EL PASO CORP/DE - 10-Q Quarterly Report

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

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FORM 10-Q

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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 November 12,
2002: 598,964,891

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EL PASO CORPORATION

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

See accompanying notes.

1

EL PASO CORPORATION

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

See accompanying notes.

2

EL PASO CORPORATION

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

See accompanying notes.

3

EL PASO CORPORATION

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

See accompanying notes.

4

EL PASO CORPORATION

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

See accompanying notes.

5

EL PASO CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. BASIS OF PRESENTATION

We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the United States Securities and Exchange Commission. Because
this is an interim period filing presented using a condensed format, it does not
include all of the disclosures required by generally accepted accounting
principles. You should read it along with our 2001 Annual Report on Form 10-K
which includes a summary of our significant accounting policies and other
disclosures. The financial statements as of September 30, 2002, and for the
quarters and nine months ended September 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 4 through 8), to fairly present our interim period results. Due to
the seasonal nature of our businesses, information for interim periods may not
indicate the results of operations for the entire year. In addition, prior
period information presented in these financial statements includes
reclassifications which were made to conform to the current period presentation.
These reclassifications have no effect on our previously reported net income or
stockholders' equity.

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

Goodwill and Other Intangible Assets

Our intangible assets consist of goodwill resulting from acquisitions and
other intangible assets. 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
intangibles that have lives that are indefinite are no longer amortized. Rather,
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. We also recognized
a pretax and after-tax gain of $154 million related to the elimination 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 of goodwill during the
first quarter of 2002, and concluded we did not have any adjustment to our
goodwill amounts. The net carrying amounts and changes in the net carrying
amounts of goodwill for each of our segments for the nine month period ended
September 30, 2002, are as follows:

Our other intangible assets consist of capitalized development costs,
software licensing agreements, customer lists, our general partnership interest
in El Paso Energy Partners, L.P., and other miscellaneous intangible assets. We
amortize all intangible assets on a straight-line basis over their estimated
useful life excluding our general partnership interest in El Paso Energy
Partners which has been determined to have an indefinite life. El Paso Energy
Partners is a publicly traded master limited partnership of which our subsidiary
serves as the general partner. See Note 16 for a further discussion of our
relationships with the partnership.

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The following are the gross carrying amounts and accumulated amortization of our
other intangible assets as of:

Amortization expense of our intangible assets that were subject to
amortization was $4 million and $16 million for the quarter and nine months
ended September 30, 2002. For the quarter and nine months ended September 30,
2001, amortization of all intangible assets, including goodwill, was $14 million
and $38 million. Based on the current amount of intangible assets subject to
amortization, our estimated amortization expense is $6 million for each of the
next five years. These amounts may vary as a result of future acquisitions and
dispositions.

The following table presents our income (loss) from continuing operations
before extraordinary items and cumulative effect of accounting changes, net
income (loss) and earnings per common share for the quarter and nine months
ended September 30, 2001, as if goodwill and other indefinite-lived intangibles
had not been amortized during those periods, compared with the income (loss)
from continuing operations before extraordinary items and cumulative effect of
accounting changes, net income (loss) and earnings per common share we reported
for the quarter and nine months ended September 30, 2002:

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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 estimated operating losses in these operations. We applied
SFAS No. 144 in accounting for our coal mining operations and the proposed sale
of our San Juan assets. Our coal mining business was treated as discontinued
operations in the second quarter of 2002, and the San Juan assets were treated
as assets held for sale in the third quarter of 2002. See Notes 2 and 7 for
further information.

Early Extinguishment of Debt

During the third quarter of 2002, we adopted the provisions of SFAS No.
145, Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB
Statement No. 13, and Technical Corrections. SFAS No. 145 requires that we
evaluate any gains or losses incurred when we retire debt early to determine
whether they are extraordinary in nature or whether they should be included in
income from continuing operations in the income statement. In the third quarter
of 2002, we retired debt totaling $94 million, which resulted in a gain of $21
million. Because we believe that we will continue to retire debt in the near
term, we reported these gains as income from continuing operations, as part of
other income.

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
No. 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 No. 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.

During the second quarter of 2002, we adopted a consensus decision reached
by the Emerging Issues Task Force (EITF) in EITF Issue No. 02-3, Issues Related
to Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. The consensus required that all mark-to-market gains and losses
related to energy trading contracts, including physical settlements, be recorded
on a net basis in the income statement instead of being reported on a gross
basis as revenues for physically settled sales and expenses for physically
settled purchases. As a result of adoption, we now report our trading activity
on a net basis as a component of revenues. We also applied this guidance to all
prior periods, which had no impact on previously reported net income or
stockholders' equity. For the quarter and nine months ended September 30, 2001,
we reclassified costs of $10.6 billion and $34.3 billion to operating revenues.
In October 2002, the EITF reached several additional decisions regarding
accounting for energy trading contracts. See Note 18 for a discussion of these
decisions.

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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 generally 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 can
change if the restructured contract meets the definition of a derivative and is
therefore required to be marked to its fair value under SFAS No. 133. In the
period the restructuring is completed, the book value of the restructured
contract (if it meets the definition of a derivative) 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 operating 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 cost 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, such as in
our Mount Carmel transaction. We also employed the principles of our power
restructuring business in reaching a settlement in the first quarter of 2002 of
the dispute under our Nejapa power contract which included a cash payment to us.
We recorded these payments as operating revenues. For the nine months ended
September 30, 2002, we recognized total revenues from power restructuring and
contract termination activities of $1,160 million and total costs of $594
million. On the date the restructuring transactions were completed, revenues
recorded were $1,103 million and costs were $539 million. Revenues and costs
recorded after the initial completion date, which consisted of changes in value
of the restructured contracts and those associated with performing under the
contracts, were $57 million and $55 million.

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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. Through the date of this report, we have completed or announced the
following asset sales:

Completed Asset Sales

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(1)We did not recognize gains or losses on the natural gas and oil production
properties sold since they were not significant in terms of the total costs
or reserves in our full cost pool of properties.

(2)Proceeds of $735 million consisted of $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.

Announced Asset Sales

We have announced the sale of additional assets to third parties,
including:

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(1)These properties are in our financial statements as discontinued operations.
See Note 7 for further discussion.

The proposed San Juan asset 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, which is comprised of independent
members of the partnership's Board of Directors. In addition, we received a
fairness opinion from Deutsche Bank stating that the proceeds to be received
from El Paso Energy Partners for all of the assets being sold was fair in
relation to the value of the related assets. This transaction is subject to

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customary regulatory reviews and approvals, as well as the execution of
definitive agreements, the completion of due diligence and the partnership's
ability to successfully obtain financing for the transaction. The proposed sale
contemplates that we will receive up to $350 million of the El Paso Energy
Partners' Series C units, a new non-voting class of the partnership's limited
partner interest, with the balance of the consideration to be received in cash.
The potential $350 million amount will be reduced by the proceeds from any sale
of limited partnership interests by El Paso Energy Partners before the closing
of the San Juan asset sale. The Series C units will be issued at the greater of
$32 per unit or the average market price for the five trading days ending on the
business day immediately preceding the closing date. If the average market price
of the units is less than $27, the San Juan asset sale may be delayed,
terminated or renegotiated.

The San Juan assets have been classified as assets held for sale in our
balance sheet as of September 30, 2002, and we stopped depreciating these assets
beginning July 2002. The total assets being sold include net property, plant and
equipment and other assets of approximately $442 million. We reclassified these
assets as other current assets as of September 30, 2002, since we plan to sell
them in the next twelve months. Based upon our anticipated proceeds, we expect
to realize a gain from this sale of approximately $262 million.

The sale of our federally regulated natural gas gathering system located in
the Panhandle Field of Texas is subject to final closing pending a FERC
abandonment order.

The sale of our investments in the Alliance Pipeline and Aux Sable natural
gas liquids plant is subject to customary regulatory reviews and approvals and
the execution of definitive agreements. Based on the estimated sales price, we
recorded a loss for the quarter ended September 30, 2002, of approximately $47
million. The loss relates to our investment in Aux Sable and is included in our
Field Services segment.

Our other announced sales are subject to customary regulatory reviews and
approvals.

3. ANNOUNCED EXIT OF ENERGY TRADING ACTIVITIES

On November 8, 2002, we announced our plan to exit the energy trading
business. Our primary plan includes forming a new wholly owned subsidiary to
separately hold, manage and liquidate our trading assets and liabilities in an
orderly manner over a period of eighteen to twenty-four months. Additionally, in
October, new accounting guidance was issued which disallows the use of
mark-to-market accounting for energy-related contracts that do not qualify as
derivatives under SFAS No. 133. We are in the initial stage of evaluating the
impact of our decision to exit the energy trading business and adopting the new
accounting rules; however, we expect the carrying value of our trading assets
and liabilities, as shown on our balance sheet as of September 30, 2002, will be
written down substantially. At this time, we estimate that these events will
result in an after-tax charge of approximately $400 million to $600 million
($600 million to $900 million before tax). We expect to adopt the new accounting
rules and implement the exit strategy in the fourth quarter of 2002. For a
further discussion of our exit plan, see Item 2, Management's Discussion and
Analysis of Financial Condition, under the subheading Merchant Energy. The new
accounting guidance is further discussed in Note 18, New Accounting
Pronouncements Not Yet Adopted.

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4. RESTRUCTURING AND MERGER-RELATED COSTS AND ASSET IMPAIRMENTS

The following tables summarize our organizational restructuring and
merger-related costs and asset impairments for the periods ended September 30:

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 the second and third quarters of 2002, we completed an employee
restructuring across all of our operating segments which resulted in a reduction
of approximately 509 full-time positions through terminations. Through September
30, 2002, we had incurred and paid $23 million of employee severance and
termination costs in connection with these actions. We also incurred fees of $40
million to eliminate stock price and credit rating triggers related to our
Chaparral and Gemstone investments. This amount was paid in the second quarter
of 2002. See Note 16 for further information on the Chaparral and Gemstone
amendments.

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Merger-Related Costs

Employee severance, retention and transition costs include direct payments
to, and benefit costs for, severed employees and early retirees that occurred as
a result of our merger-related workforce reduction and consolidation. Following
our merger with The Coastal Corporation (Coastal), we completed an employee
restructuring across all of our operating segments, resulting in the reduction
of 3,285 full-time positions through a combination of early retirements and
terminations. Employee severance costs include actual severance payments and
costs for pension and post-retirement benefits settled and curtailed under
existing benefit plans as a result of these restructurings. Retention charges
include payments to employees who were retained following the mergers and
payments to employees to satisfy contractual obligations. Transition costs
relate to costs to relocate employees and costs for severed and retired
employees arising after their severance date to transition their jobs into the
ongoing workforce.

Employee severance, retention, and transition costs for the nine months
ended September 30, 2001, were approximately $829 million which include pension
and post-retirement benefits of $214 million which were accrued at the merger
date and will be paid over the applicable benefit periods of the terminated and
retired employees. All other costs were expensed as incurred and have been paid.
Also included in the 2001 employee severance, retention and transition costs was
a charge of $278 million resulting from the issuance of approximately 4 million
shares of common stock on the date of the Coastal merger in exchange for the
fair value of Coastal employees' and directors' stock options and restricted
stock. A total of 339 employees and 11 directors received these shares.

Transaction costs for the nine months ended September 30, 2001, were $70
million which 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 mergers. All of these items
were expensed in the periods in which they were incurred.

Business and operational integration costs include charges to consolidate
facilities and operations of our business segments. Total charges for the nine
months ended September 30, 2001, were $424 million, of which $153 million
related to a charge resulting from a mark-to-market loss on an energy-related
contract for transportation capacity on the Alliance Pipeline. Prior to the
merger, this contract was managed by Coastal's Production segment. Following the
merger, it was determined that this contract should be managed by our trading
group, consistent with our energy-related pipeline capacity contracts. As a
result, it was transferred to Merchant Energy. The charge reflects the estimated
realizable value of the contract as an energy-related trading contract. Our
integration costs also include incremental fees under software and seismic
license agreements of $15 million, which were recorded in our Production
segment, and approximately $250 million in estimated lease-related costs to
relocate our pipeline operations from Detroit, Michigan to Houston, Texas and
from El Paso, Texas to Colorado Springs, Colorado incurred in both our Pipelines
and Corporate segments. 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 agreements. All other costs were
expensed as incurred.

Merger-related asset impairments for the nine months ended September 30,
2001, were $149 million which relate to write-offs or write-downs of capitalized
costs for duplicate systems, redundant 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. Our Merchant Energy segment
incurred $116 million in asset impairment charges primarily related to the
write-down of $37 million for the Oyster Creek refining facility which was shut
down following the merger, $35 million for the Kansas refinery which was closed
as part of the sale of retail outlets in the Midwest, $20 million for
capitalized development costs primarily associated with our petroleum operations
and $24 million for other assets. Included in our Production segment was a $16
million charge to write-down Australian and Indonesian international assets
since the decision was made following the merger to no longer actively seek
future exploratory drilling opportunities in these areas. Additional charges of
$16 million were incurred in the Pipelines segment primarily to write-off
investments in the Whitecap and the Supply Link projects, both of which were
pipeline projects discontinued following the merger. All of these assets have
either had their operations suspended or continue to be held for use. The
charges taken were based

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on a comparison of the cost of the assets to their estimated fair value to the
ongoing operations based on our changes in operating strategy.

Other costs for the nine months ended September 30, 2001, were $213 million
which include payments made in satisfaction of obligations arising from the
approval of our merger with Coastal and other miscellaneous charges. These items
were expensed in the period in which they were 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.
In this regard, we have filed a Notice of Dispute against the Argentine
government under the Bilateral Investment Treaty asserting that actions taken by
the government are contrary to the rights granted to investors under the treaty.
Any opportunity for recovery under the treaty is uncertain.

The 2001 asset impairment charges of $107 million resulted primarily from a
$39 million write-down in our Merchant Energy segment for our investment in East
Asia Power, an international power project in the Philippines, a $45 million
write-down for our investment in Velocom, a telecommunications company in
Brazil, and $15 million for our investment in Telergy, a telecommunication
provider in the New York metropolitan area. Our telecommunications impairments
have been included in our Corporate and Other operations. These impairments were
a result of weak or changing economic conditions causing permanent declines in
the value of these assets, and the charges taken were based on a comparison of
each asset's carrying value to its estimated fair value based on future
estimated cash flows.

5. CEILING TEST CHARGES

Under the full cost method of accounting for natural gas and oil production
properties, we perform quarterly ceiling tests to evaluate whether the carrying
value of natural gas and oil production 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.

During the nine months ended September 30, 2002, we recorded ceiling test
charges of $267 million, of which $33 million was charged during the first
quarter and $234 million was charged 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 June 30, 2002, which was approximately $1.43 per million
British thermal units.

For the nine months ended September 30, 2001, we recorded ceiling test
charges of $135 million, including $87 million for our Canadian full cost pool,
$28 million for our Brazilian full cost pool, and $20 million for other
international production operations, primarily in Turkey. Our third quarter 2001
charges are based on the daily posted gas and oil prices as of November 1, 2001,
adjusted for oilfield or gas gathering hub and wellhead price differences as
appropriate. Had we computed the third quarter 2001 ceiling test charges based
upon the daily posted gas and oil prices as of September 30, 2001, we would have
incurred a
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ceiling test charge of $275 million. The amount would have included $227 million
for our Canadian full cost pool and $48 million for our Brazilian full cost pool
and other international production operations.

We use financial instruments to hedge against the volatility of natural gas
and oil prices. The impact of these hedges was considered in determining our
ceiling test charges, and will be factored into future ceiling test
calculations. Had the impact of our hedges not been included in calculating our
third quarter 2001 ceiling test charges, we would have incurred a third quarter
charge of $576 million at September 30, 2001, relating to our domestic full cost
pool. The charges for our international cost pools would not have materially
changed since we do not significantly hedge our international production
activities.

6. CHANGES IN ACCOUNTING ESTIMATES

Included in our operation and maintenance costs for the quarter and nine
months ended September 30, 2001, were approximately $113 million and $316
million in costs related to changes in accounting estimates. The costs for the
nine months ended September 30, 2001, consist of $229 million in additional
environmental remediation liabilities, $48 million in additional accrued legal
obligations and a $39 million charge to reduce the value of our spare parts
inventories to reflect changes in the usability of these parts in our worldwide
operations. The change in our estimated environmental remediation liabilities
was due to a number of events, including $109 million resulting from the sale of
a majority of our retail gas stations, $31 million related to our closure of our
Gulf Coast Chemical and Midwest refining operations, $10 million associated with
the lease of our Corpus Christi refinery to Valero, and $79 million associated
with conforming Coastal's methods of environmental identification, assessment
and remediation strategies and processes to our historical practices following
our merger with Coastal. The change in estimate of our legal obligations was a
result of a review process to assess our legal exposures, strategies and plans
following the merger with Coastal. Finally, the charge related to our spare
parts inventories was primarily the result of several events that occurred as
part of and following our merger with Coastal, including the consolidation of
numerous operating locations, the sale of a majority of our retail gas stations,
the shutdown of our Midwest refining operations and the lease of our Corpus
Christi refinery. These charges were also a direct result of a fire at our Aruba
refinery whereby a portion of the plant was rebuilt following the fire rendering
many of these parts unusable. Also impacting these amounts was the evaluation of
the operating standards, strategies and plans of our combined company following
the merger. Our changes in accounting estimates have reduced our after-tax
earnings by approximately $76 million and $214 million for the quarter and nine
months ended September 30, 2001.

