UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________

Form 10-Q

(Mark One)

R	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended September 30, 2010
	For the quarterly period ended March 31, 2011
	OR
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to

Commission File Number 1-4101

________________

Tennessee Gas Pipeline Company

(Exact Name of Registrant as Specified in Its Charter)

Delaware	74-1056569
(State or Other Jurisdiction of 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

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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

	Large accelerated filer o	Accelerated filer o		Non-accelerated filer þ	Small reporting company o
			(Do not check if a smaller reporting company)

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

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Common stock, par value $5 per share. Shares outstanding on ~~November 5~~May 6, ~~2010~~2011: 208

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

TENNESSEE GAS PIPELINE COMPANY

	TENNESSEE GAS PIPELINE COMPANY

	TABLE OF CONTENTS

	Caption	Page

	PART I — Financial Information
Item 1.	Financial Statements	1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	8
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	*
Item 4.	Controls and Procedures	11

	PART II — Other Information
Item 1.	Legal Proceedings	12
Item 1A.	Risk Factors	12
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	*
Item 3.	Defaults Upon Senior Securities	*
Item 4.	(Removed and Reserved)	12
Item 5.	Other Information	12
Item 6.	Exhibits	13
	Signatures	14

TABLE OF CONTENTS

	Caption	Page
	PART I — Financial Information
Item 1.	Financial Statements	1
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	9
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	*
Item 4.	Controls and Procedures	14
	PART II — Other Information
Item 1.	Legal Proceedings	15
Item 1A.	Risk Factors	15
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	*
Item 3.	Defaults Upon Senior Securities	*
Item 4.	(Removed and Reserved)	15
Item 5.	Other Information	15
Item 6.	Exhibits	16
	Signatures	17

____________

* 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 H to Form 10-Q.

*	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 H to Form 10-Q.


	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
	TBtu = trillion British thermal units

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

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

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

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

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

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PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

TENNESSEE GAS PIPELINE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions)

(Unaudited)

	Quarter Ended September 30,						Nine Months Ended September 30,
	Quarter Ended March 31,
	2010			2009			2010			2009
	2011			2010
Operating revenues	$	~~213~~234		$	~~221~~224		$	~~637~~		$	~~704~~
Operating expenses
Operation and maintenance		8175			9773			~~235~~			~~274~~
Depreciation and amortization		5348			4648			~~148~~			~~139~~
Taxes, other than income taxes		1416			14			41			43
		148			157			424			456
		139			135
Operating income		6595			6489			~~213~~			~~248~~
Earnings from unconsolidated affiliate		4			34			11			8
Other income, net		78			15			16			8
Interest and debt expense		(3837	)		(4038	)		~~(113~~	)		~~(117~~	)
Affiliated interest income, net		43			43			11			12
Income before income taxes		4273			3263			~~138~~			~~159~~
Income taxes		1428			1224			51			61
Net income	$	2845		$	2039		$	87		$	98

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)

(Unaudited)

	September 30, 2010		December 31, 2009
	March 31, 2011		December 31, 2010
ASSETS
Current assets
Cash and cash equivalents	$	—	$	—
Accounts and notes receivable
Customer		1437		1224
Affiliates		~~464~~370		~~152~~378
Other		4845		1351
Materials and supplies		4144		4344
Deferred income taxes		4443		4443
Other		115		85
Total current assets		~~622~~544		~~272~~545
Property, plant and equipment, at cost		4,~~844~~974		4,~~680~~951
Less accumulated depreciation and amortization		1,~~044~~050		~~936~~1,056
		3,800		3,744
		3,924		3,895
Additional acquisition cost assigned to utility plant, net		1,~~932~~913		1,~~963~~923
Total property, plant and equipment, net		5,~~732~~837		5,~~707~~818
Other assets
Notes receivable from affiliates		587		939
Note receivable from affiliate		608		617
Investment in unconsolidated affiliate		5759		7956
Other		6878		7076
		712		1,088
		745		749
Total assets	$	7,~~066~~126	$	7,~~067~~112
LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities
Accounts payable
Trade	$	4756	$	6090
Affiliates		6534		7238
Other		4253		4757
Taxes payable		33		94
Current maturities of long-term debt		86		86
Contractual deposits		36		31
Taxes payable		14		23
Asset retirement obligations		32		66
Contractual deposits		28		28
Asset retirement obligations		29		28
Accrued interest		47		33
Regulatory liabilities		7378		2878
Other		1636		2438
Total current liabilities		~~391~~461		~~455~~499
Long-term debt		1,849		1,846
Long-term debt, less current maturities		1,766		1,765
Other liabilities
Deferred income taxes		1,~~401~~446		1,~~351~~422
Regulatory liabilities		~~104~~74		~~153~~90
Other		3633		6435
		1,541		1,568
		1,553		1,547
Commitments and contingencies (Note 3)
Stockholder’s equity
Common stock, par value $5 per share; 300 shares authorized; 208 shares issued and outstanding		—		—
Additional paid-in capital		2,209		2,209
Retained earnings		1,~~076~~137		1,~~323~~092
Note receivable from affiliate		—		(334	)
Total stockholder’s equity		3,346		3,301
Total stockholder’s equity		3,285		3,198
Total liabilities and stockholder’s equity	$	7,126	$	7,112
Total liabilities and stockholder’s equity	$	7,066	$	7,067

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)

	Nine Months Ended September 30,
	Quarter Ended March 31,
	2010			2009
	2011			2010
Cash flows from operating activities
Net income	$	8745		$	9839
Adjustments to reconcile net income to net cash from operating activities
Depreciation and amortization		~~148~~48			~~139~~48
Deferred income taxes		4924			11
Earnings from unconsolidated affiliate, adjusted for cash distributions		22(3	)		2(1	)
Other non-cash income items		(6	)		(1	)
Asset and liability changes		(~~107~~35	)		99(35	)
Net cash provided by operating activities		~~193~~73			~~350~~61
Cash flows from investing activities
Capital expenditures		(~~193~~96	)		(~~251~~57	)
Net change in notes receivable from affiliates		327			(277	)
Net change in note receivable from affiliate		23			(6	)
Other		7—			—3
Net cash provided by (used in) investing activities		141			(528	)
Net cash used in investing activities		(73	)		(60	)
Cash flows from financing activities
Net change in cash and cash equivalents		—			1
Net proceeds from the issuance of long-term debt		—			234
Dividend paid to parent		(334	)		—
Other		—			(1	)
Net cash provided by (used in) financing activities		(334	)		233
Net change in cash and cash equivalents		—			55
Cash and cash equivalents
Beginning of period		—			—
End of period	$	—		$	551

See accompanying notes.

