<PAGE>

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                                 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, 2003

                                       OR

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

      FOR THE TRANSITION PERIOD FROM                  TO

                         COMMISSION FILE NUMBER 1-4101

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

                         TENNESSEE GAS PIPELINE COMPANY
             (Exact Name of Registrant as Specified in its Charter)

<Table>
<S>                                            <C>
                   DELAWARE                                      74-1056569
         (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 by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).  Yes [ ] No [X]

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

     Common Stock, par value $5 per share. Shares outstanding on August 13,
2003: 208

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

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

                         TENNESSEE GAS PIPELINE COMPANY

                               TABLE OF CONTENTS

<Table>
<Caption>
                                    CAPTION                             PAGE
                                    -------                             ----
<S>       <C>                                                           <C>
                        PART I -- Financial Information
Item 1.   Financial Statements........................................    1
Item 2.   Management's Discussion and Analysis of Financial Condition
            and Results of Operations.................................   11
          Cautionary Statement Regarding Forward-Looking Statements...   14
Item 3.   Quantitative and Qualitative Disclosures About Market
            Risk......................................................   14
Item 4.   Controls and Procedures.....................................   14

                          PART II -- Other Information
Item 1.   Legal Proceedings...........................................   16
Item 2.   Changes in Securities and Use of Proceeds...................   16
Item 3.   Defaults Upon Senior Securities.............................   16
Item 4.   Submission of Matters to a Vote of Security Holders.........   16
Item 5.   Other Information...........................................   16
Item 6.   Exhibits and Reports on Form 8-K............................   16
          Signatures..................................................   18
</Table>

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

     Below is a list of terms that are common to our industry and used
throughout this document:

<Table>
<S>      <C>
/d       = per day
BBtu     = billion British thermal units
MMcf     = million cubic feet
</Table>

    When we refer to cubic feet measurements, all measurements are at a pressure
of 14.73 pounds per square inch.

                                        i
<PAGE>

                        PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

                         TENNESSEE GAS PIPELINE COMPANY

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

<Table>
<Caption>
                                                             QUARTER ENDED    SIX MONTHS ENDED
                                                                JUNE 30,          JUNE 30,
                                                             --------------   ----------------
                                                             2003      2002   2003       2002
                                                             ----      ----   -----      -----
<S>                                                          <C>       <C>    <C>        <C>
Operating revenues.........................................  $168      $165   $380       $353
                                                             ----      ----   ----       ----
Operating expenses
  Operation and maintenance................................    57        74    124        134
  Depreciation, depletion and amortization.................    45        38     83         74
  Taxes, other than income taxes...........................    12        12     24         25
                                                             ----      ----   ----       ----
                                                              114       124    231        233
                                                             ----      ----   ----       ----
Operating income...........................................    54        41    149        120
Earnings from unconsolidated affiliates....................     4         3     11          8
Other income...............................................     2         4      3          5
Interest and debt expense..................................   (33)      (31)   (65)       (59)
Affiliated interest income, net............................     1         2     --          4
                                                             ----      ----   ----       ----
Income before income taxes and cumulative effect of
  accounting change........................................    28        19     98         78
Income taxes...............................................     8         5     29         22
                                                             ----      ----   ----       ----
Income before cumulative effect of accounting change.......    20        14     69         56
Cumulative effect of accounting change, net of income
  taxes....................................................    --        --     --         10
                                                             ----      ----   ----       ----
Net income.................................................  $ 20      $ 14   $ 69       $ 66
                                                             ----      ----   ----       ----
Other comprehensive loss...................................    --        --     (1)        --
                                                             ----      ----   ----       ----
Comprehensive income.......................................  $ 20      $ 14   $ 68       $ 66
                                                             ====      ====   ====       ====
</Table>

                            See accompanying notes.

                                        1
<PAGE>

                         TENNESSEE GAS PIPELINE COMPANY

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

<Table>
<Caption>
                                                              JUNE 30,     DECEMBER 31,
                                                                2003           2002
                                                              ---------    ------------
<S>                                                           <C>          <C>
Current assets
  Cash and cash equivalents.................................   $   --         $   --
  Accounts and notes receivable
    Customer, net of allowance of $4 in 2003 and 2002.......      128            119
    Affiliates..............................................       46            110
    Other...................................................       99             76
  Materials and supplies....................................       24             24
  Deferred income taxes.....................................       51             47
  Other.....................................................       13             14
                                                               ------         ------
         Total current assets...............................      361            390
                                                               ------         ------
Property, plant and equipment, at cost......................    3,139          3,074
  Less accumulated depreciation, depletion and
    amortization............................................      540            484
                                                               ------         ------
                                                                2,599          2,590
  Additional acquisition cost assigned to utility plant,
    net.....................................................    2,217          2,236
                                                               ------         ------
         Total property, plant and equipment, net...........    4,816          4,826
                                                               ------         ------
Other assets
  Notes receivable from affiliates..........................      644            599
  Investments in unconsolidated affiliates..................      182            179
  Other.....................................................       48             51
                                                               ------         ------
                                                                  874            829
                                                               ------         ------
         Total assets.......................................   $6,051         $6,045
                                                               ======         ======

Current liabilities
  Accounts payable
    Trade...................................................   $   49         $   82
    Affiliates..............................................       24             88
    Other...................................................       15             17
  Taxes payable.............................................       39             37
  Accrued interest..........................................       25             25
  Other.....................................................       61             61
                                                               ------         ------
         Total current liabilities..........................      213            310
                                                               ------         ------
Long-term debt..............................................    1,596          1,595
                                                               ------         ------
Other liabilities
  Deferred income taxes.....................................    1,254          1,196
  Other.....................................................      177            201
                                                               ------         ------
                                                                1,431          1,397
                                                               ------         ------

Commitments and contingencies

Stockholder's equity
  Common stock, par value $5 per share; 300 shares
    authorized; 208 shares issued and outstanding...........       --             --
  Additional paid-in capital................................    2,210          2,210
  Retained earnings.........................................      605            536
  Accumulated other comprehensive loss......................       (4)            (3)
                                                               ------         ------
         Total stockholder's equity.........................    2,811          2,743
                                                               ------         ------
         Total liabilities and stockholder's equity.........   $6,051         $6,045
                                                               ======         ======
</Table>

                            See accompanying notes.

