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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)


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

For the fiscal year ended December 31, 2006


o		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 1-4874

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 if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes þ No o

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 þ No o

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. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filer þ

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

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 February 21, 2007: 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

TENNESSEE GAS PIPELINE COMPANY

TABLE OF CONTENTS


	Caption	Page

	PART I
Item 1.	Business		3
Item 1A.	Risk Factors		6
Item 1B.	Unresolved Staff Comments		10
Item 2.	Properties		10
Item 3.	Legal Proceedings		10
Item 4.	Submission of Matters to a Vote of Security Holders		*

	PART II

Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		10
Item 6.	Selected Financial Data		*
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		11
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		15
Item 8.	Financial Statements and Supplementary Data		16
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		37
Item 9A.	Controls and Procedures		37
Item 9B.	Other Information		37

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance		*
Item 11.	Executive Compensation		*
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		*
Item 13.	Certain Relationships and Related Transactions, and Director Independence		*
Item 14.	Principal Accountant Fees and Services		37

	PART IV

Item 15.	Exhibits and Financial Statement Schedules		38
	Signatures		39
Amendment No.1 to Amended Credit Agreement
Amendment No.1 to Receivables Purchase Agreement
Certification of PEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of PEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906


*		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	LNG	=	liquefied natural gas
BBtu	= billion British thermal units	MMcf	=	million cubic feet
Bcf	= billion cubic feet	NGL	=	natural gas liquid

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”, “ours”, or “TGP”, we are describing Tennessee Gas Pipeline Company and/or our subsidiaries.

PART I

ITEM 1. BUSINESS

Overview and Strategy

Our pipeline system and storage facility operate under tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms and other terms and conditions of service to our customers. The fees or rates established under our tariffs are a function of our costs of providing services to our customers, including a reasonable return on our invested capital.

Our strategy is to protect and enhance the value of our transmission and storage business by:

	•		Optimizing our contract portfolio;

	•		Managing market segmentation and differentiation;

	•		Focusing on efficiency initiatives;

	•		Expanding both ends of our pipeline system; and

	•		Seeking new business opportunities.

Below is a further discussion of our pipeline system and storage facility.

The TGP System. The TGP system consists of approximately 14,100 miles of pipeline with a design capacity of approximately 6,961 MMcf/d. During 2006, 2005 and 2004, average throughput was 4,534 BBtu/d, 4,443 BBtu/d and 4,469 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. Our system also has interconnects at the U.S.- Mexico border and the U.S.- Canada border.

As of December 31, 2006, we have the following pipeline expansion projects on our system that have been approved by the FERC:


				Anticipated
Project	Capacity		Description	Completion Date
	(MMcf/d)
Louisiana Deepwater Link		850	To construct a 300 foot extension of our 20-inch Grand Isle supply lateral, construct 2,100 feet of 24-inch West Delta supply lateral, abandon 3,100 feet of the 20-inch line connected to the Grand Isle platform, and install appurtenant facilities on Enterprise Products Partners’ Independence Hub platform located in Mississippi Canyon Block 920.	July 2007

Triple -T Extension		200	To construct 6.2 miles of 24-inch pipeline, to extend our existing 30-inch Triple-T Line beginning in Eugene Island Block 349, to interconnect with Enterprise Products Partners, L.P.’s Anaconda System on the El 371 platform, as well as associated piping and other appurtenant facilities.	September 2007

Essex Middlesex Project		80	To construct 7.8 miles of 24-inch pipeline connecting our Beverly-Salem line to the DOMAC line in Essex and Middlesex Counties, Massachusetts.	November 2007

Northeast ConneXion - New England		108	To construct a compression station and modify compression at six existing facilities on our interstate pipeline system in Pennsylvania, New York, and Massachusetts.	November 2007

Storage Facility. We have approximately 90 Bcf of underground working natural gas storage capacity along our system. Of this amount, 29 Bcf is contracted from Bear Creek Storage Company (Bear Creek), our affiliate. Bear Creek is a joint venture that we own equally with our affiliate, Southern Gas Storage Company, a subsidiary of Southern Natural Gas Company (SNG). 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 us under long-term contracts.

Markets and Competition

Our customers consist of natural gas distribution and industrial companies, electric generation companies, natural gas producers, other natural gas pipelines and natural gas marketing and trading companies. We provide transportation and storage services in both our natural gas supply and market areas. Our pipeline system connects with multiple pipelines that provide our customers with access to diverse sources of supply and various natural gas markets.

Imported LNG is one of the fastest growing supply sectors of the natural gas market. LNG terminals and other regasification facilities can serve as important sources of supply for pipelines, enhancing their delivery capabilities and operational flexibility and complementing traditional supply transported into market areas. However, these LNG delivery systems also may compete with us for transportation of gas into market areas we serve.

Electric power generation is the fastest growing demand sector of the natural gas market. The growth of the electric power industry potentially benefits the natural gas industry by creating more demand for natural gas turbine generated electric power. This effect is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity, increased natural gas prices and the use and availability of other fuel sources for power generation. In addition, in several regions of the country, new additions in electric generating capacity have exceeded load growth and electric transmission capabilities out of those regions. These developments may inhibit owners of new power generation facilities from signing firm contracts with us.

We have historically operated under long-term contracts. In response to changing market conditions, however, we have shifted from a traditional dependence solely on long-term contracts to an approach that balances short-term and long-term commitments. This shift, which can increase the volatility of our revenues, is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new pipeline competition, shifts in supply sources, volatility in natural gas prices, demand for short-term capacity and new power generation markets.

Our existing transportation and storage contracts mature at various times and in varying amounts of throughput capacity. Our ability to extend our existing contracts or remarket expiring capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the rates allowed under our tariffs. Currently, we have discounted a substantial portion of these rates to remain competitive.

The following table details our customers, contracts and competition on our pipeline system as of December 31, 2006:


Customer Information	Contract Information	Competition
Approximately 460 firm and interruptible customers, none of which individually represents more than 10 percent of our revenues	Approximately 470 firm transportation contracts. Weighted average remaining contract term of approximately four years.	We face competition in the northeast, Appalachian, midwest and southeast market areas. We compete with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on our system competes with alternative energy sources such as electricity, hydroelectric power, coal and fuel oil. In addition, we compete with pipelines and gathering systems for connection to new supply sources in Texas, the Gulf of Mexico and the Canadian border.

		In the offshore areas of the Gulf of Mexico, factors such as the distance of the supply fields from the pipeline, relative basis pricing of the pipeline receipt points, and costs of intermediate gathering or required processing of the natural gas to be transported may influence determinations of whether natural gas is ultimately attached to our system.

Regulatory Environment

Our interstate natural gas transmission system and storage operations are regulated by the FERC under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We operate under tariffs approved by the FERC that establish rates, cost recovery mechanisms, terms and conditions of service to our 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 services and facilities;

	•		maintenance of accounts and records;

	•		relationships between pipelines and certain affiliates;

	•		terms and conditions of services;

	•		depreciation and amortization policies;

	•		acquisition and disposition of facilities; and

	•		initiation and discontinuation of services.

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

We are subject to U.S. Department of Transportation regulations that establish safety requirements in the design, construction, operation and maintenance of our interstate natural gas transmission system and storage facility. Our operations on U.S. government land are regulated by the U.S. Department of the Interior.

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 February 21, 2007, we had approximately 1,500 full-time employees, none of whom are subject to a collective bargaining arrangement.

ITEM 1A. RISK FACTORS

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

This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements are based on assumptions and beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and the differences between assumed facts and actual results can be material, depending upon the circumstances. Where we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and based on assumptions believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur 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. Our results of operations are, to a large extent, driven by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volumes of natural gas we are able to transport and store 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 throughput, to renegotiate existing contracts as they expire or to remarket unsubscribed capacity:

	•		service area competition;

	•		expiration or turn back of significant contracts;

	•		changes in regulation and actions of regulatory bodies;

	•		weather conditions that impact throughput and storage levels;

	•		price competition;

	•		drilling activity and availability of natural gas;

	•		continued development of additional sources of gas supply that can be accessed;

	•		decreased natural gas demand due to various factors, including increases in prices and the increased availability or popularity of alternative energy sources such as coal, fuel oil and hydroelectric power;

	•		availability and increased cost of capital to fund ongoing maintenance and growth projects;

	•		opposition to energy infrastructure development, especially in environmentally sensitive areas;

	•		adverse general economic conditions; and

	•		unfavorable movements in natural gas prices in supply and demand areas.

The revenues of our pipeline businesses are generated under contracts that must be renegotiated periodically.

Our revenues are generated under transportation and storage contracts that expire periodically and must be renegotiated, extended or replaced. Although we actively pursue the renegotiation, extension or replacement of these contracts, we may not be able to extend or replace these contracts when they expire or may only be able to do so on terms that are not as favorable as existing contracts. 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. Currently, a substantial portion of our revenues are under contracts that are discounted at rates below the maximum rates allowed under our tariff.

Fluctuations in energy commodity prices could adversely affect our business.

Revenues generated by our transportation and storage contracts depend on volumes and rates, both of which can be affected by the price of natural gas. Increased natural gas prices could result in a reduction of the volumes transported by our customers, including power companies that may not dispatch natural gas-fired power plants if natural gas prices increase. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels as well as local distribution companies’ loss of customer base. The success of our transmission and storage operations is subject to continued development of additional gas supplies to offset the natural decline from existing wells connected to our system, which requires the development of additional oil and gas reserves and obtaining additional supplies from interconnecting pipelines, primarily in the Gulf of Mexico. A decline in energy prices could cause a decrease in these development activities and could cause a decrease in the volume of natural gas available for transmission and storage through our system. We retain a fixed percentage of natural gas transported. This retained natural gas is used as fuel and to replace lost and unaccounted for natural gas. We are at risk if we retain less natural gas than needed for fuel and to replace lost and unaccounted for natural gas. Pricing volatility may, in some cases, impact the value of under or over recoveries of retained natural gas, as well as imbalances and system encroachments. If natural gas prices in the supply basins connected to our pipeline system are higher than prices in other natural gas producing regions, our ability to compete with other transporters and our long term recontracting efforts may be negatively impacted. Furthermore, fluctuations in pricing between supply sources and market areas could negatively impact our transportation revenues. 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 and NGL;

	•		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 business is regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of the Interior and various state and local regulatory agencies. Regulatory actions taken by these 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. In setting authorized rates of return in recent FERC decisions, the FERC has utilized a proxy group of companies that includes local distribution companies that are not faced with as much competition or risks as interstate pipelines. The inclusion of these lower risk companies may create downward pressure on tariff rates when subjected to review by the FERC in future rate proceeding. Shippers on other pipelines have sought reductions from the FERC for the rates charged to their customers. If our tariff rates were reduced or redesigned in a future rate proceeding, our results of operations, financial position and cash flows could be materially adversely affected.

