UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

(Mark One)


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

For the quarterly period ended ~~September 30, 2010~~March 31, 2011


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

For the transition period fromto

Commission File Number 1-14365

El Paso Corporation

(Exact Name of Registrant as Specified in Its Charter)


Delaware		76-0568816
(State or Other Jurisdiction of		(I.R.S. Employer
Incorporation or Organization)		~~76-0568816~~ ~~(I.R.S. Employer~~ Identification No.)

El Paso Building
1001 Louisiana Street
Houston, Texas		77002
(Address of Principal Executive Offices)		~~77002~~ (Zip Code)

Telephone Number: (713) 420-2600

Internet Website: www.elpaso.com

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. Yesþ Noo

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). Yesþ Noo

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


Large accelerated filerþ	Accelerated filero	Non-accelerated filero	Smaller reporting companyo
		(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). Yeso Noþ

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 $3 per share. Shares outstanding on ~~November 1, 2010: 704,142,559~~May 2, 2011: 768,967,144

EL PASO CORPORATION

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			23
Item 3.	Quantitative and Qualitative Disclosures About Market Risk			38
Item 4.	Controls and Procedures			39

~~Item 1. Financial Statements~~		1
~~Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations~~					27
~~Item 3. Quantitative and Qualitative Disclosures About Market Risk~~		46
~~Item 4. Controls and Procedures~~		47	PART II — OTHER INFORMATION

~~PART II — OTHER INFORMATION~~
Item 1.	Legal Proceedings			40
Item ~~1. Legal Proceedings~~1A.	Risk Factors			4840
Item ~~1A. Risk Factors~~2.		48
~~Item 2.~~ Unregistered Sales of Equity Securities and Use of Proceeds		4940
Item 3.	Defaults Upon Senior Securities			4941
Item 4. ~~(Removed~~	(Removed and Reserved)			4941
Item 5.	Other Information			4941
Item 6.	Exhibits			5041
	Signatures			5142
EX-12
EX-31.A
EX-31.B
EX-32.A
EX-32.B
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

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


/d		= per day

Bbl		= barrels

BBtu		= billion British thermal units

Bcf		= billion cubic feet

GW		= gigawatts

GWh		= gigawatt hours

LNG		= liquefied natural gas

MBbls		= thousand barrels

Mcf		= thousand cubic feet

Mcfe		= thousand cubic feet of natural gas equivalents

MMBbls		= million barrels

MMBtu		= million British thermal units

MMcf		= million cubic feet

MMcfe		= million cubic feet of natural gas equivalents

NGL		= natural gas liquids

TBtu		= trillion British thermal units

When we refer to oil and natural gas ~~and oil~~ in “equivalents,” we are doing so to compare quantities of oil with quantities of natural gas or to express these different commodities in a common unit. In calculating equivalents, we use a generally recognized standard in which one Bbl of oil is equal to six Mcf of natural gas. Also, 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”, “the company” or “El Paso”, we are describing El Paso Corporation and/or our subsidiaries.

PART I — FINANCIAL INFORMATION

Item 1. Financial Statements

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per common share amounts)
(Unaudited)

Quarters Ended Nine Months Ended
September 30, September 30,
2010 2009 2010 2009
Operating revenues $ 1,213 $ 981 $ 3,632 $ 3,438

Operating expenses
Cost of products and services 57 45 163 158
Operation and maintenance 327 346 911 910
Ceiling test charges 14 5 16 2,085
Depreciation, depletion and amortization 239 200 699 653
Taxes, other than income taxes 58 56 181 181

695 652 1,970 3,987

Operating income (loss) 518 329 1,662 (549 )
Earnings from unconsolidated affiliates 28 11 167 42
Other income (expense) (33 ) 33 84 71
Interest and debt expense (255 ) (256 ) (782 ) (764 )

Income (loss) before income taxes 258 117 1,131 (1,200 )
Income tax (benefit) expense 75 35 343 (425 )

Net income (loss) 183 82 788 (775 )
Net income attributable to noncontrolling interests (41 ) (15 ) (101 ) (38 )

Net income (loss) attributable to El Paso Corporation 142 67 687 (813 )
Preferred stock dividends of El Paso Corporation 9 9 28 28

Net income (loss) attributable to El Paso Corporation’s common stockholders $ 133 $ 58 $ 659 $ (841 )

Basic earnings (loss) per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders $ 0.19 $ 0.08 $ 0.95 $ (1.21 )

Diluted earnings (loss) per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders $ 0.19 $ 0.08 $ 0.90 $ (1.21 )

Dividends declared per El Paso Corporation’s common share $ 0.01 $ 0.05 $ 0.03 $ 0.15


	Quarter Ended
	March 31,
	2011			2010
Operating revenues	$	989		$	1,401


Operating expenses
Cost of products and services		47			53
Operation and maintenance		305			301
Depreciation, depletion and amortization		254			218
Taxes, other than income taxes		76			69

		682			641


Operating income		307			760
Earnings from unconsolidated affiliates		30			28
Loss on debt extinguishment		(41	)		—
Other income, net		99			60
Interest and debt expense		(240	)		(243	)

Income before income taxes		155			605
Income tax expense		19			186

Net income		136			419
Net income attributable to noncontrolling interests		(74	)		(31	)

Net income attributable to El Paso Corporation		62			388
Preferred stock dividends of El Paso Corporation		—			(9	)

Net income attributable to El Paso Corporation’s common stockholders	$	62		$	379

Basic earnings per common share
Net income attributable to El Paso Corporation’s common stockholders	$	0.09		$	0.54

Diluted earnings per common share
Net income attributable to El Paso Corporation’s common stockholders	$	0.08		$	0.51


Dividends declared per El Paso Corporation’s common share	$	0.01		$	0.01

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share and per share amounts)

(Unaudited)


	September 30,			December 31,			March 31,			December 31,
	2010			2009			2011			2010
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade	$	514		$	459		$	452		$	610
Affiliates		9			7			11			9
Other		399			424			420			386
Short-term financing obligations, including current maturities		637			477			495			489
Liabilities from price risk management activities		181			269			188			176
Asset retirement obligations		110			158			64			63
Accrued interest		244			208			247			202
Other		620			684			533			630

Total current liabilities		2,714			2,686			2,410			2,565


Long-term financing obligations, less current maturities		13,134			13,391			13,566			13,517


Other
Other long-term liabilities
Liabilities from price risk management activities		454			462			401			397
Deferred income taxes		507			339			628			568
Other		1,416			1,491			1,450			1,461

		2,377			2,292			2,479			2,426


Commitments and contingencies (Note 10)
Commitments and contingencies (Note 7)

Preferred stock of subsidiaries		681			145			745			698


Equity
El Paso Corporation stockholders’ equity:
Preferred stock, par value $0.01 per share; authorized 50,000,000 shares; issued 750,000 shares of 4.99% convertible perpetual stock; stated at liquidation value		750			750
Common stock, par value $3 per share; authorized 1,500,000,000 shares; issued 719,513,700 shares in 2010 and 716,041,302 shares in 2009		2,159			2,148
Preferred stock, par value $0.01 per share; authorized 50,000,000 shares; issued 750,000 shares of 4.99% convertible perpetual stock as of December 31, 2010; stated at liquidation value								—			750
Common stock, par value $3 per share; authorized 1,500,000,000 shares; issued 778,840,616 shares in 2011 and 719,743,724 shares in 2010								2,337			2,159
Additional paid-in capital		4,484			4,501			5,246			4,484
Accumulated deficit		(2,505	)		(3,192	)		(2,372	)		(2,434	)
Accumulated other comprehensive loss		(749	)		(718	)		(729	)		(751	)
Treasury stock (at cost); 15,403,572 shares in 2010 and 14,761,654 shares in 2009		(290	)		(283	)
Treasury stock (at cost); 14,475,623 shares in 2011 and 15,492,605 shares in 2010								(272	)		(291	)

Total El Paso Corporation stockholders’ equity		3,849			3,206			4,210			3,917
Noncontrolling interests		1,752			785			2,447			2,147

Total equity		5,601			3,991			6,657			6,064

Total liabilities and equity	$	24,507		$	22,505		$	25,857		$	25,270

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)


	Nine Months Ended						Quarter Ended
	September 30,						March 31,
	2010			2009			2011			2010
Cash flows from operating activities
Net income (loss)	$	788		$	(775	)
Adjustments to reconcile net income (loss) to net cash from operating activities
Net income							$	136		$	419
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		699			653			254			218
Ceiling test charges		16			2,085
Deferred income tax expense (benefit)		339			(448	)
Deferred income tax expense								26			194
Earnings from unconsolidated affiliates, adjusted for cash distributions		(115	)		17			(18	)		(13	)
Loss on debt extinguishment								41			—
Other non-cash income items		70			53			(64	)		(4	)
Asset and liability changes		(293	)		196			156			(336	)

Net cash provided by operating activities		1,504			1,781			531			478


Cash flows from investing activities
Capital expenditures		(2,733	)		(2,081	)		(1,089	)		(741	)
Cash paid for acquisitions, net of cash acquired		(33	)		(39	)
Net proceeds from the sale of assets and investments		332			303
Other		22			15			—			(6	)

Net cash used in investing activities		(2,412	)		(1,802	)		(1,089	)		(747	)


Cash flows from financing activities
Net proceeds from issuance of long-term debt		1,399			1,369			806			775
Payments to retire long-term debt and other financing obligations		(1,273	)		(1,290	)		(794	)		(617	)
Net proceeds from issuance of noncontrolling interests		956			212			457			231
Distributions to noncontrolling interest holders								(39	)		(19	)
Net proceeds from issuance of preferred stock of subsidiary		120			—			30			—
Distributions to holders of preferred stock of subsidiary								(5	)		(5	)
Dividends paid		(49	)		(133	)		(16	)		(16	)
Distributions to noncontrolling interest holders		(64	)		(33	)
Distributions to holders of preferred stock of subsidiary		(15	)		—
Other		8			(7	)		14			—

Net cash provided by financing activities		1,082			118			453			349


Change in cash and cash equivalents		174			97			(105	)		80
Cash and cash equivalents
Beginning of period		635			1,024			347			635

End of period	$	809		$	1,121		$	242		$	715

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(In millions)

(Unaudited)


	Nine Months Ended						Quarter Ended
	September 30,						March 31,
	2010			2009			2011			2010
El Paso Corporation stockholders’ equity:
Preferred stock:
Balance at beginning and end of period	$	750		$	750
Balance at beginning of period							$	750		$	750
Conversion of preferred stock								(750	)		—

Balance at end of period								—			750

Common stock:
Balance at beginning of period		2,148			2,138			2,159			2,148
Conversion of preferred stock								174			—
Other, net		11			10			4			—

Balance at end of period		2,159			2,148			2,337			2,148

Additional paid-in capital:
Balance at beginning of period		4,501			4,612			4,484			4,501
Conversion of preferred stock								576			—
Dividends		(49	)		(133	)		(7	)		(16	)
Issuances of noncontrolling interests (Note 9)								170			—
Other, including stock-based compensation		32			26			23			12

Balance at end of period		4,484			4,505			5,246			4,497

Accumulated deficit:
Balance at beginning of period		(3,192	)		(2,653	)		(2,434	)		(3,192	)
Net income (loss) attributable to El Paso Corporation		687			(813	)
Net income attributable to El Paso Corporation								62			388

Balance at end of period		(2,505	)		(3,466	)		(2,372	)		(2,804	)

Accumulated other comprehensive loss:
Accumulated other comprehensive income (loss):
Balance at beginning of period		(718	)		(532	)		(751	)		(718	)
Other comprehensive loss		(31	)		(177	)
Other comprehensive income								22			12

Balance at end of period		(749	)		(709	)		(729	)		(706	)

Treasury stock, at cost:
Balance at beginning of period		(283	)		(280	)		(291	)		(283	)
Stock-based and other compensation		(7	)		(2	)		19			(1	)

Balance at end of period		(290	)		(282	)		(272	)		(284	)

Total El Paso Corporation stockholders’ equity at end of period		3,849			2,946			4,210			3,601


Noncontrolling interests:
Balance at beginning of period		785			561			2,147			785
Distributions paid to noncontrolling interests		(64	)		(33	)
Issuances of noncontrolling interests		956			212
Net income attributable to noncontrolling interests (Note 12)		75			38
Issuances of noncontrolling interests (Note 9)								287			231
Distributions to noncontrolling interests								(39	)		(19	)
Net income attributable to noncontrolling interests (Note 9)								52			26

Balance at end of period		1,752			778			2,447			1,023

Total equity at end of period	$	5,601		$	3,724		$	6,657		$	4,624

EL PASO CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1. Basis of Presentation and Significant Accounting Policies

Basis of Presentation

We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (SEC). ~~Because this is~~As 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 (GAAP)~~. You~~, and should be 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.~~10-K. The financial statements as of ~~September 30, 2010,~~March 31, 2011, and for the quarters ended March 31, 2011 and ~~nine months ended September 30,~~ 2010, ~~and 2009,~~ 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. Our financial statements for prior periods include reclassifications that were made to conform to the current year presentation, none of which impacted our reported net income (loss) or stockholders’ equity. Additionally, our statement of cash flows for the quarter ended March 31, 2010, reflects a decrease in both net cash provided by operating activities and net cash used in investing activities related to the timing of certain capital expenditures which was considered immaterial to our 2010 consolidated financial statements. Due to the seasonal nature of our businesses, 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 following is an update of our~~There were no changes in the significant accounting policies described in our 2010 Annual Report on Form 10-K and no significant accounting pronouncements issued ~~and~~but not yet adopted ~~during the nine months ended September 30, 2010.~~

~~Transfers~~as 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 programs under which we previously sold senior interests in certain of our pipeline accounts receivable to a third party financial institution (through wholly-owned special purpose entities). 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 programs, we entered into new accounts receivable sales programs under which we sell certain of our pipeline accounts receivable in their entirety to the third party financial institution (through wholly-owned special purpose entities). 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 14.

~~Variable Interest Entities.~~On January 1, 2010, we adopted an accounting standards update for variable interest entities that revise how companies determine the primary beneficiary of these entities, among other changes. Companies are now required to use a qualitative approach based on their responsibilities and power over the entities’ operations, rather than a quantitative approach in determining the primary beneficiary as previously required. Additionally, the primary beneficiary is required to retrospectively present qualifying assets and liabilities of variable interest entities separately on the balance sheet. Other than the required change in presentation on our balance sheet, the adoption of this accounting standards update did not have a material impact on our financial statements. For a further discussion of our involvement with variable interest entities, see Note 14.March 31, 2011.

2. ~~Divestitures~~

During 2010, we (i) completed the sale of certain of our interests in Mexican pipeline and compression assets for approximately $300 million and recorded a pretax gain of approximately $80 million in earnings from unconsolidated affiliates and (ii) sold non-core natural gas producing properties located in our Gulf Coast division for approximately $22 million. During 2009, we (i) sold our investment in the Argentina-to-Chile pipeline to our partners in the project for approximately $32 million, (ii) sold non-core natural gas producing properties located in our Central and Western divisions for approximately $95 million, and (iii) sold our interest in the Porto Velho power generation facility in Brazil to our partner in the project for total consideration of $179 million, including $78 million in notes receivable. In the second quarter of 2009, we sold the notes, including accrued interest, to a third party financial institution for $57 million and recorded a loss of approximately $22 million.

~~3. Ceiling Test Charges~~

We are required to conduct quarterly impairment tests of our capitalized costs in each of our full cost pools. During the quarters and nine months ended September 30, 2010 and 2009, we recorded the following ceiling test charges:

Quarters Ended September 30, Nine Months Ended September 30,
2010 2009 2010 2009
(In millions)
Full cost pool:
U.S. $ — $ — $ — $ 2,031
Brazil — — — 28
Egypt 14 5 16 26

Total $ 14 $ 5 $ 16 $ 2,085

During 2009, the calculation of these charges was based on spot commodity prices at the end of each quarter, as required at that time. As a result of our adoption of the SEC’s final rule on the Modernization of Oil and Gas Reporting, effective December 31, 2009, we began using a 12-month average price (calculated as the unweighted arithmetic average of the price on the first day of each month within the 12-month period prior to the end of the reporting period) when performing these ceiling tests. In calculating our ceiling test charges, we are also required to hold prices constant over the life of the reserves, even though actual prices of natural gas and oil are volatile and change from period to period.

4. Other Income, ~~and Other Expense~~Net

The following are the components of other income and other expense for the quarters ~~and nine months~~ ended ~~September 30:~~March 31:


	Quarters Ended September 30,					Nine Months Ended September 30,
	2010			2009		2010		2009		2011		2010
				(In millions)						(In millions)
Other Income
Allowance for equity funds used during construction	$	55		$	18	$	156	$	60	$	97	$	50
Other		19			15		36		36		7		14

Total		74			33		192		96		104		64


Other Expenses
Loss on debt extinguishment (Note 9)	$	104		$	—	$	104	$	—
Other Expense
Other		3			—		4		25		5		4

Total		107			—		108		25		5		4

Other income (expense)	$	(33	)	$	33	$	84	$	71
Other income, net										$	99	$	60

5. Financial Instruments

During the quarter and nine months ended September 30, 2010, there have been no changes to the types of instruments or the levels in which they are classified. For a further description of these levels and our corresponding instruments classified by level, see our 2009 Annual Report on Form 10-K.

~~Listed below are the fair values of our financial instruments that are recorded at fair value classified in each level at September 30, 2010 and December 31, 2009:~~

September 30, 2010 December 31, 2009
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
(In millions)
Assets

Commodity-based derivatives
Production-related natural gas and oil derivatives $ — $ 381 $ — $ 381 $ — $ 169 $ — $ 169
Other natural gas derivatives — 32 17 49 — 106 21 127
Power-related derivatives — — 14 14 — — 37 37
Interest rate derivatives — 11 — 11 — 11 — 11
Marketable securities invested in non-qualified compensation plans 21 — — 21 20 — — 20

Total assets 21 424 31 476 20 286 58 364

Liabilities

Commodity-based derivatives
Production-related natural gas and oil derivatives — (13 ) — (13 ) — (42 ) — (42 )
Other natural gas derivatives — (61 ) (100 ) (161 ) — (153 ) (133 ) (286 )
Power-related derivatives — — (356 ) (356 ) — — (386 ) (386 )
Interest rate derivatives — (105 ) — (105 ) — (17 ) — (17 )
Other — — (13 ) (13 ) — — (31 ) (31 )

Total liabilities — (179 ) (469 ) (648 ) — (212 ) (550 ) (762 )

Total $ 21 $ 245 $ (438 ) $ (172 ) $ 20 $ 74 $ (492 ) $ (398 )

On certain derivative contracts recorded as assets in the table above, we are exposed to the risk that our counterparties may not perform or post the required collateral, if any, with us. We have assessed this counterparty risk in light of the collateral our counterparties have posted with us and determined that our exposure is primarily related to our production-related derivatives and is limited to nine financial institutions, each of which has a current Standard & Poor’s credit rating of A or better.

~~The following table presents the changes in our financial assets and liabilities included in Level 3 for the quarters and nine months ended September 30, 2010:~~

Change in Fair Value Change in Fair Value
Balance at Reflected in Reflected in Balance at
Beginning of Operating Operating Settlements, End of
Period Revenues⁽¹⁾ Expenses⁽²⁾ Net Period
(In millions)
Quarter Ended September 30, 2010

Assets $ 43 $ (11 ) $ — $ (1 ) $ 31
Liabilities (494 ) (3 ) (1 ) 29 (469 )

Total $ (451 ) $ (14 ) $ (1 ) $ 28 $ (438 )

Nine Months Ended September 30, 2010

Assets $ 58 $ (25 ) $ — $ (2 ) $ 31
Liabilities (550 ) (14 ) (2 ) 97 (469 )

Total $ (492 ) $ (39 ) $ (2 ) $ 95 $ (438 )


⁽¹⁾		Includes approximately $12 million and $38 million of net losses that had not been realized through settlements for the quarter and nine months ended September 30, 2010. These losses are primarily based on additional market information on these contracts.