7. 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 our
Merchant Energy segment, consist of fifteen active underground and two surface
mines located in Kentucky, Virginia and West Virginia. Following the
authorization of the sale by our Board of Directors, we compared the carrying
value of the underlying assets to our estimated sales proceeds, net of estimated
selling costs, based on bids received in the sales process in the second and
third quarters of 2002. Because this carrying value was higher than our
estimated net sales proceeds, we recorded impairment charges of $148 million in
the second quarter of 2002 and $37 million in the third quarter of 2002.

We expect that our coal mining business will be sold in two parts: (1) coal
reserves and properties and (2) coal mining operations. In November 2002, we
announced an agreement to sell substantially all of our reserves and properties
in West Virginia, Virginia and Kentucky to an affiliate of Natural Resources
Partners, L.P. for $69 million. We expect to complete the sale, subject to
regulatory reviews and approvals, in the fourth quarter of 2002. We expect to
enter into agreements to sell the coal mining operations within the next six
months.

15

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 September 30, 2002 to other 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:

8. EXTRAORDINARY ITEMS

Under a Federal Trade Commission 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 nine months ended September 30, 2001, net proceeds
from these sales were approximately $279 million. We recognized extraordinary
net gains of approximately $26 million, net of income taxes of approximately $27
million, including a third quarter 2001 charge of $5 million to record
additional estimated income taxes on these sales.

16

9. EARNINGS PER SHARE

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

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

(1) Due to their antidilutive effect on earnings per common share, for 2002, we
excluded a total of 16 million shares for all potentially dilutive
securities, and for 2001, we excluded a total of 8 million shares for the
assumed conversion of convertible debentures.

17

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

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

(1) Due to their antidilutive effect on earnings per common share, for 2002, we
excluded a total of 16 million shares for all potentially dilutive
securities, 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.

18

10. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

The following table summarizes the carrying value of our trading and
non-trading price risk management assets and liabilities as of September 30,
2002 and December 31, 2001:

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

(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. See Note 18 for a discussion of changes in the
accounting rules that will impact our accounting for energy trading
contracts.

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

(3) We do not 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.

(4) Net assets from price risk management activities include current and
non-current assets and current and non-current liabilities from price risk
management activities on the balance sheet.

Included in other derivatives as of September 30, 2002, are $963 million of
derivative contracts related to the power restructuring activities of our
consolidated subsidiaries. Of this amount, $872 million relates to a power
restructuring that occurred during the first quarter of 2002 at our Eagle Point
Cogeneration power plant, and $91 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 $6 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 that were sold during 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 make adjustments to this discount rate when we believe that
market changes in the rates result in changes in fair values that can be
realized. We consider whether changes in the rates are the result of changes in
the capital markets, or are the result of sustained economic changes. During the
third quarter, treasury rates declined. We did not adjust our discount rate for
this decline in treasury rates since this decrease, combined with the
significant uncertainties in the capital markets, did not result in an increased
fair value that we believe could have been realized in the market. 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 may change 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, and we removed the hedging
designation on derivatives that had a fair value loss of

19

$91 million at September 30, 2002. This amount, net of income taxes of $33
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 $58 million in accumulated other comprehensive income,
we estimate that unrealized losses of $20 million, net of income taxes, related
to these derivatives will be reclassified to income over the next twelve months.

11. INVENTORY

Our inventory consisted of the following:

12. DEBT AND OTHER CREDIT FACILITIES

At September 30, 2002, our weighted average interest rate on our commercial
paper and short-term credit facilities was 2.4%, and at December 31, 2001, it
was 3.2%. We had the following short-term borrowings and other financing
obligations:

Our commercial paper program is currently rated at A3/P3. As a result, we
do not have the current ability to issue commercial paper at attractive rates.
Through the date of this filing, we repaid all of our outstanding commercial
paper, except for $8 million.

20

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.

Issuances

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

(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 September 30,
2002, and includes a $44 million change in value due to a change in the Euro
to U.S. dollar foreign currency exchange rate from the issuance date to
September 30, 2002.

(3) These senior notes relate to an offering of 11.5 million 9% equity security
units, which include forward purchase contracts on El Paso common stock to
be settled on August 16, 2005. See Note 14 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.

21

Retirements

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

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

(2) The majority of this debt was exchanged for equity. See Note 14 for further
discussion.

Credit Facilities

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 and, as such, are liable for any amounts outstanding. 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 Company (formerly The Coastal
Corporation), EPNG and TGP are designated borrowers under this facility and, as
such, are liable for any amounts outstanding. The interest rate under both of
these facilities varies based on our senior unsecured debt rating, and as of
September 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 September 30, 2002, there were no borrowings outstanding;
however, we have issued $492 million of letters of credit under the $1 billion
facility.

In September 2002, Moody's lowered our senior unsecured debt rating from
Baa2 to Baa3, and in November 2002, Standard and Poor's lowered our senior
unsecured debt rating from BBB to BBB-. As a result of these actions, the
current interest rate on an initial draw under both of our credit facilities
would be at a rate of LIBOR plus 0.80%, plus a 0.25% utilization fee for drawn
amounts above 25% of the committed amounts.

22

Restrictive Covenants

We and our subsidiaries have entered into debt instruments and guaranty
agreements that contain covenants such as restrictions on debt levels,
restrictions on liens securing debt and guarantees, restrictions on mergers and
on the sales of assets, capitalization requirements, dividend restrictions and
cross-payment default and cross-acceleration provisions. A breach of any of
these covenants could result in acceleration of our debt and other financial
obligations and that of our subsidiaries.

Under our revolving credit facilities, the significant debt covenants and
cross defaults are:

(a) the ratio of consolidated debt and guarantees to capitalization
cannot exceed 70 percent (excluding certain project financing and
securitization programs and other miscellaneous items);

(b) the consolidated debt and guarantees (other than excluded items)
of our subsidiaries cannot exceed the greater of $600 million or
10 percent of our consolidated net worth;

(c) we or our principal subsidiaries cannot permit liens on the equity
interest in our principal subsidiaries or create liens on assets
material to our consolidated operations securing debt and
guarantees (other than excluded items) exceeding the greater of
$300 million or 10 percent of our consolidated net worth, subject
to certain permitted exceptions; and

(d) the occurrence of an event of default for any non-payment of
principal, interest or premium with respect to debt (other than
excluded items) in an aggregate principal amount of $200 million
or more; or the occurrence of any other event of default with
respect to such debt that results in the acceleration thereof.

We were in compliance with the above covenants as of the date of this
filing, and no borrowings were outstanding under our revolving credit
facilities; however, we have issued $492 million of letters of credit under the
$1 billion facility.

We have also issued various guarantees securing financial obligations of
our subsidiaries and unconsolidated affiliates with similar covenants as in the
above credit facilities.

With respect to guarantees issued by our subsidiaries, the most significant
debt covenant, in addition to the covenants discussed above, is that El Paso CGP
maintain a minimum net worth of $1.2 billion. If breached, the amounts
guaranteed by the guaranty agreements could be accelerated. The guaranty
agreements also have a $30 million cross-acceleration provision.

In addition, three of our subsidiaries have indentures associated with
their public debt that contain $5 million cross-acceleration provisions.

13. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

California Lawsuits. We and several of our subsidiaries have been named as
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). These suits contend that our entities acted
improperly to limit the construction of new pipeline capacity to California
and/or to manipulate the price of natural gas sold into the California
marketplace. Specifically, the plaintiffs argue that our conduct violates
California's antitrust statute (Cartwright Act), constitutes unfair and unlawful
business practices prohibited by California statutes, and amounts to a violation
of California's common law restrictions against monopolization. In general, the
plaintiffs are seeking (i) declaratory and injunctive relief regarding allegedly
anticompetitive actions, (ii) restitution, including treble damages, (iii)
disgorgement of profits, (iv) prejudgment and post-judgment interest, (v) costs
of prosecuting the actions and (vi) attorney's fees. The lawsuits have been
consolidated before a single judge and are at the preliminary pleading stages
with trial scheduled for September 2003 on several of the cases. 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
23

lawsuits. The derivative suit originally was filed in California, but was
dismissed and refiled in Texas in March 2002. At this time, our legal exposure
related to these lawsuits and claims is not determinable.

In September 2001, we received a civil document subpoena from the
California Attorney General, seeking information said to be relevant to the
Department's ongoing investigation into the high electricity prices in
California. We are continuing to cooperate in responding to their discovery
requests.

Nevada Lawsuit. The state of Nevada and four individuals have purportedly
filed a lawsuit in District Court for Clark County, Nevada on November 1, 2002,
naming us and a number of our subsidiaries and affiliates as defendants. While
the complaint has not yet been served on us, we believe that its allegations are
similar to those in the California cases. The suit purportedly seeks
unquantified monetary damages, to be trebled, general and special damages and
attorney fees and costs.

Shareholder Class Action Suits. Beginning in July 2002, twelve purported
shareholder class action suits alleging violations of federal securities laws
have been filed against us and several of our officers. Eleven of these suits
are now consolidated in federal court in Houston before a single judge (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. One shareholder derivative lawsuit
was filed in federal court in Houston in August 2002. This derivative action
generally alleges the same claims as those made in the shareholder class action,
has been consolidated with the shareholder class actions pending in Houston and
has been stayed. A second shareholder derivative lawsuit was filed in Delaware
State Court in October 2002 and generally alleges the same claims as those made
in the consolidated shareholder class action lawsuit. The twelfth shareholder
class action lawsuit was filed in federal court in New York City in October 2002
and challenges the accuracy or completeness of our February 27, 2002 prospectus
for an equity offering that was completed on June 21, 2002 (a list of the
shareholder derivative suits is included in Part II, Item I, Legal Proceedings).
We have not been formally served with this lawsuit.

Carlsbad. In August 2000, a main transmission line owned and operated by
EPNG ruptured at the crossing of the Pecos River near Carlsbad, New Mexico.
Twelve individuals at the site were fatally injured. On June 20, 2001, the U.S.
Department of Transportation's Office of Pipeline Safety issued a Notice of
Proposed Violation against EPNG. The Notice alleged five violations of its
regulations (a list of the alleged five violations is included in Part II, Item
1, Legal Proceedings), proposed fines totaling $2.5 million and proposed
corrective actions. We have fully accrued for these fines. In October 2001, EPNG
filed a 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. EPNG is cooperating with the National Transportation Safety Board in
an investigation into the facts and circumstances concerning the possible causes
of the rupture. On November 1, 2002, EPNG received a federal grand jury subpoena
for documents relating to the rupture and will comply fully with the subpoena.
In addition, a number of personal injury and wrongful death lawsuits were filed
against EPNG in connection with the rupture. All but one of these suits have
been settled. The settlement payments have been fully covered by insurance. In
connection with the settlement of the cases, EPNG has agreed to contribute $10
million to a charitable foundation as a memorial to the families involved. This
contribution will not be covered by insurance. The remaining case is Geneva
Smith, et al vs. EPEC and EPNG filed October 23, 2000 in Harris County, Texas.

24

Grynberg. In 1997, a number of our subsidiaries were named defendants in
actions brought by Jack Grynberg on behalf of the U.S. Government under the
False Claims Act. Generally, these complaints allege an industry-wide conspiracy
to underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands, which deprived the U.S.
Government of royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and heating value of
natural gas produced from royalty properties been differently measured,
analyzed, calculated and reported, together with interest, treble damages, civil
penalties, expenses and future injunctive relief to require the defendants to
adopt allegedly appropriate gas measurement practices. No monetary relief has
been specified in this case. These matters have been consolidated for pretrial
purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court
for the District of Wyoming, filed June 1997). In May 2001, the court denied the
defendants' motions to dismiss.

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

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

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

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of September 30, 2002, we had approximately $139 million accrued for all
outstanding legal matters, including $10 million accrued for our contribution to
a charitable foundation.

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 September 30, 2002, we had accrued approximately $518 million,
including approximately $492 million for expected remediation costs and
associated onsite, offsite and groundwater technical studies, and approximately
$26 million for related environmental legal costs, which we anticipate incurring
through 2027. Approximately

25

$15 million of the accrual was related to discontinued coal mining operations.
Our reserves are based on the following estimates of reasonably possible
outcomes:

Below is a reconciliation of our accrued liability as of December 31, 2001
to our accrued liability as of September 30, 2002 (in millions):

Balance as of December 31, 2001............................. $564
Additions/adjustments for remediation activities............ 13
Payments for remediation activities......................... (43)
Other changes, net.......................................... (16)
----
Balance as of September 30, 2002............................ $518
====

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. For the fourth quarter of 2002, we estimate that our total
expenditures will be approximately $29 million, of which $1 million we estimate
will be for capital related expenditures. In addition, approximately $20 million
of this amount will be expended under government directed clean-up plans. The
remaining $8 million will be self-directed or in connection with facility
closures.

Internal PCB Remediation Project. Since 1988, TGP, our subsidiary, has
been engaged in an internal project to identify and 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
remediation activities. TGP is also working with the Pennsylvania and New York
environmental agencies regarding remediation and post-remediation activities at
the Pennsylvania and New York stations.

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

PCB Cost Recoveries. In May 1995, following negotiations with its
customers, TGP filed an agreement with the 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
September 30, 2002, TGP has over-collected PCB costs by approximately $114
million. The over-collection will be reduced by future eligible costs incurred
for the remainder of the

26

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. As of September 30, 2002, TGP has recorded a regulatory
liability (included in other non-current liabilities on our balance sheet) for
future refund obligations of approximately $53 million. This agreement also
provides for carrying charges incurred up to the date of the refunds.

Coastal Eagle Point. From May 1999 to March 2001, our Coastal Eagle Point
Oil Company received several Administrative Orders and Notices of Civil
Administrative Penalty Assessment from the New Jersey Department of
Environmental Protection. 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. At the agency's request, the
administrative law judge put the hearings on inactive status until December 2002
to allow time for settlement discussions.

EPA Fuel Regulations. 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
have settled with the EPA for $120,000. The settlement agreement also includes
an additional $52,500 penalty for a self-disclosed fuels noncompliance. We
expect to pay the total settlement of $172,500 in the fourth quarter of 2002.

CERCLA Matters. 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 57
active sites under the Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA) or state equivalents. We have sought to resolve our
liability as a PRP at these sites through indemnification by third parties and
settlements which provide for payment of our allocable share of remediation
costs. As of September 30, 2002, we have estimated our share of the remediation
costs at these sites to be between $30 million and $41 million, and we have
established reserves which are included in the environmental reserves discussed
above. We believe our reserves 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.

Rates and Regulatory Matters

Wholesale Power Customers' Complaints. In late 2001 and early 2002,
several wholesale power customers filed complaints (a list of the complaints is
included in Part II, Item 1, Regulatory Proceedings) with the FERC against El
Paso Merchant Energy, L.P. (EPME) and other wholesale power marketers. These
customers entered into contracts with EPME and other wholesale power suppliers
for the purchase of power to be delivered in the future. Based on allegations in
the complaints, these customers have asked the FERC to reform the contracts they
entered into with EPME and other wholesale power marketers on the grounds that
they involve rates and terms that are "unjust and unreasonable" or "contrary to"
the public interest within the meaning of the Federal Power Act (FPA). EPME and
other respondents believe the allegations in the complaint are without merit and
have asked the FERC to dismiss these complaints. A hearing relating to the first
complaint was completed on October 22, 2002 and an initial decision from the
presiding administrative law judge (ALJ) is expected by December 31, 2002.
Hearings for all but one of the remaining complaints are set for December 2002,
with decisions in those cases by the respective presiding ALJs expected by late
February 2003. The decisions of the ALJs will then be submitted to the FERC for
its review. The FERC has not yet acted on the last complaint filed, so no
hearing has been scheduled in that matter.

27

CPUC Complaint Proceeding. In April 2000, the Public Utilities Commission
of the State of California (CPUC) filed a complaint under Section 5 of the
Natural Gas Act (NGA) with the FERC alleging that the sale of approximately 1.2
billion cubic feet per day of capacity by EPNG to EPME, both of whom are our
wholly owned subsidiaries, raised issues of market power, violation of FERC's
marketing affiliate regulations and asked that the contracts be voided. Although
the FERC held that EPNG did not violate its marketing affiliate requirements, it
established a hearing before an ALJ to address the market power issue. In the
spring and summer of 2001, two hearings were held before the ALJ to address the
market power issue and, at the request of the ALJ, the affiliate issue. In
October 2001, the ALJ issued an initial decision on the two issues, finding that
the record did not support a finding that either EPNG or EPME had exercised
market power and that accordingly the market power claims should be dismissed.
The ALJ found, however, that EPNG had violated the marketing affiliate rules.
EPNG and other parties filed briefs on exceptions and briefs opposing exceptions
to the October initial decision.

