EL PASO CGP CO - 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 1-7176

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EL PASO CGP COMPANY
(Exact Name of Registrant as Specified in its Charter)

DELAWARE 74-1734212
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)

EL PASO BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)

Telephone Number: (713) 420-2600

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 $1 per share. Shares outstanding on November 14,
2002: 1,000

EL PASO CGP COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION H(1)(a) AND
(b) OF FORM 10-Q AND IS THEREFORE FILING THIS REPORT WITH A REDUCED DISCLOSURE
FORMAT AS PERMITTED BY SUCH INSTRUCTION.

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EL PASO CGP COMPANY

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

See accompanying notes.

1

EL PASO CGP COMPANY

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

See accompanying notes.

2

EL PASO CGP COMPANY

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

See accompanying notes.

3

EL PASO CGP COMPANY

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

See accompanying notes.
4

EL PASO CGP COMPANY

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

See accompanying notes.

5

EL PASO CGP COMPANY

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 3 through 7), 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
stockholder's 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.
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 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:

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Our other intangible assets consist of capitalized development costs,
software licensing agreements, customer lists and other miscellaneous intangible
assets. We amortize all intangible assets on a straight-line basis over their
estimated useful life. 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 $3 million and $12 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 $8 million
and $21 million. Based on the current amount of intangible assets subject to
amortization, our estimated amortization expense for each of the next five years
are as follows: $1 million for each of 2003, 2004 and 2005 and less than $1
million for both 2006 and 2007. 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) for the quarter and nine months ended September 30, 2001, as if
goodwill had not been amortized during those periods, compared with the income
(loss) from continuing operations before extraordinary items and cumulative
effect of accounting changes and net income (loss) we reported for the quarter
and nine months ended September 30, 2002:

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 pipelines and midstream assets, which met all of the requirements. Our coal
mining business was treated as discontinued operations in the second quarter of
2002, and the assets were treated as assets held for sale in the third quarter
of 2002. See Notes 2 and 6 for further information.

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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 $10 million, which resulted in a gain of $1 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
stockholder's equity. For the quarter and nine months ended September 30, 2001,
we reclassified costs of $4.4 billion and $12.8 billion to operating revenues.
In October 2002, the EITF reached several additional decisions regarding
accounting for energy trading contracts. See Note 15 for a discussion of these
decisions.

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
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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 completed the Eagle Point Cogeneration restructuring in the first
quarter of 2002. The restructured power contract is presented in our balance
sheet as an asset from price risk management activities, and the associated
power supply agreement is presented as a liability 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. We 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
this payment as operating revenue. For the nine months ended September 30, 2002,
we recognized total revenues from power restructuring and contract termination
activities of $1,030 million and total costs of $606 million. On the date the
restructuring transactions were completed, revenues recorded were $973 million
and costs were $551 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.

2. DIVESTITURES

In December 2001, El Paso Corporation (El Paso), our parent, announced a
plan to strengthen its balance sheet in order to improve its 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.

Announced Asset Sales

In July 2002, our parent entered into a letter of intent with El Paso
Energy Partners, L.P., an affiliate, to sell our Typhoon offshore natural gas
and oil gathering pipelines, as well as our natural gas liquids (NGL) pipelines
and a related fractionation facility in Texas. The Typhoon pipelines consist of
a 35-mile, 20-inch natural gas pipeline and a 16-mile, 12-inch oil pipeline
originating on the Chevron/BHP "Typhoon" platform in the Green Canyon area of
the Gulf of Mexico. The NGL assets consist of over 500 miles of NGL pipelines
and a related fractionation facility in Texas.

9

This proposed sale was approved by both our parent's 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, our parent 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
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 closing of
this sale is expected to occur by the end of 2002.

These assets have been classified as assets held for sale in our balance
sheet as of September 30, 2002, and we stopped depreciating them beginning July
2002. The total assets being sold include net property, plant and equipment of
approximately $109 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 do not expect to realize a material gain
or loss from this sale.

The sale of our federally regulated natural gas gathering system located in
the Panhandle Field of Texas for $19 million is subject to final closing pending
a FERC abandonment order.

The proposed sale of our 14.4 percent equity interest in the Canadian and
United States segments of the Alliance Pipeline and our Aux Sable natural gas
liquids plant, and related entities for approximately $165 million 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.

In November 2002, El Paso entered into an agreement with Westport Resources
Corporation to sell our Natural Buttes and Ouray natural gas gathering
facilities. These assets include 240 miles of natural gas gathering pipelines
with approximately 200 MMcf/d of capacity. The transaction is expected to close
by year end.

