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, 2002

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-7176

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

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

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

Telephone Number: (713) 420-2600

Indicate by check mark whether the Registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.

Common Stock, par value $1 per share. Shares outstanding on August 14,
2002: 1,000

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

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

EL PASO CGP COMPANY

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

See accompanying notes.

1

EL PASO CGP COMPANY

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

See accompanying notes.

2

EL PASO CGP COMPANY

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

See accompanying notes.

3

EL PASO CGP COMPANY

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

See accompanying notes.

4

EL PASO CGP COMPANY

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

See accompanying notes.

5

EL PASO CGP COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

1. BASIS OF PRESENTATION

We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the United States Securities and Exchange Commission. Because
this is an interim period filing presented using a condensed format, it does not
include all of the disclosures required by generally accepted accounting
principles. You should read it along with our 2001 Annual Report on Form 10-K
which includes a summary of our significant accounting policies and other
disclosures. The financial statements as of June 30, 2002, and for the quarters
and six months ended June 30, 2002 and 2001, are unaudited. We derived the
balance sheet as of December 31, 2001, from the audited balance sheet filed in
our Form 10-K. In our opinion, we have made all adjustments, all of which are of
a normal, recurring nature (except for the items discussed below and in Notes 3,
4, 6 and 7), to fairly present our interim period results. Due to the seasonal
nature of our businesses, information for interim periods may not indicate the
results of operations for the entire year. In addition, prior period information
presented in these financial statements includes reclassifications which were
made to conform to the current period presentation. These reclassifications have
no effect on our previously reported net income or stockholder's equity.

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

Goodwill and Other Intangible Assets

Our intangible assets consist primarily of goodwill resulting from
acquisitions. On January 1, 2002, we adopted Statement of Financial Accounting
Standards (SFAS) No. 141, Business Combinations, and SFAS No. 142, Goodwill and
Other Intangible Assets. These standards require that we recognize goodwill
separately from other intangible assets. In addition, goodwill and
indefinite-lived intangibles are no longer amortized. Instead, goodwill is
periodically tested for impairment, at least on an annual basis, or whenever an
event occurs that indicates that an impairment may have occurred. Prior to
adoption of these standards, we amortized goodwill and other intangibles using
the straight-line method over periods ranging from 5 to 40 years. We completed
our initial periodic impairment tests during the first quarter of 2002, and
concluded that we did not have any adjustment to our goodwill. Amortization of
goodwill would have been approximately $3 million and $6 million, net of income
taxes, for the quarter and six months ended June 30, 2002 had we not adopted
these standards. In addition, had we applied the amortization provisions of SFAS
No. 141 and 142 on January 1, 2001, we would have reported the following
amounts:

Asset Impairments

On January 1, 2002, we adopted SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. SFAS No. 144 changed the accounting
requirements related to when an asset qualifies as held for sale or as a
discontinued operation and the way in which we evaluate impairments of assets.
It also changes accounting for discontinued operations such that we can no
longer accrue future operating losses in these operations. We applied SFAS No.
144 in accounting for our coal mining operations, which met all of the
requirements to be treated as discontinued operations in the second quarter of
2002. See Note 6 for further information.

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Price Risk Management Activities

In the second quarter of 2002, we adopted Derivatives Implementation Group
(DIG) Issue No. C-15, Scope Exceptions: Normal Purchases and Sales Exception for
Certain Option-Type Contracts and Forward Contracts in Electricity. DIG Issue
C-15 requires that if an electric power contract includes terms that are based
upon market factors that are not related to the actual costs to generate the
power, the contract is a derivative that must be recorded at its fair value. An
example is a power sales contract at a natural gas-fired power plant that has
pricing indexed to the price of coal. Our adoption of these rules did not have a
material effect on our financial statements. The accounting for electric power
contracts as derivatives was not clearly addressed when SFAS No. 133, Accounting
for Derivatives and Hedging Activities, was adopted in January 2001. DIG Issue
No. C-15 and other DIG Issues have attempted to resolve inconsistencies in the
accounting for power contracts, and we believe the rules will continue to
evolve. It is possible that our accounting for these contracts may change as new
guidance is issued and existing rules are applied and interpreted.

In the second quarter of 2002, we also adopted DIG Issue No. C-16, Scope
Exceptions: Applying the Normal Purchases and Sales Exception to Contracts that
Combine a Forward Contract and Purchased Option Contract. DIG Issue C-16
requires that if a fixed-price fuel supply contract allows the buyer to
purchase, at their option, additional quantities at a fixed price, the contract
is a derivative that must be recorded at its fair value. One of our
unconsolidated affiliates, the Midland Cogeneration Venture Limited Partnership,
recognized a gain on fuel supply contracts upon adoption of these new rules, and
we recorded a gain of $14 million, net of income taxes, as a cumulative effect
of an accounting change in our income statement for our proportionate share of
this gain.

In June 2002, the Emerging Issues Task Force (EITF) reached a consensus in
EITF Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and
Risk Management Activities, requiring that all mark-to-market gains and losses
related to energy trading contracts, including physical settlements be recorded
in the income statement on a net basis instead of being reported on a gross
basis as revenues for physically settled sales and expenses for physically
settled purchases. We elected to adopt this consensus issue in the second
quarter, and now report our trading activity on a net basis as a component of
revenues. We have also applied this guidance to all prior periods, which had no
impact on previously reported net income or stockholder's equity. Revenues and
costs that have been netted as a result of adopting this consensus was as
follows:

The EITF continues to evaluate disclosure and valuation issues in its
continuing deliberations on Issue No. 02-3, and we will monitor and assess the
impact of adopting these issues when and if a consensus is reached.

Accounting for Power Restructuring Activities. Our Merchant Energy
segment's power restructuring activities involve amending or terminating a power
plant's existing power purchase contract to eliminate the requirement that the
plant provide power from its own generation to the regulated utility and
replacing that requirement with the ability to provide power to the utility from
the wholesale power market. Prior to a restructuring, the power plant and its
related power purchase contract are accounted for at their historical cost,
which is either the cost of construction or, if acquired, the acquisition cost.
Revenues and expenses prior to restructuring are, in most cases, accounted for
on an accrual basis as power is generated and sold to the utility. Following a
restructuring, the accounting treatment for the power purchase agreement changes
because the restructured contract must be marked to its fair value under SFAS
No. 133. In the period the restructuring is completed, the book value of the
restructured contract is adjusted to its fair value, with any change reflected
in
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income. Since the power plant no longer has the exclusive right to provide power
under the original, dedicated power purchase contract, it operates as a peaking
merchant plant, generating power only when it is economical to do so. Because of
this significant change in its use, in most cases the book value of the plant is
reduced to its fair value through a charge to earnings. These changes require us
to terminate or amend any related fuel supply and steam agreements associated
with the operations of the facility.

We completed the Eagle Point Cogeneration restructuring in the first
quarter of 2002. The restructured power contract is presented in our balance
sheet as an asset from price risk management activities, and the associated
power supply agreement is presented as a liability from price risk management
activities. In our income statement we present, as revenues, the original
adjustment that occurs when the contracts are marked to fair value as
derivatives, as well as subsequent changes in the value of the contracts. Other
costs associated with the restructuring activity, including adjustments to the
underlying power plant's book value and any related intangible assets, contract
termination fees and closing costs, are recorded in our income statement as
costs of products and services. Power restructuring activities can also involve
contract terminations that result in a cash payment by the utility to cancel the
underlying power contract. We employed the principles of our power restructuring
business in reaching a settlement of the dispute under our Nejapa power contract
which included a cash payment to us. We recorded this payment as revenue. During
the first six months of 2002, we recognized revenues from power restructuring
and contract termination activities of $973 million and corresponding costs of
$551 million, most of which occurred during the first quarter.