Also in October 2001, the FERC's Office of Market Oversight and Enforcement
filed comments stating that the record at the hearings was inadequate to
conclude that EPNG had complied with FERC regulations in the transportation of
gas to California. In December 2001, the FERC remanded the proceeding to the ALJ
for a supplemental hearing on the availability of capacity at our California
delivery points. On September 23, 2002, the ALJ issued his initial decision,
again finding that there was no evidence that EPME had exercised market power
during the period at issue to drive up California gas prices and therefore
recommended that the complaint against EPME be dismissed. However, the ALJ found
that EPNG had withheld at least 345 MMcf/d of capacity (and perhaps as much as
696 MMcf/d) from the California market during the period from November 1, 2000
through March 31, 2001. The ALJ found that this alleged withholding violated
EPNG's certificate obligations and was an exercise of market power that
increased the gas price to California markets. He therefore recommended that the
FERC initiate penalty procedures against EPNG. EPNG and others filed briefs on
exceptions to the initial decision on October 23, 2002. In support of EPNG's
request, EPNG informed the FERC that the initial decision is inconsistent with
the facts, the law, and FERC policy and urged the FERC to reverse it. Briefs
opposing exceptions were filed on November 12, 2002. Oral argument, currently
set for December 2, 2002, will be heard by the FERC commissioners prior to the
issuance of an order on the initial decisions.

Systemwide Capacity Allocation Proceeding. In July 2001, several of EPNG's
customers who hold contracts with volumetric ceilings (Contract Demand or CD
customers) filed a complaint against EPNG at the FERC under Section 5 of the NGA
claiming, among other things, that EPNG's full requirements contracts (contracts
with no volumetric limitations) with customers located east of California (EOC)
should be converted to CD contracts, that EPNG should be required to expand its
system to serve all of its customers' growing requirements instead of relying on
the pro rata allocation provisions of its FERC approved tariff to allocate its
available capacity among its EOC and CD customers, and that EPNG should be
required to give demand charge credits to its CD customers when EPNG is unable
to meet their full contract demands. Likewise, in July 2001, several of EPNG's
EOC customers filed a complaint under Section 5 of the NGA alleging that EPNG
had violated the NGA and EPNG's contractual obligations to them by not expanding
its system, at EPNG's own cost, to meet their increased requirements.

On May 31, 2002, the FERC issued an order on the complaints in which it
required that (i) full requirements service, for all EOC customers other than
small volume customers, be converted to service with specified volumetric rights
(i.e., contract demand service); (ii) firm customers be assigned specific
receipt point rights in lieu of their existing systemwide receipt point rights;
(iii) EPNG prospectively give reservation charge credits to all firm customers
for any failure to schedule confirmed volumes except in cases of force majeure;
(iv) EPNG refrain from entering into new firm contracts until EPNG has
demonstrated that it has adequate capacity on the system; and (v) EPNG conduct a
process to allow existing CD customers to turn back capacity for acquisition by
full requirements customers. The FERC indicated in the May 31 order that EPNG
was to remain revenue neutral as a result of this turnback process. In addition,
the order stated that the FERC expected EPNG to file for certificate authority
to add compression to its Line 2000 project, thereby increasing its system
capacity by 320 MMcf/d, without cost coverage until the next rate case (which
will be January 1, 2006). EPNG had previously stated it was willing to add
compression to the project at a public

28

conference held in April 2002, provided it was assured of rate coverage in the
next rate case. The May 31 order established dates by which the steps necessary
to implement the order's requirements would be completed. The changes required
by the order were to be made effective November 1, 2002.

On July 1, 2002, EPNG and numerous other parties filed for clarification
and/or rehearing of the May 31 order. Although the order required the full
requirements customers to agree among themselves on an appropriate allocation of
unsubscribed westflow pipeline capacity by July 31, 2002, the customers failed
to reach such an agreement. On September 20, 2002, the FERC issued an order
postponing the effective date of the conversions required by their May 31 order
until May 1, 2003. The order instructed EPNG to allocate among its full
requirements customers the 320 MMcf/d of capacity that will be available once
compression is added to Line 2000 (which the FERC estimated would be in the
summer of 2003; however, EPNG anticipates the first and second phases of the
compression will be in service by mid 2004, and has so advised the FERC). In
addition, the order prohibited EPNG from reselling any firm capacity that
expires under existing contracts between May 31, 2002, and May 1, 2003,
requiring instead that EPNG allocate this capacity to its full requirements
customers. In total, the September 20 order requires that EPNG's full
requirements customers pay only their current reservation charges for existing
unsubscribed capacity, for the 230 MMcf/d of capacity that was made available in
November 2002 by the Line 2000 project, for the additional 320 MMcf/d of
capacity to be available once the compression of Line 2000 is completed, and for
all capacity subject to contracts expiring before May 1, 2003. Beginning May 1,
2003, EPNG will be required to pay reservation charge credits when it is unable
to schedule confirmed volumes except in cases of force majeure. Between November
1, 2002, and May 1, 2003, EPNG is required to pay reservation charge credits to
CD customers when it is unable to schedule 95 percent of their confirmed volumes
except for reasons of force majeure and provided that there is no capacity
available to meet their needs from other supply basins on its system.

Several pleadings have been filed in response to the September 20 order,
including requests by several customers to modify the order based on the ALJ's
decision in the CPUC Complaint Proceeding discussed above, requests by customers
and others to vacate and/or stay the order and our responses to those pleadings,
and numerous applications for rehearing and/or clarification filed by EPNG and
others. All such motions and requests remain pending before the FERC. On
November 1, 2002, the FERC issued a tolling order to allow it additional time to
act upon the requests for rehearing and indicated that it anticipates issuing an
order on rehearing by January 31, 2003. EPNG anticipates that in the order the
FERC will address the various motions made as well as the requests for
clarification and rehearing. In the interim, EPNG is proceeding with the
directives contained in the September 20 order.

Line 2000 Project. On July 31, 2000, EPNG applied with the FERC for a
certificate of public convenience and necessity for its Line 2000 project, which
was designed to replace old compression on the system with a converted oil
pipeline, resulting in no increase in system capacity. In response to demand
conditions on EPNG's system, however, EPNG filed in March 2001 to amend its
application to convert the project to an expansion project of 230 MMcf/d. On May
7, 2001, the FERC authorized the amended Line 2000 project. EPNG has received
authorization to place the line in service, and anticipates having all segments
of Line 2000 in service by mid-November 2002 at a total estimated capital cost
of $185 million.

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

Marketing Affiliate NOPR. In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct
governing the relationship between interstate pipelines and marketing affiliates
to all energy affiliates. The proposed regulations, if adopted by the FERC,
would dictate how all our energy affiliates conduct business and interact with
our interstate pipelines. In December 2001, we filed comments with the FERC
addressing our concerns with the proposed rules. A

29

public hearing was held on May 21, 2002, providing an opportunity to comment
further on the NOPR. Following the conference, additional comments were filed by
our pipeline subsidiaries and others. At this time, we cannot predict the
outcome of the NOPR, but adoption of the regulations in their proposed form
would, at a minimum, place additional administrative and operational burdens on
us.

Negotiated Rate NOI. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that seeks comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. Several of our pipelines have entered
into these transactions over the years, and the FERC is now reviewing whether
negotiated rates should be capped, whether or not the "recourse rate" (a
cost-of-service based rate) continues to safeguard against a pipeline exercising
market power, as well as other issues related to negotiated rate programs. On
September 25, 2002, our pipelines and others filed comments. Reply comments were
filed on October 25, 2002. At this time, we cannot predict the outcome of this
NOI.

Cash Management NOPR. On August 1, 2002, the FERC issued a NOPR requiring
that all cash management or money pool arrangements between a FERC regulated
subsidiary and a non-FERC regulated parent must be in writing, and set forth:
the duties and responsibilities of cash management participants and
administrators; the methods of calculating interest and for allocating interest
income and expenses; and the restrictions on deposits or borrowings by money
pool members. The NOPR also requires specified documentation for all deposits
into, borrowings from, interest income from, and interest expenses related to,
these arrangements. Finally, the NOPR proposed that as a condition of
participating in a cash management or money pool arrangement, the FERC regulated
entity maintain a minimum proprietary capital balance of 30 percent, and the
FERC regulated entity and its parent maintain investment grade credit ratings.
On August 28, 2002, comments were filed. The FERC held a public conference on
September 25, 2002, to discuss the issues raised in the comments.
Representatives of companies from the gas and electric industries participated
on a panel and uniformly agreed that the proposed regulations should be revised
substantially and that the proposed capital balance and investment grade credit
rating requirements would be excessive. At this time, we cannot predict the
outcome of this NOPR.

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

Australia. In June 2001, the Western Australia regulators issued a draft
rate decision at lower than expected levels for the Dampier-to-Bunbury pipeline
owned by EPIC Energy Australia Trust, in which we have a 33 percent ownership
interest and a total investment, including financial guarantees, of
approximately $200 million. EPIC Energy Australia 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 we
received a favorable ruling in August 2002. The court directed the regulator to
review its position and comply with applicable regulatory law. A resolution is
expected in 2003. If the original 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 $140 million.
Additionally, EPIC Energy (WA) Nominees Pty. Ltd. has debt of approximately
AUD$1.8 billion (U.S.$1 billion) maturing in March 2003. Uncertainty about the
future rates may impact this refinancing.

Southwestern Bell Proceeding. We are engaged in proceedings with
Southwestern Bell involving disputes regarding our telecommunications
interconnection agreement in our metropolitan transport business. In July 2002,
we received a favorable ruling from the administrative law judge in Phase 1 of
the proceedings. We anticipate a determination from the Public Utilities
Commission (PUC) of Texas on the administrative law judge's recommendation no
later than the first quarter of 2003. Despite the favorable ruling from the
administrative law judge, the PUC retains the right to affirm or reject the
award and any significant rejection of the award could negatively impact our
metro transport business. An adverse resolution to the proceeding by the PUC
could have a negative impact on our ongoing operations and prospects in this
business.

30

California Trading Strategies. 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.

Wash Trade Inquiries. On May 21 and 22, 2002, the FERC issued 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. In
May and June 2002, EPME responded, denying that it had conducted any wash or
round trip trades (i.e., simultaneous, prearranged trades entered into for the
purpose of artificially inflating trading volumes or revenues, or manipulating
prices).

On June 7, 2002, we received an informal inquiry from the SEC regarding the
issue of round trip trades. Although we do not believe any round trip trades
occurred, we submitted data to the SEC on July 15, 2002. On July 12, 2002, we
received a federal grand jury subpoena for documents concerning so-called round
trip or wash trades. We have complied with these requests.

Price Reporting to Indices. On October 22, 2002, the FERC issued a data
request to all of the largest North American Gas Marketers, including EPME,
regarding price reporting of transactional data to the energy trade press. We
have engaged an outside firm to investigate fully the matters raised in the data
request. We have identified at least one incident in which it appears that
inaccurate pricing information may have been provided to a trade publication. We
are cooperating fully with the FERC in this matter.

Refunds Pricing. On August 13, 2002, the FERC issued a Notice Requesting
Comment on Method for Determining Natural Gas Prices for Purposes of Calculating
Refunds in ongoing California refund proceedings dealing with sales of electric
power in which some of our companies are involved. Referencing a Staff Report
also issued on August 13, 2002, the FERC requested comments on whether it should
change the method for determining the delivered cost of natural gas in
calculating the mitigated market-clearing price in the refund proceeding and, if
so, what method should be used. Comments were filed on October 15, 2002. We
cannot predict the outcome of this proceeding.

While the outcome of our outstanding legal matters, environmental matters
and rates and regulatory matters cannot be predicted with certainty, based on
the information we know now 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 these matters. It is also possible that these matters could
impact our credit rating. See Item 2, Management's Discussion and Analysis under
the subheading Recent Developments. Further, for environmental matters, it is
also possible that other developments, such as increasingly strict environmental
laws and regulations and claims for damages to property, employees, other
persons and the environment resulting from our current or past operations, could
result in substantial costs and liabilities in the future. As new information
for our outstanding legal matters, environmental matters and rates and
regulatory matters becomes available, or relevant developments occur, we will
review our accruals and make any appropriate adjustments. The impact of these
changes may have a material effect on our results of operations and on our cash
flows in the period the event occurs.

Other Commercial Commitments

In 2001, our subsidiaries 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 of our subsidiaries under the
five time-charter agreements is approximately $2.5 billion over the term of the
time charters. If our subsidiaries were unable to fulfill their obligations
under the five time charter arrangements, our maximum
31

commitment, in the form of corporate guarantees and letters of credit, would be
$254 million, which will increase to $290 million if we exercise the option for
the time charter on the fifth ship. 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

Enron Bankruptcy. 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 NGL and the trading of physical
natural gas, power, petroleum and financial derivatives.

Our Merchant Energy positions are governed under a master International
Swap Dealers Association, Inc. agreement, various master natural gas agreements,
a master power purchase and sale agreement, and other commodity agreements. We
terminated most of these trading-related contracts, which we believe was proper
and in accordance with the terms of these contracts. In October 2002, we filed
proofs of claim against Enron trading entities in an amount totaling
approximately $318 million. After considering the cash margins Enron has
deposited with us as well as the reserves we have established, our Merchant
Energy exposure to Enron is $29 million, which is classified as current accounts
and notes receivable. We believe this amount is reasonable based on broker
quotes obtained from parties who are interested in buying our bankruptcy claim
position.

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

As a result of current circumstances surrounding the energy sector, the
creditworthiness of several industry participants has been called into question.
We have taken actions to mitigate our exposure to these participants; however,
should several industry participants file for Chapter 11 bankruptcy protection
and contracts with our various subsidiaries are not assumed by other
counterparties, it could have a material adverse effect on our financial
position, operating results or cash flows.

Broadwing Arbitration. In June 2000, El Paso Global Networks (EPGN),
formerly known as El Paso Communications Company, entered into an agreement with
Broadwing Communications Services to construct and maintain a fiber optic
telecommunications system from Houston, Texas to Los Angeles, California. In May
2002, EPGN terminated its agreements with Broadwing due to Broadwing's failure
to meet its contractual obligations. Broadwing disputed EPGN's right to
terminate the agreements. Subsequently, EPGN filed a demand for arbitration and
named its arbitrator. We have also sought and obtained injunctive relief to
require Broadwing to perform maintenance activity and prohibit it from removing
materials or equipment purchased for the project. If it is determined that we
properly terminated the contract, Broadwing is required to return all money paid
by us which is $62 million and transfer all of the work completed to date free
and clear of any liens. However, if we are unsuccessful in our claim against
Broadwing or should they become financially insolvent, we may be subject to a
substantial write-down or complete write-off of this route. Although the outcome
of the arbitration 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 total invested capital of $109 million as of
September 30, 2002.

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Economic Conditions of Brazil. We have investments in power, pipeline and
production projects in Brazil, including an investment in Gemstone, with an
aggregate exposure, including financial guarantees, of approximately $1.8
billion. During the second and third quarters 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 presidential elections which were
completed in late October 2002. 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 68 percent devaluation of the local currency against the U.S. dollar since
the end of the first 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. In addition, Brazil's newly elected President
may impose changes affecting our business, including imposing tariff controls on
electricity and fuels. We currently believe that the economic difficulties in
Brazil will not have a material adverse effect on our investment in the country,
but we continue to monitor the economic situation and any potential changes in
governmental policy. Future developments in Brazil could cause us to reassess
our exposure.

Meizhou Wan Power Project. We own a 25 percent equity interest in a 762
megawatt, coal-fired power generating project, Meizhou Wan Generating, located
in Fuzhou, People's Republic of China. Our investment in the project was $76
million at September 30, 2002, and we have also issued $35 million in guarantees
and letters of credit for equity support and debt service reserves for the
project. The project debt is collateralized only by the project's assets, and is
non-recourse to us. The project declared that it was ready for commercial
operations in August 2001; however, the provincial government, who also buys all
power generated from the project, has not accepted the project for commercial
operations. In October 2002, we reached an interim agreement to allow the plant
to operate and sell power at reduced rates until March 2003 while a long-term
resolution to existing and past contract terms is negotiated. The price the
project receives from the sale of power in the interim agreement is expected to
be sufficient to provide for the operating costs and debt service of the
project, but does not provide for a return on investment to the project's
owners. If the project is unable to reach a long-term agreement with the
provincial government, with higher rates than in the interim agreement, we could
be required to impair our investment in the project, since cash flows from the
project would not be sufficient to provide us with a return of our investment,
and we may incur additional losses if our guarantees and letters of credit are
called upon. Our losses are limited to the extent of our investment, guarantees
and letters of credit.

