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 JUNE 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 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 August 14,
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
MBbls = thousand barrels
Mcf = thousand cubic feet
Mcfe = thousand cubic feet of gas equivalents
MMBtu = million British thermal units
MMcf = million cubic feet

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

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 2002 Annual Report on Form 10-K,
which includes a summary of our significant accounting policies and other
disclosures. The financial statements as of June 30, 2003, and for the quarters
and six months ended June 30, 2003 and 2002, are unaudited. We derived the
balance sheet as of December 31, 2002, from the audited balance sheet filed in
our 2002 Form 10-K. 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
indicate the 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 have no effect on our previously reported net income or
stockholder's equity.

Significant Accounting Policies

Our accounting policies are consistent with those discussed in our 2002
Form 10-K, except as follows:

Accounting for Asset Retirement Obligations. On January 1, 2003, we
adopted Statement of Financial Accounting Standard (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 non-current
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 June 30, 2003, reported in other
non-current liabilities in our balance sheet, and the changes in the net
liability for the six months ended June 30, 2003, were as follows (in millions):

Liability at January 1, 2003................................ $ 156
Liabilities settled in 2003................................. (27)
Accretion expense in 2003................................... 5
Liabilities incurred in 2003................................ 1
Changes in estimate......................................... (7)
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Net liability at June 30, 2003............................ $ 128
======

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 wells and the costs to do so. Had we adopted SFAS No. 143
as of January 1, 2002, our non-current retirement liabilities would have been
approximately $130 million as of

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January 1, 2002, and our income from continuing operations and net income for
the quarter and six months ended June 30, 2002, would have been lower by $2
million and $4 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 six months ended June 30, 2003, we recorded $2 million and $9
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.

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
guarantees, including financial performance and fair value guarantees, issued
after December 31, 2002, at their fair value when they are issued. There was no
initial financial statement impact of adopting this standard.

Accounting for Regulated Operations. Our natural gas pipelines are subject
to the regulations and accounting procedures 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 regulatory
accounting principles under SFAS No. 71, Accounting for the Effects of Certain
Types of Regulation. We continue to evaluate the application of SFAS No. 71 for
changes in the competitive environment and our operating cost structures. See a
further discussion of our accounting for regulated operations in our 2002 Form
10-K.

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 reflected below do not include any asset impairments we may have
recognized at the time we decided to sell the asset or investment. See Notes 4,
6 and 13 for a discussion of impairments on long-lived assets, assets treated as
discontinued operations and investments in unconsolidated affiliates.

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(1) Includes $61 million of net proceeds related to the working capital of the
assets sold. Working capital is reflected in cash flows from operating
activities rather than proceeds from asset sales.

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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)These sales were completed in July 2003.

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

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. The more
significant criteria we evaluate are whether:

- Management, with the authority to approve the sale, commits to a plan to
sell the asset;

- The asset is available for immediate sale in its present condition;

- An active program to locate a buyer and other actions required to
complete the sale have been started; and

- The sale of the asset is probable and is expected to be completed within
one year.

To the extent that all of these criteria as well as the other requirements
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
$64 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 June 30,
2003. We also had approximately $1.7 billion of assets classified as
discontinued operations. See a further discussion of our discontinued operations
in Note 6.

We continue to evaluate assets we may sell in the future. As specific
assets are identified for sale, 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 the 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 sales 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 our impairments
related to our discontinued operations, see Note 6; and for impairments on our
investments in unconsolidated affiliates, see Note 13.

In February 2002, we sold CIG Trailblazer Gas Company, L.L.C., a company
which owned pipeline expansion rights, to a third party. Our Pipelines segment
recorded a gain on this sale of approximately $11 million.

In March 2002, we sold natural gas and oil properties to El Paso and to
third parties. Net proceeds from these sales were approximately $500 million. We
did not recognize a gain or loss on these sales because we apply the full cost
method of accounting for our oil and natural gas operations (which requires that
gains or losses on property sales are only recognized in certain circumstances).

In May and June 2002, we completed sales of natural gas and oil properties,
a natural gas gathering system and a natural gas plant. Net proceeds from these
sales were approximately $325 million. We

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recognized a gain on long-lived assets of $10 million, $6 million after taxes,
on the natural gas gathering system and the plant.

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 quarter and six months ended June 30, 2003, our ceiling test
charges were less than $1 million. For the six months ended June 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 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. These write-downs were based upon the daily posted natural gas and
oil prices as of June 30, 2002, adjusted for oil field or natural gas gathering
hub and wellhead price differences, as appropriate. The 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, which was approximately $1.43 MMBtu.

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 our hedges not been included in calculating our 2002 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.

4. GAIN ON LONG-LIVED ASSETS

Our gain on long-lived assets from continuing operations 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 $987 million and $1.3 billion of asset
impairments for the quarter and six months ended June 30, 2003, related to
our petroleum 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 pipeline expansion rights in our Pipelines segment and
the sale of the Dragon Trail processing plant in our Field Services segment.

9

Asset Impairments

We are required to test assets for recoverability whenever events or
changes in circumstances indicate that the carrying amount of these assets may
not be fully recoverable. One triggering event 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 and
second quarters of 2003. As a result of these assessments, we recognized
impairments of $5 million in the second quarter of 2003 and $14 million for the
first six months of 2003 in our Production segment related to non-full cost
assets in Canada. For additional asset impairments on our discontinued
operations and investments in unconsolidated affiliates, see Notes 6 and 13.