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TENNESSEE GAS PIPELINE COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

We ~~are an indirect wholly owned subsidiary of El Paso Corporation (El Paso). We~~ prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission. ~~Because~~As ~~this is~~ an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. generally accepted accounting principles., ~~You~~and you should read this report along with our ~~2009~~2010 Annual Report on Form 10-K~~, which contains a summary of our significant accounting policies and other disclosures~~. The financial statements as of ~~September~~March 3031, ~~2010~~2011, and for the quarters ~~and nine months~~ ended ~~September~~March 3031, ~~2010~~2011 and ~~2009~~2010, are unaudited. We ~~derived~~The ~~the~~ condensed consolidated balance sheet as of December 31, ~~2009~~2010, was derived from the audited balance sheet filed in our ~~2009~~2010 Annual Report on Form 10-K. In our opinion, we have made adjustments, all of which are of a normal, recurring nature to fairly present our interim period results. Due to the seasonal nature of our business, information for interim periods may not be indicative of our operating results for the entire year. Our disclosures in this Form 10-Q are an update to those provided in our 2010 Annual Report on Form 10-K.

Significant Accounting Policies

~~The~~There ~~following~~were isno anchanges ~~update~~in ofthe ~~our~~ significant accounting policies described in our 2010 Annual Report on Form 10-K and no significant accounting pronouncements issued ~~and~~but ~~adopted~~not ~~during~~yet ~~the~~adopted ~~nine~~as ~~months~~of ~~ended~~March ~~September 30~~31, ~~2010~~2011.

~~Transfers~~2. of Financial Assets. On January 1, 2010, we adopted an accounting standards update for financial asset transfers. Among other items, this update requires the sale of an entire financial asset or a proportionate interest in a financial asset in order to qualify for sale accounting. These changes were effective for sales of financial assets occurring on or after January 1, 2010. In January 2010, we terminated our prior accounts receivable sales program under which we previously sold a senior interest in certain accounts receivable to a third party financial institution (through a wholly-owned special purpose entity). As a result, the adoption of this accounting standards update did not have a material impact on our financial statements. Upon termination of the prior accounts receivable sales program, we entered into a new accounts receivable sales program under which we sell certain accounts receivable in their entirety to the third party financial institution (through a wholly-owned special purpose entity). The transfer of these receivables qualifies for sale accounting under the provisions of this accounting standards update. We present the cash flows related to the prior and new accounts receivable sales programs as operating cash flows in our statements of cash flows. For further information, see Note 4.Instruments

~~Variable~~At ~~Interest~~March ~~Entities. On~~31, ~~January~~2011 1and December 31, 2010, wethe ~~adopted~~carrying anamounts ~~accounting~~of ~~standards~~cash ~~update~~and ~~for~~cash ~~variable~~equivalents ~~interest~~and ~~entities~~trade ~~that~~receivables ~~revises~~and ~~how~~payables ~~companies~~represent ~~determine~~fair value because of the ~~primary~~short-term ~~beneficiary~~nature of these ~~entities~~instruments. At March 31, ~~among~~2011 ~~other~~and ~~changes.~~December ~~Companies~~31, ~~are~~2010, ~~now~~we ~~required~~had toan ~~use~~interest abearing ~~qualitative~~note ~~approach~~receivable ~~based~~from onEl ~~their~~Paso ~~responsibilities~~Corporation (El Paso) of $953 million and ~~power~~$976 ~~over~~million ~~the~~due ~~entities’~~upon ~~operations~~demand, ~~rather~~with ~~than~~ a ~~quantitative~~variable ~~approach~~interest inrate ~~determining~~of ~~the~~1.5% ~~primary~~at ~~beneficiary~~each asbalance ~~previously~~sheet ~~required~~date. ~~The~~While ~~adoption~~we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this ~~accounting~~note ~~standards~~receivable ~~update~~approximates ~~did~~its ~~not~~carrying ~~have~~value adue ~~material~~to ~~impact~~the note being due on ~~our~~demand ~~financial~~and ~~statements~~the market-based nature of the interest rate.

2. Fair Value of Financial Instruments

At September 30, 2010 and December 31, 2009, the carrying amounts of cash and cash equivalents and current receivables and payables represented fair value because of the short-term nature of these instruments. At September 30, 2010 and December 31, 2009, we had an interest bearing note receivable from El Paso of approximately $1.0 billion due upon demand, with a variable interest rate of 1.5% in both periods. While we are exposed to changes in interest income based on changes to the variable interest rate, the fair value of this note receivable approximates its carrying value due to the note being due on demand and the market-based nature of the interest rate.

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In addition, the carrying amounts of our long-term debt and their estimated fair values, which are based on quoted market prices for the same or similar issues, are as follows:

	September 30, 2010				December 31, 2009
	March 31, 2011				December 31, 2010
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Long-term debt	$	1,849	$	2,081	$	1,846	$	2,086
Long-term debt, including current maturities	$	1,852	$	2,167	$	1,851	$	2,071

3. Commitments and Contingencies

Legal Proceedings

We and our affiliates are named defendants in numerous legal proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we ~~had~~believe nowe ~~accrual~~have ~~for~~established ~~our~~appropriate ~~outstanding~~reserves ~~legal~~for ~~proceedings~~these ~~at September 30, 2010~~matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and ~~establish~~adjust our accruals accordingly, and these adjustments could be material. As of March 31, 2011, we had accrued less than $1 million for all of our outstanding legal proceedings.

