UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)

      x

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF

THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2004

OR

      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 1-4101

Tennessee Gas Pipeline Company

(Exact name of registrant as specified in its charter)

Delaware	74-1056569
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)
El Paso Building
1001 Louisiana Street
Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

Telephone number: (713) 420-2600

Securities registered pursuant to Section 12(b) of the Act: None

Securities registered pursuant to Section 12(g) of the Act: None

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes  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 an accelerated filer (as defined in Rule 12b-2 of the 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 March 29, 2005: 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		1
Item  2.	Properties		3
Item  3.	Legal Proceedings		3
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		4
Item  6.	Selected Financial Data		*
Item  7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		5
	Risk Factors and Cautionary Statement for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		10
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		39
Item 9A.	Controls and Procedures		39
Item 9B.	Other Information		40
	PART III
Item 10.	Directors and Executive Officers of the Registrant		*
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		*
Item 14.	Principal Accountant Fees and Services		40
	PART IV
Item 15.	Exhibits and Financial Statement Schedules		41
	Signatures		45
Restated Certificate of Incorporation
Certification of CEO pursuant to Section 302
Certification of CFO pursuant to Section 302
Certification of CEO 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
BBtu	=	billion British thermal units
Bcf	=	billion cubic feet
MDth	=	thousand dekatherms
MMcf	=	million cubic feet

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

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

i

PART I

ITEM 1. BUSINESS

General

      We are a Delaware corporation incorporated in 1947 and a wholly owned indirect 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.

      The Pipeline System. The Tennessee Gas Pipeline system consists of approximately 14,200 miles of pipeline with a design capacity of approximately 6,876 MMcf/d. During 2004, 2003 and 2002, average throughput was 4,469 BBtu/d, 4,710 BBtu/d and 4,596 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.

      Storage Facilities. We have approximately 90 Bcf of underground working natural gas storage capacity, of which 1 Bcf is contracted from ANR Pipeline Company and 29 Bcf from Bear Creek Storage Company (Bear Creek), both of whom are our affiliates.

      Bear Creek is a joint venture that we own equally through our subsidiary, Tennessee Storage Company, 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.

Regulatory Environment

      Our interstate natural gas transmission system and storage operations are regulated by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Our pipeline system and storage facilities operate under FERC-approved tariffs that establish rates, terms and conditions for services 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 pipeline and energy affiliates;

      • terms and conditions of services;

      • depreciation and amortization policies;

      • acquisition and disposition of facilities; and

      • initiation and discontinuation of services.

      The fees or rates established under our tariffs are a function of our costs of providing services to our customers, and include provisions for a reasonable return on our invested capital. Approximately 65 percent of our 2004 transportation services and storage revenue is attributable to reservation charges paid by firm customers. Firm customers are those who are obligated to pay a monthly reservation charge, regardless of the amount of natural gas they transport or store, for the term of their contracts. The remaining 35 percent of our transportation services and storage revenue is variable. Due to our regulated nature and the high percentage of our revenue attributable to reservation charges, 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 and market conditions, regulatory actions, competition, weather and the creditworthiness of our customers. We also

1

experience volatility in our financial results when the amounts of natural gas utilized in operations differ from the amounts we receive for that purpose.

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

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

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

Markets and Competition

      Our markets consist of 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 shippers with access to diverse sources of supply and various natural gas markets serviced by these pipelines.

      A number of large natural gas consumers are companies who use natural gas to fuel electric power generation facilities. Electric power generation is the fastest growing demand sector of the natural gas market. The growth and development of the electric power industry potentially benefit the natural gas industry by creating more demand for natural gas turbine generated electric power, but this effect is offset, in varying degrees, by increased generation efficiency, the more effective use of surplus electric capacity and increased natural gas prices.

      We have historically operated under long-term contracts. 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 is due to changes in market conditions and competition driven by state utility deregulation, local distribution company mergers, new supply sources, volatility in natural gas prices, demand for short-term capacity and new markets in power plants.

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

2

      The following table details the markets we serve and the competition on our pipeline system as of December 31, 2004:

Customer Information	Contract Information	Competition
Approximately 432 firm and   interruptible customers Major Customers:   None of which individually represents more than 10 percent of revenues	Approximately 464 firm contracts Weighted average remaining contract term of approximately five years.	We face strong 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 from 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 options, costs of intermediate gathering or required processing of the natural gas may all influence determinations of whether natural gas is ultimately attached to our system.

Environmental

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

Employees

      As of March 24, 2005, we had approximately 1,870 full-time employees, none of whom are subject to a collective bargaining arrangement.

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.

3

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 2004 or 2003. During 2002, a $67 million non-cash dividend of affiliated receivables was declared and paid to our parent.

ITEM 6. SELECTED FINANCIAL DATA

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

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

      The information required by this Item is presented in a reduced disclosure format pursuant to General Instruction I to Form 10-K. The notes to our consolidated financial statements contain information that is pertinent to the following analysis, including a discussion of our significant accounting policies. As discussed in Part II, Item 8, Financial Statements and Supplementary Data, Note 1 our financial statements for the years ended December 31, 2003 and 2002 have been restated for the manner in which we originally applied the provisions of Statements of Financial Accounting Standards (SFAS) No. 141 and SFAS No. 142.

Overview

      Our business primarily consists of interstate natural gas transmission, storage and related services. Our interstate natural gas transportation system and natural gas storage businesses face 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.

      The FERC regulates the rates we can charge our customers. These rates are a function of the costs of providing services to our customers, including a reasonable return on our invested capital. As a result, 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 and market conditions, regulatory actions, competition, weather and the creditworthiness of our customers. We also experience volatility in our financial results when the amounts of natural gas utilized in operations differ from the amounts we receive for those purposes. In 2004, 65 percent of our transportation services and storage revenues were attributable to reservation charges paid by firm customers. The remaining 35 percent was variable.

      We have historically operated under long-term contracts. However, we have shifted from a traditional dependence solely on long-term contracts to a portfolio approach which balances short-term opportunities with 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 supply sources, volatility in natural gas prices, demand for short-term capacity and new markets in power plants.

      In addition, our ability to extend existing customer contracts or remarket expiring contracted capacity is dependent on the 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 constraints, we attempt to recontract or remarket our capacity at the maximum rates allowed under our tariffs, although, at times, we discount 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 five years as of December 31, 2004.

      Below is the contract expiration portfolio for all contracts executed as of December 31, 2004, including those whose terms begin in 2005 or later. When these contracts are included, the portfolio has a weighted average remaining contract term of approximately five years.

			Percent of Total
	MDth/d		Contracted Capacity
2005		1,519		21
2006		583		8
2007		739		10
2008 and beyond		4,415		61

5

Results of Operations

      Our management, as well as El Paso’s management, uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business. We define EBIT as net income adjusted for (i) items that do not impact our income from continuing operations, (ii) income taxes, (iii) interest and debt expense and (iv) affiliated interest income. Our business consists of consolidated operations as well as investments in unconsolidated affiliates. We exclude interest and debt expense from this measure so that our management can evaluate our operating results without regard to our financing methods. We believe the discussion of our results of operations based on EBIT is useful to our investors because it allows them to more effectively evaluate the operating performance of both our consolidated business and our unconsolidated investments using the same performance measure analyzed internally by our management. 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.

      The following is a reconciliation of EBIT to net income for the years ended December 31:

					2003
		2004			(Restated)
		(In millions, except
		volume amounts)
Operating revenues		$	751		$	726
Operating expenses			(491	)		(450	)
	Operating income		260			276
Earnings from unconsolidated affiliates			13			25
Other income, net			3			7
	Other		16			32
	EBIT		276			308
Interest and debt expense			(130	)		(130	)
Affiliated interest income, net			12			4
Income taxes			(64	)		(61	)
	Net income	$	94		$	121
Throughput volumes (BBtu/d)(1)			4,469			4,710

(1)  Throughput volumes exclude volumes related to our equity investment in Portland Natural Gas Transmission System (PNGTS) which was sold in the fourth quarter of 2003.

6

     The following items contributed to our overall EBIT decrease of $32 million for the year ended December 31, 2004 as compared to 2003:

											EBIT
		Revenue			Expense			Other			Impact
		Favorable/(Unfavorable)
		(In millions)
Gas not used in operations and other gas sales		$	28		$	—		$	—		$	28
Resolution of measurement dispute in 2004 at processing plant serving our system			10			—			—			10
Completion of regulatory asset collection and regulatory liability amortization in 2004			(12	)		—			—			(12	)
Lower environmental remediation, legal and other related costs in 2003 primarily due to a revision in our estimated costs to complete our internal polychlorinated biphenyls remediation project			—			(15	)		—			(15	)
Higher allocated costs			—			(16	)		—			(16	)
Accruals for employee severance costs in 2004			—			(2	)		—			(2	)
Impact of the sale of our interest in PNGTS in 2003			—			—			(13	)		(13	)
Other			(1	)		(8	)		(3	)		(12	)
	Total impact on EBIT	$	25		$	(41	)	$	(16	)	$	(32	)

      The following provides further discussions of 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 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 recover and dispose of relative to the amounts of gas we use for operating purposes, and the price of natural gas. The disposition of gas not needed for operations results in revenues to us, which are driven by volumes and prices during the period. Recoveries of gas not used in operations were and are based on factors such as system throughput, facility enhancements and the ability to operate the systems in the most efficient and safe manner. A steadily increasing natural gas price environment during this timeframe resulted in the favorable impact to our operating results in 2004 versus 2003. We anticipate that this area of our business will continue to vary in the future and will be impacted by things such as rate actions, efficiency of our pipeline operations, natural gas prices and other factors.