5. OTHER EXPENSES

Other expenses for the quarter and six months ended June 30, 2002, were $8
million and $150 million. Included in other expenses for the six months ended
June 30, 2002 was a $90 million steam contract termination fee paid to our Eagle
Point refinery (in the petroleum division) by our Eagle Point Cogeneration
facility (in our global power division of our Merchant Energy segment) in the
first quarter of 2002. These amounts were eliminated in consolidation since the
income associated with the petroleum division is reflected in discontinued
operations while the power division's expense is included as part of our
Merchant Energy's segment results. In the first six months of 2002, other
expenses also included $52 million of minority interest in our consolidated
subsidiaries.

6. DISCONTINUED OPERATIONS

Petroleum Operations

In June 2003, El Paso's Board of Directors authorized the sale of
substantially all of our petroleum operations, including our Aruba refinery, our
Unilube blending operations, our domestic and international terminalling
facilities and our petrochemical and chemical plants. The Board's actions were
in addition to previous actions taken when they approved the sales of our Eagle
Point refinery, our asphalt 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 a pre-tax
charge of approximately $987 million during the second quarter of 2003 related
to our petroleum and chemical assets. This charge was in addition to the $350
million pre-tax impairment charge recognized during the first quarter of 2003
when El Paso announced its intent to sell our Eagle Point refinery and several
chemical assets. These impairments were based on a comparison of the carrying
value of the underlying 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 and our established time frame for completing the
sales, among other factors. Our petroleum operations and assets were
historically included in our Merchant Energy segment, and we reclassified these
assets and operations from Merchant Energy to discontinued operations for all
periods presented in these financial statements. We will also be required to
reflect these assets as discontinued operations in our annual periods that were
previously reported in our 2002 Form 10-K.

Of our second quarter 2003 impairment charge on our Aruba refinery,
approximately $50 million relates to a portion of the facility we lease under an
operating lease. During the second quarter, we amended this lease to provide a
full guarantee to all the parties who invested in the lessors. As a result, we
consolidated the lessor during the second quarter of 2003, increasing our total
fixed assets by $370 million (prior to impairment) and our long-term debt by
$370 million. As a result of El Paso's intent to exit substantially all of our
petroleum operations, these leased assets and associated debt were also
reclassified as discontinued operations. Our $50 million impairment charge was
based on the cost of these fixed assets relative to their estimated fair value.

In the second quarter of 2003, we entered into a product offtake agreement
for the sale of a number of the products produced at our Aruba refinery. As a
result of this contract, the buyer became the single largest customer of our
Aruba refinery, purchasing approximately 75 percent of the products produced at
that plant.

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The agreement is for one year with two one-year extensions at the buyer'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 our Board of Directors, we compared the carrying
value of the underlying assets to our estimated sales proceeds, net of estimated
selling costs, based on bids received in the sales process. Because this
carrying value was higher than our estimated net sales proceeds, we recorded an
impairment charge of $148 million in our total loss from discontinued operations
in the second quarter of 2002.

Our petroleum operations and our coal mining operations, which were
historically included in our Merchant Energy segment, have been reclassified as
discontinued operations in our financial statements for all of the historical
periods presented. We will also be required to reflect them as discontinued
operations for all historical annual periods previously reported in our 2002
Form 10-K. In addition, we reclassified all of the assets and liabilities of our
petroleum operations as of June 30, 2003 to other current assets and
liabilities. The summarized financial results and financial position data of
discontinued operations were as follows:

Operating Results

2002
Revenues......................................... $ 1,197 $101 $ 1,298
Costs and expenses............................... (1,261) (68) (1,329)
Gain (loss) on long-lived assets................. 2 (148) (146)
Other income (expense)........................... (2) 6 4
Interest and debt expense........................ (10) -- (10)
------- ---- -------
Loss before income taxes......................... (74) (109) (183)
Income taxes..................................... (25) (42) (67)
------- ---- -------
Loss from discontinued operations, net of income
taxes......................................... $ (49) $(67) $ (116)
======= ==== =======

2002
Revenues......................................... $ 2,062 $ 168 $ 2,230
Costs and expenses............................... (2,099) (164) (2,263)
Gain (loss) on long-lived assets................. 2 (148) (146)
Other income..................................... 94 6 100
Interest and debt expense........................ (13) -- (13)
------- ----- -------
Income (loss) before income taxes................ 46 (138) (92)
Income taxes..................................... 16 (52) (36)
------- ----- -------
Income (loss) from discontinued operations, net
of income taxes............................... $ 30 $ (86) $ (56)
======= ===== =======

Financial Position Data

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 one 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 June 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.

As of June 30, 2003, other derivatives include $960 million of derivative
contracts associated with 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 2002 Form 10-K.

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9. INVENTORY

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(1) As a result of El Paso's intent to dispose of our petroleum and chemical
assets, inventory balances totalling $435 million and $635 million as of
June 30, 2003 and December 31, 2002, have been reclassified as assets of
discontinued operations (see Note 6).
(2) We record these amounts as other non-current assets in our balance sheet.

10. DEBT AND OTHER CREDIT FACILITIES

We had $560 million and $369 million of current maturities of long-term
debt at June 30, 2003, and December 31, 2002.