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Rates and Regulatory Matter

Rate Case. In November 2010, we filed a rate case with the Federal Energy Regulatory Commission (FERC) proposing an increase in our base tariff rates, including a proposed change in our rate structure. In December 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to June 1, 2011, subject to refund, the outcome of a hearing and other proceedings. At this time, the outcome of this matter is not determinable.

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 of the disposal or release of specified substances at current and former operating sites. At ~~September~~March ~~30, 2010 and December~~ 31, ~~2009~~2011, weour ~~had~~accrual ~~accrued~~was approximately $64 million ~~and $5 million~~ for expected remediation costs and associated onsite, offsite and groundwater technical studies and for related environmental legal costs; however, we estimate that our exposure could be as high as $87 million. Our ataccrual ~~September~~includes ~~30,~~approximately ~~2010~~$1 million for environmental contingencies related to properties we previously owned.

Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will ~~expend~~spend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities.

Polychlorinated Biphenyls (PCB) Cost Recoveries and Refund. Since 1994, we have been conducting remediation activities at certain of our compressor stations associated with PCBs and other hazardous materials. We have collected amounts, substantially in excess of remediation costs to date, through a surcharge to our customers under a settlement approved by the ~~Federal Energy Regulatory Commission (~~FERC) in November of 1995. In November 2009, the FERC approved an amendment to the 1995 settlement that provides for interim refunds over a three year period of approximately $157 million of our collected amounts plus interest of 8%. Through ~~September~~March 3031, ~~2010~~2011, we have refunded approximately $4978 million to our customers. Our refund obligations are recorded as regulatory liabilities on our balance sheet and as of ~~September~~March 3031, ~~2010~~2011, we have classified approximately $6778 million as current liabilities based on the timing of when these amounts are expected to be refunded to our customers.

Superfund Matters. Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as Superfund, or state equivalents for four active sites. Liability under the federal CERCLA statute may be joint and several, meaning that we could be required to pay in excess of our pro rata share of remediation costs. We consider the financial strength of other PRPs in estimating our liabilities. Accruals for these issues are included in the environmental reserve discussed above.

For 2011, we estimate that our total remediation expenditures will be approximately $1 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $11 million in the aggregate for the remainder of 2011 through 2015, including capital expenditures associated with the impact of the Environmental Protection Agency rule on emissions of hazardous air pollutants from reciprocating internal combustion engines which are subject to regulations with which we have to be in compliance by October 2013.

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, regulations and orders of regulatory agencies, as well as claims for damages to property and the environment or injuries to employees and other persons resulting from our current or past operations, could result in substantial costs and liabilities in the future. As this information becomes available, or other relevant developments occur, we will adjust our accrual amounts accordingly. While there are still uncertainties related to the ultimate costs we may incur, based upon our evaluation and experience to date, we believe our reserves are adequate.

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For the remainder of 2010, we estimate that our total remediation expenditures will be approximately $1 million, most of which will be expended under government directed clean-up plans. In addition, we expect to make capital expenditures for environmental matters of approximately $11 million in the aggregate for the remainder of 2010 through 2014. Included in this amount is approximately $7 million to be expended from 2010 to 2013 associated with the impact of the Environmental Protection Agency (EPA) rule related to emissions of hazardous air pollutants from reciprocating internal combustion engines which was finalized in August 2010. Our engines that are subject to the regulations have to be in compliance by October 2013.

Rates and Regulatory Matter

Rate Case. If we determine there is a sufficient change in our revenues, costs or billing determinants, we have the option to file a rate case with the FERC to provide an opportunity to recover our prudently incurred costs. We anticipate filing a new rate case in November 2010 with revised rates expected to become effective June 2011.

Other Commitments

For a further discussion of our purchase obligations and other commercial commitments, see our 2010 Annual Report on Form 10-K.

Capital Commitments. At September 30, 2010, we had capital commitments of approximately $263 million primarily related to our 300 Line expansion project, of which $40 million will be spent in the remainder of 2010, $218 million in 2011 and $5 million in 2012.

Asset Retirement Obligations. At September 30, 2010 and December 31, 2009, we had total asset retirement liabilities of $34 million and $91 million, and we have classified $32 million and $66 million as current liabilities on our balance sheets.

4. Accounts Receivable Sales Program

~~During~~We ~~2009,~~participate wein ~~had~~ an ~~agreement to sell a senior interest in certain~~ accounts receivable ~~(which~~sales ~~are~~program ~~short-term~~where ~~assets~~we ~~that~~sell ~~generally~~receivables ~~settle~~in ~~within~~their 60entirety ~~days)~~ to a third party financial institution (through a wholly-owned special purpose entity)~~, and we retained a subordinated interest in those receivables~~. The sale of ~~the senior interest qualified for sale accounting and was conducted to accelerate cash from~~ these ~~receivables,~~accounts ~~the~~receivable ~~proceeds from~~ (which ~~were~~are ~~used~~short-term toassets ~~increase~~that ~~liquidity~~generally ~~and~~settle ~~lower~~within ~~our~~60 ~~overall~~days) ~~cost~~qualify offor ~~capital. During the quarter and nine months ended September 30, 2009, we received $117 million and $356 million of cash related to the~~ sale ofaccounting. The ~~the~~third ~~senior~~party ~~interest,~~financial ~~collected~~institution ~~$98~~involved ~~million~~in ~~and~~our ~~$373~~accounts ~~million~~receivable ~~from~~sales ~~the~~program ~~subordinated~~acquires ~~interest~~interests ~~we retained~~ in ~~the~~various ~~receivables,~~financial assets and ~~recognized~~issues acommercial ~~loss~~paper ofto ~~less~~fund ~~than~~those ~~$1 million on these transactions~~acquisitions. AtWe ~~December~~do ~~31,~~not ~~2009,~~consolidate the third party financial institution ~~held~~because ~~$40 million of senior interest and~~ we ~~held~~do ~~$43~~not ~~million~~have of subordinated interest. Our subordinated interest is reflected in accounts receivable on our balance sheet. In January 2010, we terminated this accounts receivable sales program and paid $40 million to acquire the ~~senior~~power ~~interest. We reflected the cash flows related~~ to ~~the~~control, ~~accounts receivable sold under this program~~direct, ~~changes~~or inexert ~~our~~significant ~~retained~~influence ~~subordinated~~over ~~interest,~~its ~~and~~overall ~~cash~~activities ~~paid~~since toour ~~terminate~~receivables ~~the~~do ~~program,~~not ascomprise ~~operating~~a ~~cash~~significant ~~flows~~portion ~~on our statement~~ of ~~cash~~its ~~flows~~operations.