In addition, increased regulatory requirements relating to the integrity of our pipeline requires additional spending in order to maintain compliance with these requirements. Any additional requirements that are enacted could significantly increase the amount of these expenditures.

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

Environmental compliance and remediation costs and the costs of environmental liabilities could exceed our estimates.

Our operations are subject to various environmental laws and regulations that establish compliance and remediation obligations. Compliance obligations can result in significant costs to install and maintain pollution controls, fines and penalties resulting from any failure to comply and potential limitations on our operations. Remediation obligations can result in significant costs associated with the investigation and remediation of contaminated properties (some of which have been designated as Superfund sites by the United States Environmental Protection Agency under the Comprehensive Environmental Response, Compensation and Liability Act), as well as damage claims arising out of the contamination of properties or impact on natural resources. It is not possible for us to estimate exactly the amount and timing of all future expenditures related to environmental matters because of:

	•		The uncertainties in estimating pollution control and clean up costs, including sites where only preliminary site investigation or assessments have been completed;

	•		The discovery of new sites or additional information at existing sites;

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

	•		The nature of environmental laws and regulations, including the interpretation and enforcement thereof.

Currently, various legislative and regulatory measures to address greenhouse gas (GHG) emissions (including carbon dioxide and methane) are in various phases of discussion or implementation. These include the Kyoto Protocol (which is impacting proposed domestic legislation), proposed federal legislation and state actions to develop statewide or regional programs, each of which have imposed or would impose reductions in GHG emissions. These actions could result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any GHG emissions program. These actions could also impact the consumption of natural gas, thereby affecting our operations.

Although we believe we have established appropriate reserves for our environmental liabilities, we could be required to set aside additional amounts due to these uncertainties which could significantly impact our future results of operations, cash flows or financial position. For additional information concerning our environmental matters, 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 pipeline operations, including pipeline ruptures, explosions, pollution, release of toxic substances, fires, adverse weather conditions and other hazards, each of which could result in damage to or destruction of our facilities or damages or injuries to persons. In addition, our operations and assets face possible risks associated with acts of aggression or terrorism. If any of these events were to occur, we could suffer substantial losses.

While we maintain insurance against many of these risks to the extent and in amounts we believe are reasonable, this insurance does not cover all risks. Many of our insurance coverages have material deductibles as well as limits on our maximum recovery. As a result, our results of operations, cash flow or financial condition could be adversely affected if a significant event occurs that is not fully covered by insurance.

The expansion of our business by constructing new facilities subjects us to construction and other risks that may adversely affect our financial results.

We may expand the capacity of our existing pipeline or storage facility by constructing additional facilities. Construction of these facilities is subject to various regulatory, development and operational risks, including:

	•		our ability to obtain necessary approvals and permits by regulatory agencies on a timely basis and on terms that are acceptable to us;

	•		the ability to obtain continued access to sufficient capital to fund expansion projects;

	•		potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project;

	•		impediments on our ability to acquire rights-of-way or land rights on a timely basis on terms that are acceptable to us;

	•		our ability to construct projects within anticipated costs, including the risk that we may incur cost overruns resulting from inflation or increased costs of equipment, materials or labor, or other factors beyond our control, that may be material;

	•		lack of anticipated future growth in natural gas supply; and

	•		lack of transportation, storage or throughput commitments.

Any of these risks could prevent a project from proceeding, delay its completion or increase its anticipated costs. As a result, new facilities may not achieve our expected investment return, which could adversely affect our results of operations, cash flows or financial position .

Our business requires the retention and recruitment of a skilled workforce and the loss of employees could result in the failure to implement our business plan.

Our business requires the retention and recruitment of a skilled workforce. If we are unable to retain and recruit employees such as engineers and other technical positions, our business could be negatively impacted.

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 into this report.

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 or its other subsidiaries could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated B2 by Moody’s Investor Service and B by Standard & Poor’s. The ratings assigned to our senior unsecured indebtedness are currently rated Ba1 by Moody’s Investor Service and B+ by Standard & Poor’s. We and El Paso are on a positive outlook with these agencies. Downgrades of our or El Paso’s credit ratings could increase our cost of capital and collateral requirements, and could impede our access to capital markets.

El Paso provides cash management and other corporate services for us. Pursuant to El Paso’s cash management program, we transfer surplus cash to El Paso in exchange for an affiliated receivable. In addition, we conduct commercial transactions with some of our affiliates. If El Paso or such affiliates are unable to meet their respective liquidity needs, we may not be able to access cash under the cash management program, or our affiliates may not be able to pay their obligations to us. However, we might still be required to satisfy affiliated company payables. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position. For a further discussion of these matters, Part II, see Item 8, Financial Statements and Supplementary Data, Note 11.

We may be subject to a change in control if an event of default occurs under El Paso’s credit agreement.

Under, El Paso’s $1.75 billion credit agreement, our common stock and the common stock of several of our affiliates are pledged as collateral. As a result, our ownership is subject to change if there is an event of default under the credit agreement and El Paso’s lenders exercise rights over their collateral, even if we do not have any borrowings outstanding under the credit agreement.

A default under El Paso’s $1.75 billion credit agreement by any party could accelerate our future borrowings, if any, under the credit agreement and our long-term debt, which could adversely affect our liquidity position.

We are a party to El Paso’s $1.75 billion credit agreement. We are only liable, however, for our borrowings under the credit agreement, which were zero at December 31, 2006. Under the credit agreement, a default by El Paso, or any other borrower could result in the acceleration of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of our future borrowings, if any, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.

We are an indirect wholly owned subsidiary of El Paso.

As an indirect wholly owned subsidiary of El Paso, subject to limitations in our credit agreements, El Paso has substantial control over:

	•		our payment of dividends;

	•		decisions on our financing and 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.

ITEM 1B. UNRESOLVED STAFF COMMENTS

We have not included a response to this item since no response is required under Item 1B of Form 10-K.

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, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

All of our common stock, par value $5 per share, is owned by an indirect subsidiary of El Paso and, accordingly, our stock is not publicly traded.

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. No common stock dividends were declared or paid in 2006 or 2005.

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.

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. Our Management’s Discussion and Analysis (MD&A) should be read in conjunction with our consolidated financial statements and the accompanying footnotes. MD&A includes forward-looking statements that are subject to risks and uncertainties that may result in actual results differing from the statements we make. Factors that could cause actual results to differ include those risks and uncertainties that are discussed in Part I, Item 1A, Risk Factors.

Overview

Our business primarily consists of interstate natural gas transmission and storage services. Each of these services faces varying degrees of competition from other pipelines, proposed LNG facilities, as well as from alternative energy sources used to generate electricity, such as hydroelectric power, coal and fuel oil. Our revenues from transportation and storage consist of the following types.

Because of our regulated nature, our revenues have historically been relatively stable. However, our financial results can be subject to volatility due to factors such as changes in natural gas prices market conditions, regulatory actions, competition, the creditworthiness of our customers and weather. We also experience volatility in our financial results when the amounts of natural gas utilized in our operations differs from the amounts we recover from our customers for that purpose.

Historically, much of our business was conducted through long-term contracts with customers. In response to changing market conditions, we however, have shifted from a traditional dependence solely on long-term contracts to an approach that balances short-term and long-term commitments. This shift, which can increase the volatility of our revenues, is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new pipeline competition, shifts in supply sources, volatility in natural gas prices, demand for short-term capacity and new markets in electric generation.

In addition, our ability to extend existing customer contracts or remarket expiring contracted capacity is dependent on competitive alternatives, the regulatory environment at the federal, state and local levels and market supply and demand factors at the relevant dates these contracts are extended or expire. The duration of new or renegotiated contracts will be affected by current prices, competitive conditions and judgments concerning future market trends and volatility. Subject to regulatory requirements, we attempt to recontract or remarket our capacity at the rates allowed under our tariffs. Currently, we have discounted a substantial portion of these rates to remain competitive. Our existing contracts mature at various times and in varying amounts of throughput capacity. We continue to manage our recontracting process to mitigate the risk of significant impacts on our revenues. The weighted average remaining contract term for active contracts is approximately four years as of December 31, 2006.

Below is the contract expiration portfolio for our firm transportation contracts as of December 31, 2006, including those with terms beginning in 2007 or later.