⁽²⁾		~~Includes $1 million and $2 million of net losses that had not been realized through settlements for the quarter and nine months ended September 30, 2010.~~

~~Production-Related Derivatives.~~We attempt to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of natural gas and oil production through the use of derivative natural gas and oil swaps, basis swaps and option contracts; however, we are subject to commodity price risks on a portion of our forecasted production. As of September 30, 2010 and December 31, 2009, we have production-related derivatives on 272 Tbtu and 313 Tbtu of natural gas and 6,484 MBbl and 4,016 MBbl of oil.

~~Other Commodity-Based Derivatives.~~In our Marketing segment, we have long-term natural gas and power derivative contracts that include forwards, swaps and options that we either intend to manage until their expiration or liquidate to the extent it is economical and prudent. None of these derivatives are designated as accounting hedges. As of September 30, 2010 and December 31, 2009, these derivative contracts include (i) natural gas contracts that obligate us to sell natural gas to power plants and have various expiration dates ranging from 2012 to 2019, with expected obligations under individual contracts with third parties ranging from 12,550 MMBtu/d to 104,750 MMBtu/d and (ii) derivative power contracts that require us to swap locational differences in power prices between three power plants in the Pennsylvania-New Jersey-Maryland (PJM) eastern region with the PJM west hub on approximately 3,700 GWh from 2010 to 2012, 2,400 GWh for 2013 and 1,700 GWh from 2014 to April 2016. These contracts also require us to provide approximately 1,700 GWh of power per year and approximately 71 GW of installed capacity per year in the PJM power pool through April 2016. For these natural gas and power contracts, we have entered into contracts to economically mitigate our exposure to commodity price changes on substantially all of these volumes as well as changes in locational price differences between the PJM regions.

~~Interest Rate Derivatives~~. We have long-term debt with variable interest rates that exposes us to changes in market-based interest rates. As of September 30, 2010 and December 31, 2009, we had interest rate swaps, which are designated as cash flow hedges that we used to convert the interest rate on approximately $1.3 billion and $169 million of debt from a floating LIBOR interest rate to a fixed interest rate. Approximately $1.1 billion of the debt hedged as of September 30, 2010, relates to debt commitments associated with our Ruby pipeline project. These swaps begin accruing interest on July 1, 2011 and have termination dates ranging from June 2013 to June 2017 which correspond to the estimated principal outstanding on the Ruby debt over the term of these swaps. For a further discussion of our Ruby financing, see Note 9.

	•		Production-Related Commodity Based Derivatives.As of March 31, 2011 and December 31, 2010, we have production-related derivatives (oil and natural gas swaps, collars, basis swaps and option contracts) to mitigate a portion of our commodity price risk and stabilize cash flows associated with forecasted sales of natural gas and oil production on 253 TBtu and 283 TBtu of natural gas and 15,777 MBbl and 12,240 MBbl of oil. None of these contracts are designated as accounting hedges.

	•		Other Commodity-Based Derivatives.As of March 31, 2011 and December 31, 2010, in our Marketing segment we have forwards, swaps and options contracts related to long-term natural gas and power. These contracts, the longest of which extends into 2019, include (i) obligations to sell natural gas to power plants ranging from 12,550 MMBtu/d to 95,000 MMBtu/d and (ii) an obligation to swap locational differences in power prices between three power plants in the Pennsylvania-New Jersey-Maryland (PJM) eastern region with the PJM west hub on approximately 1,700 to 3,700 GWh, to provide annually approximately 1,700 GWh of power and approximately 71 GW of installed capacity in the PJM power pool. We have entered into contracts to economically mitigate our exposure to commodity price changes and locational price differences on substantially all of these natural gas and power volumes. None of these derivatives are designated as accounting hedges.

	•		Interest Rate Derivatives.We have long-term debt with variable interest rates that exposes us to changes in market-based interest rates. As of March 31, 2011 and December 31, 2010, we had interest rate swaps, that are designated as cash flow hedges that effectively convert the interest rate on approximately $1.3 billion of debt from a floating LIBOR interest rate to a fixed interest rate. Approximately $1.1 billion of the debt hedged as of March 31, 2011 relates to debt associated with our Ruby pipeline project that begin accruing interest on July 1, 2011 and have termination dates ranging from June 2013 to June 2017. These termination dates correspond to the estimated principal outstanding on the Ruby debt over the term of these swaps. For a further discussion of our Ruby financing, see Note 6.

We also have long-term debt with fixed interest rates that exposes us to paying higher than market rates should interest rates decline. We use interest rate swaps designated as fair value hedges to protect the value of certain of these debt instruments by converting the fixed amounts of interest due under the debt agreements to variable interest payments. We record changes in the fair value of these derivatives in interest ~~expense.~~expense which is offset by changes in the fair value of the related hedged items. As of ~~September 30, 2010~~March 31, 2011 and December 31, ~~2009, our hedges~~2010, these interest rate swaps converted the interest rate on approximately ~~$218~~$184 million of debt from a fixed rate to a variable rate of LIBOR plus 4.18%.

Fair Value Measurement.We ~~also had interest rate swaps with~~separate the fair values of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Our assessment and classification of an instrument within a ~~notional amount~~level can change over time based on the maturity or liquidity of ~~$222 million~~the instrument. During the quarter ended March 31, 2011, there have been no changes to the inputs and valuation techniques used to measure fair value, the types of instruments, or the levels in which they are classified. Our marketable securities in non-qualified compensation plans and other are reflected at fair value on our balance sheets as other long-term assets, other current liabilities and other long-term liabilities. We net our derivative assets and liabilities for ~~which changes in~~counterparties where we have a legal right of offset and classify our derivatives as either current or non-current assets or liabilities based on their anticipated settlement date. At March 31, 2011 and December 31, 2010, cash collateral held was not material. The following table presents the fair value of ~~these swaps were substantially eliminated by offsetting swaps contracts.~~our financial instruments at March 31, 2011 and December 31, 2010 (in millions).


	March 31, 2011											December 31, 2010
	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
Assets
Commodity-based derivatives
Production-related oil and natural gas derivatives	$	—	$	307		$	—		$	307		$	—	$	373		$	—		$	373
Other natural gas derivatives		—		146			18			164			—		139			18			157
Power-related derivatives		—		—			26			26			—		—			31			31

Total commodity-based derivative assets		—		453			44			497			—		512			49			561
Interest rate derivatives designated as hedges
Fair value hedges		—		7			—			7			—		8			—			8
Impact of master netting arrangements		—		(306	)		(12	)		(318	)		—		(229	)		(14	)		(243	)

Total price risk management assets	$	—	$	154		$	32		$	186		$	—	$	291		$	35		$	326
Marketable securities in non-qualified compensation plans		20		—			—			20			20		—			—			20

Total net assets	$	20	$	154		$	32		$	206		$	20	$	291		$	35		$	346


Liabilities
Commodity-based derivatives
Production-related oil and natural gas derivatives	$	—	$	(257	)	$	—		$	(257	)	$	—	$	(136	)	$	—		$	(136	)
Other natural gas derivatives		—		(167	)		(76	)		(243	)		—		(162	)		(90	)		(252	)
Power-related derivatives		—		—			(341	)		(341	)		—		—			(359	)		(359	)

Total commodity-based derivative liabilities		—		(424	)		(417	)		(841	)		—		(298	)		(449	)		(747	)
Interest rate derivatives designated as hedges
Cash flow hedges		—		(66	)		—			(66	)		—		(69	)		—			(69	)
Impact of master netting arrangements		—		306			12			318			—		229			14			243

Total price risk management liabilities	$	—	$	(184	)	$	(405	)	$	(589	)	$	—	$	(138	)	$	(435	)	$	(573	)
Other		—		—			(11	)		(11	)		—		—			(12	)		(12	)


Total net liabilities	$	—	$	(184	)	$	(416	)	$	(600	)	$	—	$	(138	)	$	(447	)	$	(585	)


Total	$	20	$	(30	)	$	(384	)	$	(394	)	$	20	$	153		$	(412	)	$	(239	)

~~During~~On certain derivative contracts recorded as assets in the ~~second quarter~~table above, we are exposed to the risk that our counterparties may not perform or post the required collateral. Based on our assessment of ~~2009,~~counterparty risk in light of the collateral our ~~Euro-denominated debt matured~~counterparties have posted with us (primarily in the form of letters of credit), we have determined that our exposure is primarily related to our production-related derivatives and ~~we settled all~~is limited to nine financial institutions, each of ~~our related cross-currency swaps,~~ which ~~were designated as fair value hedges~~has a current Standard & Poor’s credit rating of ~~this debt.~~A or better.

1310

~~Statements of Income~~The following table presents the changes in our financial assets and ~~Comprehensive Income~~~~. Listed below~~liabilities included in Level 3 for the quarter ended March 31, 2011 (in millions):


				Change in Fair			Change in Fair
	Balance at			Value Reflected			Value Reflected
	Beginning of			in Operating			in Operating					Balance at End
	Period			Revenues⁽¹⁾			Expenses⁽²⁾			Settlements_		of Period
Assets	$	35		$	(3	)	$	—		$	—	$	32
Liabilities		(447	)		2			(1	)		30		(416	)

Total	$	(412	)	$	(1	)	$	(1	)	$	30	$	(384	)


⁽¹⁾		^{Includes approximately $4 million of net losses that had not been realized through settlements as of March 31, 2011.}

⁽²⁾		^{Includes approximately $1 million of net losses that had not been realized through settlements as of March 31, 2011.}

Below are the impacts of our commodity-based and interest rate derivatives to our statements of income ~~statement~~ and ~~statement~~statements of comprehensive income (loss) for the quarters ~~and nine months~~ ended ~~September 30:~~March 31:

2010 2009
Other Other
Operating Interest Other Comprehensive Operating Interest Other Comprehensive
Revenues Expense Income Income (Loss) Revenues Expense Income Income (Loss)
(In millions)
Quarters ended September 30,

Production-related derivatives⁽¹⁾
$ 184 $ — $ — $ 2 $ 87 $ — $ — $ (95 )
Other natural gas and power derivatives not designated as hedges (14 ) — — — (20 ) — — —
Total interest rate derivatives⁽²⁾
— 4 — (43 ) — 2 — —

Total price risk management activities⁽³⁾
$ 170 $ 4 $ — $ (41 ) $ 67 $ 2 $ — $ (95 )

Nine months ended September 30,

Production-related derivatives⁽¹⁾
$ 468 $ — $ — $ 8 $ 536 $ — $ — $ (322 )
Other natural gas and power derivatives not designated as hedges (40 ) — — — 53 — — —
Total interest rate derivatives⁽²⁾
— 13 — (89 ) — 9 (26 ) 8

Total price risk management activities⁽³⁾
$ 428 $ 13 $ — $ (81 ) $ 589 $ 9 $ (26 ) $ (314 )


	2011							2010
						Other						Other
	Operating			Interest		Comprehensive		Operating		Interest		Comprehensive
	Revenues			Expense		Income (Loss)		Revenues		Expense		Income (Loss)
						(In millions)
Production-related derivatives	$	(109	)	$	—	$	3	$	253	$	—	$	3
Other natural gas and power derivatives not designated as hedges		(1	)		—		—		17		—		—
Total interest rate derivatives		—			4		3		—		5		(1	)

Total	$	(110	)	$	4	$	6	$	270	$	5	$	2


⁽¹⁾		We reclassified $2 million and $8 million of accumulated other comprehensive loss for the quarter and nine months ended September 30, 2010 and $95 million and $322 million of accumulated other comprehensive income for the quarter and nine months ended September 30, 2009 into operating revenues on derivatives for which we removed the cash-flow hedging designation in 2008. Approximately $12 million of our accumulated other comprehensive loss will be reclassified to operating revenues over the next twelve months.

⁽²⁾		Included in interest expense is $1 million and $5 million representing the amount of accumulated other comprehensive income that was reclassified into income related to these interest rate derivatives designated as cash flow hedges for the quarter and nine months ended September 30, 2010. We anticipate that $15 million of our accumulated other comprehensive income will be reclassified to interest expense during the next twelve months. No ineffectiveness was recognized on our interest rate cash flow hedges for the quarter and nine months ended September 30, 2010.

⁽³⁾		We also had approximately $1 million and $3 million of losses for the quarters ended September 30, 2010 and 2009 and $2 million of losses and $22 million of gains for the nine months ended September 30, 2010 and 2009 recognized in operating expenses related to other derivative instruments not associated with our price risk management activities.

1411

Book Value Cash
Company Interest Rate Increase (Decrease) Received (Paid)
(In millions)
Issuances

Ruby Holding Company loan commitment⁽¹⁾
13.00% 188 187
Ruby Pipeline, L.L.C. credit facility variable 362 308
El Paso notes due 2020⁽²⁾
6.50% 348 —
El Paso Pipeline Partners Operating Company, L.L.C. notes due 2020 6.50% 535 528
El Paso revolving credit facility variable 193 193
El Paso Pipeline Partners Operating Company, L.L.C. revolving credit facility variable 114 114
Other variable 69 69

Increases through September 30, 2010
$ 1,809 $ 1,399

Repayments, repurchases, and other

El Paso Exploration and Production Company revolving credit facility variable $ (469 ) $ (469 )
El Paso revolving credit facility variable (393 ) (393 )
El Paso Pipeline Partners Operating Company, L.L.C. revolving credit facility variable (114 ) (114 )
El Paso notes due 2010 7.75% and 7.80% (149 ) (149 )
El Paso notes due 2013⁽²⁾
12.00% (323 ) (77 )
Ruby Holding Company loan commitment⁽¹⁾
13.00% (405 ) —
Other various (53 ) (71 )

Decreases through September 30, 2010
$ (1,906 ) $ (1,273 )


				Book Value			Cash
				Increase			Received
Company	Interest Rate			(Decrease)			(Paid)
	(In millions)
Issuances
Ruby Pipeline, L.L.C. credit facility	variable			$	391		$	391
El Paso Exploration and Production Company (EPEP) revolving credit facility	variable				200			200
El Paso Pipeline Partners Operating Company, L.L.C. (EPPOC) revolving credit facility	variable				215			215

Increases through March 31, 2011				$	806		$	806


Repayments, repurchases, and other
EPEP revolving credit facility	variable			$	(400	)	$	(400	)
El Paso revolving credit facility	variable				(100	)		(100	)
EPPOC revolving credit facility	variable				(107	)		(107	)
El Paso notes due 2012 through 2025		7.25%-12.00	%		(140	)		(181	)
Other	various				(4	)		(6	)

Decreases through March 31, 2011				$	(751	)	$	(794	)

swaps that begin in July 2011 and convert the floating LIBOR interest rate to fixed interest rates on approximately $1.1 billion of total borrowings under this agreement. ~~For a further discussion of these swaps, see Note 8.~~

We have provided a contingent completion and cost-overrun guarantee to the Ruby lenders; however, upon the Ruby pipeline project becoming operational and making certain permitting representations, the project financing will become non-recourse to us. Pursuant to the cost overrun guarantee to the Ruby lenders, ~~we are required to post letters~~as of ~~credit for any forecasted cost overruns on the project approved by the lender’s independent engineer. In this regard,~~March 31, 2011, we have ~~posted $245~~$350 million outstanding in letters of credit to cover ~~the~~ anticipated cost overruns. If additional ~~costs~~cost overruns are forecasted and approved by the lender’s engineer in subsequent months, ~~then~~ additional ~~letters of credit will~~collateral may be required to be issued pursuant to the Ruby financing agreements.

~~10.~~7. Commitments and Contingencies

Legal Proceedings

Cash Balance Plan Lawsuit.In December 2004, a purported class action lawsuit entitledTomlinson, et al.v. El Paso Corporation and El Paso Corporation Pension Planwas filed in U.S. District Court for Denver, Colorado. The lawsuit alleges various violations of the Employee Retirement Income Security Act (ERISA) and the Age Discrimination in Employment Act as a result of our change from a ~~defined benefit~~final average earnings formula pension plan to a cash balance pension plan. ~~The~~In 2010, a trial court ~~has~~ dismissed all of the ~~claims.~~claims in this matter. The dismissal of the case has been appealed.

~~Retiree Medical Benefits Matters.~~~~In 2002, a lawsuit entitled~~~~Yolton et al. v. El Paso Tennessee Pipeline Co. and Case Corporation~~was filed in a federal court in Detroit, Michigan on behalf of a group of retirees of Case Corporation (Case) that alleged they are entitled to retiree medical benefits under a medical benefits plan for which we serve as plan administrator pursuant to a merger agreement with Tenneco Inc. Although we had asserted that our obligations under the plan were subject to a cap pursuant to an agreement with the union for Case employees, the trial court ruled that the benefits were vested and not subject to the cap. As a result, we are currently obligated to pay the amounts above the cap. In addition, we are obligated to pay damages incurred by retirees prior to the court’s ruling that the benefits were not subject to the cap pursuant to a claims procedure approved by the court. We have been engaged in settlement discussions with the plaintiffs. However, if we are unable to reach a mutually agreeable settlement, we intend to pursue appellate options. We believe our accruals established for this matter are adequate.

Price Reporting Litigation.Beginning in 2003, several lawsuits were filed against El Paso Marketing L.P. (EPM) alleging that El Paso, EPM and other energy companies conspired to manipulate the price of natural gas by providing false price information to industry trade publications that published gas indices. While some of the cases have been settled or dismissed, several of the cases are in various stages of pre-trial or appellate proceedings as further described in our ~~2009~~2010 Annual ~~Report~~report on Form 10-K. ~~In September 2010, the dismissal~~Although damages in excess of $140 million have been alleged in total against all defendants in one of the ~~Missouri state court lawsuit entitled~~~~Missouri Public Service v. El Paso Corporation, et al~~~~was upheld on appeal~~remaining lawsuits where a damage number is provided, there remains significant uncertainty regarding the validity of the causes of action, the damages asserted and ~~is now a final judgment. Our~~the level of damages, if any, that may be allocated to us. Therefore, our costs and legal exposure related to the remaining outstanding lawsuits and claims are not currently determinable.

MTBE. Certain of our subsidiaries used, produced, sold or distributed methyl tertiary-butyl ether (MTBE) as a gasoline additive. Various lawsuits were filed throughout the U.S. regarding the potential impact of MTBE on water supplies. The lawsuits have been brought by different parties, including state attorney generals, water districts and individual water companies seeking different remedies against us and many other defendants, including remedial activities, damages, attorneys’ fees and costs. These cases were initially consolidated for pre-trial purposes in multi-district litigation (MDL) in the U.S. District Court for the Southern District of New York. Several cases were later remanded to state court. Eighty-seven of the cases have been settled or dismissed, with all of the settlements being substantially funded by insurance. We have twelve remaining lawsuits, which consist of ten cases that are pending in the MDL and two cases that are pending in state courts. Of ~~our twelve~~these remaining lawsuits, it is likely that our insurers will assert denial of coverage on nine of the ~~nine~~ most-recently ~~filed. Our~~filed lawsuits. Although damages in excess of two billion dollars have been alleged in total against all defendants in some of the remaining cases, based upon discovery conducted to date, our share of the relevant markets upon which alleged damages have been historically allocated among individual defendants is relatively small. In addition, there remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, that may be allocated to us as well as availability of insurance coverages. Therefore, our costs and legal exposure related to the remaining lawsuits are not currently determinable.

material. As of ~~September 30, 2010,~~March 31, 2011, we had approximately ~~$49~~$50 million accrued, which has not been reduced by $2$3 million of related insurance receivables, for all of our outstanding legal proceedings.