In the first quarter of 2010, we entered into a new accounts receivable sales program to continue to sell accounts receivable to the third party financial institution that qualify for sale accounting under the updated accounting standards related to financial asset transfers. Under this program, we sell receivables in their entirety to the third party financial institution (through a wholly-owned special purpose entity). As of September 30, 2010, the third party financial institution held $78 million of the accounts receivable we sold under the program. In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and receive an additional amount upon the collection of the underlying receivables~~. Our~~ ~~ability~~(which towe ~~recover~~refer ~~this~~to ~~additional~~as ~~amount~~a isdeferred ~~based~~purchase ~~solely on the collection of the underlying receivables~~price). ~~During~~Our ~~the~~ability ~~quarter~~to ~~and~~recover ~~nine months ended September 30, 2010, we received $117 million and $390 million of cash up front from~~ the ~~sale~~deferred ofpurchase ~~the~~price ~~receivables~~is ~~and~~based ~~received~~solely anon ~~additional $128 million and $306 million of cash upon~~ the collection of the underlying receivables. As ofThe ~~September~~table ~~30,~~below ~~2010,~~contains weinformation ~~had not collected approximately $39 million~~ related to our accounts receivable sales, which is reflected as other accounts receivable on our balance sheet (and was initially recorded at an amount which approximates its fair value using observable inputs other than quoted prices in active markets). We recognized a loss of less than $1 million on our accounts receivable sales during the quarter and nine months ended September 30, 2010. Because the cash received up front and the cash received as the underlying receivables are collected relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the new accounts receivable sales program ~~as operating cash flows on our statement of cash flows~~.

	Quarter Ended March 31,
	2011		2010
	(In millions)
Accounts receivable sold to the third-party financial institution(1)	$	204	$	227
Cash received for accounts receivable sold under the program		118		160
Deferred purchase price related to accounts receivable sold		86		67
Cash received related to the deferred purchase price		84		85
Amount paid in conjunction with terminated program(2)		—		40

_______________

(1)	During the quarters ended March 31, 2011 and 2010, losses recognized on the sale of accounts receivable were immaterial.

(2)	In January 2010, we terminated our previous accounts receivable sales program and paid $40 million to acquire the related senior interests in certain receivables under that program. See our 2010 Annual Report on Form 10-K for further information.

	March 31,		December 31,
	2011		2010
	(In millions)
Accounts receivable sold and held by third-party financial institution	$	76	$	75
Uncollected deferred purchase price related to accounts receivable sold(1)		37		35

_______________

(1)	Initially recorded at an amount which approximates its fair value using observable inputs other than quoted prices in active markets.

The deferred purchase price related to the accounts receivable sold is reflected as other accounts receivable on our balance sheet. Because the cash received up front and the deferred purchase price relate to the sale or ultimate collection of the underlying receivables, and are not subject to significant other risks given their short term nature, we reflect all cash flows under the accounts receivable sales program as operating cash flows on our statement of cash flows. Under the accounts receivable sales program, we service the underlying receivables for a fee. The fair value of this servicing agreement, as well as the fees earned, were not material to our financial statements for the quarters ended March 31, 2011 and 2010.

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Under both the prior and current accounts receivable sales programs, we serviced the underlying receivables for a fee. The fair value of these servicing agreements as well as the fees earned were not material to our financial statements for the periods ended September 30, 2010 and 2009.

The third party financial institution involved in both of these accounts receivable sales programs acquires interests in various financial assets and issues commercial paper to fund those acquisitions. We do not consolidate the third party financial institution because we do not have the power to direct its overall activities (and do not absorb a majority of its expected losses) since our receivables do not comprise a significant portion of its operations.

5. Investment in Unconsolidated Affiliate and Transactions with Affiliates

Investment in Unconsolidated Affiliate

We have a 50 percent ownership interest in Bear Creek Storage Company, L.L.C. (Bear Creek), a joint venture with Southern Natural Gas Company, our affiliate. For the ~~nine~~quarters ~~months~~ ended ~~September~~March 3031, ~~2010~~2011 and ~~2009~~2010, we received ~~approximately~~$1 million and $103 million in cash distributions from Bear Creek. Also, during the third quarter of 2010, Bear Creek utilized its note receivable balance under the cash management program with El Paso to pay a cash distribution to its partners, including $23 million to us. In October 2010, we received an additional $4 million in cash distributions.

Summarized financial information offor our proportionate share of ~~our~~Bear ~~unconsolidated~~Creek ~~affiliate~~ for the ~~periods~~quarters ended ~~September~~March 31 30 is presented as follows:

	Quarter Ended September 30,				Nine Months Ended September 30,
	2011		2010
	2010		2009		2010		2009
	(In millions)
	(In millions)
Operating results data:
Operating results data:
Operating revenues	$	5	$	5
Operating revenues	$	5	$	5	$	15	$	14
Operating expenses		1		1
Operating expenses		1		2		4		6
Income from continuing operations and net income		4		4
Income from continuing operations and net income		4		3		11		8

Transactions with Affiliates

Cash Management Program ~~and Other Notes Receivable~~. 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. El Paso uses the cash management program to settle intercompany transactions between participating affiliates. We have historically advanced cash to El Paso in exchange for an affiliated note receivable that is due upon demand. At ~~September~~March 3031, ~~2010~~2011 and December 31, ~~2009~~2010, we had a note receivable from El Paso of ~~approximately~~$953 million and $~~1.0~~976 ~~billion~~million. We classified ~~approximately~~ $~~451~~345 million of this receivable as current on our balance sheet at ~~September~~March 3031, ~~2010~~2011, based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. The interest rate on this ~~variable~~note ~~rate~~is ~~note~~variable and was 1.5% at ~~September~~March 3031, ~~2010~~2011 and December 31, ~~2009~~2010.

