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, 2003

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 by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes [ ] No [X]

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 12,
2003: 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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EL PASO CGP COMPANY

TABLE OF CONTENTS

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Below is a list of terms that are common to our industry and used
throughout this document:

/d = per day
Bbl = barrels
BBtu = billion British thermal units
Bcfe = billion cubic feet of natural gas
equivalents
MBbls = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of natural gas
equivalents
MMBtu = million British thermal units
MMcf = million cubic feet
Tcfe = trillion cubic feet of natural gas
equivalents

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

When we refer to "us", "we", "our", "ours", or "El Paso CGP", we are
describing El Paso CGP Company and/or our subsidiaries.

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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 AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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 Current Report on Form 8-K dated
September 23, 2003 (which updated the financial statement information originally
presented in our 2002 Form 10-K to reclassify our petroleum markets business as
a discontinued operation), which includes a summary of our significant
accounting policies and other disclosures. The financial statements as of
September 30, 2003, and for the quarters and nine months ended September 30,
2003 and 2002, are unaudited. We derived the balance sheet as of December 31,
2002, from the audited balance sheet filed in our Current Report on Form 8-K
dated September 23, 2003. In our opinion, we have made all adjustments which are
of a normal, recurring nature to fairly present our interim period results. Due
to the seasonal nature of our businesses, information for interim periods may
not be indicative of our results of operations for the entire year. Our results
for all periods presented have been reclassified to reflect our petroleum and
coal mining operations as discontinued operations. In addition, prior period
information presented in these financial statements includes reclassifications
which were made to conform to the current period presentation. These
reclassifications had no effect on our previously reported net income or
stockholder's equity.

Our accounting policies are consistent with those discussed in our Current
Report on Form 8-K dated September 23, 2003, except as follows:

Accounting for Asset Retirement Obligations. On January 1, 2003, we
adopted Statement of Financial Accounting Standards (SFAS) No. 143, Accounting
for Asset Retirement Obligations. SFAS No. 143 requires that we record a
liability for retirement and removal costs of long-lived assets used in our
business. This liability is recorded at its estimated fair value, with a
corresponding increase to property, plant and equipment. This increase in
property, plant and equipment is then depreciated over the remaining useful life
of the long-lived asset to which that liability relates. An ongoing expense is
also recognized for changes in the value of the liability as a result of the
passage of time, which we also record in depreciation, depletion and
amortization expense in our income statement. In the first quarter of 2003, we
recorded a charge as a cumulative effect of accounting change of approximately
$21 million, net of income taxes, related to our adoption of SFAS No. 143. We
also recorded property, plant and equipment of $111 million and asset retirement
obligations of $156 million as of January 1, 2003. Our asset retirement
obligations are associated with our natural gas and oil wells and related
infrastructure in our Production segment and our natural gas storage wells in
our Pipelines segment. We have obligations to plug wells when production on
those wells is exhausted, and we abandon them. We currently forecast that these
obligations will be met at various times, generally over the next 10 years,
based on the expected productive lives of the wells and the estimated timing of
plugging and abandoning those wells. The net asset retirement liability as of
January 1, 2003 and September 30, 2003, reported in other current and
non-current liabilities in our balance sheet, and the changes in the net
liability for the nine months ended September 30, 2003, were as follows (in
millions):

Liability at January 1, 2003................................ $ 156
Liabilities settled in 2003................................. (29)
Accretion expense in 2003................................... 7
Liabilities incurred in 2003................................ 1
Changes in estimate......................................... (7)
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Net liability at September 30, 2003....................... $ 128
======

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Our changes in estimate represent changes to the expected amount and timing
of payments to settle our asset retirement obligations. These changes primarily
result from obtaining new information about the timing of our obligations to
plug our natural gas and oil wells and the costs to do so. Had we adopted SFAS
No. 143 as of January 1, 2002, our current and non-current retirement
liabilities on that date would have been approximately $130 million and our
income from continuing operations and net income for the quarter and nine months
ended September 30, 2002, would have been lower by $2 million and $6 million.

Accounting for Costs Associated with Exit or Disposal Activities. On
January 1, 2003, we adopted SFAS No. 146, Accounting for Costs Associated with
Exit or Disposal Activities. SFAS No. 146 requires that we recognize costs
associated with exit or disposal activities when they are incurred rather than
when we commit to an exit or disposal plan. We applied the provisions of SFAS
No. 146 in accounting for restructuring costs we incurred during 2003. For the
quarter and nine months ended September 30, 2003, we recorded $1 million and $10
million of employee severance costs, less income taxes of less than $1 million
and $1 million associated with our discontinued operations, substantially all of
which had been paid as of June 30, 2003. As we continue to evaluate our business
activities and seek additional cost savings, we expect to incur additional
charges that will be evaluated under this accounting standard.

Amendment of Statement 133 on Derivative Instruments and Hedging
Activities. In April 2003, the Financial Accounting Standards Board (FASB)
issued SFAS No. 149, Amendment of Statement 133 on Derivative Instruments and
Hedging Activities. This statement amends SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities to incorporate several
interpretations of the Derivatives Implementation Group (DIG), and also makes
several modifications to the definition of a derivative as it was defined in
SFAS No. 133. SFAS No. 149 affects contracts entered into or modified after June
30, 2003. There was no initial financial statement impact of adopting this
standard, although the FASB and DIG continue to deliberate on the application of
the standard to certain derivative contracts, such as power capacity contracts,
which may impact our financial statements in the future.

Accounting for Certain Financial Instruments with Characteristics of both
Liabilities and Equity. In May 2003, the FASB issued SFAS No. 150, Accounting
for Certain Financial Instruments with Characteristics of both Liabilities and
Equity. This statement provides guidance on the classification of financial
instruments as equity, as liabilities, or as both liabilities and equity. In
particular, the standard requires that we classify all mandatorily redeemable
securities as liabilities in the balance sheet. We adopted the provisions of
SFAS No. 150 on July 1, 2003, and reclassified $300 million of our Coastal
Finance I preferred interests from preferred interests of consolidated
subsidiaries to long-term debt in our balance sheet. We also began classifying
dividends accrued on the preferred interests as interest and debt expense in our
income statement after July 1, 2003. For the quarter and nine months ended
September 30, 2003, total dividends were $6 million and $18 million. The third
quarter of 2003 dividends of $6 million were recorded in interest expense in our
income statement. The first and second quarter of 2003 dividends of $12 million
were recorded as distributions on preferred interests of consolidated
subsidiaries in our income statement.

Accounting for Guarantees. On January 1, 2003, we adopted Financial
Accounting Standards Board Interpretation (FIN) No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others. FIN No. 45 requires that we record a liability for all
guarantees, including financial performance and fair value guarantees, issued
after December 31, 2002, at fair value when they are issued. There was no
initial financial statement impact of adopting this standard.

Accounting for Regulated Operations. Our interstate natural gas pipelines
and storage operations are subject to the jurisdiction of the Federal Energy
Regulatory Commission (FERC) in accordance with the Natural Gas Act of 1938 and
Natural Gas Policy Act of 1978. In 1996, we discontinued the application of SFAS
No. 71, Accounting for the Effects of Certain Types of Regulation. However, as a
result of recent changes in our competitive environment and operating cost
structures, we are evaluating the applicability of the provisions of SFAS No. 71
to our financial statements. The outcome of this evaluation could result in the
restoration of our application of this accounting in some, if not all, of our
regulated systems. We expect to complete our current evaluation of the
applicability of SFAS No. 71 by the end of the year. For a discussion of
differences in accounting for regulated operations, see our Current Report on
Form 8-K dated September 23, 2003.

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2. DIVESTITURES

During 2003, we completed or announced the sale of a number of assets and
investments in each of our business segments. The gains and losses on these
sales and any asset impairments recorded on these assets, investments and
operations are discussed in Notes 4, 6 and 14.

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(1) Excludes $48 million of costs incurred in preparing assets for disposal,
returns of invested capital and cash transferred with assets sold.

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(1) Amounts on sales that have been announced or are under contract for sale are
estimates, subject to customary regulatory approvals, final sale
negotiations and other conditions.

(2) We have entered into a non-binding letter of intent to sell these assets.

(3) This sale was completed in October 2003.

8

Each period, we evaluate our potential asset sales to determine if any meet
the criteria as held for sale or as discontinued operations under SFAS No. 144,
Accounting for the Impairment or Disposal of Long-Lived Assets. To the extent
that all of the criteria of SFAS No. 144 are met, we classify an asset as held
for sale or, if appropriate, discontinued operations. For example, El Paso's
Board of Directors (or a designated subcommittee of its Board) is required to
approve asset dispositions greater than specified thresholds. Unless specific
approval is received by its Board (or a designated subcommittee) by the end of a
given reporting period to commit to a plan to sell an asset, we would not
classify it as held for sale or discontinued operations in that reporting period
even if it is management's stated intent to sell the asset. As of December 31,
2002, we had $31 million of long-lived assets classified as held for sale and
reflected in current assets in our balance sheet, all of which had been sold as
of September 30, 2003. As of September 30, 2003, we had no long-lived assets
classified as held for sale and had approximately $1.6 billion of assets
classified as discontinued operations as of September 30, 2003 (see Note 6).