Rates and Regulatory Matters

~~El Paso Natural Gas Company (EPNG)~~EPNG Rate Case.In April 2010, the FERC approved an uncontested partial offer of settlement which increased EPNG’s base tariff rates, effective January 1, 2009. As part of the settlement, EPNG made ~~an initial refund~~refunds to its customers in ~~April 2010, and paid the remaining refunds in August~~ 2010. The settlement resolved all but four issues in the proceeding. ~~A hearing~~In January 2011, the Presiding Administrative Law Judge issued a decision that for the most part found against EPNG on the ~~remaining issues was completed in June 2010~~four issues. EPNG will appeal those decisions to the FERC and may also seek review of any of the FERC’s decisions to the U.S. Court of Appeals. Although the final outcome is not currently ~~determinable. We~~determinable, we believe our accruals established for this matter are ~~adequate.~~adequate based on the expected final outcome.

In September 2010, EPNG filed a new rate case with the FERC proposing an increase in its base tariff rates as permitted under the settlement of the previous rate case. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, 2011, subject to refund, the outcome of a hearing and other proceedings. At this time, the outcome of this matter is not ~~currently~~ determinable.

TGP Rate Case.In November 2010, TGP filed a rate case with the FERC proposing an increase in its base tariff rates, including a proposed change in its 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.

CIG Rate Case.In February 2011, the FERC approved an amendment of CIG’s 2006 rate case settlement allowing the effective date of a required new rate case to be moved to December 1, 2011. In April 2011, CIG filed a second petition to amend the effective date of a required new rate case to be moved to February 1, 2012 to allow CIG and its shippers the opportunity to reach a settlement of the rate proceeding before it is formally filed with the FERC. The FERC has not ruled on that petition. At this time, the outcome of the pre-filing settlement negotiations and the outcome of the upcoming general rate case, in the event pre-filing settlement cannot be reached, are uncertain.

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 30, 2010, we had accrued~~March 31, 2011, our accrual was approximately ~~$177~~$168 million for environmental matters, which has not been reduced by ~~$20~~$19 million for amounts to be paid directly under government sponsored programs or through contractual arrangements with third parties. Our accrual includes approximately ~~$173~~$165 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $4$3 million for related environmental legal costs. Of the $177 million accrual, $12 million was reserved for facilities we currently operate and $165 million was reserved for non-operating sites (facilities that are shut down or have been sold) and Superfund sites.

Our estimates of potential liability range from approximately ~~$177~~$168 million to approximately ~~$374~~$352 million. Our recorded environmental liabilities reflect our current estimates of amounts we will expend on remediation projects in various stages of completion. 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. By type of site, our reserves are based on the following estimates of reasonably possible outcomes:

September 30, 2010
Sites Expected High
(In millions)
Operating $ 12 $ 20
Non-operating 149 315
Superfund 16 39

Total $ 177 $ 374

Superfund, or state equivalents for 3130 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 previously indicated estimates for Superfund sites.

For ~~the remainder of 2010,~~2011, we estimate that our total remediation expenditures will be approximately ~~$16~~$40 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 ~~$25~~$27 million in the aggregate for the remainder of ~~2010~~2011 through ~~2014. Included in this amount is approximately $20 million to be expended from 2010 to 2013~~2015, including capital expenditures associated with the impact of the Environmental Protection Agency (EPA) rule on emissions of hazardous air pollutants from reciprocating internal combustion engines which ~~was finalized in August 2010. Our engines that~~ are subject to ~~the~~ 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.

Guarantees and Other Contractual Commitments

Guarantees and Indemnifications.We ~~are involved in various joint ventures~~have guarantees and other ownership arrangements that sometimes require financial and performance guarantees. We also periodically provide indemnification arrangements related to assets or businesses we have sold for which our potential exposure can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. For a further discussion, see our 2009 Annual Report on Form 10-K. For those arrangementsindemnifications with ~~a specified dollar amount, we have~~ a maximum stated value of approximately $0.8 billion, primarily related to indemnification arrangements associated with the sale of ANR Pipeline Company in 2007 ~~our Macae power facility in Brazil,~~ and ~~other~~certain legacy assets. These amounts exclude guarantees for which we have issued related letters of credit discussed in Note ~~9. Included in the above maximum stated value are certain indemnification agreements that have expired; however, claims were made prior to the expiration of the related claim periods.~~6. We are unable to estimate a maximum exposure of our guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.

As of ~~September 30, 2010,~~March 31, 2011, we have recorded obligations of ~~$19~~$17 million related to our guarantee and indemnification arrangements. Our liability consists primarily of an indemnification that one of our subsidiaries provided related to its sale of an ammonia facility that is reflected in our financial statements at its estimated fair value. We have provided a partial parental guarantee of our subsidiary’s obligations under this indemnification. We believe that our guarantee and indemnification agreements for which we have not recorded a liability are not probable of resulting in future losses based on our assessment of the nature of the guarantee, the financial condition of the guaranteed party and the period of time that the guarantee has been outstanding, among other considerations.

~~Commitments, Purchase Obligations~~For a further discussion of our guarantees, indemnifications, purchase obligations, and ~~Other Matters.~~In 2009, the FERC approved an amendment to the 1995 FERC settlement with Tennessee Gas Pipeline Company (TGP) that provides for interim refunds over a three year period of approximately $157 million for amounts collected related to certain environmental costs. These refunds are recorded as other ~~current and non-current liabilities~~commercial commitments see our 2010 Annual Report on ~~our balance sheet and are expected to be paid over a three year period with interest. As of September 30, 2010, TGP has refunded approximately $49 million to their customers.~~Form 10-K.

~~11.~~8. Retirement Benefits

Components of Net Benefit Cost.The components of net benefit cost ~~for our pension and postretirement benefit plans~~are as follows for the quarters ~~and nine months~~ ended ~~September 30, are as follows:~~March 31:


	Quarters Ended September 30,												Nine Months Ended September 30,
							Other												Other												Other
	Pension						Postretirement						Pension						Postretirement						Pension						Postretirement
	Benefits						Benefits						Benefits						Benefits						Benefits						Benefits
	2010			2009			2010			2009			2010			2009			2010			2009			2011			2010			2011			2010
	(In millions)																								(In millions)
Service cost	$	5		$	6		$	—		$	—		$	14		$	14		$	—		$	—		$	5		$	5		$	—		$	—
Interest cost		29			31			8			10			86			91			25			29			26			28			8			8
Expected return on plan assets		(39	)		(43	)		(3	)		(3	)		(118	)		(129	)		(10	)		(9	)		(36	)		(39	)		(4	)		(3	)
Amortization of net actuarial loss (gain)		18			12			—			—			55			34			(2	)		—			23			19			—			(1	)
Amortization of prior service cost (credit)		—			(1	)		(1	)		(1	)		1			(1	)		(1	)		(1	)

Net benefit cost	$	13		$	5		$	4		$	6		$	38		$	9		$	12		$	19		$	18		$	13		$	4		$	4

Noncontrolling ~~Interests.~~~~During the first half of 2010, we contributed a 51 percent interest~~Interest in ~~Southern LNG Company, L.L.C. (SLNG), which owns~~EPB.We are the Elba Island LNG receiving terminal, a 51 percent interest in El Paso Elba Express Company, L.L.C. (Elba Express), which owns the Elba Express Pipeline, and an additional 20 percent interest in Southern Natural Gas Company (SNG) to EPB in exchange for $1.3 billion which included cash and 5.3 million EPB common units. EPB raised the funds for the acquisitions primarily through the issuance of 21.4 million common units, which increased our noncontrolling interests, and the proceeds from debt offerings. In September 2010, EPB issued a total of 13.2 million common units to the public and 0.3 million general partner ~~units to us.~~of EPB, a master limited partnership (MLP) formed in 2007. As of ~~September 30, 2010, our ownership interest in EPB is 54 percent, including our~~March 31, 2011, we hold a 2 percent general partner ~~interest.~~

interest and a 45 percent limited partner interest in the partnership. In accordance with its partnership agreement, EPB ~~makes~~is obligated to make quarterly distributions of available cash to its ~~unitholders~~unitholders. We receive our share of these cash distributions through our limited partner ownership interest, general partner interest, and incentive distribution rights (IDRs) we are entitled to as the general partner. Prior to February 15, 2011, we held subordinated units in ~~accordance with its partnership agreement.~~EPB. Upon payment of the quarterly cash distribution for the fourth quarter of 2010, the financial tests required for the conversion of subordinated units into common units were satisfied. As a result, our subordinated units were converted on February 15, 2011 into common units on a one-for-one basis effective January 3, 2011.

During the ~~nine months~~first quarter of 2011, EPB issued 13.8 million common units for $457 million in conjunction with the contribution of an additional 25 percent ownership interest in Southern Natural Gas (SNG). While we still control EPB, as a result of this unit issuance our total ownership percentage in EPB (including our general partner interest) decreased from approximately 51 percent to 47 percent. Our consolidated statement of equity for the quarter ended ~~September 30, 2010 and 2009,~~March 31, 2011 reflects the issuance of the EPB ~~made cash distributions~~common units as an increase of ~~$64 million and $33~~$287 million to ~~its non-affiliated common unitholders. We have recorded~~noncontrolling interests and $170 million to El Paso Corporation’s additional paid-in capital. Our net income attributable to ~~noncontrolling~~El Paso Corporation, together with the increase in El Paso Corporation’s additional paid-in capital for the quarter ended March 31, 2011 totaled $232 million.

To the extent that the consideration for the sales of assets to EPB is not in the form of additional equity in EPB, our interest ~~holders~~in our assets becomes diluted over time. However our economic interest will benefit from the receipt of ~~$25 million~~incentive distributions in accordance with the partnership agreement.

Our IDRs provide for the receipt of an increasing portion of quarterly distributions based on the level of distribution to all unitholders. We can elect to relinquish the right to receive incentive distribution payments and ~~$15 million during~~reset, at higher levels, the ~~quarters ended September 30, 2010~~minimum quarterly distribution amount and ~~2009, and $75 million and $38 million during~~cash target distribution levels upon which the ~~nine months ended September 30, 2010 and 2009, which represents~~incentive distribution payments would be set. We are currently entitled to receive the ~~non-affiliated common unitholders share~~maximum level of ~~EPB’s income.~~incentive distributions.

Preferred Stock of Subsidiaries.During ~~2009, Global Infrastructure Partners (GIP),~~the quarter ended March 31, 2011, our partner on our Ruby pipeline project, Global Infrastructure Partners (GIP), contributed ~~$145~~an additional $30 million ~~to our subsidiary,~~and as of March 31, 2011 had contributed $700 million, including approximately $555 million for a convertible preferred interest in Ruby Pipeline Holding Company, L.L.C. (Ruby) and ~~received a convertible preferred equity interest in Ruby that was simultaneously exchanged~~$145 million for a convertible preferred equity interest in Cheyenne Plains ~~Investment~~Gas Pipeline Company, L.L.C. (Cheyenne Plains). GIP earns a 15 percent dividend on its preferred interests in Cheyenne Plains. In addition, GIP provided a $405 million loan for Ruby project funding. During the third quarter of 2010, GIP’s loan of $405 million was converted to a convertible preferred equity interest in Ruby. In addition, GIP provided an additional $120 million contribution for a convertible preferred equity interest in Ruby. GIP will earn a 13 percent return on its convertible preferred interests in Ruby beginning on the earlier of the date ~~Ruby~~the pipeline project is placed in ~~service. For a further discussion of the Ruby transaction, see Note 14.~~

The convertible preferred equity interests in Cheyenne Plains and Ruby have been classified between liabilities and equity on our balance sheet since the events that require redemption of the preferred interests are not entirely within our control and are not certain to occur.service or August 2011. We paid preferred dividends of $5 ~~million and $15~~ million on GIP’s preferred interest in Cheyenne Plains for the ~~quarter~~quarters ended March 31, 2011 and ~~nine months ended September 30,~~ 2010. Also, for the ~~nine months~~quarter ended ~~September 30, 2010,~~March 31, 2011, we ~~recognized a~~recorded $17 million related to the return ~~of $11 million~~ on GIP’s preferred interest in Ruby. Both the preferred dividends and the return on GIP’s preferred interests are reflected in net income attributable to noncontrolling interests on our income statement. GIP’s preferred interests in Cheyenne Plains and Ruby are classified between liabilities and equity on our balance sheet. For a further discussion of the Ruby transaction, see Note 11.

Net Income Attributable to Noncontrolling Interests.The components of net income attributable to noncontrolling interests on our statements of income are as follows for the quarters ~~and nine months~~ ended ~~September 30, are as follows:~~March 31:


	Quarters Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009		2011		2010
	(In millions)								(In millions)
EPB	$	25	$	15	$	75	$	38	$	52	$	26
Preferred Stock of Cheyenne Plains		5		—		15		—		5		5
Preferred Stock of Ruby		11		—		11		—		17		—

Net income attributable to noncontrolling interests	$	41	$	15	$	101	$	38	$	74	$	31

~~13.~~10. Business Segment Information

As of ~~September 30, 2010,~~March 31, 2011, our business consists of ~~two core segments,~~the following segments: Pipelines, ~~and~~ Exploration and Production, ~~as well as our Marketing segment.~~and Marketing. We also have other business and corporate activities. Our segments are strategic business units that provide a variety of energy products and services. They are managed separately as each segment requires different technology and marketing strategies. ~~Prior to 2010, we also had a Power segment which has been combined into our corporate and other activities for all periods presented.~~ A further discussion of each segment ~~and our corporate and other activities~~ follows.

Pipelines.Our Pipelines segment provides natural gas transmission, storage, and related services, primarily in the ~~United States.~~U.S. As of ~~September 30, 2010,~~March 31, 2011, we conducted our activities primarily through eight wholly or majority owned interstate pipeline systems and equity interests in two transmission systems. In addition to the storage capacity in our wholly and majority owned pipelines systems, we also own or have interests in three underground natural gas storage facilities and two LNG terminal facilities, one of which is under construction.

Exploration and Production.Our Exploration and Production segment is engaged in the exploration for and the acquisition, development and production of oil, natural gas ~~oil~~ and NGL, in the ~~United States,~~U.S., Brazil and Egypt.

Marketing.Our Marketing segment markets on behalf of our Exploration and Production segment and manages the price risks associated with our oil and natural gas ~~and oil~~ production as well as manages our remaining legacy trading portfolio.

~~Corporate and~~ Other.Our ~~corporate and~~ other activities include our corporate general and administrative functions, ~~our emerging~~ midstream ~~business, our remaining power~~ operations and other miscellaneous businesses.

~~Our management uses~~Beginning January 1, 2011, we use segment earnings before interest expense and income taxes ~~(EBIT)~~(Segment EBIT) as a measure to assess the operating results and effectiveness of our business ~~segments which consist of both consolidated businesses and investments in unconsolidated affiliates.~~segments. We believe Segment EBIT is useful to our investors because it allows them to ~~evaluate more effectively the operating performance using~~use the same performance measure analyzed internally by our ~~management. We define~~management to evaluate the performance of our businesses and investments without regard to the manner in which they are financed or our capital structure. Segment EBIT is defined as net income (loss) adjusted for ~~items such as (i)~~ interest and debt expense ~~(ii)~~and income ~~taxes, and (iii) net income~~taxes. It does not reflect a reduction for any amounts attributable to noncontrolling ~~interests so that our investors may evaluate our operating results without regard to our financing methods or capital structure.~~interests. Segment EBIT may not be comparable to ~~measures~~measurements used by other companies. Additionally, Segment EBIT should be considered in conjunction with net income (loss), income (loss) before income taxes and other performance measures such as operating income or operating cash flows. Our 2010 amounts have been conformed to reflect our current performance measure.

Below is a reconciliation of our Segment EBIT to our net income ~~(loss)~~ for the periods ended ~~September 30:~~March 31:

Quarters Ended Nine Months Ended
September 30, September 30,
2010 2009 2010 2009
(In millions)
Segment EBIT $ 583 $ 386 $ 1,908 $ (453 )
Corporate and Other (111 ) (28 ) (96 ) (21 )

Consolidated EBIT 472 358 1,812 (474 )
Interest and debt expense (255 ) (256 ) (782 ) (764 )
Income tax benefit (expense) (75 ) (35 ) (343 ) 425

Net income (loss) attributable to El Paso Corporation 142 67 687 (813 )
Net income attributable to noncontrolling interests 41 15 101 38

Net income (loss) $ 183 $ 82 $ 788 $ (775 )


	2011			2010
	(In millions)
Segment EBIT	$	395		$	848
Interest and debt expense		(240	)		(243	)
Income tax expense		(19	)		(186	)

Net income		136			419
Net income attributable to noncontrolling interests		(74	)		(31	)

Net income attributable to El Paso Corporation	$	62		$	388

2118

Segments
Exploration Corporate
Pipelines and Production Marketing and Other⁽¹⁾ Total
(In millions)
Nine Months Ended September 30, 2010

Revenue from external customers $ 2,072 $ 966 ⁽²⁾ $ 556 $ 38 $ 3,632
Intersegment revenue 37 569 ⁽²⁾ (601 ) (5 ) —
Operation and maintenance 599 ⁽⁴⁾ 275 — 37 911
Ceiling test charges — 16 — — 16
Depreciation, depletion and amortization 327 352 — 20 699
Earnings (losses) from unconsolidated affiliates 157 ⁽³⁾ (3 ) — 13 167
EBIT 1,198 754 (44 ) (96 )⁽⁵⁾ 1,812

Nine Months Ended September 30, 2009

Revenue from external customers $ 2,016 $ 977 ⁽²⁾ $ 443 $ 2 $ 3,438
Intersegment revenue 34 375 ⁽²⁾ (401 ) (8 ) —
Operation and maintenance 587 306 7 10 910
Ceiling test charges — 2,085 — — 2,085
Depreciation, depletion and amortization 310 334 — 9 653
Earnings (losses) from unconsolidated affiliates 73 (29 ) — (2 ) 42
EBIT 1,049 (1,536 ) 34 (21 ) (474 )


⁽¹⁾		Includes eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. During the nine months ended September 30, 2010 and 2009, we recorded an intersegment revenue elimination of $16 million and $8 million in the “Corporate and Other” column to remove intersegment transactions.

⁽²⁾		Revenues from external customers include gains of $468 million and $536 million for the nine months ended September 30, 2010 and 2009 related to our financial derivative contracts associated with our natural gas and oil production. Intersegment revenues represent sales to our Marketing segment, which is responsible for marketing our production to third parties.