                                        2
<PAGE>

                         TENNESSEE GAS PIPELINE COMPANY

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

<Table>
<Caption>
                                                              SIX MONTHS ENDED
                                                                  JUNE 30,
                                                              -----------------
                                                               2003       2002
                                                              ------     ------
<S>                                                           <C>        <C>
Cash flows from operating activities
  Net income................................................  $  69      $  66
  Adjustments to reconcile net income to net cash from
     operating activities
     Depreciation, depletion and amortization...............     83         74
     Undistributed earnings of unconsolidated affiliates....     (4)        (8)
     Deferred income tax expense............................     53         20
     Cumulative effect of accounting change.................     --        (10)
     Other non-cash income items............................      1          2
  Working capital changes...................................    (75)       (44)
  Non-working capital changes and other.....................    (27)       (11)
                                                              -----      -----
          Net cash provided by operating activities.........    100         89
                                                              -----      -----
Cash flows from investing activities
  Additions to property, plant and equipment................    (54)       (80)
  Net change in affiliated advances receivable..............    (45)      (178)
  Net payments to dispose of assets.........................     (3)        (8)
  Other.....................................................      2         --
                                                              -----      -----
          Net cash used in investing activities.............   (100)      (266)
                                                              -----      -----
Cash flows from financing activities
  Net repayments of commercial paper........................     --        (61)
  Net proceeds from the issuance of long-term debt..........     --        238
                                                              -----      -----
          Net cash provided by financing activities.........     --        177
                                                              -----      -----
Net change in cash and cash equivalents.....................     --         --
Cash and cash equivalents
  Beginning of period.......................................     --          4
                                                              -----      -----
  End of period.............................................  $  --      $   4
                                                              =====      =====
</Table>

                            See accompanying notes.

                                        3
<PAGE>

                         TENNESSEE GAS PIPELINE COMPANY

              NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
                                  (UNAUDITED)

1. BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

     We are an indirect wholly owned subsidiary of El Paso Corporation (El
Paso). We prepared this Quarterly Report on Form 10-Q under the rules and
regulations of the United States Securities and Exchange Commission. Because
this is an interim period filing presented using a condensed format, it does not
include all of the disclosures required by generally accepted accounting
principles. You should read it along with our 2002 Annual Report on Form 10-K,
which includes a summary of our significant accounting policies and other
disclosures. The financial statements as of June 30, 2003, and for the quarters
and six months ended June 30, 2003 and 2002, are unaudited. We derived the
balance sheet as of December 31, 2002, from the audited balance sheet filed in
our 2002 Form 10-K. In our opinion, we have made all adjustments which are of a
normal, recurring nature to fairly present our interim period results. Due to
the seasonal nature of our business, information for interim periods may not
necessarily indicate the results of operations for the entire year. In addition,
prior period information presented in these financial statements includes
reclassifications which were made to conform to the current period presentation.
These reclassifications have no effect on our previously reported net income or
stockholder's equity.

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

     Accounting for Costs Associated with Exit or Disposal Activities.  As of
January 1, 2003, we adopted Statement of Financial Accounting Standards (SFAS)
No. 146, Accounting for Costs Associated with Exit or Disposal Activities. SFAS
No. 146 requires that we recognize costs associated with exit or disposal
activities when they are incurred rather than when we commit to an exit or
disposal plan. There was no initial financial statement impact of adopting this
standard.

     Accounting for Guarantees.  On January 1, 2003, we adopted Financial
Accounting Standards Board Interpretation (FIN) No. 45, Guarantor's Accounting
and Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others. FIN No. 45 requires that we record a liability for all
guarantees, including financial performance and fair value guarantees, issued
after December 31, 2002, at fair value when they are issued. There was no
initial financial statement impact of adopting this standard.

     Accounting for Regulated Operations.  Our natural gas systems and storage
operations are subject to the jurisdiction of the Federal Energy Regulatory
Commission (FERC) in accordance with the Natural Gas Act of 1938 and the Natural
Gas Policy Act of 1978, and we apply the provisions of SFAS No. 71, Accounting
for the Effects of Certain Types of Regulation to these businesses. We continue
to evaluate the application of SFAS No. 71 for changes in the competitive
environment and our operating cost structures. See a further discussion of our
accounting for regulated operations in our 2002 Form 10-K.

2. CUMULATIVE EFFECT OF ACCOUNTING CHANGE

     On January 1, 2002, we adopted SFAS No. 141, Business Combinations, and
SFAS No. 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires that
once SFAS No. 142 is adopted, any negative goodwill should be written off as a
cumulative effect of an accounting change. Prior to adoption of the standards,
we had negative goodwill associated with our 30 percent investment in Portland
Natural Gas Company. As a result of our adoption of these standards on January
1, 2002, we recognized a pretax and after-tax gain of $10 million as a
cumulative effect of an accounting change in our 2002 income statement related
to the elimination of this negative goodwill.

3. DEBT AND OTHER CREDIT FACILITIES

     In April 2003, El Paso entered into a new $3 billion revolving credit
facility, with a $1.5 billion letter of credit sublimit, which matures on June
30, 2005. The $3 billion revolving credit facility has a borrowing cost of
                                        4
<PAGE>

LIBOR plus 350 basis points and letter of credit fees of 350 basis points. This
facility replaces El Paso's previous $3 billion revolving credit facility.
Approximately $1 billion of El Paso financing arrangements (including leases,
letters of credit and other facilities) were also amended to conform El Paso's
obligations to the new $3 billion revolving credit facility. We, along with El
Paso and our affiliates, ANR Pipeline Company, and El Paso Natural Gas Company
(EPNG), are borrowers under the $3 billion revolving credit facility and El
Paso's equity in several of its subsidiaries, including us and our equity in
Bear Creek Storage, collateralizes the $3 billion revolving credit facility and
the other financing arrangements. We remain jointly and severally liable under
the $3 billion revolving credit facility until August 19, 2003. Except for the
following conditions, after that date we will only be liable for the amounts we
borrow under the $3 billion revolving credit facility. If, on August 19, 2003,
(1) an event of default is continuing with respect to the $3 billion revolving
credit facility or (2) El Paso or any of the subsidiary guarantors under the $3
billion revolving credit facility or any of El Paso's restricted subsidiaries
(each as defined in the facility) is subject to a bankruptcy or similar
proceeding, then we will continue to be jointly and severally liable for any
amounts outstanding under the $3 billion revolving credit facility until none of
the events described in (1) or (2) above exists. As of August 11, 2003, none of
these conditions existed. Once our joint and several liability expires on August
19, 2003, there are no circumstances in which we could again become liable under
El Paso's $3 billion facility except for amounts borrowed by us under the $3
billion revolving credit facility. As of June 30, 2003, $1.5 billion was
outstanding and $1.1 billion in letters of credit were issued under the $3
billion facility, none of which were borrowed by or issued on behalf of us.

