TENNESSEE GAS PIPELINE CO - 10-Q Quarterly Report

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

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FORM 10-Q

(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 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

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

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)

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 November 10,
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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TENNESSEE GAS PIPELINE COMPANY

TABLE OF CONTENTS

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

/d = per day
BBtu = billion British thermal units
MMcf = million cubic feet

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

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PART I -- FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TENNESSEE GAS PIPELINE COMPANY

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

See accompanying notes.

1

TENNESSEE GAS PIPELINE COMPANY

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

See accompanying notes.

2

TENNESSEE GAS PIPELINE COMPANY

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

See accompanying notes.

3

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 September 30, 2003, and for the
quarters and nine months ended September 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 be indicative of our 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 had 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 currently apply the provisions of SFAS No. 71,
Accounting for the Effects of Certain Types of Regulation. The accounting
required by SFAS No. 71 differs from the accounting required for businesses that
do not apply its provisions. Transactions that are generally recorded
differently as a result of applying regulatory accounting requirements include
the capitalization of an equity return component on regulated capital projects,
post retirement employee benefit plans and other costs included in, or expected
to be included in, future rates. As a result of recent changes in our
competitive environment and operating cost structure, we continue to assess the
applicability of the provisions of SFAS No. 71 to our financial statements.

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, negative goodwill should be written off as a
cumulative effect of an accounting change. Prior to adoption of these 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 pre-tax 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.

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3. DEBT AND OTHER CREDIT FACILITIES

Trinity River

In March 2003, El Paso retired amounts outstanding under its Trinity River
financing arrangement. Prior to this retirement, our 50 percent ownership in
Bear Creek Storage, along with various assets of El Paso, collateralized that
arrangement.

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 LIBOR
plus 350 basis points, letter of credit fees of 350 basis points and a
commitment fee of 75 basis points on the unused portion of the facility. This
facility replaces El Paso's previous $3 billion revolving credit facility.
Approximately $1 billion of other 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 its equity in us and
our equity in Bear Creek Storage, collateralizes the $3 billion revolving credit
facility and the other financing arrangements. We were jointly and severally
liable under the $3 billion revolving credit facility through August 19, 2003,
after which time we are only liable for amounts we directly borrow. As of
September 30, 2003, $1.3 billion was outstanding and $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 were also a borrower under El Paso's $1 billion revolving credit
facility which expired on August 4, 2003.

Under the $3 billion revolving credit facility and other indentures, 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 transactions 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
discussed in Note 5. For the nine months ended September 30, 2003, we were in
compliance with these covenants.

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 Stevens County,
Kansas. Quinque has been dropped as a plaintiff and Will Price has been added.
This class action complaint alleges that the defendants mismeasured natural gas
volumes and heating content of natural gas on non-federal and non-Native
American lands. The plaintiff in this case seeks certification of a

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nationwide class of natural gas working interest owners and natural gas royalty
owners to recover royalties that the plaintiff contends these owners should have
received had the volume and heating value of natural gas produced from their
properties been differently measured, analyzed, calculated and reported,
together with prejudgment and postjudgment interest, punitive damages, treble
damages, attorneys' 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 September 30, 2003, we had no material 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 September
30, 2003, we had accrued approximately $48 million, including approximately $47
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 September 30, 2003 was based on the most likely outcome that can be
reasonably estimated. Below is a reconciliation of our accrued liability as of
September 30, 2003 (in millions):

Balance as of January 1, 2003............................... $ 84
Additions/adjustments for remediation activities(1)......... (31)
Payments for remediation activities......................... (5)
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Balance as of September 30, 2003............................ $ 48
====

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(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 $48 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 remediation
expenditures will be approximately $2 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 our
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
estimate a more likely outcome for the total project has not been possible until
recently. The new estimate identified a $31 million reduction in our estimated
cost to complete the project.

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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 September 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 September 30, 2003, we have recorded a regulatory liability (included
in other non-current liabilities on our balance sheet) of $85 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 three 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 September
30, 2003 we have estimated our share of the remediation costs at 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. Reserves for these matters are included in the
environmental reserve discussed above.

