TENNESSEE GAS PIPELINE CO - 10-K Annual Report

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-K
(MARK ONE)

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

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

OR

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

FOR THE TRANSITION PERIOD FROM TO .

COMMISSION FILE NUMBER 1-4101

TENNESSEE GAS PIPELINE COMPANY
(Exact name of registrant as specified in its charter)

DELAWARE 74-1056569
(State or Other Jurisdiction of (I.R.S. Employer
Incorporation or Organization) Identification No.)

EL PASO BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)

TELEPHONE NUMBER: (713) 420-2600

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT: NONE

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE

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 if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [X]

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Act). Yes [ ] No [X]

STATE THE AGGREGATE MARKET VALUE OF THE VOTING STOCK HELD BY NON-AFFILIATES
OF THE
REGISTRANT.... NONE

INDICATE THE NUMBER OF SHARES OUTSTANDING OF EACH OF THE REGISTRANT'S
CLASSES OF COMMON STOCK, AS OF THE LATEST PRACTICABLE DATE.

Common Stock, par value $5 per share. Shares outstanding on March 27, 2003:
208

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

DOCUMENTS INCORPORATED BY REFERENCE: NONE

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TENNESSEE GAS PIPELINE COMPANY

TABLE OF CONTENTS

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* We have not included a response to this item in this document since no
response is required pursuant to the reduced disclosure format permitted by
General Instruction I to Form 10-K.

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
Bcf = billion cubic feet
MMcf = million cubic feet

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

When we refer to "us", "we", "our", or "ours", we are describing Tennessee
Gas Pipeline Company and/or our subsidiaries.

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PART I

ITEM 1. BUSINESS

GENERAL

We are a Delaware corporation incorporated in 1947 and a wholly owned
subsidiary of El Paso Tennessee Pipeline Co., a direct subsidiary of El Paso
Corporation (El Paso). Our primary business consists of the interstate
transportation and storage of natural gas. We conduct our business activities
through two natural gas pipeline systems and storage facilities, all of which
are discussed below.

The Pipeline Systems. The Tennessee Gas Pipeline (TGP) system consists of
approximately 14,200 miles of pipeline with a design capacity of approximately
6,487 MMcf/d. During 2002, 2001 and 2000, our average throughput was 4,596
BBtu/d, 4,405 BBtu/d and 4,354 BBtu/d. This multiple-line system begins in the
natural gas producing regions of Louisiana, the Gulf of Mexico and south Texas
and extends to the northeast section of the U.S., including the metropolitan
areas of New York City and Boston. The TGP system also has an interconnect at
the U.S.-Mexico border.

We have a number of transmission system expansion projects that have been
approved by the Federal Energy Regulatory Commission (FERC) as follows:

We also have an approximate 30 percent ownership interest in the Portland
Natural Gas Transmission system. The Portland system consists of approximately
294 miles of interstate natural gas pipeline, including lateral lines, with a
design capacity of 214 MMcf/d. During 2002, 2001 and 2000, average throughput on
the Portland system was 144 BBtu/d, 123 BBtu/d and 110 BBtu/d. The Portland
system extends from the Canadian border near Pittsburg, New Hampshire to Dracut,
Massachusetts.

Storage Facilities. Along our TGP pipeline system, we have approximately
97 Bcf of underground working natural gas storage capacity, of which 7 Bcf is
contracted from ANR Pipeline Company and 29 Bcf from Bear Creek Storage Company
(Bear Creek), our affiliates.

Bear Creek is a joint venture that we own equally with our affiliate,
Southern Gas Storage Company. Bear Creek owns and operates an underground
natural gas storage facility located in Louisiana. The facility has a capacity
of 50 Bcf of base gas and 58 Bcf of working storage. Bear Creek's working
storage capacity is committed equally to Southern Natural Gas Company and us
under long-term contracts.

Under our tariff structure, customers pay us on the basis of stated rates
for transportation, storage and related services. Approximately 71 percent of
our transportation and storage revenue is attributable to a capacity reservation
or a demand charge paid by "firm" customers. These firm customers are obligated
to pay a monthly demand charge, regardless of the amount of natural gas they
transport or store, for the term of their contracts. The remaining 29 percent of
our revenue is attributable to charges based solely on the volumes of natural
gas actually transported or stored on our pipeline system.

REGULATORY ENVIRONMENT

Our interstate natural gas transmission systems and storage operations are
regulated by the FERC under the Natural Gas Act of 1938 and the Natural Gas
Policy Act of 1978. Our pipeline systems and storage

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facilities operate under FERC-approved tariffs that establish rates, terms and
conditions for services to their customers. Generally, the FERC's authority
extends to:

- rates and charges for natural gas transportation, storage and related
services;

- certification and construction of new facilities;

- extension or abandonment of facilities;

- maintenance of accounts and records;

- relationships between pipeline and marketing affiliates;

- terms and conditions of services;

- depreciation and amortization policies;

- acquisition and disposition of facilities; and

- initiation and discontinuation of services.

The fees or rates established under our tariffs are a function of our costs
of providing services to our customers, and include provisions for a reasonable
return on our invested capital. Consequently, our financial results have
historically been relatively stable. However, our results can be subject to
volatility due to factors such as weather, changes in natural gas prices and
market conditions, regulatory actions, competition and the credit-worthiness of
our customers.

Our interstate pipeline system is also subject to federal, state and local
statutes and regulations regarding pipeline safety and environmental matters.
Our system has an ongoing inspection program designed to keep all of our
facilities in compliance with environmental and pipeline safety requirements. We
believe that our system is in material compliance with the applicable
requirements.

We are also subject to regulation over the safety requirements in the
design, construction, operation and maintenance of our interstate natural gas
transmission systems and storage facilities by the U.S. Department of
Transportation. Our operations on U.S. government land are regulated by the U.S.
Department of the Interior.

A discussion of our significant rate and regulatory matters is included in
Part II, Item 8, Financial Statements and Supplementary Data, Note 8 and is
incorporated herein by reference.

MARKETS AND COMPETITION

On our TGP system, we have approximately 434 firm and interruptible
customers, including distribution and industrial companies, electric generation
companies, natural gas producers, other natural gas pipelines and natural gas
marketing and trading companies. We provide transportation services in both our
natural gas supply and market areas. We have approximately 436 firm
transportation contracts with remaining terms that extend from one month to 19
years and with a weighted average remaining contract term of approximately five
years. As of December 31, 2002, approximately 93 percent of our total capacity
is subscribed under firm transportation agreements. We do not own a majority of
the natural gas that we transport or store and accordingly do not assume natural
gas commodity price risk related to such gas.

Our TGP interstate natural gas transmission system and natural gas storage
business face varying degrees of competition from other pipelines, as well as
from alternative energy sources such as electricity, hydroelectric power, coal
and fuel oil. We compete with other interstate and intrastate pipelines for
deliveries to customers who can take deliveries at multiple connection points.
Our system faces strong competition in the Northeast, Appalachian, Midwest and
Southeast market areas. We also compete with other pipelines and local
distribution companies to deliver increased quantities of natural gas to our
market areas. In addition, we compete with pipelines and gathering systems for
connection to new supply sources in Texas, the Gulf of Mexico and at the
Canadian border.

Electric power generation is one of the fastest growing demand sectors of
the natural gas market. The potential consequences of proposed and ongoing
restructuring and deregulation of the electric power industry

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are currently unclear. Restructuring and deregulation benefits the natural gas
industry by creating more demand for natural gas turbine generated electric
power, but this effect is offset, in varying degrees, by increased generation
efficiency and more effective use of surplus electric capacity as a result of
open market access.

In response to changing market conditions, we have shifted from a
traditional dependence solely on long-term contracts to an approach that
balances short-term and long-term commitments. The shift is due to changes in
market conditions and competition driven by state utility deregulation, local
distribution company mergers, new supply sources, volatility in natural gas
prices, demand for short-term capacity and new markets in power plants.

Our ability to extend our existing contracts or re-market expiring capacity
is dependent on competitive alternatives, access to capital, the regulatory
environment at the local, state and federal levels and market supply and demand
factors at the relevant dates these contracts are extended or expire. The
duration of new or re-negotiated contracts will be affected by current prices,
competitive conditions and judgments concerning future market trends and
volatility. While we are allowed to negotiate contract terms at fully subscribed
quantities and at maximum rates allowed under our tariffs, we must, at times,
discount our contracts to remain competitive.

ENVIRONMENTAL

A description of our environmental activities is included in Part II, Item
8, Financial Statements and Supplementary Data, Note 8, and is incorporated
herein by reference.

EMPLOYEES

As of March 26, 2003, we had approximately 1,580 full-time employees, none
of whom is subject to a collective bargaining arrangement.

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ITEM 2. PROPERTIES

A description of our properties is included in Item 1, Business, and is
incorporated herein by reference.

We believe that we have satisfactory title to the properties owned and used
in our businesses, subject to liens for taxes not yet payable, liens incident to
minor encumbrances, liens for credit arrangements and easements and restrictions
that do not materially detract from the value of these properties, our interests
in these properties, or the use of these properties in our businesses. We
believe that our properties are adequate and suitable for the conduct of our
business in the future.

ITEM 3. LEGAL PROCEEDINGS

A description of our legal proceedings is included in Part II, Item 8,
Financial Statements and Supplementary Data, Note 8, and is incorporated herein
by reference.

