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, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

     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 26, 2008: 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

TABLE OF CONTENTS

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

     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.

Overview and Strategy

     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 as discussed below.

     Our pipeline system and storage facilities operate under tariffs approved by the Federal Energy Regulatory Commission (FERC) that establish rates, cost recovery mechanisms and other terms and conditions of services 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 enhance the value of our transportation and storage business by:

     Pipeline System. Our pipeline system consists of approximately 13,700 miles of pipeline with a design capacity of approximately 7 Bcf/d. During 2007, 2006 and 2005, average throughput was 4,880 BBtu/d, 4,534 BBtu/d and 4,443 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, 2007, we had the following FERC approved pipeline expansion project on our system:

     We also have other expansion projects further discussed in Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations.

     Storage Facilities. We have approximately 92 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 58 Bcf of working storage capacity. Bear Creek’s working storage capacity is committed equally to SNG and us under long-term contracts.

     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 potential benefit 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 natural gas transportation 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. We have discounted a substantial portion of these rates to remain competitive.

     The following table details information related to our pipeline system, including the customers, contracts and the competition we face as of December 31, 2007. Firm customers reserve capacity on our pipeline system and storage facilities and 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. Interruptible customers are customers without reserved capacity that pay usage charges based on the volume of gas they request to transport, store, inject or withdraw.

     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 and other terms and conditions of service to our customers. Generally, the FERC’s authority extends to:

     Our interstate pipeline system is also subject to federal, state and local safety and environmental statutes and regulations of the U.S. Department of Transportation and the U.S. Department of Interior. We have ongoing inspection programs designed to keep our facilities in compliance with pipeline safety and environmental requirements and we believe that our system is in material compliance with the applicable regulations.

     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.

     As of February 27, 2008, we had approximately 1,600 full-time employees, none of whom are subject to a collective bargaining arrangement.

     This report contains forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. These forward-looking statements are based on assumptions or beliefs that we believe to be reasonable; however, assumed facts almost always vary from actual results, and differences between assumed facts and actual results can be material, depending upon the circumstances. Where, based on assumptions, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the stated expectation or belief will occur, be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. All of our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany such forward-looking 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.

     Our business is the transportation and storage of natural gas for third parties. The results of our transportation and storage operations are impacted by the volumes of natural gas we transport or store and the prices we are able to charge for doing so. The volume 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 also beyond our control, may unfavorably impact our ability to maintain or increase current throughput, or to remarket unsubscribed capacity on our pipeline system.

     Our revenues are generated under transportation and storage contracts which expire periodically and must be renegotiated, extended or replaced. If we are unable to extend or replace these contracts when they expire or renegotiate contract terms as favorable as the existing contracts, we could suffer a material reduction in our revenues, earnings and cash flows. Currently, a substantial portion of our revenues are under contracts that are discounted at rates below the maximum rates allowed under our tariff. For additional information on the expiration of our contract portfolio, see Part II, Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations. In particular, our ability to extend and replace contracts could be adversely affected by factors we cannot control, including:

     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 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 natural 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 reserves available for transmission and storage through our system.

     We retain a fixed percentage of natural gas transported as provided in our tariff. 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 impact the value of under or over recoveries of retained natural gas, 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 activities 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:

     Our business is regulated by the FERC, the U.S. Department of Transportation, the U.S. Department of Interior and various state and local regulatory agencies whose actions 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 and sets authorized rates of return. The FERC uses a discounted cash flow model that incorporates the use of proxy groups to develop a range of reasonable returns earned on equity interests in companies with corresponding risks. The FERC then assigns a rate of return on equity within that range to reflect specific risks of that pipeline when compared to the proxy group companies. The FERC had been using a proxy group of companies that included local distribution companies that are not faced with as much competition or risk as interstate pipelines. The inclusion of these lower risk companies could have created downward pressure on tariff rates when subjected to review by the FERC in future rate proceedings. Recently, the U.S. Court of Appeals for the DC Circuit issued a decision that would require the FERC, if it utilizes lower risk companies in the proxy group, to make upward adjustments to the return on equity to compensate for their lower level of risk. Pursuant to the FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. A successful complaint or protest against our rates could have an adverse impact on our revenues. In addition, in July 2007, the FERC issued a proposed policy statement addressing the issue of the proxy groups it will use to decide the return on equity of natural gas pipelines. The proposed policy statement describes the FERC’s intention to allow the use of master limited partnerships in proxy groups, which we and other pipelines have advocated. However, the FERC also proposed certain restrictions that would reduce the overall benefit that pipelines would receive by use of master limited partnerships in the proxy group.