      Expansions. Our pipeline system connects the principal natural gas supply regions to the largest consuming regions in the U.S. While we continue to experience intense competition along our mainline corridors, we are well positioned to capture growth opportunities in the deepwater Gulf of Mexico and have an infrastructure that complements liquefied natural gas (LNG) growth along the Gulf Coast. These new supplies offset the continued decline of production from the Gulf of Mexico shelf. Additionally, we are developing our ConneXion Expansions in the Northeast market area.

      During the two year period ended December 31, 2004, we completed a number of expansion projects that have generated or will generate new sources of revenues, the most significant of which were the South Texas Expansion and the Can East Expansion. Our expansions during this two year period added approximately 439 MMcf/d to our overall pipeline system.

      Regulatory Matters. In November 2004, the FERC issued a proposed accounting release that may impact certain costs we incur related to our pipeline integrity program. If the release is enacted as written, we would be required to expense certain future pipeline integrity costs instead of capitalizing them as part of our property, plant and equipment. Although we continue to evaluate the impact that this potential accounting release will have on our consolidated financial statements, we currently estimate that we would be required to expense an additional amount of pipeline integrity expenditures in the range of approximately $7 million to $15 million annually over the next eight years.

7

      In November 2004, the FERC issued a Notice of Inquiry (NOI) seeking comments on its policy regarding selective discounting by natural gas pipelines. The FERC seeks comments regarding whether its practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons is appropriate when the discount is given to meet competition from another natural gas pipeline. We, along with several of our affiliated pipelines, filed comments on the NOI in March 2005. The final outcome of this inquiry cannot be predicted with certainty, nor can we predict the impact that the final rule will have on us.

      We can file for changes in our rates which are subject to the approval of the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to negatively impact our profitability. We have no requirements to file a new rate case and, absent any future regulatory action, expect to continue operating under our existing rates.

Affiliated Interest Income, Net

      Affiliated interest income, net for the year ended December 31, 2004, was $8 million higher than the same period in 2003. The increase was due to higher average advances to El Paso under its cash management program and higher average short-term interest rates. The average advances to El Paso were $509 million in 2004 versus $166 million in 2003. The average short-term interest rate increased to 2.4% in 2004 from 2.0% in 2003.

Income Taxes

	Year Ended
	December 31,
				2003
	2004			(Restated)
	(In millions,
	except for rates)
Income taxes	$	64		$	61
Effective tax rate		41	%		34	%

      Our effective tax rate for 2004 was different than the statutory rate of 35 percent primarily due to state income taxes and the expiration of certain state net operating loss carryovers. Our effective tax rate for 2003 was impacted by state net operating losses which reduced the effective tax rate, offset by the change in the realizability of state net operating loss carryovers. For a reconciliation of the statutory rate to the effective rates, see Item 8, Financial Statements and Supplementary Data, Note 2.

Liquidity

      Our liquidity needs have historically been provided by cash flow from operating activities and the use of 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. 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, 2004, we had a cash advance receivable from El Paso of $928 million as a result of this program. This receivable is due upon demand; however, we do not anticipate settlement within the next twelve months. At December 31, 2004, this receivable was classified as non-current notes receivable from affiliates on our balance sheet. In addition to El Paso’s cash management program, we are also eligible to borrow amounts available under El Paso’s $3 billion credit agreement, under which we and our interest in Bear Creek are pledged as collateral. We believe that cash flows from operating activities will be adequate to meet our short-term capital and debt service requirements for existing operations.

8

Capital Expenditures

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

		2004		2003
		(In millions)
Maintenance		$	149	$	120
Expansion/Other			15		43
	Total	$	164	$	163

      Under our current plan, we expect to spend between approximately $129 million and $146 million in each of the next three years for capital expenditures primarily to maintain the integrity of our pipeline and ensure the safe and reliable delivery of natural gas to our customers. In addition, we have budgeted to spend between $56 million and $127 million in each of the next three years to expand the capacity and services of our pipeline system. We expect to fund our maintenance and expansion capital expenditures through internally generated funds and/or by recovering some of the amounts advanced to El Paso under its cash management program.

      In September 2004, we incurred significant damage to sections of our offshore pipeline facilities due to Hurricane Ivan. Total costs incurred for 2004 were approximately $14 million and our estimate of future costs are approximately $17 million. For facilities which we jointly own, the costs will be allocated among each of the partners. We expect insurance reimbursement for our share of the cost of the damage with the exception of our share of a $2 million insurance deductible allocated from El Paso.

Commitments and Contingencies

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

New Accounting Pronouncements Issued But Not Yet Adopted

      As of December 31, 2004, there were a number of accounting standards and interpretations that had been issued, but not yet adopted by us. Based on our assessment of those standards, we do not believe there are any that could have a material impact on us.

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

      This report contains or incorporates by reference forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Where any forward-looking statement includes a statement of the assumptions or bases underlying the forward-looking statement, we caution that, while we believe these assumptions or bases to be reasonable and in good faith, assumed facts or bases almost always vary from the actual results, and the differences between assumed facts or bases and actual results can be material, depending upon the circumstances. Where, in any forward-looking statement, we or our management express an expectation or belief as to future results, that expectation or belief is expressed in good faith and is believed to have a reasonable basis. We cannot assure you, however, that the statement of expectation or belief will result or be achieved or accomplished. The words “believe,” “expect,” “estimate,” “anticipate,” and similar expressions will generally identify forward-looking statements. Our forward-looking statements, whether written or oral, are expressly qualified by these cautionary statements and any other cautionary statements that may accompany those statements. In addition, we disclaim any obligation to update any forward-looking statements to reflect events or circumstances after the date of this report.

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

Risks Related to Our Business

Our success depends on factors beyond our control.

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

•  service area competition;

•  expiration and/or turn back of significant contracts;

•  changes in regulation and actions of regulatory bodies;

•  future weather conditions;

•  price competition;

•  drilling activity and supply availability of natural gas;

•  decreased availability of conventional gas supply sources and the availability and timing of other gas supply sources;

•  increased availability or popularity of alternative energy sources such as hydroelectric power;

•  increased cost of capital;

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

•  adverse general economic conditions; and

•  unfavorable movements in natural gas and liquids prices.

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

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

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

•  competition by other pipelines, including the proposed construction by other companies of additional pipeline capacity in markets served by us;

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

•  reduced demand and market conditions in the areas we serve;

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

•  regulatory actions.

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

Fluctuations in energy commodity prices could adversely affect our business.

      Revenues generated by our transportation services and storage contracts depend on volumes and rates, both of which can be affected by the prices of natural gas. Increased natural gas prices could result in a reduction of the volumes transported by our customers, such as power companies who, depending on the price of fuel, may not dispatch gas-fired power plants. Increased prices could also result in industrial plant shutdowns or load losses to competitive fuels and local distribution companies’ loss of customer base. We also experience volatility in our financial results when the amounts of natural gas utilized in operations differ from the amounts we receive for that purpose. The success of our operations is subject to continued development of additional oil and natural gas reserves in the vicinity of our facilities and our ability to access additional supplies from interconnecting pipelines, primarily in the Gulf of Mexico, to offset the natural decline from existing wells connected to our systems. A decline in energy prices could precipitate a decrease in these development activities and could cause a decrease in the volume of reserves available for transmission or storage on our system. 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 may be negatively impacted. Fluctuations in energy prices are caused by a number of factors, including:

•  regional, domestic and international supply and demand;

•  availability and adequacy of transportation facilities;

•  energy legislation;

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

•  abundance of supplies of alternative energy sources; and

•  political unrest among oil-producing countries.

The agencies that regulate us and our customers affect our profitability.

      Our pipeline business is regulated by the FERC, the U.S. Department of Transportation and various state and local regulatory agencies. Regulatory actions taken by these agencies have the potential to adversely affect

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our profitability. In particular, the FERC regulates the rates we are permitted to charge our customers for our services. If our tariff rates were reduced in a future rate proceeding, if our volume of business under our currently permitted rates was decreased significantly or if we were required to substantially discount the rates for our services because of competition, our profitability and liquidity could be reduced.

Costs of environmental liabilities, regulations and litigation could exceed our estimates.

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

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

•  the uncertainties in estimating clean up costs;

•  the discovery of new sites or information;

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

•  the nature of environmental laws and regulations; and

•  potential changes in environmental laws and regulations, including changes in the interpretation or enforcement thereof.

      Although we believe we have established appropriate reserves for liabilities, including clean up costs, we could be required to set aside additional reserves in the future due to these uncertainties, and these amounts could be material. For additional information, see 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 and 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 face possible risks associated with acts of aggression on our assets. If any of these events were to occur, we could suffer substantial losses.

      While we maintain insurance against many of these risks, to the extent and in amounts that we believe are reasonable, our financial condition and operations could be adversely affected if a significant event occurs that is not fully covered by insurance.

Risks Related to Our Affiliation with El Paso

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

Our relationship with El Paso and its financial condition subjects us to potential risks that are beyond our control.

