<PAGE>

================================================================================

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

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

                                   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 1-9864

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

                         EL PASO TENNESSEE PIPELINE CO.
             (Exact Name of Registrant as Specified in its Charter)

<Table>
<S>                                            <C>
                   DELAWARE                                      76-0233548
         (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)
</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 $0.01 per share. Shares outstanding on August 14,
2002: 1,971

================================================================================
<PAGE>

                        PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

                         EL PASO TENNESSEE PIPELINE CO.

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

<Table>
<Caption>
                                                         QUARTER ENDED       SIX MONTHS ENDED
                                                            JUNE 30,             JUNE 30,
                                                        ----------------    ------------------
                                                         2002      2001      2002       2001
                                                        ------    ------    -------    -------
<S>                                                     <C>       <C>       <C>        <C>
Operating revenues....................................  $  290    $  798    $ 1,016    $ 1,835
                                                        ------    ------    -------    -------
Operating expenses
  Cost of products and services.......................      33       316        353        732
  Operation and maintenance...........................     190       179        429        372
  Restructuring and merger-related costs and asset
     impairments......................................      12        43        354         72
  Depreciation, depletion and amortization............      55        52        115        126
  Taxes, other than income taxes......................      23        18         45         42
                                                        ------    ------    -------    -------
                                                           313       608      1,296      1,344
                                                        ------    ------    -------    -------
Operating income (loss)...............................     (23)      190       (280)       491
                                                        ------    ------    -------    -------
Other income
  Earnings from unconsolidated affiliates.............      76        36         80         57
  Other, net..........................................      21        50         31         74
                                                        ------    ------    -------    -------
                                                            97        86        111        131
                                                        ------    ------    -------    -------
Income (loss) before interest, income taxes and other
  charges.............................................      74       276       (169)       622
                                                        ------    ------    -------    -------
Non-affiliated interest and debt expense..............      32        37         71         78
Affiliated interest expense, net......................      25        44         43        109
Minority interest.....................................       6        --         12         --
Income taxes..........................................       3        75        (99)       147
                                                        ------    ------    -------    -------
                                                            66       156         27        334
                                                        ------    ------    -------    -------
Income (loss) before extraordinary items and
  cumulative effect of accounting change..............       8       120       (196)       288
Extraordinary items, net of income taxes..............      --        38         --         38
Cumulative effect of accounting change, net of income
  taxes...............................................      --        --         97         --
                                                        ------    ------    -------    -------
Net income (loss).....................................  $    8    $  158    $   (99)   $   326
                                                        ======    ======    =======    =======
</Table>

                            See accompanying notes.

                                        1
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

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

<Table>
<Caption>
                                                              JUNE 30,   DECEMBER 31,
                                                                2002         2001
                                                              --------   ------------
<S>                                                           <C>        <C>
                                       ASSETS
Current assets
  Cash and cash equivalents.................................  $   125      $   197
  Accounts and notes receivable, net
     Customer...............................................    3,140        2,723
     Affiliates.............................................      379          271
     Other..................................................      430          600
  Inventory.................................................       37           79
  Assets from price risk management activities..............    1,587        2,529
  Margin deposits on energy trading activities..............      714          379
  Other.....................................................      395          318
                                                              -------      -------
          Total current assets..............................    6,807        7,096
                                                              -------      -------
Property, plant and equipment, at cost
  Pipelines.................................................    2,895        2,824
  Gathering and processing systems..........................      919        2,199
  Power facilities..........................................      595          563
  Other.....................................................       99           99
                                                              -------      -------
                                                                4,508        5,685
Less accumulated depreciation, depletion and amortization...      964        1,040
                                                              -------      -------
                                                                3,544        4,645
Additional acquisition costs assigned to utility plant,
  net.......................................................    2,254        2,271
                                                              -------      -------
          Total property, plant and equipment, net..........    5,798        6,916
                                                              -------      -------
Other assets
  Notes receivable from unconsolidated affiliates...........      276          295
  Investments in unconsolidated affiliates..................    2,385        2,825
  Assets from price risk management activities..............    2,583        2,156
  Other.....................................................      623          707
                                                              -------      -------
                                                                5,867        5,983
                                                              -------      -------
          Total assets......................................  $18,472      $19,995
                                                              =======      =======
</Table>

                            See accompanying notes.

                                        2
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

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

<Table>
<Caption>
                                                              JUNE 30,   DECEMBER 31,
                                                                2002         2001
                                                              --------   ------------
<S>                                                           <C>        <C>
                        LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
  Accounts payable
     Trade..................................................  $ 3,171      $ 2,927
     Affiliates.............................................      398          533
     Other..................................................      135          308
  Short-term borrowings and other financing obligations.....      445          567
  Notes payable to unconsolidated affiliates................    2,612        2,399
  Liabilities from price risk management activities.........    1,656        2,089
  Margin deposits from customers on energy trading
     activities.............................................       11          649
  Other.....................................................      500          557
                                                              -------      -------
          Total current liabilities.........................    8,928       10,029
                                                              -------      -------
Long-term debt and other financing obligations..............    1,688        1,563
                                                              -------      -------
Other liabilities
  Liabilities from price risk management activities.........    1,462        1,236
  Deferred income taxes.....................................    1,765        1,971
  Other.....................................................      887          996
                                                              -------      -------
                                                                4,114        4,203
                                                              -------      -------
Commitments and contingencies
Minority interests..........................................      355          356
                                                              -------      -------
Stockholders' equity
  Preferred stock, authorized; 20,000,000 shares Series A,
     no par; issued 6,000,000 shares; stated at liquidation
     value..................................................      300          300
  Common stock, par value $0.01 per share; authorized
     100,000 shares; issued 1,971 shares....................       --           --
  Additional paid-in capital................................    1,992        1,973
  Retained earnings.........................................    1,199        1,641
  Accumulated other comprehensive income (loss).............     (104)         (70)
                                                              -------      -------
          Total stockholders' equity........................    3,387        3,844
                                                              -------      -------
          Total liabilities and stockholders' equity........  $18,472      $19,995
                                                              =======      =======
</Table>

                            See accompanying notes.

                                        3
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

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

<Table>
<Caption>
                                                               SIX MONTHS ENDED
                                                                   JUNE 30,
                                                              ------------------
                                                              2002        2001
                                                              -----      -------
<S>                                                           <C>        <C>
Cash flows from operating activities
  Net income (loss).........................................  $ (99)     $   326
  Adjustments to reconcile net income (loss) to net cash
     from operating activities
     Non-cash gains from trading and power activities.......    (38)        (347)
     Non-cash portion of merger-related costs and asset
      impairments...........................................    342           38
     Depreciation, depletion and amortization...............    115          126
     Undistributed earnings of unconsolidated affiliates....    (48)         (10)
     Deferred income tax expense (benefit)..................   (121)         160
     Extraordinary items....................................     --          (59)
     Cumulative effect of accounting change.................    (97)          --
     Other non-cash income items............................     42          (11)
  Working capital changes...................................   (581)       3,115
  Non-working capital changes and other.....................    (18)        (146)
                                                              -----      -------
          Net cash provided by (used in) operating
           activities.......................................   (503)       3,192
                                                              -----      -------
Cash flows from investing activities
  Additions to property, plant and equipment................   (195)        (252)
  Net proceeds from the sale of assets......................    275          246
  Additions to investments..................................    (20)        (219)
  Net proceeds from investments.............................     29            5
  Cash deposited in escrow..................................    (84)        (133)
  Return of cash deposited in escrow........................     11           --
  Net change in other affiliated advances receivable........     94           --
  Repayment of notes receivable from unconsolidated
     affiliates.............................................     13           13
  Other.....................................................      1           --
                                                              -----      -------
          Net cash provided by (used in) investing
           activities.......................................    124         (340)
                                                              -----      -------
Cash flows from financing activities
  Net repayments of commercial paper........................    (61)         (47)
  Payments to retire long-term debt.........................     (2)        (364)
  Net proceeds from the issuance of long-term debt..........    238           --
  Net change in other affiliated advances payable...........    214       (2,406)
  Repayment of notes payable................................    (11)          --
  Decrease in notes payable to unconsolidated affiliates....     --           (9)
  Dividends paid............................................    (71)         (12)
                                                              -----      -------
          Net cash provided by (used in) financing
           activities.......................................    307       (2,838)
                                                              -----      -------
Increase (decrease) in cash and cash equivalents............    (72)          14
Cash and cash equivalents
  Beginning of period.......................................    197          179
                                                              -----      -------
  End of period.............................................  $ 125      $   193
                                                              =====      =======

</Table>

                            See accompanying notes.