Milford Power Project. We own a 25 percent direct equity interest in a 540
megawatt power plant construction project located in Milford, Connecticut.
Chaparral, our affiliate, owns an additional 70 percent interest in this
project. The project has been financed through equity contributions,
construction financing from lenders that is recourse only to the project and
through a construction management services agreement that we funded. This
project has experienced significant construction delays, primarily associated
with technological difficulties with its turbines including the inability to
operate on both gas and fuel oil or to operate at its designed capacity as
specified in the construction contract. In October 2001, we entered into a
construction management services agreement providing additional funding through
October 1, 2002. The construction contractor failed to complete construction of
the plant prior to October 1, 2002, in accordance with the terms and
specifications of the construction contract. As a result, the project was in
default under its construction lending agreement. On October 25, 2002, we
entered into a standstill agreement with the construction lending banks that
expires on December 2, 2002. Between now and December 2, 2002, we will be
negotiating with the contractor and with the lending banks to attempt to reach
agreements on contract disputes, including resolution of liquidated damages that
are due to the project under the terms of the construction contract and for
successful completion of plant construction. We may be unable to reach a
negotiated settlement of the disputes prior to December 2, 2002, in which case
the lending banks may have the right to accelerate the construction loan and
foreclose on the project resulting in an impairment of our investment in the
project. At September 30, 2002, our direct investment in the project was $79
million, and Chaparral's investment was $47 million. We estimate that if the
investment were written off in its entirety, the
33

charge we would incur would be approximately $126 million based on both our
direct investment in the project and our indirect investment through Chaparral.
We have also provided a guarantee of $8 million to fund a debt service account
for Milford. We may be required to fund the account should the facility not be
financially able to do so within two years from its commercial operations date.

Berkshire Power Project. We own a 25 percent direct equity interest in a
272 megawatt power plant located in Massachusetts. Chaparral, our affiliate,
owns an additional 31.4 percent interest in this project. The construction
contractor failed to deliver a plant capable of operating on both gas and fuel
oil, or capable of operating at its designed capacity. Berkshire is negotiating
with the contractor with respect to its failure to deliver the project in
accordance with guaranteed specifications, including fuel oil firing capability.
During the third quarter of 2002, the project lenders asserted that Berkshire
was in default on its loan agreement. Berkshire is in the process of negotiating
with its lenders to resolve disputed contract terms. Failure to reach a
satisfactory resolution in these matters could have a material adverse effect on
the value of our investment in the project. At September 30, 2002, our direct
investment in Berkshire was $26 million, including receivables of $18 million
under a subordinated fuel agreement, and Chaparral's investment was $5 million.

14. 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 on which we
will pay quarterly contract adjustment payments at an annual rate of 2.86% and
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. The senior notes we 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. At that time, 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. We
recorded approximately $43 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.

Fees and expenses incurred in connection with the equity security units
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.

FELINE PRIDES(SM)

In August 2002, we issued 12,184,444 shares of common stock to satisfy
purchase contract obligations under our FELINE PRIDES(SM) program. In return for
the issuance of stock, we received approximately $25 million in cash from the
maturity of a zero coupon bond and the return of $435 million of our existing

34

6.625% senior debentures due August 2004, that were issued in 1999. The zero
coupon bond and the senior debentures had been held as collateral for the
purchase contract obligations. The $25 million received from the maturity of the
zero coupon bond was used to retire additional senior debentures. Total debt
reduction from the issuance of the common stock was approximately $460 million.

Preferred Stock

As part of our balance sheet enhancement plan announced in December 2001,
we completed amendments to our Chaparral and Gemstone agreements in 2002 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.

Dividend

On November 7, 2002, we declared a quarterly dividend of $0.2175 per share
on our common stock, payable on January 6, 2003, to stockholders of record on
December 6, 2002. Also, during the nine months ended September 30, 2002, El Paso
Tennessee Pipeline Co., our subsidiary, paid dividends of $19 million on our
Series A cumulative preferred stock, which is 8 1/4% per annum (2.0625% per
quarter).

15. 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. In the second quarter of 2002, we reclassified our
historical coal mining operations from our Merchant Energy segment to
discontinued operations in our financial statements. All periods were restated
to reflect this change.

We use earnings before interest expense and income taxes (EBIT) to assess
the operating results and effectiveness of our business segments. We define EBIT
as operating income, adjusted for several items, including: equity earnings from
unconsolidated investments, minority interests on consolidated, but less than
wholly-owned operating subsidiaries, gains and losses on sales of assets and
other miscellaneous non-operating items. Items that are not included in this
measure are financing costs, including interest and debt expense and returns on
preferred interests of consolidated subsidiaries, income taxes, discontinued
operations, extraordinary items and the impact of accounting changes. We believe
this measurement is useful to our investors because it allows them to evaluate
the effectiveness of our businesses and operations and our investments from an
operational perspective, exclusive of the costs to finance those activities and
exclusive of income taxes, neither of which are directly relevant to the
efficiency of those operations. This measurement may not be comparable to
measurements used by other companies and should not be used as a substitute for
net income or other performance measures such as operating cash flow. The
following are our segment results as of and for the periods ended September 30:

- ---------------
(1) Includes our Corporate and telecommunication activities, eliminations of
intercompany transactions and in 2001, our retail business. Our intersegment
revenues, along with our intersegment operating expenses, consist of normal
course of business-type transactions between our operating segments. We
record an intersegment revenue elimination, which is the only elimination
included in the "Other" column, to remove intersegment transactions.

(2) Merchant Energy revenues take into account the adoption of a consensus
reached on EITF Issue No. 02-3, which requires us to report all physical
sales of energy commodities in our energy trading activities on a net basis
as a component of revenues. See 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:

16. 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 an interest of 50 percent or less, as well as those in which we
hold greater than a 50 percent interest. Our proportional share of the net
income of the unconsolidated affiliates in which we hold a greater than 50
percent interest was $9 million and $14 million for the quarters ended, and $25
million and $39 million for the nine months ended September 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
September 30, 2002 and December 31, 2001, the outstanding balance on these
securities, plus accrued interest, was $125 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 controlled. In connection with the elimination of these triggers, we
issued an El Paso guarantee supporting Gemstone's notes in the amount of $950
million, which can be called on in the event Gemstone is unable to meet its
obligations under its notes.

Chaparral

We have a credit facility with Chaparral that had an outstanding balance,
plus accrued interest, of $698 million and $552 million at September 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 September 30, 2002 and December 31, 2001.

37

In April 2002, we completed amendments to the Chaparral agreements,
eliminating the stock price and credit rating triggers and reducing the number
of shares of mandatorily convertible preferred stock that was held in a share
trust. In connection with the elimination of these triggers, we issued an El
Paso guarantee supporting Chaparral's notes totaling approximately $1 billion,
which can be called on in the event Chaparral is unable to meet its obligations
under its notes.

As discussed more completely in our 2001 Form 10-K, we have entered into a
number of transactions with Chaparral and its subsidiaries, including providing
management and administrative services, capital contributions and being a party
to a number of commercial contracts. As of September 30, 2002 and December 31,
2001, we had the following investment in Chaparral:

As of September 30, 2002, Chaparral had $1.8 billion of consolidated third
party debt. Chaparral's debt is related to specific projects that it owns or has
interests in, and is recourse solely to those projects. Chaparral's equity
consisted of our investment of $264 million and Limestone Investors' investment
of $1.1 billion.

El Paso Energy Partners

A subsidiary in our Field Services segment serves as the general partner of
El Paso Energy Partners, a master limited partnership that has limited
partnership units that trade on the New York Stock Exchange. Field Services
acquired the general partner in August 1998, together with an approximate 27.3
percent interest in the common units of the master limited partnership. Since
then, Field Services' ownership percentage in the common units of the limited
partnership has decreased to 26.5 percent. The remaining 73.5 percent of the
common units of the limited partnership are owned by public unit holders
(including small amounts owned by the general partner's management and
employees), none of which exceeds a 10 percent ownership interest. A majority of
the members of the Board of Directors of El Paso Energy Partners are independent
of us, and the audit and conflicts committee is completely comprised of
independent members.

As the general partner, Field Services manages the partnership's daily
operations, provides the strategic direction and performs all of the
partnership's administrative and operational activities under a general and
administrative services agreement or, in some cases, separate operational
agreements. El Paso Energy Partners contributes to our income through our
general partner interest and our ownership of common and preferred units. We do
not have any loans to or from El Paso Energy Partners. In addition, except for a
nominal guarantee of lease obligations on behalf of a subsidiary of El Paso
Energy Partners, we have not provided any guarantees, either monetary or
performance, on behalf of or for the benefit of El Paso Energy Partners nor do
we have any other liabilities other than normal course of business as a result
of or arising out of our role as the general partner or our ownership interest
in El Paso Energy Partners. Our normal course of business transactions with El
Paso Energy Partners include sales of natural gas and services, such as
transportation and fractionation, storage, processing and other types of
operational services.

In April 2002, we sold midstream assets to El Paso Energy Partners for
total consideration of $735 million. In July 2002, we entered into a letter of
intent with El Paso Energy Partners for the sale of the San Juan assets for $782
million. See Note 2 for further discussion.

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17. PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Clydesdale and Trinity River. In March 2002, we completed the amendments
to the Trinity River (also known as Red River) 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
Standard and Poor's and Moody's. We completed a similar amendment for our
Clydesdale (also known as Mustang) agreements in July 2002.

El Paso Oil & Gas Resources Preferred Units. In July 2002, we repurchased
from UAGC, Inc., an unaffiliated investor, 50,000 units representing all
outstanding preferred units in El Paso Oil & Gas Resources Company, L.P., our
wholly owned partnership, for $50 million plus accrued and unpaid dividends.

Coastal Limited Ventures Preferred Stock. In July 2002, we repurchased
from JPMorgan Chase Bank, 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 RBCC, Inc., an unaffiliated investor, in El Paso
Production Oil & Gas Associates, L.P., 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.

18. 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 fair value,
with a corresponding asset which is depreciated over the remaining useful life
of the long-lived asset to which the liability relates. An ongoing expense will
also be recognized for changes in the value of the liability as a result of the
passage of time. The provisions of SFAS No. 143 are effective for fiscal years
beginning after June 15, 2002. We are currently assessing and quantifying the
asset retirement obligations associated with our long-lived assets. We expect to
complete our assessment of these asset retirement obligations and be able to
estimate their effect on our financial statements in the fourth quarter of 2002.

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
associated with a restructuring, discontinued operations, plant closings or
other exit or disposal activities. The statement is effective for fiscal years
beginning after December 31, 2002, and will impact any exit or disposal
activities we initiate after January 1, 2003.

Accounting for Contracts Involved in Energy Trading and Risk Management
Activities

In October 2002, the EITF reached two decisions on EITF Issue No. 02-3,
Issues Related to Accounting for Contracts Involved in Energy Trading and Risk
Management Activities. The first of the two decisions requires that we account
for all energy-related contracts that do not qualify as derivatives under SFAS
No. 133 using the accrual method of accounting, rather than mark-to-market
accounting as was previously required under EITF Issue No. 98-10, Accounting for
Contracts Involved in Energy Trading and Risk Management Activities. Following
our application of this consensus of EITF Issue No. 02-3, we will continue to
record our derivative contracts at fair value under SFAS No. 133. The
energy-related contracts not qualifying as derivatives will be those that
require physical delivery or may have an element of service required under the
contract. Examples of non-derivative energy contracts include transportation
capacity contracts, storage contracts and tolling contracts.

39

The other consensus reached will require that we account for all inventory
held by our energy-trading operation at the lower of its cost or fair value,
rather than using mark-to-market accounting as was previously allowed under EITF
Issue No. 98-10. Upon adoption we will adjust the fair value of these
inventories in our balance sheet to their corresponding cost using an inventory
valuation method (such as average cost) and record a cumulative effect of
accounting change.

We will adopt these decisions during the fourth quarter of 2002, at which
time we will be required to eliminate the fair value of non-derivative trading
contracts from our balance sheet, adjust our inventory to reflect the lower of
its cost or market value and record a cumulative effect of accounting change. At
this time, we estimate that this will result in a cumulative effect loss of
approximately $225 million to $350 million after-taxes ($350 million to $550
million before taxes). Our estimate may be impacted by additional interpretive
guidance that is expected on EITF Issue No. 02-3 as well as the interpretation
of SFAS No. 133, as amended.

40

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

The information contained in Item 2 updates, and you should read it in
conjunction with, information disclosed in our 2001 Annual Report on Form 10-K
in addition to the financial statements and notes presented in Item 1, Financial
Statements, of this Quarterly Report on Form 10-Q.

Included throughout this Management's Discussion and Analysis are terms
that are common to our industry:

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

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.

LIQUIDITY AND CAPITAL RESOURCES

RECENT DEVELOPMENTS

Market Conditions

Since the fourth quarter of 2001, a number of developments in our
businesses and industry have significantly impacted our operations and
liquidity. These have included:

- The bankruptcy of Enron Corp. and the resulting decline in the energy
trading industry;

- The modification of credit standards by the rating agencies; and

- Regulatory and political pressure arising out of the California energy
crisis of 2001.

Prior to its bankruptcy in December 2001, Enron was the largest trader of
wholesale natural gas and power in the United States and was a significant
competitor and counterparty of ours in these markets. Its bankruptcy immediately
impacted the liquidity in the wholesale energy markets, removing a substantial
trading partner for us and all other energy traders. The effects of the
bankruptcy filing and the resulting impact on the industry were immediate and
sustained, impacting our ability to enter into both short and long-term
wholesale energy trades and our collective ability to convert our existing
market positions with Enron into cash. In response, the credit rating agencies,
Moody's and Standard and Poor's, re-evaluated the credit ratings of companies
involved in energy trading activities, and the credit ratings of most of the
largest participants in the energy trading industry have been downgraded to
below investment grade and some have experienced significant financial distress.
In September 2002, Moody's downgraded our senior unsecured debt from Baa2 to
Baa3 (their lowest "investment grade" rating) and has kept us under review for
possible further downgrade. In November 2002, Standard and Poor's downgraded our
senior unsecured debt from BBB to BBB- (their lowest "investment grade" rating),
and we remain on negative credit watch. The rating agencies also lowered our
commercial paper rating which resulted in the commercial paper markets currently
being unavailable to us at attractive prices.

Maintaining a strong credit rating is critical to our ability to conduct
business. Most traders enter into transactions on a margin basis, which means
that the actual cash deposited with the purchaser or seller to the transaction
is a fraction of the funds that will actually be exchanged at the time
settlement occurs. When a company's credit rating falls below investment grade
additional cash is required to support these transactions. In addition, many of
our financial guarantees, purchase obligations and other commercial commitments
and contracts could be negatively impacted by lower credit ratings. As a result,
if our rating were lowered to "below investment grade," it could result in
immediate additional collateral demands on us.

41

California Capacity

As discussed in Item 1, Financial Statements, Note 13, Commitments and
Contingencies, in September 2002, EPNG received an initial decision from a FERC
ALJ related to whether EPNG exercised market power with regard to its pipeline
capacity to the California border during the latter part of 2000 and the early
part of 2001. In that decision, the ALJ held that EPNG withheld capacity from
California. We believe the ALJ's ruling is incorrect as a matter of fact, law
and policy. We believe that EPNG has consistently demonstrated that it operates
its system in a manner to maximize the flow of gas at all times consistent with
safety, reliability and operational considerations, and that volume differences
during the period in question (November 1, 2000 to March 31, 2001) have been
fully explained on the record. The ALJ's decision had an immediate negative
impact on our stock price and the market value of our debt, and apparently
influenced the rating downgrade by Moody's and more recently the rating
downgrade by Standard and Poor's, each discussed above. Despite our position
that the ALJ's ruling is incorrect as a matter of fact, law and policy, should
the FERC uphold the ALJ's decision, and should we not prevail in our appeal of
that decision, the long-term impact on our credit rating, liquidity and our
ability to raise capital to meet our ongoing and future investing and financing
needs could be substantial depending on the remedy the FERC may seek to impose
and the impact the decision could have on our pending state court litigation.

RESPONSE AND OUTLOOK

In December 2001, in response to industry developments, we announced a plan
to enhance our liquidity and strengthen our capital structure. In May 2002, we
also announced a plan to limit our investment in, and exposure to, energy
trading and to focus our activities and investments in our core natural gas
business. Under these plans, we have announced and accomplished the following:

On November 8, 2002, we announced our intention to exit the trading
business. Our actions were prompted by the continued liquidity demands on that
business and our desire to eliminate some of the potential demands on our cash
flow. Our actions are discussed more fully under our Results of Operations
section under our Merchant Energy Segment discussion. Our future goals are to
continue to improve our financial position through the additional payoff of debt
and other financing instruments, and we will accomplish these actions primarily
through the use of operating cash flows, additional asset sales and executing
the trading exit strategy discussed above. The actual assets sold will depend on
a number of factors, including short-term market developments, the availability
of qualified buyers and the acceptability of offers received. In addition, since
we are operating in a short timeframe to sell assets, losses and write-downs of
the assets we sell could occur.