     We, EPNG and El Paso were borrowers under El Paso's $1 billion revolving
credit facility which expired on August 4, 2003. As of June 30, 2003, $132
million in letters of credit were issued under the $1 billion facility, none of
which were issued on behalf of us. The letters of credit either expired or were
reissued under the $3 billion revolving credit facility prior to August 4, 2003.

     We are subject to a number of restrictions and covenants. The most
restrictive of these include (i) limitations on the incurrence of additional
debt, based on a ratio of debt to EBITDA (as defined in the agreements); (ii)
limitations on the use of proceeds from borrowings; (iii) limitations in some
cases, on transaction with our affiliates; (iv) limitations on the incurrence of
liens; (v) potential limitations on our ability to declare and pay dividends;
and (vi) potential limitations on our ability to participate in the El Paso cash
management program. For the six months ended June 30, 2003, we were in
compliance with these covenants.

     In March 2003, El Paso retired the outstanding balance under the Trinity
River financing arrangement. Our 50 percent ownership in Bear Creek Storage,
along with various assets of El Paso, collateralized that arrangement.

4. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

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

     Will Price (formerly Quinque).  We and a number of our affiliates 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

                                        5
<PAGE>

Stevens County, Kansas. Quinque has been dropped as a plaintiff and Will Price
has been added. This class action complaint alleges that the defendants
mismeasured natural gas volumes and heating content of natural gas on
non-federal and non-Native American lands. The plaintiffs in this case seek
certification of a nationwide class of natural gas working interest owners and
natural gas royalty owners to recover royalties that the plaintiffs contend
these owners should have received had the volume and heating value of natural
gas produced from their properties been differently measured, analyzed,
calculated and reported, together with prejudgment and postjudgment interest,
punitive damages, treble damages, attorney's fees, costs and expenses, and
future injunctive relief to require the defendants to adopt allegedly
appropriate gas measurement practices. No monetary relief has been specified in
this case. Plaintiffs' motion for class certification was denied on April 10,
2003. Plaintiffs' motion to file another amended petition to narrow the proposed
class to royalty owners in wells in Kansas, Wyoming and Colorado was granted on
July 28, 2003. Our costs and legal exposure related to this lawsuit and claims
are not currently determinable.

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

     For each of our outstanding legal matters, we evaluate the merits of the
case, our exposure to the matter, possible legal or settlement strategies and
the likelihood of an unfavorable outcome. If we determine that an unfavorable
outcome is probable and can be estimated, we establish the necessary accruals.
As of June 30, 2003, we had no accruals for our outstanding legal matters.

  Environmental Matters

     We are subject to federal, state and local laws and regulations governing
environmental quality and pollution control. These laws and regulations require
us to remove or remedy the effect on the environment of the disposal or release
of specified substances at current and former operating sites. As of June 30,
2003, we had accrued approximately $50 million, including approximately $49
million for expected remediation costs and associated onsite, offsite and
groundwater technical studies and approximately $1 million for related
environmental legal costs, which we anticipate incurring through 2027. Our
accrual at June 30, 2003 was based on the most likely outcome that can be
reasonably estimated. Below is a reconciliation of our accrued liability as of
June 30, 2003 (in millions):

<Table>
<S>                                                            <C>
Balance as of January 1, 2003...............................       $ 84
Additions/adjustments for remediation activities(1).........        (31)
Payments for remediation activities.........................         (3)
                                                                   ----
Balance as of June 30, 2003.................................       $ 50
                                                                   ====
</Table>

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

(1) Represents a reduction in the estimated costs to complete our internal PCB
    remediation project as discussed below.

     In addition, we expect to make capital expenditures for environmental
matters of approximately $51 million in the aggregate for the years 2003 through
2008. These expenditures primarily relate to compliance with clean air
regulations. For the remainder of 2003, we estimate that our total expenditures
will be approximately $4 million. All of this amount is being expended under
government directed clean-up plans.

     Internal PCB Remediation Project.  Since 1988, we have been engaged in an
internal project to identify and address the presence of polychlorinated
biphenyls (PCBs) and other substances, including those on the EPA's List of
Hazardous Substances (HSL), at compressor stations and other facilities we
operate. While conducting this project, we have been in frequent contact with
federal and state regulatory agencies, both through informal negotiation and
formal entry of consent orders. We executed a consent order in 1994 with the
EPA, governing the remediation of the relevant compressor stations and are
working with the EPA and the relevant states regarding those remediation
activities. We are also working with the Pennsylvania and New York environmental
agencies regarding remediation and post-remediation activities at the
Pennsylvania and New York stations. In May 2003 we finalized a new estimate of
the cost to complete the PCB/HSL Project. Over the years there have been
developments that impacted various individual components, but our ability to

                                        6
<PAGE>

estimate a more likely outcome for the total project has not been possible until
recently. The new estimate identified a $31 million reduction in the cost to
complete the project.

     PCB Cost Recoveries.  In May 1995, following negotiations with our
customers, we filed an agreement with the FERC that established a mechanism for
recovering a substantial portion of the environmental costs identified in our
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. We have twice
received approval from the FERC to extend the collection period, which is now
currently set to expire in June 2004. The agreement also provided for bi-annual
audits of eligible costs. As of June 30, 2003, we had pre-collected our PCB
costs by approximately $117 million. The pre-collection will be reduced by
future eligible costs incurred for the remainder of the remediation project. To
the extent actual eligible expenditures are less than the amounts pre-collected,
we will refund to our customers the pre-collection amount plus carrying charges
incurred up to the date of the refunds.