                                        4
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

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

<Table>
<Caption>
                                                              QUARTER ENDED     SIX MONTHS ENDED
                                                                 JUNE 30,           JUNE 30,
                                                              --------------    ----------------
                                                              2002     2001      2002      2001
                                                              -----    -----    ------    ------
<S>                                                           <C>      <C>      <C>       <C>
Net income (loss)...........................................  $  8     $158     $ (99)    $ 326
                                                              ----     ----     -----     -----
Foreign currency translation adjustments....................     4      (12)        4       (20)
Unrealized net gains (losses) from cash flow hedging
  activity
  Cumulative-effect transition adjustment (net of tax of
     $66)...................................................    --       --        --      (154)
  Unrealized mark-to-market losses arising during period
     (net of tax of $25 and $28 in 2002 and $84 and $61 in
     2001)..................................................   (32)     195       (41)      (88)
  Reclassification adjustments for changes in initial value
     to settlement date (net of tax of $10 and $6 in 2002
     and $71 and $132 in 2001)..............................    11      110         3       226
                                                              ----     ----     -----     -----
       Other comprehensive income (loss)....................   (17)     293       (34)      (36)
                                                              ----     ----     -----     -----
Comprehensive income (loss).................................  $ (9)    $451     $(133)    $ 290
                                                              ====     ====     =====     =====
</Table>

                            See accompanying notes.

                                        5
<PAGE>

                         EL PASO TENNESSEE PIPELINE CO.

              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 (SEC).
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 and 4), 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 stockholders' 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 required 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. SFAS No. 141
requires that any negative goodwill should be written off as a cumulative effect
of an accounting change. 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. As a result of our adoption of these standards on
January 1, 2002, we stopped amortizing goodwill, and recognized a pretax and
after-tax gain of $97 million related to the write-off of negative goodwill. We
have reported this gain as a cumulative effect of an accounting change in our
income statement.

     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 and negative goodwill would have been approximately $2
million and $4 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 net income of $160 million and $330 million for the
quarter and six months ended June 30, 2001.

  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. There was no initial
financial statement impact of adopting this statement.

  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
                                        6
<PAGE>

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 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. There was no initial
financial statement impact of adopting this standard.

     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 stockholders' equity. Revenues and
costs that have been netted as a result of adopting this consensus were as
follows:

<Table>
<Caption>
                                                         QUARTER ENDED      SIX MONTHS ENDED
                                                           JUNE 30,             JUNE 30,
                                                       -----------------   -------------------
                                                        2002      2001       2002       2001
                                                       -------   -------   --------   --------
                                                                    (IN MILLIONS)
<S>                                                    <C>       <C>       <C>        <C>
     Gross operating revenues........................  $ 9,158   $ 8,314   $ 17,431   $ 18,496
     Costs reclassified..............................   (8,868)   (7,516)   (16,415)   (16,661)
                                                       -------   -------   --------   --------
          Net operating revenues reported in the
            income statement.........................  $   290   $   798   $  1,016   $  1,835
                                                       =======   =======   ========   ========
</Table>

     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.

2. DIVESTITURES

     In March 2001, we sold natural gas liquids transportation and fractionation
assets acquired in our December 2000 acquisition of Pacific Gas & Electric's
(PG&E's) midstream operations to our affiliate, El Paso Energy Partners, L.P., a
publicly traded master limited partnership, for approximately $133 million.

     In April 2002, we sold midstream assets for approximately $265 million to
one of our affiliates, El Paso Energy Partners. Net proceeds from this sale were
approximately $259 million in cash, and common units of El Paso Energy Partners
with a fair value of $6 million. No gain or loss was recognized on this sale.

     In July 2002, our parent entered into a letter of intent with El Paso
Energy Partners to sell our onshore and offshore natural gas and oil gathering
systems, natural gas liquids transportation and fractionation assets. We stopped
depreciating these assets beginning in July 2002 since these assets are held for
sale.

                                        7
<PAGE>

3. RESTRUCTURING AND MERGER-RELATED COSTS AND ASSET IMPAIRMENTS

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

<Table>
<Caption>
                                                        QUARTER ENDED     SIX MONTHS ENDED
                                                           JUNE 30,           JUNE 30,
                                                        --------------    ----------------
                                                        2002     2001     2002       2001
                                                        -----    -----    -----      -----
                                                                  (IN MILLIONS)
<S>                                                     <C>      <C>      <C>        <C>
Restructuring costs...................................   $12      $--     $ 12        $--
Merger-related costs..................................    --        5       --         34
Asset impairments.....................................    --       38      342         38
                                                         ---      ---     ----        ---
          Total.......................................   $12      $43     $354        $72
                                                         ===      ===     ====        ===
</Table>

  Restructuring Costs

     In December 2001, El Paso Corporation (El Paso), our parent, announced a
plan to strengthen its balance sheet, reduce costs and focus its activities on
its core natural gas businesses. In May 2002, we completed an employee
restructuring across all our operating segments which resulted in a reduction of
approximately 208 full-time positions through terminations. In connection with
this, we incurred $12 million of employee severance and termination costs. As of
June 30, 2002, we had paid $7 million of this charge, and the remainder will be
paid in the third quarter of 2002. Employee severance costs included severance
payments and costs for pension benefits settled and curtailed under existing
benefit plans.

  Merger-related Costs

     During the periods ended June 30, 2001, we incurred merger-related costs
associated with El Paso merger with The Coastal Corporation as follows:

<Table>
<Caption>
                                                         QUARTER ENDED    SIX MONTHS ENDED
                                                         JUNE 30, 2001     JUNE 30, 2001
                                                         -------------    ----------------
                                                                   (IN MILLIONS)
<S>                                                      <C>              <C>
Employee severance, retention and transition costs.....       $1                $ 5
Make-whole commitments.................................        4                 25
Other..................................................       --                  4
                                                              --                ---
                                                              $5                $34
                                                              ==                ===
</Table>

     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 El Paso's merger-related workforce reduction and consolidation.
The amount of employee severance, retention and transaction costs paid and
charged against the accrued amount for the six months ended June 30, 2001 was
approximately $5 million. Make-whole commitments relate to a series of payments
we will make to El Paso Energy Partners in connection with the Federal Trade
Commission's (FTC) ordered divestiture of interests in assets owned by the
partnership.

  Asset Impairments

     During the first quarter of 2002, we recognized an asset impairment charge
in our Merchant Energy segment of $342 million related to our investments in
Argentina. During the latter part of 2001, economic conditions in Argentina
deteriorated, and the Argentine government defaulted on its public debt
obligations. In the first quarter of 2002, the government changed several
Argentine laws, including:(i) repealing the one-to-one exchange rate for the
Argentine Peso with U.S. dollar; (ii) mandating that all Argentine contracts and
obligations previously denominated in U.S. dollars be re-negotiated and
denominated in Argentine Pesos; and (iii) imposing a tax on crude oil exports.
The Argentine Peso devaluation combined with these new law changes effectively
converted our projects' contracts and sources of revenue from U.S. dollars to
Argentine Pesos and resulted in the impairment charge, which represents the full
amount of each of the investments

                                        8
<PAGE>

impacted by these law changes. We have a remaining investment in a pipeline
project in Argentina with an aggregate investment of approximately $39 million.
Should these conditions persist, or if new unfavorable developments occur, we
may also be required to evaluate our remaining investment for impairment. We
continue to monitor the situation closely, including our rights and remedies
under applicable law, treaties and political risk policies arising from the
emergency measures taken in Argentina.

     During the second quarter of 2001, we incurred an asset impairment charge
of $38 million resulting from Merchant Energy's impairment of its East Asia
Power investment in the Philippines. This write-down was a result of weak
economic conditions causing a permanent decline in the value of our investment.
We continue to hold this investment.

4. EXTRAORDINARY ITEMS

     As a result of El Paso's merger with Coastal in January 2001, we were
required by the FTC to sell our Midwestern Gas Transmission system. We completed
this sale in April 2001. Net proceeds were approximately $95 million, and we
recognized an extraordinary gain of $38 million, net of income taxes of $21
million.

5. 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:

<Table>
<Caption>
                                                              JUNE 30,    DECEMBER 31,
                                                                2002          2001
                                                              --------    ------------
                                                                   (IN MILLIONS)
<S>                                                           <C>         <C>
Net assets(1)
  Trading contracts(2)......................................   $1,051        $1,337
  Non-trading contracts.....................................        1            23
                                                               ------        ------
                                                               $1,052        $1,360
                                                               ======        ======
</Table>

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

(1) 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.

(2) 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.

6. INVENTORY

     Our inventory consisted of the following:

<Table>
<Caption>
                                                              JUNE 30,   DECEMBER 31,
                                                                2002         2001
                                                              --------   ------------
                                                                   (IN MILLIONS)
<S>                                                           <C>        <C>
Materials and supplies and other............................    $36          $38
Natural gas in storage......................................      1           41
                                                                ---          ---
                                                                $37          $79
                                                                ===          ===
</Table>

                                        9
<PAGE>

7. DEBT AND OTHER CREDIT FACILITIES

     At June 30, 2002, our weighted average interest rate on our commercial
paper and short-term borrowings was 2.6% and at December 31, 2001, it was 3.2%.
We had the following short-term borrowings and other financing obligations:

<Table>
<Caption>
                                                              JUNE 30,    DECEMBER 31,
                                                                2002          2001
                                                              --------    ------------
                                                                   (IN MILLIONS)
<S>                                                           <C>         <C>
Commercial paper............................................    $363          $424
Notes payable...............................................      64            75
Current maturities of long-term debt and other financing
  obligations...............................................      18            68
                                                                ----          ----
                                                                $445          $567
                                                                ====          ====
</Table>

     During the first quarter of 2002, we distributed several of our midstream
business entities which had $180 million of long-term debt to El Paso.