     Also, 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.

     Our operations are subject to various environmental laws and regulations regarding 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 or clean up of contaminated properties (some of which have been designated as Superfund sites by the 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. Although we believe we have established appropriate reserves for our environmental liabilities, it is not possible for us to estimate the exact amount and timing of all future expenditures related to environmental matters and we could be required to set aside additional amounts which could significantly impact our future consolidated results of operations, cash flows, or financial position. See Part II, Item 8, Financial Statements and Supplementary Data, Note 8.

     In estimating our environmental liabilities, we face uncertainties that include:

     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 and various United States federal legislative proposals which have been made over the last several years. It is difficult to predict the timing of enactment of any federal legislation, as well as the ultimate legislation that will be enacted. However, components of the legislation that have been proposed in the past could negatively impact our operations and financial results, including whether any of our facilities are designated as the point of regulation for GHG emissions, whether the federal legislation will expressly preempt the potentially conflicting state GHG legislation and how inter-fuel issues will be handled, including how allowances are granted and whether caps will be imposed on GHG charges.

     Legislation and regulation are also in various stages of proposal, enactment, and implementation in many of the states in which we operate. This includes various initiatives of individual and coalitions of states, including states in the northeastern portion of the United States that are members of the Regional Greenhouse Gas Initiative.

     Additionally, various governmental entities and environmental groups have filed lawsuits seeking to force the federal government to regulate GHG emissions and individual companies to reduce the GHG emissions from their operations. These and other suits may also result in decisions by federal agencies, state courts and other agencies that impact our operations and our ability to obtain certifications and permits to construct future projects.

     These legislative, regulatory, and judicial actions could also result in changes to our operations and to the consumption and demand for natural gas. Changes to our operations could include increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities, (iii) construct new facilities, (iv) acquire allowances to authorize our GHG emissions, (v) pay any taxes related to our GHG emissions and (vi) administer and manage a GHG emissions program.

     While we may be able to include some or all of any costs in the rates charged by us, such recovery of costs is uncertain and may depend on events beyond our control including the outcome of future rate proceedings before the FERC and the provisions of any final legislation.

     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 (such as hurricanes and flooding), terrorist activity or acts of aggression, and other hazards. Each of these risks could result in damage to or destruction of our facilities or damages or injuries to persons and property causing us to suffer substantial losses.

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

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

     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. If we are unable to retain and recruit employees such as engineers and other technical personnel, our business could be negatively impacted.

     We, El Paso, and its subsidiaries are subject to the risks arising from adverse changes in general domestic economic conditions including recession or economic slowdown. Recently, the direction and relative strength of the U.S. economy has been increasingly uncertain due to softness in the housing markets, rising oil prices, and difficulties in the financial services sector. If economic growth in the United States is slowed, demand growth from consumers for natural gas transported by us may decrease which could impact our planned growth capital. Additionally, our access to capital could be impeded. Any of these events, which are beyond our control, could negatively impact our business, results of operations, financial condition, and liquidity.

     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 included herein or incorporated by reference into this report.

     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 Ba3 by Moody’s Investor Service, BB- by Standard & Poor’s and BB+ by Fitch Ratings. The ratings assigned to our senior unsecured indebtedness are currently investment grade, rated Baa3 by Moody’s Investor Service, BB by Standard & Poor’s and investment grade with a BBB- rating by Fitch Ratings. We and El Paso are (i) on a positive outlook with Moody’s Investor Service and Standard & Poor’s and (ii) on a stable outlook with Fitch Ratings. 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 note 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 payables. Our inability to recover any affiliated receivables owed to us could adversely affect our financial position. For a further discussion of these matters, see Part II, Item 8, Financial Statements and Supplementary Data, Note 11.