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

Item 4, Submission of Matters to a Vote of Security Holders, has been
omitted from this report pursuant to the reduced disclosure format permitted by
General Instruction I to Form 10-K.

PART II

ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

All of our common stock, par value $5 per share, is owned by El Paso
Tennessee Pipeline Co. and, accordingly, there is no public trading market for
our stock.

We pay dividends on our common stock from time to time from legally
available funds that have been approved for payment by our Board of Directors.
During 2002, a $67 million non-cash dividend of affiliated receivables was
declared and paid to our parent. No dividends were declared or paid in 2001.

ITEM 6. SELECTED FINANCIAL DATA

Item 6, Selected Financial Data, has been omitted from this report pursuant
to the reduced disclosure format permitted by General Instruction I to Form
10-K.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS

The information required by this Item is presented in a reduced disclosure
format pursuant to General Instruction I to Form 10-K. The notes to our
consolidated financial statements contain information that is pertinent to the
following analysis, including a discussion of our significant accounting
policies.

GENERAL

Our business consists of interstate natural gas transmission and storage
operations and related services. Our interstate natural gas transmission systems
and natural gas storage business face varying degrees of competition from other
pipelines, as well as from alternate energy sources, such as electricity,
hydroelectric power, coal and fuel oil. We are regulated by the FERC which
regulates the rates we can charge our customers. These rates are a function of
our costs of providing services to our customers, and include a return on our
invested capital. As a result, our financial results have historically been
relatively stable. However, they can be subject to volatility due to factors
such as weather, changes in natural gas prices and market conditions, regulatory
actions, competition and the credit-worthiness of our customers. In addition,
our ability to extend existing customer contracts or re-market expiring
contracted capacity is dependent on competitive alternatives, the regulatory
environment and supply and demand factors at the relevant dates these contracts
are extended or expire. We make every attempt to negotiate contract terms at
fully-subscribed quantities and at maximum rates allowed under our tariffs,
although at times, we discount our rates to remain competitive.

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 operating
income, adjusted for equity earnings from unconsolidated affiliates, gains and
losses on sales of assets, and other miscellaneous non-operating items. Items
that are not included in this measure are financing costs, including interest
and debt expense, affiliated interest income, income taxes and cumulative effect
of accounting change. Below is a reconciliation of operating results to EBIT and
income before cumulative effect of accounting change for the year ended December
31:

We believe EBIT is a useful measurement for our investors because it
provides information that can be used to evaluate the effectiveness of our
businesses and investments from an operational perspective, exclusive of the
costs to finance those activities and exclusive of income taxes, neither of
which are directly relevant to the efficiency of those operations. This
measurement may not be comparable to measurements used by other

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companies and should not be used as a substitute for net income or other
performance measures such as operating cash flow.

OPERATING RESULTS (EBIT)

Operating revenues for the year ended December 31, 2002, were $26 million
lower than in 2001. This decrease included $19 million due to lower
transportation revenues from open capacity sold under short-term contracts due
to milder weather in 2002, as well as an $11 million decrease due to the
favorable resolution of regulatory issues related to natural gas purchase
contracts in 2001. The impact of lower natural gas prices in 2002 on natural gas
recoveries caused a decrease of $26 million. These decreases were partially
offset by an increase of $18 million due to the favorable resolution in 2002 of
measurement issues at a processing plant serving our system and additional
revenues of $13 million from transmission system expansion projects placed in
service after the fourth quarter of 2001.

Operating expenses for the year ended December 31, 2002, were $52 million
higher than in 2001. The increases were due to $30 million of higher shared
services costs allocated to us by El Paso, higher amortization expense of $13
million related to additional acquisition costs assigned to our utility plant
and higher field operation costs of $2 million in 2002. Also contributing to the
increase were higher costs associated with contracted natural gas storage of $4
million and higher electric compression costs of $3 million.

REVENUE OUTLOOK

Our business is primarily driven by contracts with shippers transporting or
storing natural gas on our pipeline system. Our tariff structure, which is
regulated by the FERC, requires shippers to pay us on the basis of stated
transportation and storage rates. Under our tariff structure, approximately 71
percent of our transportation and storage revenue is attributed to a capacity
reservation, or demand charge, paid by firm customers. These firm customers are
obligated to pay a monthly demand charge, regardless of the amount of natural
gas they actually transport or store on our pipeline system, for the term of
their contracts. As these contracts expire, our revenue varies depending on the
rates at which they are renewed. During 2002, the renewal rates for contracts
with our customers have declined as a result of increased competition, causing
our revenue to decrease. We anticipate this trend to stabilize or to improve in
the foreseeable future based on the current market environment for our pipeline
system.

INTEREST AND DEBT EXPENSE

Interest and debt expense for the year ended December 31, 2002, was $14
million higher than 2001. Below is the analysis of our interest expense for the
year ended December 31:

The increase in interest and debt expense on long-term debt was due to
higher average debt balances outstanding in 2002 than in 2001. In June 2002, we
issued $240 million aggregate principal amount 8.375% notes due 2032, resulting
in $12 million of increased interest expense. Also contributing to the increase
was a decrease in interest capitalized on construction projects of $8 million
due to lower capitalization rates in 2002 than in 2001. Offsetting the increased
interest expense was a decrease in the average commercial paper balances
outstanding from $320 million in 2001 to $257 million in 2002 with the weighted
average interest rate

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decreasing from 4.78% in 2001 to 2.62% in 2002, resulting in a decrease in
interest expense for short-term borrowings of $8 million.

AFFILIATED INTEREST INCOME

Affiliated interest income for the year ended December 31, 2002, was $8
million higher than 2001. The increase was primarily due to the increase in
interest bearing advances to El Paso, partially offset by lower 2002 short-term
interest rates under El Paso's cash management program. The average short-term
interest rates decreased from 4.3% in 2001 to 1.8% in 2002, and average advances
to affiliates participating in our cash management program were $474 million in
2002 versus $15 million in 2001.

INCOME TAXES

Income tax expense for the years ended December 31, 2002 and 2001, was $42
million and $72 million, resulting in effective tax rates of 29 percent and 32
percent. Our effective tax rates differed from the statutory rate of 35 percent
in both periods primarily due to state income taxes. For a reconciliation of the
statutory rate to the effective rates, see Item 8, Financial Statements and
Supplementary Data, Note 2.

OTHER

In October 2001, we announced the development of our Blue Atlantic
Transmission System. This pipeline project consists of approximately 750 miles
of 36-inch pipe designed to carry up to 1 Bcf/d. The pipeline will follow a
sub-sea route from an anticipated production area offshore on the Scotian shelf,
make landfall on the Southern coast of Nova Scotia, then continue sub-sea to
landing points in the New York and New Jersey areas. Current cost estimates are
approximately $2.5 billion, and current expenditures to date are $21 million. We
anticipate that all necessary regulatory filings will be made in 2004, and the
system will be placed in service by the fourth quarter of 2007.

LIQUIDITY AND CAPITAL RESOURCES

LIQUIDITY

Our liquidity needs are provided by cash flow from operating activities and
the use of a cash management program with our parent company, El Paso. Under El
Paso's cash management program, depending on whether we have short-term cash
surpluses or requirements, we either provide cash to El Paso or El Paso provides
cash to us. We have historically provided cash advances to El Paso, and we
reflect these net advances to our parent as investing activities in our
statement of cash flows. As of December 31, 2002, we had advanced $599 million
as a result of this program. These receivables are due upon demand; however, as
of December 31, 2002, we have classified this amount as non-current notes
receivable from affiliates in our balance sheet because we do not anticipate
settlement within the next twelve months. We believe that cash flow from
operating activities and cash provided by El Paso's cash management program will
be adequate to meet our short-term capital requirements for existing operations.
Our cash flows for the years ended December 31 were as follows:

In a series of credit rating agency actions in late 2002 and early 2003,
and contemporaneously with the downgrades of the senior unsecured indebtedness
of our parent company, El Paso, our senior unsecured indebtedness was downgraded
to below investment grade and is currently rated B1 by Moody's and B+ by
Standard & Poor's and we remain on negative outlook. These downgrades will
increase our cost of capital, collateral requirements and could impede our
access to capital markets in the future.

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As a result of the downgrade of El Paso's credit rating to below investment
grade, cash generated within our Bear Creek investment can be used only for
purposes of redeeming the preferred interests of an El Paso financing
arrangement, referred to as Trinity River, that our investment collateralizes
and for its internal cash needs. Until the preferred interests were redeemed in
full, we were not able to receive any cash distributions from our ownership
interest in Bear Creek. In March 2003, El Paso entered into a $1.2 billion
two-year term loan and the proceeds were used to retire the outstanding balance
under the Trinity River financing agreement.

In August 2002, the FERC issued a notice of proposed rulemaking requiring,
among other things, that FERC regulated entities participating in cash
management arrangements with non-FERC regulated parents maintain a minimum
proprietary capital balance of 30 percent, and that the FERC regulated entity
and its parent maintain investment grade credit ratings, as a condition to
participating in the cash management program. If this proposal were adopted, the
cash management program with El Paso would terminate, which could affect our
liquidity. We cannot predict the outcome of this rulemaking at this time.

