<PAGE>

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                                 UNITED STATES
                       SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

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

                                  FORM 10-Q/A
(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, 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

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

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

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

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

                        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 May 15, 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.

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>

BASIS FOR AMENDED FORM 10-Q

     We are filing this amended Form 10-Q for the quarterly period ended March
31, 2002, to provide a more comprehensive discussion of a power restructuring
transaction that was completed during the first quarter of 2002, and the impact
of that transaction on our first quarter 2002 operating results. This amendment
relates solely to the matters discussed above and does not change in any way the
financial results reported in our original Form 10-Q filed on May 15, 2002. In
addition, this amended Form 10-Q does not update all information included in
that original Form 10-Q and you should refer to our Current Reports on Form 8-K
dated after May 15, 2002, for additional events that have occurred since that
date.

     You can request a copy of this amended filing at no charge. Requests should
be directed to El Paso Corporation 1001 Louisiana, Houston, Texas 77002,
attention: Bruce Connery, Vice President, Investor Relations; telephone
713-420-5855. You may also access this amended filing on the SEC website at
www.sec.gov, where all of our SEC filings may be found.
<PAGE>

                        PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

                              EL PASO CGP COMPANY

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

<Table>
<Caption>
                                                               QUARTER ENDED
                                                                 MARCH 31,
                                                              ----------------
                                                               2002      2001
                                                              -------   ------
<S>                                                           <C>       <C>
Operating revenues..........................................  $4,952    $7,797
                                                              ------    ------
Operating expenses
  Cost of products and services.............................   3,652     6,716
  Operation and maintenance.................................     362       382
  Merger-related costs......................................      --       767
  Ceiling test charge.......................................      10        --
  Depreciation, depletion and amortization..................     207       164
  Taxes, other than income taxes............................      42        68
                                                              ------    ------
                                                               4,273     8,097
                                                              ------    ------
Operating income (loss).....................................     679      (300)
                                                              ------    ------
Other income (expense)
  Earnings from unconsolidated affiliates...................      51        61
  Other, net................................................     (25)       12
                                                              ------    ------
                                                                  26        73
                                                              ------    ------
Income (loss) before interest, income taxes and other
  charges...................................................     705      (227)
                                                              ------    ------
Non-affiliated interest and debt expense....................     107       124
Affiliated interest expense, net............................       3         4
Minority interest...........................................      10        14
Income taxes................................................     191       (32)
                                                              ------    ------
                                                                 311       110
                                                              ------    ------
Income (loss) before extraordinary items....................     394      (337)
Extraordinary items, net of income taxes....................      --       (10)
                                                              ------    ------
Net income (loss)...........................................  $  394    $ (347)
                                                              ======    ======
</Table>

                            See accompanying notes.

                                        1
<PAGE>

                              EL PASO CGP COMPANY

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

<Table>
<Caption>
                                                              MARCH 31,   DECEMBER 31,
                                                                2002          2001
                                                              ---------   ------------
<S>                                                           <C>         <C>
                                        ASSETS
Current assets
  Cash and cash equivalents.................................   $   199      $   131
  Accounts and notes receivable, net
     Customer...............................................     1,636        1,821
     Affiliates.............................................       323          546
     Other..................................................       194          211
  Inventory.................................................       861          693
  Assets from price risk management activities..............       505          425
  Other.....................................................       287          357
                                                               -------      -------
          Total current assets..............................     4,005        4,184
                                                               -------      -------
Property, plant and equipment, at cost
  Natural gas and oil properties, at full cost..............     7,602        7,765
  Pipelines.................................................     6,595        6,558
  Refining, crude oil and chemical facilities...............     2,442        2,425
  Power facilities..........................................       472          271
  Gathering and processing systems..........................       433          428
  Other.....................................................       507          516
                                                               -------      -------
                                                                18,051       17,963
  Less accumulated depreciation, depletion and
     amortization...........................................     6,361        5,945
                                                               -------      -------
          Total property, plant and equipment, net..........    11,690       12,018
                                                               -------      -------
Other assets
  Investments in unconsolidated affiliates..................     1,730        1,883
  Assets from price risk management activities..............     1,305          267
  Other.....................................................       701          714
                                                               -------      -------
                                                                 3,736        2,864
                                                               -------      -------
          Total assets......................................   $19,431      $19,066
                                                               =======      =======
</Table>

                            See accompanying notes.

