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:

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(1) Includes our Corporate and telecommunication activi