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 MARCH 31, 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 May 15, 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
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.

i

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 Form 10-K which includes a
summary of our significant accounting policies and other disclosures. The
financial statements as of March 31, 2003, and for the quarters ended March 31,
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, all of which are of a normal, recurring
nature (except for the items discussed below and in Notes 2 through 5), to
fairly present our interim period results. Due to the seasonal nature of our
businesses, information for interim periods may not indicate the results of
operations for the entire year. In addition, prior period information presented
in these financial statements includes reclassifications which were made to
conform to the current period presentation. These reclassifications have no
effect on our previously reported net income or stockholder's equity.

Significant Accounting Policies Update

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 asset is
depreciated over the remaining useful life of the long-lived asset to which that
liability relates. An ongoing expense is recognized for changes in the value of
the liability as a result of the passage of time, which we 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 $106 million
and non-current 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 the wells. We currently
forecast that these obligations will be met at various times over the next
twenty-four years, based on the expected natural gas and oil contained in the
wells and the estimated timing of plugging and abandoning the wells. The net
asset retirement liability as of January 1, 2003 and March 31, 2003, reported in
other non-current liabilities in our balance sheet, and the changes in the net
liability for the quarter ended March 31, 2003, were as follows (in millions):

Liability at January 1, 2003................................ $156
Liability settled in 2003................................... (25)
Accretion expense in 2003................................... 3
Other....................................................... (1)
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Net liability at March 31, 2003........................... $133
====

Had we adopted SFAS No. 143 as of January 1, 2002, our non-current
retirement liabilities would have been approximately $140 million as of January
1, 2002, and our income from continuing operations and net income for the
quarter ended March 31, 2002, would have been lower by $2 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

6

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 recognized
$7 million of employee severance costs, less income taxes of $2 million, in the
first quarter of 2003, all of which had been paid as of March 31, 2003. We
recorded these costs as operation and maintenance expenses in our income
statement and impacted the results in our Merchant Energy segment. 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 all
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 jurisdiction of the Federal
Energy Regulatory Commission (FERC) in accordance with the Natural Gas Act of
1938 and Natural Gas Policy Act of 1978. We discontinued the application of
regulatory accounting principles under Statement of Financial Accounting
Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of
Regulation in 1996. SFAS No. 71 provides that rate regulated enterprises account
for and report assets and liabilities consistent with the economic effect of the
way in which regulators establish rates, if those rates are designed to recover
the costs of providing the regulated service and if it is reasonable to assume
that those rates can be charged and collected. While our rates are designed to
recover our costs, our ability to extend or re-market expiring contracts is
highly dependent on competitive alternatives at the time these contracts are
extended or expire. Currently, a substantial portion of our revenues are under
contracts that are discounted at rates below the maximum rates. We will continue
to evaluate the application of regulatory accounting principles based on on-
going changes in the regulatory and economic environment and further actions in
current and future rate cases or settlements.

2. DIVESTITURES

During 2003, we completed or announced the sale of a number of assets as
part of El Paso Corporation's (El Paso) 2003 Operational and Financial Plan.
These sales transactions occurred in each of our business segments as follows:

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(1) Amounts do not include asset impairments recognized, if any, at the time we
decide to sell the asset. See Note 4 for a discussion of impairments taken
on long-lived assets.

(2) We did not recognize gains or losses on these completed sales of natural gas
and oil properties because individually they did not significantly alter the
relationship between capitalized costs and proved reserves at the time they
were sold.

(3) Sales that have been announced, but not completed, are subject to customary
regulatory approvals, final sale negotiations and other conditions and are
estimates.

(4) We have entered into a non-binding letter of intent to sell these assets for
estimated net proceeds of $250 million. In the first quarter of 2003, we
recognized an impairment of $350 million. See Note 4 for a discussion of
this impairment.

We evaluate potential asset sales each period 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 the Board of Directors is required to approve
asset dispositions greater than specified thresholds. Unless specific approval
is received by its Board of Directors or its designated subcommittee by the end
of the period to commit to a plan to sell an asset, we would not classify it as
held for sale or discontinued operations even if it is management's stated
intent to sell the asset. In our balance sheet we classified several long-lived
assets as held for sale, including Field Services' gathering systems located in
Wyoming and Merchant Energy's petroleum asphalt operations and lease crude
business and its Florida petroleum terminals and tug and barge operations. The
total assets held for sale had net book values in property, plant and equipment
of approximately $50 million as of March 31, 2003 and $134 million as of
December 31, 2002. These assets were classified as other current assets as of
March 31, 2003 and December 31, 2002, since we plan to sell them in the next
twelve months.