It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe our 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 September 30,
2003, $68 million of the interruptible transportation surcharge had been
collected. There is no time limit for collection of the remaining

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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, issue
operational flow orders and impose 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 FERC 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 FERC clarified
its application of its policy to allow replacement shippers the ability to
select additional primary points as that policy applies to our grandfathered
contracts finding that replacement shippers are not permitted to obtain
redundant primary delivery point rights in excess of their contract demand. The
FERC 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. We filed certain required tariff revisions
relating to operational flow orders (OFO), OFO penalties, and penalty revenue
crediting and sought further rehearing of certain issues. We implemented most
all of Order No. 637 provisions on October 1, 2003, except for point elevations,
for which we have sought an April 1, 2004 effective date. 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) proposing 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 have
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 an order that prospectively prohibits
pipelines from negotiating rates based upon natural gas commodity price indices
and imposes certain new filing requirements to ensure the transparency of
negotiated rate transactions. Requests for rehearing were filed on August 25,
2003 and remain pending. We do not expect that the order on rehearing will have
a material effect on us.

Cash Management Rule. On October 23, 2003, the FERC approved a rule that
requires a FERC regulated entity to file its cash management agreement with the
FERC, maintain records of transactions involving its participation in the cash
management program, compute its proprietary capital ratio quarterly based on
criteria established by the FERC, and notify the FERC 45 days after the end of a
calendar quarter whether its proprietary capital ratio falls below 30 percent
and subsequently when its proprietary capital ratio returns to or exceeds 30
percent. In the rule, the FERC stated that the requirements imposed by the rule
are not in the nature of a regulation governing participation in cash management
programs and that the rule does

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not dictate the content or terms for participating in a cash management program.
Although the rule is subject to rehearing, we do not believe an order on
rehearing will have a material effect on us.

On September 10, 2003, the Office of Executive Director of Regulatory
Audits completed an industry-wide audit of the FERC Form 2 related to cash
management. The audit included our affiliates, EPNG and Mojave. The audit did
not identify any instances of non-compliance with the FERC's reporting and
recording requirements but recommended that EPNG and Mojave revise and update
their existing cash management agreements with El Paso. We are in the process of
reviewing and revising our cash management agreement pursuant to this
recommendation.

Emergency Reconstruction of Interstate Natural Gas Facilities Rule. On May
19, 2003, the FERC issued a 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 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. It also 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. Although we cannot predict the outcome of this
rulemaking, we do not expect this order to have a material effect on us.

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 possible that the outcome of these
matters could impact our credit rating and that of our parent. Further, for
environmental matters, it is 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.

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:

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

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In October 2003, we announced the sale of our 29.64 percent interest in the
Portland Natural Gas Transmission system to TransCanada Corporation for
approximately $56 million. We will record a pre-tax loss of approximately $2
million related to this sale in the fourth quarter of 2003.

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. As of September 30, 2003 and December 31,
2002, we had advanced to El Paso $691 million and $599 million. The market rate
of interest at September 30, 2003 was 3.5% and at December 31, 2002, was 1.5%.
These receivables are due upon demand; however, as of September 30, 2003 and
December 31, 2002, we have classified these amounts as non-current notes
receivable 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 December 31, 2002, at an interest rate of 2.21%.

At September 30, 2003 and December 31, 2002, we also had other accounts
receivable from related parties of $205 million and $72 million. In addition, we
had accounts payable to related parties of $132 million and $88 million at
September 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 nine months ended September 30, 2003 and 2002:

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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 and 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 accounting changes, (ii) income taxes, (iii)
interest and debt expense and (iv) affiliated interest income. Our business
consists of consolidated operations as well as investments in unconsolidated
affiliates. 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 both our consolidated
business and our unconsolidated investments. In addition, this is the
measurement used by El Paso to evaluate the operating performance of its
business segments. We exclude interest and debt expense from this measure so
that investors may evaluate our operating results without regard to our
financing methods. EBIT 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 September 30:

Third Quarter 2003 Compared to Third Quarter 2002

Operating revenues for the quarter ended September 30, 2003, were $19
million lower than the same period in 2002. This decrease was primarily due to a
$14 million favorable resolution of measurement issues at a processing plant
serving our pipeline system in 2002. Also contributing to the decrease was $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 our sale of ETN in March 2000 and a decrease
in transportation reservation revenues of $2 million due to the impact of
contract conversions and renewals.