     Under El Paso’s $1.5 billion credit agreement, our common stock and the common stock of one of El Paso’s other subsidiaries are pledged as collateral. As a result, our ownership is subject to change if there is a 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. For additional information concerning El Paso’s credit facility, see Part II, Item 8, Financial Statements and Supplementary Data, Note 7.

     We are a party to El Paso’s $1.5 billion credit agreement. We are only liable, however, for our borrowings under the credit agreement, which were zero at December 31, 2007. Under the credit agreement, a default by El Paso, or any other borrower could result in the acceleration of repayment of all outstanding borrowings, including the borrowings of any non-defaulting party. The acceleration of repayments of borrowings, if any, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.

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

     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.

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

     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 business, 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 business. We believe that our properties are adequate and suitable for the conduct of our business in the future.

     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.

     Information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

     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 2007 or 2006.

     Information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

     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. These risks and uncertainties are discussed further in Part I, Item 1A, Risk Factors.

     Our business primarily consists of interstate transportation and storage of natural gas. Each of these businesses faces varying degrees of competition from other existing 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 services consist of the following types.

     The FERC regulates the rates we can charge our customers. These rates are generally a function of the cost of providing services to our customers, including a reasonable return on our invested capital. 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, declines in the creditworthiness of our customers and weather. We also experience volatility in our financial results when the amounts of natural gas used in our operations differ 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 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.

     We continue to manage our recontracting process to limit the risk of significant impacts on our revenues from expiring contracts. 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. The weighted average remaining contract term for active contracts is approximately four years as of December 31, 2007.

     Listed below are the expiration of our contract portfolio and the associated revenue expirations for our firm transportation contracts as of December 31, 2007, including those with terms beginning in 2008 or later.

     Our management uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business. We believe EBIT is useful to 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, (iii) interest and debt expense, and (iv) affiliated interest income. We exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods. EBIT may not be comparable to measurements used by other companies. Additionally, EBIT should be considered in conjunction with net income and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our EBIT to net income, our throughput volumes and an analysis and discussion of our results for the year ended December 31, 2007 compared with 2006.

     Services Revenues. During 2007, we sold additional capacity in the south central region of our system and transported higher volumes under firm transportation contracts.

     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. The financial impact of gas not needed for operations is influenced by factors such as system throughput, facility enhancements and the ability to operate the system efficiently. Gas not needed for operations results in revenues to us, which we recognize when the volumes are retained. During the year ended December 31, 2007 our EBIT was favorably impacted by higher volumes of gas not used in our operations compared to 2006.

     Contract Settlement. In 2007, we received $10 million to settle a bankruptcy claim against USGen New England, Inc.

     Projects Placed in Service in 2007 and 2006. In December 2006, our Northeast ConneXion—NY/NJ expansion project was placed into service resulting in an increase in our operating revenues. This increase was partially offset by depreciation of the new facilities. In July 2007, we completed the Louisiana Deepwater Link project which has increased gas supply attached to our system by up to 900 MMcf/d. In September 2007, we completed the Triple—T Extension project which also increased gas supply attached to our system. Revenues for these projects are based on throughput levels as natural gas reserves are developed. In November 2007, our Northeast ConneXion—New England expansion project was placed into service. This project provided an additional 108 MMcf/d of capacity to meet growing demand for natural gas in the New England market area. The expansion is estimated to increase our EBIT by approximately $14 million annually beginning in 2008.

     We currently have the following projects in various stages of development:

     Operating and General and Administrative Costs. During the year ended December 31, 2007, our operating costs were higher than the same period in 2006 primarily due to increased throughput, increased reserves for non-trade accounts receivable, and higher electric compression costs at certain compressor stations.

     Gain/Loss on Long-Lived Assets. During 2007, we completed the sale of a pipeline lateral for approximately $35 million and recorded a pretax gain on the sale of approximately $7 million in operating and maintenance expense on our income statement. During 2007, we also recorded a loss of $8 million related to a pipeline asset which was purchased to repair hurricane damage and not subsequently utilized.

     Allowance for Funds Used During Construction (AFUDC). AFUDC was higher during 2007 primarily due to capitalized hurricane expenditures.