CAPITAL EXPENDITURES

Our capital expenditures during the periods indicated are listed below:

Under our current plan, we expect to spend between approximately $144
million and $172 million in each of the next three years for capital
expenditures primarily to maintain the integrity of our pipelines and ensure the
reliable delivery of natural gas to our customers. In addition, we have budgeted
to spend between $48 million and $316 million in each of the next three years to
expand the capacity and services of our pipeline systems for long-term
contracts. In the current environment, we will require long-term contract
commitments for capital intensive projects. We expect to fund our maintenance
and expansion capital expenditures through internally generated funds and
external financing.

DEBT

As of December 31, 2002, we had long-term debt outstanding of $1,595
million, net of a $31 million discount, none of which matures within the next
five years. For a discussion of our debt and other credit facilities, see Item
8, Financial Statements and Supplementary Data, Note 7, which is incorporated
herein by reference.

COMMITMENTS AND CONTINGENCIES

For a discussion of our commitments and contingencies, see Item 8,
Financial Statements and Supplementary Data, Note 8, which is incorporated
herein by reference.

NEW ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

As of December 31, 2002, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.

ACCOUNTING FOR COSTS ASSOCIATED WITH EXIT OR DISPOSAL ACTIVITIES

In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated
with Exit or Disposal Activities. This statement will require us to recognize
costs associated with exit or disposal activities when they

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are incurred rather than when we commit to an exit or disposal plan. Examples of
costs covered by this guidance include lease termination costs, employee
severance costs associated with a restructuring, discontinued operations, plant
closings or other exit or disposal activities. This statement is effective for
fiscal years beginning after December 31, 2002, and will impact any exit or
disposal activities we initiate after January 1, 2003.

ACCOUNTING FOR GUARANTEES

In November 2002, the FASB issued FASB Interpretation (FIN) No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. This interpretation requires
that companies record a liability for all guarantees issued after January 31,
2003, including financial, performance, and fair value guarantees. This
liability is recorded at its fair value upon issuance, and does not affect any
existing guarantees issued before December 31, 2002. While we do not believe
there will be any initial impact of adopting this standard, it will impact any
guarantees we issue in the future.

RISK FACTORS AND 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 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. Our forward-looking statements,
whether written or oral, are expressly qualified by these cautionary statements
and any other cautionary statements that may accompany those statements. In
addition, we disclaim any obligation to update any forward-looking statements to
reflect events or circumstances after the date of this report.

With this in mind, you should consider the risks discussed elsewhere in
this report and other documents we file with the Securities and Exchange
Commission (SEC) from time to time and the following important factors that
could cause actual results to differ materially from those expressed in any
forward-looking statement made by us or on our behalf.

RISKS RELATED TO OUR BUSINESS

OUR SUCCESS DEPENDS ON FACTORS BEYOND OUR CONTROL.

Our business is the transportation and storage of natural gas for third
parties. As a result, the volume of natural gas involved in these activities
depends on the actions of those third parties and is beyond our control.
Further, the following factors, most of which are beyond our control, may
unfavorably impact our ability to maintain or increase current revenues, to
renegotiate existing contracts as they expire, or to remarket unsubscribed
capacity:

- future weather conditions, including those that favor alternative energy
sources;

- price competition;

- drilling activity and supply availability;

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- expiration and/or turn back of significant contracts;

- service area competition;

- changes in regulation and actions of regulatory bodies;

- credit risk of customer base;

- increased cost of capital; and

- natural gas and liquids prices.

THE REVENUES OF OUR PIPELINE BUSINESSES ARE GENERATED UNDER CONTRACTS THAT MUST
BE RENEGOTIATED PERIODICALLY.

Our revenues are generated under contracts which expire periodically and
must be renegotiated and extended or replaced. Although we actively pursue the
renegotiation, extension and/or replacement of these contracts, we cannot assure
you that we will be able to extend or replace these contracts when they expire
or that the terms of any renegotiated contracts will be as favorable as the
existing contracts. Currently, a substantial portion of our revenues are under
contracts that are discounted at rates below the maximum rates allowed under our
tariff. For a further discussion of these matters, see Part I, Item 1,
Business -- Markets and Competition.

In particular, our ability to extend and/or replace contracts could be
adversely affected by factors we cannot control, including:

- the proposed construction by other companies of additional pipeline
capacity in markets served by us;

- changes in state regulation of local distribution companies, which may
cause them to negotiate short-term contracts or turn back their capacity
when their contracts expire;

- reduced demand and market conditions;

- the availability of alternative energy sources or gas supply points; and

- regulatory actions.

If we are unable to renew, extend or replace these contracts or if we renew
them on less favorable terms, we may suffer a material reduction in our revenues
and earnings.

WE FACE COMPETITION THAT COULD ADVERSELY AFFECT OUR OPERATING RESULTS.

In the northeastern markets, we compete with other interstate and
intrastate pipeline companies and local distribution companies in the
transportation and storage of natural gas. If we are unable to compete
effectively with these and other energy enterprises, our future profitability
may be negatively impacted. Even if we do compete effectively with these and
other energy enterprises, we may discount our rates more than currently
anticipated to retain committed volumes or to re-contract released volumes as
our existing contracts expire, which could adversely affect our revenues and
results of operations.

FLUCTUATIONS IN ENERGY COMMODITY PRICES COULD ADVERSELY AFFECT OUR BUSINESS.

If natural gas prices in the supply basins connected to our pipeline system
are higher than prices in other natural gas producing regions, especially
Canada, our ability to compete with other transporters may be negatively
impacted. Revenues generated by our contracts depend on volumes and rates, both
of which can be affected by the prices of natural gas. Increased natural gas
prices could result in loss of load from our customers, such as power companies
not dispatching gas fired power plants, industrial plant shutdown or load loss
to competitive fuels and local distribution companies' loss of customer base due
to conversion from natural gas. The success of our operations is subject to
continued development of additional oil and natural gas reserves in the vicinity
of our facilities and our ability to access additional reserves, primarily in
the Gulf of Mexico, to offset the natural decline from existing wells connected
to our systems. A decline in energy prices could precipitate a decrease in these
development activities and could cause a decrease in the volume of

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reserves available for transmission or storage on our system. Fluctuations in
energy prices are caused by a number of factors, including:

- regional, domestic and international supply and demand;

- availability and adequacy of transportation facilities;

- energy legislation;

- federal and state taxes, if any, on the transportation and storage of
natural gas;

- abundance of supplies of alternative energy sources; and

- political unrest among oil-producing countries.

THE AGENCIES THAT REGULATE US AND OUR CUSTOMERS AFFECT OUR PROFITABILITY.

Our pipeline business is regulated by the FERC, the U.S. Department of
Transportation and various state and local regulatory agencies. Regulatory
actions taken by those agencies have the potential to adversely affect our
profitability. In particular, the FERC regulates the rates we are permitted to
charge our customers for our services. If our tariff rates were reduced in a
future rate proceeding, if our volume of business under our currently permitted
rates was decreased significantly or if we were required to substantially
discount the rates for our services because of competition, our profitability
and liquidity could be reduced.

Further, state agencies that regulate our local distribution company
customers could impose requirements that could impact demand for our services.

COSTS OF ENVIRONMENTAL LIABILITIES, REGULATIONS AND LITIGATION COULD EXCEED OUR
ESTIMATES.

Our operations are subject to various environmental laws and regulations.
These laws and regulations obligate us to install and maintain pollution
controls and to clean up various sites at which regulated materials may have
been disposed of or released. We are also party to legal proceedings involving
environmental matters pending in various courts and agencies.

It is not possible for us to estimate reliably the amount and timing of all
future expenditures related to environmental matters because of:

- the uncertainties in estimating clean up costs;

- the discovery of new sites or information;

- the uncertainty in quantifying liability under environmental laws that
impose joint and several liability on all potentially responsible
parties;

- the nature of environmental laws and regulations; and

- the possible introduction of future environmental laws and regulations.

Although we believe we have established appropriate reserves for
liabilities, including clean up costs, we could be required to set aside
additional reserves in the future due to these uncertainties. For additional
information, see Part II, Item 8, Financial Statements and Supplementary Data,
Note 8.

OUR OPERATIONS ARE SUBJECT TO OPERATIONAL HAZARDS AND UNINSURED RISKS.

Our operations are subject to the inherent risks normally associated with
those operations, including pipeline ruptures, explosions, pollution, release of
toxic substances, fires and adverse weather conditions, and other hazards, each
of which could result in damage to or destruction of our facilities or damages
to persons and property. In addition, our operations face possible risks
associated with acts of aggression on our assets. If any of these events were to
occur, we could suffer substantial losses.

While we maintain insurance against many of these risks, our financial
condition and operations could be adversely affected if a significant event
occurs that is not fully covered by insurance.
11

TERRORIST ATTACKS AIMED AT OUR FACILITIES COULD ADVERSELY AFFECT OUR BUSINESS.

On September 11, 2001, the United States was the target of terrorist
attacks of unprecedented scale. Since the September 11th attacks, the United
States government has issued warnings that energy assets, including our nation's
pipeline infrastructure, may be a future target of terrorist organizations.
These developments have subjected our operations to increased risks. Any future
terrorist attack on our facilities, those of our customers and, in some cases,
those of other pipelines, could have a material adverse effect on our business.