In November 2002, we announced an agreement to sell substantially all of
our reserves and properties in Virginia, West Virginia and Kentucky. We expect
to complete the sale in the fourth quarter of 2002. These properties are in our
financial statements as discontinued operations. See Note 6 for further
discussion.

3. MERGER-RELATED COSTS AND ASSET IMPAIRMENTS

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

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 El Paso, we completed an employee restructuring across all of
our operating segments, resulting in the reduction of 3,200 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 $583 million which included 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 El Paso common stock on the date of the our merger in exchange for the
fair value of our employees' and directors' stock options and restricted stock.
A total of 339 employees and 11 directors received these shares.

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 $164 million. The charges include
incremental fees under software and seismic license agreements of $15 million,
which were recorded in our Production segment, and approximately $149 million in
estimated lease-related costs to relocate our pipeline operations from Detroit,
Michigan to Houston, Texas incurred in both our Pipeline 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 $148 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 El Paso. 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

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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 the 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 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 $93 million
which include payments made in satisfaction of obligations arising from the
approval of our merger with El Paso and other miscellaneous charges. These items
were expensed in the period in which they were incurred.

Asset Impairments

During the nine months ended September 30, 2001, we incurred an asset
impairment charge of approximately $9 million resulting from unrecoverable
capitalized costs of Merchant Energy's Corpus Christi refinery.

4. 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. As of September 30, 2002, using period-end
daily posted natural gas and oil prices, our capitalized costs exceeded the
ceiling limit. Due to an increase in daily posted prices subsequent to September
30, 2002, no ceiling test charges were recorded in our income statement for the
third quarter 2002, based upon the daily posted natural gas and oil prices as of
November 1, 2002, adjusted for oilfield or gas gathering hub and wellhead price
differences as appropriate. Had we computed the third quarter ceiling test
charges based upon the daily posted natural gas and oil prices as of September
30, 2002, we would have incurred a ceiling test charge of $96 million for our
domestic full cost pool.

During the nine months ended September 30, 2002, we recorded ceiling test
charges of $243 million, of which $10 million was charged during the first
quarter and $233 million was charged during the second quarter. The write-down
includes $226 million for our Canadian full cost pool, $10 million for our
Brazilian full cost pool and $7 million for 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 unit. For the nine months ended September 30,
2001, we recorded ceiling test charges of $115 million, including $87 million
for our Canadian full cost pool and $28 million for our Brazilian full cost
pool.

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 ceiling test
charges, we would have incurred an additional third quarter 2002 charge of $29
million, or a total charge of $125 million for the nine months ended September
30, 2002, and $830 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.

5. 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,
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$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 our methods of
environmental identification, assessment and remediation strategies and
processes to El Paso's historical practices following our merger with El Paso.
The change in estimate of our legal obligations was a result of a review process
to assess our legal exposures, strategies and plans following our merger with El
Paso. 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 El Paso, 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 $209 million for the quarter and nine months ended September 30,
2001.

6. DISCONTINUED OPERATIONS

In June 2002, our parent's 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 parent's 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.

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 because we plan
to sell them in the next twelve months. The summarized financial results of
discontinued operations are as follows:

7. EXTRAORDINARY ITEMS

Under a Federal Trade Commission order, as a result of our January 2001
merger with El Paso, we sold 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 $184
million. We recognized extraordinary net losses of approximately $11 million,
net of income taxes of approximately $5 million, including a third quarter 2001
charge of $4 million to record additional estimated income taxes on these sales.

8. 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:

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(1) Trading contracts represent those that qualify for accounting under EITF
Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities. See Note 15 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.

Other derivatives are 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 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

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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 is updated each period based on changes in actual and projected
market prices, fluctuations in the credit ratings of our counterparties,
significant changes in interest rates, and changes to the assumed timing of
deliveries.

In May 2002, we announced a plan to reduce the volumes of natural gas that
we have hedged for our Production segment, and we removed the hedging
designation on derivatives that had a fair value loss of $56 million at
September 30, 2002. This amount, net of income taxes of $20 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 $36 million in accumulated other comprehensive income, we estimate that
unrealized losses of $2 million, net of income taxes, related to these
derivatives will be reclassified to income over the next twelve months.

9. INVENTORY

Our inventory consisted of the following:

10. DEBT AND OTHER CREDIT FACILITIES

At December 31, 2001, our weighted average interest rate on our short-term
credit facilities was 2.4%, and there were no amounts outstanding under these
facilities at September 30, 2002. We had the following short-term borrowings and
other financing obligations:

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

15

Issuances

Retirements

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

(1) These notes are collateralized solely by the cash flows and contracts of
these consolidated subsidiaries, and are non-recourse to our parent and
other affiliated 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) These amounts represent a buyback of our bonds in the open market in July
and August 2002.