2. DIVESTITURES

In December 2001, El Paso Corporation (El Paso), our parent, announced a
plan to strengthen its balance sheet in order to improve the its liquidity in
response to changes in market conditions in our industry. A key component of
that plan was the identification and sale of assets.

In February 2002, we sold CIG Trailblazer Gas Company, L.L.C., a company
which owned pipeline expansion rights, to a third party. Proceeds from the sale
were $12 million, and we recorded a gain on the sale of approximately $11
million, $7 million after taxes.

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 the properties sold since they were not
significant in terms of the total costs or reserves in our full cost pool of
properties.

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 recognized a gain of $10 million, $6
million after taxes, on the natural gas gathering system and the plant. This
gain was recorded on our income statement in net gain on sale of assets.

Our parent also announced the sales of an additional $133 million of
assets, which include natural gas and oil production properties and related
contracts and a natural gas gathering system. In July 2002, we completed the
sale of the natural gas and oil production properties and related contracts. We
did not recognize a gain or loss on the properties sold since they were not
significant in terms of the total costs or reserves in our full cost pool of
properties.

In July 2002, our parent entered into a letter of intent with El Paso
Energy Partners, L.P., an affiliate, to sell our Typhoon offshore natural gas
and oil gathering pipelines, as well as natural gas liquids (NGL) pipelines and
a related fractionation facility in Texas. The Typhoon pipelines consist of a
35-mile, 20-inch natural gas pipeline and a 16-mile, 12-inch oil pipeline from
the Typhoon platform in the Green Canyon area of the Gulf of Mexico. We stopped
depreciating these assets beginning in July 2002 since these assets are held for
sale.

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3. MERGER-RELATED AND ASSET IMPAIRMENTS

Our merger-related costs and asset impairments for the periods ended June
30 consisted of the following:

Merger-Related Costs

On January 29, 2001, we merged with El Paso in a transaction that was
accounted for as a pooling of interests. The following are costs we incurred
related to the merger:

Employee severance, retention and transition costs include direct payments
to, and benefit costs for, terminated employees and early retirees that occurred
as a result of our merger-related workforce reduction and consolidation.
Following the merger, El Paso completed an employee restructuring across all of
our operating segments, reducing approximately 3,200 full-time positions through
a combination of early retirements and terminations. Employee severance costs
include severance payments and costs for pension and post-retirement benefits
settled and curtailed under existing benefit plans as a result of this
restructuring. Retention charges include payments to employees who were retained
following the merger and payments to employees to satisfy contractual
obligations. Transition costs relate to costs to relocate employees and costs
for terminated and retired employees arising after their severance date to
transition their job responsibility to the ongoing workforce. The amount of
employee severance, retention and transition costs paid and charged against the
accrued amount for the six months ended June 30, 2001, was approximately $87
million. The pension and post-retirement benefits were accrued on the merger
date and will be paid over the applicable benefit periods of the terminated and
retired employees. The rest of the charges were paid during the remainder of
2001.

Also included in employee severance, retention and transition costs for the
six months ended June 30, 2001, was a charge of $278 million resulting from the
issuance of approximately 4 million shares of El Paso common stock incurred on
the merger date in exchange for the fair value of our employees' and directors'
stock options.

Transaction costs include investment banking, legal, accounting, consulting
and other advisory fees incurred to obtain federal and state regulatory
approvals and take other actions necessary to complete our merger. All of these
items were expensed as incurred.

Business and operational integration costs include charges to consolidate
facilities and operations of our business segments, such as lease termination
and abandonment charges and incremental fees under software and seismic license
agreements. These charges were accrued at the time we completed our relocations
and closed these offices. The amounts accrued will be paid over the term of the
applicable non-cancelable lease agreement. All other costs were expensed as
incurred.

9

Merger-related asset impairments relate to write-offs or write-downs of
capitalized costs for duplicate systems, and facilities and assets whose value
was impaired as a result of decisions on the strategic direction of our combined
operations following the merger. These charges occurred in our Merchant Energy,
Pipeline, and Production segments, and all of these assets have either had their
operations suspended or continue to be held for use. The charges taken were
based on a comparison of the cost of the assets to their estimated fair value to
the ongoing operations based on the change in operating strategy.

Other costs include payments made in satisfaction of obligations arising
from the Federal Trade Commission (FTC) approval of our merger with El Paso and
other miscellaneous charges. These items were expensed as incurred.

Asset Impairments

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

4. CHANGES IN ACCOUNTING ESTIMATES

Included in our operation and maintenance costs for the quarter and six
months ended June 30, 2001, were approximately $203 million in costs related to
changes in estimates. They consist of $159 million of additional environmental
remediation liabilities and a $44 million charge to reduce the value of our
spare parts inventories to reflect changes in the usability of these parts in
our worldwide operations. Both charges arose as a result of an ongoing
evaluation of our operating standards and plans following our merger with El
Paso and our combined operating strategy. These changes in estimates reduced our
after-tax earnings by approximately $135 million.

5. CEILING TEST CHARGES

Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to evaluate 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. As of 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 write-down includes $226 million for our
Canadian full cost pool, $10 million for our Brazilian full cost pool and $7
million for other international production operations. The charge for the
Canadian full cost pool primarily resulted from a low daily posted price for
natural gas at the end of the second quarter, which was approximately $1.43 per
million British thermal units.

We use financial instruments to hedge against volatility of natural gas and
oil prices. The impact of these hedges was considered in determining our 2002
ceiling test charge, and will be factored into future ceiling test calculations.
Had the impact of our hedges not been included in calculating our 2002 ceiling
test charge, the charge for our international cost pools would not have
materially changed 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.

6. DISCONTINUED OPERATIONS

In June 2002, our parent's Board of Directors authorized the sale of our
coal mining operations. Those operations, which have historically been included
in the operations of our Merchant Energy segment, consist of fifteen active
underground and two surface mines located in Kentucky, Virginia and West
Virginia. We expect to complete the sale of these operations before the end of
2002. Following authorization of the sale by our parent's Board of Directors, we
compared the carrying value of the underlying assets to our estimated sales
proceeds, net of estimated selling costs, based on bids received in the sales
process. Because this carrying value was higher than our estimated net sales
proceeds, we recorded a charge of $148 million, which has been included in our
total loss from discontinued operations in the second quarter of 2002.

10

Our coal mining operations have been classified as discontinued operations
in our financial statements for all periods presented. In addition, we
reclassified all of the assets and liabilities of our coal mining operations as
of June 30, 2002, as current assets and liabilities because we plan to sell them
in the next twelve months. The summarized financial results of discontinued
operations are as follows:

7. EXTRAORDINARY ITEMS

Under an FTC order, as a result of our January 2001 merger with El Paso, we
sold our Gulfstream pipeline project, our 50 percent interest in the Stingray
and U-T Offshore pipeline systems, and our investments in the Empire State and
Iroquois pipeline systems. For the quarter and six months ended June 30, 2001,
net proceeds from these sales were approximately $40 million and $184 million,
and we recognized an extraordinary net gain (loss) of approximately $3 million
and $(7) million, net of income tax expense of approximately $2 million and $1
million.