We continue to evaluate assets we may sell in the future. Recently, we
announced that we intend to pursue a sale of our Aruba refinery and domestic
power assets. These activities are in the early stages and no definitive
agreements have been received or approved by El Paso's management or Board of
Directors. We believe it is likely that a decision to sell these assets in the
current economic environment will result in future impairments or losses. The
amounts of the losses will be based on an estimate of the expected fair value of
the assets as determined by market data that becomes available to us as the
sales process proceeds. As of March 31, 2003, our net investment in the Aruba
refinery was approximately $1.2 billion (excluding the Aruba coker facility
which will have a carrying value, following its consolidation in the second
quarter of 2003, of $0.4 billion). See Note 8 for a discussion of our
consolidation of the Aruba coker facility.

In March 2002, we sold natural gas and oil properties to El Paso and to
third parties. Net proceeds from these sales were approximately $512 million. We
did not recognize a gain or loss on these sales because

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individually at the time these properties were sold these sales did not
significantly alter the relationship between capitalized costs and proved
reserves.

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 ended March 31, 2002, we recorded ceiling test charges of
$10 million for our Brazilian full cost pool, based upon the daily posted
natural gas and oil prices as of March 31, 2002, adjusted for oilfield or
natural gas gathering hub and wellhead price differences, as appropriate.

We use financial instruments to hedge against the volatility of natural gas
and oil prices. The impact of these hedges was considered in determining our
ceiling test charges and will be factored into future ceiling test calculations.
The charges for our international cost pools would not have changed had the
impact of these hedges not been included in calculating our first quarter
ceiling test charges since we do not significantly hedge our international
production activities.

4. GAIN (LOSS) ON LONG-LIVED ASSETS

Our gain (loss) on long-lived assets consists of net realized gains and
losses on sales of long-lived assets and impairments of long-lived assets.
During each of the quarters ended March 31, our gain (loss) on long-lived assets
was as follows:

Net Realized Gain

Our net realized gain on sales of long-lived assets for the quarters ended
March 31, 2003 and 2002, was $55 million and $11 million. Our 2003 gains were
primarily related to the sales of the Corpus Christi refinery and the Florida
petroleum terminals and tug and barge operations in our Merchant Energy segment.
See Note 2 for a further discussion of these divestitures. Our 2002 gains were
primarily related to the sale of pipeline expansion rights in our Pipelines
segment.

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 recoverable. One triggering event that may indicate an asset's carrying
amount may not be recoverable is the expectation that it is more likely than not
that we will sell or dispose of an asset before the end of its estimated useful
life. Based on our intentions as of March 31, 2003, that we will dispose of some
of our assets, we tested those assets for recoverability during the first
quarter of 2003 that we believed would be more likely than not be sold. As a
result of this assessment, we recognized an impairment of $350 million on our
Eagle Point refinery and several of our chemical assets in our Merchant Energy
segment. We also recorded impairment charges of approximately $9 million in the
first quarter of 2003 which related to non-full cost assets in Canada in our
Production segment.

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5. DISCONTINUED OPERATIONS

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.

Our coal mining operations have been classified in other current assets and
liabilities as discontinued operations in our financial statements for all
periods. The summarized financial results of discontinued operations were as
follows:

10

6. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

The following table summarizes the carrying value of our trading and
non-trading price risk management assets and liabilities as of March 31, 2003
and December 31, 2002:

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

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

Other derivatives include derivative contracts related to the power
restructuring activities of our consolidated subsidiaries of $967 million as of
March 31, 2003 and $968 million as of December 31, 2002. Of this amount, $882
million and $878 million relate to a power restructuring transaction at our
Eagle Point Cogeneration facility as of March 31, 2003 and December 31, 2002,
and $85 million and $90 million relate to a power restructuring transaction at
our Capitol District Energy Center Cogeneration Associates plant as of March 31,
2003 and December 31, 2002.

7. INVENTORY

Our inventory consisted of the following:

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

8. DEBT AND OTHER CREDIT FACILITIES

We had $371 million and $369 million of current maturities of long-term
debt at March 31, 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 in June 2005. This
facility replaces the previous $3 billion revolving credit facility. El Paso's
existing $1 billion revolving credit facility, which matures in August 2003, and
approximately $1 billion of other financing arrangements (including leases,
letters of credit

11

and other facilities) were also amended to conform El Paso's obligations to the
new $3 billion revolving credit facility. The $3 billion revolving credit
facility, $1 billion revolving credit facility, and the other financing
arrangements are collateralized, along with other assets of El Paso, by our
equity in ANR Pipeline Company (ANR), Wyoming Interstate Company, ANR Storage
Company and our equity in the companies that own the assets that collateralize
the Clydesdale financing arrangement.