We continue to evaluate assets we may sell in the future. As specific
assets are identified for divestiture, we will be required to record them at the
lower of fair value or historical cost. This may require us to assess them for
possible impairment. The amounts of these impairment charges, if any, will
generally be based on estimates of the expected fair value of the assets as
determined by market data obtained through the divestiture process or by
assessing the probability-weighted cash flows of the asset. For a discussion of
impairment charges incurred on our long-lived assets, see Note 4; for
impairments on discontinued operations, see Note 6; and for impairments on our
investments in unconsolidated affiliates, see Note 14.

As of September 30, 2002, we had completed the following asset sales:

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(1)Excludes $3 million of costs incurred in preparing assets for disposal,
returns of invested capital and cash transferred with the assets sold.

3. CEILING TEST CHARGES

Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to determine whether the carrying
value of natural gas and oil properties exceeds the present value of future net
revenues, discounted at 10 percent, plus the lower of cost or fair market value
of unproved properties, net of related income tax effects.

For 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 during the second quarter. The 2002 charges include
$226 million for our Canadian full cost pool, $10 million for our Brazilian full
cost pool and $7 million for other international production operations. Our
ceiling test charges were based upon the daily posted natural gas and oil prices
at the end of each period, adjusted for oilfield or natural gas gathering hub
and wellhead price differences, as appropriate. The 2002 charge for our Canadian
full cost pool primarily resulted from a low daily posted price for natural gas
at the end of the second quarter of 2002.

For the third quarter 2002, capitalized costs in our United States full
cost pool did not exceed the ceiling limit, based upon the daily posted 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 gas and oil prices as of
September 30, 2002, we would have incurred a ceiling test charge of $96 million
for our United States full cost pool.

9

Also, 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. The charges for our international cost pools would not have
changed had the impact of these hedges not been included in calculating these
ceiling test charges since we do not significantly hedge our international
production activities. However, we would have incurred an additional charge of
$28 million related to our United States full cost pool in 2002.

4. GAIN (LOSS) ON LONG-LIVED ASSETS

Our gain (loss) on long-lived assets consists of net realized gains and
losses on sales of long-lived assets and impairments of long-lived assets, and
was as follows:

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(1) These amounts exclude approximately $1.3 billion of asset impairments for
the nine months ended September 30, 2003, related to our petroleum markets
operations that were reclassified as discontinued operations.

Net Realized Gain

Our 2003 net realized gains were primarily related to the sales of the
Mid-Continent midstream assets in our Field Services segment, the Table Rock
sulfur extraction facility in our Pipelines segment and non-full cost pool
assets in our Production segment. Our 2002 net realized gains were primarily
related to the sales of expansion rights in our Pipelines segment and the sale
of the Dragon Trail processing plant in our Field Services segment.

Asset Impairments

We are required to test assets for possible impairment whenever events or
changes in circumstances indicate that the carrying amount of these assets may
not be fully recoverable. One event that triggers this test is the expectation
that it is more likely than not that we will sell or dispose of the asset before
the end of its estimated useful life. Based on El Paso's intent to dispose of a
number of our assets, we tested those assets for recoverability during the first
nine months of 2003. As a result of these assessments, we recognized impairments
of $10 million and $24 million in the third quarter and the first nine months of
2003 related to non-full cost pool Canadian assets in our Production segment and
a crude oil pipeline in our Merchant Energy segment. For additional asset
impairments on our discontinued operations and investments in unconsolidated
affiliates, see Notes 6 and 14.

5. OTHER EXPENSES

Other expenses for the quarter and nine months ended September 30, 2002,
were $1 million and $151 million. Included in the nine month amount was a $90
million contract termination fee paid by our Eagle Point Cogeneration facility
(in our global power division of our Merchant Energy segment) to our Eagle Point
refinery (in the petroleum markets division classified as discontinued
operations). This payment was eliminated in consolidation since the income
associated with the petroleum markets division is reflected in discontinued
operations while the power division's expense is included in Merchant Energy's
operating results. Other expenses for the nine month period also included $50
million of minority interest in our consolidated subsidiaries.

6. DISCONTINUED OPERATIONS

Petroleum Markets Operations

In June 2003, El Paso's Board of Directors authorized the sale of
substantially all of our petroleum markets operations, including our Aruba
refinery, our Unilube blending operations, our domestic and

10

international terminalling facilities and our petrochemical and chemical plants.
The Board's actions were in addition to previous actions approving the sales of
our Eagle Point refinery, our asphalt business, our Florida terminal, tug and
barge business and our lease crude operations. Based on our intent to dispose of
these operations, we were required to adjust these assets to their estimated
fair value. As a result, we recognized pre-tax charges during the nine months
ended September 30, 2003 totaling $1,366 million related to our petroleum
markets assets, which included $929 million related to our Aruba refinery and
$252 million related to the impairment of our Eagle Point refinery. These
impairments were based on a comparison of the carrying value of our petroleum
markets assets to their estimated fair value. Our fair value estimates were
based on preliminary market data obtained through the early stages of the sales
process and an analysis of expected discounted cash flows. The magnitude of
these charges was impacted by a number of factors, including the nature of the
assets to be sold, and our established time frame for completing the sales.

In the second quarter of 2003, we entered into a product offtake agreement
with Vitol S.A. Inc. (Vitol) for the sale of a number of the products produced
at our Aruba refinery. As a result of this contract, Vitol became the single
largest customer of our Aruba refinery, purchasing approximately 75 percent of
the products produced at that plant. The agreement is for one year with two
one-year extensions at Vitol's option. We have the right to terminate the
agreement when the refinery is sold.

Coal Mining Operations

In the latter part of 2002 and the first quarter of 2003, we sold our coal
mining operations. These operations consisted of fifteen active underground and
two surface mines located in Kentucky, Virginia and West Virginia. Following the
authorization of the sale by El Paso's Board of Directors, we recorded
impairment charges of $37 million and $185 million in our loss from discontinued
operations during the third quarter and the nine months ended September 30,
2002.

Our petroleum markets operations and our coal mining operations were
historically included in our Merchant Energy segment, and are classified as
discontinued operations in our financial statements for all of the historical
periods presented. All of the assets and liabilities of the remaining
discontinued businesses are classified as other current assets and liabilities
as of September 30, 2003. The summarized financial results and financial
position data of discontinued operations were as follows:

12

7. CUMULATIVE EFFECT OF ACCOUNTING CHANGES

On January 1, 2003, we adopted SFAS No. 143. As a result, we recorded a
cumulative effect of an accounting change of approximately $21 million, net of
income taxes (see Note 1).

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. One of our
unconsolidated affiliates, the Midland Cogeneration Venture Limited Partnership,
recognized a gain on a fuel supply contract upon adoption of this new rule, 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.

8. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

The following table summarizes the carrying value of our price risk
management assets and liabilities as of September 30, 2003 and December 31,
2002:

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(1) Trading contracts are derivative contracts that historically have been
entered into for purposes of generating a profit or benefiting from
movements in market prices.

(2) 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 comprised of derivative contracts primarily related
to our power restructuring activities at our Eagle Point Cogeneration and our
Capitol District Energy Center Cogeneration Associates facilities. For a further
discussion of our power restructuring activities, see our Current Report on Form
8-K dated September 23, 2003.

9. INVENTORY

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(1) We recorded these amounts as other non-current assets in our balance sheet.

10. DEBT AND OTHER CREDIT FACILITIES

We had $272 million and $369 million of current maturities of long-term
debt at September 30, 2003, and December 31, 2002.

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Credit Facilities

In April 2003, El Paso entered into a new $3 billion revolving credit
facility, with a $1.5 billion letter of credit sublimit, which matures on June
30, 2005. El Paso's $3 billion revolving credit facility has a borrowing cost of
LIBOR plus 350 basis points, letter of credit fees of 350 basis points and
commitment fees of 75 basis points on unused amounts of the facility. This
facility replaced El Paso's previous $3 billion revolving credit facility.
Approximately $1 billion of El Paso's other financing arrangements were also
amended to conform the provisions of those obligations to El Paso's $3 billion
revolving credit facility. The $3 billion revolving credit facility and those
other financing arrangements are secured by our equity in ANR Pipeline Company
(ANR), Wyoming Interstate Company Ltd. (WIC), ANR Storage Company and our equity
in the companies that own the assets that collateralize the Clydesdale financing
arrangement discussed below.

In April 2003, El Paso removed us as a borrower under its $1 billion 3-year
revolving credit and competitive advance facility, which expired on August 4,
2003.