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8. FINANCIAL INSTRUMENTS AND PRICE RISK MANAGEMENT ACTIVITIES

The following table summarizes the carrying value of our trading and
non-trading price risk management assets and liabilities as of June 30, 2002 and
December 31, 2001:

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

(2) Non-trading contracts include hedges related to our oil and natural gas
producing activities and derivatives from our power contract restructuring
activities.

(3) We do not recognize gains on the fair value of trading or non-trading
positions beyond ten years unless there is clearly demonstrated liquidity in
a specific market.

Other derivatives are derivative contracts related to the power
restructuring activities of our consolidated subsidiaries. Of this amount, $882
million relates to a power restructuring that occurred during the first quarter
of 2002 at our Eagle Point Cogeneration power plant, and $97 million relates to
a 2001 power restructuring at our Capitol District Energy Center Cogeneration
Associates plant.

The fair value of the derivatives related to our power restructuring
activities is determined based on the expected cash receipts and payments under
the contracts using future power prices compared to the contractual prices under
these contracts. We discount these cash flows at an interest rate commensurate
with the term of each contract and the credit risk of each contract's
counterparty. We also adjust our valuations for factors such as market
liquidity, market price correlation and model risk, as needed. Future power
prices are based on the forward pricing curve of the appropriate power delivery
and receipt points in the applicable power market. This forward pricing curve is
derived from a combination of actual prices observed in the applicable market,
price quotes from brokers and extrapolation models that rely on actively quoted
prices and historical information. The timing of cash receipts and payments are
based on the expected timing of power delivered under these contracts. The fair
value of our derivatives is updated each period based on changes in actual and
projected market prices, fluctuations in the credit ratings of our
counterparties, significant changes in interest rates, and changes to the
assumed timing of deliveries.

In May 2002, we announced a plan to reduce the volumes of natural gas that
we have hedged for our Production segment. We removed the hedging designation on
derivatives with a fair value loss of $15 million in May 2002. This amount, net
of income taxes of $5 million, is reflected in accumulated other comprehensive
income and will be reclassified to income as the original hedged transactions
are settled through 2004. Of the net loss of $10 million in accumulated other
comprehensive income, we estimate that unrealized gains of $29 million, net of
income taxes, related to these derivatives will be reclassified to income over
the next twelve months.

9. INVENTORY

Our inventory consisted of the following:

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10. DEBT AND OTHER CREDIT FACILITIES

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

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

Issuances

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(1) These notes are collateralized solely by the cash flows and contracts of
these consolidated subsidiaries, and are non-recourse to our parent and
other affiliated companies. The Mohawk River Funding IV financing relates to
our Capitol District Energy Center Cogeneration Associates restructuring
transaction and the Utility Contract Funding financing relates to our Eagle
Point Cogeneration restructuring transaction.

Retirements

In June 2002, El Paso amended its existing $1 billion 3-year revolving
credit and competitive advance facility to permit El Paso to issue up to $500
million in letters of credit and to adjust pricing terms. This facility matures
in August 2003. We are a designated borrower under this facility and, as such,
are liable for any amounts outstanding under this facility. The interest rate
varies based on El Paso's senior unsecured debt rating, and as of June 30, 2002,
an initial draw would have had a rate of LIBOR plus 0.625%, plus a 0.25%
utilization fee for drawn amounts above 25% of the committed amounts. As of June
30, 2002, there were no borrowings outstanding, and $450 million in letters of
credit were issued under the facility.

In August 2002, holders of our $460 million 6.625% FELINE PRIDES(SM) will
be required to purchase El Paso common stock. The holder may either exchange the
FELINE PRIDES(SM) for 0.6622 shares of El Paso common stock, or continue to hold
the FELINE PRIDES(SM) and pay cash for the stock. For each FELINE PRIDES(SM)
exchanged, we will reduce the outstanding principal amount of our FELINE
PRIDES(SM).

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Other Financing Arrangements

During 2000, El Paso formed a series of companies to provide financing to
invest in various El Paso capital projects and other assets. Several of our
assets, including our Colorado Interstate Gas transmission system and, beginning
in July 2002, additional natural gas and oil properties as collateral to El
Paso's financings.

11. COMMITMENTS AND CONTINGENCIES

Legal Proceedings

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. 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.

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. 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 Quinque
complaint was transferred to the same court handling the Grynberg complaint and
has now been sent back to Kansas State Court for further proceedings. A motion
to dismiss this case is pending.

In compliance with the 1990 amendments to the Clean Air Act, we use the
gasoline additive, methyl tertiary-butyl ether (MTBE), in some of our gasoline.
We also produce, buy, sell and distribute MTBE. A number of lawsuits have been
filed throughout the U.S. regarding MTBE's potential impact on water supplies.
We are currently one of several defendants in five such lawsuits in New York.
Our costs and legal exposure related to these lawsuits and claims are not
currently determinable.

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

For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of June 30, 2002, we had reserves of approximately $44 million for all
outstanding legal matters, including $1 million reserved for our discontinued
coal mining operations.

While the outcome of our outstanding legal matters cannot be predicted with
certainty, based on information known to date and our existing accruals, we do
not expect the ultimate resolution of these matters to have a material adverse
effect on our financial position, operating results or cash flows. As new
information 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.

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 June 30, 2002, we had a reserve of approximately $279 million for
expected remediation costs (including related environmental litigation), which
included $15 million reserved for our discontinued coal mining operations. In
addition, we expect to make capital expenditures for environmental matters of
approximately

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$199 million in the aggregate for the years 2002 through 2007. These
expenditures primarily relate to compliance with clean air regulations.

From May 1999 to March 2001, our Coastal Eagle Point Oil Company received
several Administrative Orders and Notices of Civil Administrative Penalty
Assessment from the New Jersey Department of Environmental Protection. All of
the assessments are related to alleged noncompliance with the New Jersey Air
Pollution Control Act pertaining to excess emissions from the first quarter 1998
through the fourth quarter 2000 reported by our Eagle Point refinery in
Westville, New Jersey. The New Jersey Department of Environmental Protection has
assessed penalties totaling approximately $1.1 million for these alleged
violations. Our Eagle Point refinery has been granted an administrative hearing
on issues raised by the assessments and, currently, is in negotiations to settle
these assessments.

We have been designated and have received notice that we could be
designated, or have been asked for information to determine whether we could be
designated, as a Potentially Responsible Party (PRP) with respect to 17 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 CERCLA sites, as appropriate, through indemnification by third
parties and settlements which provide for payment of our allocable share of
remediation costs. As of June 30, 2002, we have estimated our share of the
remediation costs at these sites to be between $5 million and $8 million and
have provided reserves that we believe are adequate for such costs. Since the
clean-up costs are estimates and are subject to revision as more information
becomes available about the extent of remediation required, and because in some
cases we have asserted a defense to any liability, our estimates could change.
Moreover, liability under the federal CERCLA statute is joint and several,
meaning that we could be required to pay in excess of our pro rata share of
remediation costs. Our understanding of the financial strength of other PRPs has
been considered, where appropriate, in determining our estimated liabilities.