      Due to our relationship with El Paso, adverse developments or announcements concerning El Paso could adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to El Paso’s senior unsecured indebtedness are below investment grade, currently rated Caa1 by Moody’s Investor Service and CCC+ by Standard & Poor’s. The ratings assigned to our senior unsecured

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indebtedness are currently rated B1 by Moody’s Investor Service and B- by Standard & Poor’s. Further downgrades of our credit rating could increase our cost of capital and collateral requirements, and could impede our access to capital markets. El Paso continues its efforts to execute its Long-Range Plan that established certain financial and other objectives, including significant debt reduction. An inability to meet these objectives could adversely affect El Paso’s liquidity position, and in turn affect our financial condition.

      Pursuant to El Paso’s cash management program, surplus cash is made available to El Paso in exchange for an affiliated receivable. In addition, we conduct commercial transactions with some of our affiliates. El Paso provides cash management and other corporate services for us. If El Paso is unable to meet its liquidity needs, there can be no assurance that we will be able to access cash under the cash management program, or that our affiliates would pay their obligations to us. However, we might still be required to satisfy affiliated company payables. Our inability to recover any affiliated receivables owed to us could adversely affect our ability to repay our outstanding indebtedness. For a further discussion of these matters, see Item 8, Financial Statements and Supplementary Data, Note 11.

      In 2004, El Paso restated its 2003 and prior financial statements and the financial statements of certain of its subsidiaries for the same periods due to revisions to their natural gas and oil reserves and for adjustments related to the manner in which they historically accounted for hedges of their natural gas production. As a result of these reserve revisions, several class action lawsuits have been filed against El Paso and several of its subsidiaries, but not against us. The reserve revisions have also become the subject of investigations by the SEC and U.S. Attorney. These investigations and lawsuits may further negatively impact El Paso’s credit ratings and place further demands on its liquidity.

      We are required to maintain an effective system of internal control over financial reporting. As a result of our efforts to comply with this requirement, we determined that as of December 31, 2004, we did not maintain effective internal control over financial reporting. As more fully discussed in Item 9A, we identified several deficiencies in internal control over financial reporting, two of which management has concluded constituted material weaknesses. Although we have taken steps to remediate some of these deficiencies, additional steps must be taken to remediate the remaining control deficiencies. If we are unable to remediate our identified internal control deficiencies over financial reporting, or we identify additional deficiencies in our internal controls over financial reporting, we could be subjected to additional regulatory scrutiny, future delays in filing our financial statements and suffer a loss of public confidence in the reliability of our financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles, which could have a negative impact on our liquidity, access to capital markets and our financial condition.

      In addition to the risk of not completing the remediation of all deficiencies in our internal controls over financial reporting, we do not expect that our disclosure controls and procedures or our internal controls over financial reporting will prevent all mistakes, errors and fraud. Any system of internal controls, no matter how well designed or implemented, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. The design of a control system must reflect the fact that the benefits of controls must be considered relative to their costs. The design of any system of controls also is based in part upon certain assumptions about the likelihood of future events, and there can be no assurance that any design will succeed in achieving its stated goals under all potential future conditions. Therefore, any system of internal controls is subject to inherent limitations, including the possibility that controls may be circumvented or overridden, that judgments in decision-making can be faulty, and that misstatements due to mistakes, errors or fraud may occur and may not be detected. Also, while we document our assumptions and review financial disclosures, the regulations and literature governing our disclosures are complex and reasonable persons may disagree as to their application to a particular situation or set of facts. In addition, the applicable regulations and literature are relatively new. As a result, they are potentially subject to change in the future, which could include changes in the interpretation of the existing regulations and literature as well as the issuance of more detailed rules and procedures.

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We may be subject to a change in control under certain circumstances.

      Our parent pledged its equity interests in us and we pledged our equity in Bear Creek as collateral under El Paso’s $3 billion credit agreement. As a result, our ownership, as well as Bear Creek’s ownership is subject to change if there is an event of default under the credit agreement and El Paso’s lenders under its credit agreement exercise rights over their collateral.

A default under El Paso’s $3 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 $3 billion credit agreement. We are only liable, however, for our borrowings under the credit agreement, which were zero at December 31, 2004. Under the credit agreement, a default by El Paso, or any other party, could result in the acceleration of all outstanding borrowings under the credit agreement, including the borrowings of any non-defaulting party. The acceleration of our future borrowings, if any, under the credit agreement, or the inability to borrow under the credit agreement, could adversely affect our liquidity position and, in turn, our financial condition.

We could be substantively consolidated with El Paso if El Paso were forced to seek protection from its creditors in bankruptcy.

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

We are an indirect subsidiary of El Paso.

      As an indirect subsidiary of El Paso, El Paso has substantial control over:

•  our payment of dividends;

•  decisions on our financings and our capital raising activities;

•  mergers or other business combinations;

•  our acquisitions or dispositions of assets; and

•  our participation in El Paso’s cash management program.

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

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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, 2004, 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, 2004					December 31, 2003
		Carrying					Carrying
		Amounts			Fair Value		Amounts		Fair Value
		(In millions)
Liabilities:
Long-term debt, including current portion(1) — fixed rate		$	1,598		$	1,720	$	1,597	$	1,633
	Average interest rate		7.6	%

(1)  The holders of the $300 million, 7.0% debentures due 2027, have the option to require us to redeem their debentures at par value in 2007.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

(In millions)

		Year Ended December 31,
					2003			2002
		2004			(Restated)			(Restated)
Operating revenues		$	751		$	726		$	702
Operating expenses
	Operation and maintenance		279			240			271
	Depreciation, depletion and amortization		161			161			149
	Taxes, other than income taxes		51			49			46
			491			450			466
Operating income			260			276			236
Earnings from unconsolidated affiliates			13			25			16
Other income, net			3			7			9
Interest and debt expense			(130	)		(130	)		(126	)
Affiliated interest income, net			12			4			9
Income before income taxes			158			182			144
Income taxes			64			61			42
Net income		$	94		$	121		$	102
Other comprehensive gain (loss)			—			3			(3	)
Comprehensive income		$	94		$	124		$	99

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

				December 31,
				2004		2003
ASSETS
Current assets
	Cash and cash equivalents			$	—	$	—
	Accounts and notes receivable
		Customer, net of allowance of $3 in 2004 and $4 in 2003			103		96
		Affiliates			16		6
		Other			38		47
	Materials and supplies				23		23
	Deferred income taxes				34		32
	Other				14		10
			Total current assets		228		214
Property, plant and equipment, at cost					3,180		3,238
	Less accumulated depreciation, depletion and amortization				440		540
					2,740		2,698
Additional acquisition cost assigned to utility plant, net					2,159		2,198
			Total property, plant and equipment, net		4,899		4,896
Other assets
	Notes receivable from affiliates				930		841
	Investments in unconsolidated affiliates				151		138
	Other				38		43
					1,119		1,022
			Total assets	$	6,246	$	6,132
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
	Accounts payable
		Trade		$	73	$	47
		Affiliates			27		8
		Other			15		11
	Taxes payable				79		113
	Accrued interest				25		25
	Contractual deposits				20		26
	Other				25		33
			Total current liabilities		264		263
Long-term debt					1,598		1,597
Other liabilities
	Deferred income taxes				1,228		1,212
	Other				209		208
					1,437		1,420
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				2,206		2,205
	Retained earnings				741		647
			Total stockholder’s equity		2,947		2,852
			Total liabilities and stockholder’s equity	$	6,246	$	6,132

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

					Year Ended December 31,
								2003			2002
					2004			(Restated)(1)			(Restated)(1)
Cash flows from operating activities
	Net income				$	94		$	121		$	102
	Adjustments to reconcile net income to net cash from operating activities
		Depreciation, depletion and amortization				161			161			149
		Deferred income taxes				15			24			81
		Earnings from unconsolidated affiliates, adjusted for cash distributions				(13	)		(17	)		(16	)
		Other non-cash income items				—			1			(1	)
		Asset and liability changes
			Accounts and notes receivable			(16	)		94			(123	)
			Accounts payable			49			(122	)		(7	)
			Taxes payable			(31	)		76			(62	)
		Other asset and liability changes
			Assets			13			(4	)		51
			Liabilities			(11	)		(30	)		(34	)
				Net cash provided by operating activities		261			304			140
Cash flows from investing activities
	Additions to property, plant and equipment					(164	)		(163	)		(234	)
	Proceeds from the sale of investments and assets					—			57			2
	Net change in affiliated advances					(89	)		(203	)		274
	Other					(8	)		5			—
				Net cash provided by (used in) investing activities		(261	)		(304	)		42
Cash flows from financing activities
	Net repayments of commercial paper					—			—			(424	)
	Net proceeds from the issuance of long-term debt					—			—			238
				Net cash used in financing activities		—			—			(186	)
Net change in cash and cash equivalents						—			—			(4	)
Cash and cash equivalents
	Beginning of period					—			—			4
	End of period				$	—		$	—		$	—

⁽¹⁾  Only individual line items in cash flows from operating activities have been restated. Total cash flows from operating activities, investing activities and financing activities were unaffected by our restatement.