Credit Facilities

In April 2003, El Paso removed us as a borrower under the $1 billion 3-year
revolving credit and competitive advance facility, and as such, we are no longer
jointly and severally liable for any amounts outstanding under that facility. In
addition, 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. This
facility replaces its previous $3 billion 364-day revolving credit facility. In
addition, approximately $1 billion of other financing arrangements were amended
to conform their obligations to the new $3 billion revolving credit facility.
The $3 billion revolving credit facility and these other financing arrangements
are collateralized, along with other assets of El Paso, including 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.

As of June 30, 2003, El Paso maintained a $1 billion revolving credit
facility, which expired on August 4, 2003.

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.

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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
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 $1.2 billion. If breached, the amounts guaranteed by the
guaranty agreement could be accelerated. The guaranty agreement also has a $30
million cross-acceleration provision.

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 $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 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 June 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 over the next two years, and 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.
El Paso repaid $100 million of this term loan in May 2003. As of June 30, 2003,
the balance owed to third parties under the Clydesdale financing arrangement was
$643 million. In August 2003, El Paso made a quarterly principal payment of $100
million on this term loan.

11. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

Grynberg. In 1997, a number of our subsidiaries were named defendants in
actions brought by Jack Grynberg on behalf of the U.S. Government under the
False Claims Act. Generally, these complaints allege an industry-wide conspiracy
to underreport the heating value as well as the volumes of the natural gas
produced from federal and Native American lands, which deprived the U.S.
Government of royalties. The plaintiff in this case seeks royalties that he
contends the government should have received had the volume and heating value of
natural gas produced from royalty properties been differently measured,
analyzed, calculated and reported, together with interest, treble damages, civil
penalties, expenses and future injunctive relief to require the defendants to
adopt allegedly appropriate gas measurement practices. No monetary relief has
been specified in this case. These matters have been consolidated for pretrial
purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court
for the District of Wyoming, filed June 1997). In May 2001, the court denied the
defendants' motions to dismiss. Discovery is proceeding. Our costs and legal
exposure related to these lawsuits and claims are not currently determinable.

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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,
attorney's fees, costs and expenses, and future injunctive relief to require the
defendants to adopt allegedly appropriate gas measurement practices. No monetary
relief has been specified in this case. 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 one such lawsuit in New
York. The plaintiffs seek remediation of their groundwater and prevention of
future contamination, compensatory damages for the costs of replacement water
and for diminished property values, as well as punitive damages, attorney's
fees, court costs, and, in some cases, future medical monitoring. Our costs and
legal exposure related to this lawsuit and claims are not currently
determinable.

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

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of June 30, 2003, we had approximately $31 million accrued for all
outstanding legal matters. Approximately $5 million of the accrual was related
to discontinued petroleum 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 June 30,
2003, we had accrued approximately $150 million, including approximately $149
million for expected remediation costs at current and former operated sites and
associated onsite, offsite and groundwater technical studies, and approximately
$1 million for related environmental legal costs, which we anticipate incurring
through 2027. Approximately $45 million of the accrual was related to
discontinued petroleum operations.

16

The high end of our reserve estimate was approximately $236 million and the
low end was approximately $139 million. The estimate of $139 million represents
a combination of two estimating methodologies. First, where the most likely
outcome can be reasonably estimated, that cost has been accrued ($44 million).
Second, where the more likely outcome cannot be estimated, a range of costs is
established ($95 million to $192 million) and the lower end of the 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 June 30, 2003 (in
millions):

Balance as of January 1, 2003............................... $171
Additions/adjustments for remediation activities............ (12)
Payments for remediation activities......................... (13)
Other changes, net.......................................... 4
----
Balance as of June 30, 2003................................. $150
====

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 $27 million.

Coastal Eagle Point. From May 1999 to March 2001, our Coastal Eagle Point
Oil Company received several Administrative Orders and Notices of Civil
Administrative Penalty Assessment from the New Jersey Department of
Environmental Protection (DEP). All of the assessments are related to alleged
noncompliance with the New Jersey Air Pollution Control Act (the Act) pertaining
to excess emissions from the first quarter 1998 through the fourth quarter 2000
reported by our Eagle Point refinery in Westville, New Jersey. The DEP has
assessed penalties totaling approximately $1.3 million for these alleged
violations. The DEP has indicated a willingness to accept a reduced penalty and
a supplemental environmental project. Our Eagle Point refinery has been granted
an administrative hearing on issues raised by the assessments. Subsequently DEP
assessed an additional $118,000 in penalties for alleged noncompliance with the
Act. On February 24, 2003, EPA Region 2 issued a Compliance Order based on a
1999 EPA inspection of the refinery's leak detection and repair (LDAR) program.
Alleged violations include failure to monitor all components, and failure to
timely repair leaking components. During an August 2000 follow-up inspection,
the EPA confirmed our Eagle Point refinery had improved its implementation of
the program. The Compliance Order requires documentation of compliance with the
program. We met with the EPA and DEP in March 2003 to discuss the Order and the
possibility for a global settlement pursuant to the EPA's refinery enforcement
initiative. Global settlements involving other refiners have included civil
penalties and addressed LDAR as well as new source review, the benzene standard,
and the standard for combustion of refinery fuel gas. On April 25, 2003, our
Eagle Point refinery sent a letter to the EPA committing to global settlement
discussions, which are ongoing. Our Eagle Point refinery expects to resolve both
the DEP assessments and the EPA refinery initiative issues.