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

Rates and Regulatory Matters

In March 2001, Colorado Interstate Gas Company (CIG) filed a rate case with
the Federal Energy Regulatory Commission (FERC) proposing increased rates of $9
million annually and new and enhanced services for its customers. This filing
was required under the settlement of its 1996 general rate case. CIG received an
order from the FERC in late April 2001, which suspended the rates until October
1, 2001, subject to refund, and subject to the outcome of an evidentiary
hearing. On September 26, 2001, the FERC issued an order rejecting two firm
services CIG had proposed in its rate filing and required it to reallocate the
costs allocated to those two services to existing services. CIG has complied
with this order and has arranged with the affected customers to provide service
under existing rate schedules. CIG and its customers entered into a unanimous
settlement agreement in May 2002 settling all issues in the case. The
settlement, which contained a modest rate increase, was approved by the FERC in
July 2002. Provided that no parties seek rehearing within 30 days, this will
become a final order. We will pay refunds plus accrued interest within 60 days
from the final order date. We have made provisions for these refunds and, as a
result, the refunds will not have an adverse effect on our financial position or
results of operations.

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

15

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, at which interested parties were given an opportunity to comment
further on the NOPR. Following the conference, additional comments were filed by
El Paso pipelines and others. We cannot predict the outcome of the NOPR, but
adoption of the regulations in substantially the form proposed would, at a
minimum, place additional administrative and operational burdens on us.

On July 17, 2002, the FERC issued a Notice of Inquiry (NOI) that seeks
comments regarding its policy, established in 1996, of permitting pipelines to
enter into negotiated rates transactions. Several of our pipelines have entered
into these transactions over the years, and the FERC is now undertaking a review
of whether negotiated rates should be capped, whether or not a pipeline's
"recourse rate" (its cost of service based rate) continues to serve as a viable
alternative and safeguard against the exercise of alleged pipeline market power,
as well as other issues related to its negotiated rate program. Comments are due
on September 25, 2002, with reply comments due on October 25, 2002. We cannot
predict the outcome of this NOI.

On August 1, 2002, the FERC issued a NOPR requiring that all arrangements
concerning the 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 must maintain a minimum proprietary capital balance of 30 percent, and
the FERC regulated entity and its parent must maintain investment grade credit
ratings. Comments on the NOPR are due on August 22, 2002. We cannot predict the
outcome of this NOPR.

Also on August 1, 2002, the FERC's Chief Accountant issued, to be effective
immediately, an Accounting Release providing guidance on how jurisdictional
entities should account for money pool arrangements and the types of
documentation that should be maintained for these arrangements. The Accounting
Release sets forth the documentation requirements set forth in the NOPR for
money pool arrangements, but does not address the requirements in the NOPR that
as a condition for participating in money pool arrangements the FERC regulated
entity must maintain a minimum proprietary capital balance of 30 percent and
that the entity and its parent must have investment grade credit ratings.
Requests for rehearing are due on September 3, 2002.

While the outcome of our rates and regulatory matters cannot be predicted
with certainty, based on the information known to date and our existing
accruals, we do not expect the ultimate resolution of these matters to have a
material adverse effect on our financial position, operating results or cash
flows. As new information 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.

Other Matters

Affiliates of Enron hold both short-term and long-term capacity on our
pipeline systems. At this time,
we are uncertain as to Enron's intent to maintain or release capacity associated
with contracts on our
pipeline entities and also Enron's ability to honor the terms of their
contracts. The Court has established August 19, 2002, as the deadline for Enron
to assume or reject contracts with us. Future revenue related to these capacity
contracts will depend upon the outcome of Enron's bankruptcy proceedings and our
ability to re-market or otherwise maximize the value of the rejected or released
capacity. We do not presently know the precise values that will be received by
our pipelines as a result of these efforts.

As a result of current circumstances surrounding the energy sector, the
creditworthiness of several industry participants has been called into question.
We have taken actions to mitigate our exposure to these participants; however,
should several industry participants file for Chapter 11 bankruptcy protection
and

16

contracts with our various subsidiaries are not assumed by other counterparties,
it could have a material adverse effect on our financial position, operating
results or cash flows.

12. SEGMENT INFORMATION

We segregate our business activities into four distinct operating segments:
Pipelines, Production, Merchant Energy and Field Services. These segments are
strategic business units that provide a variety of energy products and services.
They are managed separately as each business unit requires different technology
and marketing strategies. During the quarter, we reclassified our historical
coal mining operations from Merchant Energy segment to discontinued operations
in our financial statements. All periods were restated to reflect this change.
We measure segment performance using earnings before interest expense and income
taxes (EBIT). The following are our segment results as of and for the periods
ended June 30:

- ---------------
(1) Includes our Corporate, eliminations of intercompany transactions and in
2001, our retail business.

(2) Merchant Energy revenues take into account the adoption of EITF Issue No.
02-3, which requires us to report all physical sales of energy commodities
on a net basis. See Note 1 regarding the adoption of this Issue.

17

The reconciliations of EBIT to income (loss) from continuing operations
before extraordinary items and cumulative effect of accounting changes and total
assets are presented below:

13. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS

We hold investments in various affiliates which we account for using the
equity method of accounting. Summarized financial information for our
proportionate share of unconsolidated affiliates below includes affiliates in
which we hold a less than 50 percent interest as well as those in which we hold
a greater than 50 percent interest. Our proportional shares of the
unconsolidated affiliates in which we hold a greater than 50 percent interest
had net income of $6 million and $8 for the quarters ended and $18 million and
$24 million for the six months ended June 30, 2002 and 2001.

Consolidation of Investments

As of December 31, 2001, we had investments in Eagle Point Cogeneration
Partnership, Capitol District Energy Center Cogeneration Associates and Mohawk
River Funding IV. During 2002, we obtained additional rights from our partners
in each of these investments and also acquired an additional one percent
ownership

18

interest in Capitol District Energy Center Cogeneration Associates and Mohawk
River Funding IV. As a result of these actions, we began consolidating these
investments effective January 1, 2002.

Related Party Transactions

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

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

We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of its participating affiliates, thus
minimizing total borrowing from outside sources. We had net borrowings of $1,479
million, at a market rate of interest which was 1.9% at June 30, 2002 and $908
million at a market interest rate of 2.1% at December 31, 2001. In addition, we
had a demand note receivable with El Paso of $122 million at June 30, 2002, with
an interest rate of 2.4%, and $120 million at December 31, 2001, with an
interest rate of 4.2%.

At June 30, 2002, we had current accounts and notes receivable from related
parties of $385 million and $426 million at December 31, 2001. In addition, we
had a non-current note receivable from a related party of $26 million and $27
million included in other non-current assets at June 30, 2002 and at December
31, 2001.

At June 30, 2002, we had accounts and notes payable to related parties of
$292 million and $428 million at December 31, 2001. In addition, included in
short-term borrowings at December 31, 2001 was a current note payable to related
parties of $67 million.

El Paso Energy Partners

Our parent has entered into a letter of intent to sell our Typhoon offshore
natural gas and oil pipelines as well as our NGL pipelines and a related
fractionation facility in Texas to El Paso Energy Partners. This proposed
transaction has been approved by both our parent's and El Paso Energy Partners'
Boards of Directors which included the approval by El Paso Energy Partners'
special conflicts committee. There were also fairness opinions issued on this
transaction. This transaction is subject to customary regulatory review and
approval. The closing of the sale is anticipated by the end of 2002.