Long-Term Debt Obligations

During the first quarter of 2003, we completed several debt financing
transactions related to our long-term debt 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, other financing obligations and for general corporate and
investment purposes.

Restrictive Covenants

We have entered into debt instruments and guaranty agreements that contain
covenants such as restrictions on debt levels, restrictions on liens securing
debt and guarantees, restrictions on mergers and on sales of assets,
capitalization requirements, dividend restrictions and cross-acceleration
provisions. A breach of any of these covenants could accelerate 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 agreements could be accelerated. The guaranty agreements also have a
$30 million cross-acceleration provision.

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

As part of El Paso's $3 billion revolving credit facility, our
subsidiaries, ANR and upon the maturity of the 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. The proceeds from the issuance of debt by
the pipeline company borrowers can be used only for maintenance and expansion
capital expenditures or investments in other FERC-regulated assets and to
refinance existing debt.

As mentioned above, we amended a number of other financing arrangements to
permit the execution of El Paso's $3 billion revolving credit facility. This
included amending an operating lease where El Paso provides a guarantee to the
lessor for the residual value of the facility that we lease. The amendments to
this operating lease included extending a full guarantee to all of the parties
who invested in the lessor, including the equity holder. As a result of the
amendments, we will be required to consolidate the lessor in the second quarter
of 2003. The operating lease impacted was for a facility at our Aruba refinery.

When we consolidate the lessor of this facility, the assets owned by the
lessor and the debt that supports the assets will be consolidated in our
financial statements. In addition, these assets, once consolidated, will be

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tested for impairment. Based on our preliminary analysis, we believe the impact
on our financial statements will be as follows (in millions):

Increase in total assets.................................... $370
Less: Impairment charge..................................... 20
----
Net increase in assets...................................... $350
====
Increase in long-term debt.................................. $370
====

Other Financing Arrangements

We collateralize, along with other El Paso assets, a financing arrangement
established by El Paso referred to as Clydesdale. In April 2003, El Paso
restructured the Clydesdale financing arrangement, and guaranteed the third
party equity. The amount of El Paso's obligation at March 31, 2003, was $761
million. In addition, this obligation was refinanced by El Paso in April 2003 as
a term loan that will amortize in equal quarterly amounts over the next two
years. 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.

9. 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.

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. 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

13

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.

Cimarron County. In January of 2003, one of our subsidiaries, CIG Field
Services Company (CIG), was named a defendant in a suit titled Patty Hiner, As
Duly Elected County Assessor, The Board of County Commissioners for Cimarron
County, Oklahoma v. CIG in Cimarron County District Court, alleging that in 1999
its agents falsely represented the value of its property to the Cimarron County
Property Tax Assessor. The plaintiffs seek compensatory and punitive damages.
The case has been removed to the United States District Court for the Western
District of Oklahoma. Plaintiff's motion to remand was denied. CIG Field
Services has filed a Motion to Dismiss. 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 March 31, 2003, we had approximately $33 million accrued for all
outstanding legal matters.

Environmental Matters

We are subject to extensive federal, state and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require us to remove or remedy the effect on the environment of the
disposal or release of specified substances at current and former operating
sites. As of March 31, 2003, we had accrued approximately $155 million,
including approximately $154 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. The high end of our reserve
estimates was approximately $227 million and the low end was approximately $135
million, and our accrual at March 31, 2003 was based on the estimated most
likely reasonable amount of liability. 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 March 31, 2003 (in
millions):

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 2003, we estimate that our total remediation expenditures will
be approximately $24 million. In addition, approximately $18 million of this
amount will be expended under

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government directed clean-up plans. The remaining $6 million will be
self-directed or in connection with facility closures.

Coastal Eagle Point. From May 1999 to March 2001, our Coastal Eagle Point
Oil Company received several Administrative Orders and Notices of Civil
Administrative Penalty Assessment from the New Jersey Department of
Environmental Protection (DEP). All of the assessments are related to alleged
noncompliance with the New Jersey Air Pollution Control Act pertaining to excess
emissions from the first quarter 1998 through the fourth quarter 2000 reported
by our Eagle Point refinery in Westville, New Jersey. The 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. 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.
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 26 active sites under the
Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or
state equivalents. We have sought to resolve our liability as a PRP at these
sites through indemnification by third parties and settlements which provide for
payment of our allocable share of remediation costs. As of March 31, 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
determining our estimated liabilities.