     As of June 30, 2003, we have recorded a regulatory liability (included in
other non-current liabilities on our balance sheet) of $83 million for future
refund obligations. This obligation increased by $25 million in the second
quarter due to the reduction of our accrual of estimated future remediation and
legal costs.

     Kentucky PCB Project.  In November 1988, the Kentucky environmental agency
filed a complaint in a Kentucky state court alleging that we 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. We entered into interim agreed orders with
the agency to resolve many of the issues raised in the complaint. The relevant
Kentucky compressor stations are being remediated under a 1994 consent order
with the EPA. Despite our remediation efforts, the agency may raise additional
technical issues or seek additional remediation work in the future.

     CERCLA Matters.  We have received notice that we could be designated, or
have been asked for information to determine whether we could be designated, as
a Potentially Responsible Party (PRP) with respect to five active sites under
the Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) or state equivalents. We have sought to resolve our liability as a PRP
at these sites through indemnification by third parties and settlements which
provide for payment of our allocable share of remediation costs. As of June 30,
2003 we have estimated our share of the remediation costs of these sites to be
between $1 million and $2 million. Since the clean-up costs are estimates and
are subject to revision as more information becomes available about the extent
of remediation required, and because in some cases we have asserted a defense to
any liability, our estimates could change. Moreover, liability under the federal
CERCLA statute is joint and several, meaning that we could be required to pay in
excess of our pro rata share of remediation costs. Our understanding of the
financial strength of other PRPs has been considered, where appropriate, in
estimating our liabilities.

     It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe the reserves are
adequate.

 Rates and Regulatory Matters

     Gas Supply Realignment Costs.  In 1997, the FERC approved the settlement of
all issues related to the recovery of our Gas Supply Realignment (GSR) and other
transition costs. Under the agreement, we are entitled to collect up to $770
million from our customers, $693 million through a demand surcharge and $77
million through an interruptible transportation surcharge. As of June 30, 2003,
$67 million of the interruptible transportation surcharge had been collected.
There is no time limit for collection of the remaining

                                        7
<PAGE>

interruptible transportation surcharge. This agreement also provides for a rate
case moratorium that expired November 2000 and an escalating cap on the rates we
can charge some of our customers, indexed to inflation, through October 2005.

     Order No. 637.  In February 2000, the FERC issued Order No. 637. Order 637
impacts the way pipelines conduct their operational activities, including how
they release capacity, segment capacity and manage imbalance services,
operational flow orders and pipeline penalties. We filed our compliance proposal
in August 2000 and received an order on compliance from the FERC in April 2002.
Most of our compliance proposal was accepted, but the FERC rejected our
proposals regarding overlapping capacity segments, discounting and the priority
of capacity. In response, we sought rehearing and have made another compliance
filing. On October 31, 2002, FERC issued its order responding to the United
States Court of Appeals for the D.C. Circuit's order remanding various aspects
of Order No. 637. On December 2, 2002, we submitted our compliance filing with
FERC to comply with the October 31 order. We also filed for rehearing of the
October 31 order.

     On July 11, 2003, the FERC issued an order on the rehearing request and on
our compliance filing. The Commission denied our request for rehearing regarding
a replacement shipper's ability to select additional primary points,
forwardhauls and backhauls to the same delivery point, and discounting. The
Commission clarified its application of its policy to allow replacement shippers
the ability to select additional primary points as that policy applies to
Tennessee's grandfathered contracts finding that replacement shippers are not
permitted to obtain redundant primary delivery point rights in excess of their
contract demand. The Commission also approved our compliance filing proposal to
redesign our scheduling imbalance penalty finding that the proposed penalty was
designed to prevent the impairment of reliable firm service. The Commission
required us to file certain tariff revisions within 30 days relating to
operational flow orders (OFO), OFO penalties, and penalty revenue crediting. We
will also seek further rehearing of certain issues. We cannot predict the
outcome of the compliance filings or the requests for rehearing.

     Marketing Affiliate NOPR.  In September 2001, the FERC issued a Notice of
Proposed Rulemaking (NOPR). The NOPR proposes to apply the standards of conduct
governing the relationship between interstate pipelines and marketing affiliates
to all energy affiliates. The proposed regulations, if adopted by the FERC,
would dictate how we conduct business and interact with our energy affiliates.
We filed comments with the FERC addressing our concerns with the proposed rules,
participated in a public conference, and filed additional comments. At this
time, we cannot predict the outcome of the NOPR, but adoption of the regulations
in their proposed form would, at a minimum, place additional administrative and
operational burdens on us.

     Negotiated Rate Policy.  In July 2002, the FERC issued a Notice of Inquiry
(NOI) that sought comments regarding its 1996 policy of permitting pipelines to
enter into negotiated rate transactions. We have entered into those transactions
over the years, and the FERC is now reviewing whether negotiated rates should be
capped, whether or not the "recourse rate" (a cost-of-service based rate)
continues to safeguard against a pipeline exercising market power and other
issues related to negotiated rate programs. El Paso's pipelines and others filed
comments on the NOI.

     In July 2003, the FERC issued modifications to its negotiated rate policy
applicable to interstate natural gas pipelines. The new policy has two primary
changes. First, the FERC will no longer permit the pricing of negotiated rates
based on natural gas commodity price indices, although it will permit current
contracts negotiated on that basis to continue until the end of the applicable
contract period. Second, the FERC is imposing new filing requirements on
pipelines to ensure the transparency of negotiated rate transactions.

     Interim Rule on Cash Management.  In August 2002, the FERC issued a NOPR
proposing, inter alia, that all cash management or money pool arrangements
between a FERC-regulated subsidiary and its non-FERC regulated parent be in
writing and that, as a condition of participating in such an arrangement, the
FERC-regulated entity maintain a minimum proprietary capital balance of 30
percent and both it and its parent maintain investment grade credit ratings.
After receiving written comments and hearing industry participants' concerns at
a public conference in September 2002, the FERC issued an Interim Rule on Cash
Management on June 26, 2003, which did not adopt the proposed limitations on
entry into or participating in
                                        8
<PAGE>

cash management programs. Instead, the Interim Rule requires natural gas
companies to maintain up-to-date documentation authorizing the establishment of
the cash management programs in which they participate and supporting all
deposits into, borrowings and interest from, and interest expense paid to such
programs.