Income Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. At March 31, 2011 and December 31, ~~2009~~2010, we had a ~~non-interest~~net ~~bearing~~current ~~note~~income tax receivable of $~~334~~2 million ~~from~~and an$4 Elmillion. ~~Paso~~The ~~affiliate~~majority ~~reflected~~of asthese abalances, ~~reduction~~as ofwell ~~our~~as ~~stockholder’s~~deferred ~~equity.~~income ~~During~~taxes ~~the~~and ~~third~~amounts ~~quarter~~associated ofwith ~~2010,~~the weresolution ~~collected~~of ~~this~~unrecognized ~~note~~tax ~~receivable~~benefits, ~~and~~will ~~then~~become ~~immediately~~payable ~~distributed~~to ~~the~~or ~~cash~~receivable ~~received~~from toEl ~~our parent~~Paso.

Other Affiliate Balances. At March 31, 2011 and December 31, 2010, we had contractual deposits from our affiliates of $10 million.

Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of business. For a further discussion of our affiliated transactions, see our 2010 Annual Report on Form 10-K. The following table shows revenues and charges from our affiliates for the quarters ended March 31:

	2011		2010
	(In millions)
Revenues(1)	$	43	$	5
Operation and maintenance expenses		17		21
Reimbursements of operating expenses		17		15

_______________

(1)	During the first quarter of 2011, we sold 5.8 TBtu of natural gas not used in operations to our affiliate, El Paso Marketing, L.P.

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Income Taxes. El Paso files consolidated U.S. federal and certain state tax returns which include our taxable income. In certain states, we file and pay taxes directly to the state taxing authorities. At September 30, 2010 and December 31, 2009, we had net federal and state income taxes payable of $5 million and $75 million. The majority of these balances, as well as deferred income taxes and amounts associated with the resolution of unrecognized tax benefits, will become payable to El Paso.

Other Affiliate Balances. At September 30, 2010 and December 31, 2009, we had contractual deposits from our affiliates of $9 million.

Affiliate Revenues and Expenses. We enter into transactions with our affiliates within the ordinary course of business. For a further discussion of our affiliated transactions, see our 2009 Annual Report on Form 10-K. The following table shows revenues and charges from our affiliates for the periods ended September 30:

	Quarter Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(In millions)
Revenues from affiliates	$	5	$	4	$	15	$	12
Operation and maintenance expenses from affiliates		17		18		58		52
Reimbursement of operating expenses charged to affiliates		14		11		44		34

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The information required by this Item 2 is presented in a reduced disclosure format pursuant to General Instruction H to Form 10-Q. In addition, this Item 2 updates, and should be read in conjunction with the information disclosed in our ~~2009~~2010 Annual Report on Form 10-K, and the financial statements and notes presented in Item 1 of this Quarterly Report on Form 10-Q.

Results of Operations

~~Our~~Beginning January 1, 2011, our management uses segment earnings before interest expense and income taxes (Segment EBIT) as a measure to assess the operating results and effectiveness of our business, which consists of consolidated operations as well as an investment in an unconsolidated affiliate. We believe Segment EBIT is useful to investors to provide them with the same measure used by Elour ~~Paso~~ management to evaluate our performance and so that investors may evaluate our operating results without regard to our financing methods. We define Segment EBIT as net income adjusted for items such as (i) interest and debt expense, (ii) affiliated interest income, and (iii) income taxes. WeSegment ~~exclude interest and debt expense from this measure so that investors may evaluate our operating results without regard to our financing methods.~~ EBIT may not be comparable to measures used by other companies. Additionally, Segment EBIT should be considered in conjunction with net income, income before income taxes and other performance measures such as operating income or operating cash flows. Below is a reconciliation of our Segment EBIT to net income, our throughput volumes and an analysis and discussion of our results for the ~~nine~~quarter ~~months~~ ended ~~September~~March 3031, ~~2010~~2011 compared with the same period in ~~2009~~2010.

Operating Results:

	2010			2009
	2011			2010
	(In millions, except for volumes)
Operating revenues	$	~~637~~234		$	~~704~~224
Operating expenses		(~~424~~139	)		(~~456~~135	)
Operating income		~~213~~95			~~248~~89
Earnings from unconsolidated affiliate		114			84
Other income, net		168			85
EBIT		240			264
Segment EBIT		107			98
Interest and debt expense		(~~113~~37	)		(~~117~~38	)
Affiliated interest income, net		113			123
Income taxes		(5128	)		(6124	)
Net income	$	8745		$	9839
Throughput volumes (BBtu/d)		46,~~950~~424			45,~~650~~491

Segment EBIT Analysis:

	Variance
	Operating Revenue			Operating Expense			Other		Total
	Favorable/(Unfavorable)
	(In millions)
Gas not used in operations and other natural gas sales	$	~~(67~~9	)	$	141		$	—	$	~~(53~~10	)
Expansions		6			(3	)		8		11
AFUDC on expansions		—			—			3		3
Reservation and other services revenues		(7	)		—			—		(7	)
Operating and general and administrative expenses		—			(3	)		—		(3	)
Operating and general and administrative expenses		—			19			—		19
Other(1)		1			(2	)		—		(1	)
Hurricane repairs		—			6			—		6
Total impact on Segment EBIT	$	10		$	(4	)	$	3	$	9
Other(1)		1			(4	)		3		—
Total impact on EBIT	$	(67	)	$	32		$	11	$	(24	)

_______________

(1)	Consists of individually insignificant items.