			Percent of Total
	BBtu/d		Contracted Capacity
2007		1,248		17
2008		1,061		15
2009		992		13
2010 and beyond		3,984		55

Total		7,285		100

Results of Operations

Our management uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business which consists of consolidated operations as well as an investment in an unconsolidated affiliate. We believe EBIT is useful to our investors because it allows them to more effectively evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, (ii) income taxes and (iii) interest and debt expense. We exclude interest and debt expense from this measure so that investors may evaluate our operating results independently from our financing methods. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flow. Below is a reconciliation of EBIT to net income for the years ended December 31:


	2006			2005
	(In millions, except
	volumes)
Operating revenues	$	793		$	757
Operating expenses		(534	)		(540	)

Operating income		259			217
Earnings from unconsolidated affiliates		15			14
Other income, net		14			5

EBIT		288			236
Interest and debt expense		(129	)		(131	)
Affiliated interest income, net		43			25
Income taxes		(75	)		(48	)

Income before cumulative effect of accounting change		127			82
Cumulative effect of accounting change, net of income taxes		—			(3	)

Net income	$	127		$	79


Throughput volumes (BBtu/d)		4,534			4,443

The following items contributed to our overall EBIT increase of $52 million for the year ended December 31, 2006 as compared to 2005:


									EBIT
	Revenue			Expense			Other		Impact
	Favorable/(Unfavorable)
	(In millions)
Gas not used in operations and other natural gas sales	$	28		$	2		$	—	$	30
Higher services revenues		14			—			—		14
Lower general and administrative expenses		—			20			—		20
Impacts of Hurricanes Katrina and Rita		—			6			—		6
Higher pipeline integrity costs		—			(7	)		—		(7	)
Higher operating costs		—			(8	)		—		(8	)
Allowance for funds used during construction		—			—			9		9
Other⁽¹⁾		(6	)		(7	)		1		(12	)

Total impact on EBIT	$	36		$	6		$	10	$	52


⁽¹⁾		Consists of individually insignificant items.

The following discusses some of the significant items listed above as well as events that may affect our operations in the future.

Gas Not Used in Operations and Other Natural Gas Sales. The financial impact of operational gas, net of gas used in operations, is based on the amount of natural gas we are allowed to retain and dispose of according to our tariff, relative to the amounts of natural gas we use for operating purposes and the price of natural gas. Gas not needed for operations results in revenues to us, which we recognize when the volumes are retained. The financial impact of gas not needed for operations is driven by volumes and prices during a given period and influenced by factors such as system throughput, facility enhancements and the ability to operate the system in the most efficient and safe manner. During the year ended December 31, 2006, our EBIT was favorably impacted by higher gas prices for sales of gas not used in our operations compared to 2005.

Higher Services Revenues. During 2006, our reservation revenues increased due to sales of additional capacity and higher realized rates as a result of increased demand in our service areas. In addition, our usage revenues increased overall, primarily due to increased activity under various interruptible services provided under our tariff as a result of favorable market conditions.

Lower General and Administrative Expenses. During the year ended December 31, 2006, our general and administrative expenses were lower than in 2005, primarily due to a decrease in accrued benefit costs and lower allocated costs from El Paso.

Impacts of Hurricanes Katrina and Rita. Our operation and maintenance expenses were higher during the year ended December 31, 2005, due to unreimbursed amounts expended to repair damage caused by Hurricanes Katrina and Rita. During 2006, we incurred more capital related costs compared to 2005.

Higher Pipeline Integrity Costs. As of January 1, 2006, we adopted an accounting release issued by the FERC that requires us to expense certain costs we incur related to our pipeline integrity program. Prior to adoption, we capitalized these costs as part of our property, plant and equipment.

Higher Operating Costs. Our field operating costs were higher during the year ended December 31, 2006 compared to 2005, due to higher labor, contract, maintenance and fuel costs as a result of increased demand in our supply areas impacted by the hurricanes.

Allowance for Funds Used During Construction (AFUDC). AFUDC was higher during the year ended December 31, 2006, primarily due to capitalized costs related to hurricane related expenditures.

Expansions. Currently, we have the following expansion projects that have been approved by the FERC:

Anticipated

Completion

or In Service

Estimated

Estimated Annual

Project

Date

Cost

Revenues

Louisiana Deepwater Link

July 2007

$55 million⁽²⁾

—⁽³⁾

Triple -T Extension

September 2007

$33 million⁽¹⁾

—⁽³⁾

Essex Middlesex Project

November 2007

$47 million

2007 — $1 million; Thereafter—$8 million annually

Northeast ConneXion — New England

November 2007

$103 million

2007 — $6 million; Thereafter—$37 million annually


⁽¹⁾		Amount shown is net of anticipated receipt of approximately $12 million in contributions-in-aid-of construction.

⁽²⁾		Estimate reflects anticipated payment of approximately $15 million in contributions to a third party.

⁽³⁾		Revenues for these projects will be based on throughput levels as natural gas reserves are developed.

Sale of Lateral. In August 2006, we executed an agreement with a third party to sell a lateral for approximately $36 million which was approved by the FERC in December 2006. The sale was finalized in February 2007 and we will record a gain on the sale of approximately $8 million during the first quarter of 2007. We do not anticipate any material adverse impacts on future earnings as a result of this sale.

Affiliated Interest Income, Net

Affiliated interest income, net for the year ended December 31, 2006, was $18 million higher than in 2005 due to higher average advances to El Paso under its cash management program and higher average short-term interest rates. The average advances due from El Paso of $621 million in 2005 increased to $785 million in 2006. In addition, the average short-term interest rates increased from 4.2% in 2005 to 5.7% in 2006.

Income Taxes


	Year Ended
	December 31,
	2006			2005
	(In millions,
	except for rates)
Income taxes	$	75		$	48
Effective tax rate		37	%		37	%

Our effective tax rates for 2006 and 2005 were different than the statutory rate of 35 percent primarily due to state income taxes in both years. For a reconciliation of the statutory rate to the effective rates, see Item 8, Financial Statements and Supplementary Data, Note 3.

Liquidity and Capital Expenditures

Liquidity Overview

Our liquidity needs are provided by cash flows from operating activities. In addition, we participate in El Paso’s cash management program. 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 in exchange for an affiliated note receivable or payable. We have historically provided cash advances to El Paso, and we reflect these advances as investing activities in our statement of cash flows. At December 31, 2006, we had notes receivable from El Paso and other affiliates of $651 million that are due upon demand. However, we do not anticipate settlement within the next twelve months. In addition to our advances under El Paso’s cash management program, we had other notes receivable from El Paso of $422 million at December 31, 2006. See Item 8, Financial Statements and Supplementary Data, Note 11 for a further discussion of El Paso’s cash management program and our other notes receivable.

In addition to the cash management program, we are eligible to borrow amounts available under El Paso’s $1.75 billion credit agreement. We are only liable for amounts we directly borrow. We had no borrowings at December 31, 2006 under the credit agreement. At December 31, 2006, there was approximately $0.6 billion of borrowing capacity available to all eligible borrowers under the $1.75 billion credit agreement. For a further discussion of this credit agreement, see Item 8, Financial Statements and Supplementary Data, Note 7.

During the third quarter of 2006, we entered into agreements to sell certain accounts receivable to a qualifying special purpose entity (QSPE) under Statement of Financial Accounting Standards (SFAS) No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. As of December 31, 2006, we sold approximately $70 million of receivables, net of an allowance of approximately $1 million, received cash of approximately $34 million, received subordinated beneficial interests of approximately $35 million and recognized a loss of approximately $1 million. The cash received from the sale was advanced to El Paso under the cash management program. We reflect accounts receivable sold under this program and the related redemption of the subordinated beneficial interests as operating cash flows in our statement of cash flows. For a further discussion of the sales of our accounts receivable, see Item 8, Financial Statements and Supplementary Data, Note 11.

We believe that cash flows from operating activities and amounts available under El Paso’s cash management program and its $1.75 billion credit agreement, if necessary, will be adequate to meet our short-term capital and debt service requirements for our existing operations and planned expansion opportunities.

El Paso recently announced that it will pursue the formation of a master limited partnership in 2007 to enhance the value and financial flexibility of its pipeline assets and to provide a lower cost source of capital for new projects.

Debt

The holders of our $300 million, 7.0% debentures due in March 2027, had the option to require us to redeem their debentures at par value on March 15, 2007, together with accrued and unpaid interest. We have classified this amount on our balance sheet as current maturities of long term debt at December 31, 2006 to reflect this option. The holders of these obligations did not exercise their redemption option, which expired on February 15, 2007, thus, the debt will mature on its scheduled maturity date. For a further discussion of our debt, see Item 8, Financial Statements and Supplementary Data, Note 7.

Capital Expenditures

Our capital expenditures for the years ended December 31 were as follows:


	2006		2005
	(In millions)
Maintenance	$	160	$	138
Expansion/Other		101		30
Hurricanes⁽¹⁾		160		35

Total	$	421	$	203


⁽¹⁾		Amounts shown are net of insurance proceeds of $19 million and $28 million for 2006 and 2005 respectively.

Under our current plan, we expect to spend between approximately $125 million and $150 million in each of the next three years for capital expenditures primarily to maintain the integrity of our pipeline, to comply with clean air regulations and to ensure the safe and reliable delivery of natural gas to our customers. In addition, we have budgeted to spend between $33 million and $198 million in each of the next three years to expand the capacity and services of our pipeline system. We also expect to make capital expenditures for environmental matters of approximately $6 million in the aggregate for the years 2007 through 2011, which are not included in these amounts. These expenditures are primarily for Clean Air Act compliance projects. We expect to fund our capital expenditures through a combination of internally generated funds and, if necessary, repayments by El Paso of amounts advanced under its cash management program.

Hurricanes

We continue to repair damages to our pipeline caused by Hurricanes Katrina and Rita in 2005. We currently estimate total repair costs of approximately $355 million. Our mutual insurance company has indicated that we will not receive insurance recoveries of some of the amounts due to exceeding aggregate loss limits per event. We expect the remaining repair costs to be incurred in 2007 and most of the insurance reimbursements to be received in 2007 and into 2008. While we do not believe the unrecovered costs will materially impact our overall liquidity or financial results, the timing between expenditures and reimbursements may impact our liquidity from period to period. The table below provides further detail on what we have spent to date, our estimated remaining costs, and insurance recoveries.


	Recoverable		Unrecoverable
	Costs		Costs⁽¹⁾		Total
			(In millions)
Cumulative costs through December 31, 2006	$	100	$	130	$	230
Estimated remaining		55		70		125

Total costs	$	155	$	200	$	355

Less: Reimbursements to date		25

Expected future reimbursements	$	130


⁽¹⁾		Approximately $155 million of these costs are capital costs.