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

(In millions, except share amounts)

												Accumulated
		Common stock				Additional						other			Total
						paid-in			Retained			comprehensive			stockholder’s
		Shares		Amount		capital			earnings			income (loss)			equity
January 1, 2002			208	$	—	$	1,410		$	491		$	—		$	1,901
	Net income (Restated)									102						102
	Allocated tax benefit of El Paso equity plans						2									2
	Contribution from parent						798									798
	Non-cash dividend to parent									(67	)					(67	)
	Other comprehensive loss, net of tax of $1												(3	)		(3	)
December 31, 2002 (Restated)			208		—		2,210			526			(3	)		2,733
	Net income (Restated)									121						121
	Allocated tax expense of El Paso equity plans						(5	)								(5	)
	Sale of Portland Natural Gas investment, net of tax of $1												3			3
December 31, 2003			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

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Basis of Presentation and Summary of Significant Accounting Policies

  Basis of Presentation

      Our consolidated financial statements 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.

Restatement

      During the completion of the financial statements for the year ended December 31, 2004, we identified an error in the manner in which we had originally adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations and SFAS No. 142, Goodwill and Other Intangible Assets, in 2002. Upon adoption of these standards, we incorrectly adjusted the cost of investments in unconsolidated affiliates and recorded a cumulative effect of a change in accounting principle for the excess of our share of the affiliates’ fair value of net assets over their original cost, which we believed was negative goodwill. The amount originally recorded as a cumulative effect of accounting change was $10 million and related to our investment in the Portland Natural Gas Transmission System (PNGTS). We subsequently determined that the amount we adjusted was not negative goodwill, but rather an amount that should have been allocated to the long-lived assets underlying our investment. As a result, we were required to restate our 2002 financial statements to reverse the amount we recorded as a cumulative effect of an accounting change on January 1, 2002. This adjustment also impacted a loss we recorded when we sold PNGTS in the fourth quarter of 2003. The restatements also affected the investment and stockholders’ equity balances we reported as of December 31, 2002. Below are the effects of our restatement:

		Years Ended
		December 31, 2002				December 31, 2003
		As Reported		As Restated		As Reported		As Restated
		(In millions)
Income Statement:
	Earnings from unconsolidated affiliates					$	15	$	25
	Cumulative effect of accounting changes, net of income taxes	$	10	$	—
	Net income		112		102		111		121
Balance Sheet:
	Investments in unconsolidated affiliates	$	179	$	169
	Stockholder’s equity		2,743		2,733

      Other than the effects above, the components of this adjustment were immaterial to all previously reported interim and annual periods.

  Principles of Consolidation

      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

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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 financial statements in conformity with accounting principles generally accepted in the U.S. 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 system and storage operations are subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and we currently apply the provisions of SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. We perform an annual study to assess the ongoing applicability of SFAS No. 71. The accounting required by SFAS No. 71 differs from the accounting required for businesses that do not apply its provisions. Transactions that are generally recorded differently as a result of applying regulatory accounting requirements include capitalizing an equity return component on regulated capital projects, postretirement employee benefit plans, and other costs 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 amount of natural gas scheduled to be delivered or received. We value these imbalances due to or from shippers and operators at specific index prices. Imbalances are settled in cash or in-kind, subject to the terms of our settlement.

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

  Property, Plant and Equipment

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

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      We use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar lives and other characteristics are grouped and depreciated as one asset. We apply the FERC-accepted depreciation rate to the total cost of the group until its net book value equals its salvage value. Currently, our depreciation rates vary from one to 24 percent. Using these rates, the remaining depreciable lives of these assets range from 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 accounted for under SFAS No. 71, we charge accumulated depreciation and amortization for the original cost, plus the cost to remove, sell or dispose, less its salvage value. We do not recognize a gain or loss unless we sell an entire operating unit. We include gains or losses on dispositions of operating units in income. On 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 pipeline property balances are additional acquisition costs assigned to utility plants which represents the excess of allocated purchase costs over historical costs of these facilities. These costs are amortized on a straight-line basis using FERC approved rates, and we do not recover those excess costs in our rates.

      At December 31, 2004 and 2003, we had approximately $89 million and $88 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 invested in 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. Debt amounts capitalized during the years ended December 31, 2004, 2003 and 2002, were $1 million, $1 million and $3 million. These amounts are included as a reduction to interest expense in our income statement. The equity portion is calculated using the most recent FERC approved equity rate of return. The equity portion capitalized during the year ended December 31, 2004 and 2003, were $2 million and $3 million (exclusive of any tax related impacts) and none was capitalized in the year ended December 31, 2002. These 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 apply the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets and Accounting Principles Board Opinion No. 18, The Equity Method of Accounting for Investments in Common Stock, to account for asset and investment impairments. Under these standards, we evaluate an asset or investment for impairment when events or circumstances indicate that its carrying value 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 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 carrying value 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 our investment in unconsolidated affiliates. If an impairment is indicated or if we decide to exit or 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, less costs to sell. 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 to be sold and our established time frame for completing the sales, among other factors.

  Revenue Recognition

      Our revenues are generated from transportation and storage services. For our transportation and storage services, we recognize reservation revenues on firm contracted capacity over the contract period regardless of the amount of natural gas that is transported or stored. For interruptible or volumetric based services, we

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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. Revenues for all services are generally based on the thermal quantity of gas delivered or subscribed at a price specified in the contract. We are subject to FERC regulations and, as a result, revenues we collect may possibly be refunded in a final order of a future rate proceeding or as a result of a rate settlement. We establish reserves for these potential refunds.

  Environmental Costs and Other Contingencies

      We record environmental liabilities when our environmental assessments indicate that remediation efforts are probable, and the costs can be reasonably estimated. We recognize a current period expense for the liability when the clean-up efforts do not benefit future periods. We capitalize costs that benefit more than one accounting period, except in instances where separate agreements or legal and regulatory guidelines dictate otherwise. Estimates of our liabilities are based on currently available facts, existing technology and presently enacted laws and regulations taking into account the likely effects of inflation and other societal and economic factors, and include estimates of associated legal costs. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by the Environmental Protection Agency (EPA) or other organizations. These estimates are subject to revision in future periods based on actual costs or new circumstances and are included in our balance sheet in other current and long-term liabilities at their undiscounted amounts. We evaluate recoveries from insurance coverage, rate recovery, government sponsored and other programs separately from our liability and, when recovery is assured, we record and report an asset separately from the associated liability in our financial statements.

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

  Income Taxes

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

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2. Income Taxes

      The following table reflects the components of income taxes included in net income for each of the three years ended December 31:

			2004			2003			2002
			(In millions)
Current
	Federal		$	52		$	37		$	(35	)
	State			(3	)		—			(4	)
				49			37			(39	)
Deferred
	Federal			1			27			89
	State			14			(3	)		(8	)
				15			24			81
		Total income taxes	$	64		$	61		$	42

      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:

						2003(1)
			2004			(Restated)			2002
			(In millions)
Income taxes at the statutory federal rate of 35%			$	55		$	64		$	50
Increase (decrease)
	State income taxes, net of federal income tax effect			6			(6	)		(8	)
	Change in the realizability of deferred tax assets for:
		Federal net operating loss carryover of an acquired company		—			—			2
		State net operating loss carryovers		2			4			—
	Valuation allowances			—			—			(2	)
	Other			1			(1	)		—
	Income taxes		$	64		$	61		$	42
	Effective tax rate			41	%		34	%		29	%

⁽¹⁾  Income taxes at the statutory rate, individual line items in income taxes and the effective tax rate have been restated. Total income taxes were unaffected by our restatement.

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

				2004		2003
				(In millions)
Deferred tax liabilities
	Property, plant and equipment			$	1,447	$	1,404
	Other				106		144
			Total deferred tax liability		1,553		1,548
Deferred tax assets
	Net operating loss and credit carryovers
		U.S. Federal			155		156
		State			75		89
	Accrual for regulatory issues				10		10
	Environmental liability				57		56
	Other liabilities				62		57
			Total deferred tax asset		359		368
Net deferred tax liability				$	1,194	$	1,180

      Under El Paso’s tax accrual policy, we are allocated the tax effects associated with our employees’ non-qualified dispositions of employee stock purchase plan stock, the exercise of non-qualified stock options and the vesting of restricted stock as well as restricted stock dividends. This allocation reduced taxes payable by $1 million and $2 million in 2004 and 2002 and increased taxes payable by $5 million in 2003. These tax effects are included in additional paid-in capital in our balance sheet.

      As of December 31, 2004, we had $1 million of alternative minimum tax credit carryovers and $439 million of federal net operating loss carryovers. The alternative minimum tax credits carryover indefinitely. The carryover period for the net operating loss ends as follows: approximately $130 million in 2018; $75 million in 2019; $17 million in 2020; $180 million in 2021 and $37 million in 2023. Usage of these carryovers is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation year rules of IRS regulations.

      As of December 31, 2004, we had $1,002 million of state net operating loss carryovers. These carryovers, if not utilized, will expire in varying amounts over the period from 2005 to 2023.

3. Financial Instruments

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

		2004				2003
		Carrying				Carrying
		Amount		Fair Value		Amount		Fair Value
		(In millions)
Balance sheet financial instruments:
	Long-term debt(1)	$	1,598	$	1,720	$	1,597	$	1,633

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

     At December 31, 2004 and 2003, the carrying amounts of cash and cash equivalents, short-term borrowings, and trade receivables and payables are representative of fair value because of the short-term maturity of these instruments.