     In May 2002, El Paso renewed its $3 billion, 364-day revolving credit and
competitive advance facility. Tennessee Gas Pipeline Company (TGP), our
subsidiary, remains a designated borrower under this facility and, as such, is
liable for any amounts outstanding under this facility. This facility matures in
May 2003. 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, and TGP is a designated borrower under this facility
and, as such, is liable for any amounts outstanding under this facility. The
interest rate under both of these facilities 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 $1
billion facility.

     In June 2002, TGP issued $240 million aggregate principal amount 8.375%
notes due 2032. Proceeds were approximately $238 million, net of issuance costs.
As a result, TGP has no remaining capacity under its shelf registration
statement on file with the SEC.

8. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     Several of our subsidiaries and affiliates were named defendants in eleven
purported class action, municipal or individual lawsuits, filed in California
state courts (a list of the California cases is included in Part II, Item 1,
Legal Proceedings). The eleven suits contend that El Paso entities acted
improperly to limit the construction of new pipeline capacity to California
and/or to manipulate the price of natural gas sold into the California
marketplace. The lawsuits have been consolidated before a single judge and are
at the preliminary pleading stages, with trial not anticipated until late 2003
at the earliest.

     In September 2001, we received a civil document subpoena from the
California Department of Justice, seeking information said to be relevant to the
Department's ongoing investigation into the high electricity prices in
California. We have produced and expect to continue to produce materials under
this subpoena.

     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.

                                        10
<PAGE>

     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 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 totaling $26 million for all outstanding
legal matters.

     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 $118 million for
expected remediation costs (including related environmental litigation). In
addition, we expect to make capital expenditures for environmental matters of
approximately $69 million in the aggregate for the years 2002 through 2007.
These expenditures primarily relate to compliance with clean air regulations.

     Since 1988, TGP has been engaged in an internal project to identify and
deal with the presence of polychlorinated biphenyls (PCBs) and other substances,
including those on the Environmental Protection Agency's (EPA) List of Hazardous
Substances, at compressor stations and other facilities it operates. While
conducting this project, TGP has been in frequent contact with federal and state
regulatory agencies, both through informal negotiation and formal entry of
consent orders, to ensure that its efforts meet regulatory requirements. TGP
executed a consent order in 1994 with the EPA, governing the remediation of the
relevant compressor stations and is working with the EPA, and the relevant
states regarding those remediation activities. TGP is also working with the
Pennsylvania and New York environmental agencies regarding remediation and
post-remediation activities at the Pennsylvania and New York stations.

     In November 1988, the Kentucky environmental agency filed a complaint in a
Kentucky state court alleging that TGP discharged pollutants into the waters of
the state and disposed of PCBs without a permit. The agency sought an injunction
against future discharges, an order to remediate or remove PCBs and a civil
penalty. TGP entered into agreed orders with the agency to resolve many of the
issues raised in the complaint and received water discharge permits from the
agency for its Kentucky compressor stations. The relevant Kentucky compressor
stations are being characterized and remediated under the 1994 consent order
with the EPA. Despite these remediation efforts, the agency may raise additional
technical issues or require additional remediation work in the future.

     In May 1995, following negotiations with its customers, TGP filed an
agreement with the Federal Energy Regulatory Commission (FERC) that established
a mechanism for recovering a substantial portion of the environmental costs
identified in its internal remediation project. The agreement, which was
approved by the FERC in November 1995, provided for a PCB surcharge on firm and
interruptible customers' rates to pay for eligible costs under the PCB
remediation project, with these surcharges to be collected over a defined
collection period. TGP has twice received approval from the FERC to extend the
collection period, which is

                                        11
<PAGE>

now currently set to expire in June 2004. The agreement also provided for
bi-annual audits of eligible costs. As of June 30, 2002, TGP has over-collected
PCB costs by approximately $113 million for which it has established a
non-current liability. The over-collection will be reduced by future eligible
costs incurred for the remainder of the remediation project. TGP is required to
refund to its customers the over-collection amount to the extent actual eligible
expenditures are less than amounts collected. Presently, TGP estimates the
future refund obligation, at the conclusion of the remediation process, to be
approximately $50 million.

     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 6 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 $1 million and $2 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 determining of 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 April 2000, the California Public Utilities Commission (CPUC) filed a
complaint with the FERC alleging that the sale of approximately 1.2 billion
cubic feet per day of California capacity by El Paso Natural Gas Company (EPNG),
our affiliate, to El Paso Merchant Energy Company, our subsidiary, was
anticompetitive and an abuse of the affiliate relationship under the FERC's
policies. Other parties in the proceeding requested that Merchant Energy pay
back any profits it earned under the contract. In March 2001, the FERC
established a hearing, before an administrative law judge, to address the issue
of whether EPNG and/or Merchant Energy had market power and, if so, had
exercised it. In October 2001, a FERC administrative law judge issued a proposed
decision finding that El Paso did not exercise market power and that the market
power portion of the CPUC's complaint should be dismissed. However, the decision
did find that El Paso had violated the FERC's marketing affiliate regulations.
In October 2001, the Market Oversight and Enforcement section of the FERC's
Office of the General Counsel filed comments in this proceeding stating that
record development at the trial was inadequate to conclude that EPNG and
Merchant Energy complied with the FERC's regulations. In December 2001, the FERC
remanded the proceeding to the administrative law judge for a supplemental
hearing on the availability of EPNG's pipeline capacity. The hearing commenced
on March 21, 2002, and concluded on April 4, 2002. Oral arguments were held on
April 10, 2002. A post-hearing briefing was completed on June 5, 2002, and an
administrative law judge's ruling is expected soon.

     In September 2001, the FERC issued a Notice of Proposed Rulemaking (NOPR).
The NOPR proposes to apply the standards of conduct governing the relationship
between interstate pipelines and marketing affiliates to all energy affiliates.
The proposed regulations, if adopted by the FERC, would dictate how all our
                                        12
<PAGE>

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's 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 rate transactions. Our pipeline has 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.

     In June 2001, the Western Australia regulators issued a draft rate decision
at lower than expected levels of rates for the Dampier-to-Bunbury pipeline owned
by EPIC Energy Australia Trust, in which we have a 33 percent ownership interest
and a total investment, including financial guarantees, of approximately $198
million. EPIC Energy Australia has appealed a variety of issues related to the
draft decision to the Western Australia Supreme Court. The appeal was heard at
the Western Australia Supreme Court in November 2001, and a decision from the
court is expected in the second half of 2002. If the draft decision rates are
implemented, the new rates will adversely impact future operating results,
liquidity and debt capacity, possibly reducing the value of our investment by up
to $138 million. Additionally, EPIC Energy (WA) Nominees Pty. Ltd. has debt of
approximately AUD$1.8 billion (U.S.$1 billion) maturing in March 2003. Possible
delays in the timing of the Supreme Court decision and uncertainty of the future
rates may impact this refinancing.

     El Paso Merchant Energy L.P. (EPME), our subsidiary, responded on May 22,
2002 to the FERC's May 8, 2002 request for statements of admission or denial
with respect to trading strategies designed to manipulate California power
markets. EPME provided an affidavit stating that it had not engaged in these
trading strategies.

     On May 21 and 22, 2002, the FERC issued additional data requests, including
requests for statements of admission or denial with respect to so-called "wash"
or "round trip" trades in western power and gas markets. In May and June 2002,
EPME responded, denying that it had conducted any wash or round trip trades,
(i.e.,

                                        13
<PAGE>

simultaneous, prearranged trades entered into for the purpose of artificially
inflating trading volumes or revenues, or manipulating prices.)

     On June 7, 2002, we received an informal inquiry from the SEC regarding the
issue of round trip trades. Although we do not believe any round trip trades
occurred, we submitted data to the SEC on July 15, 2002. On July 12, 2002, we
received a grand jury subpoena for documents concerning round trip or wash
trades. We are conducting due diligence and plan to cooperate fully with these
requests.

     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 Commercial Commitments

     In 2001, we entered into agreements to time-charter four separate ships to
secure transportation for our developing liquefied natural gas business. In May
2002, we entered into amendments to three of the initial four time charters to
reconfigure the ships with onboard regasification technology and to secure an
option for an additional time charter for a fifth ship. The exercise of the
option for the fifth ship will represent a commitment of $522 million over the
term of such charter. However, we are obligated to pay a termination fee of $24
million in the event the option is not exercised by April 2003. The agreements
provide for deliveries of vessels between 2003 and 2005. Each time charter has a
twenty-year term commencing when the vessels are delivered with the possibility
of two five-year extensions. The total commitment under the five time-charter
agreements is approximately $2.5 billion over the term of the time charters. We
are party to an agreement with an unaffiliated global integrated oil and gas
company under which the third party agrees to bear 50 percent of the risk
incidental to the initial $1.8 billion commitment made for the first four time
charters.