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

     Emergency Reconstruction of Interstate Natural Gas Facilities Final
Rule.  On May 19, 2003, the FERC issued a Final Rule that amends its regulations
to enable natural gas interstate pipeline companies, in emergency situations,
resulting in sudden, unanticipated loss of natural gas or capacity, to replace
facilities when immediate action is required to restore service for the
protection of life or health or for the maintenance of physical property.
Specifically, the Final Rule permits a pipeline to replace mainline facilities
using a route other than an existing right-of-way, to commence construction
without being subject to a 45-day waiting period, and to undertake projects that
exceed the existing blanket cost constraints. Lastly, the Final Rule requires
that landowners be notified of potential construction but provides for a
possible waiver of the 30-day waiting period.

     Pipeline Safety Notice of Proposed Rulemaking.  In January 2003, the U.S.
Department of Transportation issued a NOPR proposing to establish a rule
requiring pipeline operators to develop integrity management programs to
comprehensively evaluate their pipelines and take measures to protect pipeline
segments located in what the notice refers to as "high consequence areas." The
proposed rule resulted from the enactment of the Pipeline Safety Improvement Act
of 2002, a new bill signed into law in December 2002. Comments on the NOPR were
filed on April 30, 2003. At this time, we cannot predict the outcome of this
rulemaking.

     While the outcome of our outstanding legal matters, environmental matters
and rates and regulatory matters cannot be predicted with certainty, based on
current information and our existing accruals, we do not expect the ultimate
resolution of these matters to have a material adverse effect on our financial
position, operating results or cash flows. However, it is possible that new
information or future developments could require us to reassess our potential
exposure related to these matters. It is also possible that the outcome of these
matters could impact our credit rating and that of our parent. Further, for
environmental matters, it is also possible that other developments, such as
increasingly strict environmental laws and regulations and claims for damages to
property, employees, other persons and the environment resulting from our
current or past operations, could result in substantial costs and liabilities in
the future. As new information for our outstanding legal matters, environmental
matters and rates and regulatory matters becomes available, or relevant
developments occur, we will review our accruals and make any appropriate
adjustments. The impact of these changes may have a material effect on our
results of operations, our financial position, and on our cash flows in the
period the event occurs.

                                        9
<PAGE>

5. INVESTMENTS IN UNCONSOLIDATED AFFILIATES AND RELATED PARTY TRANSACTIONS

     We hold investments in various affiliates which we account for using the
equity method of accounting. Summarized financial information for our
proportionate share of these investments is as follows:

<Table>
<Caption>
                                                                QUARTER     SIX MONTHS
                                                                 ENDED         ENDED
                                                               JUNE 30,      JUNE 30,
                                                              -----------   -----------
                                                              2003   2002   2003   2002
                                                              ----   ----   ----   ----
                                                                    (IN MILLIONS)
<S>                                                           <C>    <C>    <C>    <C>
Operating results data:
  Operating revenues........................................   $9     $9    $18    $17
  Operating expenses........................................    3      4      6      7
  Income from continuing operations.........................    2      3      8      6
  Net income(1).............................................    2      3      8      6
</Table>

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

(1) Our proportionate share of net income includes our share of taxes payable by
    partners recorded by our equity investments.

  Transactions with Affiliates

     We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of participating affiliates, thus minimizing
total borrowings from outside sources. Our continued participation in the
program may be dependent on any final rule issued by the FERC in connection with
its Interim Rule on Cash Management as discussed in Note 4. As of June 30, 2003
and December 31, 2002, we had advanced to El Paso $644 million and $599 million.
The market rate of interest at June 30, 2003 was 1.3% and at December 31, 2002,
it was 1.5%. These receivables are due upon demand. However, as of June 30, 2003
and December 31, 2002, we have classified these amounts as non-current notes
receivables from affiliates because we do not anticipate settlement within the
next twelve months. In addition, we had a demand note receivable with El Paso of
$38 million at June 30, 2003 and December 31, 2002, at an interest rate of 1.3%
and 2.21%.

     At June 30, 2003 and December 31, 2002, we also had other accounts
receivable from related parties of $8 million and $72 million. In addition, we
had accounts payable to related parties of $24 million and $88 million at June
30, 2003 and December 31, 2002. These balances arose in the normal course of
business.

     The following table shows revenues and charges from our affiliates for the
quarters and six months ended June 30, 2003 and 2002:

<Table>
<Caption>
                                                                QUARTER     SIX MONTHS
                                                                 ENDED         ENDED
                                                               JUNE 30,      JUNE 30,
                                                              -----------   -----------
                                                              2003   2002   2003   2002
                                                              ----   ----   ----   ----
                                                                    (IN MILLIONS)
<S>                                                           <C>    <C>    <C>    <C>
Revenues from affiliates....................................  $16    $21    $24    $44
Operations and maintenance from affiliates..................   27     33     51     53
Reimbursement for operating expenses from affiliates........   10     10     20     20
</Table>

                                        10
<PAGE>

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

     The information contained in Item 2 updates, and should be read in
conjunction with, the information disclosed in our 2002 Form 10-K in addition to
the financial statements and notes presented in Item 1 of this Form 10-Q.