⁽³⁾		~~Includes a gain of approximately $80 million related to the sale of certain of our interests in Mexican pipeline and compression assets.~~

⁽⁴⁾		~~Includes a $21 million non-cash asset write down based on a FERC order related to the sale of a compressor station and gas processing plant in 2009.~~

⁽⁵⁾		~~Includes a $104 million loss on debt extinguishment as further discussed in Note 4.~~

Total assets by segment are presented below:


	September 30,		December 31,		March 31,			December 31,
	2010		2009		2011			2010
	(In millions)				(In millions)
Pipelines	$	18,932	$	17,324	$	20,189		$	19,651
Exploration and Production		4,652		4,025		4,735			4,657
Marketing		213		345		210			222
Other						896			943

Total segment assets		23,797		21,694		26,030			25,473
Corporate and Other		710		811
Eliminations						(173	)		(203	)

Total consolidated assets	$	24,507	$	22,505	$	25,857		$	25,270

During the third quarter of 2010, (i) GIP’s loan of $405 million was converted to a convertible preferred equity interest in Ruby; (ii) GIP provided an additional $120 million contribution for a convertible preferred equity interestinterests (see Note 9) in Ruby and ~~(iii)~~Cheyenne Plains. We consolidate Ruby and Cheyenne Plains as variable interest entities as we ~~borrowed approximately $362 million under~~are the ~~$1.5 billion facility. In October 2010, we made an additional draw~~primary beneficiary of ~~approximately $240 million~~these entities that own the Ruby pipeline project and the Cheyenne Plains pipeline. GIP’s contributions are classified between liabilities and equity on our balance sheet since the ~~facility.~~

events that require redemption of the preferred interests are not entirely within our control and are not certain to occur. GIP will hold its interest in Cheyenne Plains until certain conditions are satisfied including placing the Ruby pipeline project in service. GIP has the right to convert its preferred equity in Ruby to common equity in Ruby at any time; however, the preferred equity is subject to mandatory conversion to Ruby common equity upon the satisfaction of certain conditions, including Ruby entering into additional firm transportation agreements.

If all conditions to completion are satisfied or waived, GIP would own a 50 percent equity interest in Ruby and all ownership in Cheyenne Plains would be transferred back to us. However, if certain conditions are not satisfied including placing the Ruby pipeline project in service by the end of November ~~2011,~~2011. Should this not occur, GIP has the option to convert its Cheyenne Plains preferred interest to a common interest and/or be repaid in cash for its remaining investments in Cheyenne Plains and Ruby including a 15 percent return on its investments in Cheyenne Plains and Ruby. Our obligation to repay these amounts is secured by our equity interests in Ruby, Cheyenne Plains, and approximately 50 million common units we own in EPB. ~~For~~If all conditions to closing are satisfied or waived, GIP would own a ~~further discussion of our~~50 percent preferred equity interest in Ruby ~~transaction, refer~~and all ownership in Cheyenne Plains would be transferred back to ~~Note 12 and our 2009 Annual Report on Form 10-K.~~

~~Other.~~~~We also hold interests~~us. Additionally, GIP has the right to convert its preferred equity in ~~other variable interest entities that we account for as investments~~Ruby to common equity in ~~unconsolidated affiliates. These entities do not have significant operations and accordingly do not have a material impact to our financial statements.~~Ruby at any time.

Accounts Receivable Sales ~~Programs.~~Program.~~During 2009,~~We participate in accounts receivable sales programs where several of our pipeline subsidiaries ~~had agreements~~sell receivables in their entirety to ~~sell senior interests in certain~~a third-party financial institution (through wholly-owned special purpose entities). The sale of ~~their~~these accounts receivable (which are short-term assets that generally settle within 60 days) to a third party financial institution (through wholly-owned special purpose entities), and we retained subordinated interests in those receivables. The sale of these senior interests qualified for sale accounting and was conducted to accelerate cash from these receivables, the proceeds from which were used to increase liquidity and lower our overall cost of capital. During the quarter and nine months ended September 30, 2009, we received $230 million and $709 million of cash related to the sale of the senior interests, collected $197 million and $686 million from the subordinated interests we retained in the receivables, and recognized a loss of approximately $1 million on these transactions. At December 31, 2009, the third party financial institution held $90 million of senior interests and we held $79 million of subordinated interests. Our subordinated interests are reflected in accounts receivable on our balance sheet. In January 2010, we terminated these accounts receivable sales programs and paid $90 million to acquire the senior interests. We reflected the cash flows related to the accounts receivable sold under this program, changes in our retained subordinated interests, and cash paid to terminate the programs, as operating cash flows on our statement of cash flows.

~~In the first quarter of 2010, we entered into new accounts receivable sales programs 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, and to include an additional pipeline subsidiary’s accounts receivable in the program. Under these programs, several of our pipeline subsidiaries sell receivables in their entirety to the third-party financial institution (through wholly-owned special purpose entities). As of September 30, 2010, the third-party financial institution held $195 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 to recover this additional amount is based solely on the collection of the underlying receivables. During the quarter and nine months ended September 30, 2010, we received $338 million and $1.1 billion of cash up front from the sale of the receivables and received an additional $266 million and $746 million of cash upon the collection of the underlying receivables. As of September 30, 2010, we had not collected approximately $81 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 as a Level 2 measurement). We recognized a loss of approximately $1 million and $2 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 programs as operating cash flows on our statement of cash flows.

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.

accounting. 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 control, direct, or exert significant influence over 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.

~~15. Investments in, Earnings from~~ In connection with our accounts receivable sales, we receive a portion of the sales proceeds up front and ~~Transactions with Unconsolidated Affiliates~~

~~We hold investments in unconsolidated affiliates which are accounted for using~~receive an additional amount upon the ~~equity method~~collection of ~~accounting.~~the underlying receivables (which we refer to as a deferred purchase price). Our ability to recover the deferred purchase price is based solely on the collection of the underlying receivables. The earnings from unconsolidated affiliates reflected on our income statement include (i) our share of net earnings directly attributable to these unconsolidated affiliates, and (ii) impairments, gains and losses on divestitures and other adjustments recorded by us. Thetable below contains information ~~below~~ related to our unconsolidated affiliates includes (i) our net investment and earnings (losses) we recorded from these investments, (ii) summarized financial information of our proportionate share of these investments, and (iii) revenues and charges with our unconsolidated affiliates.accounts receivable sales program.

Earnings (Losses) from
Investment Unconsolidated Affiliates
Quarters Ended Nine Months Ended
September 30, December 31, September 30, September 30,
2010 2009 2010 2009 2010 2009
(In millions) (In millions)
Net Investment and Earnings (Losses)

Four Star⁽¹⁾
$ 408 $ 450 $ (2 ) $ (7 ) $ (3 ) $ (29 )
Citrus 704 630 27 20 67 54
Gulf LNG⁽²⁾
252 285 (1 ) (1 ) (1 ) (2 )
Gasoductos de Chihuahua⁽³⁾
— 184 — 5 88 17
Bolivia-to-Brazil Pipeline 102 105 1 (6 ) 10 (7 )
Other 72 64 3 — 6 9

Total $ 1,538 $ 1,718 $ 28 $ 11 $ 167 $ 42


	Quarter Ended
	March 31,
	2011		2010
	(In billions)
Accounts receivable sold to the third-party financial institution⁽¹⁾	$	0.6	$	0.6
Cash received for accounts receivable sold under the program		0.4		0.5
Deferred purchase price related to accounts receivable sold		0.2		0.1
Cash received related to the deferred purchase price		0.2		0.2
Amount paid in conjunction with terminated programs⁽²⁾		—		0.1


⁽¹⁾		We^{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 $90 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 billions)
Accounts receivable sold and held by third-party financial institution	$	0.2	$	0.2
Uncollected deferred purchase price related to accounts receivable sold⁽¹⁾		0.1		0.1


⁽¹⁾		^{Initially recorded at an amount which approximates its fair value as a Level 2 measurement.}

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 programs as operating cash flows on our statement of cash flows. Under the accounts receivable sales programs, we service 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 quarters ended March 31, 2011 and 2010.

12. Investments in, Earnings from and Transactions with Unconsolidated Affiliates

Our net investments in and earnings (losses) from our unconsolidated affiliates are as follows as of March 31, 2011 and December 31, 2010 and for the quarters ended March 31:


					Earnings (Losses) from
	Investment				Unconsolidated Affiliates
	March 31,		December 31,		Quarter Ended March 31,
	2011		2010		2011			2010
	(In millions)				(In millions)
Net Investment and Earnings (Losses)
Four Star⁽¹⁾	$	381	$	393	$	(2	)	$	—
Citrus⁽²⁾		847		822		25			15
Gulf LNG⁽³⁾		267		266		—			—
Bolivia-to-Brazil Pipeline		106		104		2			5
Other		82		88		5			8

Total	$	1,683	$	1,673	$	30		$	28


⁽¹⁾		^{Our amortization of our purchase cost in excess of the underlying net assets of Four Star ofwas $9 million and $12$10 million for the quarters ended September 30, 2010March 31, 2011 and 2009 and $28 million and $37 million for the nine months ended September 30, 2010 and 2009.2010.}

⁽²⁾		^{As of September 30, 2010March 31, 2011, we had outstanding receivables of approximately $13 million, not included above, related to a promissory note from Citrus whereby we will lend up to $150 million. During April 2011, Citrus drew an additional $12 million under the note.}

⁽³⁾		^{As of March 31, 2011 and December 31, 2009,2010, we had outstanding advances and receivables of $78$88 million and $56$85 million, not included above, related to our investment in Gulf LNG.}

⁽³⁾		~~In April 2010, we completed~~ These amounts include interest on the ~~sale of our interest in this investment~~related advances and ~~recorded a pretax gain of approximately $80 million. See Note 2.~~receivables.


	Quarters Ended				Nine Months Ended				Quarter Ended
	September 30,				September 30,				March 31,
	2010		2009		2010		2009		2011		2010
			(In millions)						(In millions)
Summarized Financial Information
Operating results data:
Operating revenues	$	126	$	124	$	386	$	382	$	128	$	132
Operating expenses		63		58		201		195		67		73
Net income		40		34		119		93		40		38

Other Investment-Related Matters.We currently have outstanding disputes and other matters related to an investment in two Brazilian power plant facilities (Manaus/Rio Negro) formerly owned by us. We have filed lawsuits to collect amounts due to us (approximately ~~$68~~$71 million of Brazilian reais-denominated accounts receivable) by the ~~plant’s~~plants’ power purchaser, which are also guaranteed by the purchaser’s ~~parent.~~parent, Eletrobras, Brazil’s state-owned utility. The power utility that purchased the power from these facilities and its parent have asserted counterclaims that would largely offset our accounts receivable. We have not established an allowance against the receivables owed and have accrued what we believe is an appropriate amount in relation to the asserted counterclaims.

Our project companies that previously owned ~~the~~ the Manaus and Rio Negro power plants have also been assessed approximately ~~$75~~$82 million of Brazilian reais-denominated ICMS taxes by the Brazilian taxing authorities for payments received by the companies from the plants’ power purchaser from 1999 to 2001. By agreement, the power purchaser must indemnify our project companies for these ICMS taxes, along with related interest and penalties, and has therefore been defending the projects against this lawsuit. In order to prevent further collection efforts by the tax authorities for this matter, security must be provided for the potential tax liability to the court’s satisfaction. The tax authorities and court ~~have~~ rejected ~~the~~certain assets pledged by the power purchaser, ~~to date,~~ and during the third quarter of 2010 the tax courts blocked certain of El Paso’s bank accounts associated with the Rio Negro power plant in order to obtain this security. The power purchaser has appealed the court’s decision. The power purchaser’s parent subsequently offered to pledge other assets acceptable to the tax authorities and a decision by the court whether to approve these assets is pending. If the court approves, then the power purchaser ~~is unable~~will ask the court to ~~resolve~~vacate any orders encumbering our bank accounts and other assets. Until this tax matter is resolved, our ability to collect amounts due to us from the power purchaser could be impacted. Any potential taxes owed by the Manaus and Rio Negro project companies are also guaranteed by the purchaser’s parent. Based on our assessment, we have not established any accruals for this matter.

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

The information contained in Item 2 updates, and ~~you~~ should be read it in conjunction with, 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.

Overview and Outlook

During the ~~first nine months of 2010,~~quarter ended March 31, 2011, our primary focus has been on the execution of our business plan, delivering on our backlog of expansion projects in our pipeline segment, and continued operational success in our exploration and production business. Our operating and financial results and outlook are discussed further in individual segment results.

~~In our pipeline business,~~Segment EBIT ~~for the quarter and nine months in 2010~~ was up 2 percent and 14 percent over the same periods in 2009, driven primarily by income on expansion projects and a gain on the sale of our Mexico Pipeline assets during the second quarter. Approximately 80 percent of our pipeline revenues are collected in the form of demand or reservation charges, which are not dependent upon commodity prices or throughput levels. This, coupled$395 million, compared with the diversity of our pipeline systems, helps mitigate against the risk of changes in throughput and ongoing shifts in supply and demand. Operationally, total pipeline throughput was down 3 percent year to date in 2010 versus$848 million for the same period in ~~2009. During~~2010. In 2011, Pipeline Segment EBIT increased slightly over 2010 ~~we experienced~~to approximately $499 million for the quarter benefiting from expansion projects placed in service in 2010 and from the allowance for funds used during construction (AFUDC) related to pipeline expansion projects not yet in service (including Ruby); partially offset by lower ~~demand and firm transportation commitments~~reservation revenues on our EPNG ~~system~~system. Our Exploration and ~~long haul transportation being replaced~~Production Segment EBIT decreased by ~~short haul transportation~~approximately $421 million largely due to mark-to-market impacts on our ~~Tennessee Gas Pipeline (TGP) system. As~~financial derivatives, despite increases in production volumes quarter over quarter. During the first quarter of 2011, we ~~experience shifts~~also incurred approximately $41 million in ~~gas flows, demand changes and changes in firm transportation commitments, we evaluate whether~~losses associated with the repurchase of debt. We continue to ~~file rate cases. Currently, one~~work towards completion of our ~~pipelines has an outstanding rate case pending before~~backlog of pipeline expansion projects, and in April, the ~~FERC and certain of our other pipelines have projected upcoming rate actions with anticipated effective dates from 2011 through 2014. Changes~~Florida Gas Transmission (FGT) Phase VIII Expansion was placed in ~~gas flows and the outcome of our rate cases can impact the financial performance of our pipeline segment.~~

In our pipeline business, we will continue to focus on execution of our pipeline backlog, a multi-year expansion program, the bulk of which occurs in 2010 and 2011. In 2010, we have placed three projects in service ~~and expect to place two additional projects in service in the fourth quarter, all~~ on time and ~~in total, expected to be approximately $100 million under~~on budget. On Ruby, our largest project, we began construction in mid-2010. Based on delays in obtaining regulatory clearances, we currently expect that the project will be completed in June 2011, three months later than originally anticipated, and will be approximately 10 to 15 percent over budget. Overall, we expect our multi-year pipeline expansion backlog to be within 5 percent of our original budgets.

In our exploration and production business, ~~we have~~our continued ~~executing on~~2011 capital focus is in our ~~strategy, with production volumes up slightly over 2009, lower per unit cash operating costs,~~Haynesville, Altamont, Eagle Ford, and ~~by expanding our 2011 and 2012 hedging programs designed~~Wolfcamp areas which provide us greater exposure to support our balance sheet and cash flows. Hedges on our 2010 natural gas production have allowed us to achieve a realized price of $5.93 per Mcf in 2010, at a time where realized prices in 2010 on physical sales of natural gas have been declining. We expect this trend of lower natural gas prices to continue, and we are currently hedged on approximately 60 percent of our remaining domestic natural gas volumes in 2010. Our expanded 2011 and 2012both oil and natural gas ~~production hedges will help protect our cash flows in these years.~~

~~We have shifted capital~~liquids opportunities. Finally, in our ~~exploration and production~~midstream business, ~~toward our core programs: Haynesville, Eagle Ford and Altamont. In addition,~~ we have focused on execution and cost management to ensure favorable economics of our programs in the current low gas price environment. In September, we leased approximately 123,000 acres in the Wolfcamp Shale play in the Permian Basin for approximately $180 million. The Wolfcamp Shale is an emerging oil shale play that will represent a new opportunity for us in 2011. The shift in our capital program to more activity in Eagle Ford and Altamont, as well as the expansion of our acreage position in Wolfcamp provides us greater exposure to oil or natural gas liquids opportunities. We intend to fund the cost of the acquired acreage in Wolfcamp over time through portfolio rationalization, and future development capital will compete with other programs in the portfolio. We are also considering securing a joint venture partner for our Eagle Ford acreage to accelerate development of this core area and optimize our total portfolio.

We continue to seek out opportunities ~~for our emerging Midstream business and have several projects under development~~ that focus on synergies with our pipeline and/or exploration and production ~~businesses. We will continue to focus on~~businesses, funding these projects in a manner that is consistent with our long-term goal of improving our balance sheet, including the evaluation of additional partnership opportunities on our projects. For the remainder of 2011, we expect that our pipeline and exploration and production operations will provide a strong base of earnings and operating cash flow. Our operating and financial results and outlook are further discussed in the individual segment results that follow.

From a liquidity perspective, we have funded our 2010 capital and liquidity needs largely through cash flow from operations and funds provided through capital market activities (including execution on our financing strategy utilizing EPB), bank facilities, project financings (including Ruby) and asset sales. By Juneas of ~~this year, we had met our 2010 funding needs, and our activities for the remainder of the year will be focused on meeting our~~March 31, 2011, ~~funding objectives. As of September 30, 2010,~~ we had approximately ~~$2.5~~$2.8 billion of available liquidity (exclusive of cash and credit facility capacity of EPB and Ruby). During the first quarter of 2011, we generated operating cash flow of approximately $0.5 billion and have spent approximately $1.1 billion primarily on our pipeline and exploration and production capital programs. Our remaining 2011 capital expenditures are approximately $2.1 billion and remaining debt maturities are approximately $0.5 billion, which we will repay as they mature. Among other financing activities, during the first quarter our MLP also issued approximately $0.5 billion in common units. As further described inLiquidity and Capital Resources,we believe we are well positioned in 2011 to meet our ~~current~~ obligations ~~based on the anticipated performance of~~as well as continue with our ~~core businesses,~~efforts to strengthen our ~~financing actions taken to date and our available liquidity.~~balance sheet. We will ~~however,~~ continue to assess and take further actions where prudent to meet our long-term objectives and capital ~~requirements. See~~~~Liquidity~~requirements and ~~Capital Resources~~~~for a further discussion of~~to address any changes in the financial and commodity markets and our ~~financing and capital activities.~~businesses.

2723

Segment Results

~~We have two core operating~~As of March 31, 2011, our business ~~segments,~~consists of the following segments: Pipelines, ~~and~~ Exploration and ~~Production.~~Production, and Marketing. We also have ~~a Marketing segment~~other business and corporate activities that ~~markets our natural gas~~include midstream and ~~oil production and manages our legacy trading activities.~~other miscellaneous businesses. Our segments are managed separately, provide a variety of energy products and services, and require different technology and marketing strategies. ~~Prior to 2010,~~

Beginning January 1, 2011, we ~~also had a Power~~use segment which has been combined into our corporate and other activities for all periods presented. Our corporate and other activities include our general and administrative functions, our emerging midstream business, our remaining power operations, and other miscellaneous businesses.

~~Our management uses~~ earnings before interest expense and income taxes ~~(EBIT)~~(Segment EBIT) as a measure to assess the operating results and effectiveness of our business ~~segments, which consist of both consolidated businesses and investments in unconsolidated affiliates.~~segments. We believe Segment EBIT is useful to our investors because it allows them to ~~evaluate more effectively our operating performance using~~use the same performance measure analyzed internally by our ~~management. We define~~management to evaluate the performance of our businesses and investments without regard to the manner in which they are financed or our capital structure. Segment EBIT is defined as net income (loss) adjusted for ~~items such as (i)~~ interest and debt expense ~~(ii)~~and income ~~taxes and (iii) net income~~taxes. It does not reflect a reduction for any amounts attributable to noncontrolling ~~interests so that our investors may evaluate our operating results without regard to our financing methods or capital structure.~~interests. Segment EBIT may not be comparable to measurements used by other companies. Additionally, Segment EBIT should be considered in conjunction with net income (loss), income (loss) before income taxes and other performance measures such as operating income or operating cash flows. Our 2010 amounts have been conformed to reflect our current performance measure.

