at June 30, 2002, versus $4,013 million at
December 31, 2001. The increase was due to the consolidation of our Eagle Point
Cogeneration Partnership and our Capitol District Energy Center Cogeneration
Associates investments in January 2002.

In July 2002, we purchased from unaffiliated investors 200,000 shares of
preferred stock in Coastal Oil & Gas Resources, Inc. and Coastal Limited
Ventures, Inc., our wholly owned subsidiaries, for $65 million plus accrued and
unpaid dividends. We purchased the limited partnership interest, from an
unaffiliated investor, in a partnership formed with Coastal Limited Ventures,
Inc. The payment of approximately $285 million to the unaffiliated investor was
equal to the sum of the limited partner's outstanding capital plus unpaid
priority returns.

Lines of Credit

Mesquite, a subsidiary of Chaparral and our affiliate, may borrow up to
$925 million from us under a line of credit facility. As of June 30, 2002,
Mesquite had $788 million outstanding under this facility at an interest rate of
2.3%.

Letters of Credit

As of June 30, 2002, we had outstanding letters of credit of $1,010 million
versus $465 million as of December 31, 2001. The increase is primarily due to
the issuance of letters of credit in connection with the management of our
trading operations.

Other Commercial Commitments

In 2001, we entered into agreements to time-charter four separate ships to
secure transportation for our developing LNG business. In May 2002, we entered
into amendments to three of the initial four time charters to reconfigure the
ships with onboard regasification technology and to secure an option for an
additional time charter for a fifth ship. The exercise of the option for the
fifth ship will represent a commitment of $522 million over the term of such
charter. However, we are obligated to pay a termination fee of $24 million in
the event the option is not exercised by April 2003. The agreements provide for
deliveries of vessels between 2003 and 2005. Each time charter has a twenty-year
term commencing when the vessels are delivered with the possibility of two
five-year extensions. The total commitment under the five time-charter
agreements is approximately $2.5 billion over the term of the time charters. We
are party to an agreement with an unaffiliated global integrated oil and gas
company under which the third party agrees to bear 50 percent of the risk
incidental to the initial $1.8 billion commitment made for the first four time
charters.

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Statements, Note 12, which is incorporated herein by
reference.

NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

See Item 1, Financial Statements, Note 17, which is incorporated herein by
reference.

49

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. These statements are subject to risks and uncertainties.
Forward-looking statements include information concerning possible or assumed
future results of operations. 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;

- pending legal proceedings and claims, including environmental matters;

- future economic performance;

- operating income;

- management's plans; and

- goals and objectives for future operations.

Important factors that could cause actual results to differ materially from
estimates or projections contained in forward-looking statements are described
in our Annual Report on Form 10-K for the year ended December 31, 2001, and
other filings with the Securities and Exchange Commission.

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 Annual Report on Form
10-K for the year ended December 31, 2001, except as presented below:

COMMODITY PRICE RISK

The following table presents our potential one-day unfavorable impact on
earnings before interest and income taxes as measured by Value-at-Risk using the
historical simulation technique for our energy related contracts and is prepared
based on a confidence level of 95 percent and a one-day holding period.

Portfolio Value-at-Risk represents the combined Value-at-Risk for our
trading and non-trading price risk management activities. The separate
calculation of Value-at-Risk for trading and non-trading contracts ignores the
natural correlation that exists between commodity contracts and prices. As a
result, the individually determined values will be higher than the combined
Value-at-Risk in most instances. We manage our risks through a portfolio
approach that balances both trading and non-trading risks.

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PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item 1, Financial Statements, Note 12, which is incorporated
herein by reference.