     Our effective tax rate of 37 percent for the years ended December 31, 2007 and 2006 was higher than the statutory rate of 35 percent due to the effect of state income taxes. For a reconciliation of the statutory rate to the effective tax rates, see Item 8, Financial Statements and Supplementary Data, Note 3.

     Liquidity Overview. Our liquidity needs are provided by cash flows from operating activities. In addition, we participate in El Paso’s cash management program and depending on whether we have short-term cash surpluses or requirements, we either advance cash to El Paso or El Paso advances cash to us in exchange for an affiliated note receivable or payable that is due upon demand. We have historically advanced cash to El Paso, which we reflect in investing activities in our statement of cash flows. At December 31, 2007, we had notes receivable from El Paso and other affiliates of approximately $1 billion. We do not intend to settle these notes within the next twelve months and therefore have classified them as non-current on our balance sheet. In 2007, we settled with El Paso certain tax attributes previously reflected as deferred income taxes in our financial statements for $77 million. This settlement is reflected as operating activities in our statement of cash flows. See Item 8, Financial Statements and Supplementary Data, Note 11, for a further discussion of El Paso’s cash management program and our other affiliate notes receivable.

     In addition to the cash management program, in November 2007, El Paso entered into a $1.5 billion credit agreement, which amended and restated its existing $1.75 billion credit agreement. We continue to be an eligible borrower under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2007, El Paso had approximately $0.3 billion of letters of credit issued and $0.4 billion of debt outstanding under this facility, none of which was issued or borrowed by us. For a further discussion of this credit agreement, see Item 8, Financial Statements and Supplementary Data, Note 7.

     We believe that cash flows from operating activities combined with amounts available to us under El Paso’s cash management program and its credit agreement, if necessary, will be adequate to meet our capital requirements and our existing operating needs.

     Credit Profile. In March 2007, Moody’s Investor Services upgraded our senior unsecured debt rating to an investment grade rating of Baa3 and upgraded El Paso’s senior unsecured debt rating to Ba3 while maintaining a positive outlook. Additionally, in March 2007, (i) Standard and Poor’s upgraded our senior unsecured debt ratings to BB and upgraded El Paso’s senior unsecured debt rating to BB- maintaining a positive outlook and (ii) Fitch Ratings initiated coverage on us and assigned an investment grade rating of BBB- on our senior unsecured debt and a rating of BB+ on El Paso’s senior unsecured debt. Our ratings affect the cost of capital that is available in third party credit markets, generally allowing for a lower cost of capital relative to non-investment grade companies.

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

     Under our current plan, we have budgeted to spend approximately $180 million in 2008 for capital expenditures, net of insurance proceeds, primarily to maintain and improve the integrity of our pipeline, to comply with regulations and to ensure the safe and reliable delivery of natural gas to our customers. In addition, we have budgeted to spend approximately $130 million in 2008 to expand the capacity and services of our pipeline system. We expect to fund our capital expenditures through a combination of internally generated funds and, if necessary, repayments by El Paso of amounts we advanced under its cash management program.

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

     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.

     Our primary market risk is exposure to changing interest rates. At December 31, 2007, we had notes receivable from El Paso and other affiliates of approximately $700 million, with variable interest rates of 6.5% that are due upon demand. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of these notes receivable approximate their carrying value due to the market-based nature of its interest rate. The table below shows the carrying value and related weighted average effective interest rates of our non-affiliated interest bearing securities by expected maturity dates and the fair value of these securities. At December 31, 2007, 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.

     We are also exposed to risks associated with changes in natural gas prices on natural gas that we are allowed to retain, net of gas used in operations. 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 these purposes. Pricing volatility may also impact the value of under or over recoveries of retained natural gas, imbalances and system encroachments. We sell retained gas in excess of gas used in operations 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, which include fixed price and variable price contracts within certain price constraints, to manage this risk.

     Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined by SEC rules adopted under the Securities Exchange Act of 1934, as amended. Our internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. It consists of policies and procedures that:

Under the supervision and with the participation of management, including the President and Chief Financial Officer, we made an assessment of the effectiveness of our internal control over financial reporting as of December 31, 2007. In making this assessment, we used the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on our evaluation, we concluded that our internal control over financial reporting was effective as of December 31, 2007.