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 27 active sites under the
Comprehensive Environmental Response, Compensation and Liability Act

17

(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 June 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 operating 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
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). The NOPR proposes to apply the standards of conduct
governing the relationship between interstate pipelines and marketing affiliates
to all energy affiliates. The proposed regulations, if adopted by the FERC,
would dictate how all our energy affiliates conduct business and interact with
our interstate pipelines. 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 modifications to its negotiated rate policy
applicable to interstate natural gas pipelines. The new policy has two primary
changes. First, the FERC will no longer permit the pricing of negotiated rates
based on natural gas commodity price indices, although it will permit current
contracts negotiated on that basis to continue until the end of the applicable
contract period. Second, the FERC is imposing new filing requirements on
pipelines to ensure the transparency of negotiated rate transactions.

Interim Rule on Cash Management. In August 2002, the FERC issued a NOPR
proposing, inter alia, that all cash management or money pool arrangements
between a FERC-regulated subsidiary and its non-FERC regulated parent be in
writing and that, as a condition of participating in such an arrangement, the
FERC-regulated entity maintain a minimum proprietary capital balance of 30
percent and both it and its parent maintain investment grade credit ratings.
After receiving written comments and hearing industry participants' concerns at
a public conference in September 2002, the FERC issued an Interim Rule on Cash
Management on June 26, 2003, which did not adopt the proposed limitations on
entry into or participating in cash management programs. Instead, the Interim
Rule requires natural gas companies to maintain up-to-date documentation
authorizing the establishment of the cash management programs in which they
participate and supporting all deposits into, borrowings and interest from, and
interest expense paid to such programs.

18

The Interim Rule also seeks comments on a proposed reporting requirement
that a FERC-regulated entity file cash management agreements and any changes
thereto within ten days and that it notify the Commission within five days when
its proprietary capital ratio falls below 30 percent (i.e., its long-term
debt-to-equity ratio rises above 70 percent) and when it subsequently returns to
or exceeds 30 percent. We filed comments on the Interim Rule on August 7, 2003.

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. At this time, we cannot predict the outcome of this
rulemaking.

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 us and our pipeline affiliates to
issue a combined $700 million of long-term notes. The letter requested that El
Paso explain how it intended to use the proceeds from the issuance of the notes
and if the notes will be included in the two regulated companies' capital
structure for rate-setting purposes. Our response to the FERC was filed on March
12, 2003. On April 2, 2003, we 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 also possible that these matters could
impact our debt rating and credit rating. Further, for environmental matters, it
is also possible that other developments, such as increasingly strict
environmental laws and regulations and claims for damages to property,
employees, other persons and the environment resulting from our current or past
operations, could result in substantial costs and liabilities in the future. As
new information 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 on our cash flows in the period the event occurs.

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 77 percent versus the U.S.
dollar since January 2003 (through June 30, 2003) and an increase in the local
inflation rate of approximately 25 percent for the same period. A stand-by
agreement with the IMF is expected to receive final approval of the IMF Board in
August. The Dominican government maintains that the accord, which should
hopefully lead to some $1.2 billion in disbursements from multilaterals over the
next 24 months, will serve to restore consumer and investor confidence,
stabilize the exchange rate and pave the way to economic recovery. The initial
disbursement of the funds is not anticipated until early September of 2003.

19

We have investments in power projects in the Dominican Republic with an
aggregate exposure, including financial guarantees, of approximately $104
million. We own a 48.33 percent interest in a 67 megawatt heavy fuel oil fired
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.

12. 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 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. 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. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. As a result, 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. This measurement may not be comparable to measurements used by
other companies and should not be used as a substitute for net income or other
performance measures such as operating income or operating cash flow. The
reconciliations of EBIT to income (loss) from continuing operations are
presented below:

20

The following tables reflect our segment results as of and for the periods
ended June 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) Merchant Energy revenues were restated on July 1, 2002 due to the adoption
of a consensus reached on Emerging Issues Task Force (EITF) Issue No. 02-3,
Issues Related to Accounting for Contracts Involved in Energy Trading and
Risk Management Activities, which requires us to report all physical sales
of energy commodities in our energy trading activities on a net basis as a
component of revenues. See our 2002 Form 10-K regarding the adoption of EITF
Issue No. 02-3.

21

Total assets by segment are presented below:

13. 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, as well as those 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 a greater than 50 percent interest
was $2 million and $6 million for the quarters ended, and $9 million and $18
million for the six months ended, June 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 the 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 11 for further
discussion on the FERC's Interim Rule on Cash Management. As of June 30, 2003,
and December 31, 2002, we had borrowed $1,602 million and $2,374 million. The
market rate of interest as of June 30, 2003, and December 31, 2002, was 1.3% and
1.5%. In addition, we had a demand note receivable with El Paso of $231 million
and $199 million at June 30, 2003, and December 31, 2002. The interest rate for
this demand note receivable was 1.8% at June 30, 2003, and 2.2% at December 31,
2002.

22

At June 30, 2003, and December 31, 2002, we had current accounts and notes
receivable from related parties of $300 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 $235 million and $126
million included in other non-current assets at June 30, 2003, and at December
31, 2002.

