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 recov