RISKS RELATED TO OUR AFFILIATION WITH EL PASO

El Paso files reports, proxy statements and other information with the SEC
under the Securities Exchange Act of 1934, as amended. Each prospective investor
should consider this information and the matters disclosed therein in addition
to the matters described in this report. Such information is not incorporated by
reference herein.

OUR RELATIONSHIP WITH EL PASO AND ITS FINANCIAL CONDITION SUBJECTS US TO
POTENTIAL RISKS THAT ARE BEYOND OUR CONTROL.

Due to our relationship with El Paso, adverse developments or announcements
concerning El Paso could adversely affect our financial condition, even if we
have not suffered any similar development. The outstanding senior unsecured
indebtedness of El Paso has been downgraded to below investment grade, currently
rated Caa1 by Moody's and B by Standard & Poor's (with a negative outlook at
both agencies), which in turn resulted in a similar downgrading of our
outstanding senior unsecured indebtedness to B1 by Moody's and B+ by Standard &
Poor's (with a negative outlook at both agencies). These downgrades will
increase our cost of capital and collateral requirements, and could impede our
access to capital markets. As a result of these recent downgrades, El Paso has
realized substantial demands on its liquidity, which demands have included:

- application of cash required to be withheld from El Paso's cash
management program in order to redeem preferred membership interests at
one of El Paso's minority interest financing structures; and

- cash collateral or margin requirements associated with contractual
commitments of El Paso subsidiaries.

These downgrades may subject El Paso to additional liquidity demands in the
future. These downgrades are a result, at least in part, of the outlook
generally for the consolidated businesses of El Paso and its needs for
liquidity.

In order to meet its short term liquidity needs, El Paso has embarked on
its 2003 Operational and Financial Plan that contemplates drawing all or part of
its availability under its existing bank facilities and consummating significant
asset sales. In addition, El Paso may take additional steps, such as entering
into other financing activities, renegotiating its credit facilities and further
reducing capital expenditures, which should provide additional liquidity. There
can be no assurance that these actions will be consummated on favorable terms,
if at all, or even if consummated, that such actions will be successful in
satisfying El Paso's liquidity needs. In the event that El Paso's liquidity
needs are not satisfied, El Paso could be forced to seek protection from its
creditors in bankruptcy. Such a development could materially adversely affect
our financial condition.

Pursuant to El Paso's cash management program, surplus cash is made
available to El Paso in exchange for an affiliated receivable. In addition, we
conduct commercial transactions with some of our affiliates. As of December 31,
2002, we have net receivables of approximately $621 million from El Paso and its
affiliates. El Paso provides cash management and other corporate services for
us. If El Paso is unable to meet its liquidity needs, there can be no assurance
that we will be able to access cash under the cash management program, or that
our affiliates would pay their obligations to us. However, we might still be
required to satisfy affiliated company payables. Our inability to recover any
intercompany receivables owed to us could adversely

12

affect our ability to repay our outstanding indebtedness. For a further
discussion of our related party transactions, see Part II, Item 8, Financial
Statements and Supplementary Data, Note 11.

WE ARE JOINTLY AND SEVERALLY LIABLE FOR ALL OUTSTANDING AMOUNTS UNDER EL PASO'S
CREDIT FACILITIES.

We are a designated borrower under El Paso's $3 billion, 364-day revolving
credit and competitive advance facility and El Paso's $1 billion, 3-year
revolving credit and competitive advance facility. As such, we are jointly and
severally liable for any amounts outstanding under these facilities. As of March
1, 2003, $1.5 billion was outstanding under the $3 billion facility and $956
million (including $456 million in letters of credit) was outstanding under the
$1 billion facility. If, for any reason, El Paso does not repay any of the
outstanding amounts under these facilities, and we are required to repay any
such amounts, our financial condition and liquidity could be materially
adversely affected.

WE COULD BE SUBSTANTIVELY CONSOLIDATED WITH EL PASO IF EL PASO WERE FORCED TO
SEEK PROTECTION FROM ITS CREDITORS IN BANKRUPTCY.

If El Paso were the subject of voluntary or involuntary bankruptcy
proceedings, El Paso and its other subsidiaries and their creditors could
attempt to make claims against us, including claims to substantively consolidate
our assets and liabilities with those of El Paso and its other subsidiaries. The
equitable doctrine of substantive consolidation permits a bankruptcy court to
disregard the separateness of related entities and to consolidate and pool the
entities' assets and liabilities and treat them as though held and incurred by
one entity where the interrelationship between the entities warrants such
consolidation. We believe that any effort to substantively consolidate us with
El Paso and/or its other subsidiaries would be without merit. However, we cannot
assure you that El Paso and/or its other subsidiaries or their respective
creditors would not attempt to advance such claims in a bankruptcy proceeding
or, if advanced, how a bankruptcy court would resolve the issue. If a bankruptcy
court were to substantively consolidate us with El Paso and/or its other
subsidiaries, there could be a material adverse effect on our financial
condition and liquidity.

ONGOING LITIGATION AND INVESTIGATIONS REGARDING EL PASO COULD SIGNIFICANTLY
ADVERSELY AFFECT OUR BUSINESS.

On March 20, 2003, El Paso entered into an agreement in principle (the
Western Energy Settlement) with various public and private claimants, including
the states of California, Washington, Oregon, and Nevada, to resolve the
principal litigation, claims, and regulatory proceedings against El Paso and its
subsidiaries relating to the sale or delivery of natural gas and electricity
from September 1996 to the date of the Western Energy Settlement. A more
detailed description of the Western Energy Settlement can be found in El Paso's
reports filed with the SEC. If El Paso is unable to negotiate definitive
settlement agreements, or if the settlement is not approved by the courts or the
FERC, the proceedings and litigation will continue.

Since July 2002, twelve purported shareholder class action suits alleging
violations of federal securities laws have been filed against El Paso and
several of its officers. Eleven of these suits are now consolidated in federal
court in Houston before a single judge. The suits generally challenge the
accuracy or completeness of press releases and other public statements made
during 2001 and 2002. The twelfth shareholder class action lawsuit was filed in
federal court in New York City in October 2002 challenging the accuracy or
completeness of El Paso's February 27, 2002 prospectus for an equity offering
that was completed on June 21, 2002. It has since been dismissed, in light of
similar claims being asserted in the consolidated suits in Houston. Four
shareholder derivative actions have also been filed. One shareholder derivative
lawsuit was filed in federal court in Houston in August 2002. This derivative
action generally alleges the same claims as those made in the shareholder class
action, has been consolidated with the shareholder class actions pending in
Houston and has been stayed. A second shareholder derivative lawsuit was filed
in Delaware State Court in October 2002 and generally alleges the same claims as
those made in the consolidated shareholder class action lawsuit. A third
shareholder derivative suit was filed in state court in Houston in March 2002,
and a fourth shareholder derivative suit was filed in state court in Houston in
November 2002. The third and fourth shareholder derivative suits both generally
allege that manipulation of California gas supply and gas prices exposed El Paso
to claims of antitrust conspiracy, FERC penalties and erosion of share value. At
this time, El Paso's legal exposure related to these lawsuits and claims is not
determinable.
13

Another action was filed against El Paso in December 2002, on behalf of
participants in El Paso's 401(k) plan.

If El Paso does not prevail in these cases (or any of the other litigation,
administrative or regulatory matters disclosed in El Paso's 2002 Form 10-K to
which El Paso is, or may be, a party), and if the remedy adopted in these cases
substantially impairs El Paso's financial position, the long-term adverse impact
on El Paso's credit rating, liquidity and its ability to raise capital to meet
its ongoing and future investing and financing needs could be substantial. Such
a negative impact on El Paso could have a material adverse effect on us as well.

THE PROXY CONTEST INITIATED BY SELIM ZILKHA TO REPLACE EL PASO'S BOARD OF
DIRECTORS COULD HAVE A MATERIAL ADVERSE EFFECT ON US.

On February 18, 2003, Selim Zilkha, a stockholder of El Paso, announced his
intention to initiate a proxy solicitation to replace El Paso's entire board of
directors with his own nominees and on March 11, 2003, Mr. Zilkha filed his
preliminary proxy statement to that effect with the SEC. This proxy contest may
be highly disruptive and may negatively impact El Paso's ability to achieve the
stated objectives of its 2003 Operational and Financial Plan. In addition, El
Paso may have difficulty attracting and retaining key personnel until such proxy
contest is resolved. Therefore, this proxy contest, whether or not successful,
could have a material adverse effect on El Paso's liquidity and financial
condition, which, in turn, could adversely affect our liquidity and financial
condition.

WE ARE A WHOLLY OWNED SUBSIDIARY OF EL PASO TENNESSEE PIPELINE CO., A DIRECT
SUBSIDIARY OF EL PASO.

El Paso has substantial control over:

- our payment of dividends;

- decisions on our financings and our capital raising activities;

- mergers or other business combinations;

- our acquisitions or dispositions of assets; and

- our participation in El Paso's cash management program.

El Paso may exercise such control in its interests and not necessarily in
the interests of us or the holders of our long-term debt.

RISKS RELATED TO OUR LONG-TERM DEBT

OUR SUBSTANTIAL LONG-TERM DEBT COULD IMPAIR OUR FINANCIAL CONDITION AND OUR
ABILITY TO FULFILL OUR DEBT OBLIGATIONS.