The mutual insurance company has also notified us that effective June 1, 2006, the aggregate loss limits on future events are reduced to $500 million from $1 billion, which will limit our recoveries on future hurricanes or other insurable events.

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

See Item 8, Financial Statements and Supplementary Data, Note 1, under New Accounting Pronouncements Issued But Not Yet Adopted, which is incorporated herein by reference.

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 effective interest rates of our interest bearing securities by expected maturity dates and the fair value of these securities. At December 31, 2006, the fair values of our fixed rate long-term debt securities have been estimated based on quoted market prices for the same or similar issues.


	December 31, 2006													December 31, 2005
	Expected Fiscal Year of Maturity of Carrying Amounts
												Fair		Carrying		Fair
	2007			2011			Thereafter			Total		Value		Amount		Value
	(In millions, except for rates)
Liabilities:
Long-term debt, including current maturities — fixed rate	$	298	⁽¹⁾	$	80		$	1,224		$	1,602	$	1,779	$	1,600	$	1,703
Average effective interest rate		7.1	%		7.5	%		7.7	%


⁽¹⁾		The holders of our $300 million, 7.0% debentures due in March 2027, had the option to require us to redeem their debentures at par value on March 15, 2007, together with accrued and unpaid interest. We classified this amount on our balance sheet as current maturities of long term debt at December 31, 2006 to reflect this option. The holders of these obligations did not exercise their redemption option, which expired on February 15, 2007, thus, the debt will mature on its scheduled maturity date. For a further discussion of our debt, see Item 8, Financial Statements and Supplementary Data, Note 7.

We are also exposed to changes in natural gas prices associated with the natural gas that we are allowed to retain, net of gas used in operations. We sell this retained gas when such gas is not operationally necessary or when such gas needs to be removed from the system, which may subject us to both commodity price and locational price differences depending on when and where that gas is sold. In some cases, where we have made a determination that, by a certain point in time, it is operationally necessary to dispose of gas not used in operations, we use forward sales contracts to manage this risk, which include fixed prices and variable prices within certain price constraints. Our revenues associated with the sale of gas not used in operations increased during 2006 due to increases in natural gas prices.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Report of Independent Registered Public Accounting Firm

The Board of Directors and Stockholder of Tennessee Gas Pipeline Company

We have audited the accompanying consolidated balance sheet of Tennessee Gas Pipeline Company (the Company) as of December 31, 2006, and the related consolidated statements of income, stockholder’s equity, and cash flows for the year then ended. Our audit also included the financial statement schedule listed in the Index at Item 15(a) for the year ended December 31, 2006. These financial statements and schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and schedule based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company’s internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also 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 audit provides a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Tennessee Gas Pipeline Company at December 31, 2006, and the consolidated results of its operations and its cash flows for the year then ended, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

As discussed in Note 1 to the consolidated financial statements, effective January 1, 2006, the Company adopted the Federal Energy Regulatory Commission’s accounting release related to pipeline assessment costs and effective December 31, 2006, the Company adopted the recognition provisions of Statement of Financial Accounting Standards No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132(R).

/s/ Ernst & Young LLP

Houston, Texas
February 26, 2007

Report of Independent Registered Public Accounting Firm

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, 2005, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for each of the two years in the period ended December 31, 2005 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 the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards 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 Financial Accounting Standards Board Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, on December 31, 2005.

/s/ PricewaterhouseCoopers LLP

Houston, Texas
February 28, 2006

TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)


	December 31,
	2006		2005
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Accounts receivable
Customer, net of allowance of $1 in 2005		21		123
Affiliates		70		25
Other		43		25
Materials and supplies		28		22
Assets held for sale		28		—
Deferred income taxes		117		9
Other		7		8

Total current assets		314		212

Property, plant and equipment, at cost		3,707		3,345
Less accumulated depreciation, depletion and amortization		606		543

		3,101		2,802
Additional acquisition cost assigned to utility plant, net		2,079		2,119

Total property, plant and equipment, net		5,180		4,921

Other assets
Notes receivable from affiliates		1,073		1,098
Investment in unconsolidated affiliate		98		101
Other		37		32

		1,208		1,231

Total assets	$	6,702	$	6,364


LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	90	$	85
Affiliates		26		18
Other		44		38
Current maturities of long-term debt		300		—
Taxes payable		78		37
Asset retirement obligations		33		—
Accrued interest		24		24
Contractual deposits		28		21
Other		12		21

Total current liabilities		635		244

Long-term debt		1,302		1,600

Other liabilities
Deferred income taxes		1,407		1,271
Regulatory liabilities		160		170
Other		41		52

		1,608		1,493


Commitments and contingencies
Stockholder’s equity
Common stock, par value $5 per share; 300 shares authorized; 208 shares issued and outstanding		—		—
Additional paid-in capital		2,207		2,207
Retained earnings		947		820
Accumulated other comprehensive income		3		—

Total stockholder’s equity		3,157		3,027

Total liabilities and stockholder’s equity	$	6,702	$	6,364

See accompanying notes.

TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)


	Year Ended December 31,
	2006			2005			2004
Cash flows from operating activities
Net income	$	127		$	79		$	94
Adjustments to reconcile net income to net cash from operating activities Depreciation, depletion and amortization		164			161			161
Cumulative effect of accounting change		—			3			—
Deferred income taxes		26			60			15
Earnings from unconsolidated affiliates, adjusted for cash distributions		2			50			(13	)
Other non-cash income items		(6	)		(1	)		—
Asset and liability changes
Accounts receivable		32			(42	)		(16	)
Accounts payable		27			15			49
Taxes payable		37			(30	)		(31	)
Other, net		(20	)		74			2

Net cash provided by operating activities		389			369			261


Cash flows from investing activities
Additions to property, plant and equipment		(421	)		(203	)		(164	)
Net change in notes receivable affiliates		25			(168	)		(89	)
Other		7			2			(8	)

Net cash used in investing activities		(389	)		(369	)		(261	)


Net change in cash and cash equivalents		—			—			—
Cash and cash equivalents
Beginning of period		—			—			—

End of period	$	—		$	—		$	—

See accompanying notes.

TENNESSEE GAS PIPELINE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

We are a Delaware corporation incorporated in 1947, and an indirect wholly owned 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 our natural gas pipeline system and storage facilities. Our consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles and we include the accounts of all majority owned and 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.

We consolidate entities when we either (i) have the ability to control the operating and financial decisions and policies of that entity or (ii) are allocated a majority of the entity’s losses and/or returns through our variable interests in that entity. The determination of our ability to control or exert significant influence over an entity and whether we are allocated a majority of the entity’s losses and/or returns involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control, the policies and decisions of an entity and where we are not allocated a majority of the entity’s losses and/or returns. We use the cost method of accounting where we are unable to exert significant influence over the entity.

Use of Estimates

The preparation of our financial statements 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.

Regulated Operations

Our natural gas transmission system and storage operations are subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938, the Natural Gas Policy Act of 1978 and the Energy Policy Act of 2005. We apply the regulatory accounting principles prescribed under Statement of Financial Accounting Standards (SFAS) No. 71, Accounting for the Effects of Certain Types of Regulation. Under SFAS No. 71 we record regulatory assets and liabilities that would not be recorded under GAAP for non-regulated entities. Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Items to which we apply regulatory accounting requirements include certain postretirement employee benefit plan costs, an equity return component on regulated capital projects and certain items included in, or expected to be included in, future rates.

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 receivable 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 customers’ contracted amount of natural gas delivered or received. We value these imbalances due to or from shippers and operators at current index prices. Imbalances are settled in cash or in-kind, subject to the terms of our tariff.

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 as we expect to settle them within a year.

Property, Plant and Equipment

Our property, plant and equipment is recorded at its original cost of construction or, upon acquisition, at the fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead, interest and an equity return component, as allowed by the FERC. We capitalize major units of property replacements or improvements and expense minor items. Prior to January 1, 2006, we capitalized certain costs incurred related to our pipeline integrity programs as part of our property, plant and equipment. Beginning January 1, 2006, we began expensing certain of these costs based on FERC guidance. During the year ended December 31, 2006, we expensed approximately $7 million as a result of the adoption of this accounting release.

We use the composite (group) method to depreciate regulated property, plant and equipment. Under this method, assets with similar lives and 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 percent to 25 percent per year. Using these rates, the remaining depreciable lives of these assets range from one to 30 years. We re-evaluate depreciation rates each time we file with the FERC for a change in our transportation and storage service rates.

When we retire regulated property, plant and equipment, we charge accumulated depreciation and amortization for the original cost of the assets in addition to the cost to remove, sell or dispose of the assets, less their 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 operating income. For non-regulated properties, we reduce property, plant and equipment for its original cost, less accumulated depreciation and salvage value with any remaining gain or loss recorded in income.

Included in our property balances are additional acquisition costs assigned to utility plant, which represents the excess of allocated purchase costs over the historical costs of the facilities. These costs are amortized on a straight-line basis over 62 years using the same rates as the related assets, and we do not recover those excess costs in our rates.

At December 31, 2006 and 2005, we had approximately $237 million and $151 million of construction work in progress included in our property, plant and equipment.

We capitalize a carrying cost (an allowance for funds used during construction) on funds related to our construction of long-lived assets. This carrying cost consists of a return on the investment financed by debt and a return on the investment financed by equity. The debt portion is calculated based on our average cost of debt. Interest costs on debt amounts capitalized during the years ended December 31, 2006, 2005 and 2004, were $5 million, $2 million and $1 million. These debt amounts are included as a reduction to interest and debt expense in our income statement. The equity portion of capitalized costs is calculated using the most recent FERC-approved equity rate of return. The equity amounts capitalized during the year ended December 31, 2006, 2005 and 2004, were $8 million, $3 million and $2 million (exclusive of any tax related impacts). These equity amounts are included as other non-operating income on our income statement. Capitalized carrying costs for debt and equity financed construction are reflected as an increase in the cost of the asset on our balance sheet.