Consolidations

During the second quarter of 2003, El Paso amended several financing and
other agreements in connection with its new $3 billion revolving credit
agreement. These amendments were completed to accomplish several objectives,
including (i) simplifying its capital structure by eliminating several
"off-balance sheet" obligations and replacing them with direct obligations, and
(ii) strengthening the overall collateral package available to its financial
lenders. Of these amendments, one impacted us directly and is discussed below.

Aruba. We amended an operating lease at our Aruba facility to provide a
full guarantee to the parties who invested in the lessor and to allow the third
party and certain lenders to share in the collateral package that was provided
to the banks under El Paso's new $3 billion revolving credit facility. This
guarantee reduced the investor's risk of loss of its investment, resulting in
our controlling the lessor. As a result, we consolidated the lessor during the
second quarter of 2003, increasing our total property, plant and equipment by
$370 million (prior to an impairment charge we recorded on these assets of $50
million) and increasing our long-term debt by $370 million. As a result of our
intent to exit substantially all of our petroleum markets operations, these
leased assets and associated debt were reclassified as discontinued operations.

Long-Term Debt Obligations

During 2003, we have entered into and retired several debt financing
obligations:

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(1) Net proceeds were primarily used to repay maturing long-term debt, redeem
preferred interests of consolidated subsidiaries, repay short-term
borrowings and other financing obligations and for other general corporate
and investment purposes.

We reclassified $300 million of our mandatorily redeemable preferred
securities of Coastal Finance I to long-term debt as a result of the adoption of
SFAS No. 150 (see Notes 1 and 11).

14

Restrictive Covenants

We have entered into debt instruments and guaranty agreements that contain
covenants such as limitations on debt levels, limitations on liens securing debt
and guarantees, limitations on mergers and on sales of assets, capitalization
requirements and dividend limitations. A breach of any of these covenants could
potentially accelerate our debt and other financial obligations and that of our
subsidiaries.

One of the most significant debt covenants is that we must maintain a
minimum net worth of $850 million.

In addition, we have indentures associated with our public debt that
contain cross-acceleration provisions in the event of defaults greater than $5
million.

As part of El Paso's new $3 billion revolving credit facility, our
subsidiaries, ANR and, upon the maturity of El Paso's Clydesdale financing
transaction, Colorado Interstate Gas Company (CIG), cannot incur incremental
debt if the incurrence of this incremental debt would cause their debt to EBITDA
ratio (as defined in El Paso's new $3 billion revolving credit facility
agreement) for that particular company to exceed 5 to 1. Additionally, the
proceeds from the issuance of debt by the pipeline company borrowers can only be
used for maintenance and expansion capital expenditures or investments in other
FERC-regulated assets, to fund working capital requirements, or to refinance
existing debt. As of September 30, 2003, we were in compliance with these
covenants.

Other Financing Arrangements

The equity in some of our assets, along with other El Paso assets,
collateralize a financing arrangement established by El Paso referred to as
Clydesdale. In April 2003, El Paso restructured the Clydesdale financing
arrangement into a new term loan that amortizes in equal quarterly amounts of
$100 million, which began in May 2003, and El Paso guaranteed the third party
equity. These actions resulted in the consolidation of the term loan by El Paso
in the second quarter of 2003. The term loan remains collateralized by the
assets currently supporting the Clydesdale transaction, consisting of a
production payment from us, various natural gas and oil properties and our
equity in CIG. As of September 30, 2003, the balance on the Clydesdale term loan
was $521 million. In November 2003, El Paso made its quarterly payment of $100
million and retired an additional $7 million on this term loan.

11. PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

In May 1998, we formed Coastal Finance I, an indirect wholly owned business
trust, to generate funds for investment and general operating purposes. During
the third quarter of 2003, $300 million of our mandatorily redeemable preferred
securities outstanding was reclassified as a long-term debt on our balance sheet
as a result of the adoption of SFAS No. 150 (see Notes 1 and 10).

12. 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. Discovery is proceeding. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

15

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 natural gas working interest owners and natural 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,
attorneys' 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. Plaintiffs' motion for class
certification was denied on April 10, 2003. Plaintiffs' motion to file another
amended petition to narrow the proposed class to royalty owners in wells in
Kansas, Wyoming and Colorado was granted on July 28, 2003. Our costs and legal
exposure related to this lawsuit are not currently determinable.

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 ten such lawsuits in New
York, one in New Hampshire, one in Massachusetts, three in Connecticut and one
in Illinois. The plaintiffs generally seek remediation of their groundwater and
prevention of future contamination and a variety of compensatory damages as well
as punitive damages, attorney's fees, and court costs. In the case filed in
Illinois, certification of a national plaintiff's class of certain water
providers is requested. 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, 2003, we had approximately $33 million accrued for all
outstanding legal matters. Approximately $5 million of the accrual was related
to our discontinued operations.

Environmental Matters

We are subject to 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, 2003, we had accrued approximately $148 million for expected remediation
costs at current and former operated sites and associated onsite, offsite and
groundwater technical studies, which we anticipate incurring through 2027.
Approximately $50 million of the accrual was related to our discontinued
operations.

Our reserve estimates range from approximately $148 million to
approximately $251 million. Our accrual represents a combination of two
estimation methodologies. First, where the most likely outcome can be reasonably
estimated, that cost has been accrued ($46 million). Second, where the most
likely outcome cannot be estimated, a range of costs is established ($102
million to $205 million) and the lower end of the

16

range has been accrued. By type of site, our reserves are based on the following
estimates of reasonably possible outcomes.

Below is a reconciliation of our accrued liability as of September 30, 2003
(in millions):

Balance as of January 1, 2003...................................... $171
Additions/adjustments for remediation activities................... (2)
Payments for remediation activities................................ (21)
----
Balance as of September 30, 2003................................... $148
====

In addition, we expect to make capital expenditures for environmental
matters of approximately $199 million in the aggregate for the years 2003
through 2008. These expenditures primarily relate to compliance with clean air
regulations. For the remainder of 2003, we estimate that our total remediation
expenditures will be approximately $8 million.

Coastal Eagle Point. 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. The Orders allege
noncompliance with the New Jersey Air Pollution Control Act (the Act) pertaining
to excess emissions reported since 1998 by our Eagle Point refinery in
Westville, New Jersey. On February 24, 2003, EPA Region 2 issued a Compliance
Order alleging violations that included failure to monitor all components and
failure to timely repair leaking components. The alleged violations were
identified during a 1999 EPA audit of the Leak Detection and Repair program. Our
Eagle Point refinery resolved the claims of the United States and the State of
New Jersey in a Consent Decree on September 30, 2003, pursuant to the EPA's
refinery enforcement initiative. We agreed to pay a civil penalty of $1.25
million to the United States and $1.25 million to New Jersey. We will contribute
$1.0 million to an environmentally beneficial project near the refinery. Our
Eagle Point refinery will invest an estimated $3 to $7 million to upgrade the
plant's environmental controls by 2008. This settlement is subject to public
comment and court approval.

CERCLA Matters. We 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 26 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, 2003,
we have estimated our share of the remediation costs at these sites to be
between $5 million and $8 million. 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
estimating our liabilities. Accruals for these issues are included in the
previously indicated estimates for Superfund sites.

It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. 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

17

liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe our current
reserves are adequate.

Rates and Regulatory Matters

Marketing Affiliate NOPR. In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR) proposing 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. We have filed comments with the FERC addressing our
concerns with the proposed rules, participated in a public conference and filed
additional comments. 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 Policy. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that sought comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. We have entered into those 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 and other
issues related to negotiated rate programs. El Paso's pipelines and others filed
comments on the NOI.

In July 2003, the FERC issued an order that prospectively prohibits
pipelines from negotiating rates based upon natural gas commodity price indices
and imposes certain new filing requirements to ensure the transparency of
negotiated rate transactions. Requests for rehearing were filed on August 25,
2003 and remain pending. We do not expect the order on rehearing will have a
material effect on us.

Cash Management Rule. On October 23, 2003, the FERC approved a rule that
requires a FERC-regulated entity to file its cash management agreement with the
FERC, maintain records of transactions involving its participation in the cash
management program, compute its proprietary capital ratio quarterly based on
criteria established by the FERC, and notify the FERC 45 days after the end of a
calendar quarter whether its proprietary capital ratio falls below 30 percent
and subsequently when its proprietary capital ratio returns to or exceeds 30
percent. In the rule, the FERC stated that the requirements imposed by the rule
are not in the nature of a regulation governing participation in cash management
programs and that the rule does not dictate the content or terms for
participating in a cash management program. Although the rule is subject to
rehearing, we do not believe an order on rehearing will have a material effect
on us.

On September 10, 2003, the Office of Executive Director of Regulatory
Audits completed an industry-wide audit of the FERC Form 2 related to cash
management. The audit included our affiliates, El Paso Natural Gas Company
(EPNG) and Mojave Pipeline Company. The audit did not identify any instances of
non-compliance with the FERC's reporting and recording requirements but
recommended that both EPNG and Mojave revise and update their existing cash
management agreements with El Paso. Our other pipelines affiliates are in the
process of reviewing and revising their cash management agreements pursuant to
this recommendation.