(3) The majority of this debt was exchanged for El Paso common stock. See below
for further discussion.

In June 2002, El Paso amended its existing $1 billion 3-year revolving
credit and competitive advance facility to permit El Paso to issue up to $500
million in letters of credit and to adjust pricing terms. This facility matures
in August 2003. We are a designated borrower under this facility and, as such,
are liable for any amounts outstanding under this facility. The interest rate
varies based on El Paso's 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, and $492 million in
letters of credit were issued under the facility.

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

In August 2002, El Paso issued 12,184,444 shares of its 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

16

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.

We 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 sales of assets,
capitalization requirements, dividend restrictions and cross-acceleration
provisions. A breach of any of these covenants could accelerate the debt or
other financial obligations of us and our subsidiaries.

One of the most significant debt covenants is that we 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 have a
$30 million cross-acceleration provision. In addition, we have indentures
associated with our public debt that contain $5 million cross-acceleration
provisions.

Other Financing Arrangements

During 2000, El Paso formed a series of companies that it refers to as
Clydesdale. Clydesdale was formed to provide financing to invest in various
capital projects and other assets. A third-party investor contributed cash of $1
billion into Clydesdale in exchange for the preferred securities of one of El
Paso's consolidated subsidiaries. Our assets that collateralize the preferred
interest include Colorado Interstate Gas Company, and beginning in July 2002,
additional natural gas and oil properties.

11. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

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
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

17

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 $67 million accrued for all
outstanding legal matters.

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 $281 million,
including approximately $277 million for expected remediation costs and
associated onsite, offsite and groundwater technical studies, and approximately
$4 million for related environmental legal costs, which we anticipate incurring
through 2027. Approximately $15 million of the accrual was related to our
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............................. $260
Additions/adjustments....................................... 27
Payments.................................................... (10)
Other changes, net.......................................... 4
----
Balance as of September 30, 2002............................ $281
====

In addition, we expect to make capital expenditures for environmental
matters of approximately $199 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 $20 million. In addition, approximately $14
million of this amount will be expended under government directed clean-up
plans. The remaining $6 million will be self-directed or in connection with
facility closures.

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

18

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 22
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 $5 million and $8 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

Rate Case. In March 2001, Colorado Interstate Gas Company (CIG) filed a
rate case with the Federal Energy Regulatory Commission (FERC) proposing
increased rates of $9 million annually and new and enhanced services for its
customers. CIG received an order from the FERC in late April 2001, which
suspended the rates until October 1, 2001, subject to refund, and subject to the
outcome of hearing. On September 26, 2001, the FERC rejected two firm services
CIG had proposed in its rate filing and required it to reallocate the costs
allocated to those two services to existing services. CIG complied with this
order and arranged with the affected customers to provide service under existing
rate schedules. CIG and its customers entered into a settlement agreement in May
2002 settling all issues in the case. The settlement, which contained a rate
increase, was approved by the FERC in August 2002, and became final in September
2002. The settlement obligates CIG to file a rate case to be effective no later
than October 1, 2006. CIG will pay approximately $12 million in refunds on
November 25, 2002. These refunds are included in other current liabilities, and
will not have an adverse effect on our financial position or results of
operations.

Marketing Affiliate NOPR. In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct
governing the relationship between interstate pipelines and marketing affiliates
to all energy affiliates. The proposed regulations, if adopted by the FERC,
would dictate how all our energy affiliates conduct business and interact with
our interstate pipelines. In December 2001, we filed comments with the FERC
addressing our concerns with the proposed rules. A public hearing was held on
May 21, 2002, providing an opportunity to comment further on the NOPR. Following
the conference, additional comments were filed by our pipeline subsidiaries and
others. At this time, we cannot predict the outcome of the NOPR, but adoption of
the regulations in their proposed form would, at a minimum, place additional
administrative and operational burdens on us.

Negotiated Rate NOI. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that seeks comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. 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

19

September 25, 2002, El Paso's 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.

While the outcome of our outstanding legal matters, environmental matters
and rates and regulatory matters cannot be predicted with certainty, based on
the information known to date and our existing accruals, we do not expect the
ultimate resolution of these matters to have a material adverse effect on our
financial position, operating results or cash flows. It is possible that new
information or future developments could require us to reassess our potential
exposure related to these matters. 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 Commitments

ANR Independence Pipeline Company, our subsidiary, owns a 33.3 percent
interest in Independence Pipeline Company with an investment balance of
approximately $18 million. The Management Committee of Independence Pipeline
Company voted to dissolve the partnership effective September 30, 2002. Though
the pipeline was not constructed, Independence Pipeline Company owns some
property and rights of way that were purchased. These assets will be sold over
the course of a one-year period and are not expected to amount to more than $1
million. At the end of the third quarter of 2002, we fully reserved for the
investment balance.