Asset and Investment Impairments

We evaluate assets and investments for impairment when events or circumstances indicate that their carrying values may not be recovered. These events include market declines that are believed to be other than temporary, changes in the manner in which we intend to use a long-lived asset, decisions to sell an asset or investment and adverse changes in the legal or business environment such as adverse actions by regulators. When an event occurs, we evaluate the recoverability of our long-lived assets’ carrying values based on either (i) our long-lived assets’ ability to generate future cash flows on an undiscounted basis or (ii) the fair value of our investment in our unconsolidated affiliate. If an impairment is indicated or if we decide to sell a long-lived asset or group of assets, we adjust the carrying value of these assets downward, if necessary, to their estimated fair value. Our fair value estimates are generally based on market data obtained through the sales process or an analysis of expected discounted cash flows. The magnitude of any impairment is impacted by a number of factors, including the nature of the assets being sold and our established time frame for completing the sales, among other factors.

We reclassify the asset or assets to be sold as either held-for-sale or as discontinued operations, depending on, among other criteria, whether we will have significant long-term continuing involvement with those assets after they are sold. We cease depreciating assets in the period that they are reclassified as either held for sale or as discontinued operations.

Revenue Recognition

Our revenues are primarily generated from transportation and storage services. Revenues for all services are based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity ratably over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric-based services, we record revenues when physical deliveries of natural gas are made at the agreed upon delivery point or when gas is injected or withdrawn from the storage facility. Gas not used in operations is based on the volumes of natural gas we are allowed to retain relative to the amounts we use for operating purposes. We recognize revenue on gas not needed for operations when the volumes are retained under our tariff. We are subject to FERC regulations and, as a result, revenues we collect may be subject to refund in a rate proceeding. We establish reserves for these potential refunds.

Environmental Costs and Other Contingencies

Environmental Costs. We record environmental liabilities at their undiscounted amounts in our balance sheet in other current and long-term liabilities when our environmental assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into consideration the likely effects of other societal and economic factors, 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 or other organizations. Our estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and we recognize a current period expense when clean-up efforts do not benefit future periods.

We evaluate any amounts paid directly or reimbursed by government sponsored programs and potential recoveries or reimbursements of remediation costs from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the creditworthiness or solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our balance sheet.

Other Contingencies. We recognize liabilities for other contingencies when we have an exposure that when fully analyzed, indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the lower end of the range is accrued.

Income Taxes

El Paso maintains a tax accrual policy to record both regular and alternative minimum taxes for companies included in its consolidated federal and state income tax returns. The policy provides, among other things, that (i) each company in a taxable income position will accrue a current expense equivalent to its federal and state income taxes, 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 returns. El Paso pays all consolidated U.S. federal and state income taxes directly to the appropriate taxing jurisdictions and, under a separate tax billing agreement, El Paso may bill or refund its subsidiaries for their portion of these income tax payments.

Pursuant to El Paso’s policy, we record 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.

Accounting for Asset Retirement Obligations

We account for our asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 47, Accounting for Conditional Asset Retirement Obligations. We record a liability for legal obligations associated with the replacement, removal and retirement of our long-lived assets. Our asset retirement liabilities are recorded at their estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the long-lived asset to which that liability relates. An ongoing expense is also recognized for changes in the value of the liability as a result of the passage of time, which we record as depreciation, depletion and amortization expense in our income statement. Because we believe it is probable that we will recover certain of these costs through our rates, we have recorded an asset (rather than expense) associated with certain of the depreciation of the property, plant and equipment and certain of the accretion of the liabilities described above.

Pension and Other Postretirement Benefits

In December 2006, we adopted the provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132(R). Under SFAS No. 158, we record an asset or liability for our pension and other postretirement benefit plans based on their funded or unfunded status. We also record any deferred amounts related to unrealized gains and losses or changes in actuarial assumptions in accumulated other comprehensive income, a component of stockholder’s equity, until those gains and losses are recognized in the income statement. For a further discussion of our adoption of SFAS No. 158, see Note 9.

Evaluation of Prior Period Misstatements in Current Financial Statements

In December 2006, we adopted the provisions of the Securities and Exchange Commission's (SEC) Staff Accounting Bulletin (SAB) No. 108. Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements. SAB No. 108 provides guidance on how to evaluate the impact of financial statement misstatements from prior periods that have been identified in the current year. The adoption of these provisions did not have any impact on our financial statements.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2006, the following accounting standards and interpretations had not yet been adopted by us.

Accounting for Uncertainty in Income Taxes. In July 2006, the FASB issued FIN No. 48, Accounting for Uncertainty in Income Taxes. FIN No. 48 clarifies SFAS No. 109, Accounting for Income Taxes, and requires us to evaluate our tax positions for all jurisdictions and all years where the statute of limitations has not expired. FIN No. 48 requires companies to meet a more likely than not threshold (i.e. greater than a 50 percent likelihood of a tax position being sustained under examination) prior to recording a benefit for their tax positions. Additionally, for tax positions meeting this more likely than not threshold, the amount of benefit is limited to the largest benefit that has a greater than 50 percent probability of being realized upon ultimate settlement. The cumulative effect of applying this interpretation will be recorded as an adjustment to the beginning balance of retained earnings, or other components of stockholder’s equity as appropriate, in the period of adoption. This interpretation is effective. for fiscal years beginning after December 15, 2006, and we do not anticipate that it will have a material impact on our financial statements.

Fair Value Measurements. In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which provides guidance on measuring the fair value of assets and liabilities in the financial statements. We will be required to adopt the provisions of this standard no later than in 2008, and are currently evaluating the impact, if any, that it will have on our financial statements.

Measurement Date of Postretirement Benefits. In December 2006, we adopted the recognition provisions of SFAS No. 158. This standard will also require us to change the measurement date of our other postretirement benefit plans from September 30, the date we currently use, to December 31 beginning in 2008. We are evaluating the impact, if any, that the measurement date provisions of this standard will have on our financial statements.

2. Divestitures

Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we classify assets to be disposed of as held for sale or, if appropriate, discontinued operations when they have received appropriate approvals by our management or Board of Directors and when they meet other criteria. At December 31, 2006, we had assets held for sale of approximately $28 million as a result of our pending sale of a lateral. The sale closed in February 2007.

3. Income Taxes

Components of Income Taxes. The following table reflects the components of income taxes included in income before cumulative effect of accounting change for each of the three years ended December 31:


	2006			2005			2004
	(In millions)
Current
Federal	$	50		$	(13	)	$	52
State		(1	)		1			(3	)

		49			(12	)		49


Deferred
Federal		18			58			1
State		8			2			14

		26			60			15

Total income taxes	$	75		$	48		$	64

Effective Tax Rate Reconciliation. Our income taxes differ 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:


	2006			2005			2004
	(In millions)
Income taxes at the statutory federal rate of 35%	$	71		$	46		$	55
State income taxes, net of federal income tax effect		4			2			6
Change in the estimated realizability of deferred tax assets for state net operating loss carryovers		—			—			2
Other		—			—			1

Income taxes	$	75		$	48		$	64

Effective tax rate		37	%		37	%		41	%

Deferred Tax Assets and Liabilities. The following are the components of our net deferred tax liability at December 31:


	2006		2005
	(In millions)
Deferred tax liabilities
Property, plant and equipment	$	1,506	$	1,444
Other		88		94

Total deferred tax liability		1,594		1,538


Deferred tax assets
Net operating loss and credit carryovers
U.S. federal		110		95
State		52		56
Other liabilities		142		125

Total deferred tax asset		304		276

Net deferred tax liability	$	1,290	$	1,262

We believe it is more likely than not that we will realize the benefit of our deferred tax assets due to expected future taxable income, including the effect of future reversals of existing taxable temporary differences primarily related to depreciation.

Net Operating Loss (NOL) Carryovers. The table below presents the details of our federal and state NOL carryover periods as of December 31, 2006:


	2007		2008-2011		2012-2016		2017-2026		Total
	(In millions)
U.S. federal NOL	$	—	$	—	$	—	$	315	$	315
State NOL		9		69		225		406		709

Usage of our U.S. federal 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.

4. Financial Instruments

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

2006

2005

Carrying

Fair

Carrying

Fair

Amount

Value

Amount

Value

(In millions)

Balance sheet financial instruments:

Long-term debt including current maturities⁽¹⁾

1,602

1,779

1,600

1,703

⁽¹⁾

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

At December 31, 2006 and 2005, the carrying amounts of cash and cash equivalents and trade receivables and payables are representative of their fair value because of the short-term maturity of these instruments.

5. Regulatory Assets and Liabilities

Below are the details of our regulatory assets and liabilities at December 31:


Description	2006		2005
	(In millions)
Current regulatory assets	$	—	$	2
Non-current regulatory assets
Grossed-up deferred taxes on capitalized funds used during construction		20		16
Postretirement benefits		9		11
Unamortized net loss on reacquired debt		2		2
Other		2		1

Total regulatory assets⁽¹⁾	$	33	$	32


Non-current regulatory liabilities
Environmental liability	$	130	$	110
Cost of removal of offshore assets		—		33
Postretirement benefits		19		16
Plant regulatory liability		11		11

Total regulatory liabilities	$	160	$	170


⁽¹⁾		Amounts are included as other current and non-current assets in our balance sheet.

6. Property, Plant and Equipment

Additional Acquisition Costs. As of December 31, 2006, additional acquisition costs assigned to utility plant was approximately $2.4 billion and accumulated depreciation was approximately $299 million. These excess costs are being amortized over the life of the related pipeline assets. Our amortization expense related to additional acquisition costs assigned to utility plant was approximately $40 million for each of 2006 and 2005.

Asset Retirement Obligations. We have legal obligations associated with our natural gas pipeline and related transmission facilities and storage wells and our Corporate headquarters building. We have obligations to plug storage wells when we no longer plan to use them and when we abandon them. Our legal obligations associated with our natural gas transmission facilities relate primarily to purging and sealing the pipeline if it is abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities and our Corporate headquarters building if these facilities are replaced or renovated. We accrue a liability for legal obligations based on an estimate of the timing and amount of their settlement.