Pipeline Safety Notice of Proposed Rulemaking. In January 2003, the U.S.
Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines, and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from the enactment of the Pipeline Safety Improvement Act
of 2002, a new bill signed into law in December 2002. Comments on the NOPR were
filed on April 30, 2003. Although we cannot predict the outcome of this
rulemaking, we do not expect the order to have a material effect on us.

FERC Inquiry. On February 26, 2003, El Paso received a letter from the
Office of the Chief Accountant at the FERC requesting details of its
announcement of 2003 asset sales and plans for ANR and our pipeline affiliate to
issue a combined $700 million of long-term notes. The letter requested that El
Paso

18

explain how it intended to use the proceeds from the issuance of the notes and
if the notes were to be included in El Paso's pipeline affiliates', including
ANR, capital structure for rate-setting purposes. El Paso's response to the FERC
was filed on March 12, 2003. On April 2, 2003, El Paso received an additional
request for information, to which we fully responded on April 15, 2003.

While the outcome of our outstanding legal matters, environmental matters,
and rates and regulatory matters cannot be predicted with certainty, based on
current information 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. However, it is possible that new
information or future developments could require us to reassess our potential
exposure related to these matters. It is possible that these matters could
impact our debt rating and credit rating. Further, for environmental matters, it
is 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
regarding 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, our financial
position, and our cash flows in the periods these events occur.

Other

Economic Conditions in the Dominican Republic. Recent developments in the
economic and financial situation in the Dominican Republic have led to a
devaluation of the Dominican peso of approximately 53 percent against the U.S.
dollar during 2003 (through September 30, 2003) and an increase in the local
inflation rate of approximately 25 percent for the same period. A stand-by
agreement with the International Monetary Fund (IMF) received final approval of
the IMF Board in August. The Dominican government maintains that the accord
could lead to approximately $1.2 billion in disbursements from multilaterals
over the next 24 months and will serve to restore consumer and investor
confidence in the banking system and economic policy framework, stabilize the
exchange rate and avoid a liquidity crisis. An initial disbursement of funds was
made in August 2003, but further disbursements are pending approval by the IMF.

We have investments in power projects in the Dominican Republic with an
aggregate exposure of approximately $100 million. We own a 48.33 percent
interest in a 67 megawatt heavy fuel oil fired power project known as the CEPP
project. We also own a 24.99 percent interest in a 513 megawatt power generating
complex known as Itabo. As a consequence of economic conditions described above,
and due to their inability to pass through higher energy prices to their
consumers, the local distribution companies that purchase the electrical output
of these facilities have been delinquent in their payments to CEPP and Itabo, as
well as the other generating facilities in the Dominican Republic since April
2003. The failure to pay generators has resulted in the inability of the
generators to purchase fuel required for the production of energy which has
caused significant energy shortfalls in the country. We currently believe that
the economic difficulties in the Dominican Republic will not have a material
adverse effect on our investments, but we will continue to monitor those
conditions and are working with the government and the local distribution
companies to resolve these issues.

Cases

The MTBE cases discussed above and filed in New York are: County of Suffolk
and Suffolk County Water Authority v. Amerada Hess Corp., et al., filed on
October 9, 2002, in the Supreme Court of the State of New York, County of
Suffolk, and the following eight cases filed on September 30, 2003 in the
Supreme Court of the State of New York, County of New York: County of Nassau v.
Amerada Hess, et al., Village of Mineola, Inc. and Water Dept. of the Village of
Mineola v. Atlantic Richfield, et al., West Hempstead Water District v. Atlantic
Richfield Co., et al., Carle Place Water District v. Atlantic Richfield Co., et
al., Town of Southampton v. Atlantic Richfield Co., et al., Village of Hempstead
v. Atlantic Richfield Co., et al., Town of East Hampton v. Atlantic Richfield
Co., et al., and Westbury Water District v. Atlantic Richfield Co., et al. The

19

tenth case Water Authority of Western Nassau v. Atlantic Richfield Co., et al.,
was filed on October 1, 2003 in the Supreme Court of the State of New York,
County of New York.

The MTBE case filed in New Hampshire is State of New Hampshire v. Amerada
Hess Corp. et al., filed in New Hampshire Superior Court, County of Merrimack,
on September 30, 2003.

The MTBE case filed in Massachusetts is Brimfield Housing Authority
(Brimfield, MA), et al. v. Amerada Hess Corporation, et al., filed in
Massachusetts Superior Court, County of Suffolk, on September 30, 2003.

The three MTBE cases filed in Connecticut are Childhood Memories v. Amerada
Hess Corporation, et al., filed in Connecticut Superior Court, Judicial District
of Litchfield, on September 30, 2003, Columbia Board of Education, Horace Porter
School v. Amerada Hess Corporation, et al., filed in Connecticut Superior Court,
Judicial District of Tolland, on September 30, 2003, and Canton Board of
Education, Cherry Brook School v. Amerada Hess Corporation, et al., filed in
Connecticut Superior Court, Judicial District of Hartford, on September 30,
2003.

The MTBE case filed in Illinois is Village of East Alton, Individually and
on behalf of all others similarly situated v. Amerada Hess Corporation, et al.,
filed in the Circuit Court, Third Judicial Circuit, Madison County, Illinois, on
September 30, 2003.

Commitments and Purchase Obligations

During 2003, we entered into purchase obligations to acquire pipe and other
equipment that will be used in our Cheyenne Plains Pipeline project. Our total
commitment is approximately $96 million and will be paid during 2004. El Paso
has guaranteed this purchase commitment.

13. SEGMENT INFORMATION

We segregate our business activities into four operating segments:
Pipelines, Production, Field Services and Merchant Energy. 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,
operational and marketing strategies. We reclassified our historical coal mining
operation in the second quarter of 2002 and our petroleum markets and chemical
operations in the second quarter of 2003 from our Merchant Energy segment to
discontinued operations in our financial statements. Merchant Energy's operating
results for all periods presented reflect this change.

We use earnings before interest expense and income taxes (EBIT) to assess
the operating results and effectiveness of our business segments. We define EBIT
as net income (loss) adjusted for (i) items that do not impact our income (loss)
from continuing operations, such as extraordinary items, discontinued operations
and the impact of accounting changes, (ii) income taxes, (iii) interest and debt
expense and (iv) distributions on preferred interests of consolidated
subsidiaries. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. We believe EBIT,
which includes the results of both these consolidated and unconsolidated
operations, is useful to our investors because it allows them to more
effectively evaluate the performance of all of our businesses and investments.
Also, we exclude interest and debt expense and distributions on preferred
interests of consolidated subsidiaries so that investors may evaluate our
operating results without regard to our financing methods or capital structure.
EBIT may not be comparable to measures used by other companies and should not be
used as a substitute for net income or

20

other performance measures such as operating income or operating cash flow. The
reconciliations of EBIT to income from continuing operations are presented
below:

The following tables reflect our segment results as of and for the periods
ended September 30 (in millions):

- ---------------
(1) Includes our Corporate and eliminations of intercompany transactions. Our
intersegment revenues, along with our intersegment operating expenses, were
incurred in the normal course of business 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) Relates to intercompany activities between our continuing operating segments
and our discontinued petroleum markets operations.

21

14. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS

We hold investments in affiliates which we account for using the equity
method of accounting. Summarized financial information of our proportionate
share of unconsolidated affiliates below includes affiliates in which we hold an
interest of 50 percent or less, and affiliates in which we hold a greater than
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 $2 million and $10 million for the
quarters ended, and $11 million and $28 million for the nine months ended
September 30, 2003 and 2002.

Our income statement reflects our earnings (losses) from unconsolidated
affiliates. This amount includes income or losses directly attributable to the
net income or loss of our equity investments as well as impairments and other
adjustments to income we record. For the quarter ended June 30, 2003, we
recorded impairment charges of $80 million related to our investments in Dauphin
Island Gathering Partners and Mobile Bay Processing Partners in our Field
Services segment due to our anticipation of incurring a loss from selling our
interests in these investments.

Related Party Transactions

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. See Note 12 for further
discussion on the FERC's Rule on Cash Management. As of September 30, 2003, and
December 31, 2002, we had borrowed $2,075 million and $2,374 million. The market
rate of interest as of September 30, 2003, and December 31, 2002, was 3.5% and
1.5%. In addition, we had a demand note receivable with El Paso of $232 million
and $199 million at September 30, 2003, and December 31, 2002. The interest rate
for this demand note receivable was 1.6% at September 30, 2003, and 2.2% at
December 31, 2002.

At September 30, 2003, and December 31, 2002, we had current accounts and
notes receivable from related parties of $243 million and $322 million. These
balances were incurred in the normal course of our business. In addition, we had
a non-current note receivable from a related party of $261 million and $126
million included in other non-current assets at September 30, 2003, and at
December 31, 2002.