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

Rate Case. In March 2001, CIG filed a rate case with the Federal Energy
Regulatory Commission (FERC) proposing increased rates of $9 million annually
and new and enhanced services for its customers. In April 2001, CIG received an
order from the FERC, which suspended the rates subject to refund, and subject to
the outcome of hearing. On September 26, 2001, the FERC approved certain of its
new or enhanced services but rejected two firm services proposed in CIG's rate
filing and required it to reallocate the costs allocated to those two services
to existing services. CIG complied with this order and arranged with the
affected customers to provide service under existing rate schedules. CIG and its
customers entered into a settlement agreement in May 2002 settling all issues in
the case. The settlement, which contained a small rate increase, was approved by
the FERC, and became final in September 2002. The settlement obligates CIG to

15

file a new rate case to be effective no later than October 1, 2006. CIG paid
approximately $8 million, including interest, in customer refunds in November
2002. These refunds were included in accrued liabilities, and will not have an
adverse effect on our financial position or results of operations. On March 13,
2003, the FERC issued an order approving CIG's refund report.

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

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

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

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

Emergency Reconstruction of Interstate Natural Gas Facilities NOPR. On
January 17, 2003, FERC issued a NOPR proposing, in emergency situations, to (1)
expand the scope of construction activities authorized under a pipeline's
blanket certificate to allow replacement of mainline facilities; (2) authorize a
pipeline to commence reconstruction of the affected system without a waiting
period; and (3) authorize automatic approval of construction that would be above
the normal cost ceiling. Comments on the NOPR were filed on February 27, 2003.
At this time, we cannot predict the outcome of this rulemaking.

Pipeline Safety Notice of Proposed Rulemaking. On January 28, 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

16

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, and we fully responded to the request. On April 2, 2003, we received
an additional request for information, which we fully responded to 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.

10. 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. In the second quarter of 2002, we
reclassified our historical coal mining operations from our Merchant Energy
segment to discontinued operations in our financial statements. Merchant
Energy's results for the period ended March 31, 2002, were restated to reflect
this change.

We use earnings before interest expense and income taxes (EBIT) to assess
the operating results and effectiveness of our business segments. We define EBIT
as operating income, adjusted for several items, including: equity earnings from
unconsolidated affiliates, minority interests of consolidated, but less than
wholly owned operating subsidiaries and other miscellaneous non-operating items.
Items that are not included in this measure are financing costs, including
interest and debt expense, return on preferred interests of consolidated
subsidiaries, income taxes, discontinued operations and the impact of accounting
changes. We believe this measurement is useful to our investors because it
allows them to evaluate the effectiveness of our businesses and operations and
our investments from an operational perspective. This measurement may not be
comparable to measurements used by other companies and should not be used as a
substitute for net income

17

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:

The following are our segment results as of and for the quarters ended
March 31:

- ---------------
(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 take into account the adoption of a consensus
reached on 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.

18

Total assets by segment are presented below:

11. 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 a 50 percent or less, as well as those in which we hold a greater
than a 50 percent interest. Our proportional share of the net income of the
unconsolidated affiliates in which we hold a greater than 50 percent interest
was $8 million and $12 million for the quarters ended March 31, 2003 and 2002.

Great Lakes

We have a 50 percent ownership interest in the Great Lakes Gas Transmission
Limited Partnership. Great Lakes Gas Transmission owns and operates a 2,115 mile
interstate natural gas pipeline that transports gas to customers in the
midwestern and northwestern United States and Canada. Summarized financial
information of our proportionate share of Great Lakes Gas Transmission for the
quarters ended March 31, 2003 and 2002 are as follows:

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. As of March 31, 2003 and
December 31, 2002, we had borrowed $2,033 million and $2,374 million. The market
rate

19

of interest as of March 31, 2003 and December 31, 2002, was 1.3% and 1.5%. In
addition, we had a demand note receivable with El Paso of $199 million at both
March 31, 2003 and December 31, 2002. The interest rate for this demand note
receivable were 1.9% at March 31, 2003 and 2.2% at December 31, 2002.

At March 31, 2003 and December 31, 2002, we had current accounts and notes
receivable from related parties of $419 million and $346 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 $145 million and $126
million included in other non-current assets at March 31, 2003 and at December
31, 2002.

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

Additionally, we sold natural gas and oil properties to El Paso. Net
proceeds from these sales were $404 million, and we did not recognize a gain or
loss on the properties sold. The proceeds exceeded the net book value by $32
million and we recorded these proceeds as an increase to paid-in-capital.

At March 31, 2003 and December 31, 2002, we had other accounts payable to
related parties of $140 million and $87 million.

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 quarters ended March 31:

12. NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

In January 2003, the Financial Accounting Standards Board 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 that companies
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.