                                        2
<PAGE>
                              EL PASO CGP COMPANY

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

<Table>
<Caption>
                                                              MARCH 31,   DECEMBER 31,
                                                                2002          2001
                                                              ---------   ------------
<S>                                                           <C>         <C>
                         LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
  Accounts and notes payable
     Trade..................................................   $ 1,756      $ 1,858
     Affiliates.............................................     1,206        1,360
     Other..................................................       427          360
  Short-term borrowings (including current maturities of
     long-term debt and other financing obligations)........     1,012        1,410
  Liabilities from price risk management activities.........       402          213
  Income taxes payable......................................       450          198
  Other.....................................................       356          402
                                                               -------      -------
          Total current liabilities.........................     5,609        5,801
                                                               -------      -------
Long-term debt and other financing obligations, less current
  maturities................................................     5,258        5,107
                                                               -------      -------
Other liabilities
  Liabilities from price risk management activities.........       242            1
  Deferred income taxes.....................................     1,639        1,740
  Other.....................................................       455          553
                                                               -------      -------
                                                                 2,336        2,294
                                                               -------      -------
Commitments and contingencies
Securities of subsidiaries
  Company-obligated preferred securities of consolidated
     trusts.................................................       300          300
  Minority interests........................................       766          594
                                                               -------      -------
                                                                 1,066          894
                                                               -------      -------
Stockholder's equity
  Common stock, par value $1 per share; authorized and
     issued 1,000 shares....................................        --           --
  Additional paid-in capital................................     1,305        1,305
  Retained earnings.........................................     3,779        3,385
  Accumulated other comprehensive income....................        78          280
                                                               -------      -------
          Total stockholder's equity........................     5,162        4,970
                                                               -------      -------
          Total liabilities and stockholder's equity........   $19,431      $19,066
                                                               =======      =======
</Table>

                            See accompanying notes.

                                        3
<PAGE>

                              EL PASO CGP COMPANY

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

<Table>
<Caption>
                                                              QUARTER ENDED
                                                                MARCH 31,
                                                              --------------
                                                              2002     2001
                                                              -----    -----
<S>                                                           <C>      <C>
Cash flows from operating activities
  Net income (loss).........................................  $ 394    $(347)
  Adjustments to reconcile net income (loss) to net cash
     from operating activities
     Non-cash gains from power and trading activities.......   (394)      --
     Non-cash portion of merger-related costs...............     --      666
     Depreciation, depletion and amortization...............    207      164
     Ceiling test charge....................................     10       --
     Undistributed earnings of unconsolidated affiliates....    (12)     (45)
     Net (gain) loss on the sale of assets..................    (11)       5
     Deferred income tax benefit............................    (58)     (17)
     Extraordinary items....................................     --       11
     Other non-cash income items............................     29       (3)
  Working capital changes...................................    339     (128)
  Non-working capital changes and other.....................   (110)     126
                                                              -----    -----
          Net cash provided by operating activities.........    394      432
                                                              -----    -----
Cash flows from investing activities
  Additions to property, plant and equipment................   (301)    (410)
  Net proceeds from the sale of assets......................    524      147
  Additions to investments..................................    (76)     (76)
  Proceeds from investments.................................      2        2
  Repayment of notes receivable from unconsolidated
     affiliates.............................................     54       77
  Other.....................................................     47       --
                                                              -----    -----
          Net cash provided by (used in) investing
           activities.......................................    250     (260)
                                                              -----    -----
Cash flows from financing activities
  Net repayments under commercial paper and short-term
     credit facilities......................................    (30)    (798)
  Repayments of notes payable...............................     (7)      --
  Issuances of common stock.................................     --        2
  Net proceeds from the issuance of long-term debt and other
     financing obligations..................................     --      152
  Payments to retire long-term debt and other financing
     obligations............................................   (431)    (429)
  Dividends paid............................................     --      (13)
  Net change in affiliated advances payable.................   (108)   1,104
                                                              -----    -----
          Net cash provided by (used in) financing
           activities.......................................   (576)      18
                                                              -----    -----
Increase in cash and cash equivalents.......................     68      190
Cash and cash equivalents
  Beginning of period.......................................    131       53
                                                              -----    -----
  End of period.............................................  $ 199    $ 243
                                                              =====    =====
</Table>

                            See accompanying notes.

                                        4
<PAGE>

                              EL PASO CGP COMPANY

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

<Table>
<Caption>
                                                               QUARTER ENDED
                                                                 MARCH 31,
                                                              ---------------
                                                              2002      2001
                                                              -----     -----
<S>                                                           <C>       <C>
Net income (loss)...........................................  $ 394     $(347)
                                                              -----     -----
Foreign currency translation adjustments....................     --        (6)
Unrealized net gains (losses) from cash flow hedging
  activity
  Cumulative-effect transition adjustment (net of tax of
     $248 million)..........................................     --      (459)
  Unrealized mark-to-market gains (losses) arising during
     period (net of tax of $70 in 2002 and $62 in 2001).....   (118)      110
  Reclassification adjustments for changes in initial value
     to settlement date (net of tax of $47 in 2002 and $97
     in 2001)...............................................    (84)      180
                                                              -----     -----
       Other comprehensive loss.............................   (202)     (175)
                                                              -----     -----
Comprehensive income (loss).................................  $ 192     $(522)
                                                              =====     =====
</Table>

                            See accompanying notes.