At September 30, 2003, and December 31, 2002, we had other accounts payable
to related parties of $325 million and $87 million. These balances were incurred
in the normal course of business.

During the third quarter of 2003, we distributed $181 million of operating
cash to El Paso to reduce its obligations associated with the Clydesdale
financing arrangement. A portion of our operating units serve as collateral
under this arrangement. See Note 10 for a discussion of the Clydesdale financing
arrangement.

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

Also, in March 2002, 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. The proceeds exceeded the net book value by $32
million, and we recorded these proceeds as an increase to paid-in-capital.

23

We enter into a number of transactions with our unconsolidated affiliates
in the ordinary course of conducting our business. The following table shows
revenues, income and expenses incurred between us and our unconsolidated
affiliates and El Paso's subsidiaries:

15. NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

As of September 30, 2003, there were several accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.

Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51

In January 2003, the FASB issued FIN No. 46, Consolidation of Variable
Interest Entities, an Interpretation of ARB No. 51. This interpretation defines
a variable interest entity as a legal entity whose equity owners do not have
sufficient equity at risk and/or a controlling financial interest in the entity.
This standard requires a company to consolidate a variable interest entity if it
is allocated a majority of the entity's losses and/or returns, including fees
paid by the entity. On October 9, 2003, the FASB issued FASB Staff Position, FSP
FIN No. 46-6, Effective Date of FASB Interpretation No. 46, Consolidation of
Variable Interest Entities. This staff position deferred our required adoption
date of FIN No. 46 to the fourth quarter of 2003.

Upon adoption of this standard, we will be required to consolidate the
preferred equity holder of one of our consolidated subsidiaries, Coastal
Securities Company Limited. The impact of this consolidation will be an increase
in long-term debt and a decrease in preferred interests in consolidated
subsidiaries by $100 million. We also continue to evaluate our joint venture and
financing arrangements to assess the impact, if any, of FIN No. 46 on those
arrangements.

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 Current Report on Form 8-K dated
September 23, 2003, and the financial statements and notes presented in Item 1
of this Form 10-Q.

SEGMENT RESULTS

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 net income (loss) adjusted for (i) items that do not impact our income (loss)
from continuing operations, such as extraordinary items, discontinued operations
and the impact of accounting changes, (ii) income taxes, (iii) interest and debt
expense and (iv) distributions on preferred interests of consolidated
subsidiaries. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. We believe EBIT,
which includes the results of both these consolidated and unconsolidated
operations, is useful to our investors because it allows them to more
effectively evaluate the performance of all of our businesses and investments.
Also, we exclude interest and debt expense and distributions on preferred
interests of consolidated subsidiaries so that investors may evaluate our
operating results without regard to our financing methods or capital structure.
EBIT may not be comparable to measures used by other companies and should not be
used as a substitute for net income or other performance measures such as
operating income or operating cash flow. The following is a reconciliation of
our operating income to our EBIT and our EBIT to our net income (loss) for the
periods ended September 30:

25

OVERVIEW OF RESULTS OF OPERATIONS

Below are our results of operations (as measured by EBIT) by segment. Our
four operating segments -- Pipelines, Production, Field Services and Merchant
Energy -- provide a variety of energy products and services. They are managed
separately as each business unit requires different technology, operational and
marketing strategies. We reclassified our historical coal mining operation in
the second quarter of 2002 and our petroleum markets and chemical operations in
the second quarter of 2003 from our Merchant Energy segment to discontinued
operations in our financial statements. Merchant Energy's results for all
periods presented reflect this change. For a further discussion of charges and
other income and expense items impacting the results below, see Item 1, Notes 1
through 5 and 14.

PIPELINES

Our Pipelines segment owns and operates our interstate transmission
businesses. For a further discussion of the business activities of our Pipelines
segment, see our Current Report on Form 8-K dated September 23, 2003. Results of
our Pipelines segment operations were as follows for the periods ended September
30:

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

(1) Throughput volumes for the quarter and nine months ended September 30, 2002,
exclude 199 BBtu/d and 210 BBtu/d related to our equity investment in the
Alliance pipeline system which was sold. Throughput volumes also exclude
volumes transported between entities within the Pipelines segment. Prior
period volumes have been restated to reflect current year presentation which
includes billable transportation throughput volume for storage withdrawal.

Third Quarter 2003 Compared to Third Quarter 2002

Operating revenues for the quarter ended September 30, 2003, were $3
million lower than the same period in 2002. The decrease was due to $8 million
from lower natural gas recovered in excess of amounts used in operations, a $3
million reduction of Dakota gasification facility purchased gas resales
following a FERC approved contract buyout effective August 1, 2003 and $3
million of lower transportation and storage revenues due to contract changes.
These decreases were offset by $10 million from higher revenues due to completed

26

system expansions and new transportation contracts and an increase of $3 million
in gas processing revenues resulting from higher liquids prices.

Operating expenses for the quarter ended September 30, 2003, were $8
million lower than the same period in 2002. The decrease was due to lower gas
used for system supply requirements of $9 million and $2 million from lower
general and administrative costs in 2003. These decreases were offset by a net
increase of $3 million related to the FERC approved gas purchase contract buyout
related to the Dakota gasification facility and an increase of $2 million due to
favorable property tax adjustments recorded in 2002.

Other income for the quarter ended September 30, 2003, was $9 million lower
than the same period in 2002 due to lower equity earnings of $6 million
resulting from the sale of our interests in the Alliance pipeline system
completed in the first quarter of 2003 and $3 million from the favorable
resolution of uncertainties in 2002 associated with the 2001 sale of our
Gulfstream pipeline project.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Operating revenues for the nine months ended September 30, 2003, were $10
million higher than the same period in 2002. The increase was due to higher
revenues of $26 million due to completed system expansions and new
transportation contracts, $17 million from higher realized prices in 2003 on the
resale of natural gas purchased from the Dakota gasification facility which was
partially offset by $5 million from lower gas resales due to a FERC approved
buyout of the Dakota gas purchase contract effective August 1, 2003 and $11
million from higher prices on natural gas recovered in excess of amounts used in
operations. Also contributing to the increase was a $9 million increase in gas
processing revenues resulting from higher liquids prices and $7 million from
higher storage gas sales. These increases were partially offset by $48 million
from lower revenues due to CIG's sale of the Panhandle field and other
production properties in July 2002 and a $10 million decrease in transportation
and storage revenues due to contract changes.

Operating expenses for the nine months ended September 30, 2003, were $9
million lower than the same period in 2002. The decrease was due to a $27
million decrease in operating costs due to CIG's sale of Panhandle field and
other production properties in July 2002, additional accruals in the second
quarter of 2002 of $10 million on estimated liabilities to assess and remediate
our environmental exposure due to an ongoing evaluation of the exposure at our
facilities, a $9 million gain on the buyout of a gas purchase contract related
to the sale of CIG's Table Rock sulfur extraction facility and the sale of
non-pipeline assets in 2003 and lower gas used for system supply requirements of
$7 million. The decreases were offset by $16 million from higher prices on
natural gas purchased at the Dakota gasification facility along with the impact
of the FERC approved gas purchase contract buyout of $6 million which was
partially offset by $5 million from lower gas purchases following the
termination of the Dakota contract, an $11 million gain on the sale of pipeline
expansion rights in 2002, $7 million of favorable general and administrative
allocations adjustments received in 2002, lower benefit costs in 2002 of $6
million and a $2 million of favorable property tax adjustments recorded in 2002.

Other income for the nine months ended September 30, 2003, was $36 million
lower than the same period in 2002. The decrease was due to $16 million from
lower equity earnings resulting from the sale of our interest in the Alliance
pipeline system completed in the first quarter of 2003, $11 million from the
favorable resolution of uncertainties in 2002 associated with the sale of our
interests in the Iroquois and Empire State pipeline systems and Gulfstream
pipeline project in 2001 and $7 million from lower equity earnings from our
investment in Great Lakes primarily due to a favorable use tax settlement
recorded by Great Lakes in the first quarter of 2002.

27

PRODUCTION

Our 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 a low total cost level.

Since December 31, 2001, we have sold over 1.8 Tcfe of proved reserves in
multiple sales transactions with various third parties and our parent. The
cumulative amount of the reserves sold represented over 43 percent of our year
end 2001 total reserve base, and generated total cash proceeds of approximately
$1.5 billion. These sales were conducted as part of our parent's overall efforts
to reduce debt and improve its liquidity position. These sales, which included
proved developed producing reserves, combined with normal production declines,
mechanical failures on certain producing wells and higher finding and
development costs, have resulted in our total equivalent production levels
declining each quarter since the first quarter of 2002. For the first nine
months of 2003, our total equivalent production has declined approximately 97
Bcfe or 39 percent as compared to the same period in 2002. Future trends in
production will be dependent upon the amount of capital allocated to our
Production segment, the level of success in our drilling programs and any future
sales activities relating to our proved reserves.