  Other Matters

     In December 2001, Enron Corp. and a number of its subsidiaries, including
Enron North America Corp. and Enron Power Marketing, Inc., filed for Chapter 11
bankruptcy protection in the United States Bankruptcy Court for the Southern
District of New York. We, through our subsidiaries, had contracts with Enron
North America and Enron Power Marketing for the trading of physical gas, power,
petroleum and financial derivatives and for transportation capacity on our
pipeline systems. We established reserves for potential losses related to the
receivables from our transportation contracts that we believe are adequate. In
addition, we have terminated most of our trading-related contracts, and Enron
has rejected many of its capacity contracts on our pipeline systems. We believe
our termination of the trading contracts was proper and in accordance with the
terms of these contracts. We, like other creditors, are discussing with Enron
the extent of our damage claims against various Enron entities.

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

     We have investments in power, pipeline and production projects in Brazil.
During the second quarter of 2002, Brazil experienced a significant decline in
its financial markets due largely to concerns over the refinancing of Brazil's
foreign debt and the upcoming presidential election. These concerns have
contributed to higher interest rates on local debt for the government and
private sectors, have significantly decreased the availability of funds from
lenders outside of Brazil and have decreased the amount of foreign investment in
the country. These factors have contributed to a downgrade of Brazil's foreign
currency debt rating and a 22% devaluation of the local currency against the
U.S. dollar during the second quarter of 2002. These developments are likely to
delay the implementation of project financings underway in Brazil. The
International Monetary Fund recently announced a $30 billion loan package for
Brazil, however the release of
                                        14
<PAGE>

the majority of the money will depend on Brazil committing to specified fiscal
targets in 2003. We currently believe that the economic difficulties in Brazil
will not have a material adverse effect on our financial position, results of
operations or cash flows. However, we will continue to monitor the economic
situation, and it is possible that future developments in Brazil could cause us
to reassess our exposure.

9. SEGMENT INFORMATION

     We segregate our business activities into three distinct operating
segments: Pipelines, 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. We measure segment performance using earnings before
interest and income taxes (EBIT). The following are our segment results as of
and for the periods ended June 30:

<Table>
<Caption>
                                                             QUARTER ENDED JUNE 30, 2002
                                                 ----------------------------------------------------
                                                             MERCHANT    FIELD
                                                 PIPELINES    ENERGY    SERVICES   OTHER(1)    TOTAL
                                                 ---------   --------   --------   --------   -------
                                                                    (IN MILLIONS)
<S>                                              <C>         <C>        <C>        <C>        <C>
Revenues from external customers...............   $  147     $    84(2)   $ 59       $ --     $   290
Intersegment revenues..........................       19         (27)(2)     15        (7)         --
Restructuring costs............................       --          11         1         --          12
Operating income (loss)........................       59         (73)       11        (20)        (23)
EBIT...........................................       66          (1)       17         (8)         74
</Table>

<Table>
<Caption>
                                                             QUARTER ENDED JUNE 30, 2001
                                                -----------------------------------------------------
                                                            MERCHANT      FIELD
                                                PIPELINES    ENERGY      SERVICES   OTHER(1)   TOTAL
                                                ---------   --------     --------   --------   ------
                                                                    (IN MILLIONS)
<S>                                             <C>         <C>          <C>        <C>        <C>
Revenues from external customers..............    $151       $ 298(2)      $348       $  1     $  798
Intersegment revenues.........................      19         (75)(2)       61         (5)        --
Merger-related costs and asset impairments....      --          39            4         --         43
Operating income..............................      65          92           25          8        190
EBIT..........................................      72         176           20          8        276
</Table>

<Table>
<Caption>
                                                           SIX MONTHS ENDED JUNE 30, 2002
                                                -----------------------------------------------------
                                                            MERCHANT      FIELD
                                                PIPELINES    ENERGY      SERVICES   OTHER(1)   TOTAL
                                                ---------   --------     --------   --------   ------
                                                                    (IN MILLIONS)
<S>                                             <C>         <C>          <C>        <C>        <C>
Revenues from external customers..............    $315       $ 427(2)      $273       $  1     $1,016
Intersegment revenues.........................      39        (195)(2)      167        (11)        --
Restructuring costs and asset impairments.....      --         353            1         --        354
Operating income (loss).......................     135        (427)          31        (19)      (280)
EBIT..........................................     147        (353)          44         (7)      (169)
</Table>

<Table>
<Caption>
                                                           SIX MONTHS ENDED JUNE 30, 2001
                                                -----------------------------------------------------
                                                            MERCHANT      FIELD
                                                PIPELINES    ENERGY      SERVICES   OTHER(1)   TOTAL
                                                ---------   --------     --------   --------   ------
                                                                    (IN MILLIONS)
<S>                                             <C>         <C>          <C>        <C>        <C>
Revenues from external customers..............    $350       $ 739(2)      $745       $  1     $1,835
Intersegment revenues.........................      39        (154)(2)      138        (23)        --
Merger-related costs and asset impairments....       1          39           32         --         72
Operating income..............................     176         283           23          9        491
EBIT..........................................     185         407           21          9        622
</Table>

---------------
(1) Includes Corporate and eliminations.

(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.

                                        15
<PAGE>

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

<Table>
<Caption>
                                                            QUARTER ENDED     SIX MONTHS ENDED
                                                              JUNE 30,            JUNE 30,
                                                            -------------     ----------------
                                                            2002     2001      2002      2001
                                                            ----     ----     ------     -----
                                                                      (IN MILLIONS)
<S>                                                         <C>      <C>      <C>        <C>
Total EBIT................................................  $74      $276     $(169)     $622
Non-affiliated interest and debt expense..................   32        37        71        78
Affiliated interest expense, net..........................   25        44        43       109
Minority interest.........................................    6        --        12        --
Income taxes..............................................    3        75       (99)      147
                                                            ---      ----     -----      ----
     Income (loss) before extraordinary items and
       cumulative effect of accounting change.............  $ 8      $120     $(196)     $288
                                                            ===      ====     =====      ====
</Table>

<Table>
<Caption>
                                                              JUNE 30,   DECEMBER 31,
                                                                2002         2001
                                                              --------   ------------
<S>                                                           <C>        <C>
Pipelines...................................................  $ 5,132      $ 5,047
Merchant Energy.............................................   12,009       11,994
Field Services..............................................      855        2,517
Other.......................................................      476          437
                                                              -------      -------
     Total segment assets...................................  $18,472      $19,995
                                                              =======      =======
</Table>

10. 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 a net loss of less than $1 million and $2 million for the quarter and six
months ended June 30, 2002 and net income of less than $1 million for the
quarter and six months ended June 30, 2001.

<Table>
<Caption>
                                                             QUARTER ENDED     SIX MONTHS ENDED
                                                               JUNE 30,            JUNE 30,
                                                             -------------     -----------------
                                                             2002     2001      2002       2001
                                                             ----     ----     ------     ------
                                                                        (IN MILLIONS)
<S>                                                          <C>      <C>      <C>        <C>
Operating results data
  Operating revenues.......................................  $286     $215      $465       $433
  Operating expenses.......................................   197      139       301        266
  Income from continuing operations........................    76       36        73         62
  Net income...............................................    76       36        73         54
</Table>

  El Paso Energy Partners

     In March 2001, we sold natural gas liquids transportation and fractionation
assets acquired in our December 2000 acquisition of PG&E's Texas midstream
operations to El Paso Energy Partners, for approximately $133 million.

     In April 2002, we sold midstream assets for approximately $265 million to
El Paso Energy Partners. Net proceeds from this sale were approximately $259
million in cash, and common units of El Paso Energy Partners with a fair value
of $6 million. No gain or loss was recognized on this sale.

     We are in the process of selling onshore and offshore natural gas and oil
gathering systems, natural gas liquids transportation and fractionation assets
to El Paso Energy Partners. See Note 2 for further discussion. This proposed
sale has been approved by both our parent's and El Paso Energy Partners' Board
of Directors which included the approval of El Paso Energy Partners' special
conflicts committee. There were also fairness opinions on the transaction. This
transaction is subject to customary regulatory review and approval. The closing
of the sale is anticipated by the end of 2002.

                                        16
<PAGE>

  Other

     We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of its participating affiliates, thus
minimizing total borrowings from outside sources. We had net borrowings of
$2,556 million at June 30, 2002, at a market rate of interest which was 1.9% and
$2,364 million at December 31, 2001, at a market interest rate of 2.1%. In
addition, we had demand note receivables with El Paso of $54 million at June 30,
2002, with interest rates that ranged from 2.4% to 2.5% and $40 million at
December 31, 2001, with interest rates that ranged from 2.7% to 3.1%. We also
had a note payable to El Paso of $56 million and $35 million at June 30, 2002
and December 31, 2001, at a current market rate.

     At June 30, 2002 and December 31, 2001, we had current accounts and notes
receivable from other related parties of $325 million and $231 million. In
addition, we had current accounts payable to other related parties of $398
million and $533 million at June 30, 2002 and December 31, 2001. These balances
arose in the normal course of business.