                                        5
<PAGE>

                              EL PASO CGP COMPANY

              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)

1. BASIS OF PRESENTATION

     Our 2001 Annual Report on Form 10-K includes a summary of our significant
accounting policies and other disclosures. You should read it in conjunction
with this Quarterly Report on Form 10-Q/A. The financial statements as of March
31, 2002, and for the quarters ended March 31, 2002 and 2001, are unaudited. The
balance sheet as of December 31, 2001, is derived from the audited balance sheet
filed in our Form 10-K. These financial statements have been prepared pursuant
to the rules and regulations of the U.S. Securities and Exchange Commission and
do not include all disclosures required by accounting principles generally
accepted in the United States. In our opinion, we have made all adjustments, all
of which are of a normal, recurring nature (except for merger-related costs and
a ceiling test charge, all discussed below), to fairly present our interim
period results. Information for interim periods may not necessarily indicate the
results of operations for the entire year due to the seasonal nature of our
businesses. The prior period information also includes reclassifications which
were made to conform to the current period presentation. These reclassifications
have no effect on our 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 recognized 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. Rather, goodwill is tested
periodically for impairment, at least on an annual basis, or whenever events or
circumstances indicate 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. Our initial
periodic tests for impairment were completed during the first quarter of 2002,
and did not indicate any impairment of our goodwill. In addition, we stopped
amortizing goodwill that would have impacted our income statement by
approximately $3 million, net of income taxes, for the quarter ended March 31,
2002. In addition, had we adopted SFAS No. 141 and 142 on January 1, 2001, for
the quarter ended March 31, 2001, we would have reported a loss before
extraordinary items of $334 million, and a net loss of $344 million.

  Asset Impairments

     On January 1, 2002, we adopted SFAS No. 144, Accounting for the Impairment
or Disposal of Long-Lived Assets. The provisions of this statement supersede
SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of. There was no initial financial statement
impact of adopting the standard.

  Price Risk Management Activities

     Accounting for Power Restructuring Activities.  Our Merchant Energy segment
conducts power contract restructuring activities that involve amending or
terminating a power plant's existing power purchase contract to eliminate the
requirement that the plant provide 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 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
Accounting for Derivatives and Hedging
                                        6
<PAGE>

Activities. 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 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, operating 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 present the restructured power contracts in our balance sheet as assets
from price risk management activities, and in our income statement, we present,
as revenues, the original adjustment that occurs when the contract is marked to
its fair value as a derivative, as well as subsequent changes in the value of
the contract. Costs associated with the restructuring activity, including
adjustments to the underlying power plant's book value and any related
intangible assets, contract termination fees and closing costs, are recorded in
our income statement as costs of products and services. During the first quarter
of 2002, we recognized revenues from power restructuring activities of $978
million and corresponding costs of products and services of $621 million related
to our Eagle Point Cogeneration restructuring transaction.

2. DIVESTITURES

     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 $7
million, net of $4 million of income taxes.

     In March 2002, we sold natural gas and oil properties to El Paso
Corporation (El Paso), our parent, and to third parties. Total proceeds from
these sales were approximately $512 million. We did not recognize a gain or loss
on the properties sold.

     In April 2002, we announced the sales of an additional $425 million of
assets, including natural gas and oil production properties and related
contracts and a natural gas gathering system.

3. MERGER-RELATED COSTS

     In January 2001, we merged with El Paso in a merger that was accounted for
as a pooling of interests. During the quarter ended March 31, 2001, we incurred
costs related to this merger consisting of the following (in millions):

<Table>
<S>                                                             <C>
Employee severance, retention and transition costs..........        $578
Transaction costs...........................................           7
Business and operational integration........................          14
Merger-related asset impairments............................         134
Other.......................................................          34
                                                                    ----
                                                                    $767
                                                                    ====
</Table>

     Employee severance, retention and transition costs include direct payments
to, and benefit costs for, severed employees and early retirees that occurred as
a result of our merger-related workforce reduction and consolidation. Following
the merger, El Paso completed an employee restructuring across all of our
operating segments, resulting in the reduction of approximately 3,200 full-time
positions through a combination of early retirements and terminations. Employee
severance costs include actual severance payments and costs for pension and
post-retirement benefits settled and curtailed under existing benefit plans as a
result of 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 severed and retired employees arising after their severance date
to transition their jobs into the ongoing workforce. 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
remainder of the charges were expensed as incurred and have been paid.

                                        7
<PAGE>

     Also included in employee severance, retention and transition costs for the
quarter ended March 31, 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 the related offices. The amounts accrued will be paid over the term
of the applicable non-cancelable lease agreements. All other costs were expensed
as incurred.

     Merger-related asset impairments relate to write-offs or write-downs of
capitalized costs for duplicate systems, redundant facilities and assets whose
value was impaired as a result of decisions on the strategic direction of our
combined operations following the merger. These charges occurred in our Merchant
Energy 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.

4. CEILING TEST CHARGE

     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. At March 31, 2002, capitalized costs exceeded this
ceiling limit by $10 million for our Brazilian full cost pool.