As further described in our Current Report on Form 8-K dated September 23,
2003, Production has historically engaged in hedging activities on its natural
gas and oil production to stabilize cash flows and to reduce the risk of
downward commodity price movements on its sales. As of September 30, 2003, we
have hedged approximately 21 million MMBtu's of our remaining anticipated
natural gas production for 2003 at a NYMEX Henry Hub price of $3.71 per MMBtu
before regional price differentials and transportation costs.

Our depletion rate is determined under the full cost method of accounting.
We expect a higher depletion rate in future periods as a result of higher
finding and development costs experienced this year, coupled with a lower
reserve base due to the asset sales mentioned above. For the fourth quarter of
2003, we expect our domestic unit of production depletion rate to be
approximately $2.29 per Mcfe.

During the nine months ended September 30, 2003, we spent approximately
$682 million on capital expenditures. In October 2003, we entered into
agreements with a wholly owned subsidiary of Lehman Brothers (Lehman), an
investment bank, and a wholly owned subsidiary of Nabors Industries Ltd.
(Nabors) that will collectively result in an additional $160 million of drilling
activity over the next nine to 12 months. Lehman will contribute 50 percent of
an estimated $230 million total cost to develop a specified package of wells in
exchange for a 50 percent net profits interest (cash proceeds available after
royalties and operating costs have been paid), and Nabors will contribute 20
percent in exchange for a 20 percent net profits interest in such package of
wells. Once a specified payout is achieved, Lehman's and Nabors' net profits
interests will convert to an overriding royalty interest in the wells for the
remainder of the wells' productive lives. El Paso will contribute the remaining
30 percent of the $230 million of capital as part of its existing 2003 and 2004
capital budget. Under the terms of the agreements, all parties have a right to
cease further investment with 30 days notice.

As of January 1, 2003, our reserve estimates were prepared internally by
our Production segment and reviewed by Huddleston & Co., Inc. During the fourth
quarter of 2003, we appointed Ryder Scott Co. as our primary reservoir engineer.

28

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

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

(1) Includes production costs, depletion, depreciation and amortization, ceiling
test charges, asset impairments, gain and loss on long-lived assets, general
and administrative expenses and severance and other taxes.

(2) Prices are stated before transportation costs.

Third Quarter 2003 Compared to Third Quarter 2002

Operating revenues for the quarter ended September 30, 2003, were $42
million lower than the same period in 2002. Our natural gas revenues, including
the impact of hedges, were $44 million lower in the third quarter of 2003. Our
2003 natural gas production volumes decreased by 40 percent, resulting in an $84
million decrease in revenues versus the same period in 2002. Realized natural
gas prices rose in 2003 by 33 percent, resulting in a $40 million increase in
revenues when compared to the same period in 2002. The overall decline in
natural gas volumes was due to the sales of production properties in New Mexico,
Utah and western Canada as well as normal production declines and mechanical
failures in certain producing wells. Our oil, condensate and liquids revenues,
including the impact of hedges, were $1 million higher in the third quarter of
2003. Our 2003 oil, condensate and liquids volumes decreased by six percent,
resulting in a $3 million decrease in revenues versus the same period in 2002.
Realized oil, condensate and liquids prices rose in 2003 by 11 percent,
resulting in a $4 million increase in revenues when compared to the same period
in 2002. The declines in volumes were primarily due to the property sales,
production declines and mechanical failures mentioned above.

29

Transportation and net product costs for the quarter ended September 30,
2003, were $7 million lower than the same period in 2002 primarily due to a
lower percentage of gas volumes subject to transportation fees and lower fees
incurred in 2003 to meet minimum payments on pipeline agreements.

Operating expenses for the quarter ended September 30, 2003, were $6
million lower than the same period in 2002 primarily due to lower oilfield
service costs of $3 million, as a result of asset dispositions which reduced
labor and production processing fees, lower severance and other taxes of $6
million and lower general and administrative costs of $5 million. Partially
offsetting these decreases were higher depletion expense of $9 million which was
comprised of a $39 million increase due to higher depreciation, depletion and
amortization (DD&A) rates in 2003 and costs of $2 million related to the
accretion of our liability for asset retirement obligations in 2003, partially
offset by a $32 million decrease due to lower production volumes in 2003. The
higher depletion rate resulted from increased finding and development costs
coupled with a lower reserve base due to asset sales.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Operating revenues for the nine months ended September 30, 2003, were $234
million lower than the same period in 2002. Our natural gas revenues, including
the impact of hedges, were $231 million lower in 2003. Our 2003 natural gas
production volumes decreased by 42 percent, resulting in a $347 million decrease
in revenues versus the same period in 2002. Realized natural gas prices rose in
2003 by 24 percent, resulting in a $116 million increase in revenues when
compared to the same period in 2002. The decline in natural gas volumes was due
to the sales of production properties in Colorado, New Mexico, Utah, Texas, and
western Canada as well as normal production declines and mechanical failures on
certain producing wells. Our oil, condensate and liquids revenues, including the
impact of hedges, were $6 million lower in 2003. Our 2003 oil, condensate and
liquids volumes decreased by 28 percent, resulting in a $35 million decrease in
revenues versus the same period in 2002. Realized oil, condensate and liquids
prices rose in 2003 by 33 percent, resulting in a $29 million increase in
revenues when compared to the same period in 2002. The declines in volumes were
primarily due to the property sales, production declines and mechanical failures
mentioned above.

Transportation and net product costs for the nine months ended September
30, 2003, were $6 million lower than the same period in 2002 primarily due to a
lower percentage of gas volumes subject to transportation fees and lower fees
incurred in 2003 to meet minimum payments on pipeline agreements.

Operating expenses for the nine months ended September 30, 2003, were $297
million lower than the same period in 2002 primarily due to a 2002 non-cash full
cost ceiling test charge of $243 million for our international properties in
Canada, Brazil and Australia. Also contributing to the decrease were lower
oilfield service costs of $36 million, primarily due to asset dispositions which
resulted in lower labor and production processing fees, a $5 million gain in
2003 on the sales of non-full cost pool assets and lower general and
administrative costs of $8 million. Further decreasing expenses were lower
depletion expenses of $24 million, comprised of a $129 million decrease due to
lower production volumes in 2003, partially offset by a $97 million increase due
to higher DD&A rates in 2003 and costs of $8 million related to the accretion of
our liability for asset retirement obligations. The higher depletion rate in
2003 resulted from increased finding and development costs coupled with a lower
reserve base due to asset sales. Partially offsetting the decreases in expenses
were intangible asset impairments of $14 million in 2003 on non-full cost assets
in Canada and higher severance and other taxes of $5 million in 2003. The
increase in severance taxes was primarily due to tax credits taken in 2002 for
qualified natural gas wells.

FIELD SERVICES

Our Field Services segment conducts our midstream activities. In the second
quarter of 2003, we sold our midstream assets in the Mid-Continent region. These
assets primarily included our Greenwood, Hugoton, Keyes and Mocane natural gas
gathering systems, our Sturgis, Mocane and Lakin processing plants and our
processing arrangements at three additional processing plants. These assets
generated EBIT of approximately $10 million during the year ended December 31,
2002. Our remaining assets now consist primarily of our processing facilities in
the south Louisiana and Rocky Mountain regions.

30

As a result of our asset sales and the resulting decline in our gathering
and processing activities, our EBIT has decreased significantly. For a further
discussion of the business activities of our Field Services segment, see our
Current Report on Form 8-K dated September 23, 2003. Results of our Field
Services segment operations were as follows for the periods ended September 30:

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

(1) Gross margins consist of operating revenues less cost of products sold. We
believe this measurement is more meaningful for analyzing our Field Services
operating results because commodity costs play such a significant role in
the determination of profit from our midstream activities.

Third Quarter 2003 Compared to Third Quarter 2002

Total gross margins for the quarter ended September 30, 2003, were $11
million lower than the same period in 2002 primarily due to lower margins as a
result of the sales of our Natural Buttes and Ouray natural gas gathering
systems in December 2002, Wyoming gathering assets in January 2003, and
Mid-Continent gathering and processing assets in June 2003.

Operating expenses for the quarter ended September 30, 2003, were $7
million lower than the same period in 2002 primarily due to the asset sales
discussed above.

Other expenses for the quarter ended September 30, 2003, were $47 million
lower than the same period in 2002 due to a loss recorded in September 2002
related to the sale of our investment in the Aux Sable natural gas liquids
plant.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Total gross margins for the nine months ended September 30, 2003, were $24
million lower than the same period in 2002. The decrease was primarily due to
lower margins of $28 million as a result of the sales of our Dragon Trail
processing plant in May 2002, Natural Buttes and Ouray natural gas gathering
systems in December 2002, Wyoming gathering assets in January 2003, and
Mid-Continent gathering and processing assets in June 2003. Partially offsetting
this decrease was a $7 million increase in our south Louisiana processing
margins due to higher natural gas liquids prices and change in contract terms.