14. MINORITY INTERESTS

Coastal Oil & Gas Resources Preferred Stock. In July, 2002, we repurchased
from an unaffiliated investor, 50,000 shares representing all outstanding
preferred stock in Coastal Oil & Gas Resources, Inc., our wholly owned
subsidiary, for $50 million plus accrued and unpaid dividends.

Coastal Limited Ventures Preferred Stock. In July, 2002, we repurchased
from an unaffiliated investor, 150,000 shares representing all outstanding
preferred stock in Coastal Limited Ventures, Inc., our wholly owned subsidiary,
for $15 million plus accrued and unpaid dividends.

Consolidated Partnership. In July, 2002, we repurchased the limited
partnership interests from an unaffiliated investor, in a partnership formed
with Coastal Limited Ventures, Inc. The payment of approximately $285 million to
the unaffiliated investor was equal to the sum of limited partner's outstanding
capital plus unpaid priority returns.

15. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

Accounting for Asset Retirement Obligations

In August 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 143, Accounting for Asset Retirement Obligations. This statement requires
companies to record a liability for the estimated retirement and removal costs
of assets used in their business. The liability is recorded at its present
value, and the same amount is added to the recorded value of the asset and is
amortized over the asset's remaining useful

19

life. The provisions of SFAS No. 143 are effective for fiscal years beginning
after June 15, 2002. We are currently evaluating the effects of this statement.

Reporting Gains and Losses from the Early Extinguishment of Debt

In April 2002, the FASB issued SFAS No. 145, Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections. This statement addresses how to report gains or losses resulting
from the early extinguishment of debt. Under current accounting rules, our
non-rate regulated entities report any gains or losses on early extinguishment
of debt as extraordinary items. When we adopt SFAS No. 145, we will be required
to evaluate whether the debt extinguishment is truly extraordinary in nature. If
we routinely extinguish debt early, the gain or loss will be included in income
from continuing operations. This statement will be effective for our 2003
year-end reporting.

Accounting for Costs Associated with Exit or Disposal Activities

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement will require us to recognize
costs associated with exit or disposal activities when they are incurred rather
than when we commit to an exit or disposal plan. Examples of costs covered by
this guidance include lease termination costs, employee severance costs that are
associated with a restructuring, discontinued operations, plant closings or
other exit or disposal activities. The provisions of this statement are
effective for fiscal years beginning after December 31, 2002 and will impact any
exit or disposal activities initiated after January 1, 2003.

20

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS(1)

The information contained in Item 2 updates, and you should read it in
conjunction with, information disclosed in our Annual Report on Form 10-K filed
March 28, 2002, in addition to the financial statements and notes presented in
Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

RECENT DEVELOPMENTS

As a result of current circumstances surrounding the energy sector, the
creditworthiness of several industry participants has been called into question.
We have taken actions to mitigate our exposure to these participants; however,
should several of these participants file for Chapter 11 bankruptcy protection
and contracts with our various subsidiaries are not assumed by other
counterparties, it could have a material adverse effect on our financial
position, operating results or cash flows.

RESULTS OF OPERATIONS

Our results of operations, along with the impact by segment of the
merger-related costs, asset impairments and other charges, are presented below.
Pro-forma amounts should not be used as a substitute for amounts reported under
generally accepted accounting principles. They are presented solely to improve
the understanding of the impact of the charges reported during the periods
presented. The results are as follows (in millions):

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

(1) Below is a list of terms that are common to our industry and used throughout
our Management's Discussion and Analysis:

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

When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl is equal to six Mcf of natural
gas. Also, when we refer to cubic feet measurements, all measurements are at
14.73 pounds per square inch.

(2) Charges include merger-related costs, asset impairments, ceiling test
charges, changes in accounting estimates, discontinued operations,
extraordinary items, cumulative effect of accounting changes and other
non-recurring gains. See Item 1, Financial Statements, for further
discussions of these charges.

21

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

(1) Charges include merger-related costs, asset impairments, ceiling test
charges, changes in accounting estimates, discontinued operations,
extraordinary items, cumulative effect of accounting changes and other
non-recurring gains. See Item 1, Financial Statements, for further
discussions of these charges.

SEGMENT RESULTS

Our four segments: Pipelines, Production, Merchant Energy and Field
Services are strategic business units that offer a variety of different energy
products and services; each requires different technology and marketing
strategies. We evaluate our segment performance based on EBIT. Operating
revenues and expenses by segment include intersegment revenues and expenses
which are eliminated in consolidation. Because changes in energy commodity
prices have a similar impact on both our operating revenues and cost of products
sold from period to period, we believe that gross margin (revenue less cost of
sales) provides a more accurate and meaningful basis for analyzing operating
results for the trading and refining portions of Merchant Energy and for the
Field Services segment. We have reclassified our historical coal mining
operations from Merchant Energy to discontinued operations in our financial
statements. All periods have been adjusted to reflect these changes. For a
further discussion of our individual segments, see Item 1, Financial Statements,
Note 12, as well as our Annual Report on Form 10-K for the year ended December
31, 2001. The segment EBIT results for the periods ended June 30 presented below
include the charges discussed above:

22

PIPELINES

Our Pipeline segment holds our interstate transmission business. Pipeline
results are relatively stable, but can be subject to variability from a number
of factors, such as weather conditions, including those conditions that may
impact the amount of power produced by natural gas fired turbines compared to
power generated by less costly coal fired generators, as well as natural gas
market price differentials which can effect our deliveries to our markets.
Results can also be impacted by the ability to market excess natural gas which
is influenced by a pipeline's rate of recovery for use and efficiencies of the
pipeline's compression equipment. Future revenues may also be impacted by
expansion projects in our service areas, competition by other pipelines for
those expansion needs and regulatory impacts on rates. Results of our Pipelines
segment operations were as follows for the periods ended June 30:

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

(1) Throughput volumes for 2001 exclude those related to pipeline systems sold
in connection with FTC orders related to our merger with El Paso including
investments in the Empire State and Iroquois pipelines. Throughput volumes
also exclude intrasegment activities.

Second Quarter 2002 Compared to Second Quarter 2001

Operating revenues for the quarter ended June 30, 2002, were $28 million
lower than the same period in 2001. The decrease was primarily due to the impact
of lower prices on natural gas and liquids sales, including sales of natural gas
produced, and resales of natural gas purchased from the Dakota gasification
facility. Also contributing to the decrease were lower sales of excess natural
gas, lower transportation revenues from capacity sold under short-term contracts
due to milder weather in 2002 and lower 2002 sales of base gas from abandoned
storage fields. Partially offsetting the decrease was higher reservation
revenues from our system expansion projects, which were placed in service in
2001.