We are required to operate and maintain our natural gas pipeline and storage systems, and intend to do so as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that the substantial majority of our natural gas pipeline and storage system assets have indeterminate lives. We continue to evaluate our asset retirement obligations and future developments could impact the amounts we record.

In estimating the liability associated with our asset retirement obligations, we utilize several assumptions, including credit-adjusted discount rates ranging from six to eight percent and a projected inflation rate of 2.5 percent. The net asset retirement liability as of December 31 reported on our balance sheet in other current and non-current liabilities, and the changes in the net liability for the years ended December 31, were as follows:


	2006			2005
	(in millions)
Net asset retirement liability at January 1	$	43		$	32
Liabilities settled		(26	)		(1	)
Liabilities incurred		—			2
Change in estimate		29			—
Accretion expense		1			—
Adoption of FIN No. 47⁽¹⁾		—			10

Net asset retirement liability at December 31⁽²⁾	$	47		$	43


⁽¹⁾		We recorded a charge in 2005 of $5 million net of income taxes of $2 million as a cumulative effect of accounting change upon our adoption of FIN No. 47. If we had adopted the provisions of FIN No. 47 as of January 1, 2004, our asset retirement liability would have been higher by approximately $9 million as of January 1, 2005, and our net income for the years ended December 31, 2005 and 2004 would not have been materially affected.

⁽²⁾		As of December 31, 2006, approximately $33 million of this amount is reflected in current liabilities which relates primarily to costs associated with obligations related to Hurricane Katrina and Rita. As of December 31, 2005, $33 million of this amount is included in our non-current regulatory liabilities.

Our change in estimate represents a change to the expected amount and timing of payments to settle our asset retirement obligations.

7. Debt and Other Credit Facilities

Debt

Our long-term debt outstanding consisted of the following at December 31:


	2006		2005
	(In millions)
6.0% Debentures due December 2011	$	86	$	86
7.5% Debentures due April 2017		300		300
7.0% Debentures due March 2027		300		300
7.0% Debentures due October 2028		400		400
8.375% Notes due June 2032		240		240
7.625% Debentures due April 2037		300		300

Less:		1,626		1,626
Current maturities		300		—
Unamortized discount		24		26

Long-term debt, less current maturities	$	1,302	$	1,600

The holders of our $300 million, 7.0% debentures due March 2027, had the option to require us to redeem their debentures at par value on March 15, 2007, together with accrued and unpaid interest. We classified this amount on our balance sheet as current maturities of long-term debt at December 31, 2006 to reflect this option. The holders of these obligations did not exercise their redemption option, which expired on February 15, 2007, thus, the debt will mature on its scheduled maturity date. In addition, we currently have the ability to call $726 million of our notes and debentures at any time prior to their stated maturity, and the ability to call our $300 million debentures due March 2027, after March 15, 2007. If we were to call these notes and debentures, we would be obligated to pay principal, accrued interest and a make-whole premium to redeem the debt.

Credit Facilities

In July 2006, El Paso entered into a new $1.75 billion credit agreement, consisting of a $1.25 billion three-year revolving credit facility and a $500 million five-year deposit letter of credit facility. We are an eligible borrower under the credit agreement and are only liable for amounts we directly borrow. We had no borrowings at December 31, 2006 under the credit agreement. Our common stock and the common stock of several of our affiliates are pledged as collateral under the agreement. At December 31, 2006, there was approximately $0.6 billion of borrowing capacity available to all eligible borrowers under the $1.75 billion credit agreement.

Under the $1.75 billion credit agreement and our indentures, we are subject to a number of restrictions and covenants. The most restrictive of these include (i) limitations on the incurrence of additional debt, based on a ratio of debt to EBITDA (as defined in the agreements), the most restrictive of which shall not exceed 5 to 1; (ii) limitations on the use of proceeds from borrowings; (iii) limitations, in some cases, on transactions with our affiliates; (iv) limitations on the incurrence of liens; (v) potential limitations on our ability to declare and pay dividends; and (vi) limitations on our ability to prepay debt. For the year ended December 31, 2006, we were in compliance with our debt-related covenants.

8. Commitments and Contingencies

Legal Proceedings

Gas Measurement Cases. We and a number of our affiliates were named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. The first set of cases was filed in 1997 by an individual under the False Claims Act, which has been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming). 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. In May 2005, a representative appointed by the court issued a recommendation to dismiss most of the actions. In October 2006, the U.S. District Judge issued an order dismissing all measurement claims against all defendants. An appeal has been filed.

Similar allegations were filed in a second set of actions initiated in 1999 in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The plaintiffs currently seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. Motions for class certification have been briefed and argued in the proceedings and the parties are awaiting the court’s ruling. The plaintiffs seek an unspecified amount of monetary damages in the form of additional royalty payments (along with interest, expenses and punitive damages) and injunctive relief with regard to future gas measurement practices. Our costs and legal exposure related to this lawsuit and claim are not currently determinable.

Hurricane Litigation. We have been named in three class action petitions for damages filed in the United States District Court for the Eastern District of Louisiana against all oil and natural gas pipeline and production companies that dredged pipeline canals, installed transmission lines or drilled for oil and natural gas in the marshes of coastal Louisiana. The lawsuits, George Barasich, et al. v. Columbia Gulf Transmission Company, et al., and Charles Villa Jr., et al. v. Columbia Gulf Transmission Company, et al., (filed in 2005), and Henry and Hattie Bands et al. v. Columbia Gulf Transmission Company et al., (filed in August 2006), assert that the defendants caused erosion and land loss, which destroyed critical protection against hurricane surges and winds and was a substantial cause of the loss of life and destruction of property. The Barasich and Bands lawsuits allege damages associated with Hurricane Katrina. The Villa lawsuit alleges damages associated with Hurricanes Katrina and Rita. All three cases were dismissed on the basis that the plaintiffs failed to state a claim on which relief could be granted. Those judgments are now final and none of the plaintiffs have appealed.

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 further information becomes available, or other relevant developments occur, we may accrue amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we had no accruals for outstanding legal matters at December 31, 2006.

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. At December 31, 2006, we had accrued approximately $15 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued. Second, where the most likely outcome cannot be estimated, a range of costs is established and if no amount in that range is more likely than any other, the lower end of the expected range has been accrued. During the year ended December 31, 2006, we reduced our accrual by $12 million as a result of the completion of negotiations with state and federal regulatory agencies, which reduced our estimated costs to remediate Polychlorinated Biphenyls (PCBs) and other hazardous substances at several of our sites. Our environmental remediation projects are in various stages of completion. The liabilities we have recorded reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Below is a reconciliation of our accrued liability from January 1, 2006 to December 31, 2006 (in millions):


Balance at January 1, 2006	$	32
Reduction in the estimated costs to complete		(12	)
Payments for remediation activities		(5	)

Balance at December 31, 2006	$	15

For 2007, we estimate that our total remediation expenditures will be approximately $7 million, which will be expended under government directed clean-up plans.

PCB Cost Recoveries. Pursuant to a consent order executed with the United States Environmental Protection Agency in May 1994, we have been conducting remediation activities at certain of our compressor stations associated with the presence of PCBs and other hazardous materials. We have recovered a substantial portion of the environmental costs identified in our PCB remediation project through a surcharge to our customers. An agreement with our customers, approved by the FERC in November 1995, established the surcharge mechanism. The surcharge collection period is currently set to expire in June 2008 with further extensions subject to a filing with the FERC. As of December 31, 2006, we had pre-collected PCB costs of approximately $139 million. This pre-collected amount 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 difference, plus carrying charges incurred up to the date of the refunds. Our regulatory liability for estimated future refund obligations to our customers increased from approximately $110 million at December 31, 2005 to approximately $130 million at December 31, 2006.

Comprehensive Environmental Response, Compensation and Liability Act (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 four active sites under the 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, 2006, we have estimated our share of the remediation costs at these sites to be between $1 million and $2 million. Because the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. Accruals for these matters are included in the environmental reserve discussed above.

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

Capital Commitments and Purchase Obligations

At December 31, 2006, we had capital and investment commitments of approximately $70 million. Our other planned capital and investment projects are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures. In addition, we have entered into unconditional purchase obligations for products, services and other capital assets, including a storage agreement with our affiliate, totaling $134 million at December 31, 2006. Our annual obligations under these agreements are $39 million in 2007, $35 million in 2008, $24 million in 2009, $10 million in 2010, $9 million in 2011 and $17 million in total thereafter.

Operating Leases

We lease property, facilities and equipment under various operating leases. Minimum future annual rental commitments on our operating leases as of December 31, 2006, were as follows:


Year Ending
December 31,	( In millions)
2007	$	1
2008		1
2009		1
2010		1
Thereafter		3

Total	$	7

Rental expense on our operating leases for each of the years ended December 31, 2006, 2005 and 2004 was $2 million, $3 million and $8 million. These amounts include our share of rent allocated to us from El Paso.

Other Commercial Commitments

We hold cancelable easements or rights-of-way arrangements from landowners permitting the use of land for the construction and operation of our pipeline system. Currently, our obligations under these easements are not material to the results of our operations.

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. El Paso matches 75 percent of participant basic contributions up to 6 percent of eligible compensation and can make additional discretionary matching contributions. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

Postretirement Benefits. We provide medical and life insurance benefits for a closed group of retirees who were eligible to retire on December 31, 1996, and did so before July 1, 1997. Medical benefits for this closed group may be subject to deductibles, co-payment provisions, and other limitations and dollar caps on the amount of employer costs. El Paso reserves 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 our rates. In 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 recovered in rates, a regulatory asset or liability is recorded. We expect to contribute $5 million to our postretirement benefit plan in 2007.