5. EXTRAORDINARY ITEMS

     Under an FTC order, as a result of our merger with El Paso, we sold our
Gulfstream pipeline project, our 50 percent interest in the Stingray pipeline
system and our investment in the Empire pipeline system during the first quarter
of 2001. Net proceeds from these sales were approximately $144 million, and we
recognized an extraordinary net loss of approximately $10 million, net of tax
benefits of approximately $1 million.

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, 2002
and December 31, 2001:

<Table>
<Caption>
                                                              MARCH 31,   DECEMBER 31,
                                                                2002          2001
                                                              ---------   ------------
                                                                   (IN MILLIONS)
<S>                                                           <C>         <C>
Net assets (liabilities)
  Trading price risk management activities(1)...............   $   (8)        $(23)
  Non-trading price risk management activities(2)
     Derivatives designated as hedges.......................      177          501
     Other derivatives......................................      997           --
                                                               ------         ----
                                                               $1,166         $478
                                                               ======         ====
</Table>

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

(1) Trading activities represent those that qualify for accounting under
    Emerging Issues Task Force Issue No. 98-10, Accounting for Contracts
    Involved in Energy Trading and Risk Management Activities.

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

                                        8
<PAGE>

     Other derivatives as of March 31, 2002, include derivative contracts
related to the power restructuring activities at our Eagle Point Cogeneration
power plant and at our Capital District Energy Center Cogeneration Associates
power 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.

7. INVENTORY

     Our inventory consisted of the following:

<Table>
<Caption>
                                                              MARCH 31,   DECEMBER 31,
                                                                2002          2001
                                                              ---------   ------------
                                                                   (IN MILLIONS)
<S>                                                           <C>         <C>
Refined products, crude oil and chemicals...................    $737          $576
Coal, materials and supplies and other......................     124           117
                                                                ----          ----
                                                                $861          $693
                                                                ====          ====
</Table>

8. 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 March 31, 2002. We had the following short-term borrowings and
other financing obligations:

<Table>
<Caption>
                                                              MARCH 31,    DECEMBER 31,
                                                                2002           2001
                                                              ---------    ------------
                                                                    (IN MILLIONS)
<S>                                                           <C>          <C>
Short-term credit facilities................................   $   --         $   30
Notes payable to unconsolidated affiliates..................       57             67
Current maturities of long-term debt and other financing
  obligations...............................................      913          1,310
Notes payable...............................................       39             --
Other.......................................................        3              3
                                                               ------         ------
                                                               $1,012         $1,410
                                                               ======         ======
</Table>

                                        9
<PAGE>

     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.

<Table>
<Caption>
                                                                        INTEREST                    NET      DUE
DATE                          COMPANY                 TYPE                RATE        PRINCIPAL   PROCEEDS   DATE
----                          -------                 ----              --------      ---------   --------   ----
                                                                                         (IN MILLIONS)
<S>                      <C>                 <C>                      <C>             <C>         <C>        <C>
Issuances
2002
  April                  Mohawk River        Senior secured notes         7.75%         $ 92        $ 90     2008
                         Funding IV
Retirements
2002
  March                  El Paso CGP         Long-term debt             Variable        $400                 2002
  Jan.-Mar.              Coastal Oil & Gas   Natural gas production      LIBOR +          24                 2002
                                             payment                     0.372%
  Jan.-Mar.              Various             Long-term debt              Various           7                 2002
</Table>

9. 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 under
report 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, if any, related to these lawsuits and claims are
not currently determinable.

     While the outcome of the matters discussed above 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 will have a material adverse
effect on our ongoing financial position, operating results or cash flows.

     In addition, 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 these matters, we evaluate the merits of the case,
our exposure to the matter and 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 make the necessary accruals. As new
information becomes available, our estimates may change. The impact of these
changes may have a material effect on our results of operations. As of March 31,
2002, we had reserves of approximately $81 million 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

                                        10
<PAGE>

environment of the disposal or release of specified substances at current and
former operating sites. As of March 31, 2002, we had a reserve of approximately
$273 million for expected remediation costs. In addition, we expect to make
capital expenditures for environmental matters of approximately $199 million in
the aggregate for the years 2002 through 2007. These expenditures primarily
relate to compliance with clean air regulations.

     From May 1999 to March 2001, our 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 noncompliances 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 March 31, 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 the determination of our estimated
liabilities. We presently believe that based on our existing reserves, and
information known to date, the impact of the costs associated with these CERCLA
sites will not 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. 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 the recorded
reserves are adequate. 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. The evidentiary hearing was suspended pending
ongoing attempts to settle the case.

     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

                                        11
<PAGE>

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. In April 2002, the FERC Staff
issued a notice of a public conference to be held on May 21, 2002, at which
interested parties will be given an opportunity to comment further on the NOPR.
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.

     While we cannot predict with certainty the final outcome or the timing of
the resolution of all of our rates and regulatory matters discussed above, we
believe the ultimate resolution of these issues, based on information known to
date, will not have a material adverse effect on our financial position, results
of operations or cash flows.