                             RESULTS OF OPERATIONS

     We use earnings before interest and income taxes (EBIT) to assess the
operating results and effectiveness of our business. We define EBIT as net
income adjusted for (i) items that do not impact our income from continuing
operations such as the impact of an accounting change, (ii) income taxes, (iii)
interest and debt expense and (iv) affiliated interest income. We exclude
interest and debt expense so that investors may evaluate our operating results
without regard to our financing methods. Our business consists of our
consolidated operations as well as our investments in unconsolidated affiliates.
As a result, we believe EBIT, which includes the results of our consolidated and
unconsolidated operations, is useful to our investors because it allows them to
more effectively evaluate the operating performance of our business and
investments. In addition, this is the measure used by El Paso to evaluate the
operating performance of its business segments. This measurement may not be
comparable to measurements used by other companies and should not be used as a
substitute for net income or other performance measures such as operating income
or operating cash flow. The following is a reconciliation of our operating
income to our EBIT and our EBIT to our net income for the periods ended June 30:

<Table>
<Caption>
                                                              QUARTER ENDED    SIX MONTHS ENDED
                                                                JUNE 30,           JUNE 30,
                                                             ---------------   -----------------
                                                              2003     2002     2003      2002
                                                             ------   ------   -------   -------
                                                                (IN MILLIONS, EXCEPT VOLUMES)
<S>                                                          <C>      <C>      <C>       <C>
Operating revenues.........................................  $  168   $  165   $  380    $  353
Operating expenses.........................................    (114)    (124)    (231)     (233)
                                                             ------   ------   ------    ------
  Operating income.........................................      54       41      149       120
                                                             ------   ------   ------    ------
Earnings from unconsolidated affiliates....................       4        3       11         8
Other income...............................................       2        4        3         5
                                                             ------   ------   ------    ------
  Other....................................................       6        7       14        13
                                                             ------   ------   ------    ------
     EBIT..................................................      60       48      163       133
Interest and debt expense..................................     (33)     (31)     (65)      (59)
Affiliated interest income, net............................       1        2       --         4
Income taxes...............................................      (8)      (5)     (29)      (22)
                                                             ------   ------   ------    ------
     Income from continuing operations.....................      20       14       69        56
Cumulative effect of accounting change, net of income
  taxes....................................................      --       --       --        10
                                                             ------   ------   ------    ------
     Net income............................................  $   20   $   14   $   69    $   66
                                                             ======   ======   ======    ======
Throughput volumes (BBtu/d)................................   4,293    4,266    5,166     4,551
                                                             ======   ======   ======    ======
</Table>

     Second Quarter 2003 Compared to Second Quarter 2002

     Operating revenues for the quarter ended June 30, 2003, were $3 million
higher than the same period in 2002. This increase was due to the impact of
higher natural gas prices in 2003 on natural gas recoveries of $9 million and
increased transportation usage revenues of $7 million due to higher contract
rates in 2003. The increase was offset by a decrease in transportation
reservation revenues of $6 million due to the impact of contract conversions and
renewals, a $4 million favorable resolution of measurement issues at a
processing plant serving the TGP system in the second quarter of 2002 and $2
million related to the amortization of deferred contract revenue from March 2000
through February 2003 for services provided to the customers of East Tennessee
Natural Gas Company (ETN) following TGP's sale of ETN in March 2000.

     Operating expenses for the quarter ended June 30, 2003, were $10 million
lower than the same period in 2002. The decrease was due to $15 million of lower
environmental remediation, legal and other related costs in

                                        11
<PAGE>

the second quarter of 2003 primarily due to a revision in our estimated costs to
complete our internal PCB remediation project (see Item 1, Note 4 for further
discussion of this project). This decrease was offset by higher depreciation of
$7 million due to a revision in depreciation expense for a facility that is
being depreciated at an incremental rate of 6.67% per year instead of the
general system rate of 1.62% per year.

     Six Months Ended 2003 Compared to Six Months Ended 2002

     Operating revenues for the six months ended June 30, 2003, were $27 million
higher than the same period in 2002. This increase was due to the impact of
higher natural gas prices in 2003 on natural gas recoveries of $20 million and
increased transportation revenues of $19 million due to higher throughput in
2003 as a result of colder weather. The increase was partially offset by a
decrease in transportation reservation revenues of $9 million due to the impact
of contract conversions and renewals, a $4 million favorable resolution of
measurement issues at a processing plant serving the TGP system in the second
quarter of 2002 and $2 million related to the amortization of deferred contract
revenue from March 2000 through February 2003 for services provided to ETN's
customers following TGP's sale of ETN in March 2000.

     Operating expenses for the six months ended June 30, 2003, were $2 million
lower than the same period in 2002. The decrease was due to $15 million of lower
environmental remediation, legal and other related costs in the second quarter
of 2003 primarily due to a revision in our estimated costs to complete our
internal PCB remediation project. This decrease was offset by higher
depreciation of $7 million due to a revision in depreciation expense for a
facility that is being depreciated at an incremental rate of 6.67% per year
instead of the general system rate of 1.62% per year, higher electric
compression costs of $5 million and higher amortization expense of $2 million
related to the additional acquisition costs assigned to our utility plant.

INTEREST AND DEBT EXPENSE

     Below is the analysis of interest expense for the quarters and six months
ended June 30, 2003 and 2002 (in millions):

<Table>
<Caption>
                                                                QUARTER     SIX MONTHS
                                                                 ENDED         ENDED
                                                               JUNE 30,      JUNE 30,
                                                              -----------   -----------
                                                              2003   2002   2003   2002
                                                              ----   ----   ----   ----
<S>                                                           <C>    <C>    <C>    <C>
Long term debt..............................................  $31    $26    $61    $51
Commercial paper............................................   --      3     --      6
Other interest..............................................    2      2      4      4
Less: capitalized interest..................................   --     --     --     (2)
                                                              ---    ---    ---    ---
     Total interest expense.................................  $33    $31    $65    $59
                                                              ===    ===    ===    ===
</Table>

  Second Quarter 2003 compared to Second Quarter 2002

     Interest and debt expense for the quarter ended June 30, 2003, was $2
million higher than the same period in 2002 primarily due to a $5 million
increase in interest expense resulting from the issuance of $240 million of
long-term debt in June 2002. This increase was offset by a $3 million decrease
in commercial paper interest expense due to the discontinuation of commercial
paper activity in the fourth quarter of 2002.

  Six Months Ended 2003 compared to Six Months Ended 2002

     Interest and debt expense for the six months ended June 30, 2003, was $6
million higher than the same period in 2002 primarily due to a $10 million
increase in interest expense resulting from the issuance of $240 million of
long-term debt in June 2002 and a $2 million decrease in interest capitalized on
construction projects due to a lower average capitalization base. These
increases were offset by a $6 million decrease in commercial paper interest
expense due to the discontinuation of commercial paper activity in the fourth
quarter of 2002.