We currently have interests in and consolidate an entity in which third
party investors hold preferred interests. The preferred interests held by the
third party investors are reflected in our balance sheet as preferred interests
of consolidated subsidiaries. The third party investors are capitalized with
five percent equity, which is held by banks in these arrangements, and 95
percent debt. We believe we would consolidate these third party investors under
these arrangements because (i) the equity investment in these third party
investors is less than the specified 10 percent of total capitalization of the
investors and (ii) the rights of the third party investors to expected residual
returns from these arrangements is limited. When we consolidate these third
party investors, the minority interest that is currently classified as preferred
interests of consolidated subsidiaries will be classified as long-term debt. At
this time, we believe the holder of the preferred stock of our consolidated
subsidiary, Coastal Securities Company Limited, will be impacted by this
standard. We believe the impact on our financial statements as a result of
implementing this standard will be (in millions):

Decrease in preferred interests of consolidated
subsidiaries.............................................. $100
Increase in long-term debt.................................. $100

20

We have a number of other financial interests that would have been affected
by this standard, but as a result of actions taken during the first quarter of
2003, or actions we will take in the second quarter of 2003, including amending
and restructuring the underlying agreements, these financial interests will be
consolidated prior to our required adoption of this standard. The financial
interests affected by these actions include an operating lease with a residual
value guarantee for a facility at our Aruba refinery (see Note 8).

21

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, Financial
Statements, of this Form 10-Q.

SEGMENT RESULTS

We use earnings before interest and income taxes (EBIT) to assess the
operating results and effectiveness of our business segments. We define EBIT as
operating income, adjusted for several items, including: equity earnings from
unconsolidated affiliates, minority interests of consolidated, but less than
wholly owned operating subsidiaries and other miscellaneous non-operating items.
Items that are not included in this measure are financing costs, including
interest and debt expense, return on preferred interests of consolidated
subsidiaries, income taxes, discontinued operations and the impact of accounting
changes. The following is a reconciliation of our operating income to our EBIT
and our EBIT to our income (loss) from continuing operations for the quarters
ended March 31:

We believe EBIT is a useful measurement for our investors because it allows
them to evaluate the effectiveness of our businesses and operations and our
investments from an operational perspective. 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.

22

OVERVIEW OF RESULTS OF OPERATIONS

Below are our results of operations (as measured by EBIT), by segment for
the quarters ended March 31. A reconciliation of operating income to EBIT is
provided below for each 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. These
segment results include the impacts of asset impairments, gains and losses on
long-lived assets and other charges, which are discussed further in Item 1,
Financial Statements, Notes 3, 4, 5 and 11.

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 quarters ended March 31:

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

(1) Throughput volumes for 2002 exclude 224 BBtu/d related to the sale of our
equity interest in the Alliance pipeline system which was completed in March
2003. Throughput volumes also exclude intersegment activities. Prior period
volumes have been restated to reflect current year presentations, which
include billable transportation throughput volume for storage withdrawal.

Operating revenues for the quarter ended March 31, 2003, were $30 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 $18 million, $10 million from higher realized prices in 2003 on
the resale of natural gas purchased from the Dakota gasification facility, an
increase in transportation revenues of $5 million resulting from increased
throughput volumes as a result of colder winter weather, $4 million increase in
reservation revenues due to system expansion projects placed in service in the
latter part of 2002 and $4 million related to a rate settlement in 2003. Also
contributing to the increase were storage gas sales of $3 million which
commenced in the fourth quarter of 2002, an increase of $3 million in natural
gas liquids revenues resulting from higher prices and a $3 million increase in
reservation revenues due to an increase in contracted volumes on the WIC system.
These increases were partially offset by a $20 million decrease in revenues due
to CIG's sale of the Panhandle field and other production properties in July
2002.

Operating expenses for the quarter ended March 31, 2003, were $20 million
higher than the same period in 2002. The increase was due to an $11 million gain
on the sale of pipeline expansion rights in February 2002,

23

an increase of $9 million from higher prices on gas purchase from the Dakota
gasification facility, lower benefit costs in 2002 of $6 million and $4 million
from higher gas costs for our system supply purchases resulting from higher
natural gas prices and volumes in 2003. These increases were partially offset by
a $12 million decrease in operating expenses due to CIG's sale of Panhandle
field and other production properties in July 2002.

Other income for the quarter ended March 31, 2003, was $15 million lower
than the same period in 2002. The decrease was due to lower equity earnings of
$5 million from Alliance Pipeline due to the sale of our interests in the fourth
quarter 2002 and a charge of $4 million related to the partial termination of a
hedging obligation for Blue Lake Gas Storage Company, an investment in which we
have a 75 percent ownership interest. Also contributing to the decrease were
lower equity earnings of $4 million from our investment in Great Lakes Gas
Transmission due to a favorable sales and use tax settlement recorded in the
first quarter of 2002 and the resolution of uncertainties in 2002 of $3 million
associated with the sales of our interests in the Empire State pipeline system
and Gulfstream pipeline project in 2001.