10. SEGMENT INFORMATION

     We segregate our business activities into four distinct operating segments:
Pipelines, Merchant Energy, Production 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. We measure segment performance using earnings before
interest expense and income taxes (EBIT). The following are our segment results
as of and for the quarters ended March 31, 2002 and 2001:

<Table>
<Caption>
                                                                  2002
                                    -----------------------------------------------------------------
                                                MERCHANT                 FIELD
                                    PIPELINES    ENERGY    PRODUCTION   SERVICES   OTHER(1)    TOTAL
                                    ---------   --------   ----------   --------   --------   -------
                                                              (IN MILLIONS)
<S>                                 <C>         <C>        <C>          <C>        <C>        <C>
Revenues from external
  customers.......................   $  256      $4,239      $  367       $ 90       $ --     $ 4,952
Intersegment revenues.............        7           1          22         11        (41)         --
Ceiling test charge...............       --          --          10         --         --          10
Operating income (loss)...........      132         397         158          5        (13)        679
EBIT..............................      178         374         160          5        (12)        705
Segment assets....................    5,309       7,281       5,670        554        617      19,431
</Table>

---------------
(1) Includes Corporate and eliminations. In 2001, we also included our retail
businesses.

<Table>
<Caption>
                                                                  2001
                                    -----------------------------------------------------------------
                                                MERCHANT                 FIELD
                                    PIPELINES    ENERGY    PRODUCTION   SERVICES   OTHER(1)    TOTAL
                                    ---------   --------   ----------   --------   --------   -------
                                                              (IN MILLIONS)
<S>                                 <C>         <C>        <C>          <C>        <C>        <C>
Revenues from external
  customers.......................   $  311      $6,616      $  441       $252      $  177    $ 7,797
Intersegment revenue..............       13         187         (12)        31        (219)        --
Merger-related costs..............       79         136          61          1         490        767
Operating income (loss)...........       61         (21)        149         24        (513)      (300)
EBIT..............................       90          27         147         24        (515)      (227)
</Table>

---------------
(1) Includes Corporate and eliminations. In 2001, we also included our retail
businesses.

                                        12
<PAGE>

     The reconciliations of EBIT to income (loss) before extraordinary items are
presented below for the quarters ended March 31:

<Table>
<Caption>
                                                              2002     2001
                                                              -----   ------
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Total EBIT..................................................  $705    $(227)
Non-affiliated interest and debt expense....................   107      124
Affiliated interest expense, net............................     3        4
Minority interest...........................................    10       14
Income taxes................................................   191      (32)
                                                              ----    -----
     Income (loss) before extraordinary items...............  $394    $(337)
                                                              ====    =====
</Table>

11. 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 these unconsolidated affiliates is presented below.

<Table>
<Caption>
                                                              2002    2001
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Operating results data
  Revenues and other income.................................  $257    $243
  Costs and expenses........................................  $204    $169
  Income from continuing operations.........................  $ 52    $ 60
  Net income................................................  $ 52    $ 60
</Table>

  Consolidation of Investments

     As of December 31, 2001, we had investments in the Eagle Point Cogeneration
Partnership, in Capital District Energy Center Cogeneration Associates and in
Mohawk River Funding IV. During 2002, we obtained additional rights from our
partners in these investments and acquired an additional one percent ownership
interest in Capital District Energy 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 $804
million at March 31, 2002, at a market rate of interest which was 1.9% and $932
million at December 31, 2001, at a market interest rate of 2.1%. In addition, we
had a demand note receivable with El Paso of $121 million at March 31, 2002,
with an interest rate of 2.4% and $120 million at December 31, 2001, with an
interest rate of 4.2%.

     At March 31, 2002, we had current accounts and notes receivable from
related parties of $202 million and $426 million at December 31, 2001. In
addition, we had a non-current note receivable from a related party of $27
million included in other non-current assets at March 31, 2002 and at December
31, 2001.

     At March 31, 2002, we had accounts and notes payable to related parties of
$402 million and $428 million at December 31, 2001. In addition, included in
short-term borrowings was a current note payable to related parties of $57
million and $67 million at March 31, 2002 and December 31, 2001.

                                        13
<PAGE>

12. 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 relating to the retirement and removal costs of
assets used in their business. The liability is discounted to its present value,
and the related asset value is increased by the amount of the resulting
liability. Over the life of the asset, the liability will be accreted to its
future value and eventually extinguished when the asset is taken out of service.
Capitalized retirement and removal costs will be depreciated over the useful
life of the related asset. The provisions of this Statement are effective for
fiscal years beginning after June 15, 2002. We are currently evaluating the
effects of this pronouncement.