12. 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.

20

We use earnings before interest 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, 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 consesus
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 revenue. 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:

13. 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 for our
proportionate share of unconsolidated affiliates below includes affiliates in
which we hold an interest of a 50 percent or less, as well as those in which we
hold a greater than a 50 percent interest. Our proportional share of the net
income of the unconsolidated affiliates in which we hold

22

a greater than 50 percent interest was $9 million and $14 million for the
quarters ended, and $27 million and $38 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.

Related Party Transactions

In March 2002, we acquired assets with a net book value, net of deferred
taxes, of approximately $8 million from El Paso.

Additionally, we sold natural gas and oil properties to El Paso. Net
proceeds from these sales were $404 million, and we did not recognize a gain or
loss on the properties sold.

We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of its participating affiliates, thus
minimizing total borrowing from outside sources. As of September 30, 2002 and
December 31, 2001, we had borrowed $1,602 million and $908 million. The market
rate of interest as of September 30, 2002 was 1.8% and at December 31, 2001, it
was 2.1%. In addition, we had a demand note receivable with El Paso of $150
million at September 30, 2002, at an interest rate of 2.3%. At December 31,
2001, the demand note receivable was $120 million at an interest rate of 4.2%.

At September 30, 2002 and December 31, 2001, we had current accounts and
notes receivable from related parties of $259 million and $426 million. In
addition, we had a non-current note receivable from a related party of $25
million and $27 million included in other non-current assets at September 30,
2002 and at December 31, 2001.

At September 30, 2002 and December 31, 2001, we had other accounts payable
to related parties of $785 million and $428 million. In addition, included in
short-term borrowings at September 30, 2002 and December 31, 2001, was a current
note payable to related parties of $1 million and $67 million.

El Paso Energy Partners

In July 2002, our parent entered into a letter of intent to sell our
Typhoon offshore natural gas and oil pipelines as well as our NGL pipelines and
a related fractionation facility in Texas to El Paso Energy Partners. See Note 2
for further discussion.

14. PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

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.

23

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 interests, from RBCC, Inc., an unaffiliated investor, in El Paso
Production Oil and 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 limited partner's outstanding
capital plus unpaid priority returns.

15. 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, we will continue to record contracts that are
derivatives under SFAS No. 133, at their fair value. The other consensus reached
will require that all inventory held by energy-trading operations be accounted
for 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. We will adopt
these decisions during the fourth quarter, and are currently evaluating the
effects of these decisions on our price risk management activities.

24

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

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.

RECENT DEVELOPMENTS

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

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

- The modification of credit standards by the rating agencies.

As a response to these industry developments, the credit rating agencies,
Moody's and Standard and Poor's, re-evaluated the credit ratings of companies
involved in energy trading activities, which included our parent and affiliates
(and us to a lesser degree) as well as the credit ratings of most of the largest
participants in the energy trading industry. Many of these participants 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.

While these developments do not have an immediate impact on our financial
position or results of operations, a further downgrade of our debt securities
would result in higher cash requirements to conduct our operations (through cash
collateral requirements). If this were to occur we would have less cash
available to use for capital expenditures and other purposes, although we do
believe we would have sufficient operating resources to fund our ongoing
operating activities.

In addition, as a result of the downgrade in the credit rating of several
of our customers, and the placement of them on negative credit watch, the
credit-worthiness of these companies have been questioned. We have taken actions
to mitigate our exposure by requesting these companies provide us with a letter
of credit or prepayment as permitted by our pipelines' tariffs. Our pipelines'
tariffs permit us to request additional credit assurance from our customers
equal to the cost of performing transportation services for either a two or
three month period depending on the pipeline. With respect to new construction
projects, we have requested credit assurance for longer periods of time from the
customers supporting those projects. If these companies file for Chapter 11
bankruptcy protection and our contracts are not assumed by other counterparties,
or if the capacity is unavailable for resale, it could have a material adverse
effect on our financial position, operating results or cash flows.

25

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

PIPELINES

Our Pipelines segment includes our interstate natural gas transmission and
gas storage operations. Our interstate natural gas 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.

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 costs of providing services to our customers. As a result, our
pipeline results have historically been relatively stable. However, they can be

26

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.

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 merger with El Paso including
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, were $24
million lower than 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 CIG's sale of the Panhandle field and other production
properties in July 2002. Also contributing to the decrease were lower
transportation revenues of $3 million from lower summer capacity sold under
short-term contracts, lower 2002 sales of base gas from abandoned storage fields
of $2 million, lower prices on liquids sales of $1 million and lower resales of
natural gas purchased from the Dakota gasification facility of $1 million. These
decreases were partially offset by higher reservation revenues of $12 million
primarily due to our system expansion projects, which were placed in service in
2001.