We have substantial long-term debt. As of December 31, 2002, we had total
long-term debt of approximately $1,595 million, all of which was senior
unsecured long-term indebtedness.

Our substantial long-term debt could have important consequences. For
example, it could:

- make it more difficult for us to satisfy our obligations with respect to
our long-term debt, which could in turn result in an event of default on
any or all of such long-term debt;

- impair our ability to obtain additional financing in the future for
working capital, capital expenditures, acquisitions, general corporate
purposes or other purposes;

- diminish our ability to withstand a downturn in our business or the
economy generally;

- require us to dedicate a substantial portion of our cash flow from
operations to debt service payments, thereby reducing the availability of
cash for working capital, capital expenditures, acquisitions, general
corporate purposes or other purposes;
14

- limit our flexibility in planning for, or reacting to, changes in our
business and the industry in which we operate; and

- place us at a competitive disadvantage compared to our competitors that
have proportionately less debt.

If we are unable to meet our debt service obligations, we could be forced
to restructure or refinance our long-term debt, seek additional equity capital
or sell assets. We may be unable to obtain financing or sell assets on
satisfactory terms, or at all.

Covenants applicable to our long-term debt will allow us to incur
significant amounts of additional indebtedness. Our incurrence of significant
additional indebtedness would exacerbate the negative consequences mentioned
above, and could adversely affect our ability to repay our long-term debt.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Our primary market risk is exposure to changing interest rates. The table
below shows the carrying value and related weighted average interest rates of
our interest bearing securities, by expected maturity dates, and the fair value
of these securities. As of December 31, 2002, the carrying amounts of short-term
borrowings are representative of fair values because of the short-term maturity
of these instruments. The fair values of our long-term debt securities have been
estimated based on quoted market prices for the same or similar issues.

15

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS)

See accompanying notes.

16

TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)

See accompanying notes.
17

TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)

See accompanying notes.

18

TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
(IN MILLIONS, EXCEPT SHARE AMOUNTS)

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our consolidated financial statements include the accounts of all
majority-owned, controlled subsidiaries after the elimination of all significant
intercompany accounts and transactions. Our financial statements for prior
periods include reclassifications that were made to conform to the current year
presentation. Those reclassifications had no impact on reported net income or
stockholder's equity.

Principles of Consolidation

We consolidate entities when we have the ability to control the operating
and financial decisions and policies of that entity. Where we can exert
significant influence over, but do not control, those policies and decisions, we
apply the equity method of accounting. We use the cost method of accounting
where we are unable to exert significant influence over the entity. The
determination of our ability to control or exert significant influence over an
entity involves the use of judgment of the extent of our control or influence
and that of the other equity owners or participants of the entity.

Use of Estimates

The preparation of financial statements in conformity with U.S. generally
accepted accounting principles requires the use of estimates and assumptions
that affect the amounts we report as assets, liabilities, revenues and expenses
and our disclosures in these financial statements. Actual results can, and often
do, differ from those estimates.

Accounting for Regulated Operations

Our natural gas systems and storage operations are subject to the
jurisdiction of the 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.
Accounting requirements for regulated businesses can differ from the accounting
requirements for non-regulated businesses. Transactions that have been recorded
differently as a result of regulatory accounting requirements include the
capitalization of an equity return component on regulated capital projects,
employee related benefits and other costs and taxes included in, or expected to
be included in, future rates.

Our application of SFAS No. 71 is based on the current regulatory
environment, our current tariff and our ability to collect the rates set under
our tariff. At this time, we currently discount a number of our expiring and
remarketed contracts as a result of competition in the markets we serve.
Although discounting of our maximum tariff rates does occur, we believe the
standards required by SFAS No. 71 for its application are met and the continued
use of regulatory accounting under SFAS No. 71, best reflects the results of
operations in the economic environment in which we currently operate. Regulatory
accounting requires us to record assets and liabilities that result from the
rate-making process that would not be recorded under generally accepted
accounting principles for non-regulated entities. We will continue to evaluate
the application of regulatory accounting principles based on on-going changes in
the regulatory and economic environment. Issues that may influence this
assessment are:

- inability to recover cost increases due to rate caps and rate case
moratoriums;

- inability to recover capitalized costs, including an adequate return on
those costs through the rate-making process;

- excess capacity;

20

- increased competition and discounting in the markets we serve; and

- impacts of ongoing initiatives in, and deregulation of, the natural gas
industry.

Cash and Cash Equivalents

We consider short-term investments with an original maturity of less than
three months to be cash equivalents.

Allowance for Doubtful Accounts

We establish provisions for losses on accounts receivable and for natural
gas imbalances due from shippers and operators if we determine that we will not
collect all or part of the outstanding balance. We regularly review
collectibility and establish or adjust our allowance as necessary using the
specific identification method.

Materials and Supplies

We value materials and supplies at the lower of cost or market value with
cost determined using the average cost method.

Natural Gas Imbalances

Natural gas imbalances occur when the actual amount of natural gas
delivered from or received by a pipeline system or storage facility differs from
the amount of natural gas scheduled to be delivered or received. We value these
imbalances due to or from shippers at specific index prices set forth in our
tariff based on the month when the imbalances occur. Imbalances are settled in
cash or in-kind, subject to the terms of our settlement.

Imbalances due from others are reported in our balance sheet as either
accounts receivable from customers or accounts receivable from affiliates.
Imbalances owed to others are reported on the balance sheet as either trade
accounts payable or accounts payable to affiliates. In addition, we classify all
imbalances as current.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its original cost of
construction or, upon acquisition, at either the fair value of the assets
acquired or the cost to the entity that first placed the asset in service. We
capitalize direct costs, such as labor and materials, and indirect costs, such
as overhead, interest and an equity return component on regulated businesses as
allowed by the FERC. We capitalize the major units of property replacements or
improvements and expense minor items.

We use the composite (group) method to depreciate property, plant and
equipment. Under this method, assets with similar lives and other
characteristics are grouped and depreciated as one asset. We apply the
FERC-accepted depreciation rate to the total cost of the group until its net
book value equals its salvage value. Currently, our depreciation rates vary from
one to 24 percent. Using these rates, the remaining depreciable lives of these
assets range from two to 32 years. We re-evaluate depreciation rates each time
we redevelop our transportation rates when we file with the FERC for an increase
or decrease in rates.

When we retire property, plant and equipment, we charge accumulated
depreciation and amortization for the original cost, plus the cost to remove,
sell or dispose, less its salvage value. We do not recognize a gain or loss
unless we sell an entire operating unit. We include gains or losses on
dispositions of operating units in income.

Additional acquisition cost assigned to utility plant represents the excess
of allocated purchase costs over historical costs of these facilities. These
costs are amortized on a straight-line basis using FERC approved rates, and we
do not recover those excess costs in our rates.

21

At December 31, 2002 and 2001, we had approximately $115 million and $232
million of construction work in progress included in our property, plant and
equipment.

As a FERC-regulated company, we capitalize a carrying cost (an allowance
for funds used during construction) on funds invested in our construction of
long-lived assets that are financed by debt. The amount capitalized is
calculated based on our average cost of debt. Debt amounts capitalized during
the years ended December 31, 2002, 2001 and 2000, were $3 million, $11 million
and $6 million. These amounts are included as a reduction of interest expense in
our income statement. Capitalized carrying costs are reflected as an increase in
the cost of the asset on our balance sheet.

Goodwill and Other Intangible Assets

We apply the provisions of SFAS No. 141, Business Combinations, and SFAS
No. 142, Goodwill and Other Intangible Assets. SFAS No. 141 requires that upon
adoption of SFAS No. 142, 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, that we amortized using the straight-line method. As a
result of our adoption of these standards on January 1, 2002, we stopped this
amortization and recognized a pretax and after-tax gain of $10 million related
to the write-off of negative goodwill as a cumulative effect of an accounting
change. Had we continued to amortize negative goodwill, our reported income for
the year ended December 31, 2002, would not have been materially different. In
addition, had we applied the amortization provisions of these standards on
January 1, 2001 and 2000, our reported income for the year ended December 31,
2001 and 2000, would not have been materially different.

Asset Impairments

We apply the provisions of SFAS No. 144, Accounting for the Impairment or
Disposal of Long-Lived Assets, to account for asset impairments. Under this
standard, we evaluate an asset for impairment when events or circumstances
indicate that a long-lived asset's carrying value may not be recovered. These
events include market declines, changes in the manner in which we intend to use
an asset or decisions to sell an asset and adverse changes in the legal or
business environment such as adverse actions by regulators. At the time we
decide to exit an activity or sell a long-lived asset or group of assets, we
adjust the carrying value of those assets downward, if necessary, to the
estimated sales price, less costs to sell. We classify these assets as either
held for sale or as discontinued operations, depending on whether they have
independently determinable cash flows.

Revenue Recognition

Our revenues consist primarily of transportation and storage services. For
our transportation and storage services, we recognize reservation revenues on
firm contracted capacity ratably over the contract period. For interruptible or
volumetric based services, we record revenues when we complete the delivery of
natural gas to the agreed upon delivery point and when gas is injected or
withdrawn from the storage facility. Revenues for all services are generally
based on the thermal quantity of gas delivered or subscribed at a price
specified in the contract. We are subject to FERC regulations and, as a result,
revenues we collect may possibly be refunded in a final order of a future rate
proceeding or as a result of a rate settlement. We establish reserves for these
potential refunds.