At June 30, 2003, and December 31, 2002, we had other accounts payable to
related parties of $96 million and $87 million. These balances were incurred in
the normal course of business.

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.

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 for the periods ended June 30:

14. NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

As of June 30, 2003, there were a number of 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.

Amendment of Statement 133 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 the interpretations of the
Derivatives Implementation Group (DIG) and also makes several minor
modifications to the definition of a derivative as it was defined in SFAS No.
133. SFAS No. 149 is effective for contracts entered into or modified after June
30, 2003. We do not believe there will be any initial impact of adopting this
standard.

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. The provisions of SFAS No. 150
are effective for all financial instruments entered into or modified after May
31, 2003, and otherwise is effective at the beginning of the first interim
period beginning July 1, 2003. Based on our preliminary assessment of the
standard, we believe its provisions will require us to reclassify our Coastal
Finance I preferred interests (currently classified as preferred interests of
consolidated subsidiaries) as liabilities beginning July 1, 2003. As of June 30,
2003, the Coastal Finance I balance was $300 million.

23

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. The provisions of FIN No. 46 are effective for all variable
interest entities created after January 31, 2003, and are effective on July 1,
2003, for all variable interest entities created before January 31, 2003.

Upon adoption of this standard on July 1, 2003, 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.

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 2002 Annual Report on Form 10-K
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. 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. Our business operations consist of both consolidated businesses as
well as substantial investments in unconsolidated affiliates. As a result, 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. This measurement may not be comparable to measurements used by
other companies and should not be used as a substitute for net income or other
performance measures such as operating 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 June 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 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 6 and 13.

PIPELINES

Our Pipelines segment holds our interstate transmission businesses. For a
further discussion of the business activities of our Pipelines segment, see our
2002 Form 10-K. Results of our Pipelines segment operations were as follows for
the periods ended June 30:

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

(1) Throughput volumes for the quarter and six months ended June 30, 2002,
exclude 208 BBtu/d and 216 BBtu/d related to our equity interest in the
Alliance pipeline system which was sold in November 2002 and March 2003.
Throughput volumes also exclude volumes transported between entities within
the Pipelines segment. Prior period volumes have been restated to reflect
current year presentations which includes billable transportation throughput
volume for storage withdrawal.

26

Second Quarter 2003 Compared to Second Quarter 2002

Operating revenues for the quarter ended June 30, 2003, were $15 million
lower than the same period in 2002. The decrease was primarily due to lower
revenues of $27 million due to CIG's sale of the Panhandle field and other
production properties in July 2002 and $7 million of lower storage revenues due
to the timing of revenues realized in 2003 versus 2002 and lower contracted
volumes partially offset by higher prices in 2003. These decreases were offset
by a $6 million increase due to completed system expansion projects and new
transportation contracts, $5 million from higher realized prices in 2003 on the
resale of natural gas purchased from the Dakota gasification facility, the
impact of higher prices in 2003 on natural gas recovered in excess of amounts
used in operations of $4 million, an increase of $2 million in liquid revenues
resulting from higher liquids prices and a $2 million increase in reservation
revenues due to an increase in contracted volumes on the WIC system.

Operating expenses for the quarter ended June 30, 2003, were $19 million
lower than the same period in 2002. The decrease was due to lower operating
expenses of $14 million due to CIG's sale of the 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 and 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. These decreases were offset by $7 million of
favorable corporate overhead allocations adjustments received in the second
quarter of 2002, volume adjustments related to one of CIG's storage fields of $5
million in 2003 and an increase of $4 million from higher prices on natural gas
purchases from the Dakota gasification facility.

Other income for the quarter ended June 30, 2003, was $12 million lower
than the same period in 2002. The decrease was due to lower equity earnings of
$6 million due to the sale of our interests in the Alliance pipeline system
completed in the first quarter of 2003 and the favorable resolution of
uncertainties associated with the 2002 sale of our interest in the Iroquois
pipeline system of $4 million.

Six Months Ended 2003 Compared to Six Months Ended 2002

Operating revenues for the six months ended June 30, 2003, were $13 million
higher than the same period in 2002. This increase was due to the impact of
higher prices in 2003 on natural gas recovered in excess of amounts used in
operations of $19 million, $14 million from higher realized prices in 2003 on
the resale of natural gas purchased from the Dakota gasification facility and a
$10 million increase due to completed system expansion projects and new
transportation contracts. Also contributing to the increase was a $6 million
increase in liquid revenues resulting from higher liquid prices, a $5 million
increase in reservation revenues due to an increase in contracted volumes on the
WIC system and a $5 million increase in transportation revenues due to higher
throughput volumes in 2003 as a result of colder winter weather. These increases
were partially offset by a $47 million decrease in revenues due to CIG's sale of
its Panhandle field and other production properties in July 2002.

Operating expenses for the six months ended June 30, 2003, were $1 million
lower than the same period in 2002. The decrease was due to a $26 million
decrease in operating costs resulting from CIG's sale of its 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 and 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. These decreases were offset by a $13 million
from higher prices on natural gas purchased at the Dakota gasification facility,
an $11 million gain on the sale of pipeline expansion rights in February 2002,
$7 million of favorable corporate overhead allocations adjustments received in
the second quarter of 2002, lower benefit costs in 2002 of $6 million and volume
adjustments related to one of CIG's storage fields of $5 million in 2003.