                                        12
<PAGE>

AFFILIATED INTEREST INCOME, NET

  Second Quarter 2003 compared to Second Quarter 2002

     Affiliated interest income, net for the quarter ended June 30, 2003, was $1
million lower than the same period in 2002 due primarily to lower average
advances to El Paso under our cash management program and lower short-term
interest rates in 2003. The average advance balance due from El Paso of $433
million for the second quarter of 2002 decreased to $269 million in 2003. The
average short-term interest rates for the second quarter decreased from 1.9% in
2002 to 1.3% in 2003.

  Six Months Ended 2003 compared to Six Months Ended 2002

     Affiliated interest income, net for the six months ended June 30, 2003, was
$4 million lower than the same period in 2002 due primarily to a change in our
interest bearing advances from El Paso, combined with lower 2003 short-term
interest rates under our cash management program. The average advance balance
changed from $468 million receivable balance for the six months ended June 30,
2002 to an $84 million average payable balance in 2003. The average short-term
interest rates decreased from 1.9% in 2002 to 1.3% in 2003.

INCOME TAXES

<Table>
<Caption>
                                                                  QUARTER         SIX MONTHS
                                                                   ENDED             ENDED
                                                                 JUNE 30,          JUNE 30,
                                                              ---------------   ---------------
                                                               2003     2002     2003     2002
                                                              ------   ------   ------   ------
                                                               (IN MILLIONS, EXCEPT FOR RATES)
<S>                                                           <C>      <C>      <C>      <C>
Income taxes................................................    $ 8      $ 5      $29      $22
Effective tax rate..........................................     29%      26%      30%      28%
</Table>

     Our effective tax rates were different than the statutory rate of 35
percent in all periods, primarily due to state income taxes.

OTHER

     CanEast.  In June 2003, we completed the CanEast Project which extends our
mainline system, through a combination of lease capacity and facilities
modifications, to the Leidy Hub, and expands our capacity in that area by about
127 MMcf/d. Total year to date expenditures on the project were approximately $4
million.

     South Texas Expansion.  The South Texas Expansion Project connects our
existing South Texas system in Hidalgo County to Gasoducto del Rio and is
designed to ultimately deliver an incremental 312 MMcf/d to the Rio Bravo power
generation complex in northern Mexico. The first phase of the project which
provides 220 MMcf/d of capacity was placed in service in August 2003. Total year
to date expenditures on the project were approximately $13 million. Construction
has begun on the second phase of the project which we expect to be completed by
the fourth quarter of 2003.

                         COMMITMENTS AND CONTINGENCIES

     See Item 1, Financial Statements, Note 4, which is incorporated herein by
reference.

                                        13
<PAGE>

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

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     This information updates, and you should read it in conjunction with,
information disclosed in Part II, Item 7A in our Annual Report on Form 10-K for
the year ended December 31, 2002, in addition to the information presented in
Items 1 and 2 of this Quarterly Report on Form 10-Q.

     There are no material changes in our quantitative and qualitative
disclosures about market risks from those reported in our Annual Report on Form
10-K for the year ended December 31, 2002.

ITEM 4. CONTROLS AND PROCEDURES

     Evaluation of Controls and Procedures.  Under the supervision and with the
participation of management, including our principal executive officer and
principal financial officer, we have evaluated the effectiveness of the design
and operation of our disclosure controls and procedures (Disclosure Controls)
and internal controls over financial reporting (Internal Controls) as of the end
of the period covered by this Quarterly Report pursuant to Rules 13a-15 and
15d-15 under the Securities Exchange Act of 1934 (Exchange Act).

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

     Limitations on the Effectiveness of Controls.  Tennessee Gas Pipeline
Company's management, including the principal executive officer and principal
financial officer, does not expect that our Disclosure Controls and Internal
Controls will prevent all errors and all fraud. The design of a control system
must reflect the fact that there are resource constraints, and the benefits of
controls must be considered relative to their costs. Because of the inherent
limitations in all control systems, no evaluation of controls can provide
absolute assurance that all control issues and instances of fraud, if any,
within the company have been detected. These inherent limitations include the
realities that judgments in decision-making can be faulty, and that breakdowns
can occur because of simple errors or mistakes. Additionally, controls can be
circumvented by the individual acts of some persons, by collusion of two or more
people, or by management override of the controls. The design of any system of
controls also is based in part upon certain assumptions about the likelihood of
future events. Therefore, a control system, no matter how well conceived and
operated, can provide only reasonable, not absolute, assurance that the
objectives of the control system are met. Our
                                        14
<PAGE>

Disclosure Controls and Internal Controls are designed to provide such
reasonable assurances of achieving our desired control objectives, and our
principal executive officer and principal financial officer have concluded that
our Disclosure Controls and Internal Controls are effective in achieving that
level of reasonable assurance.

     No Significant Changes in Internal Controls.  We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in
Tennessee Gas Pipeline Company's Internal Controls, or whether the company had
identified any acts of fraud involving personnel who have a significant role in
Tennessee Gas Pipeline Company's Internal Controls. This information was
important both for the controls evaluation generally and because the principal
executive officer and principal financial officer are required to disclose that
information to our Board's Audit Committee and our independent auditors and to
report on related matters in this section of the Quarterly Report. The principal
executive officer and principal financial officer note that there has not been
any change in Internal Controls that occurred during the most recent fiscal
quarter that has materially affected, or is reasonably likely to materially
affect, Internal Controls.

     Effectiveness of Disclosure Controls.  Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that the Disclosure Controls are effective to ensure that material information
relating to Tennessee Gas Pipeline Company and its consolidated subsidiaries is
made known to management, including the principal executive officer and
principal financial officer, on a timely basis.

     Officer Certifications.  The certifications from the principal executive
officer and principal financial officer required under Sections 302 and 906 of
the Sarbanes-Oxley Act of 2002 have been included as Exhibits to this Quarterly
Report.

                                        15
<PAGE>

                          PART II -- OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS

     See Part I, Item 1, Financial Statements, Note 4, which is incorporated
herein by reference.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

     None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

     None.