42

For the fourth quarter of 2002, our capital needs and liquidity
requirements will be significant. Our anticipated cash requirements and
estimated funding are as follows:

For 2003, our debt, financing and minority interest maturities are
approximately $2.1 billion, including an assumed $1 billion related to amounts
we may be required to pay in connection with our Chaparral guarantee that may
occur during the first quarter of 2003. See Segment Results under Merchant
Energy for a further discussion of Chaparral.

We anticipate that we will meet our cash needs and liquidity requirements
through a combination of cash on hand, cash generated from operations and
proceeds from the sale of assets. As of September 30, 2002, our available
sources of funds included (in millions):

Cash and cash equivalents................................... $1,693
Availability under our revolving lines of credit............ 3,500
------
Total available sources of funding........................ $5,193
======

Our anticipated requirements may change significantly, and our analysis is
intended to provide you with a better understanding of our cash needs, both
required and discretionary, to better understand our liquidity outlook. Factors
that could impact our ability to meet our estimated cash needs include
maintaining an investment grade credit rating, our ability to market assets for
reasonable prices and in a timely manner and our ability to prevail in the
regulatory and legal matters currently pending against us.

OVERVIEW OF CASH FLOW ACTIVITIES FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2002

During the nine months ended September 30, 2002, our cash and cash
equivalents increased by $0.5 billion to approximately $1.7 billion. During the
period, we generated an estimated $6.9 billion through a combination of cash
from operations (income before non-cash income items) of $1.6 billion and the
net issuance of a combination of long-term debt and equity securities of $5.3
billion. In addition, we generated approximately $1.6 billion through sales of
assets and investments, primarily natural gas and oil properties and midstream
assets. With the cash we received from these sources, we invested approximately
$2.7 billion in fixed assets and equity investments, paid $2.0 billion on
maturing long-term debt, paid $1.2 billion, net, on short-term debt, paid $0.3
billion in dividends, and $0.5 billion on minority and preferred interest
payments. 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 and asset sales. However, our working
capital inflows or outflows for the remainder of 2002 will be dependent on a
number of items not within our control, including operating results,
fluctuations in commodity prices, strategies we may implement to offset the
impact of commodity price fluctuations and the impact on our credit requirements
of ratings actions. Movements in commodity prices can significantly impact our
operating cash flow from period to period, either positively or negatively.

43

For the nine months ended September 30, 2002 and 2001, our cash flows were
as follows:

CASH FROM OPERATING ACTIVITIES

Net cash provided by operating activities was $1.2 billion for the nine
months ended September 30, 2002, compared to net cash provided by operating
activities of $3.5 billion for the same period in 2001. The $2.3 billion
decrease was due to a combination of lower income, as adjusted for non-cash
income items, of $0.6 billion in 2002 versus 2001 and a use of working capital
of $0.1 billion in 2002 compared to cash generated of $1.6 billion last year.
The decrease in income as adjusted for non-cash income items in the first nine
months of 2002 was due to lower earnings from our merchant and production
businesses. For a further discussion of our operating results in these segments,
see our discussion of Segment Results below.

The cash generated from working capital last year was primarily
attributable to $1.2 billion generated from the liquidation of trading assets
and $0.2 billion of margins collected from trading and hedge counterparties. The
use of working capital in 2002 was primarily due to $0.4 billion of margin
deposits we have with our trading and hedging counterparties offset by $0.4
billion generated from the liquidation of trading assets.

CASH FROM INVESTING ACTIVITIES

Net cash used in our investing activities was $1.4 billion for the nine
months ended September 30, 2002. Our investing activities consisted primarily of
capital expenditures and equity investments of $2.7 billion offset by net
proceeds from sale of assets and investments of $1.6 billion. Our capital
expenditures and equity investments included the following (in billions):

Production development, expansion and maintenance
projects.................................................. $1.6
Pipeline expansion, maintenance and integrity projects...... 0.6
Investments in unconsolidated affiliates.................... 0.1
Other (primarily petroleum and power projects).............. 0.4
----
Total capital expenditures and equity
investments...................................... $2.7
====

Our asset sales proceeds are primarily attributable to the sale of natural
gas and oil properties in Texas and Colorado for $0.8 billion, the sale of Texas
and New Mexico midstream assets to El Paso Energy Partners for $0.5 billion, and
the sale of other power, petroleum and processing assets of $0.3 billion.

CASH FROM FINANCING ACTIVITIES

Net cash provided by our financing activities was $779 million for the nine
months ended September 30, 2002. Cash provided from our financing activities
included the net issuance of long-term debt of $4.3 billion and issuances of
common stock of $1 billion. Cash used by our financing activities included
payments made to retire long-term debt and other financing obligations of $2
billion, as well as net repayments under our commercial paper and short-term
credit facilities of $1.1 billion. We also repurchased $350 million of preferred
securities previously issued by our subsidiaries and made other minority
interest payments of $161 million, primarily to

44

Chaparral which holds a 16 percent minority interest in the utility contract
funding project. Further, we made a net repayment of $586 million of notes
payable and paid dividends of $340 million.

On November 7, 2002, we declared a quarterly dividend of $0.2175 per share
on our common stock, payable on January 6, 2003, to stockholders of record on
December 6, 2002. Also, during the nine months ended September 30, 2002, El Paso
Tennessee Pipeline Co., our subsidiary, paid dividends of approximately $19
million on our Series A cumulative preferred stock, which is 8 1/4% per annum
(2.0625% per quarter).

FINANCING AND COMMITMENTS

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
which are referred to above under cash from financing activities.

Issuances

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

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

(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 September 30,
2002, and includes a $44 million change in value due to a change in the Euro
to U.S. dollar foreign currency exchange rate from the issuance date to
September 30, 2002.

(4) These senior notes relate to an offering of 11.5 million 9% equity security
units, which include 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.

45

Retirements

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

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

(2) The majority of this debt was exchanged for equity. See Item 1, Financial
Statements, Note 14 for a further discussion of this transactions.

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 billion and was used to repay short-term borrowings and other
financing obligations and for general corporate purposes.

In July 2002, Utility Contract Funding 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 Utility Contract Funding including obligations of Public Service Electric and
Gas 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 July 2002, we entered into two cross-currency swap transactions which
effectively hedged E400 million of our euro currency risk on our E500 million
Euro-denominated debt. In the first transaction, E250 million of our 7.125%
fixed rate was swapped for $252.5 million of floating rate debt at a rate of the
six-month LIBOR plus a spread of 2.195%. A second transaction swapped E150
million of our 7.125% fixed rate euro based debt for $151.5 million, 7.08% fixed
dollar based debt.

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In August 2002, we issued 12,184,444 shares of common stock to satisfy
purchase contract obligations under our FELINE PRIDES(SM) program. In return for
the issuance of the stock, we received approximately $25 million in cash from
the maturity of a zero coupon bond and the return of $435 million of our
existing 6.625% senior debentures due August 2004 that were issued in 1999. The
zero coupon bond and the senior debentures had been held as collateral for the
purchase contract obligations. The $25 million received from the maturity of the
zero coupon bond was used to retire additional senior debentures. Total debt
reduction from the issuance of the common stock was approximately $460 million.

Credit Facilities and Available Capacity

In February 2002, we filed a new shelf registration statement with the SEC
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 September 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, our subsidiaries, remain designated
borrowers under this facility and, as such, are liable for any amounts
outstanding. 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 and, as such, are liable for any
amounts outstanding. The interest rate under both of these facilities varies
based on our senior unsecured debt rating, and as of September 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
September 30, 2002, there were no borrowings outstanding; however, we have
issued $492 million of letters of credit under the $1 billion facility.

In September 2002, Moody's lowered our senior unsecured debt rating from
Baa2 to Baa3 and in November 2002, Standard and Poor's lowered our senior
unsecured debt rating from BBB to BBB-. As a result of these events, the current
interest rate on an initial draw under both of the facilities would be at a rate
of LIBOR plus 0.80%, plus a 0.25% utilization fee for drawn amounts above 25% of
the committed amounts.

Restrictive Covenants

We and our subsidiaries have entered into debt instruments and guaranty
agreements that contain covenants such as restrictions on debt levels,
restrictions on liens securing debt and guarantees, restrictions on mergers and
on the sales of assets, capitalization requirements, dividend restrictions and
cross-payment default and cross-acceleration provisions. A breach of any of
these covenants could result in acceleration of our debt and other financial
obligations and that of our subsidiaries.

Under our revolving credit facilities, the significant debt covenants and
cross defaults are:

(a) the ratio of consolidated debt and guarantees (excluding certain
project financing and securitization programs and other
miscellaneous items) to capitalization cannot exceed 70 percent;

(b) the consolidated debt and guarantees (other than excluded items)
of our subsidiaries cannot exceed the greater of $600 million or
10 percent of our consolidated net worth;

(c) we or our principal subsidiaries cannot permit liens on the equity
interest in our principal subsidiaries or create liens on assets
material to our consolidated operations securing debt and
guarantees (other than excluded items) exceeding the greater of
$300 million or 10 percent of our consolidated net worth, subject
to certain permitted exceptions; and

(d) the occurrence of an event of default for any non-payment of
principal, interest or premium with respect to debt (other than
excluded items) in an aggregate principal amount of

47

$200 million or more; or the occurrence of any other event of default
with respect to such debt that results in the acceleration thereof.

We were in compliance with the above covenants as of the date of this
filing, and no borrowings were outstanding under our revolving credit
facilities; however, we have issued $492 million of letters of credit under the
$1 billion facility.

We have also issued various guarantees securing financial obligations of
our subsidiaries and unconsolidated affiliates with similar covenants as in the
above credit facilities.

With respect to guarantees issued by our subsidiaries, the most significant
debt covenant, in addition to the covenants discussed above, is that El Paso CGP
must maintain a minimum net worth of $1.2 billion. If breached, the amounts
guaranteed by the guaranty agreements could be accelerated. The guaranty
agreements also maintain a $30 million cross-acceleration provision.

In addition, three of our subsidiaries have indentures associated with
their public debt that contain $5 million cross-acceleration provisions.

Notes Payable to Affiliates

Our notes payable to unconsolidated affiliates as of September 30, 2002,
were $373 million versus $872 million as of December 31, 2001. The decrease is
primarily due to the partial repayment of Gemstone and Chaparral debt
securities.

Minority and Preferred Interests of Consolidated Subsidiaries

The total amount outstanding for securities of subsidiaries and preferred
stock of consolidated subsidiaries was $3,728 million at September 30, 2002,
versus $4,013 million at December 31, 2001. The decrease was due primarily to
our repurchase from unaffiliated investors of 50,000 preferred units in El Paso
Oil & Gas Resources Company, L.P. and 150,000 preferred shares in Coastal
Limited Ventures, Inc. wholly owned subsidiaries, for $65 million plus accrued
and unpaid dividends in July 2002. We also reacquired the limited partnership
interest, in El Paso Production Oil & Gas Associates, L.P., a partnership formed
with Coastal Limited Ventures, Inc. The payment of approximately $285 million
was equal to the sum of the limited partner's outstanding capital plus unpaid
priority returns. We also made payments to minority interest holders, primarily
Chaparral, of $161 million. The decrease was partially offset by the
consolidation of our Eagle Point Cogeneration Partnership and our Capitol
District Energy Center Cogeneration Associates investments in January 2002 and
subsequent contributions, which increased minority interest by $170 million. For
the nine months ended September 30, 2002, we recorded $55 million of minority
interest expense.

Lines of Credit

As of September 30, 2002, Mesquite had $698 million outstanding under a
credit facility at an interest rate of 2.3%. We anticipate Mesquite will repay
approximately $300 million of the amounts due under this facility during the
fourth quarter with cash generated primarily from its sale of investments in two
power plants that were completed in November of 2002, net proceeds from
completion of a power restructuring that is also expected to close during the
fourth quarter of 2002 and operating cash flows.

Letters of Credit

As of September 30, 2002, we had outstanding letters of credit of
approximately $1 billion 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, our subsidiaries 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

48

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
of our subsidiaries under the five time-charter agreements is approximately $2.5
billion over the term of the time charters. If our subsidiaries were unable to
fulfill their obligations under the five time charter arrangements, our maximum
commitment, in the form of corporate guarantees and letters of credit, would be
$254 million, which will increase to $290 million if we exercise the option for
the time charter on the fifth ship. 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.

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 use earnings before interest expense and income taxes (EBIT) to
assess the operating results and effectiveness of our business segments. We
define EBIT as operating income, adjusted for several items, including:

- equity earnings from unconsolidated investments;

- minority interests on consolidated, but less than wholly-owned operating
subsidiaries;

- gains and losses on sales of assets; and

- other miscellaneous non-operating items.

Items that are not included in this measure are:

- financing costs, including interest and debt expense and returns on
preferred interests of consolidated subsidiaries;

- income taxes;

- discontinued operations;

- extraordinary items; and

- the impact of accounting changes.

We believe this measurement is useful to our investors because it allows
them to evaluate the effectiveness of our businesses and operations and our
investments from an operational perspective, exclusive of the costs to finance
those activities and exclusive of income taxes, neither of which are directly
relevant to the efficiency of those operations. This measurement may not be
comparable to measurements used by other companies and should not be used as a
substitute for net income or other performance measures such as operating cash
flow. For a further discussion of our individual segments, see Item 1, Financial
Statements,

49

Note 12, as well as our 2001 Annual Report on Form 10-K. The segment EBIT
results for the periods presented below include the charges discussed above:

PIPELINES

Our Pipelines segment includes our interstate transmission businesses. Our
interstate transmission systems face varying degrees of competition from other
pipelines, as well as alternate energy sources, such as electricity,
hydroelectric power, coal and fuel oil. In addition, some of our businesses have
shifted from a traditional dependence solely on long-term contracts into a
portfolio approach which balances short-term opportunities with long-term
commitments. The shift is due to changes in market conditions and competition
driven by state utility deregulation, local distribution company mergers, new
supply sources, volatility in natural gas prices, demand for short-term capacity
and new markets to supply power plants.

We are regulated by the Federal Energy Regulatory Commission. The FERC sets
the rates we can recover from our customers. These rates are generally a
function of our cost of providing service to our customers, as well as a
reasonable return on our invested capital. As a result, our pipeline results
have historically been relatively stable. However, they can be subject to
volatility due to factors such as weather, changes in natural gas prices,
regulatory actions and the creditworthiness of our customers. In addition, our
ability to extend our existing contracts or re-market expiring capacity is
dependent on the competitive alternatives, regulatory environment and the supply
and demand factors at the relevant extension or expiration dates. While every
attempt is made to negotiate contract terms at fully-subscribed quantities and
at maximum rates allowed under our tariffs, some of our contracts are discounted
to meet competition.

As discussed more fully in Item 1, Financial Statements, Note 13, under the
subheading Rates and Regulatory Matters, in September 2002, EPNG received an
initial decision from an ALJ related to whether it exercised market power with
regard to its pipeline capacity to the California border during the latter part
of 2000 and the early part of 2001. In that decision, the ALJ held that EPNG
withheld capacity from California. We believe that holding is incorrect as a
matter of fact, law, and policy. We believe that EPNG has consistently
demonstrated that it operates its systems in a manner to maximize the flow of
gas at all times consistent with safety, reliability, and operational
considerations, and that volume differences on EPNG during the period in
question (November 1, 2000 to March 31, 2001) have been fully explained on the
record. However, despite our position, should the FERC uphold the ALJ's
decision, and should we not prevail in our appeal of that decision, the
long-term impact on EPNG, and on our segment results could be substantial
depending on the remedy the FERC may seek to impose on us and the impact such
decision could have on our pending state court litigation.

Also as discussed in Item 1, Financial Statements, Note 13 under the
subheading Rates and Regulatory Matters, EPNG has an existing FERC order related
to the allocation of capacity on its system that requires it to:

- - Prospectively give reservation charge credits to its firm shippers if it fails
to schedule the shippers' confirmed volumes (except in the case of force
majeure);

50

- - Refrain from entering into new firm contracts or remarketing turned back
capacity under terminated or expired contracts until May 1, 2003; and

- - Add additional compression to its Line 2000 project (up to 320 MMcf/d) without
the recovery of these costs in its rates until its next rate case which will
be effective in January 1, 2006.

EPNG's and our Pipelines segments' future results of operations will be
impacted as a result of both orders in the capacity allocation proceeding and
the Enron bankruptcy (discussed below). The September 20 order prohibits EPNG
from remarketing approximately 471 MMDth/d of its capacity. Of this amount,
approximately 195 MMDth/d is capacity which was rejected by Enron in May 2002 in
its bankruptcy proceeding. Prior to the rejection of the contracts, EPNG was
earning approximately $1.5 million (net of revenue sharing credits) per month
from Enron for this capacity. Because EPNG cannot remarket this capacity, it
will experience a loss of revenue due to the relinquishment of this capacity in
the bankruptcy proceeding. The amount of such revenue loss cannot be determined
because it would depend on the rates it could obtain by remarketing the
capacity.