Operating expenses for the quarter ended June 30, 2002, were $167 million
lower than the same period in 2001. The decrease was primarily due to
merger-related costs of $132 million incurred to relocate our pipeline
operations from Detroit, Michigan to Houston, Texas, costs for employee
benefits, retention and transition charges and a change in accounting estimate
of $20 million recorded in the second quarter of 2001 primarily for additional
environmental remediation liabilities. Also contributing to the decrease were
lower corporate overhead allocations and lower amortization due to the
implementation of SFAS No. 142 in 2002. Additionally, lower prices on natural
gas purchased from the Dakota gasification facility, lower fuel costs resulting
from lower natural gas prices and lower benefit costs in 2002 contributed to the
decrease. The decrease was partially offset by an increase in 2002 in our
estimated liabilities to assess and remediate our environmental exposure due to
an ongoing evaluation of our facilities.

Other income for the quarter ended June 30, 2002, was $4 million higher
than the same period in 2001 primarily due to the resolution of uncertainties
associated with the sales of our interests in the Empire State and Iroquois
pipeline systems in 2001.

Six Months Ended 2002 Compared to Six Months Ended 2001

Operating revenues for the six months ended June 30, 2002, were $89 million
lower than the same period in 2001. The decrease was primarily due to the impact
of lower prices on natural gas and liquids sales, including sales of natural gas
produced and resales of natural gas purchased from the Dakota gasification
facility. Also contributing to the decrease were lower sales of excess natural
gas, lower transportation revenues

23

from capacity sold under short-term contracts due to milder weather in 2002 and
lower 2002 sales of base gas from abandoned storage fields. Partially offsetting
the decrease was higher reservation revenues from our system expansion projects,
which were placed in service in 2001.

Operating expenses for the six months ended June 30, 2002, were $300
million lower than the same period in 2001. The decrease was primarily due to
merger-related costs of $211 million incurred to relocate our pipeline
operations from Detroit, Michigan to Houston, Texas, costs for employee
benefits, severance, retention and transition charges and a change in accounting
estimate of $20 million for additional environmental remediation liabilities in
2001. Also contributing to the decrease were lower fuel costs resulting from
lower natural gas prices, lower prices on natural gas purchased from the Dakota
gasification facility and lower amortization due to the implementation of SFAS
No. 142 in 2002. Additionally, lower benefit costs, cost efficiencies following
our merger with El Paso and lower corporate overhead allocations in 2002
contributed to the decrease. Partially offsetting the decrease was an increase
in 2002 in our estimated liabilities to assess and remediate our environmental
exposure due to an ongoing evaluation of our facilities.

Other income for the six months ended June 30, 2002, was $20 million higher
than the same period in 2001. The increase was primarily due to a gain on the
sale of pipeline expansion rights in February 2002, higher equity earnings on
Great Lakes Gas Transmission in 2002 and the resolution of uncertainties
associated with the sales of our interests in the Empire State and Iroquois
pipeline systems in 2001.

PRODUCTION

Our Production segment conducts our natural gas and oil exploration and
production activities. In the past, our stated goal was to hedge approximately
75 percent of our anticipated current year production, approximately 50 percent
of our anticipated succeeding year production and a lesser percentage
thereafter. As a component of our parent's strategic repositioning plan
announced in May 2002, we modified this hedging strategy. We now expect to hedge
approximately 50 percent or less of our anticipated production for a rolling
12-month forward period. This modification of our hedging strategy will increase
our exposure to changes in commodity prices which could result in significant
volatility in our reported results of operations, financial position and cash
flows from period to period. Results of our Production segment operations were
as follows for the periods ended June 30:

- ---------------
(1) Net of transportation costs.

Second Quarter 2002 Compared to Second Quarter 2001

For the quarter ended June 30, 2002, operating revenues were $145 million
lower than the same period in 2001 due primarily to a decline in natural gas
volumes in 2002 when compared to the same period of 2001.

Transportation and net product costs for the quarter ended June 30, 2002,
were $2 million higher than the same period in 2001 primarily due to a higher
percentage of gas volumes subject to transportation fees partially offset by
costs incurred in 2001 to meet minimum payments on pipeline agreements.

Operating expenses for the quarter ended June 30, 2002, were $190 million
higher than the same period in 2001 due to increased oilfield services costs and
non-cash full cost ceiling test charges totaling $233 million incurred in 2002,
primarily for our Canadian full cost pool. The charge for the Canadian full cost
pool primarily resulted from a low daily posted price for natural gas of
approximately $1.43 per MMBtu at the end of the second quarter. Partially
offsetting these increases were write-downs in 2001 totaling $7 million of
materials and supplies resulting from the ongoing evaluation of our operating
standards and plans following our merger and lower severance and other taxes in
2002.

Six Months Ended 2002 Compared to Six Months Ended 2001

For the six months ended June 30, 2002, operating revenues were $185
million lower than the same period in 2001. The decrease was primarily due to a
decline in natural gas volumes and oil, condensate and liquids prices in 2002
when compared to the same period of 2001. The decline in natural gas volumes is
primarily a result of the first quarter 2002 sale of production properties in
Texas and Colorado. Partially offsetting the decrease was an increase in volumes
for oil, condensate and liquids in 2002 when compared to the same period of
2001.

Transportation and net product costs for the six months ended June 30,
2002, were $11 million lower than the same period in 2001 primarily due to costs
incurred in 2001 to meet minimum payments on pipeline agreements partially
offset by a higher percentage of gas volumes.

Operating expenses for the six months ended June 30, 2002, were $155
million higher than the same period in 2001 due to higher depletion expense in
2002 as a result of additional capital spending on assets in the full cost pool,
non-cash full cost ceiling test charges totaling $243 million incurred in 2002
for our Canadian full cost pool and other international properties primarily in
Australia and higher corporate overhead allocations. Also contributing to the
increase were increased oilfield services costs. Partially offsetting these
increases were merger-related costs of $61 million incurred in 2001 due to our
merger with El Paso in January 2001, write-downs in 2001 totaling $7 million of
materials and supplies resulting from the ongoing evaluation of our operating
standards and plans, and lower severance and other taxes in 2002.

25

MERCHANT ENERGY

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

As a result of current circumstances surrounding the wholesale energy
markets, we have experienced weaker market fundamentals resulting in an
elimination of industry participants and the disorderly liquidation of their
trading portfolios. Additionally, changes in credit requirements have left
several market participants less creditworthy, requiring greater use of credit
support actions. These factors have resulted in lower trading profitability
which we expect to continue for the remainder of 2002 and into 2003. In
addition, our refining business has been adversely impacted over the past twelve
months by the declining spreads between the lighter crudes, which are typically
more expensive than the heavy crudes processed at our Aruba refinery. We expect
this trend to continue into 2003.

Power Contract Restructuring Activities

Our domestic power plants have long-term power sales contracts with
regulated utilities that were entered into under the Public Utility Regulatory
Policies Act of 1978 (PURPA). The power sold to the utility under these PURPA
contracts is required to be delivered from a specified power generation plant at
power prices that are usually significantly higher than the cost of power in the
wholesale power market. Our cost of generating power at these PURPA power plants
is typically higher than the cost we would incur by obtaining the power in the
wholesale power market, principally because the PURPA power plants are less
efficient than newer power generation facilities.