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

     None.

ITEM 5. OTHER INFORMATION

     None.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

     a. Exhibits

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

<Table>
<Caption>
EXHIBIT
NUMBER                                  DESCRIPTION
-------                                 -----------
<S>       <C>   <C>
  10.A          $3,000,000,000 Revolving Credit Agreement dated as of April
                16, 2003 among El Paso Corporation, El Paso Natural Gas
                Company, Tennessee Gas Pipeline Company and ANR Pipeline
                Company, as Borrowers, the Lenders Party thereto, and
                JPMorgan Chase Bank, as Administrative Agent, ABN Amro Bank
                N.V. and Citicorp North America, Inc., as Co-Document
                Agents, Bank of America, N.A. and Credit Suisse First
                Boston, as Co-Syndication Agents, J.P. Morgan Securities
                Inc. and Citigroup Global Markets Inc., as Joint Bookrunners
                and Co-Lead Arrangers. (Exhibit 99.1 to El Paso
                Corporation's Form 8-K filed April 18, 2003, Commission File
                No. 1-4101).
  10.B          $1,000,000,000 Amended and Restated 3-Year Revolving Credit
                Agreement dated as of April 16, 2003 among El Paso
                Corporation, El Paso Natural Gas Company and Tennessee Gas
                Pipeline Company, as Borrowers, The Lenders Party thereto,
                and JPMorgan Chase Bank, as Administrative Agent, ABN Amro
                Bank N.V. and Citicorp North America, Inc., as Co-Document
                Agents, Bank of America, N.A., as Syndication Agent, J.P.
                Morgan Securities Inc. and Citigroup Global Markets Inc., as
                Joint Bookrunners and Co-Lead Arrangers. (Exhibit 99.2 to El
                Paso Corporation's Form 8-K filed April 18, 2003, Commission
                File No. 1-4101).
  10.C          Security and Intercreditor Agreement dated as of April 16,
                2003 among El Paso Corporation, the persons referred to
                therein as Pipeline Company Borrowers, the persons referred
                to therein as Grantors, each of the Representative Agents,
                JPMorgan Chase Bank, as Credit Agreement Administrative
                Agent and JPMorgan Chase Bank, as Collateral Agent,
                Intercreditor Agent, and Depository Bank. (Exhibit 99.3 to
                El Paso Corporation's Form 8-K filed April 18, 2003,
                Commission File No. 1-4101).
 *31.A          Certification of Chief Executive Officer pursuant to
                sec. 302 of the Sarbanes-Oxley Act of 2002.
 *31.B          Certification of Chief Financial Officer pursuant to
                sec. 302 of the Sarbanes-Oxley Act of 2002.
</Table>

                                        16
<PAGE>

<Table>
<Caption>
EXHIBIT
NUMBER                                  DESCRIPTION
-------                                 -----------
<S>       <C>   <C>
 *32.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.
 *32.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 such instruments does not exceed 10 percent
of our total consolidated assets.

     b. Reports on Form 8-K

<Table>
<S>                                        <C>
None.
</Table>

                                        17
<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.

                                            TENNESSEE GAS PIPELINE COMPANY

Date: August 13, 2003                          /s/ JOHN W. SOMERHALDER II
                                            ------------------------------------
                                                   John W. Somerhalder II
                                             Chairman of the Board and Director
                                               (Principal Executive Officer)

Date: August 13, 2003                              /s/ GREG G. GRUBER
                                            ------------------------------------
                                                       Greg G. Gruber
                                                   Senior Vice President,
                                             Chief Financial Officer, Treasurer
                                                        and Director
                                            (Principal Financial and Accounting
                                                          Officer)

                                        18
<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
-------                           -----------
<S>       <C>
 10.A     $3,000,000,000 Revolving Credit Agreement dated as of April
          16, 2003 among El Paso Corporation, El Paso Natural Gas
          Company, Tennessee Gas Pipeline Company and ANR Pipeline
          Company, as Borrowers, the Lenders Party thereto, and
          JPMorgan Chase Bank, as Administrative Agent, ABN Amro Bank
          N.V. and Citicorp North America, Inc., as Co-Document
          Agents, Bank of America, N.A. and Credit Suisse First
          Boston, as Co-Syndication Agents, J.P. Morgan Securities
          Inc. and Citigroup Global Markets Inc., as Joint Bookrunners
          and Co-Lead Arrangers. (Exhibit 99.1 to El Paso
          Corporation's Form 8-K filed April 18, 2003, Commission File
          No. 1-4101).
 10.B     $1,000,000,000 Amended and Restated 3-Year Revolving Credit
          Agreement dated as of April 16, 2003 among El Paso
          Corporation, El Paso Natural Gas Company and Tennessee Gas
          Pipeline Company, as Borrowers, The Lenders Party thereto,
          and JPMorgan Chase Bank, as Administrative Agent, ABN Amro
          Bank N.V. and Citicorp North America, Inc., as Co-Document
          Agents, Bank of America, N.A., as Syndication Agent, J.P.
          Morgan Securities Inc. and Citigroup Global Markets Inc., as
          Joint Bookrunners and Co-Lead Arrangers. (Exhibit 99.2 to El
          Paso Corporation's Form 8-K filed April 18, 2003, Commission
          File No. 1-4101).
 10.C     Security and Intercreditor Agreement dated as of April 16,
          2003 among El Paso Corporation, the persons referred to
          therein as Pipeline Company Borrowers, the persons referred
          to therein as Grantors, each of the Representative Agents,
          JPMorgan Chase Bank, as Credit Agreement Administrative
          Agent and JPMorgan Chase Bank, as Collateral Agent,
          Intercreditor Agent, and Depository Bank. (Exhibit 99.3 to
          El Paso Corporation's Form 8-K filed April 18, 2003, Commis-
          sion File No. 1-4101).
*31.A     Certification of Chief Executive Officer pursuant to sec.
          302 of the Sarbanes-Oxley Act of 2002.
*31.B     Certification of Chief Financial Officer pursuant to sec.
          302 of the Sarbanes-Oxley Act of 2002.
*32.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.
*32.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.
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