Operating expenses for the quarter ended September 30, 2003, were $6
million lower than the same period in 2002 primarily due to lower shared
services costs allocated to us.

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Nine Months Ended 2003 Compared to Nine Months Ended 2002

Operating revenues for the nine months ended September 30, 2003, were $8
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 $21 million
and increased transportation revenues of $21 million due primarily to higher
throughput in 2003 as a result of colder weather. The increase was partially
offset by an $18 million favorable resolution of measurement issues at a
processing plant serving our pipeline system in 2002, lower transportation
reservation revenues in 2003 of $13 million due to the impact of contract
conversions and renewals, and $4 million related to the amortization of deferred
contract revenue from March 2000 through February 2003 for services provided to
ETN's customers following our sale of ETN in March 2000.

Operating expenses for the nine months ended September 30, 2003, were $8
million lower than the same period in 2002. The decrease was due to $15 million
of lower environmental remediation, legal and other related costs primarily due
to a revision in the second quarter of 2003 of our estimated costs to complete
our internal PCB remediation project and $9 million in lower shared services
costs allocated to us. 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 $4 million
and higher amortization expense of $3 million related to acquisition costs
assigned to our utility plant.

INTEREST AND DEBT EXPENSE

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

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

AFFILIATED INTEREST INCOME, NET

Third Quarter 2003 compared to Third Quarter 2002

Affiliated interest income, net for the quarter ended September 30, 2003,
was $1 million lower than the same period in 2002 due primarily to lower average
advances to El Paso under its cash management program offset by higher
short-term interest rates in 2003. The average advance balance due from El Paso
of $598 million for the third quarter of 2002 decreased to $396 million during
the same period in 2003. The average short-term interest rates for the third
quarter increased from 1.8% in 2002 to 1.9% during the same period in 2003.

Nine Months Ended 2003 compared to Nine Months Ended 2002

Affiliated interest income, net for the nine months ended September 30,
2003, was $5 million lower than the same period in 2002 due primarily to lower
average advances to El Paso under its cash management program and lower
short-term interest rates in 2003. The average advance balance due from El Paso
of $500 million for the nine months ended September 30, 2002 decreased to $118
million during the same period

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in 2003. The average short-term interest rates decreased from 1.9% in 2002 to
1.6% during the same period in 2003.

INCOME TAXES

Our effective tax rates were different than the statutory rate of 35
percent in all periods, primarily due to state income tax net operating losses
which reduced the rate.

OTHER

CanEast. In June 2003, we completed the CanEast Project which extends our
mainline system, through a combination of lease capacity and facility
modifications, to the Leidy Hub in Leidy, Pennsylvania and expands our capacity
in that area by about 127 MMcf/d. Total year to date expenditures on the project
were approximately $6 million.

South Texas Expansion. The South Texas Expansion Project connects our
existing South Texas system in Hidalgo County, Texas to Gasoducto del Rio,
Mexico 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 first phase were approximately $16
million. Construction has begun on the second phase of the project and we expect
to place it in service during the fourth quarter of 2003. Total year to date
expenditures on the second phase have been approximately $4 million.

COMMITMENTS AND CONTINGENCIES

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

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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

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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

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.

Undertaking

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

b. Reports on Form 8-K

None.

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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: November 10, 2003 /s/ JOHN W. SOMERHALDER II
------------------------------------
John W. Somerhalder II
Chairman of the Board and Director
(Principal Executive Officer)

Date: November 10, 2003 /s/ GREG G. GRUBER
------------------------------------
Greg G. Gruber
Senior Vice President,
Chief Financial Officer, Treasurer
and Director
(Principal Financial and Accounting
Officer)

17

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.