4. Accumulated Other Comprehensive Loss

      Our accumulated other comprehensive income at December 31, 2002, included a loss of $3 million, net of $1 million in income taxes, representing our proportionate share of amounts recorded in other comprehensive

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loss by PNGTS, our equity investee, related to its derivative hedging activities. For the years ended December 31, 2003 and 2002, PNGTS did not record any ineffectiveness in earnings on its cash flow hedges. In the fourth quarter of 2003, we sold our 30 percent ownership interest in PNGTS and eliminated the accumulated other comprehensive loss associated with this investment.

5. Regulatory Assets and Liabilities

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

Description			2004		2003
			(In millions)
Current regulatory assets(1)			$	3	$	2
Non-current regulatory assets
	Grossed-up deferred taxes on capitalized funds used during construction(1)			15		15
	Postretirement benefits(1)			13		15
	Excess refund due to completion of amortization of past deficient state and excess federal deferred taxes			5		—
	Unamortized net loss on reacquired debt(1)			2		3
	Other(1)			—		2
		Total regulatory assets(2)	$	38	$	37
Current regulatory liabilities
	Cashout imbalance settlement(1)		$	9	$	9
	Excess deferred federal income taxes			—		1
Non-current regulatory liabilities
	Environmental liability(1)			97		87
	Cost of removal of off-shore assets			32		34
	Postretirement benefits(1)			13		11
	Plant regulatory liability(1)			11		11
		Total regulatory liabilities(2)	$	162	$	153

(1)	These amounts are not included in our rate base on which we earn a current return.
(2)	Amounts are included as other current and non-current assets and liabilities in our balance sheet.

6. Property, Plant and Equipment

      As of December 31, 2004, additional acquisition costs assigned to utility plant was approximately $2 billion and accumulated depreciation was approximately $220 million. These excess costs are being amortized over the life of the related pipeline assets. Our amortization expense during 2004 and 2003 was approximately $39 million and $38 million.

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7. Debt and Other Credit Facilities

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

		2004		2003
		(In millions)
6.0% Debentures due 2011		$	86	$	86
7.5% Debentures due 2017			300		300
7.0% Debentures due 2027(1)			300		300
7.0% Debentures due 2028			400		400
8.375% Notes due 2032			240		240
7.625% Debentures due 2037			300		300
			1,626		1,626
Less: Unamortized discount			28		29
	Long-term debt	$	1,598	$	1,597

⁽¹⁾  The holders of the $300 million, 7.0% debentures due 2027, have the option to require us to redeem their debentures at par value in 2007.

     Credit Facilities

      In November 2004, El Paso replaced its previous $3 billion revolving credit facility with a new $3 billion credit agreement, under which we continue to be an eligible borrower. The credit agreement consists of a $1.25 billion term loan facility, a $750 million letter of credit facility, and a $1 billion revolving credit facility. The letter of credit facility provides El Paso the ability to issue letters of credit or borrow any unused capacity as revolving loans. We are only liable for amounts we directly borrow under the credit agreement. At December 31, 2004, El Paso had $1.25 billion outstanding under the term loan facility and utilized approximately all of the $750 million letter of credit facility and approximately $0.4 billion of the $1 billion revolving credit facility to issue letters of credit, none of which were borrowed by or issued on behalf of us. Additionally, El Paso’s interests in us and our interest in Bear Creek, along with several of our affiliates continue to be pledged as collateral under the credit agreement.

      Under the $3 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) limitation on our ability to prepay debt. For the year ended December 31, 2004, we were in compliance with all of our debt-related covenants.

8. Commitments and Contingencies

  Legal Proceedings

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

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      Will Price (formerly Quinque). We and a number of our affiliates are named defendants in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., filed in 1999 in the District Court of Stevens County, Kansas. Plaintiffs allege that the defendants mismeasured natural gas volumes and heating content of natural gas on non-federal and non-Native American lands and seek to recover royalties that they contend they should have received had the volume and heating value of natural gas produced from their properties been differently measured, analyzed, calculated and reported, together with prejudgment and postjudgment interest, punitive damages, treble damages, attorneys’ fees, costs and expenses, and future injunctive relief to require the defendants to adopt allegedly appropriate gas measurement practices. No monetary relief has been specified in this case. Plaintiffs’ motion for class certification of a nationwide class of natural gas working interest owners and natural gas royalty owners was denied in April 2003. Plaintiffs were granted leave to file a Fourth Amended Petition, which narrows the proposed class to royalty owners in wells in Kansas, Wyoming and Colorado and removes claims as to heating content. A second class action petition has since been filed as to the heating content claims. The plaintiffs have filed motions for class certification in both proceedings and the defendants have filed briefs in opposition thereto. Our costs and legal exposure related to these lawsuits and claims are not currently determinable.

     Governmental Investigations

      Storage Reporting. In November 2004, we received a data request from the FERC in connection with its investigation into the weekly storage withdrawal number reported by the Energy Information Administration (EIA) for the eastern region, that was subsequently revised downward by the EIA. Specifically, we provided information on our weekly EIA submissions for the weeks ending November 12, 2004 and November 19, 2004. We did not revise the submission to the EIA subsequent to its original submissions. In December 2004, the FERC held a press conference at which they disclosed that their inquiry has determined that an unaffiliated third party was the source of the downward revision.

      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 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 current reserves are adequate. At December 31, 2004, we had no accruals for our outstanding legal matters.

     Environmental Matters

      We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. At December 31, 2004, we had accrued approximately $42 million, including approximately $41 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $1 million for related environmental legal costs, which we anticipate incurring through 2027. Our accrual was based on the most likely outcome that can be reasonably estimated. Below is a reconciliation of our accrued liability at December 31, 2004 (in millions):

Balance at January 1, 2004	$	46
Payments for remediation activities		(4	)
Balance at December 31, 2004	$	42

      In addition, we expect to make capital expenditures for environmental matters of approximately $33 million in the aggregate for the years 2005 through 2009. These expenditures primarily relate to

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compliance with clean air regulations. For 2005, we estimate that our total remediation expenditures will be approximately $5 million, which will be expended under government directed clean-up plans.

      Internal Polychlorinated Biphenyls (PCB) Remediation Project. Since 1988, we have been engaged in an internal project to identify and address the presence of PCBs and other substances, including those on the EPA List of Hazardous Substances, at compressor stations and other facilities we operate. While conducting this project, we have been in frequent contact with federal and state regulatory agencies, both through informal negotiation and formal entry of consent orders. We executed a consent order in 1994 with the EPA, governing the remediation of the relevant compressor stations, and are working with the EPA and the relevant states regarding those remediation activities. We are also working with the Pennsylvania and New York environmental agencies regarding remediation and post-remediation activities at our Pennsylvania and New York stations.

      PCB Cost Recoveries. In May 1995, following negotiations with our customers, we filed an agreement with the FERC that established a mechanism for recovering a substantial portion of the environmental costs identified in our internal remediation project. The agreement, which was approved by the FERC in November 1995, provided for a PCB surcharge on firm and interruptible customers’ rates to pay for eligible remediation costs, with these surcharges to be collected over a defined collection period. We have received approval from the FERC to extend the collection period, which is now currently set to expire in June 2006. The agreement also provided for bi-annual audits of eligible costs. As of December 31, 2004, we had pre-collected PCB costs by approximately $125 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. As of December 31, 2004, we have recorded a regulatory liability (included in other non-current liabilities on our balance sheet) of $97 million for estimated future refund obligations.

      Kentucky PCB Project. In November 1988, the Kentucky Natural Resources and Environmental Protection Cabinet filed a complaint in a Kentucky state court alleging that we discharged pollutants into the waters of the state and disposed of PCBs without a permit. The agency sought an injunction against future discharges, an order to remediate or remove PCBs and a civil penalty. We entered into interim agreed orders with the agency to resolve many of the issues raised in the complaint. The relevant Kentucky compressor stations are being remediated under a 1994 consent order with the EPA. Despite our remediation efforts, the agency may raise additional technical issues or seek additional remediation work and/or penalties in the future.

      CERCLA Matters. We have received notice that we could be designated, or have been asked for information to determine whether we could be designated, as a Potentially Responsible Party (PRP) with respect to four active sites under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA) or state equivalents. We have sought to resolve our liability as a PRP at these sites through indemnification by third parties and settlements which provide for payment of our allocable share of remediation costs. As of December 31, 2004, we have estimated our share of the remediation costs at these sites to be between $1 million and $2 million. Since the clean-up costs are estimates and are subject to revision as more information becomes available about the extent of remediation required, and because in some cases we have asserted a defense to any liability, our estimates could change. Moreover, liability under the federal CERCLA statute is joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. Our understanding of the financial strength of other PRPs has been considered, where appropriate, in estimating our liabilities. 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

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adjust our accrual amounts accordingly. While there are still uncertainties relating to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

Rates and Regulatory Matters

      Order No. 637. We filed our compliance proposal in August 2000 and received an order on compliance from the FERC in April 2002. Most of our compliance proposal was accepted, but the FERC rejected our proposals regarding overlapping capacity segments, discounting and the priority of capacity. In response, we sought rehearing and have made another compliance filing. In October 2002, the FERC issued its order responding to the United States Court of Appeals for the D.C. Circuit’s order remanding the various aspects of Order No. 637. In December 2002, we submitted a compliance filing with the FERC to comply with the October order. We also filed for rehearing of the October order. In July 2003, the FERC issued an order on our rehearing request and compliance filing as to the April 2002 Order, denying our request for rehearing regarding a replacement shipper’s ability to select additional primary points, forwardhauls and backhauls to the same delivery point, and discounting. We filed certain required tariff revisions in response to that order and sought further rehearing of certain issues. The FERC issued an order on these filings in August 2004, noting its compliance with certain of the tariff revisions, modifying others, granting our rehearing and clarification requests on certain items and denying others. We have filed for clarification and/or rehearing on certain matters. While we cannot predict the outcome of the clarification and/or rehearing filing, the majority of the Order No. 637 requirements that have been implemented on our system to date have resulted in no material adverse impact.