Below is a reconciliation of our Segment EBIT ~~(by segment)~~ to our consolidated net income ~~(loss)~~ for the quarters ~~and nine months~~ ended ~~September 30:~~March 31:


	Quarters Ended						Nine Months Ended
	September 30,						September 30,
	2010			2009			2010			2009			2011			2010
				(In millions)									(In millions)
Segment
Pipelines	$	334		$	326		$	1,198		$	1,049		$	499		$	452
Exploration and Production		261			88			754			(1,536	)		(31	)		390
Marketing		(12	)		(28	)		(44	)		34			(14	)		17
Other														(59	)		(11	)

Segment EBIT		583			386			1,908			(453	)		395			848
Corporate and Other		(111	)		(28	)		(96	)		(21	)
Interest and debt expense														(240	)		(243	)
Income tax expense														(19	)		(186	)

Consolidated EBIT		472			358			1,812			(474	)
Interest and debt expense		(255	)		(256	)		(782	)		(764	)
Income tax benefit (expense)		(75	)		(35	)		(343	)		425
Net income														136			419

Net income (loss) attributable to El Paso Corporation		142			67			687			(813	)
Net income attributable to noncontrolling interests		41			15			101			38			(74	)		(31	)

Net income (loss)	$	183		$	82		$	788		$	(775	)
Net income attributable to El Paso Corporation													$	62		$	388

Pipelines Segment

Overview and Operating Results.Our Pipelines ~~segment~~Segment EBIT for the quarter ~~and nine months~~ ended ~~September 30, 2010~~March 31, 2011 increased ~~2 percent and 14~~10 percent from the ~~same periods in 2009, and includes the impact of an $80 million gain recorded during the second~~first quarter of 2010 ~~on the sale of certain of our interests in Mexican pipeline and compression assets. During the first nine months of 2010, we also benefited~~benefiting primarily from several expansion projects placed in service in 2010 and ~~2009 and other income associated with~~an increase in AFUDC ~~primarily on~~related to pipeline expansion projects not yet in service, including our Ruby ~~pipeline project.~~project, offset by a decline in reservation revenues from our EPNG system due to lower demand and firm transportation commitments. Below are the operating results for our Pipelines segment as well as a discussion of factors impacting Segment EBIT for the quarters ~~and nine months~~ ended ~~September 30,~~March 31, 2011 compared with 2010, ~~and 2009,~~ or that could potentially impact Segment EBIT in future periods.


	Quarters Ended						Nine Months Ended
	September 30,						September 30,						2011			2010
	2010			2009			2010			2009			(In millions,
	(In millions, except for volumes)												except for volumes)
Operating revenues	$	692		$	667		$	2,109		$	2,050		$	753		$	737
Operating expenses		(402	)		(373	)		(1,128	)		(1,104	)		(378	)		(356	)

Operating income		290			294			981			946			375			381
Other income, net		85			47			318			141			124			71

EBIT before adjustment for noncontrolling interests		375			341			1,299			1,087
Net income attributable to noncontrolling interests		(41	)		(15	)		(101	)		(38	)
Segment EBIT													$	499		$	452

EBIT	$	334		$	326		$	1,198		$	1,049
Throughput volumes (BBtu/d)⁽¹⁾⁽²⁾														18,062			18,811

Throughput volumes (BBtu/d)⁽¹⁾		17,047			17,757			17,971			18,460

We capitalize a carrying cost (AFUDC) on ~~equity~~ funds related to our construction of long-lived assets. During the quarter ~~and nine months~~ ended ~~September 30 2010,~~March 31, 2011, we benefited from an increase in other income of approximately ~~$34 million and $92~~$49 million associated with the ~~pretax~~ equity portion of AFUDC on our expansion projects. This increase iswas primarily due to our Ruby pipeline project. ~~We will continue~~In April 2011, Ruby filed an amendment of its certificate requesting an increase in maximum initial recourse rates to ~~record~~reflect the new estimate of expected construction costs. Additionally, Ruby proposed in its filing to limit total AFUDC ~~until~~accruals to the total amounts included in the original certificate order. The FERC has not yet issued an order on the proposed amendment of the certificate.

Until placed in service, our Ruby project will be consolidated in our financial results. We currently fund and ~~other~~reflect 100 percent of the capital cost of this project, including cost overruns, in our results which reflect higher AFUDC capitalized due to project delays. Shortly after completion of this project, subject to meeting certain conditions, we anticipate reflecting Ruby in our financial statements as an equity investment in which we own 50 percent. Once deconsolidated, we will be required to evaluate our investment in Ruby for impairment. Based on increased costs and delays in project completion which impact the net book value of our investment, depending on the fair value at the time of evaluation, we may be required to write-down a portion of our investment in Ruby. Additionally, we will reflect equity earnings from Ruby in Segment EBIT after the impact of interest expense and preferred interests. As such, our Segment EBIT contribution from Ruby will decline once the pipeline ~~expansion projects are~~is placed in service. ~~Subsequent to placing these projects in service, our~~Our level of earnings will depend on the level of contracted customer capacity and our ability to market unsubscribed firm capacity. ~~Additionally, shortly after completion~~Currently, approximately 1.1 Bcf/d of the total design capacity of 1.5 Bcf/d on our Ruby pipeline project ~~subject to meeting certain~~is subscribed. In the near term, based on current market conditions, we ~~anticipate reflecting Ruby in our financial statements as an equity investment. Consequently, we would reflect equity earnings from Ruby in EBIT after the impact of interest and taxes.~~

~~Listed below are significant~~do not expect additional ~~updates to our backlog of projects discussed in our 2009 Annual Report on Form 10-K.~~

	•		~~Ruby Pipeline Project~~. In 2010, we received a BLM right-of-way grant for the project, final approval from the FERC and began construction of the pipeline. Although we will need additional authorizations from the FERC to construct in certain areas of the route, we expect to receive them as we satisfy various regulatory conditions and requirements, such as implementing required historic resource protection plans. Several groups have filed appeals with the U.S. Court of Appeals of certain approvals and actions of the BLM and the U.S. Fish and Wildlife Service related to the project. Although we are currently able to continue construction of the pipeline pending the federal court of appeals review of the petition, we are currently unable to predict what action, if any, the court will take in response to these appeals or any subsequent filings that may be made by one or more of these groups.

			As a result of delays in obtaining regulatory clearances to commence construction on portions of the route, we expect that the in-service date will be delayed from the original March 2011 date to June 2011 and that the costs of completing the project will be approximately 10 to 15 percent over the original cost estimate of $3.0 billion. This schedule and cost forecast could be negatively impacted by various factors, including the timing of additional regulatory clearances, adverse weather conditions in the winter season and our ability to complete construction activities during certain work periods provided for in our regulatory authorizations.

	•		~~CIG Raton 2010 Expansion.~~~~In 2010, CIG received certificate authorization from the FERC to construct the expansion which is expected to be placed in service in the fourth quarter of 2010.~~

	•		~~WIC System Expansion.~~During 2010, WIC received certificate authorization from the FERC to construct the WIC Expansion project, which will add a compressor station on the Kanda Lateral and install three miles of pipeline and reconfigure one compressor at the Wamsutter station. We placed both portions of the WIC Expansion project in service in November 2010.

	•		~~SNG South System III~~. The South System III expansion project will be completed in three phases with estimated in service dates in the fourth quarter of 2010 for Phase I, June 2011 for Phase II and June 2012 for Phase III. Construction agreements have been finalized for Phases I and II.

	•		~~TGP Northeast Upgrade Project~~. In 2010, TGP 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.

	•		~~TGP 300 Line Expansion.~~During 2010, the FERC issued a favorable environmental assessment and TGP received certificate authorization from the FERC to construct the expansion. In June 2010, we commenced construction on our compression facilities related to this project.

	•		~~TGP Northeast Supply Diversification Project.~~During 2010, we entered into precedent agreements with three shippers to provide up to approximately 250 MMcf/d of additional firm transportation service from receipt points in the Marcellus shale basin to delivery points in the New York and New England markets. Total estimated cost of this project is less than $100 million. Subject to FERC and other approvals, the project is expected to commence construction in the first half of 2012 and is anticipated to be placed in service in the fourth quarter of 2012.

long-term firm capacity subscriptions.

3025

Reservation and Usage Revenues.During the quarter ~~and nine months~~ ended ~~September 30, 2010,~~March 31, 2011, our reservation and usage revenues ~~were unfavorably impacted by lower rates and throughput~~decreased primarily on our ~~El Paso Natural Gas Company (EPNG)~~EPNG system due to the nonrenewal of expiring contracts as a result of reduced basis differentials and lower ~~usage revenues on our TGP system, partially offset by higher tariff rates on our SNG system effective September 1, 2009 pursuant to its rate case settlement. During 2010, EPNG has experienced~~throughput volumes as a ~~decrease~~result of storage withdrawals in ~~natural gas~~California and ~~electric generation demand due to weak macroeconomic conditions in the southwestern U.S.,~~ increased competition in its California and Arizona market ~~areas and reduced basis differentials. During the quarter and nine months ended September 30, 2010, throughput volumes on~~areas. The impact of these items unfavorably impacted our ~~TGP system increased~~Segment EBIT by ~~16 percent and six percent~~$21 million when compared to the same periods in 2009; however, usage revenue was lower because TGP’s 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. We believe our Marcellus expansion projects (TGP 300 Line Expansion, TGP Northeast Upgrade Project, and TGP Northeast Supply Diversification Project) will expand our presence from Marcellus to the New York and New England markets.

Although approximately 80 percent of our pipeline revenues are derived from reservation charges, lower throughput can affect our level of revenues from commodity charges, such as on our TGP system, or be an indication of the risks we may face when seeking to recontract or renew any of our existing firm transportation contracts. Continuing negative economic impacts on demand, as well as adverse shifting of sources of supply, could negatively impact basis differentials and our ability to renew firm transportation contracts that are expiring on our system or our ability to renew such contracts at current rates. Although this risk exists for all of our pipelines, it is the most significant on our EPNG system where we may be required to further discount certain transportation rates in order to renew certain firm transportation contracts should these conditions continue.

~~If we determine there is a significant change in our revenues, costs or billing determinants on any of our pipeline systems, we have the option to file rate cases~~ with the FERC on certain of our pipelines to provide an opportunity to recover our prudently incurred costs. In September 2010, EPNG filed a new rate case with the FERC. Additionally, TGP anticipates filing a new rate case in November 2010. Although these rate cases are intended to address significant factors leading to the loss in revenues or increased costs, they will not eliminate all ongoing business risks.prior period.

Gas Not Used in Operations and Revaluations.During the quarter ~~and nine months~~ ended ~~September 30, 2010 compared with the same periods in 2009,~~March 31, 2011, our Segment EBIT, primarily on our TGP system, was ~~negatively~~favorably impacted by ~~lower~~$16 million due to higher volumes and realized prices on operational ~~sales~~ and ~~unfavorable revaluations,~~other gas sales, partially offset by ~~positive impacts due to~~ lower ~~electric compression utilization~~retained fuel volumes in excess of fuel used in operations and ~~higher condensate sales.~~lower prices of approximately $11 million, as compared with the same period in 2010. Our future earnings may be impacted positively or negatively depending on changes in throughput and fluctuations in natural gas ~~prices related to the revaluation of under or over recoveries, imbalances and system encroachments.~~prices. We continue to explore options to minimize the price volatility associated with these operational pipeline activities. As a result of the TGP rate case filed with the FERC which proposes a change in its rate structure. The percentage of our revenues on TGP derived from reservation charges may increase relative to revenues derived from excess fuel recoveries.

Operating and General and Administrative Expenses. During the quarter ~~and nine months~~ ended ~~September 30, 2010,~~March 31, 2011, our operating and general and administrative expenses were ~~lower~~higher compared to the same ~~periods~~period in ~~2009~~2010 primarily due to ~~lower~~higher benefits, payroll, and ~~benefits~~contractor costs.

Asset Write Downs. During the third quarter of 2010, we incurred a $21 million non-cash asset write down based on a FERC order related to the sale of the Natural Buttes compressor station and gas processing plant in 2009. During the first quarter of 2010, we ~~also~~ recorded an impairment of approximately $10 million primarily related to our decision not to continue with a storage project due to market conditions.

~~Sale of Mexican Assets~~~~. During 2010, we recorded a gain of approximately $80 million on the sale of our interests in certain Mexican pipeline and compression assets.~~

~~Net Income Attributable to Noncontrolling Interests.~~During the quarter and nine months ended September 30, 2010, our net income attributable to noncontrolling interests increased as compared to the same period in 2009 due primarily to the issuance of additional public common units and the contribution of additional assets into the MLP. From July 2009 through September 2010, our MLP has issued 36.2 million additional public common units. Additionally, since July 2009, we have contributed an additional 18 percent interest in CIG, a 51 percent interest in SLNG and Elba Express and an additional 20 percent interest in SNG to our MLP. As of September 30, 2010, we owned 54 percent of the MLP, including our 2 percent general partner interest.

Noncontrolling interests also include preferred returns on GIP’s interests in Cheyenne Plains and Ruby. During the quarter and nine months ended September 30, 2010, we recorded $16 million and $26 million associated with GIP’s return on their preferred interests in Cheyenne Plains and Ruby. For further discussion of preferred stock of subsidiaries, see Item 1, Financial Statements, Note 12.

Other Regulatory Matters.Our pipeline systems periodically file for changes in their rates, which are subject to approval by the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability. Currently, ~~while certain~~several of our ~~pipelines are expected to continue operating under their existing rates, other~~ pipelines have projected upcoming rate actions with anticipated effective dates ~~from~~in 2011 ~~through 2014~~ as ~~discussed~~further described in Item 1, Financial Statements, Note 7 and below.

~~SNG Rate Case.~~In January 2010, the FERC approved SNG’s rate case settlement in which SNG (i) increased its base tariff rates, effective September 1, 2009, (ii) implemented a volume tracker for gas used in operations, (iii) agreed to file its next general rate case to be effective after August 31, 2012 but no later than September 1, 2013, and (iv) extended the vast majority of SNG’s firm transportation contracts until August 31, 2013.

EPNG Rate ~~Case.~~CaseIn April 2010, the FERC approved an uncontested partial offer of settlement which increased EPNG’s base tariff rates effective January 1, 2009. As part of the settlement, EPNG made an initial refund to its customers in April 2010, and paid the remaining refunds in August 2010. The settlement resolved all but four issues in the proceeding. A hearing on the remaining issues was completed in June 2010 and the outcome is not currently determinable. We believe our accruals established for this matter are adequate.

. In September 2010, EPNG filed a new rate case ~~with the FERC~~ proposing an increase in its base tariff rates ~~as permitted under the settlement of the previous rate case. These new base tariff rates~~which would increase revenue by approximately $100 million annually over previously effective tariff rates. In October 2010, the FERC issued an order accepting and suspending the effective date of the proposed rates to April 1, 2011, subject to refund, the outcome of a hearing and other proceedings. At this time, the outcome of this matter is not ~~currently~~ determinable.

TGP Rate Case.In November 2010, TGP ~~anticipates filing~~filed a rate case with the FERC proposing an increase in its base tariff rates which would increase reservation revenues by approximately $200 million annually over previously effective tariff rates. 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.

CIG Rate Case.In February 2011, the FERC approved an amendment of CIG’s 2006 rate case settlement allowing the effective date of a required new rate case to be moved to December 1, 2011. In April 2011, CIG filed a second petition to amend the effective date of a required new rate case to be moved to February 1, 2012 to allow CIG and its shippers the opportunity to reach a settlement of the rate proceeding before it is formally filed with the FERC. The FERC has not ruled on that petition. At this time, the outcome of the pre-filing settlement negotiations and the outcome of the upcoming general rate case, in ~~November 2010 with revised rates expected to become effective June 2011.~~the event pre-filing settlement cannot be reached, are uncertain.

3226

Exploration and Production Segment

Overview and Strategy

Our Exploration and Production segment conducts our oil and natural gas ~~and oil~~ exploration and production activities. The ~~profitability and performance~~success of this segment ~~are~~is driven by the ability to locate and develop economic oil and natural gas ~~and oil~~ reserves and extract those reserves at the lowest possible production and administrative costs. Accordingly, we manage this business with the goal of creating value through disciplined capital allocation, cost control and portfolio management. Our strategy focuses on building and applying competencies in assets with repeatable programs, executing to improve capital and expense efficiency, and maximizing returns by adding assets and inventory that match our competencies and divesting assets that do not. For a further discussion of our business strategy in our exploration and production business, see our ~~2009~~2010 Annual Report on Form 10-K.

Our profitability and performance is impacted by, among other factors, changes in commodity prices and industry-wide changes in the cost of drilling and oilfield services which impact our daily production, operating and capital costs. Additionally we may be impacted by the effect of hurricanes and other weather events, or the effects of domestic or international regulatory or other actions in response to events outside of our control (e.g. oil spills). WeTo the extent possible, we attempt to mitigate certain of these risks through actions, such as entering into ~~longer term~~ contractual arrangements to control costs and entering into derivative contracts to reduce the financial impact of downward commodity price movements.

In 2011, our Gulf Coast division was renamed the Southern division, and we made minor changes to the properties contained within our various domestic operating divisions. Divisional amounts for prior periods have been adjusted to reflect these changes. In March 2011, we also announced that we would develop our Eagle Ford program without a partner.

Significant Operational Factors Affecting the ~~Periods~~Quarter Ended ~~September 30, 2010~~March 31, 2011

Production.Our average daily production for the ~~nine~~three months ended ~~September 30, 2010~~March 31, 2011 was ~~777~~821 MMcfe/d, including 6263 MMcfe/d from our equity interest in the production of Four Star. Below is an analysis of our production by division for the ~~nine month periods~~quarters ended ~~September 30:~~March 31:


	2010		2009		2011		2010
	(MMcfe/d)				MMcfe/d
United States
Central		318		252		406		331
Western		159		158		155		151
Gulf Coast		206		279
Southern						166		214
International
Brazil		32		9		31		21

Total Consolidated		715		698		758		717
Four Star		62		72		63		64

Total Combined		777		770		821		781

~~2010 Drilling Results~~

~~Our drilling results for~~ We continue to work with Petrobras in this field where a fourth well is expected to begin production in late second quarter of 2011. We also continue the ~~nine months ended September 30, 2010 are as follows:~~

~~Domestic.~~~~We achieved a 98 percent success rate on 176 gross wells drilled. By division, these results were as follows:~~

Gross Wells
Success Rate Drilled
Central 99 % 140
Western 100 % 17
Gulf Coast 89 % 19

~~International~~

~~Brazil.~~~~In Brazil, our activities are primarily in the Camamu and Espirito Santo Basins. During the first nine months~~process of ~~2010, we continued to seek~~obtaining regulatory and environmental approvals ~~that are required to enter the next phase of development~~ in the Pinauna Field in the Camamu ~~Basin. Our ability~~Basin that are required in order to ~~develop this area will be dependent on~~enter the ~~receipt~~next phase of all required regulatory approvals. In the Espirito Santo Basin, the Camarupim Field began production from the second and third wells of a four well development program. We continue to work with Petrobras to connect the fourth well and anticipate bringing the well on production by the end of the first quarter of 2011. During the second quarter of 2010, we participated with Petrobras in drilling an additional exploratory well in the ES-5 block. Hydrocarbons were found in the well and we are now evaluating results. As of September 30, 2010, we have total capitalized costs in Brazil of approximately $363 million, of which $182 million are unevaluated capitalized costs.