  Derivatives Implementation Group Issue C-16

     In September 2001, the Derivatives Implementation Group of the FASB cleared
guidance on Issue C-16, Scope Exceptions: Applying the Normal Purchases and
Normal Sales Exception to Contracts that Combine a Forward Contract and a
Purchased Option Contract. This guidance impacts the accounting for fuel supply
contracts that require delivery of a contractual minimum quantity of a fuel
other than electricity at a fixed price and have an option that permits the
holder to take specified additional amounts of fuel at the same fixed price at
various times. We use fuel supply contracts such as these in our power producing
operations and currently do not reflect them in our balance sheet since they are
considered normal purchases that are not classified as derivative instruments
under SFAS No. 133. This guidance becomes effective in the second quarter of
2002, and we will be required to account for these contracts as derivative
instruments under SFAS No. 133. We are currently evaluating the financial impact
of this guidance on our financial statements.

                                        14
<PAGE>

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.

                             RESULTS OF OPERATIONS

     For the quarter ended March 31, 2002, we had net income of $394 million
versus a net loss of $347 million for the quarter ended March 31, 2001. The 2002
results include a ceiling test charge of $10 million, or $7 million after taxes.
The 2001 loss was a result of merger-related costs totaling $767 million, or
$590 million after taxes, related to our merger with El Paso. In addition, we
recorded net extraordinary losses totaling $10 million, net of income taxes, as
a result of FTC ordered sales of our Gulfstream pipeline project and our
investments in the Stingray and Empire pipeline systems. Net income, excluding
the after-tax effects of merger-related costs, the ceiling test charge and
extraordinary items, would have been $401 million in 2002 versus $253 million in
2001.

                                SEGMENT RESULTS

     Our four segments: Pipelines, Merchant Energy, Production 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. For a further discussion of our individual segments, see
Item 1, Financial Statements, Note 10, as well as our Annual Report on Form 10-K
for the year ended December 31, 2001.

     The segment EBIT results for the quarters ended March 31 presented below
include the charges discussed above:

<Table>
<Caption>
                                                              2002      2001
                                                              ----      -----
                                                               (IN MILLIONS)
<S>                                                           <C>       <C>
Pipelines...................................................  $178      $  90
Merchant Energy.............................................   374         27
Production..................................................   160        147
Field Services..............................................     5         24
                                                              ----      -----
  Segment total.............................................   717        288
Corporate and other, net....................................   (12)      (515)
                                                              ----      -----
  Consolidated EBIT.........................................  $705      $(227)
                                                              ====      =====
</Table>

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

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

<Table>
<S>    <C>  <C>                                              <C>    <C>  <C>
/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
</Table>

    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.

                                        15
<PAGE>

PIPELINES

     Our Pipelines segment holds our interstate transmission businesses. Results
of our Pipelines segment operations were as follows for the quarters ended March
31:

<Table>
<Caption>
                                                               2002         2001
                                                              -------      -------
                                                              (IN MILLIONS, EXCEPT
                                                                VOLUME AMOUNTS)
<S>                                                           <C>          <C>
Operating revenues..........................................   $ 263        $ 324
Operating expenses..........................................    (131)        (263)
Other income................................................      46           29
                                                               -----        -----
  EBIT......................................................   $ 178        $  90
                                                               =====        =====
Throughput volumes (BBtu/d)(1)..............................   8,037        7,717
                                                               =====        =====
</Table>

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

    (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.

     Operating revenues for the quarter ended March 31, 2002, were $61 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 and lower transportation revenues from capacity sold under short-term
contracts due to milder weather in 2002.

     Operating expenses for the quarter ended March 31, 2002, were $132 million
lower than the same period in 2001. The decrease was primarily due to
merger-related costs incurred for employee benefits and severance charges in the
first quarter of 2001 and cost efficiencies following our merger with El Paso.
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, lower benefit costs in the first quarter of 2002 and
lower amortization due to the implementation of SFAS No. 142 in 2002.

     Other income for the quarter ended March 31, 2002, was $17 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 and higher equity earnings on
Great Lakes Gas Transmission in 2002. Partially offsetting the increase was
lower equity income due to the sales of our interests in the Empire State and
Iroquois pipeline systems in the first and second quarters of 2001.

MERCHANT ENERGY

     Our Merchant Energy segment conducts our customer originations and trading
activities along with our power, refining, chemical and coal businesses and
other activities. Below are Merchant Energy's operating results and an analysis
of these results for the quarters ended March 31:

<Table>
<Caption>
                                                                2002         2001
                                                              ---------    ---------
                                                                  (IN MILLIONS,
                                                              EXCEPT VOLUME AMOUNTS)
<S>                                                           <C>          <C>
Trading and refining gross margins..........................  $    626     $    316
Operating and other revenues................................        93           99
Operating expenses..........................................      (322)        (436)
Other income (loss).........................................       (23)          48
                                                              --------     --------
  EBIT......................................................  $    374     $     27
                                                              ========     ========
</Table>

                                        16
<PAGE>

<Table>
<Caption>
                                                                2002         2001
                                                              ---------    ---------
                                                                  (IN MILLIONS,
                                                              EXCEPT VOLUME AMOUNTS)
<S>                                                           <C>          <C>
Volumes
  Physical
     Natural gas (BBtue/d)..................................        --        3,457
     Power (MMWh)...........................................        85          109
     Crude oil and refined products (MBbls).................   160,539      167,945
     Coal (MTons)...........................................     2,309        2,663
  Financial Settlements (BBtue/d)...........................    65,629       70,065
</Table>