      In February 2004, the Court of Appeals for the D.C. Circuit vacated certain FERC orders that applied its Order No. 637 discounting policy to Williston Basin pipeline. The FERC sought and received industry comments in advance of their order on remand. In March 2005, the FERC issued an order determining it could not support its Order No. 637 discounting policy.

      Accounting for Pipeline Integrity Costs. In November 2004, the FERC issued a proposed accounting release that may impact certain costs we incur related to our pipeline integrity program. If the release is enacted as written, we would be required to expense certain future pipeline integrity costs instead of capitalizing them as part of our property, plant and equipment. Although we continue to evaluate the impact that this potential accounting release will have on our consolidated financial statements, we currently estimate that we would be required to expense an additional amount of pipeline integrity expenditures in the range of approximately $7 million to $15 million annually over the next eight years.

      Inquiry Regarding Income Tax Allowances. In December 2004, the FERC issued a Notice of Inquiry (NOI) in response to a recent D.C. Circuit decision that held the FERC had not adequately justified its policy of providing a certain oil pipeline limited partnership with an income tax allowance equal to the proportion of its limited partnership interests owned by corporate partners. The FERC sought comments on whether the court’s reasoning should be applied to other partnerships or other ownership structures. We own interests in non-taxable entities that could be affected by this ruling. We cannot predict what impact this inquiry will have on us.

      Selective Discounting Notice of Inquiry. In November 2004, the FERC issued a NOI seeking comments on its policy regarding selective discounting by natural gas pipelines. The FERC seeks comments regarding whether its practice of permitting pipelines to adjust their ratemaking throughput downward in rate cases to reflect discounts given by pipelines for competitive reasons is appropriate when the discount is given to meet competition from another natural gas pipeline. We, along with several of our affiliated pipelines, filed comments on the NOI in March 2005. The final outcome of this inquiry cannot be predicted with certainty, nor can we be predict the impact that the final rule will have on us.

      While the outcome of our outstanding rates and regulatory matters cannot be predicted with certainty, based on current information, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results or cash flows. However, it is possible that new information or future developments could require us to reassess our potential exposure related to these matters.

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  Capital Commitments and Purchase Obligations

      At December 31, 2004, we had capital and investment commitments of $12 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 and services, including financing commitments with one of our joint ventures, totaling $134 million at December 31, 2004. Our annual obligations under these agreements are $36 million for 2005, $27 million for 2006, $15 million for 2007, $12 million for 2008, $11 million for 2009 and $33 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, 2004, were as follows:

Year Ending
December 31,		Operating Leases(1)
		(In millions)
2005		$	2
2006			2
2007			2
2008			1
2009			1
Thereafter			9
	Total	$	17

⁽¹⁾  These amounts exclude our proportional share of minimum annual rental commitments paid by El Paso, which are allocated to us through an overhead allocation.

     Rental expense on our operating leases for each of the years ended December 31, 2004, 2003 and 2002 was $8 million, $6 million and $5 million. These amounts include our share of rent allocated to us from El Paso.

  Guarantees

      We are involved in various joint ventures and other ownership arrangements that sometimes require additional financial support that results in the issuance of financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. As of December 31, 2004, we had approximately $8 million of financial and performance guarantees not otherwise reflected in our financial statements.

9. Retirement Benefits

  Pension and Retirement Benefits

      El Paso maintains a pension plan to provide benefits determined under a cash balance formula covering substantially all of its U.S. employees, including our employees. El Paso also maintains a defined contribution plan covering its U.S. employees, including our employees. Prior to May 1, 2002, El Paso matched 75 percent of participant basic contributions up to 6 percent, with the matching contributions being made to the plan’s stock fund, which participants could diversify at any time. After May 1, 2002, the plan was amended to allow for company matching contributions to be invested in the same manner as that of participant contributions. Effective March 1, 2003, El Paso suspended the matching contributions but reinstituted it again at a rate of 50 percent of participant basic contributions up to 6 percent on July 1, 2003. Effective July 1, 2004, El Paso

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increased the matching contributions to 75 percent of participant basic contributions up to 6 percent. El Paso is responsible for benefits accrued under its plans and allocates the related costs to its affiliates.

  Other Postretirement Benefits

      We maintain responsibility for postretirement 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. We have reserved the right to change these benefits. Employees who retire after July 1, 1997 will continue to receive limited postretirement life insurance benefits. Postretirement benefit plan costs are prefunded to the extent these costs are recoverable through 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 other postretirement benefit plan in 2005.

      In 2004, we adopted FASB Staff Position (FSP) No. 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. This pronouncement requires companies to record the impact of the Medicare Prescription Drug, Improvement and Modernization Act of 2003 on their postretirement benefit plans that provide drug benefits that are covered by that legislation. We determined that our postretirement benefit plans do not provide drug benefits that are covered by this legislation and, as a result, the adoption of this pronouncement did not have a material impact on our financial statements.

      The following table presents the change in projected benefit obligation, change in plan assets and reconciliation of funded status for our other postretirement benefit plan. Our benefits are presented and computed as of and for the twelve months ended September 30 (the plan reporting date):

		2004			2003
		(In millions)
Change in benefit obligation:
	Projected benefit obligation at beginning of period	$	26		$	26
	Interest cost		2			2
	Participant contributions		1			1
	Actuarial loss		1			1
	Benefits paid		(5	)		(4	)
	Projected benefit obligation at end of period	$	25		$	26
Change in plan assets:
	Fair value of plan assets at beginning of period	$	14		$	11
	Actual return on plan assets		1			2
	Employer contributions		5			4
	Participant contributions		1			1
	Benefits paid		(5	)		(4	)
	Fair value of plan assets at end of period	$	16		$	14
Reconciliation of funded status:
	Under funded status at September 30	$	(9	)	$	(12	)
	Fourth quarter contributions and income		1			2
	Unrecognized net actuarial gain		(3	)		(5	)
	Net accrued benefit cost at December 31(1)	$	(11	)	$	(15	)

⁽¹⁾  Based on our current funded status, we have reflected approximately $2 million of our accrued benefit obligation as a current liability at both December 31, 2004 and 2003.

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     Future benefits expected to be paid on our other postretirement plan as of December 31, 2004, are as follows (in millions):

Year Ending December 31,
2005		$	3
2006			3
2007			3
2008			2
2009			2
2010-2014			10
	Total	$	23

      Our postretirement benefit costs recorded in operating expenses include the following components for the years ended December 31:

	2004			2003			2002
	(In millions)
Interest cost	$	2		$	2		$	2
Expected return on plan assets		(1	)		(1	)		—
Net postretirement benefit cost	$	1		$	1		$	2

      Projected benefit obligations and net benefit costs are based on actuarial estimates and assumptions. The following table details the weighted average actuarial assumptions used for our other postretirement plan for 2004, 2003 and 2002:

		2004		2003		2002
		(Percent)
Assumptions related to benefit obligations at September 30:
	Discount rate		5.75		6.00
Assumptions related to benefit costs at December 31:
	Discount rate		6.00		6.75		7.25
	Expected return on plan assets(1)		7.50		7.50		7.50

⁽¹⁾  The expected return on plan assets is a pre-tax rate (before a tax rate ranging from 35 percent to 39 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 our 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 10.0 percent in 2004, gradually decreasing to 5.5 percent by the year 2009. Assumed health care cost trends can have a significant effect on the amounts reported for other postretirement benefit plan. However, it does not affect our costs because our costs are limited by defined dollar caps.

     Other Postretirement Plan Assets

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

		Actual		Actual
Asset Category		2004		2003
		(Percent)
Equity securities			55		24
Debt securities			30		51
Other			15		25
	Total		100		100

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      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 or 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. In 2003, we modified our target asset allocations for our postretirement benefit plan to increase our equity allocation to 65 percent of total plan assets. 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:

	2004		2003			2002
	(In millions)
Interest paid, net of capitalized interest	$	123	$	119		$	107
Income tax payments (refunds)		72		(65	)		43

11. Investments in Unconsolidated Affiliates and Transactions with Affiliates

      Bear Creek. At December 31, 2004, we have a 50 percent ownership interest in Bear Creek, a joint venture with Southern Gas Storage Company, our affiliate. Bear Creek owns and operates an underground natural gas storage facility located in Louisiana. The facility has a capacity of 50 Bcf of base gas and 58 Bcf of working storage. Bear Creek’s working storage capacity is committed equally to SNG and our pipeline system under long-term contracts. Our investment in Bear Creek at December 31, 2004 and 2003, was $151 million and $138 million. We recognized equity earnings of $13 million in 2004 and $12 million in 2003 and 2002.