The remaining 276 MMDth/d of capacity that EPNG is unable to remarket as a
result of the September 20 order will also cause a reduction in its
transportation revenues. This capacity relates to contracts that expire within
the time frame specified by the order. Under these contracts, EPNG was earning
$2 million (net of revenue sharing credits) per month in revenues prior to their
expiration. The amount of revenue loss cannot be determined because, as with the
Enron capacity, it would depend on the rates it could obtain by remarketing the
capacity. EPNG has requested rehearing of the September 20 FERC Order on this
and other aspects of the order. This request for rehearing is pending before the
FERC.

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. Enron's subsidiaries had transportation contracts on
several of our pipeline systems (including the EPNG contract discussed above).
Most of these transportation contracts have now been rejected, and our pipeline
subsidiaries have filed proofs of claim totaling approximately $137 million.
EPNG filed the largest proof of claim in the amount of approximately $128
million, which included $18 million for amounts due for services provided
through the date the contracts were rejected and $110 million for damage claims
arising from the rejection of its transportation contracts, which EPNG is
prohibited from remarketing under the capacity allocation orders discussed
above. We have fully reserved for the amounts due through the date the contracts
were rejected, and we have not recognized any revenues from these contracts
since that date.

In October 2002, we announced our intent to sell our 14.4 percent interest
in the Alliance pipeline system to Enbridge Inc. We expect to complete this sale
during the first quarter of 2003. Income earned on our investment in Alliance
for the quarter and nine months ended September 30, 2002, was approximately $5
million and $17 million.

Results of our Pipelines segment operations were as follows:

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

(1) Throughput volumes 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.

Third Quarter 2002 Compared to Third Quarter 2001

Operating revenues for the quarter ended September 30, 2002, remained flat
compared to the same period in 2001. A decrease of $29 million resulted from
lower revenues from natural gas sales and from gathering and processing
activities due to the sale of CIG's Panhandle field on July 1, 2002. Also
contributing to the decrease were $7 million from a FERC order which disallowed
the remarketing of the EPNG capacity rejected by Enron and $3 million from lower
throughput due to lower electric generation demand and milder weather in 2002.
These decreases were offset by an increase of $15 million due largely to
transmission system expansion projects placed in service in 2001 and 2002, a $14
million favorable resolution of measurement issues at a processing plant serving
the TGP system in 2002, $8 million from the Elba Island LNG facility which was
placed in service in December 2001, and $4 million of additional revenues from
the South System I (Phase 1) expansion, which was placed in service in June
2002.

Operating expenses for the quarter ended September 30, 2002, were $24
million lower than the same period in 2001. The decrease was due to price
changes on natural gas imbalances of $15 million and $14 million decrease
related to the sale of CIG's Panhandle field on July 1, 2002. Also contributing
to the decrease were lower amortization of goodwill of $5 million due to the
implementation of SFAS No. 142 in 2002 and $3 million from lower compressor
operating costs in 2002 on the EPNG system resulting from lower electric usage
and prices. These decreases were partially offset by an increase of $5 million
in estimated legal liabilities in 2002, higher amortization of additional
acquisition costs assigned to utility plant of $3 million in 2002, higher
operating expenses of $3 million due to the Elba Island LNG facility being in
service in 2002 and higher corporate overhead allocations in 2002 of $2 million.

Other income for the quarter ended September 30, 2002, was $4 million
higher than the same period in 2001 primarily due to the resolution of
uncertainties associated with the sale of our interests in the Gulfstream
pipeline project in 2001.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

Operating revenues for the nine months ended September 30, 2002, were $112
million lower than the same period in 2001. The decrease was due to lower
natural gas and liquids sales of $51 million resulting from lower prices in 2002
and $50 million due to the impact of lower prices in 2002 on natural gas
recovered in excess of the amounts used in operations. Also contributing to the
decrease were lower revenues of $29 million from natural gas sales and from
gathering and processing activities due to the sale of CIG's Panhandle field on
July 1, 2002, lower transportation revenues of $22 million from capacity sold
under short-term contracts and milder winter weather and $15 million from lower
throughput due to lower electric generation demand and milder winter weather in
2002. In addition, an $11 million decrease in operating revenues was due to
favorable resolution of regulatory issues related to natural gas purchase
contracts in 2001, a $6 million decrease was due to lower rates on the Mojave
Pipeline System as a result of a rate case settlement effective October 2001,
and

52

a $6 million decrease due to the sale of our Midwestern Gas Transmission system
in April 2001. These decreases were partially offset by $34 million additional
reservation revenues due largely to transmission system expansion projects
placed in service in 2001 and 2002, $25 million due to a larger portion of
EPNG's capacity sold at maximum tariff rates in 2002, $22 million from the Elba
Island LNG facility placed in service in December 2001, $18 million from the
favorable resolution of measurement issues at a processing plant serving the TGP
system in 2002 and $4 million from the South System I (Phase 1) expansion placed
in service in June 2002.

Operating expenses for the nine months ended September 30, 2002, were $430
million lower than the same period in 2001 primarily as a result of 2001
merger-related costs of $316 million due to our merger with Coastal. For a
discussion of these costs, see Item 1, Financial Statements, Note 4. Also
contributing to the decrease were $43 million from lower fuel and system supply
purchases costs resulting from lower natural gas volumes and prices in 2002, $19
million from the impact of price changes on natural gas imbalances, $17 million
due to lower employee benefit costs and lower operating expenses in 2002 due to
cost efficiencies following the merger with Coastal, a 2001 change in estimate
of $18 million primarily for additional environmental remediation liabilities,
lower amortization of goodwill of $14 million due to the implementation of SFAS
No. 142 in 2002, $14 million decrease related to the sale of CIG's Panhandle
field on July 1, 2002, $13 million lower corporate overhead allocations in 2002
and $10 million from lower compressor operating costs in 2002 on the EPNG system
resulting from lower electric usage and prices. These decreases were partially
offset by an increase of $14 million to our reserve for bad debts in 2002
related to the bankruptcy of Enron Corp., additional accruals of $13 million in
2002 on estimated liabilities to assess and remediate our environmental exposure
due to an ongoing evaluation of our operating facilities, an increase of $10
million in estimated legal liabilities in 2002, higher amortization of
additional acquisition costs assigned to a utility plant of $10 million in 2002
and higher operating expenses of $9 million due to the Elba Island LNG facility
returned to service in 2002.

Other income for the nine months ended September 30, 2002, was $30 million
higher than the same period in 2001. An increase of $11 million was due to a
gain on the sale of pipeline expansion rights in February 2002, and $11 million
due to the resolution of uncertainties associated with the sales of our
interests in the Empire State, Iroquois pipeline systems, and our Gulfstream
pipeline project in 2001. Also contributing to the increase were higher equity
earnings in 2002 of $10 million primarily due to our investment in Great Lakes
Gas Transmission. These increases were partially offset by lower equity earnings
of $6 million on Empire State and Iroquois pipeline systems due to the sale of
our interests in 2001.

PRODUCTION

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

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. We have hedged
approximately 50 percent of our expected natural gas production for the fourth
quarter of 2002 at a NYMEX price of $3.92 per MMBtu before regional price
differentials and transportation costs. We have hedged approximately 217 million
MMbtu's of our anticipated natural gas production for 2003 at a NYMEX price of
$3.43 per MMBtu before regional price differentials and transportation costs.

During 2002, we have continued an active onshore and offshore development
drilling program to capitalize on our land and seismic holdings. This
development drilling is done to take advantage of our large

53

inventory of drilling prospects and to develop our proved undeveloped reserve
base. We have also completed asset dispositions in Colorado and Texas as part of
our balance sheet enhancement plan. As a result of our asset dispositions, we
will likely have a lower reserve base at January 1, 2003 than we did at January
1, 2002. Since our depletion rate is determined under the full cost method of
accounting, a lower reserve base coupled with additional capital expenditures in
the full cost pool will result in higher depletion expense in future periods.
For the fourth quarter of 2002, we expect our unit of production depletion rate
to be approximately $1.40 per equivalent unit.

Our total estimated capital expenditures in 2002 are approximately $2.3
billion. Based on our current level of capital expenditures, our asset
dispositions, and our production decline rates, we expect our total 2002
equivalent production volumes to be approximately 8 percent lower than our 2001
equivalent production volumes.

We will continue to pursue strategic acquisitions of production properties
and the development of projects subject to acceptable returns. In July 2002, we
acquired natural gas properties in the Raton Basin for approximately $140
million. These properties were acquired to expand the interest in our current
coal seam project in the area.

Below are the operating results and an analysis of these results for the
periods ended September 30:

- ---------------
(1) Includes production costs, depletion, depreciation and amortization, ceiling
test charges, merger-related costs, changes in accounting estimates,
corporate overhead, general and administrative expenses and other taxes.

(2) Net of transportation costs.

Third Quarter 2002 Compared to Third Quarter 2001

For the quarter ended September 30, 2002, operating revenues were $110
million lower than the same period in 2001. An 18 percent decrease in natural
gas volumes and a 6 percent decrease in natural gas prices, before
transportation costs, contributed to $120 million of the decrease in revenues.
The decline in natural gas volumes is primarily attributable to the sale of
properties in Texas and Colorado and the impact of several South Texas wells
that were shut-in during part of the quarter. The decrease in revenues is
partially offset by a 12 percent increase in oil, condensate and liquids
volumes, and a 3 percent increase in their prices before

54

transportation costs, resulting in a $12 million increase in revenues. Further,
a gain of approximately $6 million was recognized in the third quarter of 2002
due to a mark-to-market adjustment of derivative positions that no longer
qualify as cash flow hedges under SFAS No. 133. These hedges no longer qualify
for hedge accounting treatment since they were designated as hedges of
anticipated future production from natural gas and oil properties that were sold
in March 2002.

Transportation and net product costs for the quarter ended September 30,
2002, were $10 million higher than the same period in 2001 primarily due to a
higher percentage of gas volumes subject to transportation fees and costs
incurred to meet minimum payments on pipeline agreements.

Operating expenses for the quarter ended September 30, 2002, were $132
million lower than the same period in 2001. Contributing to the decrease in
expenses were non-cash full cost ceiling test charges totaling $135 million for
international properties incurred in the third quarter of 2001. A $12 million
decrease in severance and other taxes in 2002 resulted in an additional decrease
to total expenses. Offsetting these decreases in 2002 were higher overhead
corporate allocations of $11 million and higher depletion expense of $5 million
as a result of additional capital spending on assets in the full cost pool.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

For the nine months ended September 30, 2002, operating revenues were $159
million lower than the same period in 2001. An 11 percent decrease in natural
gas volumes and a 1 percent decrease in natural gas prices, before
transportation costs, contributed to $180 million of the decrease in revenues.
The decline in natural gas volumes is primarily attributed to the sale of
properties in Texas and Colorado. The decrease in revenue is partially offset
due to a 39 percent increase in oil, condensate and liquids volumes offset by a
15 percent decrease in their prices, before transportation costs, resulting in a
$43 million increase in revenues. Further decreasing revenues was a loss of $10
million in 2002 resulting from a mark-to-market adjustment of derivative
positions that no longer qualify as cash flow hedges under SFAS No. 133. These
hedges no longer qualify for hedge accounting treatment since they were
designated as hedges of anticipated future production from natural gas and oil
properties that were sold in March 2002.

Transportation and net product costs for the nine months ended September
30, 2002, were $9 million higher than the same period in 2001 primarily due to a
higher percentage of gas volumes subject to transportation fees and costs
incurred to meet minimum payments on pipeline agreements.

Operating expenses for the nine months ended September 30, 2002, were $117
million higher than the same period in 2001. Contributing to the increase in
expenses were non-cash full cost ceiling test charges totaling $267 million
incurred in 2002 for our Canadian full cost pool and other international
properties primarily in Brazil, Turkey and Australia, offset by third quarter
2001 non-cash full cost ceiling test charges on international properties
totaling $135 million. Also contributing to the increase in 2002 expenses were
higher depletion expenses of $79 million resulting from additional capital
spending on assets in the full cost pool, increased oilfield service costs of
$31 million due primarily to higher labor, workovers and production processing
fees and higher corporate overhead allocations of $21 million. Partially
offsetting the increase in expenses were merger-related costs and other charges
of $63 million incurred in 2001 relating to our combined production operations
and $10 million of changes in accounting estimates primarily related to
write-downs of materials and supplies resulting from the ongoing evaluation of
our operating standards recognized in 2001. For a discussion of merger-related
costs, see Item 1, Financial Statements, Note 4. For a discussion of write-
downs of materials and supplies, see Item 1, Financial Statements, Note 6, and
for a discussion of our ceiling test charge, see Item 1, Financial Statements,
Note 5. In addition, the increase in expenses were offset by $73 million of
lower severance and other taxes in 2002. The severance taxes decreased primarily
because of lower natural gas volumes and prices and for tax credits in 2002 for
high cost gas wells.

Other income for the nine months ended September 30, 2002, was $4 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.

55

MERCHANT ENERGY

Our Merchant Energy segment consists of three primary divisions: domestic
and international power, petroleum and LNG and trading and energy-related price
risk management activities. 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 our plan in the Merchant Energy
segment included:

- downsizing of our trading and risk management activities;

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

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

Since that time, the energy trading environment has continued to
deteriorate as evidenced by the following factors:

- many major participants have exited the industry;

- liquidity in the energy commodity markets has been reduced; and

- increasing credit demands have created uncertainty surrounding margin
calls and cash requirements for energy trading companies.

Because of these factors, in November 2002, we decided to exit the energy
trading business and pursue an orderly liquidation of our trading portfolio. To
do this, we plan to establish a separately capitalized subsidiary to hold the
bulk of our trading portfolio and manage its liquidation. We anticipate this
liquidation would occur over a period from 18 to 24 months. Once established, we
anticipate this subsidiary would have separate credit facilities of up to $600
million. We also expect to support the credit facilities with a pledge of
pipeline equity investments (Citrus and Great Lakes). We believe our plan should
allow us to obtain an independent investment grade credit rating for the
subsidiary, which would minimize much of the uncertainty surrounding our cash
needs for potential collateral calls. Our liquidation strategy is intended to
achieve the following:

- maximize cash flow from the trading portfolio;

- reduce our risk in an uncertain environment;

- avoid a fire sale of the portfolio in the current distressed environment;

- isolate the credit and liquidity needs of the trading business from the
rest of our business; and

- clearly outline our maximum potential investment in the trading business.

Following our decision to exit our energy trading activities, we will
continue to focus on other areas of our Merchant Energy segment including our
domestic and international power activities and petroleum and LNG activities. In
these areas we will concentrate on our core business and growth opportunities
while also rationalizing our existing assets in these areas.

Domestic and International Power

Our domestic and international power business includes the ownership and
operation of power generating facilities. In most cases, we partially own our
power generating facilities and account for them using the equity method. We
conduct most of our domestic power business through Chaparral. Internationally,
we have invested in the Brazil power market through our equity investment in
Gemstone. We also have interests in a number of other project-financed power
facilities in Asia, Central America, Europe and Mexico. We also engage in power
contract restructuring activities, mostly through our unconsolidated affiliate,
Chaparral. However, our restructuring activities may also involve power plants
and related assets that are consolidated in our financial statements, as in the
case of our Mount Carmel and Eagle Point Cogeneration restructuring transactions
that occurred this year and are discussed in our results of operations below.

Chaparral. As discussed in our 2001 Form 10-K, Chaparral (also known as
Electron), was formed to obtain lower cost financing to fund our domestic
unregulated power generation business. Our indirect ownership is approximately
20 percent and the remaining amount is owned by Limestone Investors, which is
controlled by investment affiliates of Credit Suisse First Boston Corporation.
Limestone Investors also issued

56

in March 2000, $1 billion of notes collateralized by the assets of Chaparral and
Series B Preferred Stock of El Paso that we issued to a trust.

In April 2002, we substituted the Series B Preferred Stock collateral for
substantially all of the Limestone notes with an El Paso guarantee. Only a small
portion of notes that have the Series B Preferred Stock as collateral remain
outstanding. In the event that Chaparral is not able to make payments on the
Limestone notes, then the holders of those notes will look to our guarantee for
payment as well as to the assets of Chaparral.

The Limestone notes mature in March 2003, at which time we anticipate that
we will purchase Limestone Investor's interest in Chaparral. Although we may
continue to look for a new joint venture partner, we expect to consolidate
Chaparral upon the purchase of Limestone Investors' interest. Chaparral owns
approximately 34 power generation facilities. As of September 30, 2002,
Chaparral had $1.8 billion of consolidated third party debt. Chaparral's debt is
related to specific projects it owns or has interests in, and is recourse solely
to those projects. Our total investment in Chaparral at September 30, 2002 was
$264 million, but we also had additional net receivables from Chaparral which
totaled $753 million, resulting in a total net investment in Chaparral of $1
billion at September 30, 2002.