     Trading and refining gross margins consist of revenues from commodity
trading activities, less the costs of commodities sold, the impact of power
contract restructuring activities and revenues from refineries and chemical
plants, less the cost of the feedstocks used in the refining and production
processes. For the quarter ended March 31, 2002, these gross margins were $310
million higher than the same period in 2001. The increase was due to a power
plant contract restructuring at our Eagle Point Cogeneration facility in the
first quarter of 2002 discussed below. Partially offsetting the increase were
lower refining margins resulting from lower spreads between the sales prices of
the refined product and the underlying feedstock cost, lower throughput at the
Eagle Point and Aruba refineries, the lease of our Corpus Christi refinery and
related assets to Valero in June 2001, and lower margins in heavy crude-based
refined products.

     During the first quarter of 2002, we completed a power restructuring at our
Eagle Point Cogeneration power plant. In the Eagle Point Cogeneration
restructuring, we amended the existing PURPA power sales contract with Public
Service Electric and Gas, eliminating the requirement to deliver power from the
Eagle Point Cogeneration power plant and establishing fixed prices (with stated
increases) for delivery of power over the term of the amended contract. From an
accounting standpoint, these actions required us to mark the contract to its
fair value under SFAS No. 133. As a result, we recorded non-cash revenue
representing the estimated fair value of the derivative contract of
approximately $978 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 financing
agreements, adjusted the Eagle Point Cogeneration facility to its fair value as
a peaking merchant plant and entered into an agreement with El Paso Merchant
Energy, L.P., our affiliate, to provide the power we will be required to deliver
to the utility under the restructured contract. The total cost to terminate the
transportation contract was $29 million, and we paid $103 million to the utility
to terminate the original PURPA contract. We also recorded a $98 million
non-cash charge to adjust the Eagle Point Cogeneration plant to fair value and a
non-cash charge of $230 million to write-off the book value of the original
PURPA contract. We were required to mark the contract with El Paso Merchant
Energy to its fair value as a derivative at a total non-cash cost of $81
million. Based on these amounts, and including closing and other costs, our
first quarter results reflect a one-time net benefit from the Eagle Point
Cogeneration restructuring transaction of $357 million.

     Operating and other revenues consist of revenues from both international
and domestic power generation facilities and coal operations. For the quarter
ended March 31, 2002, operating and other revenues were $6 million lower than
the same period in 2001. The decrease resulted from lower power facility
revenues resulting from the sale of a power facility to a related party in 2001,
as well as lower revenues from our coal operations resulting from decreased
volumes which were partially offset by higher realized coal prices in the first
quarter of 2002.

     Operating expenses for the quarter ended March 31, 2002, were $114 million
lower than the same period in 2001. The decrease was primarily a result of
merger-related costs recorded in the first quarter of 2001 associated with
combining operations with El Paso, lower fuel costs resulting from reduced gas
prices and the lease of our Corpus Christi refinery and related assets to Valero
in June 2001. Partially offsetting the decrease was the consolidation of several
domestic power-related entities and additional reserves recorded related to our
coal operations, both occurring in the first quarter of 2002.

     Other income for the quarter ended March 31, 2002, was $71 million lower
than the same period in 2001. The decrease was primarily the result of the
minority owners' interest in income recognized on our Eagle Point

                                        17
<PAGE>

power restructuring transaction in the first quarter of 2002, as well as lower
equity earnings resulting from the consolidation of several domestic
power-related facilities in the first quarter of 2002.

PRODUCTION

     Our Production segment conducts our natural gas and oil exploration and
production activities. Results of our Production segment operations were as
follows for the quarters ended March 31:

<Table>
<Caption>
                                                                2002        2001
                                                              ---------   ---------
                                                              (IN MILLIONS, EXCEPT
                                                               VOLUMES AND PRICES)
<S>                                                           <C>         <C>
Natural gas.................................................   $   347     $   368
Oil, condensate and liquids.................................        39          56
Other.......................................................         3           5
                                                               -------     -------
          Total operating revenues..........................       389         429
Transportation and net product costs........................       (13)        (26)
                                                               -------     -------
          Total operating margin............................       376         403
Operating expenses..........................................      (218)       (254)
Other income (loss).........................................         2          (2)
                                                               -------     -------
  EBIT......................................................   $   160     $   147
                                                               =======     =======
Volumes and prices
  Natural gas
     Volumes (MMcf).........................................    83,266      90,639
                                                               =======     =======
     Average realized price ($/Mcf).........................   $  4.05     $  4.03
                                                               =======     =======
  Oil, condensate and liquids
     Volumes (MBbls)........................................     2,694       1,914
                                                               =======     =======
     Average realized prices ($/Bbl)........................   $ 13.45     $ 29.21
                                                               =======     =======
</Table>

     Operating revenues for the quarter ended March 31, 2002, were $40 million
lower than the same period in 2001. The decrease was due to lower volumes for
natural gas and a significant decline in average realized prices for oil,
condensate and liquids in 2002 when compared to the same period of 2001.