Operating expenses for the nine months ended September 30, 2003, were $26
million lower than the same period in 2002 primarily due to the asset sales
discussed above, resulting in lower operating costs and depreciation expenses of
$16 million and a net gain of $19 million from the sale of our Mid-Continent
midstream assets in the second quarter of 2003. The decreases were partially
offset by a $10 million gain in the second quarter of 2002 from the sale of our
Dragon Trail processing plant.

31

Other expenses for the nine months ended September 30, 2003, were $32
million higher than the same period in 2002 due to $80 million in impairment
charges on our Dauphin Island Gathering Partners and Mobile Bay Processing
Partners investments. The impairment was recorded based on an expected loss from
the anticipated sale of our interests in these investments. Partially offsetting
the increase was a loss of $47 million recorded in September 2002 related to the
sale of our investment in the Aux Sable natural gas liquids plant.

MERCHANT ENERGY

Our Merchant Energy segment primarily consists of global power operations,
which includes the ownership and operation of domestic and international power
generating facilities and our power restructuring activities. Our Current Report
on Form 8-K dated September 23, 2003, includes a description of the various
power activities included in our Merchant Energy segment. Historically, our
Merchant Energy segment also included our petroleum markets operations, but in
June 2003, El Paso's Board of Directors approved the sale of substantially all
of these operations. As a result, our petroleum markets operations were
reclassified as discontinued operations for all periods presented. For a further
discussion of our discontinued petroleum markets operations, see Item 1, Note 6.
Merchant Energy's operating results and an analysis of those results for the
periods ended September 30 are presented below:

In 2002, we restructured the power contracts of several of our power
plants, which resulted in significant gains in 2002 and reduced operating
revenues and expenses for those plants in 2003 because the plants were converted
to merchant plants, operating only when economically feasible. Upon
restructuring, we began recognizing changes in the fair value of the
restructured derivative contracts in our earnings rather than when the power
under the contracts was delivered. Going forward, the changes in fair value of
these restructured derivative contracts may cause volatility in our future
operating results. These restructured derivative contracts are significantly
impacted by changes in interest rates, which is more fully explained in Item 3,
Quantitative and Qualitative Disclosures About Market Risk. Due to a decline in
El Paso's credit rating in late 2002 and early 2003, we no longer pursue
additional power contract restructuring activities and are pursuing the sale of
our domestic power operations.

As we execute sales of our domestic power plants, results of operations
will increase or decrease from our current results based on the earnings and
timing of the potential sale of the respective plant or investment. In addition
to the earnings impact of the operations sold, a commitment to sell power plants
in the future may trigger an event that could result in impairment charges in
future periods.

Third Quarter 2003 Compared to Third Quarter 2002

Gross margin for our power activities consists of revenues from our power
plants and the net initial gains and losses incurred in connection with the
restructuring of power contracts, as well as the subsequent revenues, cost of
electricity purchases and changes in fair value of these contracts. The cost of
fuel in the power generation process is included in operating expenses. For the
quarter ended September 30, 2003, our gross margin was $16 million lower than
the same period in 2002. The decrease was primarily due to a $12 million
decrease in revenues from our Eagle Point merchant facility due to lower volumes
of power generated during 2003. The lower volumes resulted from mechanical
difficulties with one of the turbines used by the facility in

32

2003 and the decision to not fully operate the power plant on a merchant basis
due to lower demand and margins in 2003.

Operating expenses for the quarter ended September 30, 2003, were $7
million higher than the same period in 2002, primarily due to an impairment of a
crude oil pipeline of $10 million in 2003 due to a decline in the expected
reserves of a crude oil field from which the pipeline is used to transport crude
oil to a common gathering point. Also contributing to the increase was $6
million of costs to convert the Eagle Point merchant facility to allow for
operation in a merchant capacity in 2003. Offsetting these increases were $9
million of decreases primarily due to lower operating expenses from our Eagle
Point merchant facility resulting from lower volumes of power generated during
2003. The lower volumes resulted from mechanical difficulties with one of the
turbines used by the facility in 2003 and the decision to not fully operate the
power plant on a merchant basis due to lower demand and margins in 2003.

Other income (expense) for the quarter ended September 30, 2003, decreased
by $26 million compared to the same period in 2002. This decrease was primarily
due to a $13 million decrease in equity earnings in 2003 of one of our equity
investments that experienced a decline in the fair value of its derivative fuel
supply contracts. Also contributing to this decrease was $6 million of legal
fees related to arbitration proceedings on two of our Asian equity investments
in 2003.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

For the nine months ended September 30, 2003, our gross margin was $505
million lower than the same period in 2002. The decrease was primarily due to
$486 million of gains on power contract restructurings for our Eagle Point and
Nejapa power plants that we completed in 2002. Contributing to the decrease in
gross margin was a decrease of $77 million in 2003 power generation revenues
primarily due to mechanical difficulties with one of the turbines used by our
Eagle Point merchant facility in 2003 and the decision to not fully operate the
power plant on a merchant basis due to lower demand and margins in 2003.
Partially offsetting these decreases was a $72 million increase in gross margin
resulting from an increase in the fair values of our power restructuring
contracts in 2003 compared to a decrease in their fair values in 2002. This
increase resulted primarily from income accretion for the nine months in 2003
compared to six months in 2002 since the power contracts were restructured in
the first quarter of 2002.

Operating expenses for the nine months ended September 30, 2003, were $40
million lower than the same period in 2002. The decrease was primarily due to a
$33 million decrease in operating costs of our Eagle Point merchant facility
resulting from the decision to not fully operate the power plant on a merchant
basis due to lower demand and margins in 2003. Partially offsetting the decrease
was an impairment charge associated with a crude oil pipeline of $10 million in
2003 due to a decline in the expected reserves of a crude oil field from which
the pipeline is used to transport crude oil to a common gathering point.

Other income (expense) for the nine months ended September 30, 2003 was
$105 million higher than the same period in 2002. This increase is primarily due
to a $90 million contract termination fee we paid in 2002 to our petroleum
markets operations associated with the termination of a steam contract between
our Eagle Point power facility and the Eagle Point refinery (which is included
in our petroleum markets operations reflected in discontinued operations). Also
contributing to the increase was $50 million of minority owner's interest
primarily on the power contract restructurings for our Eagle Point and Nejapa
power plants that we completed in 2002. Partially offsetting this decrease was
$12 million of legal fees related to arbitration proceedings on two of our Asian
equity investments in 2003.

33

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter and nine months ended September
30, 2003, was $16 million and $24 million lower than the same periods in 2002.
Below is an analysis of our interest expense for the periods ended September 30:

Third Quarter 2003 Compared to Third Quarter 2002

Interest expense on long-term debt for the quarter ended September 30,
2003, was $15 million lower than the same period in 2002 primarily due to a $29
million reduction in interest due to the retirement of approximately $1.3
billion of long-term debt in 2002 and 2003 with an average interest rate of
6.90%. This decrease was partially offset by a $7 million increase in interest
related to ANR's March 2003 issuance of $300 million senior notes. In addition,
we experienced $6 million of interest due to the reclassification of $300
million of preferred securities as long-term debt in the third quarter as a
result of the adoption of a new accounting standard SFAS No. 150. See Note 1 for
a discussion of this accounting change.

Other interest for the quarter ended September 30, 2003, was $2 million
lower than the same period in 2002 primarily due to the retirement of our other
financing obligations.

Capitalized interest for the quarter ended September 30, 2003, was $1
million lower than the same period in 2002 primarily due to lower average
interest rates in the third quarter 2003 than the same period in 2002.

Nine Months Ended 2003 Compared to Nine Months Ended 2002

Interest expense on long-term debt for the nine months ended September 30,
2003, was $10 million lower than the same period in 2002 primarily due to a $67
million decrease in interest due to the retirement of approximately $1.7 billion
of long-term debt in 2002 and 2003 with an average interest rate of 6.50%. This
decrease was partially offset by a $37 million increase in interest from Utility
Contract Funding borrowed in July 2002 and Mohawk River Funding IV debt borrowed
in June 2002. These debts were borrowed for ongoing capital projects, investment
programs and operating requirements. Also offsetting the decrease was $15
million of additional interest related to ANR's March 2003 issuance of $300
million senior notes and $6 million of interest due to the reclassification of
$300 million of preferred securities as a result of the adoption of SFAS No.
150.

Other interest for the nine months ended September 30, 2003, was $18
million lower than the same period in 2002. The decrease was primarily due to a
$12 million reduction in interest resulting from the retirement of other
financing obligations and a $4 million decrease due to the reduction in our
power and trading activities in 2003.

Capitalized interest for the nine months ended September 30, 2003, was $4
million lower than the same period in 2002 primarily due to lower average
interest rates in 2003 than in 2002.