Other income for the six months ended June 30, 2003, was $27 million lower
than the same period in 2002. The decrease was due to lower equity earnings of
$11 million due to the sale of our interest in the Alliance Pipeline system
completed in the first quarter of 2003, the favorable resolution of
uncertainties in 2002 of $8 million associated with the sale of our interests in
the Iroquois and Empire State pipeline systems and the Gulfstream pipeline
project in 2001 and a charge of $4 million related to the partial termination of
a hedging obligation regarding Blue Lake Gas Storage Company in which we have a
75 percent ownership interest.

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 our ability to locate and develop economic natural gas and oil
reserves, extract those reserves with minimal production costs, sell the
products at attractive prices and operate at the lowest total cost level
possible.

As further described in our 2002 Form 10-K, 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 June 30, 2003, we have hedged approximately 42 million MMBtu's of
our remaining anticipated natural gas production for 2003 at a NYMEX Henry Hub
price of $4.36 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 in the first half of 2003, coupled
with a lower reserve base due to asset sales. For the third quarter of 2003, we
expect our domestic unit of production depletion rate to be approximately $2.17
per Mcfe.

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

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

(2) Prices are stated before transportation costs.

Second Quarter 2003 Compared to Second Quarter 2002

Operating revenues for the quarter ended June 30, 2003, were $76 million
lower than the same period in 2002. Our natural gas revenues, including the
impact of hedges, were $64 million lower in the second quarter of 2003. Our 2003
natural gas production volumes were lower by 33 percent, resulting in a $92
million

28

decrease in revenues, from the same period in 2002. Realized natural gas prices
rose in 2003 by 15 percent, resulting in a $28 million increase in revenues,
when compared to the same period in 2002. The overall decline in natural gas
volumes was due to 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 $15 million lower in the second quarter of
2003. Our 2003 oil, condensate and liquids volumes decreased by 37 percent,
resulting in a $17 million decrease in revenues, from the same period in 2002.
Realized oil, condensate and liquids prices rose in 2003 by 7 percent, resulting
in a $2 million increase in revenues, when compared to the same period in 2002.
The declines in volumes were primarily due to the property sales and production
declines mentioned above.

Operating expenses for the quarter ended June 30, 2003, were $236 million
lower than the same period in 2002 primarily due to a second quarter of 2002
non-cash full cost ceiling test charge of $233 million incurred primarily in our
Canadian full cost pool. Also contributing to the decreases were lower oilfield
service costs of $19 million primarily due to asset dispositions which resulted
in lower labor and production processing fees and a $5 million gain on the sales
of non-full cost pool assets. Partially offsetting these decreases were higher
depletion expenses of $2 million, comprised of a $34 million increase due to
higher depletion rates in 2003 and costs of $3 million related to the accretion
of our liability for asset retirement obligations, partially offset by a $35
million decrease due to lower production volumes in 2003. The higher depletion
rate resulted from higher capitalized costs in the full cost pool coupled with a
lower reserve base. In addition, these decreases were offset by higher corporate
overhead allocations of $3 million, higher severance and other taxes of $11
million in 2003 and intangible asset impairments of $5 million in 2003 related
to non-full cost assets in Canada. The increase in severance taxes was primarily
due to tax credits taken in 2002 for qualified natural gas wells.

Six Months Ended 2003 Compared to Six Months Ended 2002

Operating revenues for the six months ended June 30, 2003, were $192
million lower than the same period in 2002. Our natural gas revenues, including
the impact of hedges, were $187 million lower in 2003. Our 2003 natural gas
production volumes were lower by 42 percent, resulting in a $263 million
decrease in revenues, from the same period in 2002. Realized natural gas prices
rose in 2003 by 21 percent, resulting in a $76 million increase in revenues,
when compared to the same period in 2002. The decline in natural gas volumes was
due to 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 $7 million lower in 2003. Our 2003 oil, condensate and
liquids volumes decreased by 36 percent, resulting in a $31 million decrease in
revenues, from the same period in 2002. Realized oil, condensate and liquids
prices rose in 2003 by 44 percent, resulting in a $24 million increase in
revenues, when compared to the same period in 2002. The declines in volumes were
primarily due to the property sales and production declines mentioned above.

Operating expenses for the six months ended June 30, 2003, were $291
million lower than the same period in 2002 primarily due to a 2002 non-cash full
cost ceiling test charge of $243 million primarily for our Canadian full cost
pool. Also contributing to the decrease were lower oilfield service costs of $33
million primarily due to asset dispositions which resulted in lower labor and
production processing fees, a $5 million gain on the sales of non-full cost pool
assets and lower corporate overhead allocations of $2 million. Further
decreasing expenses were lower depletion expenses of $33 million comprised of a
$97 million decrease resulting from lower production volumes in 2003, partially
offset by a $58 million increase due to higher depletion rates in 2003 and costs
of $6 million related to the accretion of our liability for asset retirement
obligations. The higher depletion rate resulted from higher capitalized costs in
the full cost pool coupled with a lower reserve base. Partially offsetting the
decreases were higher severance and other taxes of $11 million and intangible
asset impairments of $14 million in 2003 on non-full cost assets in Canada. The
increase in severance taxes was primarily due to tax credits taken in 2002 for
qualified natural gas wells.

29

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.