If we were to purchase Limestone Investors' interest in Chaparral, we would
allocate our acquisition cost, represented by the cost to acquire Limestone
Investor's equity plus any debt assumed, to the assets and liabilities we
acquired based upon their fair values at the date of acquisition. If the fair
value of the assets acquired is less than our acquisition cost, we would
recognize goodwill for this difference, which we would be required to test for
impairment. It is possible that we could incur a charge if the goodwill is
determined to be impaired. If fair value is determined to be greater than our
purchase price, we would record the assets based upon our acquisition cost. A
number of factors, including industry developments, ongoing changes in our
business, and changes in energy prices will impact this determination of fair
value.

Through November 2002, Chaparral completed the sale of the following
assets:

- the Brush power plant for approximately $73 million in October 2002;
and

- the ManChief power plant for approximately $127 million in November
2002.

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,

57

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.

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.

Petroleum and LNG

We own or have interests in oil refineries, chemical production facilities,
petroleum terminalling and marketing operations, and blending and packaging
operations for lubricants and automotive products. Our refinery operations are
cyclical in nature and sensitive to movements in the price of crude oil. We are
currently operating in an environment where the differences in the price of our
crude oil input and the resulting products output is so narrow that we are
experiencing losses in our refinery operations. This has been compounded at our
Aruba facility where we have experienced operational difficulties following a
fire at the facility last year. We anticipate that our capacity utilization at
Aruba will improve in the fourth quarter of 2002 since we have just completed a
maintenance turnaround that is expected to bring the facility back up to full
capacity. We are also making significant progress in reducing costs at our
petroleum facilities, and we believe that conditions are favorable for improved
earnings from our petroleum activities in the future. We will continue to
rationalize our assets in this business and evaluate our petroleum activities
and their strategic fit with our core natural gas business.

We are also pursuing an LNG strategy that will focus on development of
infrastructure and technology that will provide for new supplies of natural gas
to meet the growing natural gas demand in North America. We have committed to a
time charter for four ships to secure transportation of LNG. Three of the four
ships will provide for on board regasification of the LNG. We expect the
delivery of these vessels between 2003 and 2005.

In May 2002, we received final approval from the Norwegian and United
States governments on an LNG purchase and sale agreement with Snohvit signed in
October 2001 with a consortium of natural gas production companies led by
Statoil ASA. This agreement is a derivative under SFAS No. 133, which we are
required to record as an asset from price risk management activities on our
balance sheet at its fair value. As a result, we recorded a $59 million gain in
the second quarter of 2002 to record the initial fair value of this derivative,
and recorded an increase in that fair value of $25 million during the third
quarter of 2002, for a total fair value of $84 million at September 30, 2002. In
October 2002, we entered into an agreement with Statoil ASA to allow Statoil ASA
to purchase our share of the LNG purchase and sale agreement for $210 million.
Subject to the completion of conditions required by the agreement, we expect to
complete this transaction by the end of 2002.

58

Trading and Energy-Related Price Risk Management Activities

Our trading activities have historically included customer originating and
trading activities that allow us, through financial and physical agreements, to
capture value arising from fluctuations in commodity prices.

As of September 30, 2002, the net fair value of all of our energy contracts
was $1.6 billion. Of this amount, the net fair value of our trading-related
energy contracts was approximately $1.0 billion. Our trading activities
generated margins (losses) during the nine months ended September 30, 2002 and
2001 totaling ($110) million and $229 million. The following table details the
net fair value of our energy contracts (both trading and non-trading) by year of
maturity and valuation methodology as of September 30, 2002:

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

(1) Non-trading energy contracts include derivatives from our power contract
restructuring activities of $963 million and derivatives related to our
natural gas and oil producing activities of $(363) million. Earnings related
to the natural gas and oil producing activities are included in our
Production segment results.

A reconciliation of our trading and non-trading energy contracts for the
nine months ended September 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.

59

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 have not recognized 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.

In addition to the factors impacting our trading business described above,
we will adopt the new provisions of EITF Issue No. 02-3 in the fourth quarter of
2002. This Issue has two significant provisions that will impact the fair value
of our trading price risk management activities. The first of the provisions
requires that we account for all energy-related contracts that do not qualify as
derivatives under SFAS No. 133 using the accrual method of accounting, rather
than mark-to-market accounting as was previously required under EITF Issue No.
98-10, Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. Following our application of this provision of EITF Issue No. 02-3
we will continue to record our derivative contracts at fair value under SFAS No.
133. The other provision will require that we account for all inventory held by
our energy-trading operation at the lower of its cost or fair value, rather than
using mark-to-market accounting as was previously allowed under the EITF Issue
No. 98-10. Upon adoption we will adjust the fair value of these inventories in
our balance sheet to their corresponding cost using an inventory valuation
method (such as average cost). The adoption of EITF Issue No. 02-3, in addition
to the announced trading exit strategy, may result in a total after-tax charge
of approximately $400 million to $600 million ($600 million to $900 million
before-tax).

Results of Operations

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

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

(1) Volumes include those traded over-the-counter 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.

Third Quarter 2002 Compared to Third Quarter 2001

For the quarter ended September 30, 2002, trading and refining gross
margins were $392 million lower than the same period in 2001 primarily due to a
reduction in trading margins of $296 million due to lower

60

price volatility in the natural gas and power markets, loss of option value
driven by our decision to manage our portfolio to increase cash flow and a
generally weaker trading environment in the third quarter of 2002. Also
contributing to the overall decrease in trading and refining margins was a $100
million decrease in refining margins resulting from lower spreads between the
sales prices of refined products and underlying feedstock costs and lower
throughput at our Aruba refinery. Besides the above factors, trading and
refining gross margins also reflected a net decrease of $66 million due to gains
on transactions we originated in the third quarter of 2001 associated with
transportation, storage and gas supply contracts. These decreases were partially
offset by an increase of $25 million in the value of a long-term LNG supply
contract with Snohvit and an increase of $22 million in the value of our net
trading price risk management assets and receivables resulting from the improved
credit of several of our counterparties in the third quarter of 2002.

Operating 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 September 30, 2002, operating and
other revenues were $37 million higher than the same period in 2001. The
increase was primarily due to revenues of $32 million from domestic and
international power facilities that were consolidated in the fourth quarter of
2001 and the first quarter of 2002 and management fees from Chaparral being
higher by $9 million in the third quarter of 2002.

Operating expenses for the quarter ended September 30, 2002, were $35
million higher than the same period in 2001. This was due primarily to a $96
million increase in operating expenses, partially offset by a $61 million
increase in the third quarter of 2001 primarily for additional estimated
environmental remediation liabilities. Contributing to the overall $96 million
increase in operating expenses were $19 million of higher expenses resulting
from the acquisition and consolidation of international and domestic
power-related entities in the fourth quarter of 2001 and the first quarter of
2002 and a $21 million increase in international employee expenses, training
program expenses and unscheduled maintenance expenses at our Aruba refinery in
the third quarter of 2002. Also contributing to the increase were higher
franchise and other taxes of $6 million and a higher allocation of corporate
expenses of $8 million in the third quarter of 2002.

Other income for the quarter ended September 30, 2002, was $34 million
lower than the same period in 2001 primarily due to marketing, agency and
technical services fees of $33 million earned in 2001 related to the development
of the Macae power project in Brazil. Also contributing to the decrease were
lower equity earnings of $7 million from unconsolidated projects in the third
quarter of 2002. Partially offsetting these decreases was a $15 million gain on
the sale of our 50 percent interest in a petroleum product terminal in the third
quarter of 2002.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

During 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.

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 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
61

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 collateralized solely by the contracts and cash flows of
UCF. The proceeds of the monetization are reported as financing cash flow.

We also employed the principles of our power restructuring business in
completing two contract terminations in the nine month period -- the Nejapa
transaction in the second quarter, and the Mount Carmel transaction in the first
quarter. 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. 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 nine months ended September 30, 2002, trading and refining gross
margins were $551 million lower than the same period in 2001 primarily due to
trading margins being lower by $728 million resulting from a lower price
volatility in the natural gas and power markets, loss of option value driven by
our decision to

62

manage our portfolio to increase cash flow and a generally weaker trading
environment in 2002. In addition, we had a $99 million decrease in refining
margins due to lower spreads between the sales prices of refined products and
underlying feedstock costs and lower throughput at our Eagle Point and Aruba
refineries. Also contributing to the decrease in refining gross margins was a
decrease of $128 million in marine revenue due to lower freight rates, a
decrease in vessels owned and on charter, and lower throughput at our marine
terminals, and a decrease of $87 million in refining margins resulting from the
lease of our Corpus Christi refinery and related assets to Valero in June 2001.
When we leased our refinery to Valero, we began including income from the lease
as other income. Besides the above factors, our trading and refining gross
margins were affected by transactions we originated and restructuring
transactions we completed during 2002. We recorded income of $512 million in the
first quarter of 2002 related to the Eagle Point Cogeneration and Mount Carmel
power contract restructurings as described above and a $59 million gain in the
second quarter of 2002 on the long-term LNG supply contract with Snohvit. The
fair value of the power contract restructurings decreased by $33 million from
the initial gains through September 30, 2002, and the fair value of the Snohvit
transaction increased by $25 million from the initial gain through September 30,
2002. In addition, our trading and refining gross margins decreased by $99
million due to gains on transactions we originated in 2001 associated with
transportation, storage and gas supply contracts. Offsetting the decrease in
trading and refining margins was an increase of $83 million in the value of our
net trading price risk management assets and receivables resulting from the
improved credit of several of our counterparties in 2002.

For the nine months ended September 30, 2002, operating and other revenues
were $224 million higher than the same period in 2001 primarily due to revenues
of $132 million from domestic and international power facilities that were
consolidated in the fourth quarter of 2001 and the first quarter of 2002, a $90
million gain from the termination of the Nejapa power contract in the second
quarter of 2002 and management fees from Chaparral that were higher by $28
million in 2002.

Operating expenses for the nine months ended September 30, 2002, were $165
million higher than the same period in 2001 primarily due to a $342 million
impairment of our power investments in Argentina recorded in the first quarter
of 2002 (see Item 1, Financial Statements, Note 4) and $81 million of higher
expenses resulting from the acquisition and consolidation of international and
domestic power-related entities in the fourth quarter of 2001 and the first
quarter of 2002. Also contributing to the increase were an allocation of
corporate expenses that was higher by $31 million in 2002, a $29 million
increase in international employee expenses, training program expenses and
unscheduled maintenance expenses at our Aruba refinery in 2002, a $19 million
turbine forfeiture fee for a cancelled power project during 2002, and higher
franchise and other taxes of $13 million in 2002. These increases were partially
offset by merger-related costs and asset impairments of $191 million recorded in
2001 associated with combining operations with Coastal (see Item 1, Financial
Statements, Note 4), a $133 million increase in 2001 primarily for additional
estimated environmental remediation liabilities and a decrease of $54 million in
fuel costs used 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 nine months ended September 30, 2002, was $173 million
lower than the same period in 2001 primarily due to marketing, agency and
technical services fees of $73 million from the development of the Macae power
project in Brazil earned in 2001, $49 million of Chaparral's minority ownership
interest in the initial income earned on our Eagle Point Cogeneration
restructuring transaction in the first quarter of 2002, and $13 million of
minority owner's interest in the gain on the termination of the Nejapa power
contract. Besides the above factors, other income also reflected lower equity
earnings of $24 million from unconsolidated projects in 2002. Partially
offsetting these decreases were a $15 million gain on the sale of our 50 percent
interest in a petroleum product terminal in the third quarter of 2002 and an
increase of $7 million in lease income related to the lease of our Corpus
Christi refinery to Valero in June 2001.

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,
63

these transactions should generate approximately $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 El Paso
Energy Partners, 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 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. This transaction is subject to customary regulatory reviews and
approvals, the execution of definitive agreements and receipt of satisfactory
financing. The closing of the sale is anticipated by the end of 2002. One of the
San Juan Basin assets included in this transaction is our remaining interests in
the Chaco cryogenic natural gas processing plant. As part of this transaction,
we will be required to repurchase the Chaco processing plant from El Paso Energy
Partners for $77 million in October 2021, and at that time, El Paso Energy
Partners has the right to lease the plant from us for a period of ten years with
the option to renew the lease annually thereafter. 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. The proposed sale
contemplates that we will receive up to $350 million of El Paso Energy Partners'
Series C units, a new class of the partnership's limited partner interests, with
the balance of the consideration to be received in cash. The potential $350
million Series C issuance will be reduced by the proceeds from any common unit
issuances El Paso Energy Partners may consummate before the closing of the San
Juan assets sale. Assuming a price of $32 per unit, we will receive
approximately 11 million of Series C units, and our current 27 percent ownership
interest in El Paso Energy Partners will increase to approximately 41 percent.
If the average market price is less than $27 per unit, the sale of the San Juan
assets may be delayed, terminated or renegotiated.

In accordance with SFAS No. 144, the San Juan assets were classified as
assets held for sale on the date we entered into the letter of intent with El
Paso Energy Partners. The assets are no longer depreciated once they are
classified as assets held for sale.

With the completion of these asset 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 El Paso Energy Partners to partially offset the anticipated
decrease in EBIT.

After we complete the expected sale of the San Juan 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.

In October 2002, we announced the sale of our 14.4 percent equity interest
in the Aux Sable natural gas liquids plant for approximately $10 million. We
anticipate a loss on this sale of approximately $47 million and recorded a
corresponding writedown of our investment in September 2002. In November 2002,
we entered into an agreement to sell our Natural Buttes and Ouray natural gas
gathering systems to Westport Resources Corporation for approximately $43
million. We expect to complete the transaction and record a gain on this sale of
approximately $29 million in the fourth quarter for 2002. These assets generated
EBIT of approximately $8 million during the year ended December 31, 2001.

We also serve as the general partner of El Paso Energy Partners. As the
general partner we manage the partnership's day-to-day operations and strategic
direction. We recognize earnings and receive cash from the partnership in
several ways, including through a share of the partnership's cash distributions
and through our ownership of common and preferred units. We are also reimbursed
for costs we incur to provide various operational and administrative services to
the partnership. In addition, we are reimbursed for other costs paid directly by
us on the partnership's behalf. During the nine months ended September 30, 2002,
we were

64

reimbursed approximately $39 million for expenses incurred on behalf of the
partnership. During the nine months ended September 30, 2002, our earnings and
cash from El Paso Energy Partners were as follows:

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

(1) The partnership is not obligated to pay these distributions until these
shares are redeemed.

We do not have any loans to or from El Paso Energy Partners. In addition,
except for a nominal guarantee of lease obligations on behalf of a subsidiary of
El Paso Energy Partners, we have not provided any guarantees, either monetary or
performance, on behalf of or for the benefit of El Paso Energy Partners nor do
we have any other liabilities other than normal course of business as a result
of, or arising out of, our role as the general partner or our ownership interest
in El Paso Energy Partners.

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

Third Quarter 2002 Compared to Third Quarter 2001

Total gross margins for the quarter ended September 30, 2002, were $65
million lower than the same period in 2001. The sale of our midstream assets to
El Paso Energy Partners in April 2002 resulted in a reduction in margins of $43
million. Lower NGL prices in 2002 unfavorably impacted our processing volumes
and margins primarily in the south Louisiana and south Texas regions by
approximately $12 million. 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 the Dragon
Trail processing plant in May 2002 resulted in additional reductions to our
processing margins of $6 million and $3 million.

Operating expenses for the quarter ended September 30, 2002, were $56
million lower than the same period of 2001. The decrease was primarily due to
lower operating costs of $18 million and lower depreciation expense of $9
million related to our sale of midstream assets to El Paso Energy Partners in
April 2002 and October 2001. Our depreciation expense was also lower by $6
million due to the assets held for sale classification of the San Juan Basin
assets in 2002 and lower amortization of goodwill due to the implementation of
SFAS No. 142 in January 2002. Also contributing to the decrease was a change in
our estimated environmental remediation liabilities and other charges in 2001 of
$17 million.

65

Other income for the quarter ended September 30, 2002, was $45 million
lower than the same period in 2001. In September 2002, we wrote down our
investment in the Aux Sable natural gas liquids plant by approximately $47
million, in anticipation of the loss from our announced sale of this interest.
This decrease was partially offset by higher earnings of $7 million in 2002 from
our interests in El Paso Energy Partners.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

Total gross margins for the nine months ended September 30, 2002, were $151
million lower than the same period in 2001. Margins decreased by approximately
$85 million due to our sale of midstream assets to El Paso Energy Partners in
April 2002. In addition, a $47 million decrease was due to lower NGL prices in
2002, which unfavorably impacted our processing margins and volumes in the south
Louisiana, south Texas and Rockies regions. 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 the
Dragon Trail processing plant in May 2002 also reduced our processing margins by
$18 million and $4 million. Lower natural gas prices in the San Juan Basin in
2002 resulted in a $24 million decrease in our gathering and treating margins.
Partially offsetting these decreases were favorable resolutions of fuel, rate
and volume matters of $13 million in the first quarter of 2002, $8 million of
unfavorable resolutions of fuel matters which occurred in 2001 and $14 million
due to higher realized transportation rates and increased system efficiency 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.