PRODUCTION

Our Production segment conducts our natural gas and oil exploration and
production activities. For a further discussion of the business activities of
our Production segment, see our 2002 Form 10-K. Results of our Production
segment operations were as follows for the quarters ended March 31:

- ---------------
(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.

24

For the quarter ended March 31, 2003, operating revenues were $116 million
lower than the same period in 2002. Our natural gas revenues, including the
impact of hedges, were $123 million lower in the first quarter of 2003. Our 2003
natural gas volumes decreased by 49 percent, resulting in a $171 million
decrease in revenues, from the same period in 2002. Realized natural gas prices
rose in 2003 by 27 percent, resulting in a $48 million increase in revenues,
when compared to the same period in 2002. The declines in natural gas volumes
were due largely to the sale of properties in Colorado, Utah, Texas and western
Canada during 2002 as well as normal production declines. Our oil, condensate
and liquids revenues, including the impact of hedges, were $8 million higher in
the first quarter of 2003. Realized oil, condensate and liquids prices rose in
2003 by 88 percent, resulting in a $22 million increase in revenues, when
compared to the same period in 2002. Our 2003 oil, condensate and liquids
volumes decreased by 36 percent, resulting in a $14 million decrease in
revenues, from the same period in 2002. These declines were again due largely to
the sale of properties and normal declines mentioned above.

Operating expenses for the quarter ended March 31, 2003, were $55 million
lower than the same period in 2002. Depletion expense was lower by $34 million
comprised of a $62 million decrease due to lower production volumes in 2003,
partially offset by a $25 million increase resulting from higher depletion rates
in 2003 and costs of $3 million related to retirement obligations from our
adoption in 2003 of SFAS No. 143. The higher depletion rate resulted from higher
capitalized costs in the full cost pool coupled with a lower reserve base. Also
contributing to the decrease were a non-cash full cost ceiling test charge of
$10 million incurred in the first quarter of 2002 for our international
properties in Brazil, lower corporate overhead allocations of $5 million and
decreased oilfield service costs of $15 million primarily due to asset
dispositions which reduced labor and production processing fees. Partially
offsetting the decrease in expenses were asset impairments of $9 million related
to non-full cost assets in Canada.

FIELD SERVICES

Our Field Services segment conducts our midstream activities. In March
2003, we received approval to sell our assets in the Mid-Continent region. These
assets primarily include 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. We expect to
complete this sale by the end of the second quarter of 2003. These assets
generated EBIT of approximately $10 million during the year ended December 31,
2002. Once this sale is completed, our remaining assets will consist primarily
of our processing facilities in the south Texas, south Louisiana and Rocky
Mountain regions.

25

As a result of our asset sales and the resulting decline in our gathering
and treating activities, we expect our future EBIT to decrease considerably. 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 quarters ended March 31:

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

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

Total gross margins for the quarter ended March 31, 2003, were $1 million
higher than the same period in 2002. Gross margins increased by $9 million due
to higher natural gas prices and natural gas liquids prices in 2003, which
favorably impacted our margins and volumes in the south Louisiana and Rocky
Mountain regions. Partially offsetting these increases were $8 million of lower
margins resulting from the sales of our Dragon Trail processing plant in May
2002, Natural Buttes and Ouray natural gas gathering systems in December 2002
and Wyoming gathering assets in January 2003.

Operating expenses for the quarter ended March 31, 2003, were $5 million
lower than the same period in 2002. The decrease was primarily due to lower
operating and depreciation expense of $3 million resulting from the sales of
assets discussed above. Also contributing to this decrease were lower operating
and maintenance expenses as a result of our cost reduction plan initiated in
mid-2002.

26

MERCHANT ENERGY

Our Merchant Energy segment consists of two primary divisions: global power
and petroleum. Below are Merchant Energy's operating results and an analysis of
those results for the quarters ended March 31:

Global Power

Our global power division includes the ownership and operation of domestic
and international power generating facilities. El Paso announced in April 2003
its intent to potentially sell our domestic power generation facilities. In this
regard, we have commenced a process to sell most of our domestic power
generation facilities. For a further discussion of our global power division,
see our 2002 Form 10-K. Results of our global power division operations were as
follows for the quarters ended March 31:

Gross margin consists of revenues from our power plants and the net results
from our power restructuring activities. The cost of fuel used in the power
generation process is included in operating expenses. For the quarter ended
March 31, 2003, our gross margin was $414 million lower than the same period in
2002. The decrease was due primarily to a power contract restructuring for our
Eagle Point Cogeneration facility that we completed in the first quarter of
2002, which contributed $409 million to our gross margin in 2002, including an
$80 million loss on a power supply agreement that we entered into with El Paso
in the first quarter of 2002 associated with the Eagle Point Cogeneration
restructuring transaction. Also contributing to this decrease in gross margin
was a decrease of $33 million in 2003 power generation revenues primarily due to
the shutdown of our Eagle Point Cogeneration facility for maintenance in the
first quarter of 2003.