On December 31, 2006, we adopted the provisions of SFAS No. 158, and upon adoption reflected the assets and liabilities related to our postretirement benefit plan based on their funded status. The adoption of this standard increased our other non-current assets by approximately $2 million, decreased our other current liabilities by approximately $3 million, increased our other non-current deferred tax liabilities by approximately $2 million, and increased our accumulated other comprehensive income by approximately $3 million. We anticipate that less than $1 million of our accumulated other comprehensive income will be recognized as a part of our net periodic benefit cost in 2007.

Change in Accumulated Postretirement Benefit Obligation, Plan Assets and Funded Status. Our benefits are presented and computed as of and for the twelve months ended September 30:


	2006			2005
	(In millions)
Change in accumulated postretirement benefit obligation:
Accumulated postretirement benefit obligation at beginning of period	$	24		$	25
Interest cost		1			2
Participant contributions		1			1
Actuarial loss		(2	)		—
Benefits paid		(2	)		(4	)

Accumulated postretirement benefit obligation at end of period	$	22		$	24


Change in plan assets:
Fair value of plan assets at beginning of period	$	19		$	16
Actual return on plan assets		—			1
Employer contributions		5			5
Participant contributions		1			1
Benefits paid		(2	)		(4	)

Fair value of plan assets at end of period	$	23		$	19


Reconciliation of funded status:
Fair value of plan assets at September 30	$	23		$	19
Less: Accumulated postretirement benefit obligation, end of period		22			24

Funded status at September 30		1			(5	)
Fourth quarter contributions and income		1			1
Unrecognized actuarial gains⁽¹⁾		—			(3	)

Net asset (liability) at December 31	$	2		$	(7	)


⁽¹⁾		Amounts were reclassified to accumulated other comprehensive income upon the adoption of SFAS No. 158 in 2006.

Expected Payment of Future Benefits. As of December 31, 2006, we expect the following payments under our plans (in million):


Year Ending
December 31,
2007	$	2
2008		2
2009		2
2010		2
2011		2
2012-2016		10

Total	$	20

Components of Net Benefit Cost. For each of the years ended December 31, the components of net benefit cost are as follows:


	2006			2005			2004
	(In millions)
Interest cost	$	1		$	2		$	2
Expected return on plan assets		(1	)		(1	)		(1	)

Net postretirement benefit cost	$	—		$	1		$	1

Actuarial Assumptions and Sensitivity Analysis. Accumulated postretirement benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used in determining our postretirement plan obligations for 2006, 2005 and 2004:


	2006		2005		2004
	(Percent)
Assumptions related to benefit obligations at September 30:
Discount rate		5.50		5.25
Assumptions related to benefit costs at December 31:
Discount rate		5.25		5.75		6.00
Expected return on plan assets⁽¹⁾		8.00		7.50		7.50


⁽¹⁾		The expected return on plan assets is a pre-tax rate (before a tax rate of 35 percent on postretirement benefits) that is primarily based on an expected risk-free investment return, adjusted for historical risk premiums and specific risk adjustments associated with our debt and equity securities. These expected returns were then weighted based on the target asset allocations of our investment portfolio.

Actuarial estimates for our postretirement benefits plan assumed a weighted average annual rate of increase in the per capita costs of covered health care benefits of 10.3 percent in 2006, gradually decreasing to 5.0 percent by the year 2015. Assumed health care cost trends can have a significant effect on the amounts reported for our postretirement benefit plan. However, it does not affect our costs because our costs are limited by defined dollar caps.

Plan Assets. The following table provides the actual asset allocations in our postretirement plan as of September 30:


	Actual		Actual
Asset Category	2006		2005
	(Percent)
Equity securities		61		56
Debt securities		32		29
Other		7		15

Total		100		100

The primary investment objective of our plan is to ensure that, over the long-term life of the plan, an adequate pool of sufficiently liquid assets exists to support the benefit obligation to participants, retirees and beneficiaries. In meeting this objective, the plan seeks to achieve a high level of investment return consistent with a prudent level of portfolio risk. Investment objectives are long-term in nature covering typical market cycles of three to five years. Any shortfall in investment performance compared to investment objectives is the result of general economic and capital market conditions.

The target allocation for the invested assets is 65 percent equity and 35 percent fixed income. Other assets are held in cash for payment of benefits upon presentment. Any El Paso stock held by the plan is held indirectly through investments in mutual funds.

10. Supplemental Cash Flow Information

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


	2006		2005			2004
	(In millions)
Interest paid, net of capitalized interest	$	119	$	121		$	123
Income tax payments (refunds)		13		(21	)		72

11. Investment in Unconsolidated Affiliate and Transactions with Affiliates

Investment in Unconsolidated Affiliate

Bear Creek Storage Company (Bear Creek). We have a 50 percent ownership interest in Bear Creek, a joint venture with Southern Gas Storage Company, our affiliate. During 2006 and 2005, we received $17 million and $64 million in dividends from Bear Creek.

Summarized financial information for our proportionate share of our unconsolidated affiliate as of and for the years ended December 31 is presented as follows.


	2006		2005		2004
	(In millions)
Operating results data:
Operating revenues	$	20	$	18	$	18
Operating expenses		7		7		7
Income from continuing operations and net income		15		14		13


	2006		2005
	(In millions)
Financial position data:
Current assets	$	38	$	40
Non-current assets		60		63
Current liabilities		—		—
Non-current liabilities		—		2
Equity in net assets		98		101

Transactions with Affiliates

Cash Management Program. We participate in El Paso’s cash management program which matches short-term cash surpluses and needs of participating affiliates, thus minimizing total borrowings from outside sources. We have historically provided cash to El Paso in exchange for an affiliated note receivable that is due upon demand. However, we do not anticipate settlement within the next twelve months and therefore, classified this receivable as non-current on our balance sheets. At December 31, 2006 and 2005, we had note receivables from El Paso and other affiliates of $651 million and $697 million. The interest rate at December 31, 2006 and 2005, was 5.3% and 5.0%.

Notes Receivable. At December 31, 2006 and 2005, we had non-interest bearing notes receivable of $336 million from an El Paso affiliate. In addition, we had an $86 million and $65 million variable interest note receivable from El Paso at December 31, 2006 and 2005. The interest rate at December 31, 2006 and 2005 was 5.3% and 5.0%. We classified these notes as non-current on our balance sheets.

Accounts Receivable Sales Program. During the third quarter of 2006, we entered into agreements to sell certain accounts receivable to a QSPE under SFAS No. 140. As of December 31, 2006, we sold approximately $70 million of receivables, net of an allowance of approximately $1 million, received cash of approximately $34 million, received subordinated beneficial interests of approximately $35 million and recognized a loss of approximately $1 million. In conjunction with the sale, the QSPE also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $35 million at December 31, 2006. Prior to its redemption, we reflect the subordinated beneficial interest in receivables sold as accounts receivable — affiliates on our balance sheet. We reflect accounts receivable sold under this program and the related redemption of the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under the agreements, we earn a fee for servicing the accounts receivable and performing all administrative duties for the QSPE, which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the period ended December 31, 2006.

Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. We had income taxes payable of $53 million and $16 million at December 31, 2006 and 2005. The majority of these balances will become payable to El Paso. See Note 1 for a discussion of our tax accrual policy.

Other Affiliate Balances. The following table shows other balances with our affiliates arising in the ordinary course of business at December 31:


	2006		2005
	(In millions)
Accounts receivable — other	$	—	$	11
Contractual deposits		8		7
Other non-current liabilities		1		1

Affiliate Revenues and Expenses. We transport gas for El Paso Marketing L.P. (EPM) in the normal course of our business. Services provided to EPM are based on the same terms as non-affiliates.

El Paso bills us directly for certain general and administrative costs and allocates a portion of its general and administrative costs to us. In addition to allocations from El Paso, we allocate costs to our pipeline affiliates for their proportionate share of our pipeline services. The allocations from El Paso and the allocations to our affiliates are based on the estimated level of effort devoted to our operations and the relative size of our and their EBIT, gross property and payroll.

We store natural gas in an affiliated storage facility and utilize the pipeline system of an affiliate to transport some of our natural gas. 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:


	2006		2005		2004
	(In millions)
Revenues from affiliates	$	22	$	25	$	21
Operation and maintenance expense from affiliates		56		70		67
Reimbursement of operating expenses charged to affiliates		79		79		69

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

As previously reported in our Current Report on Form 8-K dated April 18, 2006, as amended on May 8, 2006, we appointed Ernst & Young LLP as our independent registered public accounting firm for the fiscal year ending December 31, 2006 and dismissed PricewaterhouseCoopers LLP. During the fiscal years ended December 31, 2006 and 2005, there were no disagreements with our former accountant or reportable events as defined in Item 304(a)(1)(iv) and Item 304(a)(1)(v) of Regulation S-K.

ITEM 9A. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

As of December 31, 2006, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer, as to the effectiveness, design and operation of our disclosure controls and procedures, as defined by the Securities Exchange Act of 1934, as amended. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our President and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all error 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 our company have been detectedBased on the result of this evaluation, our President and Chief Financial Officer concluded that our disclosure controls and procedures are effective at December 31, 2006.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the fourth quarter 2006.

ITEM 9B. OTHER INFORMATION

None.

PART III

Item 10, “Directors, Executive Officers and Corporate Governance;” Item 11, “Executive Compensation;” Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters;” and Item 13, “Certain Relationships and Related Transactions, and Director Independence” have been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees

The audit fees for the years ended December 31, 2006 and 2005, of $678,000 and $810,000 were for professional services rendered by Ernst & Young LLP and PricewaterhouseCoopers LLP, respectively, for the audits of the consolidated financial statements of Tennessee Gas Pipeline Company.

All Other Fees

No other audit-related, tax or other services were provided by our independent registered public accounting firms for the years ended December 31, 2006 and 2005.