      PNGTS. In the fourth quarter of 2003, we sold our 30 percent interest in PNGTS to TransCanada Corporation for approximately $56 million. We recorded a pre-tax gain of approximately of $8 million related to this sale in our earnings from unconsolidated affiliates. We recognized equity earnings of $5 million in 2003 and $4 million in 2002. See Note 1 for further discussion of the restatement of our financial statements related to our accounting for PNGTS.

      Summarized financial information of our proportionate share of unconsolidated affiliates are presented below.

	Year Ended December 31,
	2004		2003		2002
	(In millions)
Operating results data:(1)
Operating revenues	$	18	$	31	$	34
Operating expenses		7		12		14
Income from continuing operations		13		17		16
Net income		13		17		16

⁽¹⁾  Includes PNGTS through September 2003.

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	December 31,
	2004		2003
	(In millions)
Financial position data:
Current assets	$	88	$	73
Non-current assets		65		65
Other current liabilities		1		—
Other non-current liabilities		1		—
Equity in net assets		151		138

     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. At December 31, 2004 and 2003, we had advanced to El Paso $928 million and $839 million. The interest rate at December 31, 2004 and 2003 was 2.0% and 2.8%. These receivables are due upon demand; however, at December 31, 2004 and 2003, we have classified these advances as non-current notes receivable from affiliates because we do not anticipate settlement within the next twelve months.

      Affiliate Receivables and Payables. At December 31, 2004 and 2003, we had accounts receivable from affiliates of $16 million and $6 million. In addition, we had accounts payable to affiliates of $27 million and $8 million at December 31, 2004 and 2003. These balances arose in the normal course of business.

      At December 31, 2004 and 2003, we had non-current notes receivable from a subsidiary of El Paso of $2 million.

      We also received $6 million and $5 million in deposits related to our transportation contracts with El Paso Marketing L.P. (EPM), formerly known as El Paso Merchant Energy L.P., which is included in our balance sheet as current liabilities at December 31, 2004 and 2003.

      We are a party to a tax accrual policy with El Paso whereby El Paso files U.S. and certain state tax returns on our behalf. In certain states, we file and pay directly to the state taxing authorities. We have state income taxes receivable of $28 million and $37 million at December 31, 2004 and 2003, which are included in accounts and notes receivable — other on our balance sheets. We have federal income taxes payable of $46 million and $77 million at December 31, 2004 and 2003, which are included in taxes payable on our balance sheets. The majority of these balances will become payable to or receivable from El Paso under the tax accrual policy. See Note 1 for a discussion of our tax accrual policy.

      Other. In the third quarter of 2004, we acquired assets from our affiliate with a net book value of $8 million.

      Affiliate Revenues and Expenses. During 2004, 2003 and 2002, we transported gas for EPM, and recognized revenues of $21 million, $24 million and $72 million.

      El Paso allocates a portion of its general and administrative expenses to us. The allocation of expenses is based on the estimated level of effort devoted to our operations and the relative size of our EBIT, gross property and payroll. For the years ended December 31, 2004, 2003, and 2002, the annual charges were $48 million, $69 million and $97 million. During 2004, 2003 and 2002, we performed operational, financial, accounting and administrative services for El Paso’s other pipeline systems. For the years ended December 31, 2004, 2003 and 2002, the amounts received for these services were $69 million, $52 million and $39 million. We record these amounts as a reduction of operating expenses and as reimbursements of costs. We believe that all the allocation methods are reasonable.

      We store natural gas in an affiliated storage facility and utilized an affiliated pipeline (ANR Pipeline Company) to transport some of our natural gas during each of the years 2004, 2003 and 2002. These costs were $1 million, $2 million and $5 million and are recorded as operating expenses. These activities were entered into in the normal course of our business and are based on the same terms as non-affiliates.

35

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

	2004		2003		2002
	(In millions)
Revenues from affiliates	$	21	$	37	$	82
Operation and maintenance expense from affiliates		49		71		102
Reimbursement of operating expenses charged to affiliates		69		52		39

12. Supplemental Selected Quarterly Financial Information (Unaudited)

      Financial information by quarter is summarized below:

		Quarters Ended
		March 31		June 30		September 30		December 31		Total
		(In millions)
2004
	Operating revenues	$	228	$	179	$	166	$	178	$	751
	Operating income		107		62		47		44		260
	Net income		49		21		13		11		94
2003 (Restated)(1)
	Operating revenues	$	212	$	168	$	161	$	185	$	726
	Operating income		95		54		50		77		276
	Net income		49		20		17		35		121

⁽¹⁾  For further discussion of the restatement, see Note 1.

36

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, 2004 and 2003, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the Index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. These financial statements and 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 2003 and 2002 consolidated financial statements have been restated.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

March 29, 2005

37

SCHEDULE II

TENNESSEE GAS PIPELINE COMPANY

VALUATION AND QUALIFYING ACCOUNTS

Years Ended December 31, 2004, 2003 and 2002

(In millions)

		Balance at		Charged to						Charged to			Balance
		Beginning		Costs and						Other			at End
Description		of Period		Expenses			Deductions			Accounts			of Period
2004
	Allowance for doubtful accounts	$	4	$	—		$	—		$	(1	)	$	3
	Legal reserves		—		—			(1	)		1			—
	Environmental reserves		46		—			(4	)(1)		—			42
	Regulatory reserves		1		—			(1	)		—			—
2003
	Allowance for doubtful accounts	$	4	$	—		$	—		$	—		$	4
	Legal reserves		4		(4	)		—			—			—
	Environmental reserves		84		(31	)(2)		(7	)(1)		—			46
	Regulatory reserves		6		(4	)		(1	)		—			1
2002
	Allowance for doubtful accounts	$	6	$	(1	)	$	(2	)(3)	$	1		$	4
	Valuation allowance on deferred tax assets		2		—			(2	)		—			—
	Legal reserves		4		—			—			—			4
	Environmental reserves		102		(4	)		(14	)(1)		—			84
	Regulatory reserves		10		(5	)		—			1			6

(1)	Primarily payments made for environmental remediation activities.
(2)	Represents a reduction in the estimated costs to complete our internal PCB remediation project.
(3)	Primarily accounts written off.

38

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

      None.

ITEM 9A.  CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

      As of December 31, 2004, we carried out an evaluation under the supervision and with the participation of our management, including our Chief Executive Officer (CEO) and our Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). 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 recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including the CEO and CFO, as appropriate, to allow timely discussion regarding required financial disclosure.

      Based on the results of this evaluation, our CEO and CFO concluded that as a result of the material weaknesses discussed below, our disclosure controls and procedures were not effective as of December 31, 2004. Because of these material weaknesses, we performed additional procedures to ensure that our financial statements as of and for the year ended December 31, 2004, were fairly presented in all material respects in accordance with generally accepted accounting principles.

Internal Control Over Financial Reporting

      During 2004, we continued our efforts to ensure our compliance with Section 404 of the Sarbanes-Oxley Act of 2002, which will apply to us at December 31, 2006. In our efforts to evaluate our internal control over financial reporting, we have identified the material weaknesses described below as of December 31, 2004. A material weakness is a control deficiency, or combination of control deficiencies, that results in a more than remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

      Access to Financial Application Programs and Data. At December 31, 2004, we did not maintain effective controls over access to financial application programs and data. Specifically, we identified internal control deficiencies with respect to inadequate design of and compliance with our security access procedures related to identifying and monitoring conflicting roles (i.e., segregation of duties) and a lack of independent monitoring of access to various systems by our information technology staff, as well as certain users that require unrestricted security access to financial and reporting systems to perform their responsibilities. These control deficiencies did not result in an adjustment to the 2004 interim or annual consolidated financial statements. However, these control deficiencies could result in a misstatement of a number of our financial statement accounts, including accounts receivable, property, plant and equipment, accounts payable, operating expenses, and potentially others, that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, management has determined that these control deficiencies constitute a material weakness.

      Identification, Capture and Communication of Financial Data Used in Accounting for Non-Routine Transactions or Activities. At December 31, 2004, we did not maintain effective controls related to identification, capture and communication of financial data used for accounting for non-routine transactions or activities. We identified control deficiencies related to the identification, capture and validation of pertinent information necessary to ensure the timely and accurate recording of non-routine transactions or activities, related to accounting for investments in unconsolidated affiliates. These control deficiencies resulted in the restatement of our 2002 and 2003 financial statements, as reflected in this annual report on Form 10-K. These control deficiencies could result in a misstatement in the aforementioned accounts that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented

39

or detected. Accordingly, management has determined that these control deficiencies constitute a material weakness.

Changes in Internal Control over Financial Reporting

      Changes in the Fourth Quarter 2004. There has been no change in our internal control over financial reporting during the fourth quarter of 2004 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

      Changes in 2005. Since December 31, 2004, we have taken action to correct the control deficiencies that resulted in the material weaknesses described above including implementing monitoring controls in our information technology areas over users who require unrestricted access to perform their job responsibilities. Other remedial actions have also been identified and are in the process of being implemented.

ITEM 9B.  OTHER INFORMATION

      None.