     In January 2002, El Paso contributed gathering and processing assets to us
with a net book value of $19 million. In March 2002, we distributed through a
dividend to El Paso, a majority of our Texas midstream operations at their net
book value of $330 million.

11. 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 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.

                                        17
<PAGE>

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

     The information contained in Item 2 updates, and you should read it in
conjunction with, information disclosed in our Annual Report on Form 10-K filed
March 25, 2002, in addition to the financial statements and notes presented in
Item 1, Financial Statements, of this Quarterly Report on Form 10-Q.

     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>
Btu       =   British thermal unit
BBtu/d    =   billion British thermal units per
              day
BBtue/d   =   billion British thermal unit
              equivalents per day
MBbls     =   thousand barrels
MMBtu     =   million British thermal units
MMcf      =   million cubic feet
MMWh      =   thousand megawatt hours
</Table>

                              RECENT DEVELOPMENTS

     In December 2001, El Paso announced a plan to strengthen its capital
structure and enhance its liquidity. In May 2002, El Paso also announced a plan
to limit its investment in, and exposure to energy trading and to focus its
activities and investment in its core natural gas businesses. A key component of
these plans impacts our Merchant operations in that working capital and credit
limits will now be implemented on our trading business.

     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 our contracts 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
restructuring and 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):

<Table>
<Caption>
                                                                      QUARTER ENDED JUNE 30,
                                               ---------------------------------------------------------------------
                                                             2002                                2001
                                               ---------------------------------   ---------------------------------
                                               REPORTED   CHARGES(1)   PRO-FORMA   REPORTED   CHARGES(1)   PRO-FORMA
                                               --------   ----------   ---------   --------   ----------   ---------
<S>                                            <C>        <C>          <C>         <C>        <C>          <C>
Pipelines....................................    $ 66        $--         $ 66        $ 72        $ --        $ 72
Merchant Energy..............................      (1)        11           10         176          39         215
Field Services...............................      17          1           18          20           4          24
                                                 ----        ---         ----        ----        ----        ----
  Segment EBIT...............................      82         12           94         268          43         311
Corporate....................................      (8)        --           (8)          8          --           8
                                                 ----        ---         ----        ----        ----        ----
  Consolidated EBIT..........................      74         12           86         276          43         319
                                                 ----        ---         ----        ----        ----        ----
Non-affiliated interest and debt expense.....     (32)        --          (32)        (37)         --         (37)
Affiliated interest and debt expense.........     (25)        --          (25)        (44)         --         (44)
Minority interest............................      (6)        --           (6)         --          --          --
Income taxes.................................      (3)        (4)          (7)        (75)        (15)        (90)
Extraordinary items, net of taxes............      --         --           --          38         (38)         --
                                                 ----        ---         ----        ----        ----        ----
Net income...................................    $  8        $ 8         $ 16        $158        $(10)       $148
                                                 ====        ===         ====        ====        ====        ====
</Table>

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

(1) Charges include restructuring and merger-related costs, asset impairments
    and extraordinary items. See Item 1, Financial Statements, for further
    discussion of these charges.

                                        18
<PAGE>

<Table>
<Caption>
                                                                SIX MONTHS ENDED JUNE 30,
                                          ---------------------------------------------------------------------
                                                        2002                                2001
                                          ---------------------------------   ---------------------------------
                                          REPORTED   CHARGES(1)   PRO-FORMA   REPORTED   CHARGES(1)   PRO-FORMA
                                          --------   ----------   ---------   --------   ----------   ---------
<S>                                       <C>        <C>          <C>         <C>        <C>          <C>
Pipelines...............................   $ 147       $  --        $147       $ 185        $  1        $ 186
Merchant Energy.........................    (353)        353          --         407          39          446
Field Services..........................      44           1          45          21          32           53
                                           -----       -----        ----       -----        ----        -----
  Segment EBIT..........................    (162)        354         192         613          72          685
Corporate...............................      (7)         --          (7)          9          --            9
                                           -----       -----        ----       -----        ----        -----
  Consolidated EBIT.....................    (169)        354         185         622          72          694
                                           -----       -----        ----       -----        ----        -----
Non-affiliated interest and debt
  expense...............................     (71)         --         (71)        (78)         --          (78)
Affiliated interest and debt expense....     (43)         --         (43)       (109)         --         (109)
Minority interest.......................     (12)         --         (12)         --          --           --
Income taxes............................      99        (119)        (20)       (147)        (24)        (171)
Extraordinary items, net of taxes.......      --          --          --          38         (38)          --
Accounting changes, net of taxes........      97         (97)         --          --          --           --
                                           -----       -----        ----       -----        ----        -----
Net income (loss).......................   $ (99)      $ 138        $ 39       $ 326        $ 10        $ 336
                                           =====       =====        ====       =====        ====        =====
</Table>

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

(1) Charges include restructuring and merger-related costs, asset impairments,
    extraordinary items and a cumulative effect of accounting change. See Item
    1, Financial Statements, for further discussions of these charges.

                                SEGMENT RESULTS

     Our three segments: Pipelines, 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
portion of Merchant Energy and for the Field Services segment. For a further
discussion of our individual segments, see Item 1, Financial Statements, Note 9,
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:

<Table>
<Caption>
                                                            QUARTER ENDED     SIX MONTHS ENDED
                                                              JUNE 30,            JUNE 30,
                                                            -------------     ----------------
                                                            2002     2001      2002      2001
                                                            ----     ----     ------     -----
                                                                      (IN MILLIONS)
<S>                                                         <C>      <C>      <C>        <C>
Pipelines.................................................  $ 66     $ 72     $ 147      $185
Merchant Energy...........................................    (1)     176      (353)      407
Field Services............................................    17       20        44        21
                                                            ----     ----     -----      ----
  Segment total...........................................    82      268      (162)      613
Corporate.................................................    (8)       8        (7)        9
                                                            ----     ----     -----      ----
  Consolidated EBIT.......................................  $ 74     $276     $(169)     $622
                                                            ====     ====     =====      ====
</Table>

PIPELINES

     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, as
well as gas supply availability which can displace the pipeline's delivery
capabilities to the markets they serve. 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 compression equipment. Future revenues
may also be impacted by expansion projects in our service areas, competition by
other pipelines for

                                        19
<PAGE>

those expansion needs and regulatory impacts on rates. Results of our Pipelines
segment operations were as follows for the periods ended June 30:

<Table>
<Caption>
                                                   QUARTER ENDED      SIX MONTHS ENDED
                                                      JUNE 30,            JUNE 30,
                                                  ----------------    ----------------
                                                   2002      2001      2002      2001
                                                  ------    ------    ------    ------
                                                  (IN MILLIONS, EXCEPT VOLUME AMOUNTS)
<S>                                               <C>       <C>       <C>       <C>
Operating revenues............................    $  166    $  170    $  354    $  389
Operating expenses............................      (107)     (105)     (219)     (213)
Other income..................................         7         7        12         9
                                                  ------    ------    ------    ------
  EBIT........................................    $   66    $   72    $  147    $  185
                                                  ======    ======    ======    ======
Throughput volumes (BBtu/d)(1)................     4,575     4,407     4,849     4,884
                                                  ======    ======    ======    ======
</Table>

---------------
(1) Throughput volumes for 2001 exclude Midwestern Gas Transmission system sold
    in connection with the FTC order related to El Paso's merger with Coastal.

  Second Quarter 2002 Compared to Second Quarter 2001

     Operating revenues for the quarter ended June 30, 2002, were $4 million
lower than the same period in 2001. The decrease was primarily due to the
favorable resolution of regulatory issues related to natural gas purchase
contracts in 2001 and the impact of lower natural gas prices on excess natural
gas recoveries in 2002. Also contributing to the decrease was the sale of the
Midwestern Gas Transmission system in April 2001. The decrease was partially
offset by revenues from transmission system expansion projects placed in service
in 2002 and a favorable resolution of measurement issues at a processing plant
serving the TGP system.

     Operating expenses for the quarter ended June 30, 2002, were $2 million
higher than the same period in 2001. The increase was primarily due to higher
amortization of additional acquisition cost assigned to utility plant, higher
field operational costs, higher costs associated with gas storage and higher
electric compression costs in 2002. The increase was partially offset by lower
corporate overhead allocations in the second quarter of 2002 and reduced
operating and depreciation expenses due to the sale of the Midwestern system in
April 2001.

  Six Months Ended 2002 Compared to Six Months Ended 2001

     Operating revenues for the six months ended June 30, 2002, were $35 million
lower than the same period in 2001. The decrease was primarily due to the
favorable resolution of regulatory issues related to natural gas purchase
contracts in 2001 and the impact of lower natural gas prices on excess natural
gas recoveries in 2002. Also contributing to the decrease were lower
transportation revenues from capacity sold under short-term contracts in 2002,
as well as the sale of the Midwestern Gas Transmission system in April 2001 and
lower revenues due to milder weather in 2002. Partially offsetting the decrease
were revenues from transmission system expansion projects placed in service in
2002 and a favorable resolution of measurement issues at a processing plant
serving the TGP system.