Operating expenses for the quarter ended September 30, 2002, were $29
million lower than the same period in 2001. A decrease of $14 million was due to
CIG's sale of the Panhandle field and other production properties in July 2002.
Also contributing to the decrease were $6 million of merger-related costs
incurred in 2001 primarily associated with asset impairments, $5 million of
lower amortization of goodwill due to the implementation of SFAS No. 142 in 2002
and $3 million of lower ad valorem taxes in 2002. For a discussion of our
merger-related costs, see Item 1, Financial Statements, Note 3.

Other income for the quarter ended September 30, 2002, was $5 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 $113
million lower than the same period. A decrease of $33 million was due to reduced
natural gas and liquids sales due to lower prices in 2002, $29 million decrease
from natural gas sales, gathering and processing activities due to CIG's sale of
the Panhandle field and other production properties in July 2002 and a $25
million decrease in sale of excess natural gas in 2001. Also contributing to the
decrease were $23 million from lower resales of natural gas

27

purchased from the Dakota gasification facility, $16 million lower
transportation revenues due to milder weather in 2002 and $4 million lower 2002
sales of base gas from abandoned storage fields. These decreases were partially
offset by higher reservation revenues of $26 million primarily due to system
expansion projects placed in service in 2001.

Operating expenses for the nine months ended September 30, 2002, were $329
million lower than the same period in 2001 primarily as a result of
merger-related costs of $217 million incurred in 2001 to relocate our pipeline
operations from Detroit, Michigan to Houston, Texas, costs for employee
benefits, severance, retention, transition charges and other miscellaneous
charges. Also contributing to the decrease were $25 million from lower gas costs
for our system supply purchases and royalties resulting from lower natural gas
prices and volumes, $23 million from lower prices on natural gas purchased from
the Dakota gasification facility, $18 million of a change in accounting estimate
primarily for additional environmental remediation liabilities in 2001, $17
million from lower benefit costs and cost efficiencies following our merger with
El Paso, $14 million lower amortization of goodwill due to the implementation of
SFAS No. 142 in 2002, $14 million decrease in operating expenses due to CIG's
sale of the Panhandle field and other production properties in July 2002, $4
million lower corporate overhead allocations and $2 million lower ad valorem
taxes in 2002. These decreases were partially offset by an increase in 2002 in
our estimated liabilities of $13 million to assess and remediate our
environmental exposure due to an ongoing evaluation of our operating facilities.

Other income for the nine months ended September 30, 2002, was $25 million
higher than the same period in 2001. The increase was due to a gain of $11
million on the sale of pipeline expansion rights in February 2002 and $11
million on 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 was higher equity
earnings in 2002 of $7 million on our Great Lakes Gas Transmission investment.
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.

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 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 $1.77 per equivalent unit.

28

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

- ---------------
(1) Include production costs, depletion, depreciation and amortization, ceiling
test charges, merger-related costs, change 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 $214
million lower than the same period in 2001. A 40 percent decrease in natural gas
volumes and a 14 percent decrease in natural gas prices, before transportation
costs, attributed to $194 million of the decrease in revenues. The decline in
natural gas volumes was primarily due to the sale of properties in Texas and
Colorado in 2002. In addition, revenues decreased by $13 million due to a 24
percent decrease in oil, condensate and liquids volumes.

Transportation and net product costs for the quarter ended September 30,
2002, were $5 million higher than the same period in 2001 primarily due to costs
incurred to meet minimum payments on pipeline agreements.

Operating expenses for the quarter ended September 30, 2002, were $145
million lower than the same period in 2001. Contributing to the decrease in
expenses were non-cash full cost ceiling test charges incurred in the third
quarter of 2001 totaling $115 million on international properties and lower
depletion expenses of $26 million in 2002 due to lower volumes, offsetting
higher rates. A $12 million decrease in severance and other taxes in 2002
resulted in an additional decrease to our operating expenses. Offsetting these
decreases were higher corporate overhead allocations of $13 million.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

For the nine months ended September 30, 2002, operating revenues were $399
million lower than the same period in 2001. A 28 percent decrease in natural gas
volumes and a 2 percent decrease in natural gas prices, before transportation
costs, resulted in a $350 million decrease in revenues. The decline in natural
gas volumes was primarily due to the sale of properties in Texas and Colorado in
2002. In addition, revenues

29

decreased $37 million due to 23 percent decrease in oil, condensate and liquids
prices, before transportation costs.