PART III

      Item 10, “Directors and Executive Officers of the Registrant;” 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;” 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, 2004 and 2003, of $925,000 and $500,000 were for professional services rendered by PricewaterhouseCoopers LLP 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 firm for the years ended December 31, 2004 and 2003.

Policy for Approval of Audit and Non-Audit Fees

      We are a 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 2005 annual meeting of stockholders.

40

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
	Consolidated Statements of Income and Comprehensive Income		16
	Consolidated Balance Sheets		17
	Consolidated Statements of Cash Flows		18
	Consolidated Statements of Stockholder’s Equity		19
	Notes to Consolidated Financial Statements		20
	Report of Independent Registered Public Accounting Firm		37
2. Financial statement schedules.
	Schedule II — Valuation and Qualifying Accounts		38
	All other schedules are omitted because they are not applicable, or the required information is disclosed in the financial statements or accompanying notes.
3. Exhibit list			42

41

TENNESSEE GAS PIPELINE COMPANY

EXHIBIT LIST

December 31, 2004

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

Exhibit
Number		Description
	*3.A	Restated Certificate of Incorporation dated May 11, 1999.
	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 TGP and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (Exhibit 4.1 to EPTP’s Form 10-K for 1997); First Supplemental Indenture dated as of March 13, 1997, between TGP and the Trustee (Exhibit 4.2 to EPTP’s 1997 Form 10-K); Second Supplemental Indenture dated as of March 13, 1997, between TGP and the Trustee (Exhibit 4.3 to EPTP’s 1997 Form 10-K); Third Supplemental Indenture dated as of March 13, 1997, between TGP and the Trustee (Exhibit 4.4 to EPTP’s 1997 Form 10-K); Fourth Supplemental Indenture dated as of October 9, 1998, between TGP and the Trustee (Exhibit 4.2 to our Form 8-K filed October 9, 1998); Fifth Supplemental Indenture dated June 10, 2002, between TGP 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 November 23, 2004, among El Paso Corporation, ANR Pipeline Company, 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 November 29, 2004). Amended and Restated Subsidiary Guarantee Agreement dated as of November 23, 2004, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.C to our Form 8-K filed November 29, 2004).
	10.B	Amended and Restated Security Agreement dated as of November 23, 2004, made by among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors 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 November 29, 2004).

42

Exhibit
Number		Description
	10.C	$3,000,000,000 Revolving Credit Agreement dated as of April 16, 2003 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company and ANR Pipeline Company, as Borrowers, the Lenders Party hereto, and JPMorgan Chase Bank, as Administrative Agent, ABN Amro Bank N.V. and Citicorp North America, Inc., as Co-Document Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as Joint Bookrunners and Co-Lead Arrangers. (Exhibit 99.1 to El Paso Corporation’s Form 8-K filed April 18, 2003); First Amendment to the $3,000,000,000 Revolving Credit Agreement and Waiver dated as of March 15, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co- Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents (Exhibit 10.A.1 to our 2003 First Quarter Form 10-Q); Second Waiver to the $3,000,000,000 Revolving Credit Agreement dated as of June 15, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents (Exhibit 10.A.2 to our 2003 Second Quarter Form 10-Q); Second Amendment to the $3,000,000,000 Revolving Credit Agreement and Third Waiver dated as of August 6, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents. (Exhibit 99.B to our Form 8-K filed August 10, 2004).
	10.D	$1,000,000,000 Amended and Restated 3-Year Revolving Credit Agreement dated as of April 16, 2003 among El Paso Corporation, El Paso Natural Gas Company and Tennessee Gas Pipeline Company, as Borrowers, The Lenders Party thereto, and JPMorgan Chase Bank, as Administrative Agent, ABN Amro Bank N.V. and Citicorp North America, Inc., as Co-Document Agents, Bank of America, N.A., as Syndication Agent, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as Joint Bookrunners and Co-Lead Arrangers. (Exhibit 99.2 to El Paso Corporation’s Form 8-K filed April 18, 2003).
	10.E	Security and Intercreditor Agreement dated as of April 16, 2003 among El Paso Corporation, the persons referred to therein as Pipeline Company Borrowers, the persons referred to therein as Grantors, each of the Representative Agents, JPMorgan Chase Bank, as Credit Agreement Administrative Agent and JPMorgan Chase Bank, as Collateral Agent, Intercreditor Agent, and Depository Bank. (Exhibit 99.3 to El Paso Corporation’s Form 8-K filed April 18, 2003).
	21	Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
	*31.A	Certification of Chief Executive Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002.
	*31.B	Certification of Chief Financial Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002.
	*32.A	Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.
	*32.B	Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.

43

Undertaking

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

44

SIGNATURES

      Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on the 29th day of March, 2005.

TENNESSEE GAS PIPELINE COMPANY

By:  /s/JOHN W. SOMERHALDER II
 

John W. Somerhalder II

Chairman of the Board

      Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated:

Signature	Title	Date
/s/ JOHN W. SOMERHALDER II (John W. Somerhalder II)	Chairman of the Board and Director (Principal Executive Officer)	March 29, 2005
/s/ STEPHEN C. BEASLEY (Stephen C. Beasley)	President and Director	March 29, 2005
/s/ GREG G. GRUBER (Greg G. Gruber)	Senior Vice President, Chief Financial Officer, Treasurer and Director (Principal Financial and Accounting Officer)	March 29, 2005

45

TENNESSEE GAS PIPELINE COMPANY

EXHIBIT INDEX

December 31, 2004

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

Exhibit
Number		Description
	*3.A	Restated Certificate of Incorporation dated May 11, 1999.
	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 TGP and Wilmington Trust Company (as successor to JPMorgan Chase Bank, formerly known as The Chase Manhattan Bank), as Trustee (Exhibit 4.1 to EPTP’s Form 10-K for 1997); First Supplemental Indenture dated as of March 13, 1997, between TGP and the Trustee (Exhibit 4.2 to EPTP’s 1997 Form 10-K); Second Supplemental Indenture dated as of March 13, 1997, between TGP and the Trustee (Exhibit 4.3 to EPTP’s 1997 Form 10-K); Third Supplemental Indenture dated as of March 13, 1997, between TGP and the Trustee (Exhibit 4.4 to EPTP’s 1997 Form 10-K); Fourth Supplemental Indenture dated as of October 9, 1998, between TGP and the Trustee (Exhibit 4.2 to our Form 8-K filed October 9, 1998); Fifth Supplemental Indenture dated June 10, 2002, between TGP 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 November 23, 2004, among El Paso Corporation, ANR Pipeline Company, 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 November 29, 2004). Amended and Restated Subsidiary Guarantee Agreement dated as of November 23, 2004, made by each of the Subsidiary Guarantors in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.C to our Form 8-K filed November 29, 2004).
	10.B	Amended and Restated Security Agreement dated as of November 23, 2004, made by among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors 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 November 29, 2004).

Exhibit
Number		Description
	10.C	$3,000,000,000 Revolving Credit Agreement dated as of April 16, 2003 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company and ANR Pipeline Company, as Borrowers, the Lenders Party hereto, and JPMorgan Chase Bank, as Administrative Agent, ABN Amro Bank N.V. and Citicorp North America, Inc., as Co-Document Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as Joint Bookrunners and Co-Lead Arrangers. (Exhibit 99.1 to El Paso Corporation’s Form 8-K filed April 18, 2003); First Amendment to the $3,000,000,000 Revolving Credit Agreement and Waiver dated as of March 15, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co- Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents (Exhibit 10.A.1 to our 2003 First Quarter Form 10-Q); Second Waiver to the $3,000,000,000 Revolving Credit Agreement dated as of June 15, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents (Exhibit 10.A.2 to our 2003 Second Quarter Form 10-Q); Second Amendment to the $3,000,000,000 Revolving Credit Agreement and Third Waiver dated as of August 6, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents. (Exhibit 99.B to our Form 8-K filed August 10, 2004).
	10.D	$1,000,000,000 Amended and Restated 3-Year Revolving Credit Agreement dated as of April 16, 2003 among El Paso Corporation, El Paso Natural Gas Company and Tennessee Gas Pipeline Company, as Borrowers, The Lenders Party thereto, and JPMorgan Chase Bank, as Administrative Agent, ABN Amro Bank N.V. and Citicorp North America, Inc., as Co-Document Agents, Bank of America, N.A., as Syndication Agent, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as Joint Bookrunners and Co-Lead Arrangers. (Exhibit 99.2 to El Paso Corporation’s Form 8-K filed April 18, 2003).
	10.E	Security and Intercreditor Agreement dated as of April 16, 2003 among El Paso Corporation, the persons referred to therein as Pipeline Company Borrowers, the persons referred to therein as Grantors, each of the Representative Agents, JPMorgan Chase Bank, as Credit Agreement Administrative Agent and JPMorgan Chase Bank, as Collateral Agent, Intercreditor Agent, and Depository Bank. (Exhibit 99.3 to El Paso Corporation’s Form 8-K filed April 18, 2003).
	21	Omitted pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
	*31.A	Certification of Chief Executive Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002.
	*31.B	Certification of Chief Financial Officer pursuant to sec. 302 of the Sarbanes-Oxley Act of 2002.
	*32.A	Certification of Chief Executive Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.
	*32.B	Certification of Chief Financial Officer pursuant to 18 U.S.C. sec. 1350 as adopted pursuant to sec. 906 of the Sarbanes-Oxley Act of 2002.