Typically, in a power contract restructuring, the PURPA power sales
contract is amended so that the power sold to the utility does not have to be
provided from the specific power plant. Because we are able to buy lower cost
power in the wholesale power market, we have the ability to reduce the cost paid
by the utility, thereby inducing the utility to enter into the power contract
restructuring transaction. Following the contract restructuring, the power plant
operates on a merchant basis, which means that it is no longer dedicated to one
buyer and will operate only when power prices are high enough to make operations
economical. In addition, we may assume, and in the case of Eagle Point
Cogeneration we did assume, the business and economic risks of supplying power
to the utility to satisfy the delivery requirements under the restructured power
contract over its term. When we assume this risk, we manage these obligations by
entering into transactions to buy power from third parties that mitigate our
risk over the life of the contract. These activities are reflected as part of
our trading activities and reduce our exposure to changes in power prices from
period to period. Power contract restructurings generally result in a higher
return in our power generation business because we can deliver reliable power at
lower prices than our cost to generate power at these PURPA power plants. In
addition, we can use the restructured contracts as collateral to obtain
financing at a cost that is comparable to, or lower than, our existing financing
costs. The manner in which we account for these activities is discussed in Item
1, Financial Statements, Note 1, of this Form 10-Q.

Power restructuring transactions are often extensively negotiated and can
take a significant amount of time to complete. In addition, there are a limited
number of facilities to which the restructuring process applies. Our ability to
successfully restructure a power plant's contracts and the future financial
benefit of that effort is difficult to determine, and may vary significantly
from period to period. Since we began these activities in 1999, we have
completed five restructuring transactions, including contract terminations, of
varying financial significance, and we have additional facilities which we will
consider for restructuring in the future.

26

Results of Operations

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

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

(1) Volumes include those settled in our origination and trading activities, as
well as those generated or produced at our consolidated power plants and
refineries.

Trading and refining gross margins consist of revenues from commodity
trading activities less the cost of commodities sold, the impact of power
contract restructuring activities and revenues from refineries and chemical
plants, less the costs of feedstocks used in the refining and production
processes.

Second Quarter 2002 Compared to Second Quarter 2001

During the quarter ended June 30, 2002, we completed a significant
transaction related to our Nejapa power facility. In March 2002, an arbitration
award panel approved the termination of the power purchase agreement between
Comision Ejecutiva Hydroelectrica del Rio Lempa and the Nejapa Power Company,
one of our consolidated subsidiaries, in exchange for a cash payment of $90
million. The award was finalized and paid to Nejapa in the second quarter of
2002. We recorded, as revenue, a $90 million gain and also recorded $13 million
in other expense for the minority owner's share of this gain. We applied the
proceeds of the award to retire a portion of Nejapa's debt.

For the quarter ended June 30, 2002, trading and refining gross margins
were $157 million lower than the same period in 2001. Contributing to the
overall decrease were lower refining margins resulting from the lease of our
Corpus Christi refinery and related assets to Valero Energy Corporation in June
2001, lower spreads between the sales prices of refined products and underlying
feedstock costs and lower throughput at the Aruba refinery. Lower revenues from
our marine operations resulting from lower freight rates, a decrease in vessels
owned and on charter and lower throughput at our marine terminals also
contributed to the overall decrease in trading and refining margins.

Operating and other revenues consist of revenues from domestic and
international power generation facilities. For the quarter ended June 30, 2002,
operating and other revenues were $136 million higher than the same period in
2001. The increase resulted from revenue from domestic and international power
facilities that were consolidated in the fourth quarter of 2001 and the first
quarter of 2002 and $90 million of revenues from the termination of the Nejapa
power contract.

Operating expenses for the quarter ended June 30, 2002, were $101 million
lower than the same period in 2001. The decrease was primarily a result of
merger-related costs, changes in accounting estimates and asset impairments of
$91 million recorded in the second quarter of 2001 associated with combining
operations with

27

The Coastal Corporation (Coastal), our former parent. The decrease was partially
offset by the consolidation of international and domestic power-related entities
in the fourth quarter of 2001 and the first quarter of 2002.

Other income for the quarter ended June 30, 2002, was $15 million lower
than the same period in 2001. The decrease was primarily the result of the
minority owner's interest in the gain from the termination of the Nejapa power
contract and a decrease in equity earnings from unconsolidated projects in the
second quarter of 2002.

Six Months Ended 2002 Compared to Six Months Ended 2001

During the six months ended June 30, 2002, we completed power
restructurings or contract terminations at our Eagle Point Cogeneration and
Nejapa power plants. The Eagle Point Cogeneration restructuring transaction was
completed in March 2002.

The Eagle Point restructuring involved several steps. First, we amended the
existing PURPA power sales contract with Public Service Electric and Gas (PSEG)
to eliminate the requirement that power be delivered specifically from the Eagle
Point power plant. This amended contract has fixed prices with stated increases
over the 14-year term that range from $85 per MWh to $126 per MWh. We entered
into the amended power sales contract through a consolidated subsidiary, Utility
Contract Funding, L.L.C. (UCF). UCF was created to hold and execute the terms of
the restructured power sales contract, to enter into a supply contract to meet
the requirements of the restructured agreement and to monetize the value of
these contracts by issuing debt. In keeping with its purpose, UCF entered into a
power supply agreement with El Paso Merchant Energy L.P. (EPME), an affiliated
company. The terms of the EPME power supply contract were identical to the
restructured power contract, with the exception of price, which was set at $37
per MWh over its 14-year term.

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

As a result of the various steps we have taken to accomplish this
restructuring, we have been able to improve the expected margin associated with
the original PURPA contract by replacing the high-cost of the power generated
from the Eagle Point plant, which had averaged over $75 per MWh, with power that
we have purchased at a cost of $37 per MWh.

From an accounting standpoint, the actions taken to restructure the
contract required us to mark the restructured power contract and the power
supply contracts to their fair value under SFAS No. 133. As a result, we
recorded non-cash revenue representing the estimated fair value of the
derivative contracts of approximately $898 million in our first quarter results.
We also amended or terminated other ancillary agreements associated with the
cogeneration facility, such as gas supply and transportation agreements, a steam
contract and existing financing agreements. In the second quarter, we paid $103
million to the utility to terminate the original PURPA contract. Also included
in our first quarter results were a $98 million non-cash charge to adjust the
Eagle Point Cogeneration plant to fair value based on its new status as a
peaking merchant plant and a non-cash charge of $230 million to write off the
book value of the original PURPA contract. Based on these amounts, and including
closing and other costs, our first quarter results reflected a net benefit from
the Eagle Point Cogeneration restructuring transaction of $348 million. Total
operating cash flows from this transaction amounted to approximately $120
million of cash paid to the utility to amend the original contract and other
miscellaneous closing costs. In July 2002, UCF completed the restructuring
transaction by monetizing the contract with PSEG and issuing $829 million of
7.944% senior notes secured solely by the contracts and cash flows of UCF. The
proceeds of the monetization will be reported as financing cash flow in the
third quarter of 2002.

For the six months ended June 30, 2002, trading and refining gross margins
were $121 million higher than the same period in 2001. The increase resulted
from income recorded in the first quarter of 2002 related to the Eagle Point
Cogeneration power plant contract restructuring. Partially offsetting the
increase were lower

28

refining margins resulting from the lease of our Corpus Christi refinery and
related assets to Valero in June 2001, lower spreads between the sales prices of
refined products and underlying feedstock costs and lower throughput at our
Aruba refinery, lower revenues from vessels owned and on charter, and lower
throughput at our marine terminals.