Gas Not Used in Operations and Other Natural Gas Sales. During the nine months ended September 30, 2010, our EBIT decreased $67 million primarily due to lower average realized prices on operational sales as compared to the same period in 2009. Our EBIT was favorably impacted by $14 million due to lower electric compression expenses from decreased utilization. For a further discussion of gas not used in operations and other natural gas sales, see our 2009 Annual Report on Form 10-K.8

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~~Expansions~~Gas Not Used in Operations and Other Natural Gas Sales. InDuring ~~2009~~the quarter ended March 31, we2011, ~~placed~~our ~~several~~Segment ~~expansion~~EBIT ~~projects~~was infavorably ~~service~~impacted ~~including~~by ~~the~~$16 ~~Carthage~~million ~~expansion~~due into ~~May,~~higher ~~the~~volumes ~~Concord~~and ~~Lateral~~realized ~~expansion~~prices inon ~~October,~~operational and ~~the~~other ~~Blue~~gas ~~Water~~sales, ~~expansion~~partially inoffset ~~November.~~by Aslower aretained ~~result,~~fuel ~~for~~volumes ~~the~~in ~~nine~~excess ~~months~~of ~~ended~~fuel ~~September~~used ~~30,~~in ~~2010,~~operations ~~our~~and ~~revenues~~lower ~~increased~~prices of approximately $11 million, as compared towith the same period in ~~2009~~2010. WeIn ~~capitalize~~addition, aour ~~carrying~~Segment ~~cost~~EBIT ~~(an~~increased ~~allowance~~by ~~for~~$3 ~~funds~~million ~~used~~due ~~during~~to ~~construction~~favorable revaluations of retained fuel volumes. Our future earnings may be impacted positively or ~~AFUDC)~~negatively depending on ~~equity~~ ~~funds~~changes ~~related~~in tothroughput ~~our~~and ~~construction~~fluctuations ofin ~~long-lived~~natural ~~assets~~gas prices. ~~During~~We continue to explore options to minimize the ~~nine~~price ~~months~~volatility ~~ended~~associated ~~September~~with ~~30,~~these ~~2010,~~operational wepipeline ~~benefited~~activities. As ~~from~~a result of our rate case filed with the FERC which proposes an increase in ~~other~~base ~~income~~tariff rates effective June 1, 2011, the percentage of ~~approximately~~our $8revenues ~~million~~derived ~~associated~~from ~~with~~reservations ~~the~~charges ~~pretax~~may ~~equity~~increase ~~portion~~and oftherefore ~~AFUDC~~may onreduce the impacts to our ~~expansion~~Segment ~~projects~~EBIT due to excess fuel recoveries.

~~Listed~~AFUDC ~~below~~on ~~are~~Expansions. ~~significant~~We ~~updates~~capitalize a carrying cost (an allowance for funds used during construction or AFUDC) on funds related to our ~~expansion~~construction ~~projects~~of ~~discussed~~long-lived inassets that is recorded as other income on our ~~2009~~income ~~Annual~~statements. ~~Report~~During the quarter ended March 31, 2011, we benefited from an increase in other income of approximately $3 million associated with the equity portion of AFUDC primarily on ~~Form~~our ~~10-K~~300 Line Project.

·Listed ~~300~~below ~~Line~~are ~~Expansion.~~significant ~~During~~updates ~~2010,~~to ~~the~~our ~~FERC~~backlog ~~issued~~of aprojects ~~favorable~~discussed ~~environmental~~further ~~assessment~~in ~~and~~our ~~we received certificate authorization from the FERC to construct the expansion. In June~~ 2010, weAnnual ~~commenced~~Report ~~construction~~ on ~~our~~Form ~~compression facilities related to this project~~10-K.

· Northeast Upgrade Project. In 2010, we entered into precedent agreements with two shippers to provide 620 MMcf/d of additional firm transportation service from receipt points in the Marcellus shale basin to an interconnect in New Jersey.

•	300 Line Project. In the first quarter of 2011, we began construction on the pipeline and the remaining compressor facilities and we expect to place the project in service in November 2011.

•	Northeast Upgrade Project. In March 2011, we filed an application with the FERC for certificate authorization to construct this project and we anticipate receiving approval in the fourth quarter of 2011. The project is anticipated to be placed in service in November 2013.

·Operating ~~Northeast~~and ~~Supply~~General ~~Diversification~~and ~~Project.~~Administrative Expenses. During ~~2010, we entered into precedent agreements with three shippers to provide approximately 250 MMcf/d of additional firm transportation service from receipt points in~~ the ~~Marcellus~~quarter ~~shale~~ended ~~basin~~March to31, ~~delivery~~2011, ~~points~~our inoperating ~~the~~and ~~New~~general ~~York~~ and ~~New~~administrative ~~England~~expenses ~~markets.~~were ~~Total~~higher ~~estimated~~compared ~~cost of this project is less than $100 million. Subject~~ to ~~FERC and other approvals,~~ the ~~project~~same isperiod ~~expected to commence construction~~ in ~~the~~2010 ~~first~~primarily ~~half~~due ofto ~~2012~~higher payroll and isprofessional ~~anticipated~~fees, topartially beoffset ~~placed~~by inlower ~~service~~allocated incosts ~~the~~from ~~fourth~~El ~~quarter of 2012~~Paso.

~~Reservation~~Regulatory and Other Services Revenues. During the nine months ended September 30, 2010, throughput volumes on our system increased by six percent compared to the same period in 2009; however, revenues were lower by approximately $11 million because long-haul transports decreased due to a shift in receipts from the Gulf Coast region to the Rockies Express Pipeline interconnect and the Marcellus shale basin, which is short-haul transportation and subject to lower rates. While our long-haul transports decreased, our backhaul service from the Marcellus shale basin increased, which favorably impacted our EBIT by approximately $6 million. In addition, usage revenues decreased by $7 million due to reduced interruptible services resulting from unfavorable price spreads, partially offset by an increase of $5 million in liquids separation dehydration sales due to higher contractual rates.Matter

WeIn ~~believe~~November 2010, we filed a rate case with the FERC proposing an increase in base tariff rates, including a proposed change in our ~~Marcellus~~rate ~~expansion~~structure ~~projects~~which ~~(300~~is ~~Line~~expected ~~Expansion~~to increase the percentage of reservation revenues relative to revenues derived from excess fuel recoveries and throughput on our system. These new base tariff rates would increase revenue by approximately $200 million annually over previously effective tariff rates. In December 2010, ~~Northeast~~the ~~Upgrade~~FERC ~~Project~~issued an order accepting and ~~Northeast~~suspending ~~Supply~~the ~~Diversification~~effective ~~Project)~~date ~~will~~of ~~expand~~the ~~our~~proposed ~~presence~~rates ~~from~~to ~~Marcellus~~June 1, 2011, subject to refund, the ~~New~~outcome ~~York~~of a hearing and ~~New~~other ~~England~~proceedings. At ~~markets~~this time, the outcome of this matter is not determinable.