Operating expenses for the nine months ended September 30, 2002, were $146
million lower than the same period of 2001. The decrease was primarily a result
of lower operating costs of $40 million and lower depreciation expense of $26
million related to our sale of midstream assets to El Paso Energy Partners in
2002 and 2001. In addition, our 2002 cost reduction plan contributed $11 million
to our lower operating costs. Our depreciation expense was also lower by $4
million due to the assets held for sale classification of the San Juan Basin
assets in 2002 and $6 million associated with lower amortization of goodwill due
to the implementation of SFAS No. 142 in 2002. Also contributing to the decrease
were $46 million of merger-related costs in 2001, which included payments to El
Paso Energy Partners related to FTC ordered sales of assets owned by the
partnership, and an $8 million increase in our estimated environmental
remediation liabilities in 2001. For a discussion of these merger-related costs,
see Item 1, Financial Statements, Note 4.

Other income for the nine months ended September 30, 2002, was $35 million
lower than the same period in 2001. In September 2002, we wrote down our
investment in the Aux Sable natural gas liquids plant by approximately $47
million, in anticipation of the loss from our announced sale of this interest.
Also contributing to this decrease was a gain of $8 million recorded in May 2001
from the sale of our 1.01 percent non-managing interest in El Paso Energy
Partners. These decreases were partially offset by higher earnings of $13
million in 2002 from our interests in El Paso Energy Partners and a $10 million
gain recorded in 2002 from the sale of our Dragon Trail processing plant.

CORPORATE AND OTHER

Corporate and other net expenses, which include general and administrative
activities as well as the operations of our telecommunications and other
miscellaneous businesses, for the quarter and nine months ended September 30,
2002, were $125 million and $1,363 million lower than the same periods in 2001.
The decrease was primarily a result of $22 million and $1,176 million in
merger-related charges and asset impairments for the quarter and nine months
ended September 30, 2001, in connection with our merger with Coastal and
additional costs of $43 million and $144 million for the quarter and nine months
ended September 30, 2001 related to increased estimates of environmental
remediation costs and legal obligations 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. For a discussion of
these costs, see Part 1, Financial Statements, Note 4. Also contributing to the
decrease was $13 million and $22 million for the quarter and nine months ended
September 30, 2002, in telecommunications expenses due to our organizational
restructuring in November 2001. In the third quarter of 2002, we recorded a $21
million gain on the early extinguishment of
66

debt. Partially offsetting the decrease for the nine months ended September 30,
2002, 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 in our Gemstone
and Chaparral investments.

Our telecommunications business consists of the following:

- Texas-based metro transport services

- Long-haul and metro dark fiber marketing activities

- Collocation and cross-connect services

Our Texas-based metro transport services business provides bandwidth
transport services to wholesale customers in Austin, San Antonio, Dallas, Ft.
Worth and Houston. We provide a cost-effective service because of our ability to
use the telecommunications infrastructure of Southwestern Bell under our
interconnection agreement with them. We are currently involved in proceedings
with Southwestern Bell that could impact our cost of using their infrastructure,
and possibly our ability to use this infrastructure in the future. For an
additional discussion of this hearing, see Part I, Financial Statements, Note 13
under the subheading Southwestern Bell Proceeding. We currently have total
assets in our Texas-based metro business of $387 million, which includes $163
million of goodwill. Because of the continuing decline in the telecommunications
industry, we evaluate the fair value of our Texas-based assets, including our
goodwill, each quarter to determine if they are impaired. As of September 30,
2002, these assets were not impaired. There are a number of factors that could
impact the valuation of our Texas-based metro transport business in the future,
including a negative outcome of our Southwestern Bell proceeding, a decline in
our forecasted demand for services in the areas we serve or a further decline in
the telecommunications industry impacting our ability to expand this business.

We also market long-haul and metro dark fiber to other telecommunications
providers for use in expanding their own network infrastructure. Our inventory
of dark fiber at September 30, 2002, was valued at $146 million, and includes
inventory-in-progress associated with the construction of a long-haul fiber
optic route from Houston, Texas to Los Angeles, California, with a cost basis of
$109 million. We are currently involved in arbitration proceedings with
Broadwing Communication Services, the company we contracted with to construct
this route, over the construction and maintenance of this fiber optic route. For
a further discussion of this matter, see Part I, Financial Statements, Note 13,
under the subheading Other Matters. The outcome of this arbitration proceeding
ranges from, if we are successful in our claims, a full recovery of amounts paid
to Broadwing, which is $62 million, together with clean title to this route, to
a substantial write-down or complete write-off of this route should we be
unsuccessful in our claim against Broadwing or should they become financially
insolvent. Consequently, we are currently unable to predict what a probable
outcome will be. We will continue to carry our investment in this fiber optic
route at its historical cost until we are able to determine it is probable that
a permanent decline in our investment has occurred, at which time any necessary
adjustment will be made. Our remaining fiber optic inventory is accounted for at
the lower of its cost or market value. During the third quarter of 2002, we
completed an analysis of market prices, and as a result, we wrote down our long
haul fiber inventory by $8 million for routes outside of Texas.

Our collocation and cross-connect services are available through our
Lakeside Technology Center, a Chicago-based telecommunications facility that
provides space for telecommunications carriers designed for their unique
equipment needs, as well as access to multiple network connections of various
telecommunications carriers. We operate this facility 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 at the facility with
Global Crossing, who 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. As a result of this event, we
analyzed the fair value of the building. Our analysis was completed in the third
quarter, and we estimated that the fair value of the building was $162 million,
which is significantly below the expected residual value originally anticipated
and guaranteed under our lease agreement and results in a contingent loss of
$113 million. Consequently, we are amortizing this deficiency over the remaining
lease term. This resulted

67

in an additional charge of $4 million in the third quarter of 2002, and will
result in a charge of $8 million for each remaining quarter through May 2006.
The building design, which is beneficial for the heavy equipment, low staffing
needs of a telecommunications provider, also limits the alternative uses for the
facility putting pressure on the fair value of the building during this
significant downturn in the telecommunications industry.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter ended September 30, 2002, was
$342 million, or $62 million higher than the same period in 2001. The increase
was primarily due to approximately $60 million increase in interest expense from
higher long-term borrowings for ongoing capital projects, investment programs
and operating requirements. Also contributing to the increase was a $30 million
increase in interest expense due to the Mohawk River Funding IV debt borrowed in
June 2002 and the UCF debt borrowed in July 2002, as well as lower capitalized
interest. These increases were partially offset by $13 million decrease in
interest expense due to repayments of short-term credit facilities and lower
interest rates on short-term borrowings, as well as $10 million decrease in
interest expense due to repayments of other financing obligations.

Interest and debt expense for the nine months ended September 30, 2002, was
$1,008 million, or $142 million higher than the same period in 2001. The
increase was primarily due to $192 million increase in interest expense from
higher long-term borrowings for ongoing capital projects, investment programs
and operating requirements. This increase was offset by a $35 million decrease
in interest expense due to retirement of long-term debt. Also contributing to
the increase was a $53 million increase in interest expense due to the new UCF
debt, the Mohawk River Funding IV debt and lower capitalized interest. These
increases were partially offset by a $42 million decrease in interest expense
due to repayments of short-term credit facilities and lower interest rates on
short-term borrowings, and a $26 million decrease in interest expense due to
lower receivable factoring and lower interest rates on other debts. We
anticipate interest and debt expenses will continue to exceed last year's levels
throughout the remainder of 2002.

RETURNS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Returns on preferred interests of consolidated subsidiaries for the quarter
and nine months ended September 30, 2002, were $13 million and $48 million lower
than the same periods in 2001, primarily due to lower interest rates in 2002.
Most of these returns are based on variable short-term rates, which were lower
on average in 2002 versus the same periods in 2001. Partially offsetting these
decreases were higher returns on preferred interests issued as part of our
Gemstone investment completed in November 2001.

INCOME TAXES

Income tax benefit for the quarter ended September 30, 2002, was $14
million resulting in an effective tax rate of 30 percent. Income tax expense for
the nine months ended September 30, 2002, was $105 million resulting in an
effective tax rate of 32 percent. Our effective tax rates were different than
the statutory rate of 35 percent primarily due to the following:

- state income taxes;

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

- foreign income taxed at different rates.

Income tax expense for the quarter and nine months ended September 30,
2001, was $102 million and $4 million, resulting in effective tax rates of 32
percent and 1 percent. The nine months ended September 30, 2001 expense includes
$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

68

the nine months ended September 30, 2001 was 35 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.

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Statements, Note 13, which is incorporated herein by
reference.

NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

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

69

CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS

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

- earnings per share;

- capital and other expenditures;

- dividends;

- financing plans;

- capital structure;

- liquidity and cash flow;

- credit ratings;

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

- future economic performance;

- operating income;

- management's plans; and

- goals and objectives for future operations.

Forward-looking statements are subject to risks and uncertainties. While we
believe the assumptions or bases underlying the forward-looking statements are
reasonable and are made in good faith, we caution that assumed facts or bases
almost always vary from the actual results, and these variances can be material,
depending upon the circumstances. We cannot assure you that the statements of
expectation or belief contained in the forward-looking statements will result or
be achieved or accomplished. Important factors that could cause actual results
to differ materially from estimates or projections contained in forward-looking
statements are described in our 2001 Annual Report on Form 10-K, and as set
forth below:

A DOWNGRADE OF OUR CREDIT RATINGS TO BELOW INVESTMENT GRADE COULD
SIGNIFICANTLY IMPACT OUR LIQUIDITY.

Moody's and Standard and Poor's currently rate our senior unsecured debt at
their lowest "investment grade" ratings and continue to keep us on negative
credit watch. If either or both of these credit rating agencies, or any other
rating agency, lower our rating to "below investment grade", our liquidity would
be immediately and significantly impacted. Additional cash would be required by
our counterparties to support our energy trading activities. Additionally, many
of our financial guarantees, purchase obligations and other commercial
commitments could be negatively impacted by lower credit ratings. Any such
downgrades could also affect our ability to obtain additional financing in the
future and would affect the terms of any such financing.

AN ADVERSE RULING OR OUTCOME IN OUR REGULATORY AND LEGAL MATTERS IN AND
RELATING TO CALIFORNIA COULD HAVE A MATERIAL IMPACT ON US.

We and some of our subsidiaries are parties to lawsuits in California
related to alleged unfair and unlawful business practices, complaints before the
FERC related to the alleged exercise of market power violations of marketing
affiliate regulations, and an alleged lack of compliances with FERC regulations
in the transportation of gas to California. If a court or regulatory agency rule
against us or one of our subsidiaries in one of these actions, the impact of
such a ruling or any penalties, awards or judgments resulting from such a ruling
could have a significant impact on us. For example, when the ALJ issued its
initial decision in

70

September 2002 that our pipeline withheld capacity from California, our stock
price was immediately and negatively affected and the credit spreads in our debt
widened. If the ALJ's decision is upheld by the FERC or if any other lawsuits or
regulatory actions in California are decided against us, it could have a
significant and sustained impact on our liquidity, credit rating and our ability
to raise capital to meet our ongoing and future investing and financing needs.

OUR OBJECTIVES IN EXITING THE ENERGY TRADING BUSINESS MAY NOT BE ACHIEVED
IN THE TIME PERIOD OR IN THE MANNER WE EXPECT, IF AT ALL.

We recently announced our intention to exit the energy trading business and
pursue an orderly liquidation of our trading portfolio. If we are unable to
achieve these objectives in the time period or the manner that we expect, it
could have a substantial negative impact on our cash flows, liquidity and
financial position. The ability to achieve our goals in the liquidation is
subject to factors beyond our control, including, among others, obtaining
maximum cash flow from our trading portfolio and isolating the credit and
liquidity needs of the energy trading business from the rest of our business.

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 2001 Annual Report on
Form 10-K, 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.

The $5 million increase in our trading Value-at-Risk is attributable to our
Snohvit transaction, which is a long-term LNG purchase contract. The increase in
trading Value-at-Risk is offset by our efforts to downsize our trading
activities and limit our investment in our trading operations.

Our non-trading Value-at-Risk decreased by $8 million due to a reduction of
our hedged volumes of future natural gas production during 2002. We reduced
these hedged volumes to reduce the cash requirements of our non-trading price
risk management activities.

ITEM 4. CONTROLS AND PROCEDURES

Under the supervision and with the participation of our management,
including our principal executive officer and principal financial officer, we
have evaluated the effectiveness of the design and operation of our disclosure
controls and procedures within 90 days of the filing date of this quarterly
report pursuant to Rules 13a-15 and 15d-15 under the Securities Exchange Act of
1934 (the "Exchange Act"). Based on that evaluation, our principal executive
officer and principal financial officer have concluded that these controls and
procedures are effective. There were no significant changes in our internal
controls or in other factors that could significantly affect these controls
subsequent to the date of their evaluation.

71

Disclosure controls and procedures are our controls and other procedures
that are designed to ensure that information required to be disclosed by us in
the reports that we file or submit under the Exchange Act is recorded,
processed, summarized and reported, within the time periods specified under the
Exchange Act. Disclosure controls and procedures include, without limitation,
controls and procedures designed to ensure that information required to be
disclosed by us in the reports that we file under the Exchange Act is
accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure.

The principal executive officer and principal financial officer
certifications required under Sections 302 and 906 of the Sarbanes-Oxley Act of
2002 have been included herein, or as Exhibits to this Quarterly Report on Form
10-Q, as appropriate.

72

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

See Part I, Item 1, Financial Statements, Note 13, 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 the 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 purported shareholder class actions filed in the U.S. District Court
for the Southern District of Texas, Houston Division, are: Marvin Goldfarb, et
al v. El Paso Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine,
filed July 18, 2002; Residuary Estate Mollie Nussbacher, Adele Brody Life
Tenant, et al v. El Paso Corporation, William Wise, and H. Brent Austin, filed
July 25, 2002; George S. Johnson, et al v. El Paso Corporation, William Wise,
and H. Brent Austin, filed July 29, 2002; Renneck Wilson, et al v. El Paso
Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August
1, 2002; and Sandra Jean Malin Revokable Trust, et al v. El Paso Corporation,
William Wise, H. Brent Austin, and Rodney D. Erskine, filed August 1, 2002; Lee
S. Shalov, et al v. El Paso Corporation, William Wise, H. Brent Austin, and
Rodney D. Erskine, filed August 15, 2002; Paul C. Scott, et al v. El Paso
Corporation, William Wise, H. Brent Austin, and Rodney D. Erskine, filed August
22, 2002; Brenda Greenblatt, et al v. El Paso Corporation, William Wise, H.
Brent Austin, and Rodney D. Erskine, filed August 23, 2002; Stephanie Beck, et
al v. El Paso Corporation, William Wise and H. Brent Austin, filed August 23,
2002; J. Wayne Knowles, et al v. El Paso Corporation, William Wise, H. Brent
Austin, and Rodney D. Erskine, filed September 13, 2002; The Ezra Charitable
Trust, et al v. El Paso Corporation, Rodney D. Erskine and H. Brent Austin,
filed October 4, 2002. IRA F.B.O. Michael Conner et al v. El Paso Corporation,
William Wise, H. Brent Austin, Jeffrey Beason, Ralph Eads, D. Dwight Scott,
Credit Suisse First Boston, J.P. Morgan Securities, filed October 25, 2002.

The shareholder derivative action filed in Houston is: Grunet Realty Corp.
v. William A. Wise, Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James
Gibbons, Anthony Hall Jr., Ronald Kuehn Jr., J. Carleton MacNeil Jr., Thomas
McDade, Malcolm Wallop, Joe Wyatt and Dwight Scott, filed August 22, 2002.

73

The shareholder derivative action filed in Delaware is: Stephen Brudno v.
William A. Wise, Byron Allumbaugh, John Bissell, Juan Carlos Braniff, James
Gibbons, Anthony Hall, Jr., Ronald Kuehn Jr., J. Carleton MacNeil Jr., Thomas
McDade, Malcolm Wallop and Joe Wyatt, filed October 2, 2002.

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

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

None

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

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

None.

ITEM 5. OTHER INFORMATION

None.

74

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.

76

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 July 10, July
12, July 23, July 25, August 8, August 14, September 30, two on October 2, and
October 9, 2002, were provided for informational purposes within this Quarterly
Report on Form 10-Q.

77

SIGNATURES

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

EL PASO CORPORATION

Date: November 14, 2002 /s/ D. Dwight Scott
------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer
(Principal Financial Officer)

Date: November 14, 2002 /s/ Jeffrey I. Beason
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

78

CERTIFICATION

I, William A. Wise, certify that:

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

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

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

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

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

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

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

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

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

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

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

/s/ William A. Wise
--------------------------------------
William A. Wise
Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)
El Paso Corporation

Date: November 14, 2002

79

CERTIFICATION

I, D. Dwight Scott, certify that:

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

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

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

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

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

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

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

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

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

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

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal controls
subsequent to the date of our most recent evaluation, including any corrective
actions with regard to significant deficiencies and material weaknesses.

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

Date: November 14, 2002

80

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.