     Operating expenses for the six months ended June 30, 2002, were $6 million
higher than the same period in 2001. The increase was primarily due to higher
amortization of additional acquisition cost assigned to utility plant, higher
field operational costs, higher costs associated with gas storage and higher
electric compression costs in 2002. Also contributing to the increase were lower
project development costs in the first quarter of 2001. Partially offsetting the
increase were lower corporate overhead allocations in the second quarter of 2002
and reduced operating and depreciation expenses due to the sale of the
Midwestern system in April 2001.

     Other income for the six months ended June 30, 2002, was $3 million higher
than the same period in 2001 primarily due to higher equity earnings resulting
from reduced losses on our investment in Australia in 2002.

     New Expansion Project.  The FERC approved TGP's Can-East project and
related compressor facilities in June 2002. Service is anticipated to commence
in November 2002. The Can-East project will extend TGP's mainline pipeline
system to the Leidy Hub using 280 million cubic feet of capacity per day that
TGP currently plans to lease from Dominion Resources and National Fuel Gas
Supply Corp.

                                        20
<PAGE>

MERCHANT ENERGY

     Our Merchant Energy segment conducts our customer origination, trading and
power activities.

  Energy-Related Price Risk Management Activities

     As of June 30, 2002, the net fair value of our energy contracts was $1,052
million. Of this amount, the net fair value of our trading-related energy
contracts was $1,051 million. Our trading activities generated margins during
the six months ended June 30, 2002 and 2001 totaling $1 million and $381
million.

     The following table details the net fair value of our energy contracts by
year of maturity and valuation methodology as of June 30, 2002:

<Table>
<Caption>
                                 MATURITY    MATURITY   MATURITY   MATURITY   MATURITY   TOTAL
                                 LESS THAN    1 TO 3     4 TO 5    6 TO 10     BEYOND     FAIR
     SOURCE OF FAIR VALUE         1 YEAR      YEARS      YEARS      YEARS     10 YEARS   VALUE
     --------------------        ---------   --------   --------   --------   --------   ------
                                                         (IN MILLIONS)
<S>                              <C>         <C>        <C>        <C>        <C>        <C>
Trading contracts
  Prices actively quoted.......    $(77)       $443       $247       $148       $ 4      $  765
  Prices based on models and
     other valuation methods...     132          84         28         18        24         286
                                   ----        ----       ----       ----       ---      ------
          Total trading
            contracts, net.....      55         527        275        166        28       1,051
                                   ----        ----       ----       ----       ---      ------
Non-trading contracts, net.....      --           1         --         --        --           1
                                   ----        ----       ----       ----       ---      ------
          Total energy
            contracts..........    $ 55        $528       $275       $166       $28      $1,052
                                   ====        ====       ====       ====       ===      ======
</Table>

     A reconciliation of our trading and non-trading energy contracts for the
six months ended June 30, 2002, is as follows:

<Table>
<Caption>
                                                                                 TOTAL
                                                                               COMMODITY
                                                       TRADING   NON-TRADING     BASED
                                                       -------   -----------   ---------
                                                                 (IN MILLIONS)
<S>                                                    <C>       <C>           <C>
Fair value of contracts outstanding at December 31,
  2001...............................................  $1,337       $ 23        $1,360
                                                       ------       ----        ------
Fair value of contracts settled during the period....    (378)       (13)         (391)
Initial recorded value of new contracts..............      71(1)      --            71
Change in fair value of contracts....................      60         (9)           51
Changes in fair value attributable to changes in
  valuation techniques...............................     (69)        --           (69)
Other................................................      30         --            30
                                                       ------       ----        ------
  Net change in contracts outstanding during the
     period..........................................    (286)       (22)         (308)
                                                       ------       ----        ------
Fair value of contracts outstanding at June 30,
  2002...............................................  $1,051       $  1        $1,052
                                                       ======       ====        ======
</Table>

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

(1) Relates primarily to the completion of our Snohvit LNG supply contract in
    the second quarter of 2002. See the discussion of this transaction under
    results of operations below.

     Included in "Changes in fair value attributable to changes in valuation
techniques" in our trading price risk management activities is a first quarter
charge of approximately $61 million related to our revised estimate of the fair
value of long-term trading positions. Specifically, we have experienced
diminished liquidity in the marketplace for natural gas and power transactions
in excess of ten years. Because we do not expect this condition to change in the
foreseeable future, we do not recognize gains from the fair value of trading or
non-trading positions beyond ten years unless there is clearly demonstrated
liquidity in a specific market. Included in "Other" are option premiums and
storage capacity transactions.

                                        21
<PAGE>

  Results of Operations

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

<Table>
<Caption>
                                                QUARTER ENDED        SIX MONTHS ENDED
                                                   JUNE 30,              JUNE 30,
                                              ------------------    ------------------
                                               2002       2001       2002       2001
                                              -------    -------    -------    -------
                                                (IN MILLIONS, EXCEPT VOLUME AMOUNTS)
<S>                                           <C>        <C>        <C>        <C>
Trading gross margin........................  $   (45)   $   138    $   (14)   $   328
Operating and other revenues................      102         76        208        183
Operating expenses..........................     (130)      (122)      (621)      (228)
Other income................................       72         84         74        124
                                              -------    -------    -------    -------
     EBIT...................................  $    (1)   $   176    $  (353)   $   407
                                              =======    =======    =======    =======

Volumes(1)
  Physical
     Natural gas (BBtue/d)..................   13,639      9,187     13,431     10,324
     Power (MMWh)...........................  108,683     45,386    214,564     81,584
     Other energy commodities (MBbls).......    6,478      4,032     12,781      5,324
Financial settlements (BBtue/d).............  194,728    120,929    176,026    145,077
</Table>

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

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

     Trading gross margin consists of revenue from commodity trading and
origination activities less the cost of commodities sold.

  Second Quarter 2002 Compared to Second Quarter 2001

     During the quarter ended June 30, 2002, we completed a significant
transaction related to a long-term LNG supply contract. In May 2002, we received
final approval from the Norwegian and United States governments on an LNG
purchase and sale agreement signed in October 2001 with a consortium of natural
gas production companies led by Statoil ASA. The consortium will develop the
Snohvit Project in northern Norway, and we will receive LNG shipments equivalent
to an estimated 91 billion cubic feet per year of natural gas during the 17-year
term of the agreement with the possibility of a 3-year extension. The first
delivery is scheduled between October 2005 and October 2006. The Snohvit
agreement is a derivative under SFAS No. 133, which we were required to mark to
its fair value when it was finalized. As a result, we recorded a $59 million
gain in the second quarter of 2002 from this transaction.

     For the quarter ended June 30, 2002, trading gross margin was $183 million
lower than the same period in 2001. The decrease was due to lower trading
margins primarily due to a weaker trading environment and lower price volatility
in the natural gas and power markets in the second quarter of 2002, partially
offset by the $59 million gain on the Snohvit transaction.

     Operating and other revenues consist of revenues from domestic and
international power generation facilities and investments, including our
management fee from Chaparral, and revenues from EnCap and our other financial
services businesses. For the quarter ended June 30, 2002, operating and other
revenues were $26 million higher than the same period in 2001. The increase
resulted from higher management fee income, primarily from Chaparral, as well as
higher income from our financial services businesses, during the second quarter
of 2002.

     Operating expenses for the quarter ended June 30, 2002, were $8 million
higher than the same period in 2001. The increase was primarily a result of
severance expensed in the second quarter of 2002 in conjunction with the
restructuring of our trading business.

                                        22
<PAGE>

     Other income for the quarter ended June 30, 2002, was $12 million lower
than the same period in 2001. The decrease was primarily the result of
marketing, agency and technical services fees related to the development of the
Macae power project in Brazil which were recorded in the second quarter of 2001,
partially offset by an increase 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 a power contract
restructuring transaction at our Mount Carmel plant. This transaction, which
occurred in the first quarter of 2002, involved the termination of the existing
power purchase contract for a fee from the utility of $50 million. In addition,
we recorded a non-cash adjustment to reflect the estimated fair value of the
Mount Carmel power plant of $25 million, resulting in a total net benefit on the
restructuring transaction of $25 million.

     For the six months ended June 30, 2002, trading gross margin was $342
million lower than the same period in 2001. The decrease was due to a weaker
trading environment and lower price volatility in the natural gas and power
markets in the second quarter of 2002. This decrease was partially offset by the
Mount Carmel power contract restructuring described above and a $59 million gain
from our Snohvit transaction.

     For the six months ended June 30, 2002, operating and other revenues were
$25 million higher than the same period in 2001. The increase primarily resulted
from higher management fees from Chaparral.

     Operating expenses for the six months ended June 30, 2002, were $393
million higher than the same period in 2001. The increase resulted from a $342
million impairment of our power investments in Argentina in the first quarter of
2002, a $19 million turbine forfeiture fee for a cancelled power project during
2002, and an increase in corporate overhead allocation to Merchant Energy in
2002. Also contributing to this increase were higher operating expenses
resulting from the expansion of our LNG business in 2002 and more extensive
operations in Europe and Mexico in 2002 as compared to 2001. The increase was
partially offset by a $38 million impairment of our investment in the East Asia
Power project in the Philippines in the second quarter of 2001.