Policy for Approval of Audit and Non-Audit Fees

We are an indirect wholly owned subsidiary of El Paso and do not have a separate audit committee. El Paso’s Audit Committee has adopted a pre-approval policy for audit and non-audit services. For a description of El Paso’s pre-approval policies for audit and non-audit related services, see El Paso Corporation’s proxy statement for its 2007 Annual Meeting of Stockholders.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(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:


	Page
Reports of Independent Registered Public Accounting Firms		16
Consolidated Statements of Income		18
Consolidated Balance Sheets		19
Consolidated Statements of Cash Flows		20
Consolidated Statements of Stockholder’s Equity		21
Notes to Consolidated Financial Statements		22

2. Financial statement schedules

Schedule II — Valuation and Qualifying Accounts

All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.

3. Exhibits

The Exhibit Index, which follows the signature page to this report and is hereby incorporated herein by reference, sets forth a list of those exhibits filed herewith, and includes and identifies contracts or arrangements required to be filed as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

Undertaking

We hereby undertake, pursuant to Regulation S-K, Item 601(b), paragraph (4)(iii), to furnish to the U.S. SEC upon request all constituent instruments defining the rights of holders of our debt and our consolidated subsidiaries not filed as an exhibit hereto 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.

TENNESSEE GAS PIPELINE COMPANY

EXHIBIT INDEX

December 31, 2006

Each exhibit identified below is a part of this Report. Exhibits filed with this Report are designated by “*”. All exhibits not so designated are incorporated herein by reference to a prior filing as indicated.


Exhibit
Number		Description
3.A		Restated Certificate of Incorporation dated May 11, 1999 (Exhibit 3.A to our 2004 Form 10-K).

3.B		By-laws dated as of June 24, 2002 (Exhibit 3.B to our 2002 Form 10-K).

4.A		Indenture dated as of March 4, 1997, between Tennessee Gas Pipeline Company and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (Exhibit 4.A to our 2005 Form 10-K).

4.A.1		First Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (Exhibit 4.A.1 to our 2005 Form 10-K).

4.A.2		Second Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (Exhibit 4.A.2 to our 2005 Form 10-K).

4.A.3		Third Supplemental Indenture dated as of March 13, 1997, between Tennessee Gas Pipeline Company and the Trustee (Exhibit 4.A.3 to our 2005 Form 10-K).

4.A.4		Fourth Supplemental Indenture dated as of October 9, 1998, between Tennessee Gas Pipeline Company and the Trustee (Exhibit 4.A.4 to our 2005 Form 10-K).

4.A.5		Fifth Supplemental Indenture dated June 10, 2002, between Tennessee Gas Pipeline Company and the Trustee (Exhibit 4.1 to our Form 8-K filed June 10, 2002).

10.A		Amended and Restated Credit Agreement dated as of July 31, 2006, among El Paso Corporation, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent. (Exhibit 10.A to our Form 8-K filed August 2, 2006).

*10.A.1		Amendment No. 1 dated as of January 19, 2007 to the Amended and Restated Credit Agreement dated as of July 31, 2006 among El Paso Corporation, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto, and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent.

10.B		Amended and Restated Security Agreement dated as of July 31, 2006, among El Paso Corporation, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Guarantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank. (Exhibit 10.B to our Form 8-K filed August 2, 2006).

10.C		First Tier Receivables Sale Agreement dated August 31, 2006, between Tennessee Gas Pipeline Company and TGP Finance Company, L.L.C. (Exhibit 10.A to our Current Report on Form 8-K, filed with the SEC on September 8, 2006).

10.D		Second Tier Receivables Sale Agreement dated August 31, 2006, between TGP Finance Company, L.L.C. and TGP Funding Company, L.L.C. (Exhibit 10.B to our Form 8-K filed September 8, 2006).

10.E		Receivables Purchase Agreement dated August 31, 2006, among TGP Funding Company, L.L.C., as Seller, Tennessee Gas Pipeline Company, as Servicer, Starbird Funding Corporation, as the initial Conduit Investor and Committed Investor, the other investors from time to time parties thereto, BNP Paribas, New York Branch, as the initial Managing Agent, the other Managing Agents from time to time parties thereto, and BNP Paribas, New York Branch, as Program Agent (Exhibit 10.C to our Form 8-K filed September 8, 2006).

*10.E.1		Amendment No 1., dated as of December 1, 2006, to the Receivables Purchase Agreement dated as of August 31, 2006, among TGP Funding Company, L.L.C., Tennessee Gas Pipeline Company, as initial Servicer, Starbird Funding Corporation and the other funding entities from time to time party hereto as Investors, BNP Paribas, New York Branch, and the other financial institutions from time to time party thereto as Managing Agents, and BNP Paribas, New York Branch, as Program Agent.

21		Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

*31.A		Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

Percent of Total

Description

Revenues in 2006

Reservation

Reservation revenues are from customers (referred to as firm customers) that reserve capacity on our pipeline system and storage facility. These firm customers are obligated to pay a monthly reservation or demand charge, regardless of the amount of natural gas they transport or store, for the term of their contracts.

Usage
and Other

Usage revenues are from both firm customers and interruptible customers (those without reserved capacity) who pay charges and provide fuel in-kind based on the volume of gas actually transported, stored, injected or withdrawn.


									Accumulated
					Additional				other		Total
	Common stock				paid-in		Retained		comprehensive		stockholder’s
	Shares		Amount		capital		earnings		income		equity
January 1, 2004		208	$	—	$	2,205	$	647	$	—	$	2,852
Net income								94				94

Allocated tax benefit of El Paso equity plans						1						1

December 31, 2004		208		—		2,206		741		—		2,947
Net income								79				79
Allocated tax benefit of El Paso equity plans						1						1

December 31, 2005		208		—		2,207		820		—		3,027
Net income								127				127
Adoption of SFAS No. 158, net of income taxes of $2										3		3

December 31, 2006		208	$	—	$	2,207	$	947	$	3	$	3,157


	Quarters Ended
	March 31		June 30		September 30		December 31			Total
	(In millions)
2006
Operating revenues	$	230	$	194	$	182	$	187		$	793
Operating income		101		62		40		56			259
Net income		52		29		17		29			127

2005
Operating revenues	$	205	$	182	$	178	$	192		$	757
Operating income		77		45		49		46			217
Income before cumulative effect of accounting change		32		13		17		20			82
Cumulative effect of accounting change, net of income taxes		—		—		—		(3	)		(3	)
Net income		32		13		17		17			79


	Balance at		Charged to						Charged to			Balance
	Beginning		Costs and						Other			at End
Description	of Period		Expenses			Deductions			Accounts			of Period
2006
Allowance for doubtful accounts	$	1	$	—		$	—		$	(1	)	$	—
Environmental reserves		32		(12	)⁽¹⁾		(5	)⁽²⁾		—			15

2005
Allowance for doubtful accounts	$	3	$	(1	)	$	(1	)	$	—		$	1
Environmental reserves		42		(5	)⁽¹⁾		(5	)⁽²⁾		—			32

2004
Allowance for doubtful accounts	$	4	$	—		$	—		$	(1	)	$	3
Legal reserves		—		—			(1	)		1			—
Environmental reserves		46		—			(4	)⁽²⁾		—			42
Regulatory reserves		1		—			(1	)		—			—


⁽¹⁾		Represents a reduction in the estimated costs to complete our internal remediation projects.

⁽²⁾		Primarily payments made for environmental remediation activities.


		TENNESSEE GAS PIPELINE COMPANY

		By:		/s/ JAMES C. YARDLEY

				James C. Yardley
				Chairman of the Board and President


Signature	Title	Date

/s/ JAMES C. YARDLEY James C. Yardley	Chairman of the Board, President and Director (Principal Executive Officer)	February 28, 2007
/s/ JOHN R. SULT John R. Sult	Senior Vice President, Chief Financial Officer and Controller (Principal Accounting and Financial Officer)	February 28, 2007
/s/ DANIEL B. MARTIN Daniel B. Martin	Senior Vice President and Director	February 28, 2007


EL PASO CORPORATION
By:	/s/ John J. Hopper
	Name:	John J. Hopper
	Title:	Vice President and Treasurer


COLORADO INTERSTATE GAS COMPANY
By:	/s/ John J. Hopper
	Name:	John J. Hopper
	Title:	Vice President and Treasurer


EL PASO NATURAL GAS COMPANY
By:	/s/ John J. Hopper
	Name:	John J. Hopper
	Title:	Vice President and Treasurer


	JPMORGAN CHASE BANK, N.A., as a Revolving Lender and Deposit Lender
	By:
		Name:
		Title:


	CITICORP NORTH AMERICA, INC., as a Revolving Lender and Deposit Lender
	By:
		Name:
		Title:


	[Lender], as a [Revolving Lender] [and] [Deposit Lender]
	By:
		Name:
		Title:


		TGP FUNDING COMPANY, L.L.C.

				By TGP Finance Company, L.L.C., its Manager

		By:		/s/ John J. Hopper

				Name: John J. Hopper
				Title: Vice President

		TENNESSEE GAS PIPELINE COMPANY, as Servicer

		By:		/s/ John J. Hopper

				Name: John J. Hopper
				Title: Vice President


		By:		/s/ Sean Reddington

				Name: Sean Reddington
				Title: Managing Director

		By:		/s/ Michael Gonik

				Name: Michael Gonik
				Title: Director


STARBIRD FUNDING CORPORATION,
as a Conduit Purchaser

By:		/s/ Franklin P. Collazo

		Name: Franklin P. Collazo
		Title: Secretary


BNP PARIBAS, acting through its New York Branch,
as Committed Investor

By:		/s/ Sean Reddington

		Name: Sean Reddington
		Title: Managing Director

By:		/s/ Michael Gonik

		Name: Michael Gonik
		Title: Director



	/s/ James C. Yardley
	James C. Yardley
	Chairman of the Board and President (Principal Executive Officer) Tennessee Gas Pipeline Company



	/s/ John R. Sult
	John R. Sult
	Senior Vice President, Chief Financial Officer and Controller (Principal Accounting and Financial Officer) Tennessee Gas Pipeline Company