AFFILIATED INTEREST EXPENSE, NET

Affiliated interest expense, net for the quarter and nine months ended
September 30, 2003, was $11 million and $25 million, or $8 million and $16
million higher than the same periods in 2002. The increase was primarily due to
higher average advances payable to El Paso under our cash management program in
2003, partially offset by higher average short-term interest rates. The average
advances payable balance for the

34

third quarter increased from $1,126 million in 2002 to $2,113 million in 2003
and the average advances payable balance for the nine months increased from
$1,089 million in 2002 to $2,129 million in 2003. The average short-term
interest rates for the third quarter increased from 1.8% in 2002 to 1.9% in 2003
and the average short-term interest rate for the nine months decreased from 1.9%
in 2002 to 1.6% in 2003.

DISTRIBUTIONS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Distributions on preferred interests of consolidated subsidiaries for the
quarter and nine months ended September 30, 2003, were $6 million and $13
million lower than the same periods in 2002 primarily due to the redemptions of
our preferred interests in consolidated subsidiaries, including those related to
El Paso Oil & Gas Associates, Coastal Limited Ventures and El Paso Oil & Gas
Resources and due to the reclassification of our Coastal Finance I mandatorily
redeemable preferred securities to long-term debt as a result of the adoption of
SFAS No. 150. The decreases were also due to lower interest rates in 2003. Our
preferred distributions are based on variable short-term rates, which were lower
on average in 2003 than the same periods in 2002.

INCOME TAXES

Income taxes from continuing operations and our effective tax rates for the
periods ended September 30 were as follows:

Our effective tax rates were different than the statutory tax rate of 35
percent in 2003 primarily due to:

- state income taxes, net of federal income tax benefit;

- foreign income taxed at different rates; and

- abandonment of foreign investments.

Our effective tax rates were different than the statutory tax rate of 35
percent in 2002 primarily due to:

- state income taxes, net of federal income tax benefit; and

- foreign income taxed at different rates.

During the quarters and nine months ended September 30, 2003 and 2002, we
experienced a number of events that have impacted our overall effective tax rate
on continuing operations. These events included the treatment of our coal and
petroleum markets operations as discontinued operations (in which income taxes
are apportioned between continuing and discontinued operations) and the
abandonment of several foreign investments. These events, coupled with
relatively low pretax income in continuing operations, have caused, and may
continue to cause, variations in our effective tax rate.

DISCONTINUED OPERATIONS

During the nine months ended September 30, 2003, our after-tax loss from
discontinued operations was $1,187 million. During this period, we recorded
pre-tax charges of $1,366 million related to impairments of long-lived assets
and investments triggered by our decision to sell substantially all of our
petroleum markets business, approximately $929 million of which related to the
impairment of our Aruba refinery and approximately $252 million of which related
to the impairment of our Eagle Point refinery.

We also incurred $23 million of net losses on our refinery operations
during the nine months ended September 30, 2003 which included losses from our
Aruba refinery of $73 million and earnings from our Eagle Point refinery of $55
million. The Aruba refinery losses primarily related to lower throughput due to
35

significant turnaround maintenance activities during the third quarter of 2003.
We expect our Eagle Point refinery's volumes to be lower in the fourth quarter
of 2003 due to scheduled turnaround maintenance activities.

The income tax benefit related to discontinued operations for the nine
months ended September 30, 2003, was $229 million resulting in an effective tax
rate for discontinued operations of 16 percent. This effective rate was
different than the statutory rate of 35 percent primarily due to state income
taxes and foreign income taxed at different rates.

In the second quarter of 2003, we entered into a product offtake agreement
with Vitol S.A. Inc., for the sale of a number of the products produced at our
Aruba refinery. As a result of this contract, Vitol became the single largest
customer of our Aruba refinery, purchasing approximately 75 percent of the
products produced at that plant. The agreement is for one year with two one-year
extensions at Vitol's option. We have the right to terminate the agreement when
the refinery is sold.

COMMITMENTS AND CONTINGENCIES

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

NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

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

36

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

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 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 our Current Report on Form 8-K dated September 23,
2003, 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 Current Report on Form
8-K dated September 23, 2003, except as presented below:

MARKET RISK

We are exposed to a variety of market risks in the normal course of our
business activities, including commodity price, foreign exchange and interest
rate risks. We measure risks on the derivative and non-derivative contracts in
our portfolio on a daily basis using a Value-at-Risk model. We measure our
Value-at-Risk using a historical simulation technique, and we prepare it based
on a confidence level of 95 percent and a one-day holding period. This
Value-at-Risk was $3 million and $7 million as of September 30, 2003 and
December 31, 2002, and represents our potential one-day unfavorable impact on
the fair values of our contracts. These contracts primarily relate to our
petroleum markets business, which is included in discontinued operations. As we
liquidate our portfolio, our Value-at-Risk may vary from period to period.

INTEREST RATE RISK

As of September 30, 2003, our non-trading derivatives not designated as
hedges (see Item 1, Note 8) were comprised of $947 million of long-term power
purchase and power supply contracts. These contracts are associated with our
power contract restructuring activities and are valued using estimated future
market power prices and a discount rate that considers the appropriate U.S.
Treasury rate plus a credit spread specific to the contract's counterparty. We
make adjustments to this discount rate when we believe that market changes in
the rates result in changes in value that can be realized. Since September 30,
2002, in order to provide for market risk, we have not reflected the increase in
the value that would result from decreases in U.S. Treasury rates because we
believe the resulting increase in fair value of these non-trading derivatives
could not be realized in a current transaction between willing parties. Had we
reflected the actual U.S. Treasury yields as of September 30, 2003 in our
valuation, the value of our non-trading derivatives would have been higher by
approximately $102 million. Our exposure to changes in interest rates and credit
spreads has not been included in our Value-at-Risk calculation since these risks
are managed separately from the other derivative positions included in our
Value-at-Risk model. As of September 30, 2003, a ten percent increase or
decrease in the discount rate used to value these positions would result in a
change in the fair value of these derivative contracts of $(38) million and $40
million.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Controls and Procedures. Under the supervision and with the
participation of 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 (Disclosure Controls)
and

37

internal controls over financial reporting (Internal Controls) as of the end of
the period covered by this Quarterly Report pursuant to Rules 13a-15 and 15d-15
under the Securities Exchange Act of 1934 (Exchange Act).

Definition of Disclosure Controls and Internal Controls. Disclosure
Controls 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 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. Internal Controls are procedures
which are designed with the objective of providing reasonable assurance that (1)
our transactions are property authorized; (2) our assets are safeguarded against
unauthorized or improper use; and (3) our transactions are properly recorded and
reported, all to permit the preparation of our financial statements in
conformity with generally accepted accounting principles.

Limitations on the Effectiveness of Controls. El Paso CGP Company's
management, including the principal executive officer and principal financial
officer, does not expect that our Disclosure Controls and Internal Controls will
prevent all errors and all fraud. The design of a control system must reflect
the fact that there are resource constraints, and the benefits of controls must
be considered relative to their costs. Because of the inherent limitations in
all control systems, no evaluation of controls can provide absolute assurance
that all control issues and instances of fraud, if any, within the company have
been detected. These inherent limitations include the realities that judgments
in decision-making can be faulty, and that breakdowns can occur because of
simple errors or mistakes. Additionally, controls can be circumvented by the
individual acts of some persons, by collusion of two or more people, or by
management override of the controls. The design of any system of controls also
is based in part upon certain assumptions about the likelihood of future events.
Therefore, a control system, no matter how well conceived and operated, can
provide only reasonable, not absolute, assurance that the objectives of the
control system are met. Our Disclosure Controls and Internal Controls are
designed to provide such reasonable assurances of achieving our desired control
objectives, and our principal executive officer and principal financial officer
have concluded that our Disclosure Controls and Internal Controls are effective
in achieving that level of reasonable assurance.

No Significant Changes in Internal Controls. We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in El
Paso CGP Company's Internal Controls, or whether the company had identified any
acts of fraud involving personnel who have a significant role in El Paso CGP
Company's Internal Controls. This information was important both for the
controls evaluation generally and because the principal executive officer and
principal financial officer are required to disclose that information to our
Board's Audit Committee and our independent auditors and to report on related
matters in this section of the Quarterly Report. The principal executive officer
and principal financial officer note that there has not been any change in
Internal Controls during the period covered by this Quarterly Report that has
materially affected, or is reasonably likely to materially affect, Internal
Controls.

Effectiveness of Disclosure Controls. Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that the Disclosure Controls are effective to ensure that material information
relating to El Paso CGP Company and its consolidated subsidiaries is made known
to management, including the principal executive officer and principal financial
officer, on a timely basis.

Officer Certification. The certifications from the principal executive
officer and principal financial officer required under Sections 302 and 906 of
the Sarbanes-Oxley Act of 2002 have been included as Exhibits to this Quarterly
Report.

38

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS.

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

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

None.

ITEM 5. OTHER INFORMATION.

None.

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

39

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 12, 2003 /s/ D. DWIGHT SCOTT
------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer and Director
(Principal Financial Officer)

Date: November 12, 2003 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

40

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.