     Other income for the six months ended June 30, 2002, was $50 million lower
than the same period in 2001. The decrease was primarily the result of
marketing, agency and technical services fees related to the development of the
Macae power project in Brazil which were recorded in the second quarter of 2001.

FIELD SERVICES

     Our Field Services segment conducts our midstream activities. During 2002,
we have entered into several transactions to divest most of our midstream
assets. In the first six months of 2002:

     - We contributed to our parent in March 2002 the gathering and processing
       assets we acquired in our acquisition of PG&E's midstream assets in
       December 2000, including the EPGT Texas intrastate pipeline system (our
       parent subsequently sold the EPGT Texas system to El Paso Energy Partners
       in April 2002). These assets generated EBIT of $26 million for the year
       ended December 31, 2001.

     - We sold gathering and processing assets in April 2002 to El Paso Energy
       Partners, of which we have an approximate 7 percent ownership interest.
       These assets included the Waha gathering and treating system, the
       Carlsbad gathering system and an approximate 42.3 percent non-operating
       interest in the Indian Basin processing plant. These assets generated
       EBIT of $26 million during the year ended December 31, 2001.

     Our parent also announced in July 2002 the proposed sale of substantially
all our natural gas gathering, processing and treating assets in the San Juan
Basin to El Paso Energy Partners. We expect this transaction to be completed by
the end of 2002. The San Juan Basin assets generated EBIT of $104 million during
the year ended December 31, 2001.

     With the completion of these transactions, we will have divested of a
substantial portion of our midstream business. As a result, we expect our future
EBIT to decrease considerably due to a decline in our gathering,

                                        23
<PAGE>

treating, and processing activities. However, we expect the increase in earnings
from our interest in the partnership to offset, in part, the anticipated
decrease in EBIT.

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

<Table>
<Caption>
                                                        QUARTER ENDED        SIX MONTHS ENDED
                                                           JUNE 30,              JUNE 30,
                                                      ------------------    ------------------
                                                       2002       2001       2002       2001
                                                      -------    -------    -------    -------
                                                      (IN MILLIONS, EXCEPT VOLUMES AND PRICES)
<S>                                                   <C>        <C>        <C>        <C>
Total gross margins.................................  $   42     $  100     $  127     $  209
Operating expenses..................................     (31)       (75)       (96)      (186)
Other income (loss).................................       6         (5)        13         (2)
                                                      ------     ------     ------     ------
  EBIT..............................................  $   17     $   20     $   44     $   21
                                                      ======     ======     ======     ======
Volume and prices
  Gathering and treating
     Volumes (BBtu/d)...............................   1,487      4,962      2,848      5,066
                                                      ======     ======     ======     ======
     Prices ($/MMBtu)...............................  $ 0.24     $ 0.14     $ 0.18     $ 0.14
                                                      ======     ======     ======     ======
  Processing
     Volumes (inlet BBtu/d).........................     812      2,408      1,356      2,178
                                                      ======     ======     ======     ======
     Prices ($/MMBtu)...............................  $ 0.12     $ 0.17       0.12     $ 0.18
                                                      ======     ======     ======     ======
</Table>

  Second Quarter 2002 Compared to Second Quarter 2001

     Total gross margins for the quarter ended June 30, 2002, were $58 million
lower than the same period in 2001. The decrease in gathering, treating and
processing margins was primarily due to the disposition of assets in March and
April 2002. Processing margins also declined due to lower natural gas liquids
(NGL) prices in 2002 and higher costs associated with a new processing
arrangement at the Chaco processing facility entered into in the fourth quarter
of 2001 with El Paso Energy Partners. Excluding the results of the divested
assets, gathering and treating margins were higher due to the unfavorable
resolution of fuel disputes in the second quarter of 2001, partially offset by
lower natural gas prices in the San Juan Basin in 2002.

     Operating expenses for the quarter ended June 30, 2002, were $44 million
lower than the same period of 2001. The decrease was primarily a result of lower
operating and depreciation expenses attributable to our disposition of assets in
2002, and $4 million in merger-related costs arising from payments to El Paso
Energy Partners related to FTC ordered sales of assets owned by the partnership
in 2001 following the El Paso merger with Coastal.

     Other income for the quarter ended June 30, 2002, was $11 million higher
than the same period in 2001 principally due to higher earnings in 2002 from our
interest in El Paso Energy Partners.

  Six Months Ended 2002 Compared to Six Months Ended 2001

     Total gross margins for the year ended June 30, 2002, were $82 million
lower than the same period in 2001. The decrease in gathering, treating and
processing margins was primarily due to the disposition of assets in March and
April of 2002. Processing margins also decreased due to lower NGL prices in 2002
and higher costs associated with a new processing arrangement at the Chaco
processing facility entered into in the fourth quarter of 2001 with El Paso
Energy Partners. Excluding the results of the divested assets, gathering and
treating margins were higher due to the favorable resolution of fuel, rate and
volume matters in the first quarter of 2002, unfavorable resolution of fuel
disputes in the second quarter of 2001, and higher realized transportation rates
from the pipeline system acquired in our acquisition of PG&E's midstream assets.
Partially offsetting these increases were lower natural gas prices in the San
Juan Basin in 2002.

     Operating expenses for the six months ended June 30, 2002, were $90 million
lower than the same period of 2001. The decrease was primarily a result of lower
operating and depreciation expenses due to our

                                        24
<PAGE>

disposition of assets in 2002, merger-related costs of $32 million arising from
payments to El Paso Energy Partners in 2001 related to FTC ordered sales of
assets owned by the partnership and merger-related employee relocation expenses
in 2001 following the El Paso merger with Coastal.

     Other income for the six months ended June 30, 2002, was $15 million higher
than the same period in 2001 principally due to higher earnings in 2002 from our
interests in El Paso Energy Partners.

INTEREST AND DEBT EXPENSE

  Non-affiliated Interest and Debt Expense, Net

     Non-affiliated interest and debt expense, net for the quarter and six
months ended June 30, 2002, was $5 million and $7 million lower than the same
period in 2001 primarily due to a reduction of long-term debt and lower interest
rates on commercial paper borrowings. This decrease was partially offset by a
decrease in capitalized interest due to lower rates on construction projects.

  Affiliated Interest Expense, Net

     Affiliated interest expense, net for the quarter and six months ended June
30, 2002, was $19 million and $66 million lower than the same period in 2001
primarily due to lower short-term interest rates on average advances from El
Paso under our cash management program with them.

INCOME TAXES

     Income tax expense for the quarter ended June 30, 2002, was $3 million,
resulting in an effective tax rate of 27 percent. Income tax benefit for the six
months ended June 30, 2002, was $99 million, resulting in an effective tax rate
of 34 percent. Our effective tax rates for both periods 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 expense for the quarter and six months ended June 30, 2001, was
$75 million and $147 million, resulting in effective tax rates of 38 percent and
34 percent. Our effective tax rates were different than the statutory tax rate
of 35 percent primarily due to the following:

     - state income taxes;

     - earnings from unconsolidated affiliates where we anticipate receiving
       dividends; and

     - foreign income taxed at different rates.

                        LIQUIDITY AND CAPITAL RESOURCES

  CASH FROM OPERATING ACTIVITIES

     Net cash used in our operating activities was $503 million for the six
months ended June 30, 2002, compared to net cash provided by operating
activities of $3,192 million for the same period in 2001. The decrease was
primarily due to cash paid for broker and over-the-counter margins in 2002, as
well as less cash generated through liquidations of price risk management
assets. Also contributing to the decrease is the change in Merchant Energy
payables related to the purchase of natural gas, as well as higher 2001
electricity rates and volumes, compared to 2002.

  CASH FROM INVESTING ACTIVITIES

     Net cash provided by our investing activities was $124 million for the six
months ended June 30, 2002. Our investing activities primarily consisted of net
proceeds from the sale of midstream assets to El Paso

                                        25
<PAGE>

Energy Partners. Cash outflows consisted mainly of additions to our property,
plant and equipment primarily in our Pipelines and Merchant Energy segments for
expansion and construction projects.

  CASH FROM FINANCING ACTIVITIES

     Net cash provided by our financing activities was $307 million for the six
months ended June 30, 2002. Cash provided from our financing activities included
the issuance of long-term debt and cash advances received from El Paso under our
cash management program. Cash outflows consisted primarily of dividends paid to
our preferred and common shareholders.

     During the six months ended June 30, 2002, we paid dividends of $12 million
on our Series A cumulative preferred stock, which is 8 1/4% per annum (2.0625%
per quarter). We also distributed $59 million of common dividends to our parent.

     We expect that future funding for our working capital needs, capital
expenditures, acquisitions, other investing activities, long-term debt
retirements, payments of dividends and other financing expenditures will be
provided by internally generated funds, commercial paper issuances, available
capacity under existing credit facilities, the issuance of new long-term debt or
equity, and/or contributions from El Paso.