As a result of our asset sales and the resulting decline in our gathering
and treating activities, our EBIT has decreased significantly. For a further
discussion of the business activities of our Field Services segment, see our
2002 Form 10-K. Results of our Field Services segment operations were as follows
for the periods ended June 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.

Second Quarter 2003 Compared to Second Quarter 2002

Total gross margins for the quarter ended June 30, 2003, were $14 million
lower than the same period in 2002. The decrease was primarily due to lower
margins of $11 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.

Operating expenses for the quarter ended June 30, 2003, were $14 million
lower than the same period in 2002 primarily due to the asset sales discussed
above, resulting in lower operating and depreciation expenses of $6 million and
a net gain of $19 million from the sale of our Mid-Continent midstream assets in
the second quarter of 2003. These decreases were partially offset by a $10
million gain in the second quarter of 2002 from the sale of our Dragon Trail
processing plant.

Other expense for the quarter ended June 30, 2003 included $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 interest in these investments.

30

Six Months Ended 2003 Compared to Six Months Ended 2002

Total gross margins for the six months ended June 30, 2003, were $13
million lower than the same period in 2002. The decrease was primarily due to
lower margins of $16 million as a result of 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 $6 million increase to our south Louisiana processing margins due to
higher natural gas liquids prices and change in contract terms.

Operating expenses for the six months ended June 30, 2003, were $19 million
lower than the same period in 2002 primarily due to the asset sales discussed
above, resulting in lower operating and depreciation expenses of $11 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.

Other expense for the six months ended June 30, 2003, included $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 interest in these investments.

MERCHANT ENERGY

Our Merchant Energy segment consists of two primary divisions: global power
and other. Historically, our Merchant Energy segment also included our petroleum
division. In June 2003, El Paso announced that its Board of Directors had
approved the sale of substantially all of our petroleum operations. As a result,
the petroleum operations were reclassified as discontinued operations for all
the historical periods presented. For a further discussion of our petroleum
operations, see Item 1, Note 6. Below are Merchant Energy's operating results
and an analysis of those results for the periods ended June 30:

31

Global Power

Our global power division includes the ownership and operation of domestic
and international power generating facilities. Our 2002 Form 10-K includes a
description of the various power activities included in global power. Due to a
decline in El Paso's credit rating in late 2002 and early 2003, we no longer
pursue power restructuring activities.

In 2002, we restructured 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,
which are significantly impacted by changes in interest rates, may cause
volatility in our future operating results.

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 sale of the respective plant or investment. In addition to the
earnings impact of the plant, a commitment to sell power plants in the future
may trigger an event that could result in impairment charges in future periods.

Results of our global power division were as follows for the periods ended
June 30:

Second Quarter 2003 Compared to Second Quarter 2002

Gross margin consists of revenues from our power plants and the net results
from our power restructuring activities. The cost of fuel in the power
generation process is included in operating expenses. For the quarter ended June
30, 2003, our gross margin was $60 million lower than the same period in 2002.
The decrease was primarily due to a $90 million gain recorded in 2002 on the
termination of a power purchase agreement at our Nejapa power facility and lower
power generation revenues of $27 million due to the partial shutdown of our
Eagle Point Cogeneration facility during the first six months of 2003 for
maintenance needed to convert the power plant to a merchant power plant.
Partially offsetting these decreases was an increase of $26 million due to the
increases in the fair values of our power restructuring contracts in 2003.

Operating expenses for the quarter ended June 30, 2003, were $25 million
lower than the same period in 2002. The decrease was primarily due to lower fuel
costs with our power plants of $14 million. Also, contributing to the decrease
was a $2 million decrease in operating costs related to the shutdown of our
Eagle Point Cogeneration facility for maintenance in 2003.

Six Months Ended 2003 Compared to Six Months Ended 2002

For the six months ended June 30, 2003, our gross margin was $475 million
lower than the same period in 2002. The decrease was primarily due to power
contract restructurings for our Eagle Point Cogeneration and Nejapa power plants
that we completed in 2002, which contributed $498 million to our gross margin in
2002, including an $80 million loss on a power supply agreement that we entered
into with E1 Paso in the first quarter of 2002 associated with the Eagle Point
Cogeneration restructuring transaction. The effects of this power supply
agreement were eliminated from Merchant Energy's consolidated results.
Contributing to the

32

decrease in gross margin was a decrease of $63 million in 2003 power generation
revenues primarily due to the partial shutdown of our Eagle Point Cogeneration
facility during the first six months of 2003 for maintenance needed to convert
the power plant to a merchant power plant. Partially offsetting these decreases
were increases in the fair values of our power restructuring contracts of $44
million during 2003.

Operating expenses for the six months ended June 30, 2003, were $47 million
lower than the same period in 2002. The decrease was primarily due to lower fuel
costs with our power plants of $23 million. Also contributing to the decrease is
a $8 million decrease in operating costs related to the shutdown of our Eagle
Point Cogeneration facility for maintenance in 2003 and a $6 million decrease in
depreciation expense in 2003 primarily due to lower depreciation on our Eagle
Point Cogeneration facility.

Other income for the six months ended June 30, 2003, was $139 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 division
associated with the termination of a steam contract between our Eagle Point
Cogeneration facility and the Eagle Point refinery (which is included in our
petroleum division reflected in discontinued operations). Also contributing to
this increase was $52 million of minority interest expense recorded primarily on
our power plant restructurings during 2002.