Operating expenses for the quarter ended March 31, 2003, were $22 million
lower than the same period in 2002. This decrease was primarily due to a $6
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.

27

Other income for the quarter ended March 31, 2003, was $143 million higher
than the same period in 2002. This increase was primarily due to a $90 million
contract termination fee we paid to our petroleum division associated with the
termination of a steam contract between our Eagle Point Cogeneration facility
and the Eagle Point refinery in 2002 that was eliminated from Merchant Energy's
consolidated results. Also contributing to this increase was $52 million of
minority interest expense recorded primarily on our power contract
restructurings during the first quarter of 2002.

Petroleum

El Paso announced in 2003 its intent to exit substantially all of our
petroleum businesses. El Paso also recently announced its intent to pursue the
sale of our Aruba refinery, in which we have a net investment of approximately
$1.2 billion, excluding an operating lease for a support facility that will be
consolidated in the second quarter of 2003. It is likely that if we pursue a
sale of Aruba in the near term, we will not recover our full investment and
could recognize an impairment or loss on the sale. For a further discussion of
our petroleum division, see our 2002 Form 10-K. Results of our petroleum
division operations were as follows for the quarters ended March 31:

Gross margin consists of revenues from our refineries and commodity trading
activities, less costs of the feedstocks used in the refining process and the
costs of commodities sold. For the quarter ended March 31, 2003, our gross
margin was $42 million higher than the same period in 2002. This increase
included higher refining margins of $37 million at our Aruba refinery due to
higher spreads between the sales prices of refined products and underlying
feedstock costs and $48 million at our Eagle Point refinery due to increased
processing volumes and higher spreads between the sales prices of refined
products and underlying feedstock costs. These increases were partially offset
by lower petroleum trading margins of $41 million on domestic crude and products
resulting from the decision to exit our petroleum-related trading operations
during 2003.

Operating expenses for the quarter ended March 31, 2003, were $328 million
higher than the same period in 2002. The increase was primarily due to a $350
million impairment of our Eagle Point refinery and our chemical assets in the
first quarter of 2003 resulting from our announced expectation that we will
dispose of these assets. Also contributing to this increase was a $28 million
increase in non-routine maintenance and other operating costs, primarily at our
Aruba facility, and $6 million of employee severance costs incurred in 2003.
Partially offsetting this increase was $56 million of net gains primarily from
the sale of our Corpus Christi refinery and Florida petroleum terminals and tug
and barge operations completed in 2003.

Other income for the quarter ended March 31, 2003, was $90 million lower
than the same period in 2002. This decrease was primarily due to a $90 million
contract termination fee we received from our global power division associated
with the termination of a steam contract between our Eagle Point refinery and
the Eagle Point Cogeneration facility in 2002, which was eliminated from
Merchant Energy's consolidated results.

CORPORATE AND OTHER

Corporate and other net expenses, which include general and administrative
activities and other miscellaneous businesses, for the quarter ended March 31,
2003, were $11 million lower than the same period in 2002. The decrease was
primarily due to a write-off of $6 million related to our environmental reserves
for Coastal Mart in 2002 as a result of the sale of substantially all of our
retail gas stations in the latter part of

28

2001. Also contributing to the decrease was a $2 million increase in interest
income related to a notes receivable from our unconsolidated subsidiaries during
the first quarter of 2003.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the quarter ended March 31, 2003, was $99
million, or $8 million lower than the same period in 2002. Below is the analysis
of our interest expense for the quarters ended March 31:

Interest expense on long-term debt for the quarter ended March 31, 2003,
was $1 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 the increase was $2 million of additional
interest related to the March issuance of $300 million ANR senior unsecured
notes. These increases were partially offset by $19 million decrease in interest
due to the retirement of approximately $1.2 billion of long-term debt in 2002
with an average interest rate of 6.7%.

Other interest for the quarter ended March 31, 2003, was $11 million lower
than the same period in 2002. The decrease was primarily due to $7 million
decrease resulting from the retirement of our other financing obligations, $2
million decrease in the factoring of receivables, and $2 million decrease due to
the termination of a marketing sales contract during 2002.