     During the first quarter of 2002, we distributed several of our midstream
business entities which had $180 million of long-term debt to our parent, El
Paso.

  Credit Facilities and Available Capacity

     In May 2002, El Paso renewed its $3 billion, 364-day revolving credit and
competitive advance facility. TGP remains a designated borrower under this
facility and, as such, is liable for any amounts outstanding under this
facility. This facility matures in May 2003. 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, and TGP is a designated
borrower under this facility and, as such, is liable for any amounts outstanding
under this facility. The interest rate under both of these facilities 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 $1 billion facility.

     In June 2002, TGP issued $240 million aggregate principal amount 8.375%
notes due 2032. Proceeds of approximately $238 million, net of issuance costs,
were used to repay short-term borrowings and for general corporate purposes. As
a result, TGP has no remaining capacity under its shelf registration statement
on file with the SEC.

  Other Commercial Commitments

     In 2001, we entered into agreements to time-charter four separate ships to
secure transportation for our developing liquefied natural gas business. In May
2002, we entered into amendments to three of the initial four time charters to
reconfigure the ships with onboard regasification technology and to secure an
option for an additional time charter for a fifth ship. The exercise of the
option for the fifth ship will represent a commitment of $522 million over the
term of such charter. However, we are obligated to pay a termination fee of $24
million in the event the option is not exercised by April 2003. The agreements
provide for deliveries of vessels between 2003 and 2005. Each time charter has a
twenty-year term commencing when the vessels are delivered with the possibility
of two five-year extensions. The total commitment under the five time-charter
agreements is approximately $2.5 billion over the term of the time charters. We
are party to an agreement with an unaffiliated global integrated oil and gas
company under which the third party agrees to bear 50 percent of the risk
incidental to the initial $1.8 billion commitment made for the first four time
charters.

                         COMMITMENTS AND CONTINGENCIES

     See Item 1, Financial Statements, Note 8, which is incorporated herein by
reference.

                 NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED

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

                                        26
<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

     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, except as presented below:

COMMODITY PRICE RISK

     The following table presents our potential one-day unfavorable impact on
earnings before interest and income taxes as measured by Value-at-Risk using the
historical simulation technique for our energy related contracts and is prepared
based on a confidence level of 95 percent and a one-day holding period:

<Table>
<Caption>
                                                              JUNE 30,   DECEMBER 31,
                                                                2002         2001
                                                              --------   ------------
                                                                   (IN MILLIONS)
<S>                                                           <C>        <C>
Trading Value-at-Risk.......................................    $12          $18
Non-Trading Value-at-Risk...................................    $ 3          $ 7
Portfolio Value-at-Risk.....................................    $ 9          $14
</Table>

     Portfolio Value-at-Risk represents the combined Value-at-Risk for the
trading and non-trading price risk management activities. The separate
calculation of Value-at-Risk for trading and non-trading contracts ignores the
natural correlation that exists between commodity contracts and prices. As a
result, the individually determined values will be higher than the combined
Value-at-Risk in most instances. We manage our risks through a portfolio
approach that balances both trading and non-trading risks.

                                        27
<PAGE>

                          PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

     See Part I, Item 1, Financial Statements, Note 8, which is incorporated
herein by reference.

     The California cases are: five filed in the Superior Court of Los Angeles
County (Continental Forge Company, et al v. Southern California Gas Company, et
al, filed September 25, 2000; and Berg v. Southern California Gas Company, et
al; filed December 18, 2000; County of Los Angeles v. Southern California Gas
Company, et al, filed January 8, 2002; The City of Los Angeles, et al v.
Southern California Gas Company, et al; and The City of Long Beach, et al v.
Southern California Gas Company, et al, both filed March 20, 2001); two filed in
the Superior Court of San Diego County (John W.H.K. Phillip v. El Paso Merchant
Energy; and John Phillip v. El Paso Merchant Energy, both filed December 13,
2000); three filed in the Superior Court of San Francisco County (Sweetie's, et
al v. El Paso Corporation, et al, filed March 22, 2001; Philip Hackett, et al v.
El Paso Corporation, et al, filed May 9, 2001; and California Dairies, Inc., et
al v. El Paso Corporation, et al, filed May 21, 2001); and one filed in the
Superior Court of the State of California, County of Alameda (Dry Creek
Corporation v. El Paso Natural Gas Company, et al, filed December 10, 2001).

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

     None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     None.

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

     We held our annual meeting of stockholders on May 20, 2002. Proposals we
presented for a stockholders' vote included the election of one director by
holders of EPTPC's 8 1/4% Cumulative Preferred Stock, Series A, and the election
of five Directors by El Paso, the sole holder of EPTPC's Common Stock.

     The one director nominated to be elected by the holder of EPTPC's 8 1/4%
Cumulative Preferred Stock Series A was elected with the following voting
results:

<Table>
<Caption>
                                                                 FOR      ABSTAIN
                                                              ---------   -------
<S>                                                           <C>         <C>
Kenneth L. Smalley..........................................  3,555,432     150
</Table>

     Each of the five directors nominated to be elected by the common
stockholder were elected with the following voting results:

<Table>
<Caption>
                                                               FOR    ABSTAIN
                                                              -----   -------
<S>                                                           <C>     <C>
William A. Wise.............................................  1,971      0
H. Brent Austin.............................................  1,971      0
Peggy A. Heeg...............................................  1,971      0
Joel Richards III...........................................  1,971      0
Jeffrey I Beason............................................  1,971      0
</Table>

     There were no broker non-votes for the election of directors.

ITEM 5. OTHER INFORMATION

     None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

a. Exhibits

                                        28
<PAGE>

     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.

<Table>
<Caption>
        EXHIBIT
         NUMBER                                        DESCRIPTION
        -------                                        -----------
<C>                      <S>   <C>
        *10.A            --    $3,000,000,000 364-Day Revolving Credit and Competitive
                               Advance Facility Agreement dated May 15, 2002, by and among
                               El Paso, EPNG, TGP, the several banks and other institutions
                               from time to time parties thereto and JPMorgan Chase Bank,
                               as Administrative Agent and CAF Advance Agent, ABN Amro Bank
                               N.V. and Citibank, N.A., as Co-Documentation Agents, and
                               Bank of America, N.A. and Credit Suisse First Boston, as
                               Co-Syndication Agents.
        *10.B            --    Amended and Restated $1,000,000,000 3-Year Revolving Credit
                               and Competitive Advance Facility Agreement dated June 27,
                               2002, by and among El Paso, EPNG, TGP, El Paso CGP, the
                               several banks and other institutions from time to time
                               parties thereto and JPMorgan Chase Bank, as Administrative
                               Agent, CAF Advance Agent and Issuing Bank, Citibank, N.A.
                               and ABN Amro Bank N.V. as Co-Documentation Agents, and Bank
                               of America, N.A., as Syndication Agent.
        *99.A            --    Certification of Chief Executive Officer pursuant to 18
                               U.S.C.sec. 1350 as adopted pursuant to sec. 906 of the
                               Sarbanes-Oxley Act of 2002.
        *99.B            --    Certification of Chief Financial Officer pursuant to 18
                               U.S.C.sec. 1350 as adopted pursuant to sec. 906 of the
                               Sarbanes-Oxley Act of 2002.
</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 these instruments does
     not exceed 10 percent of our total consolidated assets.

b. Reports on Form 8-K

     None.

                                        29
<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 TENNESSEE PIPELINE CO.

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

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

                                        30
<PAGE>

                                 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.

<Table>
<Caption>
        EXHIBIT
         NUMBER                                        DESCRIPTION
        -------                                        -----------
<C>                      <S>   <C>
        *10.A            --    $3,000,000,000 364-Day Revolving Credit and Competitive
                               Advance Facility Agreement dated May 15, 2002, by and among
                               El Paso, EPNG, TGP, the several banks and other institutions
                               from time to time parties thereto and JPMorgan Chase Bank,
                               as Administrative Agent and CAF Advance Agent, ABN Amro Bank
                               N.V. and Citibank, N.A., as Co-Documentation Agents, and
                               Bank of America, N.A. and Credit Suisse First Boston, as
                               Co-Syndication Agents.
        *10.B            --    Amended and Restated $1,000,000,000 3-Year Revolving Credit
                               and Competitive Advance Facility Agreement dated June 27,
                               2002, by and among El Paso, EPNG, TGP, El Paso CGP, the
                               several banks and other institutions from time to time
                               parties thereto and JPMorgan Chase Bank, as Administrative
                               Agent, CAF Advance Agent and Issuing Bank, Citibank, N.A.
                               and ABN Amro Bank N.V. as Co-Documentation Agents, and Bank
                               of America, N.A., as Syndication Agent.
        *99.A            --    Certification of Chief Executive Officer pursuant to 18
                               U.S.C.sec. 1350 as adopted pursuant to sec. 906 of the
                               Sarbanes-Oxley Act of 2002.
        *99.B            --    Certification of Chief Financial Officer pursuant to 18
                               U.S.C.sec. 1350 as adopted pursuant to sec. 906 of the
                               Sarbanes-Oxley Act of 2002.
</Table>