Environmental Costs and Other Contingencies

We record liabilities when our environmental assessments indicate that
remediation efforts are probable, and the costs can be reasonably estimated. We
recognize a current period expense for the liability when the clean-up efforts
do not benefit future periods. We capitalize costs that benefit more than one
accounting period, except in instances where separate agreements or legal and
regulatory guidelines dictate otherwise. Estimates of our liabilities are based
on currently available facts, existing technology and presently enacted laws and
regulations taking into account the likely effects of inflation and other
societal and economic factors,

22

and include estimates of associated legal costs. These amounts also consider
prior experience in remediating contaminated sites, other companies' clean-up
experience and data released by the Environmental Protection Agency (EPA) or
other organizations. These estimates are subject to revision in future periods
based on actual costs or new circumstances and are included in our balance sheet
in other current and long-term liabilities at their undiscounted amounts. We
evaluate recoveries from insurance coverage, rate recovery, government sponsored
and other programs separately from our liability and, when recovery is assured,
we record and report an asset separately from the associated liability in our
financial statements.

We recognize liabilities for other contingencies when we have an exposure
that, when fully analyzed, indicates it is both probable that an asset has been
impaired or that a liability has been incurred and the amount of impairment or
loss can be reasonably estimated. Funds spent to remedy these contingencies are
charged against a reserve, if one exists, or expensed. When a range of probable
loss can be estimated, we accrue the most likely amount, or at least the minimum
of the range of probable loss.

Income Taxes

We report current income taxes based on our taxable income and we provide
for deferred income taxes to reflect estimated future tax payments and receipts.
Deferred taxes represent the tax impacts of differences between the financial
statement and tax bases of assets and liabilities and carryovers at each year
end. We account for tax credits under the flow-through method, which reduces the
provision for income taxes in the year the tax credits first become available.
We reduce deferred tax assets by a valuation allowance when, based on our
estimates, it is more likely than not that a portion of those assets will not be
realized in a future period. The estimates utilized in the recognition of
deferred tax assets are subject to revision, either up or down, in future
periods based on new facts or circumstances.

El Paso maintains a tax accrual policy to record both regular and
alternative minimum taxes for companies included in its consolidated federal
income tax return. The policy provides, among other things, that (i) each
company in a taxable income position will accrue a current expense equivalent to
its federal income tax, and (ii) each company in a tax loss position will accrue
a benefit to the extent its deductions, including general business credits, can
be utilized in the consolidated return. El Paso pays all federal income taxes
directly to the IRS and, under a separate tax billing agreement, El Paso may
bill or refund its subsidiaries for their portion of these income tax payments.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2002, there were a number of accounting standards and
interpretations that had been issued, but not yet adopted by us. Below is a
discussion of the more significant standards that could impact us.

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

Accounting for Guarantees. In November 2002, the FASB issued FIN No. 45,
Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others. This interpretation requires
that companies record a liability for all guarantees issued after January 31,
2003, including financial, performance, and fair value guarantees. This
liability is recorded at its fair value upon issuance, and does not affect any
existing guarantees issued before December 31, 2002. While we do not believe
there will be any initial impact of adopting this standard, it will impact any
guarantees we issue in the future.

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2. INCOME TAXES

The following table reflects the components of income tax expense included
in income before cumulative effect of accounting change for each of the three
years ended December 31:

Our income tax expense included in income before cumulative effect of
accounting change differs from the amount computed by applying the statutory
federal income tax rate of 35 percent for the following reasons for each of the
three years ended December 31:

The following are the components of our net deferred tax liability as of
December 31:

Under El Paso's tax accrual policy, we are allocated the tax benefit
associated with our employees' exercise of non-qualified stock options and the
vesting of restricted stock as well as restricted stock dividends.

24

This allocation reduced taxes payable by $2 million in 2002, $5 million in 2001
and $7 million in 2000. These benefits are included in additional paid-in
capital in our balance sheet.

As of December 31, 2002, we had $1 million of alternative minimum tax
credit carryovers and $520 million of federal net operating loss carryovers. The
alternative minimum tax credits carryover indefinitely. The carryover period for
the net operating loss ends as follows: approximately $119 million in 2011; $130
million in 2018; $75 million in 2019; $17 million in 2020; and $179 million in
2021. Usage of these carryovers is subject to the limitations provided under
Sections 382 and 383 of the Internal Revenue Code as well as the separate return
limitation year rules of IRS regulations.

As of December 31, 2002, we had $1,129 million of state net operating loss
carryovers. These carryovers will expire in varying amounts over the period from
2003 to 2021.

3. FINANCIAL INSTRUMENTS

Fair Value of Financial Instruments

As of December 31, 2002 and 2001, the carrying amounts of cash and cash
equivalents, short-term borrowings, and trade receivables and payables are
representative of fair value because of the short-term maturity of these
instruments.

The carrying amounts and estimated fair values of our financial instruments
are as follows at December 31:

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

(1) We estimated the fair value of debt with fixed interest rates based on
quoted market prices for the same or similar issues.

4. ACCUMULATED OTHER COMPREHENSIVE LOSS

Portland Natural Gas Transmission, our unconsolidated affiliate, uses
derivatives to mitigate, or hedge, cash flow risk associated with its variable
interest rates on long-term debt. Our unconsolidated affiliates account for
these derivatives under the provisions of SFAS No. 133, Accounting for Derivates
and Hedging Activities. Our unconsolidated affiliates record changes in the fair
value of these derivatives in other comprehensive income. We are required to
record our proportionate share of the impact that these derivative instruments
have on the financial statements of our investee as adjustments to our other
comprehensive income and our investment in unconsolidated affiliates.

Our accumulated other comprehensive income includes a loss of $3 million,
net of $1 million in income taxes, representing our proportionate share of
amounts recorded in other comprehensive loss by our unconsolidated affiliate who
uses derivatives as cash flow hedges. Included in this loss is a $1 million loss
that we estimate will be reclassified from accumulated other comprehensive
income over the next 12 months. The maximum term of these cash flow hedges is 10
years. For the years ended December 31, 2002 and 2001, our unconsolidated
affiliate did not record any ineffectiveness in earnings on its cash flow
hedges.

25

5. REGULATORY ASSETS AND LIABILITIES

Our current and non-current regulatory assets and liabilities are included
on a gross basis in our balance sheets, and these balances are included in
respective other current and non-current assets and liabilities. Below are the
details of our regulatory assets and liabilities at December 31:

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

(1) These amounts are not included in our rate base on which we earn a current
return.

6. PROPERTY, PLANT AND EQUIPMENT

As of December 31, 2002, additional acquisition costs assigned to utility
plant was approximately $2 billion and accumulated depreciation was
approximately $143 million. These excess costs are being amortized over the life
of the related pipeline assets, and our amortization expense during 2002 was
approximately $34 million and during 2001 it was $22 million. The adoption of
SFAS No. 142 did not impact these amounts since they were included as part of
our property, plant and equipment, rather than as goodwill.

7. DEBT AND OTHER CREDIT FACILITIES

At December 31, 2001, our short-term borrowings consisted of commercial
paper of $424 million that carried a weighted average interest rate of 3.2%. At
December 31, 2002 we did not have any commercial paper outstanding. Our
long-term debt outstanding consisted of the following at December 31:

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

(1) These debentures are callable in 2007.

26

None of our long-term debt matures within the next five years.

In May 2002, El Paso, our indirect parent, renewed its $3 billion, 364-day
revolving credit and competitive advance facility. We are a designated borrower
under this facility and, as such, are jointly and severally liable for any
amounts outstanding under this facility. This facility matures in May 2003, and
provides that amounts outstanding on that date, are not due until May 2004. In
June 2002, El Paso amended its existing $1 billion, 3-year revolving credit and
competitive advance facility to permit it to issue up to $500 million in letters
of credit and to adjust pricing terms. This facility matures in August 2003, and
we are also a designated borrower under this facility and, as such, are jointly
and severally liable for any amounts outstanding under this facility. The
interest rate under both of these facilities varies based on El Paso's senior
unsecured debt rating, and as of December 31, 2002, an initial draw would have
had a rate of LIBOR plus 1.0%, and a 0.25% utilization fee for drawn amounts
above 25% of the committed amounts. As of December 31, 2002, $1.5 billion was
outstanding under the $3 billion facility, and $456 million in letters of credit
were issued under the $1 billion facility. In February 2003, an additional draw
of $500 million was made under the $1 billion facility.

In June 2002, we issued $240 million aggregate principal amount 8.375%
notes due 2032. Proceeds were approximately $238 million, net of issuance costs.

Other Financing Arrangements

During 1999, El Paso formed Sabine Investors, L.L.C., a wholly owned
limited liability company, and other separate legal entities (collectively,
these are referred to as the Trinity River financing arrangement), for the
purpose of generating funds for El Paso to invest in capital projects and other
assets. The proceeds from the financing transaction were collateralized by
various assets of El Paso, including our 50 percent ownership interest in Bear
Creek.