The Board of Directors and Stockholder of Tennessee Gas Pipeline Company:

We have audited the accompanying consolidated balance sheets of Tennessee Gas Pipeline Company (the Company) as of December 31, 2007 and 2006, and the related consolidated statements of income, stockholder’s equity, and cash flows for each of the two years in the period ended December 31, 2007. Our audits also included the financial statement schedule listed in the Index at Item 15(a) for each of the two years in the period ended December 31, 2007. 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 audits.

We conducted our audits 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 audits 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 audits provide 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, 2007 and 2006, and the consolidated results of its operations and its cash flows for each of the two years in the period ended December 31, 2007, 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, 2007, the Company adopted the provisions of Financial Accounting Standards Board Interpretation No. 48, Accounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109; effective December 31, 2006, the Company adopted the recognition provisions of Statement of Financial Accounting Standards No. 158, Employer’s Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106, and 132 (R); and effective January 1, 2006, the Company adopted the Federal Energy Regulatory Commission’s accounting release related to pipeline assessment costs.

Houston, Texas
February 25, 2008

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

In our opinion, the consolidated statements of income, stockholder’s equity and cash flows for the year ended December 31, 2005 listed in the Index appearing under Item 15(a) (1), present fairly, in all material respects, the results of operations and cash flows of Tennessee Gas Pipeline Company and its subsidiaries (the “Company”) for the year 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 the year 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 audit. We conducted our audit 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 audit provides a reasonable basis for our opinion.

Houston, Texas
February 28, 2006

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 consolidated financial statements are prepared in accordance with U.S. generally accepted accounting principles (GAAP) and include the accounts of all majority owned and controlled subsidiaries after the elimination of intercompany accounts and transactions.

     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.

     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.

     Our natural gas pipeline 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 follow 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 costs included in, or expected to be included in, future rates.

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

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

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

     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 contractual amount delivered or received. We value these imbalances due to or from shippers and operators utilizing 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. We classify all imbalances as current as we expect to settle them within a year.

     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 these costs based on a FERC accounting release. During the year ended December 31, 2007 and 2006, we expensed approximately $8 million and $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 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 properties not subject to regulation by the FERC, 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, 2007 and 2006, we had $197 million and $237 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 debt and equity 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, 2007, 2006 and 2005, were $6 million, $5 million and $2 million. These debt amounts are included as a reduction to interest and debt expense on 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 (exclusive of any tax related impacts) during the years ended December 31, 2007, 2006 and 2005, were $12 million, $8 million and $3 million. These equity amounts are included as other non-operating income on our income statement.

     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) the long-lived asset’s ability to generate future cash flows on an undiscounted basis or (ii) the fair value of the investment in an 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 the asset 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 sale, 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.

     Our revenues are primarily generated from natural gas 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 used in operations when the volumes are retained. 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. We record liabilities at their undiscounted amounts on our balance sheet as other current and long-term liabilities when 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 charge in operation and maintenance 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 low end of the range is accrued.

     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.

     Effective January 1, 2007, we adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109. FIN No. 48 clarifies SFAS No. 109, Accounting for Income Taxes, and requires us to evaluate our tax positions for all jurisdictions and for 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. a greater than 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 effective settlement. For a further discussion of the impact of the adoption of FIN No. 48, see Note 3.

     We account for our asset retirement obligations in accordance with SFAS No. 143, Accounting for Asset Retirement Obligations and FIN No. 47, Accounting for Conditional Asset Retirement Obligations. We record a liability for legal obligations associated with the replacement, removal or 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 and amortization expense in our income statement. We have the ability to recover certain of these costs from our customers and have recorded an asset (rather than expense) associated with the depreciation of the property, plant and equipment and accretion of the liabilities described above.

     We maintain a postretirement benefit plan covering certain of our former employees. This plan requires us to make contributions to fund the benefits to be paid out under the plan. These contributions are invested until the benefits are paid out to plan participants. We record net benefit cost related to this plan in our income statement. This net benefit cost is a function of many factors including benefits earned during the year by plan participants (which is a function of the level of benefits provided under the plan, actuarial assumptions and the passage of time), expected returns on plan assets and amortization of certain deferred gains and losses. For a further discussion of our policies with respect to our postretirement plan, see Note 9.