The California cases are: five filed in the Superior Court of Los Angeles
County (Continental Forge Company, et al v. Southern California Gas Company, et
al, filed September 25, 2000; Berg v. Southern California Gas Company, et al;
filed December 18, 2000; County of Los Angeles v. Southern California Gas
Company, et al, filed January 8, 2002; The City of Los Angeles, et al v.
Southern California Gas Company, et al; and The City of Long Beach, et al v.
Southern California Gas Company, et al, both filed March 20, 2001); two filed in
the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso Merchant
Energy; and John Phillip v. El Paso Merchant Energy, both filed December 13,
2000); three filed in the Superior Court of San Francisco County (Sweetie's, et
al v. El Paso Corporation, et al, filed March 22, 2001; Philip Hackett, et al v.
El Paso Corporation, et al, filed May 9, 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). The
shareholder derivative suit was filed in district court in Harris County, Texas
(Gebhardt v. Allumbaugh, et al, filed March 15, 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 of the State of California, San
Francisco County, and Tom McClintock, et al v. Vikram Budhrajaetal, filed May 1,
2002, in the Superior Court of the State of California, Los Angeles County.

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 minimize chances 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.

The six remaining Carlsbad lawsuits are as follows: one filed in district
court in Harris County, Texas (Geneva Smith, et al v. EPEC and EPNG, filed
October 23, 2000), and five filed in state district court in Carlsbad, New
Mexico (Chapman, as Personal Representative of the Estate of Amy Smith Heady, v.
EPEC, EPNG and John Cole, filed February 9, 2001; Chapman, as Personal
Representative of the Estate of Dustin Wayne Smith, v. EPEC, EPNG and John Cole;
Chapman, as Personal Representative of the Estate of Terry Wayne Smith, v. EPNG,
EPEC and John Cole; Rackley, as Personal Representative of the Estate of Glenda
Gail Sumler, v. EPEC, EPNG and John Cole; and Rackley, as Personal
Representative of the Estate of Amanda Sumler Smith, v. EPEC, EPNG, and John
Cole, all filed March 16, 2001). We have reached a contingent settlement in an
additional case (Dawson, as Personal Representative of Kirsten Janay Sumler, v.
EPEC and EPNG, filed November 8, 2000).

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

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

On July 7, 2002, El Paso's Amended and Restated Shareholder Rights
Agreement dated as of January 20, 1999 expired. We sent notice to the New York
Stock Exchange and Pacific Exchange to deregister the rights under the Exchange
Act.
51

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

We held our annual meeting of stockholders on May 20, 2002. Proposals we
presented for a stockholders' vote included the election of eleven directors,
the adoption of an amended employee stock purchase plan, an amendment to the
certificate of incorporation, ratification of appointment of
PricewaterhouseCoopers LLP as independent certified public accountants for the
fiscal year 2002 and two stockholder proposals.

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

There were no broker non-votes for the election of directors.

Two management proposals were presented for a stockholder vote. One
proposal was to approve an amendment and restatement of El Paso's Employee Stock
Purchase Plan to increase the number of shares authorized for issuance, and the
second proposal was to approve an amendment to El Paso's Restated Certificate of
Incorporation to increase the number of shares authorized. The proposals were
approved with the following voting results:

There were no broker non-votes on the proposals.

The appointment of PricewaterhouseCoopers LLP as the Company's independent
certified public accountants for the fiscal year 2002 was ratified with the
following voting results:

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

Two proposals submitted by stockholders were presented for a stockholder
vote. One proposal called for stockholder approval for the cancellation of the
restricted stock grant program, and the second proposal called for stockholder
approval regarding the shareholder approval of any adoption of poison pills. The
first

52

stockholder proposal was not approved and the second stockholder proposal was
approved with the following voting results:

There were 56,062,552 broker non-votes on the stockholder proposal
regarding cancellation of the restricted stock grant program and 56,102,549
broker non-votes on the stockholder proposal regarding shareholder approval of
any adoption of poison pills.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

a. Exhibits

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

Undertaking

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

b. Reports on Form 8-K

We also furnished to the SEC under Item 9, Regulation FD, Current
Reports on Form 8-K. Item 9 Current Reports on Form 8-K 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." Current Reports on
Form 8-K dated May 30, June 17, July 10, July 12, July 23, July 25, and
August 8, 2002, were provided for informational purposes within this
Quarterly Report on Form 10-Q.

55

SIGNATURES

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

EL PASO CORPORATION

Date: August 13, 2002 /s/ H. BRENT AUSTIN
------------------------------------
H. Brent Austin
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

Date: August 13, 2002 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

56

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.