Southern Gas Storage Company, our affiliate, owns the remaining 50 percent
interest in Bear Creek. Bear Creek has not made any cash dividend distributions
since 1999. As a result of the downgrade of El Paso's credit rating below
investment grade, Bear Creek's cash can be used only for purposes of redeeming
the preferred membership interests that Sabine issued at the time it was formed,
and for Bear Creek's operating needs. Accordingly, until the preferred
membership interests were redeemed in full, we were not able to receive any cash
distributions from our ownership interest in Bear Creek. Bear Creek's estimated
operating cash flow for the year ended December 31, 2002, was $26 million. In
March 2003, El Paso entered into a $1.2 billion two-year term loan and the
proceeds were used to retire the outstanding balance under the Trinity River
financing agreement.

8. 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

27

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 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, 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. Plaintiff's motion for class certification has been argued and we are
awaiting a ruling. 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 December 31, 2002, we had approximately $4 million accrued for all
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 December
31, 2002, we had accrued approximately $84 million, including approximately $79
million for expected remediation costs and associated onsite, offsite and
groundwater technical studies and approximately $5 million for related
environmental legal costs, which we anticipate incurring through 2027. Below is
a reconciliation of our accrued liability as of December 31, 2001 to our accrued
liability as of December 31, 2002 (in millions):

In addition, we expect to make capital expenditures for environmental
matters of approximately $56 million in the aggregate for the years 2003 through
2007. These expenditures primarily relate to compliance with clean air
regulations. For 2003, we estimate that our total remediation expenditures will
be approximately $7 million, of which $2 million we estimate will be for capital
related expenditures. In addition, approximately $3 million of this amount will
be expended under government directed clean-up plans. The remaining $2 million
will be self-directed or in connection with facility closure.

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, 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, to ensure that our efforts meet regulatory requirements. 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.

28

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 December 31, 2002, we had pre-collected our PCB
costs by approximately $115 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 December 31, 2002, we have
recorded a regulatory liability (included in other non-current liabilities on
our balance sheet) for future refund obligations of approximately $55 million.

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 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 December
31, 2002, we have estimated our share of the remediation costs 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
determining our estimated 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 December 31,
2002, $64 million of the interruptible transportation surcharge had been
collected. There is no time limit for collection of the remaining 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.

29

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. In turn, we submitted our
compliance filing with FERC to comply with the October 31 order. We also filed
for rehearing of the October 31 order, which remains pending. 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.
In December 2001, we filed comments with the FERC addressing our concerns with
the proposed rules. A public hearing was held on May 21, 2002, providing an
opportunity to comment further on the NOPR. Following the conference, additional
comments were filed by El Paso's pipelines and others. 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 NOI. In July 2002, the FERC issued a Notice of Inquiry
(NOI) that seeks 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. On September 25, 2002, El Paso's
pipelines and others filed comments. Reply comments were filed on October 25,
2002. At this time, we cannot predict the outcome of this NOI.

Cash Management NOPR. On August 1, 2002, the FERC issued a NOPR requiring
that all cash management or money pool arrangements between a FERC regulated
subsidiary (like us) and a non-FERC regulated parent must be in writing, and set
forth the duties and responsibilities of cash management participants and
administrators; the methods of calculating interest and for allocating interest
income and expenses; and the restrictions on deposits or borrowings by money
pool members. The NOPR also requires specified documentation for all deposits
into, borrowings from, interest income from, and interest expenses related to,
these arrangements. Finally, the NOPR proposed that as a condition of
participating in a cash management or money pool arrangement, the FERC regulated
entity maintain a minimum proprietary capital balance of 30 percent, and the
FERC regulated entity and its parent maintain investment grade credit ratings.
On August 28, 2002, comments were filed. The FERC held a public conference on
September 25, 2002, to discuss the issues raised in the comments.
Representatives of companies from the gas and electric industries participated
on a panel and uniformly agreed that the proposed regulations should be revised
substantially and that the proposed capital balance and investment grade credit
rating requirements would be excessive. At this time, we cannot predict the
outcome of this NOPR.

Also on August 1, 2002, the FERC's Chief Accountant issued an Accounting
Release, which was effective immediately. The Accounting Release provides
guidance on how companies should account for money pool arrangements and the
types of documentation that should be maintained for these arrangements.
However, it did not address the proposed requirements that the FERC regulated
entity maintain a minimum proprietary capital balance of 30 percent and that the
entity and its parent have investment grade credit ratings. Requests for
rehearing were filed on August 30, 2002. The FERC has not yet acted on the
rehearing requests.

Emergency Reconstruction of Interstate Natural Gas Facilities NOPR. On
January 17, 2003, FERC issued a NOPR proposing to (1) expand the scope of
construction activities authorized under a pipeline's blanket certificate to
allow replacement of mainline facilities; (2) authorize a pipeline to commence

30

reconstruction of the affected system without a waiting period; and (3)
authorize automatic approval of construction that would be above the normal cost
ceiling. Comments on the NOPR were filed on February 27, 2003. At this time, we
cannot predict the outcome of this rulemaking.

Pipeline Safety Notice of Proposed Rulemaking. On January 28, 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. We intend to submit
comments on the NOPR, which are due 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 impair our debt rating and the credit rating 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.

Capital Commitments and Purchase Obligations

At December 31, 2002, we had capital and investment commitments of $26
million. Our other planned capital and investment projects are discretionary in
nature, with no substantial capital commitments made in advance of the actual
expenditures. We have entered into unconditional purchase obligations for
products and services, including financing commitments with one of our joint
ventures, totaling $159 million at December 31, 2002. Our annual obligations
under these agreements are $31 million for 2003, $31 million for 2004, $29
million for 2005, $21 million for 2006, $11 million for 2007 and $36 million in
total thereafter.

Operating Leases

We lease property, facilities and equipment under various operating leases.
Minimum future annual rental commitments at December 31, 2002, were as follows:

Rental expense for operating leases for each of the year ended December 31,
2002, 2001 and 2000 was $5 million, $6 million and less than $1 million.

31

9. RETIREMENT BENEFITS

Pension and Retirement Benefits

El Paso maintains a pension plan to provide benefits determined under a
cash balance formula covering substantially all of its U.S. employees, including
our employees. El Paso also maintains a defined contribution plan covering its
U.S. employees, including our employees. Prior to May 1, 2002, El Paso matched
75 percent of participant basic contributions up to 6 percent, with matching
contributions being made to the plan's stock fund, which participants could
diversify at any time. After May 1, 2002, the plan was amended to allow for
matching contributions to be invested in the same manner as that of participant
contributions. Effective March 1, 2003, El Paso suspended the matching
contribution. El Paso is responsible for benefits accrued under its plans and
allocates the related costs to its affiliates. See Note 11 for a summary of
transactions with affiliates.

Other Postretirement Benefits

Following El Paso's acquisition of us in 1996, we retained responsibility
for postretirement medical and life insurance benefits for former employees of
operations previously disposed of by our former parent, and for employees,
including our employees, added as a result of the merger who were eligible to
retire on December 31, 1996, and did so by July 1, 1997. Medical benefits for
this closed group of retirees may be subject to deductibles, co-payment
provisions, and other limitations and dollar caps on the amount of employer
costs. We have reserved the right to change these benefits. Employees who retire
after July 1, 1997, will continue to receive limited postretirement life
insurance benefits. Postretirement benefit plan costs are prefunded to the
extent these costs are recoverable through rates. Effective February 1, 1992, we
began recovering through our rates the other postretirement benefits (OPEB)
costs included in the June 1993 rate case settlement. To the extent actual OPEB
costs differ from the amounts funded, a regulatory asset or liability is
recorded.

The following table sets forth the change in benefit obligation, change in
plan assets, reconciliation of funded status, and components of net periodic
benefit cost for other postretirement benefits as of and for the twelve months
ended September 30:

32

Net periodic benefit cost for our plans consisted of interest costs of $2
million, for each of the years ended December 31, 2002, 2001 and 2000.
Postretirement benefit obligations are based upon actuarial estimates as
described below:

Actuarial estimates for our postretirement benefits plans assumed a
weighted average annual rate of increase in the per capita costs of covered
health care benefits of 11.0 percent in 2002, gradually decreasing to 5.5
percent by the year 2008. Assumed health care cost trends can have a significant
effect on the amounts reported for other postretirement benefit plans. However,
it does not affect our costs because our costs are limited by defined dollar
caps.

10. SUPPLEMENTAL CASH FLOW INFORMATION

The following table contains supplemental cash flow information for each of
the three years ended December 31:

11. INVESTMENTS IN AND TRANSACTIONS WITH RELATED PARTIES

We hold investments in various affiliates which are accounted for on the
equity method of accounting. Our principal equity method investment is a 50
percent ownership interest in Bear Creek, a joint venture with Southern Gas
Storage Company, our affiliate. Bear Creek owns and operates an underground
natural gas storage facility located in Louisiana. The facility has a capacity
of 50 Bcf of base gas and 58 Bcf of working storage. Bear Creek's working
storage capacity is committed equally to SNG, and our pipeline system under
long-term contracts. Our investment in Bear Creek as of December 31, 2002 and
2001, was $128 million and $116 million. We recognized equity earnings of $12
million in 2002, $14 million in 2001 and $13 million in 2000. During 1999, El
Paso formed Sabine Investors, L.L.C., a wholly owned limited liability company,
and other separate legal entities, for the purpose of generating funds for El
Paso to invest in capital projects and other assets. The proceeds from the
financing transaction were collateralized by specific assets of El Paso,
including our investment in Bear Creek. In March 2003, El Paso entered into a
$1.2 billion two-year term loan and the proceeds were used to retire the
outstanding amount of the financing transaction.