If we determine there is a sufficient change in our revenues, costs or billing determinants, we have the option to file a rate case with the FERC to provide an opportunity to recover our prudently incurred costs. We anticipate filing a new rate case in November 2010 with revised rates expected to become effective June 2011. Although this rate case is intended to address significant factors leading to the loss in revenues or increased costs, it will not eliminate all ongoing business risks. The changes in gas flows, contractual commitments and the outcome of our rate case can impact the financial performance of our pipeline.

Operating and General and Administrative Expenses. During the nine months ended September 30, 2010, our operating and general and administrative expenses were lower than the same period in 2009 primarily due to lower payroll costs, net of capitalization and reimbursement from affiliates.

Hurricane Repairs. For the nine months ended September 30, 2009, our EBIT was unfavorably impacted by repair costs that were not recoverable from insurance due to losses which did not exceed our self-retention levels.

Interest and Debt Expense

Interest and debt expense for the nine months ended September 30, 2010, was $4 million lower than the same period in 2009 primarily due to a lower outstanding balance on our PCB refund obligations.

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Affiliated Interest Income, Net

The following table shows the average advances due from El Paso and the average short-term interest rates for the ~~nine~~quarters ~~months~~ ended ~~September~~March 3031:

	2010			2009
	2011			2010
	(In millions, except for rates)
Average advance due from El Paso	$	~~1,009~~970		$	~~899~~901
Average short-term interest rate		1.5	%		1.85	%

Income Taxes

Our effective tax ~~rates~~rate of ~~37 percent and~~ 38 percent for the ~~nine~~quarters ~~months~~ ended ~~September~~March 3031, ~~2010~~2011 and ~~2009~~2010 ~~were~~was higher than the statutory rate of 35 percent primarily due to the effect of state income taxes.

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Liquidity and Capital Resources

Our primary sources of liquidity are cash flows from operating activities and amounts available to us under El Paso’s cash management program while our primary uses of cash are for working capital, capital expenditures and debt service requirements. At ~~September~~March 3031, ~~2010~~2011, we had a note receivable from El Paso of ~~approximately~~ $~~1.0~~953 ~~billion~~million of which ~~approximately~~ $~~451~~345 million was classified as current based on the net amount we anticipate using in the next twelve months considering available cash sources and needs. See Item 1, Financial Statements, Note 5 for a further discussion of El Paso’s cash management program. Our primary uses of cash are for working capital and capital expenditures. For the nine months ended September 30, 2010 compared to the same period in 2009, our operating cash flows decreased by approximately $157 million primarily due to the payment of income taxes during the third quarter of 2010 versus the fourth quarter of 2009, lower reservation revenues and settlement of refund obligations associated with our PCB liability. Our cash capital expenditures for the nine months ended September 30, 2010, and our estimated capital expenditures for the remainder of this year to expand and maintain our system are listed below.

	Nine Months Ended September 30, 2010		2010 Remaining		Total
	(In millions)
Maintenance(1)	$	48	$	102	$	150
Expansion		87		76		163
Other(2)		58		32		90
	$	193	$	210	$	403

Our cash capital expenditures for the quarter ended March 31, 2011 and our estimated capital expenditures for the remainder of this year to expand and maintain our system are listed below:

	Quarter Ended March 31, 2011		2011 Remaining		Total
	(In millions)
Expansion	$	38	$	474	$	512
Maintenance		43		134		177
Other(1)		15		86		101
	$	96	$	694	$	790

_______________

(1) ~~Amount~~Relates isto ~~net~~building ofrenovations ~~insurance~~at ~~proceeds~~our ~~received~~corporate facilities.

~~(2)~~We ~~Relates~~believe we have adequate liquidity available to ~~building~~us ~~renovations~~to atmeet our ~~corporate~~capital ~~facilities~~requirements and our existing operating needs through cash flows from operating activities and amounts available to us under El Paso’s cash management program. In addition to the cash management program above, we are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of March 31, 2011, El Paso had $909 million of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. For a further discussion of this credit agreement, see our 2010 Annual Report on Form 10-K. While we do not anticipate a need to directly access the financial markets in the remainder of 2011 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our ability to act opportunistically.

Although financial market conditions have improved since late 2008 and early 2009, volatility in the remainder of 2010 and beyond in the financial markets could impact our longer-term access to capital for future growth projects as well as the cost of such capital. Additionally, although the impacts are difficult to quantify at this point, a prolonged recovery of the global economy could have adverse impacts on natural gas consumption and demand. However, we believe our exposure to changes in natural gas consumption and demand is partially mitigated by a revenue base that includes long-term contracts that are based on firm demand charges.10

We believe we have adequate liquidity available to us to meet our capital requirements and our existing operating needs through cash flows from operating activities and amounts available to us under El Paso’s cash management program. In addition to the cash management program above, we are eligible to borrow amounts available under El Paso’s $1.5 billion credit agreement and are only liable for amounts we directly borrow. As of September 30, 2010, El Paso had approximately $1.1 billion of capacity remaining and available to us and our affiliates under this credit agreement, and none of the amount outstanding under the facility was issued or borrowed by us. For a further discussion of this credit agreement, see our 2009 Annual Report on Form 10-K. While we do not anticipate a need to directly access the financial markets in the remainder of 2010 for any of our operating activities or expansion capital needs based on liquidity available to us, market conditions may impact our ability to act opportunistically.