~~Egypt.~~During the first nine months of 2010, we participated in drilling our fourth and fifth exploratory wells in the South Alamein block. The wells encountered oil shows but were temporarily plugged as we continue to evaluate the results. In the first quarter of 2010, we recorded a non-cash ceiling test charge of $2 million as a result of acreage relinquishment in the South Mariut block. During the third quarter of 2010, we recorded non-cash ceiling test charges of $14 million in our Egyptian full cost pool as a result of acreage relinquishments in the South Alamein block and a dry hole drilled in the Tanta block. Additionally, we relinquished the South Feiran concession in March 2010. As of September 30, 2010, we have total capitalized costs in Egypt of approximately $75 million, all of which are unevaluated.development.

Cash Operating Costs.We monitor cash operating costs required to produce our oil and natural gas ~~and oil~~ production volumes. Cash operating costs is a non-GAAP measure calculated on a per Mcfe basis and includes total operating expenses less depreciation, depletion and amortization expense, ceiling test and other impairment charges, transportation costs and cost of products. Cash operating costs per unit is a valuable measure of operating performance and efficiency for ~~the exploration~~our Exploration and ~~production~~Production segment. During the ~~nine months~~quarter ended ~~September 30, 2010,~~March 31, 2011, cash operating costs per unit decreased to ~~$1.76/~~$1.85/Mcfe as compared to ~~$1.83/~~$1.88/Mcfe during the same period in ~~2009 primarily~~2010, due to ~~lower lease operating expenses and general and administrative expenses.~~higher production volumes.

Capital Expenditures.Our total oil and natural gas ~~and oil~~ capital expenditures were ~~$1,040~~$352 million for the ~~nine months~~quarter ended ~~September 30, 2010,~~March 31, 2011, of which ~~$962~~$348 million were domestic capital expenditures.

Outlook for 2011.Our guidance related to capital expenditures, production volumes, cash operating costs, and depreciation, depletion and amortization is consistent with those outlined in our 2010

~~For~~ Annual Report on Form 10-K. We continue to review our capital program in light of changes in commodity prices, our decision not to seek a partner for our Eagle Ford shale acreage, the ~~full year 2010, we expect the following on a worldwide basis:~~results of our core programs, and potential acquisitions and divestitures.

	•		Capital expenditures of approximately $1.3 billion. This capital includes the leasehold acquisition in the Wolfcamp Shale for approximately $180 million during the third quarter of 2010. Of total capital expenditures, we expect to spend approximately $1.2 billion on our domestic program and approximately $0.1 billion in Brazil and Egypt;

	•		Average daily production volumes for the year of approximately 760 MMcfe/d to 780 MMcfe/d, which includes approximately 60 MMcfe/d to 65 MMcfe/d from Four Star. Production volumes from our Brazil operations are expected to be between 30 MMcfe/d and 35 MMcfe/d in 2010;

	•		~~Average cash operating costs between $1.75/Mcfe and $1.85/Mcfe for the year; and a~~

	•		~~Depreciation, depletion and amortization rate between $1.80/Mcfe and $1.85/Mcfe.~~

The following table reflects the contracted volumes and the minimum, maximum and average prices we will receive under our derivative contracts as of ~~September 30, 2010.~~March 31, 2011.

Fixed Price
Swaps⁽¹⁾ Floors⁽¹⁾ Ceilings⁽¹⁾ Basis Swaps⁽¹⁾⁽²⁾
Western Central
Texas Gulf Coast Raton Rockies Mid-Continent
Average Average Average Average Average Average Average
Volumes Price Volumes Price Volumes Price Volumes Price Volumes Price Volumes Price Volumes Price
Natural Gas

2010 31 $ 5.60 6 $ 7.00 — — 12 $ (0.40 ) 5 $ (0.78 ) 2 $ (1.93 ) 3 $ (0.74 )
2011 153 $ 6.00 18 $ 6.00 18 $ 7.29 33 $ (0.13 ) 22 $ (0.25 ) — — — —
2012 64 $ 6.36 — — — — — — — — — — — —

Oil

2010 773 $ 77.02 414 $ 75.00 414 $ 91.33
2011 — — 2,008 $ 80.00 2,008 $ 95.56
2012 — — — — 1,464 $ 95.00
2013 — — — — 1,825 $ 95.00


	2011					2012				2013
			Average					Average				Average
	Volumes⁽¹⁾		Price⁽¹⁾			Volumes⁽¹⁾		Price⁽¹⁾		Volumes⁽¹⁾		Price⁽¹⁾
Natural Gas
Fixed Price Swaps		134	$	5.76			105	$	6.01		—	$	—
Ceilings		14	$	7.29			—	$	—		—	$	—
Floors		14	$	6.00			—	$	—		—	$	—
Basis Swaps⁽²⁾
Texas Gulf Coast		25	$	(0.13	)		—	$	—		—	$	—
Raton		16	$	(0.25	)		—	$	—		—	$	—
Oil
Fixed Price Swaps		1,513	$	87.54			640	$	100.13		—	$	—
Ceilings		—	$	—			1,464	$	95.00		2,920	$	96.88
Three Way Collars — Ceiling		2,750	$	94.27			4,300	$	108.69		—	$	—
Three Way Collars — Floors⁽³⁾		2,750	$	85.14			4,300	$	90.00		—	$	—


⁽¹⁾		^{Volumes presented are TBtu for natural gas and MBbl for oil. Prices presented are per MMBtu of natural gas and per Bbl of oil.}

⁽²⁾		^{Our basis swaps effectively limit our exposure to differences between the NYMEX gas price and the price at the location where we sell our gas. The average prices listed above are the amounts we will pay per MMBtu relative to the NYMEX price to “lock-in” these locational price differences.}

⁽³⁾		^{Assumes market prices are at or above $65.00. If prices drop below $65.00, our three way collars-floors effectively “lock-in” a cash settlement of $20.14 above market prices for 2011 and a cash settlement of $25.00 above market prices for 2012.}

During the nine months ended September 30, 2010, we also entered into offsetting fixed price swap transactions that effectively lock in a cash settlement of $8.78 above market prices on 2.5 MMBbls of our anticipated 2011 crude oil production.

In October 2010, we terminated our collars on 2.0 MMBbls of our anticipated 2011 oil production and entered into a combination of instruments (referred to as a three-way collar) on 3.7 MMBbls of our anticipated 2011 oil production. For these volumes, the transactions effectively provide an average ceiling price of $94.27 per barrel and an average floor price of $85.14 per barrel unless oil prices drop below $65.00 per barrel. If oil prices drop below $65.00 per barrel, the transactions effectively lock in a cash settlement of the market prices plus $20.14, which is the difference between the average floor price and $65.00. We also entered into fixed price swaps on 1.6 MMBbls of our anticipated 2011 oil production at an average price of $86.99 per barrel.

Internationally, production from the Camarupim Field in Brazil is sold at a price that is adjusted quarterly based on a basket of fuel oil prices. In addition to the amounts included in the table above, as of September 30, 2010, we have fuel oil swaps that effectively lock in a price of approximately $4.00 per MMBtu on approximately 2 TBtu of projected Brazilian natural gas production in 2010.

The table below provides additional detail of our volumes, prices, and costs per unit. We present (i) average realized prices based on physical sales of natural gas, oil and ~~oil,~~ condensate and NGL as well as (ii) average realized prices inclusive of the impacts of financial derivative settlements. Our average realized prices, including financial derivative settlements, reflect cash received and/or paid during the period on settled financial derivatives based on the period the contracted settlements were originally scheduled to occur; however, these prices do not reflect the impact of any associated premiums paid to enter into certain of our derivative contracts.


	Quarters Ended September 30,							Nine Months Ended September 30,
					Percent							Percent			Quarter Ended March 31,
	2010		2009		Variance			2010		2009		Variance			2011		2010
Volumes
Natural gas (MMcf)
Consolidated volumes		55,331		52,805		5	%		167,839		164,728		2	%		59,262		56,147
Unconsolidated affiliate volumes		4,350		4,823		(10	)%		12,708		14,726		(14	)%		4,253		4,214
Oil, condensate and NGL (MBbls)
Oil and condensate (MBbls)
Consolidated volumes																1,194		999
Unconsolidated affiliate volumes																82		90
NGL (MBbls)
Consolidated volumes		1,540		1,336		15	%		4,574		4,296		6	%		293		403
Unconsolidated affiliate volumes		230		282		(18	)%		707		841		(16	)%		152		156
Equivalent volumes
Consolidated MMcfe		64,575		60,825		6	%		195,286		190,505		3	%		68,187		64,557
Unconsolidated affiliate MMcfe		5,729		6,515		(12	)%		16,948		19,774		(14	)%		5,660		5,690

Total combined MMcfe		70,304		67,340		4	%		212,234		210,279		1	%		73,847		70,247

Consolidated MMcfe/d		702		661		6	%		715		698		2	%		758		717
Unconsolidated affiliate MMcfe/d		62		71		(13	)%		62		72		(14	)%		63		64

Total combined MMcfe/d		764		732		4	%		777		770		1	%		821		781

Consolidated prices and costs per unit
Natural gas ($/Mcf)
Average realized price on physical sales	$	4.31	$	3.32		30	%	$	4.50	$	3.66		23	%	$	4.06	$	5.13
Average realized price, including financial derivative cash settlements⁽¹⁾	$	5.93	$	7.37		(20	)%	$	5.95	$	7.67		(22	)%
Average realized price, including financial derivative settlements⁽¹⁾⁽²⁾															$	5.44	$	6.04
Average transportation costs	$	0.30	$	0.24		25	%	$	0.30	$	0.28		7	%	$	0.31	$	0.29
Oil, condensate and NGL ($/Bbl)
Oil and condensate ($/Bbl)
Average realized price on physical sales	$	62.10	$	52.22		19	%	$	64.09	$	42.72		50	%	$	86.27	$	75.00
Average realized price, including financial derivative cash settlements⁽¹⁾⁽²⁾	$	62.51	$	82.25		(24	)%	$	63.71	$	75.66		(16	)%
Average realized price, including financial derivative settlements⁽¹⁾⁽²⁾															$	85.69	$	73.26
Average transportation costs															$	0.06	$	0.05
NGL ($/Bbl)
Average realized price on physical sales															$	50.37	$	44.67
Average transportation costs	$	0.81	$	0.80		1	%	$	0.76	$	0.85		(11	)%	$	5.01	$	2.79
Production costs and other cash operating costs ($/Mcfe)
Average lease operating expenses	$	0.70	$	0.77		(9	)%	$	0.71	$	0.76		(7	)%	$	0.74	$	0.75
Average production taxes⁽³⁾		0.24		0.24		—	%		0.29		0.26		12	%		0.32		0.31

Total production costs	$	0.94	$	1.01		(7	)%	$	1.00	$	1.02		(2	)%	$	1.06	$	1.06
Average general and administrative expenses		0.63		0.73		(14	)%		0.70		0.76		(8	)%		0.74		0.76
Average taxes, other than production and income taxes		0.05		0.04		25	%		0.06		0.05		20	%		0.05		0.06

Total cash operating costs	$	1.62	$	1.78		(9	)%	$	1.76	$	1.83		(4	)%	$	1.85	$	1.88

Depreciation, depletion and amortization ($/Mcfe)⁽⁴⁾	$	1.81	$	1.54		18	%	$	1.80	$	1.75		3	%	$	1.96	$	1.67

Quarter ~~and Nine Months~~ Ended ~~September 30,~~March 31, 2011 Compared with Quarter Ended March 31, 2010 ~~Compared to Quarter and Nine Months Ended September 30, 2009~~

Our Segment EBIT for the quarter ~~and nine months~~ ended ~~September 30, 2010 increased $173~~March 31, 2011 decreased $421 million ~~and $2.3 billion~~ as compared to the same ~~periods~~period in ~~2009.~~2010. The table below shows the significant variances of our financial results for the quarter ~~and nine months~~ ended ~~September 30, 2010~~March 31, 2011 as compared towith the same ~~periods~~period in ~~2009:~~2010:

Quarter Ended September 30, 2010 Nine Months Ended September 30, 2010
Variance Variance
Operating Operating Operating Operating
Revenue Expense Other EBIT Revenue Expense Other EBIT
Favorable/(Unfavorable)
(In millions)
Physical sales

Natural gas
Higher realized prices in 2010 $ 55 $ — $ — $ 55 $ 140 $ — $ — $ 140
Higher volumes in 2010 9 — — 9 12 — — 12
Oil, condensate and NGL
Higher realized prices in 2010 15 — — 15 98 — — 98
Higher volumes in 2010 10 — — 10 11 — — 11
Realized and unrealized gains on financial derivatives
97 — — 97 (68 ) — — (68 )
Other revenues
(10 ) — — (10 ) (10 ) — — (10 )
Depreciation, depletion and amortization expense

Higher depletion rate in 2010 — (18 ) — (18 ) — (10 ) — (10 )
Higher production volumes in 2010 — (6 ) — (6 ) — (8 ) — (8 )
Production costs
—
Lower lease operating expenses in 2010 — 2 — 2 — 7 — 7
Higher production taxes in 2010 — (2 ) — (2 ) — (8 ) — (8 )
Ceiling test charges
— (9 ) — (9 ) — 2,069 — 2,069
Impairment of inventory
— 16 — 16 — 16 — 16
Earnings from investment in Four Star
— — 5 5 — — 26 26
Other
— 9 — 9 — 8 7 15

Total Variances
$ 176 $ (8 ) $ 5 $ 173 $ 183 $ 2,074 $ 33 $ 2,290


	Variance
	Operating			Operating
	Revenue			Expense			Other			EBIT
	Favorable/(Unfavorable)
	(In millions)
Physical sales
Natural gas
Lower realized prices in 2011	$	(64	)	$	—		$	—		$	(64	)
Higher volumes in 2011		16			—			—			16
Oil and condensate
Higher realized prices in 2011		13			—			—			13
Higher volumes in 2011		15			—			—			15
NGL
Higher realized prices in 2011		2			—			—			2
Lower volumes in 2011		(5	)		—			—			(5	)
Realized and unrealized gains (losses) on financial derivatives		(362	)		—			—			(362	)
Other revenues		(12	)		—			—			(12	)
Depreciation, depletion and amortization expense
Higher depletion rate in 2011		—			(21	)		—			(21	)
Higher production volumes in 2011		—			(6	)		—			(6	)
Production costs
Higher lease operating expenses in 2011		—			(2	)		—			(2	)
Higher production taxes in 2011		—			(2	)		—			(2	)
General and administrative expenses		—			(1	)		—			(1	)
Ceiling test charges		—			2			—			2
Earnings from investment in Four Star		—			—			(2	)		(2	)
Other		—			9			(1	)		8

Total Variances	$	(397	)	$	(21	)	$	(3	)	$	(421	)

Physical sales.Physical sales represent accrual-based commodity sales transactions with customers. During the first quarter ~~and nine months ended September 30, 2010, natural gas, oil, condensate and NGL~~of 2011 our revenues ~~increased as~~from physical sales decreased compared to the same ~~periods~~quarter of 2010. Natural gas prices continued to decline, although focus on our core programs in ~~2009 due to higher commodity prices~~the Haynesville and ~~higher~~Eagle Ford shale increased oil and natural gas production ~~volumes.~~volumes in the first quarter of 2011.

Realized and unrealized gains (losses) on financial derivatives.During the first quarter ~~and nine months ended September 30, 2010,~~of 2011, we recognized net ~~gains~~losses of ~~$184 million and $468~~$109 million compared to net gains of ~~$87 million and $536~~$253 million during the same ~~periods~~period in ~~2009.~~2010. Gains or losses each period are due to changes in the fair value of our derivative contracts based on ~~movements of~~ forward commodity prices relative to the prices in ~~our~~the underlying ~~financial derivative~~ contracts.

Depreciation, depletion and amortization expense.During the first quarter ~~and nine months ended September 30, 2010,~~of 2011, our depreciation, depletion and amortization expense increased ~~compared with the same periods in 2009~~ as a result of a higher depletion rate and higher production ~~volumes. The third~~volumes compared with the same quarter ~~and nine months ended September 30,~~in 2010. In 2009, ~~depletion rate was largely impacted by the~~we recorded ceiling test charges ~~recorded~~which significantly lowered our depletion rate. We expect the upward trend in our depletion rate relative to prior periods to continue as we focus our capital on developing our core programs.

General and administrative expenses.During the first quarter of ~~2009,~~2011, our general and ~~we continue~~administrative expenses increased compared to ~~experience a lower overall depletion rate~~the same period in 2010, ~~as a result~~due to severance costs related to an office closure, offset by lower labor-related costs. The impact of ~~that charge. We expect our depreciation, depletion and amortization rate for the full year to be between $1.80/~~these severance costs was approximately $5 million, or $0.07 per Mcfe ~~and $1.85/Mcfe.~~on total cash operating costs.

Production costs.~~During the quarter and nine months ended September 30, 2010, our~~Our production costs ~~remained flat~~increased during the first quarter of 2011 as compared to the same ~~periods~~period in ~~2009~~2010 primarily due to ~~lower~~higher lease operating expenses ~~offset by~~and higher production ~~taxes. Lease operating expenses were lower primarily due to a decrease in our domestic maintenance and repair expenses while the higher production~~ taxes ~~were~~ as a result of higher ~~natural gas and oil revenues.~~production volumes. Production costs per unit were relatively flat when comparing these periods.

Marketing Segment

~~Overview~~

Our Marketing segment’s primary focus is to market our Exploration and Production segment’s oil and natural gas ~~and oil~~ production and to manage El Paso’s overall price risk. In addition, we continue to manage and liquidate ~~contracts which were primarily entered into prior to the deterioration of the energy trading environment in 2002.~~certain legacy contracts. All of our remaining contracts are subject to counterparty credit and non-performance risks while our remaining mark-to-market contracts are also subject to interest rate exposure. Our contracts are described below and in further detail in our ~~2009~~2010 Annual Report on Form 10-K.

~~Power contracts.~~Prior to third quarter 2010, our primary unhedged exposure in the Marketing segment related to mark-to-market power contracts within the PJM region that extend through April 2016. During 2010, we entered into positions with a third party financial institution that eliminated the locational price risks associated with future volumes to be delivered under these contracts.

~~Transportation-related~~Natural gas transportation-related contracts.The impact of these accrual-based contracts is based on our ability to use or remarket the contracted pipeline ~~capacity. These~~capacity and the amount of production from our Exploration and Production segment. As of March 31, 2011, these contracts require us to pay ~~total annual~~ demand charges of ~~approximately $47~~$31 million ~~in 2010~~for the remainder of 2011 and an average of ~~approximately $41~~$40 million per year between ~~2011~~2012 and ~~2014.~~2015.

~~Natural~~Legacy natural gas and power contracts.As of ~~September 30, 2010, we have long term gas~~March 31, 2011, these contracts include (i) long-term accrual based supply contracts, including transportation expenses, that obligate us to deliver natural gas to specified power ~~plants. The accounting for these~~plants and (ii) power contracts ~~is a combination of~~in the PJM region through 2016, which we mark-to-market ~~and accrual-based.~~in our results. These contracts are expected to have minimal future impact on ~~this segment~~our earnings as we have entered into offsetting positions that eliminate the price risks associated with our PJM power contracts and substantially offset ~~all of~~ the fixed price ~~exposure.~~exposure related to our natural gas supply contracts.