     We use the recognition 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) to account for our plan. Under SFAS No. 158, we record an asset or liability for our postretirement benefit plan based on its overfunded or underfunded status. Any deferred amounts related to unrealized gains and losses or changes in

actuarial assumptions are recorded either as a regulatory asset or liability. For a further discussion of our application of SFAS No. 158, see Note 9.

     As of December 31, 2007, the following accounting standards had not yet been adopted by us.

     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 adopt the provisions of this standard for our financial assets and liabilities effective January 1, 2008. Adopting the standard is not expected to have a material impact on our financial statements. The FASB provided a one year deferral of the adoption of SFAS No. 157 for certain non-financial assets and liabilities. We have elected to defer the adoption of the standard for certain of our non-financial assets and liabilities, and are currently evaluating the impact, if any, that the deferred provisions of the standard will have on our financial statements.

     Measurement Date of Postretirement Benefits. In December 2006, we adopted the recognition provisions of SFAS No. 158. Beginning in 2008, this standard will also require us to change the measurement date of our postretirement benefit plan from September 30, the date we currently use, to December 31. Adoption of the measurement date provisions of this standard is not expected to have a material impact on our financial statements.

     Fair Value Option. In February 2007, the FASB issued SFAS No. 159, Fair Value Option for Financial Assets and Financial Liabilities — including an Amendment to FASB Statement No. 115, Accounting for Certain Investments in Debt and Equity Securities, which permits entities to choose to measure many financial instruments and certain other items at fair value. We will adopt the provisions of this standard effective January 1, 2008, and do not anticipate that it will have a material impact on our financial statements.

     Business Combinations. In December 2007, the FASB issued SFAS No. 141(R), Business Combinations, which provides revised guidance on the accounting for acquisitions of businesses. This standard changes the current guidance to require that all acquired assets, liabilities, minority interest and certain contingencies be measured at fair value, and certain other acquisition-related costs be expensed rather than capitalized. SFAS No. 141(R) will apply to acquisitions that are effective after December 31, 2008, and application of the standard to acquisitions prior to that date is not permitted.

     Noncontrolling Interests. In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements, which provides guidance on the presentation of minority interests in the financial statements. This standard requires that minority interest be presented as a component of equity rather than as a “mezzanine” item between liabilities and equity, and also requires that minority interest be presented as a separate caption in the income statement. This standard also requires all transactions with minority interest holders, including the issuance and repurchase of minority interests, be accounted for as equity transactions unless a change in control of the subsidiary occurs. SFAS No. 160 is effective for fiscal years beginning after December 15, 2008, and we are evaluating the impact that this standard will have on our financial statements.

     During 2007, we completed the sale of a pipeline lateral for approximately $35 million and recorded a pretax gain on the sale of approximately $7 million. During 2007, we also recorded a loss of $8 million related to a pipeline asset which was purchased to repair hurricane damage and not subsequently utilized. We record gains and losses on long-lived assets in operation and maintenance expense in our income statement.

     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:

     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:

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

     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, 2007:

     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.

     Unrecognized Tax Benefits (Liabilities) for Uncertain Tax Matters (FIN No. 48). 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. With a few exceptions, we and El Paso are no longer subject to U.S. federal, state and local income tax examinations by tax authorities for years before 1999. Additionally, the Internal Revenue Service has completed an examination of El Paso’s U.S. income tax returns for 2003 and 2004, with a tentative settlement at the appellate level for all issues. We do not anticipate the settlement of these matters to have an impact on our unrecognized tax benefits. For our remaining open tax years, our unrecognized tax benefits (liabilities for uncertain tax matters) could increase or decrease our income tax expense and our effective income tax rates as these matters are finalized, although we are currently unable to estimate the range of potential impacts these matters could have on our financial statements.

     Upon the adoption of FIN No. 48, and a related amendment to our tax sharing agreement with El Paso, we recorded a reduction of $15 million to the January 1, 2007 balance of retained earnings. As of January 1, 2007, we had unrecognized tax benefits of $17 million (excluding interest and penalties of $6 million) which had not changed as of December 31, 2007. These unrecognized tax benefits (net of federal tax benefits) would favorably affect our income tax expense and our effective income tax rate if recognized in future periods. While the amount of our unrecognized tax benefits could change in the next twelve months, we do not expect this change to have a significant impact on our results of operations or financial position.