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Commitments and Contingencies

~~Below is a summary of certain climate change, energy policies and pipeline integrity legislation recently enacted or proposed that, if enacted, will likely impact our business.~~ For a further discussion of our commitments and contingencies, see Item 1, Financial Statements, Note 3, which is incorporated herein by reference and our 2010 Annual Report on Form 10-K.

Climate Change Legislation and Regulation. Legislative and regulatory efforts to address climate change and greenhouse gas (GHG) emissions are in various phases of discussions or implementation at international, federal, regional and state levels. We believe that legislation that either limits or sets a price on carbon emissions will increase demand for natural gas depending on the legislative provisions ultimately adopted. However, we also believe it is reasonably likely that the federal legislation being contemplated, as well as recently adopted and proposed federal regulations, would increase our cost of environmental compliance by requiring us to purchase emission allowances or offset credits, install additional equipment or change work practices, and could materially increase the cost of goods and services we purchase from suppliers due to their increased compliance costs. Although we believe that many of these costs should be recoverable in our rates, recovery through these mechanisms is still uncertain at this time.

The EPA has adopted regulations that require us to monitor and report certain GHG emissions from our operations on an annual basis. The EPA has proposed to further expand the monitoring and reporting requirements to additional natural gas transmission sources which could materially increase the costs of our operations. Our preliminary estimate of the first-year cost to our company is approximately $1 million.

The EPA has also adopted regulations that will require permits to be obtained under the Clean Air Act for GHG emissions above certain thresholds. Depending on the thresholds ultimately established by the EPA, these permit requirements could have a material impact upon the cost of our operations, could require us to install new equipment to control emissions from our facilities and could result in delays and negative impacts on our ability to obtain permits and other regulatory approvals with regard to new and existing facilities. The EPA’s regulations are being challenged in the federal courts; however, pending such judicial reviews, the thresholds that have been established by the EPA through at least 2016 are not expected to have a material impact on our operations or financial results.

It is uncertain what federal or state legislation or regulations will ultimately be adopted and whether adopted regulations will withstand likely legal challenges. Therefore, the potential impact on our operations and construction projects remains uncertain.

Energy Legislation. In conjunction with these climate change proposals, there have been various federal and state legislative and regulatory proposals that would create additional incentives to move to a less carbon intensive “footprint.” Although it is reasonably likely that many of these proposals will be enacted over the next few years, we cannot predict the form of any laws and regulations that might be enacted, the timing of their implementation, or the precise impact on our operations or demand for natural gas. However, such proposals if enacted could impact natural gas demand over the longer term.

Air Quality Regulations. In February 2010, the EPA promulgated a new one-hour National Ambient Air Quality Standard (NAAQS) for oxides of nitrogen (NO2). The new standard is in addition to the existing annual NAAQS which was not changed. While it is uncertain how the EPA and the states will apply the new one-hour NAAQS, the new NAAQS may impact our ability to obtain permits and other regulatory approvals with regard to existing and new facilities and may cause us to incur costs to install additional controls on existing and new facilities. The EPA’s new rule is being challenged in the federal courts. While the new NAAQS, if upheld, could have a material impact on our cost of operations and our cost to install new facilities, we are unable, at this point, to estimate its financial impact.

Pipeline Integrity Legislation. Several ruptures on third party pipelines have occurred recently. In response, various legislative and regulatory reforms associated with pipeline safety and integrity issues have been proposed, including reforms that would require increased periodic inspections, installation of additional valves and other equipment on our pipeline and subjecting additional pipelines (including gathering facilities) to more stringent regulation. It is uncertain what reforms, if any, will be adopted and what impact they might ultimately have on our operations or financial results.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

Omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of ~~September~~March 3031, ~~2010~~2011, we carried out an evaluation under the supervision and with the participation of our management, including our President and Chief Financial Officer (CFO), as to the effectiveness, design and operation of our disclosure controls and procedures. 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 U.S. Securities and Exchange Commission reports we file or submit under the Securities Exchange Act of 1934, as amended (Exchange Act) is accurate, complete and timely. Our management, including our President and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our President and CFO concluded that our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) were effective as of ~~September~~March 3031, ~~2010~~2011.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting during the ~~third~~first quarter of ~~2010~~2011 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Financial Statements, Note 3, which is incorporated herein by reference.

Item 1A. Risk Factors

CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS OF

THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

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

Important factors that could cause actual results to differ materially from estimates or projections contained in forward-looking statements are described in our ~~2009~~2010 Annual Report on Form 10-K under Part I, Item 1A, Risk Factors. There have been no material changes in these risk factors since that report.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

Item 3. Defaults Upon Senior Securities

Omitted from this report pursuant to the reduced disclosure format permitted by General Instruction H to Form 10-Q.

Item 4. (Removed and Reserved)

Item 5. Other Information

None.

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Item 6. Exhibits

The Exhibit Index is incorporated herein by reference.

The agreements included as exhibits to this report are intended to provide information regarding their terms and not to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by the parties to the agreements, including us, solely for the benefit of the other parties to the applicable agreement and:

·• • should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

·• • may have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

·• may apply standards of materiality in a way that is different from what may be viewed as material to certain investors; and

·• • were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, Tennessee Gas Pipeline Company has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	TENNESSEE GAS PIPELINE COMPANY
Date: November 5, 2010	/s/ Norman G. Holmes
Date: May 6, 2011	/s/ Norman G. Holmes
	Norman G. Holmes President (Principal Executive Officer)
Date: November 5, 2010	/s/ John R. Sult
Date: May 6, 2011	/s/ John R. Sult
	John R. Sult Executive Vice President and Chief Financial Officer (Principal Financial Officer)

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TENNESSEE GAS PIPELINE COMPANY

EXHIBIT INDEX

Each exhibit identified below is filed as a part of this report.

Exhibit Number	Description

31.A	Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.B	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.A	Certification of Principal Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.B	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

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