Operating Results

Overview.Our overall operating results and analysis for our Marketing segment during each of the quarters ~~and nine months~~ ended ~~September 30~~March 31 are as follows:


	Quarters Ended						Nine Months Ended						2011			2010
	September 30,						September 30,						(In millions)
	2010			2009			2010			2009
				(In millions)
Income (Loss)
Income (Loss):
Contracts Related to Legacy Trading Operations:
Changes in fair value of power contracts	$	(13	)	$	(6	)	$	(34	)	$	49		$	(1	)	$	18
Natural gas transportation-related contracts:
Demand charges		(10	)		(9	)		(29	)		(26	)		(10	)		(9	)
Settlements, net of termination payments		10			3			26			15			(1	)		11
Changes in fair value of natural gas contracts		(3	)		(14	)		(8	)		4
Changes in fair value of other natural gas derivative contracts														—			(1	)

Total revenues		(16	)		(26	)		(45	)		42			(12	)		19
Operating expenses, net		4			(2	)		—			(8	)
Operating expenses														(2	)		(2	)

Other income		—			—			1			—
Operating income (loss)													$	(14	)	$	17
Other income, net														—			—

EBIT	$	(12	)	$	(28	)	$	(44	)	$	34
Segment EBIT													$	(14	)	$	17

~~Corporate and~~ Other ~~Expenses, Net~~Activities

Our ~~corporate and~~ other activities include our corporate general and administrative functions, ~~as well as~~ our ~~recently formed~~ midstream ~~business, our remaining power~~ operations and other miscellaneous businesses.

Midstream. As of March 31, 2011, our midstream operations consist primarily of wholly-owned assets in the Haynesville area in north Louisiana and the Eagle Ford area in south Texas, in addition to an equity investment in a joint venture that owns the Altamont gathering and processing system and plant in the Uintah basin of Utah. The joint venture is currently working to expand the Altamont system, and we and our joint venture partner have each committed to make up to $500 million of future capital contributions to the joint venture for additional midstream projects to be acquired or developed by the joint venture. Our midstream business is also evaluating several larger scale projects in the Marcellus shale in Pennsylvania, the Eagle Ford area, and opportunities in emerging shale plays in the Rockies, west Texas and the northeast United States. For the full year 2011, we expect to make capital expenditures and equity investments totaling approximately $100 million related to the midstream projects discussed above.

The following is a summary of significant items impacting the Segment EBIT in our ~~corporate and~~ other activities for the quarters ~~and nine months~~ ended ~~September 30:~~March 31:

Quarters Ended Nine Months Ended
September 30, September 30,
2010 2009 2010 2009
(In millions)
Income (Loss)

Change in litigation, environmental and other reserves $ (16 ) $ (18 ) $ (14 ) $ 4
Equity earnings 2 (9 ) 13 (2 )
Loss on sale of notes receivable — — — (22 )
Loss on debt extinguishment (104 ) — (104 ) —
Other 7 (1 ) 9 (1 )

Total EBIT $ (111 ) $ (28 ) $ (96 ) $ (21 )


Income (Loss)	2011			2010
	(In millions)
Loss on debt extinguishment	$	(41	)	$	—
Change in environmental, legal, and other reserves		(11	)		(8	)
Midstream		2			—
Other		(9	)		(3	)

Total Segment EBIT	$	(59	)	$	(11	)

~~Change~~Loss on Debt Extinguishment.During the first quarter of 2011, we recorded a total loss of $41 million in ~~Litigation,~~ conjunction with repurchasing $148 million of our notes due in 2012 through 2025 for cash. In April 2011, we repurchased an additional $153 million of our notes which will result in recording a loss of approximately $19 million in the second quarter of 2011. We will continue to evaluate repurchasing debt as conditions warrant for the remainder of 2011 which may result in additional losses.

Environmental, Legal and Other Reserves.Our results for all periods presented were impacted by changes in certain legacy litigation and environmental remediation reserves and indemnification liabilities, including adjustments to environmental reserves associated with a non-operating chemical plant. Additionally impacting our results for the first nine months of 2009 were mark-to-market gains associated with an indemnification related to the sale of a legacy ammonia facility that fluctuates with ammonia prices. In the first half of 2010, we eliminated a significant portion of our exposure under this indemnification.

We have a number of pending litigation and environmental matters and reserves related to our historical business operations that affect our ~~corporate~~ results. Adverse rulings or unfavorable outcomes or settlements against us related to these matters ~~have impacted and~~ may continue to impact our future results.

~~Equity Earnings.~~~~During the quarters and nine months ended September 30, 2010 and 2009, our equity earnings (losses) were primarily from legacy power investments.~~

~~Loss on Sale of Notes Receivable.~~In the first quarter of 2009, we completed the sale of our investment in Porto Velho to our partner in the project for total consideration of $179 million, including $78 million in notes receivable. Subsequently, in the second quarter of 2009, we sold the notes, including accrued interest, to a third party financial institution for $57 million and recorded a loss of $22 million.

~~Loss on Debt Extinguishment.~~In September 2010, we exchanged approximately $348 million of our 12.00% Senior Notes due 2013 for cash and 6.50% Senior Notes due 2020. In conjunction with the transaction, we recorded a loss of $104 million.

~~Other.~~Our 2010 year-to-date EBIT was impacted by the refund of certain insurance premiums on legacy activities. In addition, during the quarter and nine months ended September 30, 2010, our EBIT was impacted by non-cash pension costs and other benefit costs related to legacy activities. Losses from our pension asset performance during 2008 will continue to be amortized into our future net benefit cost through 2011. Despite the increased expense, we do not anticipate making any contributions to our primary pension plan for the remainder of 2010. For further discussion of our primary pension plan and related net benefit cost, see our 2009 Annual Report on Form 10-K.

Interest and Debt Expense

Our interest and debt expense ~~increased~~decreased during the ~~nine months~~quarter ended ~~September 30, 2010~~March 31, 2011 as compared to the same period in ~~2009~~2010 primarily due to the ~~Ruby term loan with GIP entered into in 2009 partially~~exchange or repurchase of debt as described below. This decrease was offset by the 2010 issuance of approximately $1.3 billion of EPPOC notes having rates ranging from 4.1 percent to 7.5 percent and increases in Ruby pipeline project financing, net of higher capitalized AFUDC related to debt, onprimarily associated with the Ruby pipeline project. ~~During the second quarter~~

In 2010 and 2011, we exchanged or repurchased approximately $1.2 billion of ~~2010, the interest rate on the Ruby term loan also increased~~debt having rates ranging from 7 percent to ~~13 percent. In the third quarter of~~12 percent as further described in our 2010 ~~the Ruby term loan was converted to a convertible preferred equity~~Annual Report on Form 10-K and in Note 6. Interest savings associated with these liability management transactions have been offset by interest ~~in Ruby.~~costs on new borrowings.

Commitments and Contingencies

~~Below is a summary of certain climate change and energy policies 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 ~~10,~~7, which is incorporated herein by ~~reference.~~

~~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 the rates charged by our pipelines and in the market price for natural gas that we sell, 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 and to include onshore domestic exploration and production segments previously proposed to be exempt, which could materially increase the costs of our operations. Our preliminary estimate of the first-year cost to our company is approximately $11 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 costs 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 operationsreference and our ~~cost to install new facilities, we are unable, at this point, to estimate its financial impact.~~2010 Annual Report on Form 10-K.

4235

Liquidity and Capital Resources

During 2010, our primary focus from a liquidity perspective has been on funding our 2010 pipeline and exploration and production capital programs, meeting operating needs and repaying/repurchasing debt when due or when conditions warrant. Our primary sources of cash include cash flow from operations, funds provided through capital market activities (including executing our financing strategy utilizing EPB), bank credit facilities, project financings (such as Ruby) and asset sales where warranted. By June of this year, we had met our 2010 funding needs, and our activities for the remainder of the year are focused on meeting our 2011 funding objectives.

Available Liquidity Update and Liquidity Outlook for ~~2010.~~2011.~~At September 30, 2010, our available liquidity was~~As of March 31, 2011, we had approximately ~~$2.5 billion (approximately $0.3 billion cash and $2.2~~$2.8 billion of available ~~credit facility), exclusive~~liquidity (exclusive of ~~combined~~ cash and credit facility capacity ~~under our~~of EPB and ~~Ruby credit facilities. Through September 30, 2010, we completed several funding actions including (i)~~Ruby). The increase in our available liquidity during the ~~receipt~~first quarter of ~~$1.2 billion in cash~~2011 was primarily the result of issuing additional MLP common units in conjunction with contributing additional ownership interests in ~~SLNG, Elba Express and~~ SNG to our ~~MLP, which funded~~MLP. During the ~~acquisitions through~~first quarter of 2011, among other activities, we continued to repurchase notes and also borrowed the issuance of $0.5 billion of debt and the issuance of common units, (ii) the sale of certain of our interests in Mexican pipeline and compression assets for approximately $0.3 billion and (iii) borrowing approximately $362 millionremaining amount under our seven-year amortizing $1.5 billion Ruby financing facility that matures in 2017. In October 2010, we borrowed an additional $240 million under this Ruby facility. In September 2010, our MLP also issued approximately 13.2 million common units for net proceedsto support the construction of ~~approximately $0.4 billion which we anticipate will be used for potential future acquisitions and growth capital expenditures.~~

~~As further discussed in Item 1, Financial Statements, Notes 9 and 14, we entered into our~~the Ruby pipeline ~~project agreement with~~project.

Our planned 2011 capital expenditures will allow us to place a substantial portion of our pipeline backlog in service by the end of 2011 while continuing to support our exploration and production strategy. Our cash capital expenditures for the quarter ended March 31, 2011, and the amount of cash we expect to spend for the remainder of 2011 to grow and maintain our businesses are as follows:


	Quarter Ended		2011
	March 31, 2011		Remaining		Total
	(In billions)
Pipelines
Maintenance	$	0.1	$	0.3	$	0.4
Growth⁽¹⁾		0.7		0.6		1.3
Exploration and Production		0.3		1.0		1.3
Other⁽²⁾		—		0.2		0.2

	$	1.1	$	2.1	$	3.2


⁽¹⁾		^{Our pipeline growth capital expenditures reflect 100 percent of capital related to our Ruby project. We have a partner on this project as described below.}

⁽²⁾		^{Includes $100 million related to our midstream business.}

GIP, ~~in 2009 where they agreed to invest up to $700 million for a~~our 50 percent ~~equity interest~~partner in ~~Ruby. As of September 30, 2010, GIP had funded $670 million related to~~ the Ruby pipeline project, ~~including $145~~has provided approximately $700 million for a convertible preferred equity interest in Ruby that was simultaneously exchanged for a convertible preferred equity interest in a holding company of Cheyenne Plains and $525 million in the form of a convertible preferred equity interest in Ruby. GIP will hold their interest in Cheyenne Plains until certain conditions are satisfied including placingto support the Ruby pipeline project in service. GIP has the right to convert its preferred equity in Ruby to common equity in Ruby at any time; however, the preferred equity is subject to mandatory conversion to Ruby common equity upon the satisfaction of certain conditions, including Ruby entering into additional firm transportation agreements.project. Our obligation to repay these amounts, if required, is secured by our equity interests in Ruby, Cheyenne Plains, and approximately 50 million common units we own in our MLP.

We began construction on our Ruby pipeline project in mid-2010 and currently expect that our Ruby pipeline project will be completed in June 2011, three months later than originally anticipated and approximately 10 to 15 percent over budget, primarily based on delays in obtaining regulatory clearances. Overall, however, we expect our aggregate multi-year pipeline expansion backlog to be within 5 percent of our original budgets. We have also provided a contingent completion and cost-overrun guarantee to Ruby lenders; however, upon the Ruby pipeline project becoming operational and making certain permitting representations, the project financing will become non-recourse to us. Pursuant to the cost overrun guarantee to the Ruby lenders, ~~we are required to post letters~~as of ~~credit for any forecasted cost overruns on the project approved by the lender’s independent engineer. In this regard,~~March 31, 2011, we have ~~posted $245~~$350 million outstanding in letters of credit to cover ~~the~~ anticipated cost overruns. If additional cost overruns are forecasted and approved by the lender’s engineer in subsequent months, ~~then~~ additional ~~letters of credit will~~collateral may be required to be issued pursuant to the Ruby financing agreements. For a further description of this project and our agreement with GIP, see our 2010 Annual Report on Form 10-K and Note 11.

~~Our 2010 full year~~We expect our current liquidity sources and operating cash flow to be sufficient to fund our estimated 2011 capital requirements, including our Ruby pipeline project, other pipeline projects and exploration and production expenditures have been significant; however, our 2011 requirements decline significantly, and by the end of 2011 most of our pipeline backlog will be placed in service. Our cash capital expenditures for the nine months ended September 30, 2010, and the amount of cash we expect to spend forprogram. For the remainder of ~~2010~~2011, we also have remaining debt maturities of approximately $500 million which we will repay as they mature. As a result of our current available liquidity, hedging program in place on our oil and natural gas production, and planned future actions (including continuing with our MLP drop down strategy as markets permit), we believe we are well positioned to ~~grow and maintain~~meet our ~~businesses are~~obligations as ~~follows:~~

Nine Months Ended 2010
September 30, 2010 Remaining Total
(In billions)
Pipelines

Maintenance $ 0.2 $ 0.2 $ 0.4
Growth⁽¹⁾
1.4 1.1 2.5
Exploration and Production⁽²⁾
1.0 0.3 1.3
Other
0.1 — 0.1

$ 2.7 $ 1.6 $ 4.3


⁽¹⁾		~~Our pipeline growth capital expenditures reflect 100 percent of the capital related to the Ruby pipeline project.~~

⁽²⁾		~~Includes the leasehold acquisition of the Wolfcamp Shale during the third quarter of 2010.~~

well as continue with our efforts to strengthen our balance sheet. We will continue to assess and take further actions where prudent to meet our long-term objectives and capital requirements ~~including considering additional opportunities with our MLP~~ as well as address further changes in the ~~markets permit.~~financial and commodity markets.

There are a number of factors that could impact our plans, including our ability to access the financial markets to fund our long-term capital needs if the financial markets are restricted, or a further decline in commodity prices. If these events occur, additional adjustments to our plan and outlook may be required, including reductions in our discretionary capital program, ~~further~~ reductions in operating and general and administrative expenses, obtaining secured financing arrangements, seeking additional partners for other growth projects ~~and~~or the sale of additional non-core assets, all of which could impact our financial and operating performance.

Overview of ~~2010~~ Cash Flow Activities.During the first ~~nine months~~quarter of ~~2010,~~2011, we generated operating cash flow of approximately ~~$1.5~~$0.5 billion primarily from our pipeline and exploration and production operations. Cash flow from operations for the nine months ended September 30, 2010 was $0.3 billion lower than the same period in 2009 primarily due to lower 2010 realized commodity prices, including derivative contracts, compared with 2009 and working capital changes. We also generated approximately ~~$0.3~~$1.3 billion ~~from~~in the ~~sale of certain of our interests in Mexican pipeline and compression assets, approximately $1.0 billion~~first quarter as a result of ~~the issuance of MLP common units and approximately $1.4 billion in debt proceeds including~~ Ruby and other consolidated project financings, as well as the issuance of MLP ~~debt offerings.~~common units. We used ~~the~~ cash flow generated from these operating and financing activities to fund our capital programs and to make net repayments under our various credit facilities and other

~~Contractual Obligations~~

~~The following information provides updates to our contractual obligations, and should be read in conjunction with the information disclosed in our 2009 Annual Report on Form 10-K.~~

~~Commodity-Based Derivative Contracts~~

We use derivative financial instruments in our Exploration and Production and Marketing segments to manage the price risk of commodities. Our commodity-based derivative contracts are not currently designated as accounting hedges and include options, swaps and other natural gas, oil and power purchase and supply contracts that are not traded on active exchanges. The following table details the fair value of our commodity-based derivative contracts by year of maturity as of September 30, 2010:

Maturity Maturity Maturity Maturity Total
Less Than 1 to 3 4 to 5 6 to 10 Fair
1 Year Years Years Years Value
(In millions)
Assets $ 324 $ 115 $ (2 ) $ 7 $ 444
Liabilities (166 ) (218 ) (115 ) (31 ) (530 )

Total commodity-based derivatives $ 158 $ (103 ) $ (117 ) $ (24 ) $ (86 )

~~The following is a reconciliation of our commodity-based derivatives for the nine months ended September 30, 2010:~~

Commodity-
Based
Derivatives
(In millions)
Fair value of contracts outstanding at January 1, 2010 $ (381 )

Fair value of contract settlements during the period⁽¹⁾
(266 )
Premiums during the period⁽¹⁾
126
Changes in fair value of contracts during the period 435

Net changes in contracts outstanding during the period 295

Fair value of contracts outstanding at September 30, 2010 $ (86 )


⁽¹⁾		~~Includes $119 million of non-cash transactions associated with exchanging certain of our 2011 natural gas collars for 2011 and 2012 natural gas fixed price swaps.~~

Item 3. Quantitative and Qualitative Disclosures About Market Risk

This information updates, and ~~you~~ should be read it in conjunction with the information disclosed in our ~~2009~~2010 Annual Report on Form 10-K, in addition to the information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.

There ~~are~~have been no material changes in our quantitative and qualitative disclosures about market risks from those reported in our ~~2009~~2010 Annual Report on Form 10-K, except as presented below:

Commodity Price Risk

~~Production-Related Derivatives~~. We attempt to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of natural gas and oil production through the use of derivative natural gas and oil swaps, basis swaps and option contracts. These contracts impact our earnings as the fair value of these derivatives changes. Our production-related derivatives do not mitigate all of the commodity price risks of our forecasted sales of natural gas and oil production and, as a result, we are subject to commodity price risks on our remaining forecasted production.

~~Other Commodity-Based Derivatives.~~In our Marketing segment, we have long-term natural gas and power derivative contracts which include forwards, swaps, options and futures that we either intend to manage until their expiration or seek opportunities to liquidate to the extent it is economical and prudent. We utilize a sensitivity analysis to manage the commodity price risk associated with these contracts.

~~Sensitivity Analysis.~~The table below presents the hypothetical sensitivity of our ~~production-related derivatives and our other commodity-based~~ derivatives to changes in fair values arising from immediate selected potential changes in the market prices (primarily natural gas, oil and power prices and basis differentials) used to value these contracts. This table reflects the sensitivities of the derivative contracts only and does not include any impacts on the underlying hedged commodities.

Change in Market Price
10 Percent Increase 10 Percent Decrease
Fair Value Fair Value Change Fair Value Change
(In millions)
Production-related derivatives—net assets (liabilities)

September 30, 2010 $ 368 $ 220 $ (148 ) $ 515 $ 147
December 31, 2009 $ 127 $ (29 ) $ (156 ) $ 290 $ 163

Other commodity-based derivatives—net assets (liabilities)

September 30, 2010 $ (454 ) $ (451 ) $ 3 $ (456 ) $ (2 )
December 31, 2009 $ (508 ) $ (517 ) $ (9 ) $ (500 ) $ 8


				Change in Market Price
				10 Percent Increase						10 Percent Decrease
	Fair Value			Fair Value			Change			Fair Value			Change
							(In millions)
Production-related derivatives—net assets (liabilities)
March 31, 2011	$	50		$	(187	)	$	(237	)	$	274		$	224
December 31, 2010	$	237		$	33		$	(204	)	$	434		$	197

Other commodity-based derivatives—net assets (liabilities)
March 31, 2011	$	(394	)	$	(393	)	$	1		$	(394	)	$	—
December 31, 2010	$	(423	)	$	(422	)	$	1		$	(426	)	$	(3	)

4638

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of ~~September 30, 2010,~~March 31, 2011, 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. 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 CEO and our 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 CEO 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 30, 2010.~~March 31, 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.

4739

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Financial Statements, Note ~~10,~~7, which is incorporated herein by reference. Additional information about our legal proceedings can be found in Part I, Item 3 of our ~~2009~~2010 Annual Report on Form 10-K filed with the SEC.