     We recognize interest and penalties related to unrecognized tax benefits in income tax expense on our income statement. As of January 1, 2007 and December 31, 2007, we had liabilities for interest and penalties related to our unrecognized tax benefits of approximately $6 million. During 2007, we accrued $1 million of interest and paid $1 million related to a settlement with a taxing authority.

     At December 31, 2007 and 2006, 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. The fair value of our notes receivable from affiliates approximates their carrying value due to the market-based nature of their interest rate. The carrying amounts and estimated fair values of our long-term debt are based on quoted market prices for the same or similar issues and are as follows at December 31:

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

     Additional Acquisition Costs. At December 31, 2007 and 2006, additional acquisition costs assigned to utility plant was approximately $2.4 billion and accumulated depreciation was approximately $338 million and $299 million, respectively. These additional acquisition 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 $39 million, $40 million and $40 million for the years ended December 31, 2007, 2006 and 2005.

     Asset Retirement Obligations. We have legal obligations associated with the retirement of our natural gas pipeline, transmission facilities and storage wells, as well as obligations related to El Paso’s corporate headquarters building. Our legal obligations primarily involve purging and sealing the pipelines if they are abandoned. We also have obligations to remove hazardous materials associated with our natural gas transmission facilities and in our corporate headquarters if these facilities are ever demolished, replaced, or renovated. We continue to evaluate our asset retirement obligations and future development could impact the amounts we record.

     Where we can reasonably estimate the asset retirement obligation liability, we accrue a liability based on an estimate of the timing and amount of their settlement. In estimating the fair value of the liabilities associated with our asset retirement obligations, we utilize several assumptions, including a projected inflation rate of 2.5 percent, and credit-adjusted discount rates that currently range from six to eight percent. We record changes in estimates based on the expected amount and timing of payments to settle our asset retirement obligations. In 2006, we also revised our estimates due primarily to the impacts of hurricanes Katrina and Rita. We intend on operating and maintaining our natural gas pipeline and storage system as long as supply and demand for natural gas exists, which we expect for the foreseeable future. Therefore, we believe that we cannot reasonably estimate the asset retirement obligation liability for the substantial majority of our natural gas pipeline and storage system assets because these assets have indeterminate lives.

     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:

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

     The holders of our $300 million, 7.0% debentures did not exercise their early redemption option, which expired on February 15, 2007. Accordingly, the amount is reflected as long-term debt in our balance sheet at December 31, 2007.

     Credit Facilities. In November 2007, El Paso entered into a $1.5 billion credit agreement, which amended and restated its existing $1.75 billion credit agreement. We continue to be an eligible borrower under the $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of December 31, 2007, El Paso had approximately $0.3 billion of letters of credit issued and $0.4 billion of debt outstanding under this facility, none of which was issued or borrowed by us. Our common stock and the common stock of another El Paso subsidiary are pledged as collateral under the credit agreement.

     Under El Paso’s $1.5 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), 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; and (v) potential limitations on our ability to declare and pay dividends. For the year ended December 31, 2007, we were in compliance with our debt-related covenants.

     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 have 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 October 2006, the U.S. District Judge issued an order dismissing all 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 plaintiff seeks 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 these lawsuits and claim are not currently determinable.

     In addition to the above proceedings, 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 these 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. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we had no accruals for our outstanding legal matters at December 31, 2007. It is possible that new information or future developments could require us to reassess our potential exposure related to these matters and establish our accruals accordingly.

     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, 2007, we accrued approximately $10 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 one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. Our recorded liabilities 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, 2007 to December 31, 2007 (in millions):

     For 2008, we estimate that our total remediation expenditures will be approximately $2 million, which will be expended under government directed clean-up plans.

     Polychlorinated Biphenyls (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, 2007, we had pre-collected PCB costs of approximately $149 million, which includes interest. 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. At December 31, 2007, our regulatory liability for estimated future refund obligations to our customers was approximately $143 million.

     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, 2007, 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 orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees, and other persons 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.