Transportation and net product costs for the nine months ended September
30, 2002, were $7 million lower 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 in 2001.

Operating expenses for the nine months ended September 30, 2002, were $11
million higher than the same period in 2001. Contributing to the increase in
expenses were non-cash full cost ceiling test charges totaling $243 million
incurred in 2002 for our Canadian full cost pool and other international
properties primarily in Brazil and Australia, offset by non-cash full cost
ceiling test charges incurred in the third quarter of 2001 totaling $115 million
for international properties. Higher corporate overhead allocations of $30
million also contributed to the increase in expenses. Partially offsetting these
increases were merger-related costs and other charges of $61 million incurred in
2001 associated with combining operations with El Paso and $10 million of
changes in accounting estimates primarily related to a write-down 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 3. For a discussion of write-down of materials and
supplies, see Item 1, Financial Statements, Note 5, and for a discussion of our
ceiling test charges, see Item 1, Financial Statements, Note 4. In addition,
offsetting increased expenses were $67 million of decreased severance and other
taxes in 2002, decreased oilfield service costs of $4 million primarily due to
lower workovers and production processing and lower depletion expense of $6
million in 2002 due to lower volumes, offsetting higher rates. The severance
taxes decreased primarily because of lower natural gas volumes and prices and
for tax credits in 2002 for high cost gas wells.

MERCHANT ENERGY

Our customer origination and trading activities, as well as our power,
refining and chemical activities are conducted through our Merchant Energy
segment. As part of the power operations of our Merchant Energy segment, we
engage in power contract restructuring activities. As in the case of our Eagle
Point Cogeneration restructuring transaction discussed in results of operations
below, our restructuring of power plant facilities and related assets are
consolidated in our financial statements.

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
also engage in power contract restructuring activities that involve power plants
and related assets that are consolidated in our financial statements, as in the
case of our Eagle Point Cogeneration restructuring transaction that occurred
this year and is discussed in our results of operations below.

Power Contract Restructuring Activities

Many of our domestic power plants 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

30

over its term. When we assume this risk, we manage these obligations by entering
into transactions to buy power from third parties that mitigate our risk over
the life of the contract. These activities are reflected as part of our trading
activities and reduce our exposure to changes in power prices from period to
period. Power contract restructurings generally result in a higher return in our
power generation business because we can deliver reliable power at lower prices
than our cost to generate power at these PURPA power plants. In addition, we can
use the restructured contracts as collateral to obtain financing at a cost that
is comparable to, or lower than, our existing financing costs. The manner in
which we account for these activities is discussed in Item 1, Financial
Statements, Note 1, of this Form 10-Q.

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 five restructuring transactions, including contract terminations, of
varying financial significance, and we have additional facilities which we will
consider for restructuring in the future.

Petroleum

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.

Results of Operations

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

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

(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.

31

Trading and refining gross margins consist of revenues from commodity
trading 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 $104 million lower than the same period in 2001 primarily due to
refining margins being lower by $107 million in 2002 resulting from lower
spreads between the sales prices of the refined product and the underlying
feedstock cost and lower throughput at our Aruba refinery.

Operating and other revenues consist of revenues from domestic and
international power generation facilities. For the quarter ended September 30,
2002, operating and other revenues were $49 million higher than the same period
in 2001 primarily due to consolidation of domestic and international power
facilities in the fourth quarter of 2001 and the first quarter of 2002, which
contributed a $45 million increase to operating and other revenues.

Operating expenses for the quarter ended September 30, 2002, were $10
million higher than the same period in 2001. This was due primarily to a $71
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 $71 million
increase in operating expenses were $23 million of higher expenses resulting
from the consolidation of international and domestic power-related entities in
the fourth quarter of 2001 and the first quarter of 2002. Besides the
consolidation of these entities, operating expenses also reflected 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.

Other income for the quarter ended September 30, 2002, was $1 million lower
than the same period in 2001. This was primarily due to a $16 million decrease
in other income, partially offset by a $15 million gain on sale of our 50
percent interest in a petroleum product terminal in the third quarter of 2002.
Contributing to the overall $16 million decrease in other income were $10
million due to lower equity earnings from unconsolidated projects in 2002.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

During the nine months ended September 30, 2002, we completed power
restructurings or contract terminations at our Eagle Point Cogeneration 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 El Paso Merchant Energy L.P. (EPME), an affiliated
company. The terms of the EPME power supply contract were identical to the
restructured power contract, with the exception of price, which was set at $37
per MWh over its 14-year term.

For credit enhancement purposes, in anticipation of the financing
transaction associated with the restructuring, UCF terminated the EPME supply
contract in the second quarter of 2002 and replaced it with a supply contract
with a Morgan Stanley affiliate. UCF entered into the Morgan Stanley contract
solely for the purpose of reducing the cost of debt UCF would issue.