Item 1A. Risk Factors

CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS

OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

We have made statements in this document that constitute forward-looking statements, as that term is defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements include information concerning possible or assumed future results of operations. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements. These statements may relate to information or assumptions about:

	•		earnings per share;

	•		capital and other expenditures;

	•		dividends;

	•		financing plans;

	•		capital structure;

	•		liquidity and cash flow;

	•		pending legal proceedings, claims and governmental proceedings, including environmental matters;

	•		future economic and operating performance;

	•		operating income;

	•		management’s plans; and

	•		goals and objectives for future operations.

Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these variances can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in our forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in our forward-looking statements are described in our ~~2009~~2010 Annual Report on Form 10-K under Part I, Item 1A, Risk Factors. ~~Below is an additional risk factor that may arise as a result of the oil spill in the Gulf of Mexico, as well as the recent financial reform legislation that was enacted in July 2010.~~

Our operations and financial results could be impacted by the oil spill in the Gulf of Mexico and recent incidents on third party pipelines, or by further developments in other potential regulatory, legislative or environmental initiatives.

The oil spill in the Gulf of Mexico poses additional risks for our exploration and production and pipeline businesses, including the possibility of (i) new environmental and safety review requirements imposed on drilling and/or development operations in the Gulf of Mexico and other areas, (ii) constrained industry access to the Gulf of Mexico, (iii) other indirect effects from the oil spill such as greater scrutiny and regulation of exploration and production operations, which may include delays in the receipt of necessary permits and approvals both in the U.S. and internationally, including our offshore exploration and production operations in Brazil and (iv) negative impacts on the availability and cost of insurance coverages applicable to offshore operations. While we have reduced our focus over the past several years in the Gulf of Mexico, any of these items could have an adverse impact on our strategy and profitability in both our domestic and international exploration and production operations and on supplies of natural gas from the Gulf of Mexico to certain of our pipeline systems. In addition, we have numerous contractual arrangements with many of the parties involved in the oil spill. Although in many cases the parties remain creditworthy or have posted credit support associated with these contractual arrangements, there is a risk that one or more of the parties could default in the performance of our contracts.

~~Several ruptures on third party pipelines have occurred recently. In response, various legislative and regulatory reforms associated with pipeline safety and integrity issues~~There have been ~~proposed, including reforms~~no material changes in our risk factors since that would require increased periodic inspections, installation of additional valves and other equipment on our pipelines 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.report.

In July 2010, federal legislation was enacted to implement various financial and governance reforms. Although many of the legislative provisions were focused on the financial and banking industries, portions of the legislation will impact our businesses. The extent of the impact is uncertain at this time, due to the requirement that various implementing regulations must be adopted by the SEC and the United States Commodity Futures Trading Commission (CFTC). For example, the legislation provides for the creation of certain position limits for derivative transactions, as well as certain exemptions from the general requirement that swap transactions must be cleared through a central exchange for which collateral must be posted. The CFTC must adopt regulations that define what position limits will be imposed and what swap transactions are entitled to such exemptions. Although we believe the derivative contracts that we enter into to hedge the commodity price risk associated with our natural gas and oil production should not be impacted by such position limits and should be exempt from the requirement to clear transactions through a central exchange or to post any collateral, the impact upon our businesses will depend on the outcome of the implementing regulations adopted by the CFTC.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

Item 5. Other Information

None.

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.

5041

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, El Paso Corporation has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


		EL PASO CORPORATION
~~Date: November 5, 2010~~	~~By:~~	~~/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)


Date: ~~November 5, 2010~~ May 6, 2011	~~By:~~	/s/ Francis C. Olmsted III
		Francis C. Olmsted III
		Vice President and Controller ~~(Principal Accounting Officer)~~

(Principal Accounting Officer)

EL PASO CORPORATION
EXHIBIT INDEX

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


Exhibit
Number		Description
~~4.A~~		Sixteenth Supplemental Indenture, dated as of September 24, 2010, between El Paso Corporation and HSBC Bank USA, National Association, as trustee, to Indenture dated as of May 10, 1999 (Exhibit 4.A to our Current Report on Form 8-K filed with the SEC on September 24, 2010).

~~10.A~~		~~Registration Rights Agreement dated September 24, 2010 (Exhibit 10.A to our Current Report on Form 8-K filed with the SEC on September 24, 2010).~~

*12		Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends.

*31.A		Certification of Chief 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 Chief 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.

*101.INS		XBRL Instance Document.

*101.SCH		XBRL Schema Document.

*101.CAL		XBRL Calculation Linkbase Document.

*101.DEF		XBRL Definition Linkbase Document.

*101.LAB		XBRL Labels Linkbase Document.

*101.PRE		XBRL Presentation Linkbase Document.

5243


	September 30,		December 31,		March 31,		December 31,
	2010		2009		2011		2010
ASSETS
Current assets
Cash and cash equivalents (includes $27 in 2010 and $149 in 2009 held by variable interest entities)	$	809	$	635
Cash and cash equivalents (includes $48 in 2011 and $31 in 2010 held by variable interest entities)					$	242	$	347
Accounts and notes receivable
Customer, net of allowance of $5 in 2010 and $8 in 2009		293		346
Customer, net of allowance of $4 in 2011 and $4 in 2010						368		333
Affiliates		5		92		9		7
Other		138		115		159		160
Materials and supplies		167		175		166		169
Assets from price risk management activities		324		221		154		265
Deferred income taxes		142		298		189		165
Other		91		126		104		106

Total current assets		1,969		2,008		1,391		1,552


Property, plant and equipment, at cost
Pipelines (includes $2,409 in 2010 and $1,179 in 2009 held by variable interest entities)		21,376		19,722
Natural gas and oil properties, at full cost		21,544		20,846
Pipelines (includes $3,702 in 2011 and $3,232 in 2010 held by variable interest entities)						22,893		22,385
Oil and natural gas properties, at full cost						22,024		21,692
Other		409		314		438		416

		43,329		40,882		45,355		44,493
Less accumulated depreciation, depletion and amortization		23,323		22,987		23,565		23,421

Total property, plant and equipment, net		20,006		17,895		21,790		21,072


Other assets
Other long-term assets
Investments in unconsolidated affiliates		1,538		1,718		1,683		1,673
Assets from price risk management activities		131		123		32		61
Other		863		761		961		912

		2,532		2,602		2,676		2,646

Total assets	$	24,507	$	22,505	$	25,857	$	25,270


	Common Stock		Convertible Preferred Stock		Common Stock		Convertible Preferred Stock
	($0.01/Share)		(4.99%/Year)		($0.01/Share)		(4.99%/Year)
Amount paid through September 30, 2010	$	21	$	28
Amount paid in October 2010	$	7	$	9
Declared in October 2010:
Amount paid through March 31, 2011					$	7	$	9
Amount paid in April 2011					$	7		—
Declared in April 2011:
Date of declaration	October 14, 2010		October 14, 2010		April 1, 2011			—
Payable to shareholders on record	December 3, 2010		December 15, 2010		June 3, 2011			—
Date payable	January 3, 2011		January 3, 2011		July 1, 2011			—


	2010					2009
	Basic			Diluted		Basic			Diluted
		(In millions, except per share amounts)
Net income attributable to El Paso Corporation	$	142		$	142	$	67		$	67
Preferred stock dividends of El Paso Corporation		(9	)		—		(9	)		(9	)

Net income attributable to El Paso Corporation’s common stockholders	$	133		$	142	$	58		$	58


Weighted average common shares outstanding		699			699		696			696
Effect of dilutive securities:
Options and restricted stock		—			5		—			4
Convertible preferred stock		—			58		—			—

Weighted average common shares outstanding and dilutive securities		699			762		696			700


Basic and diluted earnings per common share:
Net income attributable to El Paso Corporation’s common stockholders	$	0.19		$	0.19	$	0.08		$	0.08

	•		~~Level 1 instruments’ fair values are based on quoted prices for the instruments in actively traded markets.~~

	•		Level 2 instruments’ fair values are primarily based on pricing data representative of quoted prices for similar assets and liabilities in active markets (or identical assets and liabilities in less active markets).

	•		Level 3 instruments’ fair values are partially calculated using pricing data that is similar to Level 2 above, but their fair value also reflects adjustments for being in less liquid markets or having longer contractual terms.


	September 30, 2010											December 31, 2009
	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
									(In millions)
Assets
Commodity-based derivatives
Production-related natural gas and oil derivatives	$	—	$	381		$	—		$	381		$	—	$	169		$	—		$	169
Other natural gas derivatives		—		32			17			49			—		106			21			127
Power-related derivatives		—		—			14			14			—		—			37			37
Interest rate derivatives		—		11			—			11			—		11			—			11
Marketable securities invested in non-qualified compensation plans		21		—			—			21			20		—			—			20

Total assets		21		424			31			476			20		286			58			364

Liabilities
Commodity-based derivatives
Production-related natural gas and oil derivatives		—		(13	)		—			(13	)		—		(42	)		—			(42	)
Other natural gas derivatives		—		(61	)		(100	)		(161	)		—		(153	)		(133	)		(286	)
Power-related derivatives		—		—			(356	)		(356	)		—		—			(386	)		(386	)
Interest rate derivatives		—		(105	)		—			(105	)		—		(17	)		—			(17	)
Other		—		—			(13	)		(13	)		—		—			(31	)		(31	)

Total liabilities		—		(179	)		(469	)		(648	)		—		(212	)		(550	)		(762	)

Total	$	21	$	245		$	(438	)	$	(172	)	$	20	$	74		$	(492	)	$	(398	)


				Change in Fair Value			Change in Fair Value
	Balance at			Reflected in			Reflected in						Balance at
	Beginning of			Operating			Operating			Settlements,			End of
	Period			Revenues⁽¹⁾			Expenses⁽²⁾			Net			Period
				(In millions)
Quarter Ended September 30, 2010
Assets	$	43		$	(11	)	$	—		$	(1	)	$	31
Liabilities		(494	)		(3	)		(1	)		29			(469	)

Total	$	(451	)	$	(14	)	$	(1	)	$	28		$	(438	)


Nine Months Ended September 30, 2010
Assets	$	58		$	(25	)	$	—		$	(2	)	$	31
Liabilities		(550	)		(14	)		(2	)		97			(469	)

Total	$	(492	)	$	(39	)	$	(2	)	$	95		$	(438	)


	Fair Value of Derivative Assets						Fair Value of Derivative Liabilities
	September 30, 2010			December 31, 2009			September 30, 2010			December 31, 2009
				(In millions)
Derivatives Designated as Hedges:
Interest rate derivatives
Cash flow hedges	$	—		$	1		$	(105	)	$	(17	)
Fair value hedges		11			10			—			—

Total derivatives designated as hedges		11			11			(105	)		(17	)

Derivatives not Designated as Hedges:
Commodity-based derivatives
Production-related		437			239			(69	)		(112	)
Other natural gas		192			519			(304	)		(678	)
Power-related		46			57			(388	)		(406	)

Total derivatives not designated as hedges		675			815			(761	)		(1,196	)

Impact of master netting arrangements		(231	)		(482	)		231			482

Total assets (liabilities) from price risk management activities		455			344			(635	)		(731	)
Other derivatives		—			—			(13	)		(31	)

Total derivatives	$	455		$	344		$	(648	)	$	(762	)


⁽¹⁾		~~Initial interest rate of 7.00% increased to 13.00% effective April 1, 2010. Loan commitment was converted to Ruby convertible preferred equity interest in August 2010.~~

⁽²⁾		In the third quarter of 2010, we exchanged debt with a principal value of approximately $348 million which, net of discounts, had a carrying value of $323 million for new notes and cash. We recorded a loss on debt extinguishment in conjunction with this transaction as further discussed in Note 4.


	September 30, 2010
Sites	Expected		High
	(In millions)
Operating	$	12	$	20
Non-operating		149		315
Superfund		16		39

Total	$	177	$	374


Balance as of January 1, 2010	$	189
Additions/adjustments for remediation activities		17
Payments for remediation activities		(29	)

Balance as of September 30, 2010	$	177


	Segments														Segments
				Exploration						Corporate							Exploration
	Pipelines			and Production			Marketing			and Other⁽¹⁾			Total		Pipelines		and Production			Marketing			Other			Eliminations			Total
							(In millions)													(In millions)
Quarter Ended September 30, 2010
2011

Revenue from external customers	$	680		$	340	⁽²⁾	$	174		$	19		$	1,213	$	703	$	84	⁽¹⁾	$	201		$	1		$	—		$	989
Intersegment revenue		12			179	⁽²⁾		(190	)		(1	)		—		50		166	⁽¹⁾		(213	)		1			(4	)		—
Operation and maintenance		220	⁽³⁾		87			(3	)		23			327		190		101			2			13			(1	)		305
Ceiling test charges		—			14			—			—			14
Depreciation, depletion and amortization		111			117			—			11			239		114		134			—			6			—			254
Earnings (losses) from unconsolidated affiliates		28			(2	)		—			2			28		25		(2	)		—			7			—			30
EBIT		334			261			(12	)		(111	)⁽⁴⁾		472
Segment EBIT																499		(31	)		(14	)		(59	)		—			395

Quarter Ended September 30, 2009
2010

Revenue from external customers	$	656		$	218	⁽²⁾	$	107		$	—		$	981	$	724	$	427	⁽¹⁾	$	249		$	1		$	—		$	1,401
Intersegment revenue		11			125	⁽²⁾		(133	)		(3	)		—		13		220	⁽¹⁾		(230	)		—			(3	)		—
Operation and maintenance		209			107			2			28			346		184		99			2			16			—			301
Ceiling test charges		—			5			—			—			5
Depreciation, depletion and amortization		104			93			—			3			200		106		107			—			5			—			218
Earnings (losses) from unconsolidated affiliates		27			(7	)		—			(9	)		11
EBIT		326			88			(28	)		(28	)		358
Earnings from unconsolidated affiliates																22		—			—			6			—			28
Segment EBIT																452		390			17			(11	)		—			848


⁽¹⁾		^{Throughput volumes include our proportionate share of unconsolidated affiliates and exclude intrasegment activities.}

⁽²⁾		^{March 31, 2010 amount includes throughput volumes of 748 BBtu/d related to our Mexican pipeline assets which were sold in 2010.}


	Quarter Ended September 30, 2010												Nine Months Ended September 30, 2010
	Variance												Variance												Variance
	Operating			Operating									Operating			Operating									Operating			Operating
	Revenue			Expense			Other			Total			Revenue			Expense			Other			Total			Revenue			Expense			Other		Total
										Favorable/(Unfavorable)															Favorable/(Unfavorable)
										(In millions)															(In millions)
Expansions	$	50		$	(10	)	$	34		$	74		$	126		$	(25	)	$	92		$	193		$	41		$	(9	)	$	49	$	81
Reservation and usage revenues		(6	)		—			—			(6	)		(6	)		3			—			(3	)		(26	)		(3	)		—		(29	)
Gas not used in operations and revaluations		(18	)		(5	)		—			(23	)		(63	)		10			—			(53	)		7			(1	)		—		6
Operating and general and administrative expenses		—			8			—			8			—			15			—			15
Operating and general and administrative expense																										—			(12	)		—		(12	)
Asset write downs		—			(21	)		—			(21	)		—			(28	)		—			(28	)		—			10			—		10
Sale of Mexican assets		—			—			—			—			—			—			80			80
Other⁽¹⁾		(1	)		(1	)		4			2			2			1			5			8			(6	)		(7	)		4		(9	)

Total impact on EBIT before adjustment for noncontrolling interests		25			(29	)		38			34			59			(24	)		177			212
Net income attributable to noncontrolling interests		—			—			(26	)		(26	)		—			—			(63	)		(63	)
Total impact on Segment EBIT																									$	16		$	(22	)	$	53	$	47

Total impact on EBIT	$	25		$	(29	)	$	12		$	8		$	59		$	(24	)	$	114		$	149


⁽¹⁾		^{Consists of individually insignificant items on several of our pipeline systems.}


				Gross Wells
	Success Rate			Drilled
Central		99	%		140
Western		100	%		17
Gulf Coast		89	%		19


	Fixed Price
	Swaps⁽¹⁾				Floors⁽¹⁾				Ceilings⁽¹⁾				Basis Swaps⁽¹⁾⁽²⁾
																		Western										Central
													Texas Gulf Coast					Raton					Rockies					Mid-Continent
			Average				Average				Average				Average					Average					Average					Average
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes		Price			Volumes		Price			Volumes		Price			Volumes		Price
Natural Gas
2010		31	$	5.60		6	$	7.00		—		—		12	$	(0.40	)		5	$	(0.78	)		2	$	(1.93	)		3	$	(0.74	)
2011		153	$	6.00		18	$	6.00		18	$	7.29		33	$	(0.13	)		22	$	(0.25	)		—		—			—		—
2012		64	$	6.36		—		—		—		—		—		—			—		—			—		—			—		—

Oil
2010		773	$	77.02		414	$	75.00		414	$	91.33
2011		—		—		2,008	$	80.00		2,008	$	95.56
2012		—		—		—		—		1,464	$	95.00
2013		—		—		—		—		1,825	$	95.00


⁽¹⁾		^{Includes equity earnings from Four Star, our unconsolidated affiliate, net of amortization of our purchase cost in excess of our equity interest in the underlying net assets.}


⁽¹⁾		^{We had no cash premiums related to natural gas and oil derivatives settled during the quarter ended March 31, 2011. Premiums paid in 2009 related to natural gas derivatives settled during the quarter and nine months ended September 30,March 31, 2010 were $48 million and $148$52 million. Had we included these premiums in our natural gas average realized prices in 2010, our realized price, including financial derivative settlements, would have decreased by $0.88/$0.93/Mcf for the quarter and nine months ended September 30,March 31, 2010. We had no cash premiums related to natural gasoil derivatives settled during the quarter and nine months ended September 30, 2009, or related to oil derivatives settled during the quarters and nine months ended September 30, 2010 and 2009.March 31, 2010.}

⁽²⁾		~~Amounts for the quarter~~^{The quarters ended March 31, 2011 and nine months ended September 30, 2009,2010 include approximately $50$82 million and $137$51 million, respectively, of cash receipts on settlements related to $186natural gas derivative contracts and approximately $1 million for each quarter, respectively, of cash received in the first quarter of 2009 for the early settlement ofpaid on settlements related to crude oil derivative contracts originally scheduled to mature throughout 2009.contracts.}

⁽³⁾		^{Production taxes include ad valorem and severance taxes.}

⁽⁴⁾		^{Includes $0.06 per Mcfe and $0.07 per Mcfe for the quarters ended September 30,March 31, 2011 and 2010 and 2009 and $0.07 per Mcfe and $0.06 per Mcfe for the nine months ended September 30, 2010 and 2009 related to accretion expense on asset retirement obligations.}


	Maturity			Maturity			Maturity			Maturity			Total
	Less Than			1 to 3			4 to 5			6 to 10			Fair
	1 Year			Years			Years			Years			Value
							(In millions)
Assets	$	324		$	115		$	(2	)	$	7		$	444
Liabilities		(166	)		(218	)		(115	)		(31	)		(530	)

Total commodity-based derivatives	$	158		$	(103	)	$	(117	)	$	(24	)	$	(86	)


	Commodity-
	Based
	Derivatives
	(In millions)
Fair value of contracts outstanding at January 1, 2010	$	(381	)

Fair value of contract settlements during the period⁽¹⁾		(266	)
Premiums during the period⁽¹⁾		126
Changes in fair value of contracts during the period		435

Net changes in contracts outstanding during the period		295

Fair value of contracts outstanding at September 30, 2010	$	(86	)