     Transportation and net product costs for the quarter ended March 31, 2002,
were $13 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 higher transported volumes in 2002.

     Operating expenses for the quarter ended March 31, 2002, were $36 million
lower than the same period in 2001. The decrease was a result of merger-related
costs incurred in 2001 due to our merger with El Paso and lower severance and
other taxes in 2002, which are generally tied to natural gas and oil volumes and
prices. These decreases were partially offset by higher depletion expense in
2002 as a result of additions of assets to the full cost pool, a non-cash full
cost ceiling test charge of $10 million on Brazilian production properties
incurred in the current quarter, higher corporate overhead allocations and
increased oilfield services costs.

                                        18
<PAGE>

FIELD SERVICES

     Our Field Services segment conducts our midstream activities. Results of
our Field Services segment operations were as follows for the quarters ended
March 31:

<Table>
<Caption>
                                                               2002         2001
                                                              -------      -------
                                                              (IN MILLIONS, EXCEPT
                                                              VOLUMES AND PRICES)
<S>                                                           <C>          <C>
Gathering, treating and processing gross margins............  $   23       $   40
Operating expenses..........................................     (18)         (16)
                                                              ------       ------
  EBIT......................................................  $    5       $   24
                                                              ======       ======
Volume and prices
  Gathering and treating
     Volumes (BBtu/d).......................................     648          938
                                                              ======       ======
     Prices ($/MMBtu).......................................  $ 0.12       $ 0.13
                                                              ======       ======
  Processing
     Volumes (inlet BBtu/d).................................   1,663        1,946
                                                              ======       ======
     Prices ($/MMBtu).......................................  $ 0.11       $ 0.14
                                                              ======       ======
</Table>

     Total gross margins for the quarter ended March 31, 2002, were $17 million
lower than the same period in 2001. The decrease was primarily due to lower
natural gas and natural gas liquids prices in 2002. Also contributing to the
decrease was lower gathering and treating volumes in 2002 due to natural
declines in production volumes in our operating regions.

     Operating expenses for the quarter ended March 31, 2002, were $2 million
higher than the same period in 2001. The increase was primarily due to higher
depreciation expense as a result of placing assets in service in mid-2001 and
higher corporate overhead allocations, partially offset by merger-related costs
in 2001 due to our January 2001 merger with El Paso.

CORPORATE AND OTHER, NET

     Corporate and other expenses for the first quarter ended March 31, 2002,
were $503 million lower than the same period in 2001. The decrease was primarily
a result of merger-related costs in 2001 in connection with our merger with El
Paso.

NON-AFFILIATED INTEREST AND DEBT EXPENSE

     Non-affiliated interest and debt expense for the quarter ended March 31,
2002, was $17 million lower than the same period in 2001 primarily due to
retirement of short-term borrowings, consisting of commercial paper and
short-term bank credit facilities.

MINORITY INTEREST

     Minority interest expense for the quarter ended March 31, 2002, was $4
million lower than the same period in 2001 primarily due to lower average
interest rates.

                                        19
<PAGE>

INCOME TAXES

     The income tax expense for the quarter ended March 31, 2002, was $191
million, resulting in an effective tax rate of 33 percent. Our effective tax
rate was different than the statutory rate of 35 percent primarily due to the
following:

     - state income taxes; and

     - foreign income taxed at different rates.

     The income tax benefit for the quarter ended March 31, 2001, was $32
million, resulting in an effective tax rate of 9 percent. Of this amount, $105
million related to 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 was 37 percent. Other
differences between the effective rate and the statutory rate of 35 percent were
primarily due to the following:

     - state income taxes; and

     - foreign income taxed at different rates.

                         COMMITMENTS AND CONTINGENCIES

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

                 NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

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

                                        20
<PAGE>

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.

                                        21
<PAGE>

                          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.

     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.

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
          99.1           -- Certification of Financial Statements
          99.2           -- Certification of Financial Statements
</Table>

     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.

                                        22
<PAGE>

                                   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 8, 2002                               /s/ H. BRENT AUSTIN
                                            ------------------------------------
                                                      H. Brent Austin
                                                Executive Vice President and
                                            Chief Financial Officer and Director
                                               (Principal Financial Officer)

Date: August 8, 2002                              /s/ JEFFREY I. BEASON
                                            ------------------------------------
                                                     Jeffrey I. Beason
                                            Senior Vice President and Controller
                                               (Principal Accounting Officer)

                                        23
<PAGE>

                               INDEX TO EXHIBITS

<Table>
<Caption>
        EXHIBIT
         NUMBER                                  DESCRIPTION
        -------                                  -----------
<C>                      <S>
          99.1           -- Certification of Financial Statements
          99.2           -- Certification of Financial Statements
</Table>