Capitalized interest for the quarter ended March 31, 2003, was $2 million
lower than the same period in 2002 primarily due to the lower interest rates in
the first quarter of 2003 than the same period in 2002.

AFFILIATED INTEREST EXPENSE, NET

Affiliated interest expense net for the quarter ended March 31, 2003, was
$7 million, or $4 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 first quarter
increased from $580 million in 2002 to $2,086 million in 2003. The average
short-term interest rates for the first quarter decreased from 1.9% in 2002 to
1.4% in 2003.

RETURN ON PREFERRED INTERESTS OF CONSOLIDATED SUBSIDIARIES

Return on preferred interests of consolidated subsidiaries for the quarter
ended March 31, 2003, was $3 million lower than the same period in 2002
primarily due to the redemption of all the preferred interests related to El
Paso Oil & Gas Resources, El Paso Oil & Gas Associates and Coastal Limited
Ventures in July 2002.

INCOME TAXES

Income tax benefit for the quarter ended March 31, 2003, was $18 million
resulting in an effective tax rate of 33 percent. Income tax expense for the
quarter ended March 31, 2002, was $202 million, resulting in an effective tax
rate of 33 percent. Our effective tax rates were different than the statutory
rate of 35 percent primarily due to the following:

- state income taxes; and

- foreign income taxed at different rates.

29

COMMITMENTS AND CONTINGENCIES

See Item 1, Financial Statements, Note 9, which is incorporated herein by
reference.

NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

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

30

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 (Internal Controls) within 90 days of the filing date of
this Quarterly Report pursuant to Rules 13a-15 and 15d-15 under the Securities
Exchange Act of 1934 (Exchange Act).

Definition of Disclosure Controls and Internal Controls. Disclosure
Controls are our controls and other procedures that are designed to ensure that
information required to be disclosed by us in the reports that we file or submit
under the Exchange Act is recorded, processed, summarized and reported, within
the time periods specified under the Exchange Act. Disclosure Controls include,
without limitation, controls and procedures designed to ensure that information
required to be disclosed by us in the reports that we file under the Exchange
Act is accumulated and communicated to our management, including our principal
executive officer and principal financial officer, as appropriate to allow
timely decisions regarding required disclosure. Internal Controls are procedures
which are designed with the objective of providing reasonable assurance that (1)
our transactions are property authorized; (2) our assets are safeguarded against
unauthorized or improper use; and (3) our transactions are properly recorded and
reported, all to permit the preparation of our financial statements in
conformity with generally accepted accounting principles.

Limitations on the Effectiveness of Controls. El Paso CGP Company's
management, including the principal executive officer and principal financial
officer, does not expect that our Disclosure Controls and Internal Controls will
prevent all errors and all fraud. 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. Further, 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, and there can be no assurance that any
design will succeed in achieving its stated goals under all potential future
conditions; over time, control may become inadequate because of changes in
conditions, or the degree of compliance with the policies or procedures may

31

deteriorate. Because of the inherent limitations in a cost-effective control
system, misstatements due to error or fraud may occur and not be detected.

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, from the date of the controls
evaluation to the date of this Quarterly Report, there have been no significant
changes in Internal Controls or in other factors that could significantly affect
Internal Controls, including any corrective actions with regard to significant
deficiencies and material weaknesses.

Effectiveness of Disclosure Controls. Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that, subject to the limitations discussed above, 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, particularly during
the period when our periodic reports are being prepared.

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 herein, or as Exhibits to this
Quarterly Report, as appropriate.

32

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

See Part I, Item 1, Financial Statements, Note 9, 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

33

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: May 15, 2003 /s/ D. DWIGHT SCOTT
------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer and Director
(Principal Financial Officer)

Date: May 15, 2003 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Principal Accounting Officer)

34

CERTIFICATION

I, Ronald L. Kuehn, Jr., certify that:

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

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

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

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

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

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

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

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

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

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

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ RONALD L. KUEHN, JR.
--------------------------------------
Ronald L. Kuehn, Jr.
Chairman of the Board and
Chief Executive Officer
(Principal Executive Officer)
El Paso CGP Company
Date: May 15, 2003

35

CERTIFICATION

I, D. Dwight Scott, certify that:

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

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

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

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

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

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

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

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

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

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

6. The registrant's other certifying officers and I have indicated in this
quarterly report whether there were significant changes in internal controls or
in other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ D. DWIGHT SCOTT
--------------------------------------
D. Dwight Scott
Executive Vice President and
Chief Financial Officer and Director
(Principal Financial Officer)
El Paso CGP Company
Date: May 15, 2003

36

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.