We also have a 30 percent ownership interest in Portland Natural Gas
Transmission System, a general partnership. Portland owns and operates a 294
mile interstate pipeline with a design capacity of 214 MMcf/d that extends from
the Canadian border near Pittsburg, New Hampshire to Dracut, Massachusetts. As
of December 31, 2002 and 2001, our investment in Portland was $51 million and
$39 million. We recognized equity earnings of $4 million in 2002 and equity
losses of less than $1 million in 2001 and $2 million in 2000.

Summarized financial information of our proportionate share of
unconsolidated affiliates are presented below. Differences in our carrying
amounts and our equity in the net assets of these investments as of December 31,
2002 and 2001, were $3 million and $(8) million. The primary difference in 2001
related to an

33

unamortized purchase price allocation on our Portland investment, which was
written off on January 1, 2002 upon our adoption of SFAS No. 141.

We participate in El Paso's cash management program which matches
short-term cash surpluses and needs of its participating affiliates, thus
minimizing total borrowing from outside sources. Our continued participation in
the program may be dependent on any final rule issued by the FERC in connection
with its cash management notice of proposed rulemaking discussed in Note 7. We
had advanced $599 million at December 31, 2002, at a market rate of interest
which was 1.5%. At December 31, 2001, we had advanced $153 million at a market
rate of interest which was 2.1%. These receivables are due upon demand; however,
as of December 31, 2002, we have classified this amount as non-current notes
receivable from affiliates because we do not anticipate settlement within the
next twelve months. In addition, we have a demand note receivable with El Paso
of $38 million at December 31, 2002, at an interest rate of 2.21%. At December
31, 2001, the demand note receivable was $28 million at an interest rate of
2.73%.

At December 31, 2002 and 2001, we had accounts receivable from related
parties of $72 million and $55 million. In addition, we had accounts payable to
related parties of $88 million and $69 million at December 31, 2002 and 2001.
These balances arose in the normal course of business. We also received $5
million in deposits related to our transportation contracts with El Paso
Merchant Energy L.P. (EPME) which is included in our balance sheet as other
current liabilities. These deposits were required as a result of the credit
rating downgrade of El Paso.

El Paso allocates a portion of its general and administrative expenses to
us. The allocation is based on the estimated level of effort devoted to our
operations and the relative size of our EBIT, gross property and payroll. For
the year ended December 31, 2002, 2001, and 2000 the annual charges were $97
million, $67 million and $90 million. During 2002 and 2001, we performed
operational, financial, accounting and administrative services for El Paso's
other pipeline systems. For the years ended December 2002 and 2001, the annual
charges were $39 million and $38 million. We recorded the amounts billed as a
reduction of our operating expenses. We believe the allocation methods are
reasonable.

During 2002, we completed several transactions to increase our equity in
proportion to our total capital (debt and equity). These transactions included
capital contributions from, and distributions in the form of dividends to, our
parent, El Paso Tennessee Pipeline Co. The capital contribution included $798
million of affiliate accounts payable to our parent and other El Paso
affiliates. We accounted for the contribution as an increase in additional
paid-in capital. In addition, we declared a non-cash dividend totaling $67
million,

34

representing a distribution of affiliate receivables, to our parent. The
dividend was recorded as a reduction of retained earnings.

During 2002, 2001 and 2000 we transported gas for an affiliate, EPME, and
recognized revenues of $74 million, $79 million and $70 million.

We store natural gas in an affiliated storage facility and utilized an
affiliated pipeline (ANR Pipeline Company) to transport some of our natural gas
during 2002 and 2001. These costs were $5 million and $2 million for these
periods and are recorded as operating expenses. These activities were entered
into in the normal course of our business and are based on the same terms as
non-affiliates.

The following table shows revenues and charges from our affiliates for each
of the three years ended December 31:

12. SUPPLEMENTAL SELECTED QUARTERLY FINANCIAL INFORMATION (UNAUDITED)

Financial information by quarter is summarized below:

35

REPORT OF INDEPENDENT ACCOUNTANTS

To the Board of Directors and Stockholder of
Tennessee Gas Pipeline Company:

In our opinion, the consolidated financial statements listed in the Index
appearing under Item 15(a)(1) present fairly, in all material respects, the
consolidated financial position of Tennessee Gas Pipeline Company and its
subsidiaries (the "Company") at December 31, 2002 and 2001, and the consolidated
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2002 in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the Index appearing under Item
15(a)(2) presents fairly, in all material respects, the information set forth
therein when read in conjunction with the related consolidated financial
statements. These financial statements and financial statement schedule are the
responsibility of the Company's management; our responsibility is to express an
opinion on these financial statements and financial statement schedule based on
our audits. We conducted our audits of these statements in accordance with
auditing standards generally accepted in the United States of America, which
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

As discussed in Note 1, the Company adopted Statement of Financial
Accounting Standards No. 141, Business Combinations, and Statement of Financial
Accounting Standards No. 142, Goodwill and Other Intangible Assets, on January
1, 2002.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
March 25, 2003

36

SCHEDULE II

TENNESSEE GAS PIPELINE COMPANY
VALUATION AND QUALIFYING ACCOUNTS

YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(IN MILLIONS)

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

(1) Upon favorable resolution of issues related to natural gas purchase
contracts, we reversed the regulatory reserve to revenue and the regulatory
asset account.

(2) Primarily accounts written off.

(3) Payments for remediation activities.

37

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

Item 10, "Directors and Executive Officers of the Registrant;" Item 11,
"Executive Compensation;" Item 12, "Security Ownership of Management;" and Item
13, "Certain Relationships and Related Transactions;" have been omitted from
this report pursuant to the reduced disclosure format permitted by General
Instruction I to Form 10-K.

ITEM 14. 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 (Internal Controls) within 90 days of the filing date of
this annual 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. TGP'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. 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. Further, 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, and there
can be no assurance that any design will succeed in achieving its stated goals
under all potential future conditions. Over time, controls may become inadequate
because of changes in conditions, or the degree of compliance with the policies
or procedures may deteriorate. Because of the inherent limitations in a
cost-effective control system, misstatements due to error or fraud may occur and
not be detected.

No Significant Changes in Internal Controls. We have sought to determine
whether there were any "significant deficiencies" or "material weaknesses" in
TGP's Internal Controls, or whether TGP had identified any acts of fraud
involving personnel who have a significant role in TGP'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 and our independent accountants and to
report on related matters in this section of the Annual Report. The principal
executive

38

officer and principal financial officer note that, from the date of the controls
evaluation to the date of this Annual Report, there have been no significant
changes in Internal Controls or in other factors that could significantly affect
Internal Controls, including any corrective actions with regard to significant
deficiencies and material weaknesses.

Effectiveness of Disclosure Controls. Based on the controls evaluation,
our principal executive officer and principal financial officer have concluded
that, subject to the limitations discussed above, the Disclosure Controls are
effective to ensure that material information relating to TGP and its
consolidated subsidiaries is made known to management, including the principal
executive officer and principal financial officer, particularly during the
period when our periodic reports are being prepared.

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 herein, or as Exhibits to this
Annual Report, as appropriate.

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(A) THE FOLLOWING DOCUMENTS ARE FILED AS A PART OF THIS REPORT:

1. Financial statements.

The following consolidated financial statements are included in Part II,
Item 8 of this report:

(B) REPORTS ON FORM 8-K:

None.

39

TENNESSEE GAS PIPELINE COMPANY

EXHIBIT LIST
DECEMBER 31, 2002

Exhibits not incorporated by reference to a prior filing are designated by
an asterisk; all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.

REPORTS ON FORM 8-K

None.

40

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
and our consolidated subsidiaries 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.

41

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, Tennessee Gas Pipeline Company has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly
authorized on the 27th day of March, 2003.

TENNESSEE GAS PIPELINE COMPANY

By: /s/ JOHN W. SOMERHALDER II
----------------------------------
John W. Somerhalder II
Chairman of the Board

Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed below by the following persons on behalf of
Tennessee Gas Pipeline Company and in the capacities and on the dates indicated:

42

CERTIFICATION

I, John W. Somerhalder II, certify that:

1. I have reviewed this annual report on Form 10-K of Tennessee Gas
Pipeline Company;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual
report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ JOHN W. SOMERHALDER II
--------------------------------------
John W. Somerhalder II
Chairman of the Board
(Principal Executive Officer)
Tennessee Gas Pipeline Company
Date: March 27, 2003

43

CERTIFICATION

I, Greg G. Gruber, certify that:

1. I have reviewed this annual report on Form 10-K of Tennessee Gas
Pipeline Company;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to make
the statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this annual
report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual
report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent functions):

a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

/s/ GREG G. GRUBER
--------------------------------------
Greg G. Gruber
Senior Vice President,
Chief Financial Officer and Treasurer
(Principal Financial Officer)
Tennessee Gas Pipeline Company
Date: March 27, 2003

44

EXHIBIT INDEX

Exhibits not incorporated by reference to a prior filing are designated by
an asterisk, all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.