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
32

power generated from the Eagle Point plant, which had averaged over $75 per MWh,
with power that we have purchased at a cost of $37 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 contracts of approximately $898 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 our 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 $348
million. Total operating cash flows from this transaction amounted to
approximately $120 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
contract termination at our Nejapa power plant in the second quarter of 2002. 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.

For the nine months ended September 30, 2002, trading and refining gross
margins were $17 million higher than the same period in 2001. Our trading and
refining margins were affected by our restructuring transactions. We recorded
income of $397 million in the first quarter of 2002 related to the Eagle Point
Cogeneration power contract restructuring described above. The fair value of our
power contract restructurings decreased by $33 million from the initial gain
through September 30, 2002. Partially offsetting this net increase in trading
and refining gross margins was a $128 million decrease in marine revenues 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. In addition, trading and
refining gross margins decreased $87 million from lower spreads between the
sales prices of refined product and the underlying feedstock cost and lower
throughput at our Eagle Point and Aruba refineries and $37 million due to
reimbursement from the insurance company received in 2001 related to the fire at
our Aruba facility in April 2001.

For the nine months ended September 30, 2002, operating and other revenues
were $218 million higher than the same period in 2001. Contributing to the
overall increase were revenues of $147 million from domestic and international
power facilities that were consolidated in the fourth quarter of 2001 and the
first quarter of 2002 and a $90 million gain from the termination of the Nejapa
power contract. Partially offsetting these increases was $20 million from the
transfer of power index swaps on our Fulton and Rensselaer power facilities and
the sale of a power facility in 2001.

Operating expenses for the nine months ended September 30, 2002, were $228
million lower than the same period in 2001 primarily as a result of decrease of
$152 million of merger-related costs and asset impairment recorded in 2001
associated with combining operations with El Paso (see Item 1, Financial
Statements, Note 3) and a $133 million increase in estimate in 2001 primarily
for additional environmental remediation and legal liabilities. Also
contributing to the decrease was 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

33

related assets to Valero in June 2001. These decreases were partially offset by
$105 million of higher expenses resulting from the consolidation of
international and domestic power-related entities in the fourth quarter of 2001
and the first quarter of 2002 and higher international employee expenses,
training program expenses and unscheduled maintenance expenses of $29 million at
our Aruba refinery in 2002.

Other income for the nine months ended September 30, 2002, was $87 million
lower than the same period in 2001. Contributing to the overall decrease was $49
million of 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 $32 million from unconsolidated projects and foreign
currency losses of $4 million in 2002. Partially offsetting these decreases were
a $15 million gain on 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

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 of 2002. These assets generated
EBIT of approximately $8 million during the year ended December 31, 2001.

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 $13
million lower than the same period in 2001. Margins decreased by approximately
$8 million primarily due to lower natural gas liquids prices and natural
declines in production in 2002, which unfavorably impacted our volumes and
margins in the Rockies and south Louisiana regions. Also contributing to the
decrease was approximately $3 million related to the sale of the Dragon Trail
processing plant in May 2002.

Operating expenses for the quarter ended September 30, 2002, were $18
million lower than the same period in 2001. The decrease was primarily due to a
change in our estimated environmental remediation liabilities and other
merger-related charges in 2001 of $16 million. Other income for the quarter
ended September 30, 2002, was a loss of $49 million attributable to the write
down of our investment in the Aux

34

Sable natural gas liquids plant of approximately $47 million, in anticipation of
the loss from our announced sale of this interest.

Nine Months Ended 2002 Compared to Nine Months Ended 2001

Total gross margins for the nine months ended September 30, 2002, were $42
million lower than the same period in 2001. Margins decreased by approximately
$34 million primarily due to lower natural gas liquids prices and natural
declines in production in 2002, which unfavorably impacted our volumes and
margins in the Rockies and south Louisiana regions. Also contributing to the
decrease was approximately $4 million related to the sale of the Dragon Trail
processing plant in May 2002.

Operating expenses for the nine months ended September 30, 2002, were $27
million lower than the same period in 2001. The decrease was primarily due to
merger-related costs of $13 million, a change in our estimated environmental
remediation liabilities of $9 million in 2001 and $6 million of lower operating
expenses as a result of our cost reduction plan in 2002.

Other income for the nine months ended September 30, 2002, was a loss of
$39 million. 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 loss was partially offset by
a $10 million gain from the sale of our Dragon Trail processing plant in 2002.