Other

Results of our other division were as follows for the periods ended June
30:

For the quarter and six months ended June 30, 2003, gross margin was $11
million and $14 million lower than the same period in 2002 primarily due to the
change in fair value of a gas supply derivative with El Paso Tennessee
Pipeline's trading division that was consolidated in late 2002.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter and six months ended June 30,
2003, was $4 million and $8 million lower than the same period in 2002. Below is
the analysis of our interest expense for the periods ended June 30:

Second Quarter 2003 Compared to Second Quarter 2002

Interest expense on long-term debt for the quarter ended June 30, 2003, was
$4 million higher than the same period in 2002 primarily due to a $19 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 contributing to

33

the increase was $5 million of additional interest related to ANR's March 2003
issuance of $300 million senior notes. These increases were partially offset by
a $19 million decrease in interest due to the retirement of approximately $1
billion of long-term debt in 2002 and 2003 with an average interest rate of
7.42%.

Other interest for the quarter ended June 30, 2003, was $10 million lower
than the same period in 2002. The decrease was primarily due to a $9 million
decrease in interest resulting from retirement of our other financing
obligations.

Capitalized interest for the quarter ended June 30, 2003, was $2 million
lower than the same period in 2002 primarily due to lower interest rates in the
second quarter 2003 than the same period in 2002.

Six Months Ended 2003 Compared to Six Months Ended 2002

Interest expense on long-term debt for the six months ended June 30, 2003,
was $5 million higher than the same period in 2002 primarily due to a $38
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 contributing to the increase was $7 million of additional
interest related to ANR's March 2003 issuance of $300 million senior notes.
These increases were partially offset by a $40 million decrease in interest due
to the retirement of approximately $1.4 billion of long-term debt in 2002 and
2003 with an average interest rate of 6.91%.

Other interest for the six months ended June 30, 2003, was $16 million
lower than the same period in 2002. The decrease was primarily due to a $13
million decrease in interest resulting from retirement of our other financing
obligations, a $2 million decrease in factoring of receivables and a $2 million
decrease in interest due to termination of a marketing sales contract during
2002.

Capitalized interest for the six months ended June 30, 2003, was $3 million
lower than the same period in 2002 primarily due to lower interest rates in 2003
than 2002.

AFFILIATED INTEREST EXPENSE, NET

Affiliated interest expense, net for quarter and six months ended June 30,
2003, was $7 million and $14 million, or $5 million and $8 million higher than
the same period 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 lower average short-term interest rates. The average advances payable
balance for the second quarter increased from $666 million in 2002 to $2,265
million in 2003 and the average advances payable balance for the six months
increased from $622 million in 2002 to $2,140 million in 2003. The average
short-term interest rates for the second quarter decreased from 1.9% in 2002 to
1.3% in 2003 and the average short-term interest rate for the six months
decreased from 1.9% in 2002 to 1.3% in 2003.

DISTRIBUTIONS ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Distributions on preferred interests of consolidated subsidiaries for the
quarter and six months ended June 30, 2003, were $4 million and $7 million lower
than the same periods in 2002 primarily due to the redemptions or elimination of
over $350 million of the preferred interests related to El Paso Oil & Gas
Associates, Coastal Limited Ventures and El Paso Oil & Gas Resources in July
2002.

INCOME TAXES

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

34

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

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

- foreign income taxed at different rates.

Additionally, income taxes from continuing operations for the quarter ended
June 30, 2003, include an adjustment to our estimated annual income tax rate as
a result of the reclassification of our petroleum business to discontinued
operations. This rate estimate adjustment caused us to record additional taxes
for the six month period that, when added to taxes on second quarter income,
resulted in the unusually high effective tax rate for the second quarter of
151%.

DISCONTINUED OPERATIONS

During the six months ended June 30, 2003, our after-tax loss from
discontinued operations was $1,138 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 businesses, approximately $929 million of which related to the second
quarter impairment of our Aruba refinery and approximately $252 million of which
related to the first quarter impairment of our Eagle Point refinery.

We also incurred losses on our refinery operations during the second
quarter of 2003 of $74 million, which primarily related to lower pricing in the
second quarter and lower crude throughput at our Aruba facility. Year to date
operating results for our refineries were slightly positive at $5 million.

The income tax benefit related to discontinued operations for the six
months ended June 30, 2003, was $226 million resulting in an effective tax rate
for discontinued operations of 17 percent. This effective rate was different
than the statutory rate of 35 percent primarily due to state income taxes and
foreign income taxes at different rates.

In the second quarter of 2003, we entered into a product offtake agreement
for the sale of a number of the products produced at our Aruba refinery. As a
result of this contract, the buyer 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 the
buyer's option. We have the right to terminate the agreement when the refinery
is sold.

COMMITMENTS AND CONTINGENCIES

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

NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

See Item 1, Note 14, which is incorporated herein by reference.

35

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 Part II, Item 7A in our Annual Report on Form 10-K for
the year ended December 31, 2002, 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 2002 Annual Report on
Form 10-K.

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 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.

36

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.

37

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

See Part I, Item 1, Note 11, 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

None.

38

SIGNATURES

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

EL PASO CGP COMPANY

Date: August 14, 2003 /s/ D. DWIGHT SCOTT
------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer and Director
(Principal Financial Officer)

Date: August 14, 2003 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

39

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.