For the six months ended June 30, 2002, operating and other revenues were
$169 million higher than the same period in 2001. The increase resulted from
revenues from domestic and international power facilities that were consolidated
in the fourth quarter of 2001 and the first quarter of 2002 and $90 million of
revenues from the termination of the Nejapa power contract. Partially offsetting
the increase was the transfer of power index swaps on our Fulton and Rensselaer
power facilities to a subsidiary of El Paso in February 2001 and the sale of a
power facility to a related party in 2001.

Operating expenses for the six months ended June 30, 2002, were $238
million lower than the same period in 2001. The decrease resulted from
merger-related costs, changes in accounting estimates and asset impairments of
$225 million recorded in the second quarter of 2001 associated with combining
operations with Coastal as well as lower fuel costs in our refining operations
resulting from lower gas prices and the lease of our Corpus Christi refinery and
related assets to Valero in June 2001. The decrease was partially offset by the
consolidation of international and domestic power-related entities in the fourth
quarter of 2001 and the first quarter of 2002.

Other income for the six months ended June 30, 2002, was $86 million lower
than the same period in 2001. The decrease was primarily the result of the
minority owner's interest in the gain on the termination of the Nejapa power
contract of $13 million, the minority owner's interest in the Eagle Point
transaction of $49 million and lower equity earnings on domestic power projects
consolidated in the fourth quarter of 2001 and the first quarter of 2002. The
power projects we consolidated in the fourth quarter of 2001 and the first
quarter of 2002 are not wholly-owned by us. As a result, the minority owner's
interest in the income earned from these facilities, which we classify as other
income, also reduced other income in the first six months of 2002.

FIELD SERVICES

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

29

Second Quarter 2002 Compared to Second Quarter 2001

Total gross margins for the quarter ended June 30, 2002, were $11 million
lower than the same period in 2001. The decrease was primarily due to lower
natural gas liquids prices in 2002, which unfavorably impacted our processing
volumes and margins in the Rockies and south Louisiana regions. Also
contributing to the decrease was the sale of our Dragon Trail processing plant
in May 2002 and lower gathering and treating volumes in 2002 due to natural
declines in production in our operation regions.

Operating expenses for the quarter ended June 30, 2002, were $10 million
lower than the same period in 2001. The decrease was primarily due to $5 million
of merger-related costs in 2001 due to our January 2001 merger with El Paso and
lower operating expenses as a result of our cost-saving efforts in 2002.

Other income for the quarter ended June 30, 2002, was $9 million higher
than the same period in 2001 primarily due to a gain of $10 million recognized
on the sale of our Dragon Trail processing plant, partially offset by lower
earnings from our Deepwater Holdings equity investment which was sold to El Paso
Energy Partners in October 2001.

Six Months Ended 2002 Compared to Six Months Ended 2001

Total gross margins for the six months ended June 30, 2002, were $29
million lower than the same period in 2001. The decrease was primarily due to
lower natural gas liquids prices in 2002, which unfavorably impacted our
processing volumes and margins in the Rockies and south Louisiana regions. Also
contributing to the decrease was the sale of our Dragon Trail processing plant
in May 2002 and lower gathering and treating volumes in 2002 due to natural
declines in production in our operation regions.

Operating expenses for the six months ended June 30, 2002, were $9 million
lower than the same period in 2001. The decrease was primarily due to $6 million
of merger-related costs in 2001 due to our January 2001 merger with El Paso and
lower operating expenses as a result of our cost-saving efforts in 2002. These
decreases were slightly offset by higher depreciation expense as a result of
placing assets in service in mid-2001.

Other income for the six months ended June 30, 2002, was $9 million higher
than the same period in 2001 primarily due to a gain of $10 million recognized
on the sale of our Dragon Trail processing plant, partially offset by lower
earnings from our Deepwater Holding equity investments which was sold to El Paso
Energy Partners in October 2001.

CORPORATE AND OTHER, NET

Corporate and other expenses, which include general and administrative
activities as well as other miscellaneous businesses, for the quarter and six
months ended June 30, 2002, were $142 million and $645 million lower than the
same periods in 2001. The decrease was primarily a result of $165 million and
$653 million in merger-related charges for the quarter and six months ended June
30, 2001, in connection with our merger with El Paso, additional costs for the
quarter and six months ended June 30, 2001 of $103 million related to increased
estimates of environmental remediation in fair value of spare parts inventories
to reflect changes in usability of spare parts inventories in our corporate
operations based on an ongoing evaluation of our operating standards and plans
following the merger with El Paso.

INTEREST AND DEBT EXPENSE

Non-affiliated Interest and Debt Expense

Non-affiliated interest and debt expense for the six months ended June 30,
2002, was $16 million lower than the same period in 2001 primarily due to
retirement of long-term debt in the first quarter of 2002 and short-term
borrowings, consisting of commercial paper and short-term bank credit
facilities, in the first quarter of 2001. This decrease was partially offset by
interest from the issuance of long-term debt in October 2001.

30

Affiliated Interest Expense, Net

Affiliated interest expense, net for the quarter and six months ended June
30, 2002, was $15 million and $17 million lower than the same period in 2001 due
to lower short-term interest rates on average advances from El Paso Corporation
under our cash management program.

MINORITY INTEREST

Minority interest expense for the quarter and six months ended June 30,
2002, was $1 million and $5 million lower than the same period in 2001,
primarily due to lower average interest rates.

INCOME TAXES

Income tax benefit for the quarter ended June 30, 2002, was $17 million,
resulting in effective tax rate of 33 percent. Income tax expense for the six
months ended June 30, 2002, was $184 million, resulting in effective tax rate of
33 percent. Our effective tax rates were different than the statutory rate of 35
percent primarily due to the following:

- state income taxes; and

- foreign income taxed at different rates.

Income tax benefit for the quarter and six months ended June 30, 2001, was
$19 million and $51 million, resulting in effective tax rates of 23 percent and
11 percent. The six months ended June 30, 2001 benefit was net of $105 million
of tax expense associated with non-deductible merger charges and changes in our
estimates of additional tax liabilities. The majority of these estimated
additional liabilities were paid in 2001 and are being contested by us. The
effective tax rate excluding these charges for the six months ended June 30,
2001 was 34 percent. Other differences between the effective tax rates and the
statutory tax rate of 35 percent were primarily due to the following:

- state income taxes; and

- foreign income taxed at foreign rates.

COMMITMENTS AND CONTINGENCIES

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

NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

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

31

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

There are no material changes in our quantitative and qualitative
disclosures about market risks from those reported in our Annual Report on Form
10-K for the year ended December 31, 2001.

32

PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

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

ITEM 2. CHANGES IN SECURITIES.

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES.

None.

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

None.

ITEM 5. OTHER INFORMATION.

None.

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

a. Exhibits.

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

Undertaking

We hereby undertake, pursuant to Regulation S-K, Item 601(b),
paragraph (4)(iii), to furnish to the U.S. Securities and Exchange
Commission, upon request, all constituent instruments defining the rights
of holders of our long-term debt not filed herewith for the reason that the
total amount of securities authorized under any of such instruments does
not exceed 10 percent of our total consolidated assets.

b. Reports on Form 8-K

None.

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: August 14, 2002 /s/ H. BRENT AUSTIN
------------------------------------
H. Brent Austin
Executive Vice President and
Chief Financial Officer and Director
(Principal Financial Officer)

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

34

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.