CORPORATE AND OTHER

Corporate and other net expenses, which include general and administrative
activities as well as other miscellaneous businesses, for the quarter and nine
months ended September 30, 2002, were $86 million and $731 million lower than
the same periods in 2001. The decrease was primarily due to a charge of $554
million in merger-related costs for the nine months ended September 30, 2001, in
connection with our 2001 merger with El Paso. Additional costs for the quarter
and nine months ended September 30, 2001, were charges of $42 million and $145
million related to increased estimates of environmental remediation and
reductions in 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 merger.
Also contributing to the decrease in corporate and other expenses for the
quarter and nine months ended September 30, 2002, were losses in 2001 of $13
million and $32 million in our Retail business as a result of the sale of
substantially all of our retail gas stations in 2001.

INTEREST AND DEBT EXPENSE

Non-affiliated Interest and Debt Expense

Non-affiliated interest and debt expense for the quarter ended September
30, 2002, was $119 million, or $16 million higher than the same period in 2001
primarily due to $22 million increase in interest from Mohawk River Funding IV
debt borrowed in June 2002 and the UCF debt borrowed in July 2002. These debts
were borrowed for ongoing capital projects, investment programs and operating
requirements. These increases were partially offset by $4 million decrease in
interest due to lower receivable factoring, $3 million decrease in interest due
to repayment of $400 million long-term debt in the first quarter of 2002 as well
as the conversion of $435 million FELINE PRIDES(SM) to El Paso common stock in
August 2002.

Affiliated Interest Expense, Net

Affiliated interest expense, net for the quarter ended September 30, 2002,
was $4 million, or $8 million lower than the same period in 2001 due to lower
short-term interest rates on decreased average advances from El Paso under our
cash management program. The average short-term interest rates for the third
quarter decreased from 3.8% in 2001 to 1.8% in 2002.

Affiliated interest expense, net for the nine months ended September 30,
2002, was $9 million, or $25 million lower than the same period in 2001
primarily due to lower short-term interest rates on average

35

advances from El Paso under our cash management program. The average short-term
interest rates for the nine months decreased from 4.9% in 2001 to 1.9% in 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 $7 million and $28 million, or $4
million and $9 million lower than the same periods in 2001, primarily due to a
redemption of preferred stock in a consolidated trust in July 2002.

INCOME TAXES

Income tax benefit for the quarter ended September 30, 2002, was $10
million, resulting in an effective tax rate of 33 percent. Income tax expense
for the nine months ended September 30, 2002, was $174 million, resulting in an
effective tax rate of 33 percent. Our effective tax rates were different than
the statutory rate of 35 percent primarily due to the following:

- state income taxes; and

- foreign income taxed at different rates.

Income tax expense for the quarter ended September 30, 2001, was $20
million resulting in an effective tax rate of 34 percent. Income tax benefit for
the nine months ended September 30, 2001, was $31 million, resulting in an
effective tax rate of 8 percent. The nine months ended September 30, 2001
benefit included $105 million of tax expense associated with non-deductible
merger charges and changes in our estimates of additional tax liabilities. The
majority of these estimated additional liabilities were paid in 2001 and are
being contested by us. The effective tax rate excluding these charges for the
nine months ended September 30, 2001 was 34 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; and

- foreign income taxed at different rates.

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Statements, Note 11, which is incorporated herein by
reference.

NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

See Item 1, Financial Statements, Note 15, which is incorporated herein by
reference.

36

CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995

This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and to be made in
good faith, assumed facts or bases almost always vary from the actual results,
and the differences between assumed facts or bases and actual results can be
material, depending upon the circumstances. Where, in any forward-looking
statement, we or our management express an expectation or belief as to future
results, that expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions will
generally identify forward-looking statements.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

This information updates, and you should read it in conjunction with,
information disclosed in Part II, Item 7A in our Annual Report on Form 10-K for
the year ended December 31, 2001, in addition to the information presented in
Items 1 and 2 of this Quarterly Report on Form 10-Q.

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.

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.

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.

37

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

See Part I, Item 1, Financial Statements, Note 11, which is incorporated
herein by reference.

ITEM 2. CHANGES IN SECURITIES.

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

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

None.

ITEM 5. OTHER INFORMATION.

None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.

a. Exhibits.

Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an "*"; all
exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.

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

None.

38

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 CGP COMPANY

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

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

39

CERTIFICATION

I, William A. Wise, certify that:

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

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.

Date: November 14, 2002 /s/ WILLIAM A. WISE
--------------------------------------
William A. Wise
Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)
El Paso CGP Company

40

CERTIFICATION

I, D. Dwight Scott, certify that:

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

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.

Date: November 14, 2002 /s/ D. DWIGHT SCOTT
--------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer and Director
(Principal Financial Officer)
El Paso CGP Company

41

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.