     Notice of Inquiry on Pipeline Fuel Retention Policies. In September 2007, the FERC issued a Notice of Inquiry regarding its policy about the in-kind recovery of fuel and lost and unaccounted for gas by natural gas pipeline companies. Under current policy, pipeline companies have options for recovering these costs. For some companies, the tariff states a fixed percentage as a non-negotiable fee-in-kind retained from the volumes tendered for shipment by each shipper. There is also a tracker approach, where the pipeline company’s tariff provides for prospective adjustments to the fuel retention rates from time-to-time, but does not include a mechanism to allow the company to reconcile past over or under-recoveries of fuel. Finally, some pipeline companies’ tariffs provide for a tracker with a true-up approach, where provisions in the companies’ tariff allow for periodic adjustments to the fuel retention rates, and also provide for a true-up of past over and under-recoveries of fuel and lost and unaccounted for gas. In this proceeding, the FERC is seeking comments on whether it should change its current policy and prescribe a uniform method for all pipeline companies to use in recovering these costs. Our tariff currently provides for a fixed percentage recovery basis. At this time, we do not know what impact this proceeding may ultimately have on us.

     Notice of Proposed Rulemaking. In October 2007, the Minerals Management Service (MMS) issued a Notice of Proposed Rulemaking for Oil and Gas and Sulphur Operations in the Outer Continental Shelf — Pipelines and Pipeline Rights-of-Way. If adopted, the proposed rules would substantially revise MMS Outer Continental Shelf (OCS) pipeline and rights-of-way (ROW) regulations. The proposed rules would have the effect of: (1) increasing the financial obligations of entities, like us, which have pipelines and pipeline rights-of-way in the OCS; (2) increasing the regulatory requirements imposed on the operation and maintenance of existing pipelines in the OCS; and (3) increasing the requirements and preconditions for obtaining new rights-of-way in the OCS.

     Capital Commitments. At December 31, 2007, we had capital and investment commitments of approximately $21 million. We have other planned capital and investment projects that 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 $115 million at December 31, 2007. Our annual obligations under these agreements are $48 million in 2008, $30 million in 2009, $11 million in 2010, $9 million in 2011, $5 million in 2012 and $12 million in total thereafter.

     Operating Leases and Other Commercial Commitments. We lease property, facilities and equipment under various operating leases. Minimum future annual rental commitments on our operating leases as of December 31, 2007, were as follows:

     Rental expense on our operating leases for each of the three years ended December 31, 2007, 2006 and 2005 was $2 million, $2 million and $3 million. These amounts include rent allocated to us from El Paso.

     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. Our obligations under these easements are not material to our results of operations.

     Pension and Retirement Benefits. El Paso maintains a pension plan and a retirement savings plan covering substantially all of its U.S. employees, including our employees. The benefits under the pension plan are determined under a cash balance formula. Under its retirement savings plan, El Paso matches 75 percent of participant basic contributions up to six 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 in this group who retire after July 1, 1997 continue to receive limited postretirement life insurance benefits. Our postretirement benefit plan costs are prefunded to the extent these costs are recoverable through our rates and in 1992, we began recovering through our

rates the other postretirement benefits (OPEB) costs. To the extent actual OPEB costs differ from the amounts recovered in rates, a regulatory asset or liability is recorded. We do not expect to make any contributions to our postretirement benefit plan in 2008.

     In December 2006, we adopted the recognition 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), and began reflecting assets and liabilities related to our postretirement benefit plan based on its funded or unfunded status and reclassified all actuarial deferrals as a component of accumulated other comprehensive income. In March 2007, the FERC issued guidance requiring regulated pipeline companies to recognize a regulatory asset or liability for the amount that would otherwise be recorded in accumulated other comprehensive income under SFAS No. 158, if it is probable that amounts calculated on the same basis as SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, would be included in our rates in future periods. Upon adoption of this FERC guidance, we reclassified approximately $3 million from the beginning balance of accumulated other comprehensive income to a regulatory liability, which represented the amount we believe will be included in our future rates.

     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:

     Expected Payment of Future Benefits. As of December 31, 2007, we expect the following payments (net of participant contributions) under our plan (in million):

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

     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 2007, 2006 and 2005: