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

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

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)		Identification No.)
El Paso Building
1001 Louisiana Street
Houston, Texas		77002
(Address of Principal Executive Offices)		(Zip Code)

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

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

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

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

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

     Common stock, par value $3 per share. Shares outstanding on 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
PART II — OTHER INFORMATION
Item 1.		Legal Proceedings			40
Item 1A.		Risk Factors			40
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			40
Item 3.		Defaults Upon Senior Securities			41
Item 4.		(Removed and Reserved)			41
Item 5.		Other Information			41
Item 6.		Exhibits			41
		Signatures			42
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 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)

		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)

		March 31,				December 31,
		2011				2010
ASSETS
Current assets
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 $4 in 2011 and $4 in 2010			368				333
Affiliates			9				7
Other			159				160
Materials and supplies			166				169
Assets from price risk management activities			154				265
Deferred income taxes			189				165
Other			104				106
Total current assets			1,391				1,552
Property, plant and equipment, at cost
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			438				416
			45,355				44,493
Less accumulated depreciation, depletion and amortization			23,565				23,421
Total property, plant and equipment, net			21,790				21,072
Other long-term assets
Investments in unconsolidated affiliates			1,683				1,673
Assets from price risk management activities			32				61
Other			961				912
			2,676				2,646
Total assets		$	25,857			$	25,270

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions, except share and per share amounts)
(Unaudited)

		March 31,				December 31,
		2011				2010
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade		$	452			$	610
Affiliates			11				9
Other			420				386
Short-term financing obligations, including current maturities			495				489
Liabilities from price risk management activities			188				176
Asset retirement obligations			64				63
Accrued interest			247				202
Other			533				630
Total current liabilities			2,410				2,565
Long-term financing obligations, less current maturities			13,566				13,517
Other long-term liabilities
Liabilities from price risk management activities			401				397
Deferred income taxes			628				568
Other			1,450				1,461
			2,479				2,426
Commitments and contingencies (Note 7)
Preferred stock of subsidiaries			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 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			5,246				4,484
Accumulated deficit			(2,372	)			(2,434	)
Accumulated other comprehensive loss			(729	)			(751	)
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			4,210				3,917
Noncontrolling interests			2,447				2,147
Total equity			6,657				6,064
Total liabilities and equity		$	25,857			$	25,270

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)

		Quarter Ended
		March 31,
		2011				2010
Cash flows from operating activities
Net income		$	136			$	419
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization			254				218
Deferred income tax expense			26				194
Earnings from unconsolidated affiliates, adjusted for cash distributions			(18	)			(13	)
Loss on debt extinguishment			41				—
Other non-cash income items			(64	)			(4	)
Asset and liability changes			156				(336	)
Net cash provided by operating activities			531				478
Cash flows from investing activities
Capital expenditures			(1,089	)			(741	)
Other			—				(6	)
Net cash used in investing activities			(1,089	)			(747	)
Cash flows from financing activities
Net proceeds from issuance of long-term debt			806				775
Payments to retire long-term debt and other financing obligations			(794	)			(617	)
Net proceeds from issuance of noncontrolling interests			457				231
Distributions to noncontrolling interest holders			(39	)			(19	)
Net proceeds from issuance of preferred stock of subsidiary			30				—
Distributions to holders of preferred stock of subsidiary			(5	)			(5	)
Dividends paid			(16	)			(16	)
Other			14				—
Net cash provided by financing activities			453				349
Change in cash and cash equivalents			(105	)			80
Cash and cash equivalents
Beginning of period			347				635
End of period		$	242			$	715

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY
(In millions)
(Unaudited)

		Quarter Ended
		March 31,
		2011				2010
El Paso Corporation stockholders’ equity:
Preferred stock:
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			2,159				2,148
Conversion of preferred stock			174				—
Other, net			4				—
Balance at end of period			2,337				2,148
Additional paid-in capital:
Balance at beginning of period			4,484				4,501
Conversion of preferred stock			576				—
Dividends			(7	)			(16	)
Issuances of noncontrolling interests (Note 9)			170				—
Other, including stock-based compensation			23				12
Balance at end of period			5,246				4,497
Accumulated deficit:
Balance at beginning of period			(2,434	)			(3,192	)
Net income attributable to El Paso Corporation			62				388
Balance at end of period			(2,372	)			(2,804	)
Accumulated other comprehensive income (loss):
Balance at beginning of period			(751	)			(718	)
Other comprehensive income			22				12
Balance at end of period			(729	)			(706	)
Treasury stock, at cost:
Balance at beginning of period			(291	)			(283	)
Stock-based and other compensation			19				(1	)
Balance at end of period			(272	)			(284	)
Total El Paso Corporation stockholders’ equity at end of period			4,210				3,601
Noncontrolling interests:
Balance at beginning of period			2,147				785
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			2,447				1,023
Total equity at end of period		$	6,657			$	4,624

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
(Unaudited)

		Quarter Ended
		March 31,
		2011				2010
Net income		$	136			$	419
Pension and postretirement obligations:
Reclassification of actuarial gains during period (net of income taxes of $7 in 2011 and $6 in 2010)			16				13
Other (net of income taxes of $3 in 2011 and 2010)			6				(1	)
Other comprehensive income			22				12
Comprehensive income			158				431
Comprehensive income attributable to noncontrolling interests			(74	)			(31	)
Comprehensive income attributable to El Paso Corporation		$	84			$	400

See accompanying notes.

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). 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), and should be read along with our 2010 Annual Report on Form 10-K. The financial statements as of March 31, 2011, and for the quarters ended March 31, 2011 and 2010, are unaudited. The condensed consolidated balance sheet as of December 31, 2010, was derived from the audited balance sheet filed in our 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

     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 but not yet adopted as of March 31, 2011.

2. Other Income, Net

     The following are the components of other income and other expense for the quarters ended March 31:

		2011				2010
		(In millions)
Other Income
Allowance for equity funds used during construction		$	97			$	50
Other			7				14
Total			104				64
Other Expense
Other			5				4
Total			5				4
Other income, net		$	99			$	60

     Allowance for Equity Funds Used During Construction. As allowed by the Federal Energy Regulatory Commission (FERC), we capitalize a pre-tax carrying cost on equity funds related to the construction of long-lived assets in our FERC regulated business and reflect this amount as an increase in the cost of the asset on our balance sheet. We calculate this amount using the most recent FERC approved equity rate of return. These amounts are recovered over the depreciable lives of the long-lived assets to which they relate.

3. Income Taxes

     Income taxes for the quarters ended March 31 were as follows:

		2011				2010
		(In millions, except rates)
Income tax expense		$	19			$	186
Effective tax rate			12	%			31	%

     Effective Tax Rate. We compute interim period income taxes by applying an anticipated annual effective tax rate to our year-to-date income or loss, except for significant unusual or infrequently occurring items, which are recorded in the period the item occurs. Changes in tax laws or rates are recorded in the period of enactment. Our effective tax rate is affected by items such as income attributable to nontaxable noncontrolling interests, dividend exclusions on earnings from unconsolidated affiliates where we anticipate receiving dividends, the effect of state income taxes (net of federal income tax effects), and the effect of foreign income which can be taxed at different rates.

     During the first quarter of 2011, our effective tax rate was lower than the statutory rate primarily due to the benefit to our anticipated annual effective tax rate of income attributable to nontaxable noncontrolling interests and dividend exclusions on earnings from unconsolidated affiliates where we anticipate receiving dividends. In addition, our effective tax rate for the first quarter of 2011 was favorably impacted by the resolution of several tax matters and earned state tax credits. During the first quarter of 2010, our effective tax rate was lower than the statutory rate primarily due to income attributable to nontaxable noncontrolling interests partially offset by $18 million of additional deferred income tax expense from healthcare legislation enacted in March 2010 which reduces the tax deduction for retiree prescription drug expenses to the extent they are reimbursed under the Medicare subsidy program.

4. Earnings Per Share

     Basic and diluted earnings per common share were as follows for the quarters ended March 31:

		2011								2010
		Basic				Diluted				Basic				Diluted
						(In millions, except per share amounts)
Net income attributable to El Paso Corporation		$	62			$	62			$	388			$	388
Preferred stock dividends of El Paso Corporation			—				—				(9	)			—
Interest on preferred securities			—				—				—				3
Net income attributable to El Paso Corporation’s common stockholders		$	62			$	62			$	379			$	391
Weighted average common shares outstanding			714				714				696				696
Effect of dilutive securities:
Options and restricted stock			—				10				—				6
Convertible preferred stock			—				44				—				58
Trust preferred securities			—				—				—				8
Weighted average common shares outstanding and dilutive securities			714				768				696				768
Basic and diluted earnings per common share:
Net income attributable to El Paso Corporation’s common stockholders		$	0.09			$	0.08			$	0.54			$	0.51

     We exclude potentially dilutive securities from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on net income attributable to El Paso Corporation per common share is antidilutive. Our potentially dilutive securities for the periods presented consist of employee stock options, restricted stock, convertible preferred stock and trust preferred securities. In March 2011, we converted our preferred stock to common stock as further described in Note 9. For the quarters ended March 31, 2011 and 2010, certain of our employee stock options were antidilutive. Additionally, for the quarter ended March 31, 2011, our trust preferred securities were antidilutive.

5. Financial Instruments

     The following table reflects the carrying value and fair value of our financial instruments:

		March 31, 2011								December 31, 2010
		Carrying				Fair				Carrying				Fair
		Amount				Value				Amount				Value
						(In millions)
Long-term financing obligations, including current maturities		$	14,061			$	15,343			$	14,006			$	14,686
Marketable securities in non-qualified compensation plans			20				20				20				20
Commodity-based derivatives			(344	)			(344	)			(186	)			(186	)
Interest rate derivatives			(59	)			(59	)			(61	)			(61	)
Other			(8	)			(8	)			(11	)			(11	)

     As of March 31, 2011 and December 31, 2010, the carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and short-term financing obligations represent fair value because of the short-term nature of these instruments. The carrying amounts of our restricted cash and noncurrent receivables approximate their fair value based on the nature of their interest rates and our assessment of the ability to recover these amounts. We estimated the fair value of our long-term financing obligations based on quoted market prices for the same or similar issues, including consideration of our credit risk related to those instruments.

     Our derivative financial instruments are further described in our 2010 Annual Report on Form 10-K and below:

	•		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 which is offset by changes in the fair value of the related hedged items. As of March 31, 2011 and December 31, 2010, these interest rate swaps converted the interest rate on approximately $184 million of debt from a fixed rate to a variable rate of LIBOR plus 4.18%.

     Fair Value Measurement. We 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 level can change over time based on the maturity or liquidity of 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 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 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	)

     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. Based on our assessment of counterparty risk in light of the collateral our 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 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 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	)

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

		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

6. Debt, Other Financing Obligations and Other Credit Facilities

		March 31,				December 31,
		2011				2010
		(In millions)
Short-term financing obligations, including current maturities		$	495			$	489
Long-term financing obligations			13,566				13,517
Total		$	14,061			$	14,006

     Changes in Financing Obligations. During the quarter ended March 31, 2011, we had the following changes in our financing obligations:

						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	)

     Subsequent to March 31, 2011, our overall debt has increased by approximately $500 million due to incremental borrowings under our revolving credit facilities. This increase was partially offset by a reduction in letters of credit issued under these facilities related to our Ruby pipeline project.

     Repurchase of Senior Notes. In March 2011, we repurchased $148 million of notes and recorded a loss on debt extinguishment of approximately $41 million. In April 2011, we repurchased an additional $153 million of notes and will record a loss of approximately $19 million in the second quarter of 2011.

     Credit Facilities/Letters of Credit. We have various credit facilities in place which allow us to borrow funds or issue letters of credit. During the first quarter of 2011, we increased the total letter of credit capacity under certain existing letter of credit facilities by $125 million with a weighted average fixed facility fee of 1.95 percent and maturities ranging from March 2013 to September 2014. As of March 31, 2011, the aggregate amount outstanding under all of our credit facilities was $0.2 billion (excluding $0.4 billion outstanding on the EPPOC $750 million revolving credit facility) and $1.1 billion of letters of credit and surety bonds issued, including $0.4 billion related to our price risk management activities. Our total available capacity under all of our facilities was approximately $2.6 billion as of March 31, 2011 (not including capacity available under the EPPOC $750 million revolving credit facility and our Ruby project financing).

     The availability of borrowings under our credit agreements and our ability to incur additional debt is subject to various financial and non-financial covenants and restrictions. There have been no significant changes to our restrictive covenants, and as of March 31, 2011, we were in compliance with all of our debt covenants. For a further discussion of our credit facilities and restrictive covenants, see our 2010 Annual Report on Form 10-K.

     Ruby Pipeline Financing. During 2010, we entered into a seven-year amortizing $1.5 billion financing facility for our Ruby pipeline project (see Note 11) that requires principal payments at various dates through June 2017. As of March 31, 2011, we have utilized substantially all of the capacity under this facility. Our initial interest rate on amounts borrowed is LIBOR plus 3 percent which increases to LIBOR plus 3.25 percent for years three and four, and to LIBOR plus 3.75 percent for years five through seven assuming we refinance $700 million of the facility by the end of year four. If we do not refinance $700 million by the end of year four, the rate will be LIBOR plus 4.25 percent for years five through seven. In conjunction with entering into this facility, we entered into interest rate

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.

     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, as of March 31, 2011, we have $350 million outstanding in letters of credit to cover anticipated cost overruns. If additional cost overruns are forecasted and approved by the lender’s engineer in subsequent months, additional collateral may be required to be issued pursuant to the Ruby financing agreements.

7. Commitments and Contingencies

Legal Proceedings

     Cash Balance Plan Lawsuit. In December 2004, a purported class action lawsuit entitled Tomlinson, et al.v. El Paso Corporation and El Paso Corporation Pension Plan was 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 final average earnings formula pension plan to a cash balance pension plan. In 2010, a trial court dismissed all of the claims in this matter. The dismissal of the case has been appealed.

     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 2010 Annual report on Form 10-K. Although damages in excess of $140 million have been alleged in total against all defendants in one of the remaining lawsuits where a damage number is provided, 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. 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 these remaining lawsuits, it is likely that our insurers will assert denial of coverage on nine of the most-recently 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.

     In addition to the above proceedings, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings and claims that arise in the ordinary course of our business. For each of these matters, we evaluate the merits of the case or claim, our exposure to the matter, possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we establish the necessary accruals. While the outcome of these matters, including those discussed above, cannot be predicted with certainty, and there are still uncertainties related to the costs we may incur, based upon our evaluation and experience to date, we believe we have established appropriate reserves for these matters. It is possible, however, that new information or future developments could require us to reassess our potential exposure related to these matters and adjust our accruals accordingly, and these adjustments could be

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

Rates and Regulatory Matters

     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 refunds to its customers in 2010. The settlement resolved all but four issues in the proceeding. In January 2011, the Presiding Administrative Law Judge issued a decision that for the most part found against EPNG on the 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 believe our accruals established for this matter are 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 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 March 31, 2011, our accrual was approximately $168 million for environmental matters, which has not been reduced by $19 million for amounts to be paid directly under government sponsored programs or through contractual arrangements with third parties. Our accrual includes approximately $165 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $3 million for related environmental legal costs.

     Our estimates of potential liability range from approximately $168 million to approximately $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:

		March 31, 2011
Sites		Expected				High
		(In millions)
Operating		$	8			$	12
Non-operating			146				303
Superfund			14				37
Total		$	168			$	352

     Superfund Matters. Included in our recorded environmental liabilities are projects where we have received notice that we have been designated or could be designated, as a Potentially Responsible Party (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act (CERCLA), commonly known as

Superfund, or state equivalents for 30 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 2011, we estimate that our total remediation expenditures will be approximately $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 $27 million in the aggregate for the remainder of 2011 through 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 are subject to regulations with which we have to be in compliance by October 2013.

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

Guarantees and Other Contractual Commitments

     Guarantees and Indemnifications. We have guarantees and indemnifications with a maximum stated value of approximately $0.8 billion, primarily related to indemnification arrangements associated with the sale of ANR Pipeline Company in 2007 and certain legacy assets. These amounts exclude guarantees for which we have issued related letters of credit discussed in Note 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 March 31, 2011, we have recorded obligations of $17 million related to our guarantee and indemnification arrangements. 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.

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

8. Retirement Benefits

     Components of Net Benefit Cost. The components of net benefit cost are as follows for the quarters ended March 31:

										Other
		Pension								Postretirement
		Benefits								Benefits
		2011				2010				2011				2010
		(In millions)
Service cost		$	5			$	5			$	—			$	—
Interest cost			26				28				8				8
Expected return on plan assets			(36	)			(39	)			(4	)			(3	)
Amortization of net actuarial loss (gain)			23				19				—				(1	)
Net benefit cost		$	18			$	13			$	4			$	4

9. Equity and Preferred Stock of Subsidiaries

     Convertible Perpetual Preferred Stock. On March 11, 2011, we exercised our mandatory conversion right related to our $750 million of convertible perpetual preferred stock. Upon conversion, holders of our convertible preferred stock received approximately 57.9 million shares of common stock (approximately 77.2295 shares of El Paso common stock for each share of preferred stock converted).

     Common and Preferred Stock Dividends. The table below shows the amount of dividends paid and declared (in millions, except per share amount):

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

     Dividends on our common stock and convertible preferred stock are treated as a reduction of additional paid-in-capital since we currently have an accumulated deficit. We expect dividends paid in 2011 on our common stock and preferred stock will be taxable to our stockholders because we anticipate that these dividends will be paid out of current or accumulated earnings and profits for tax purposes. Our ability to pay dividends can be impacted by certain restrictions as further described in our 2010 Annual Report on Form 10-K.

     Noncontrolling Interest in EPB. We are the general partner of EPB, a master limited partnership (MLP) formed in 2007. As of March 31, 2011, we hold a 2 percent general partner interest and a 45 percent limited partner interest in the partnership. In accordance with its partnership agreement, EPB is obligated to make quarterly distributions of available cash to its 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 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 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 March 31, 2011 reflects the issuance of the EPB common units as an increase of $287 million to noncontrolling interests and $170 million to El Paso Corporation’s additional paid-in capital. Our net income attributable to 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 in our assets becomes diluted over time. However our economic interest will benefit from the receipt of 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 reset, at higher levels, the minimum quarterly distribution amount and cash target distribution levels upon which the incentive distribution payments would be set. We are currently entitled to receive the maximum level of incentive distributions.

     Preferred Stock of Subsidiaries. During the quarter ended March 31, 2011, our partner on our Ruby pipeline project, Global Infrastructure Partners (GIP), contributed an additional $30 million 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 $145 million for a convertible preferred equity interest in Cheyenne Plains Gas Pipeline Company, L.L.C. (Cheyenne Plains). GIP earns a 15 percent dividend on its preferred interests in Cheyenne Plains. GIP will earn a 13 percent return on its convertible preferred interests in Ruby beginning on the earlier of the date the pipeline project is placed in service or August 2011. We paid preferred dividends of $5 million on GIP’s preferred interest in Cheyenne Plains for the quarters ended March 31, 2011 and 2010. Also, for the quarter ended March 31, 2011, we recorded $17 million related to the return 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 ended March 31:

		2011				2010
		(In millions)
EPB		$	52			$	26
Preferred Stock of Cheyenne Plains			5				5
Preferred Stock of Ruby			17				—
Net income attributable to noncontrolling interests		$	74			$	31

10. Business Segment Information

     As of March 31, 2011, our business consists of the following segments: Pipelines, Exploration and Production, 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. A further discussion of each segment follows.

     Pipelines. Our Pipelines segment provides natural gas transmission, storage, and related services, primarily in the U.S. As of 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 and NGL, in the 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 production as well as manages our remaining legacy trading portfolio.

     Other. Our other activities include our corporate general and administrative functions, midstream operations and other miscellaneous businesses.

     Beginning January 1, 2011, we use segment earnings before interest expense and income taxes (Segment EBIT) as a measure to assess the operating results and effectiveness of our business segments. We believe Segment EBIT is useful to our investors because it allows them to use the same performance measure analyzed internally by our 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 interest and debt expense and income taxes. It does not reflect a reduction for any amounts attributable to noncontrolling 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 to our net income for the periods ended March 31:

		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

     The following table reflects our segment results for the quarters ended March 31:

		Segments
						Exploration
		Pipelines				and Production				Marketing				Other				Eliminations				Total
										(In millions)
2011
Revenue from external customers		$	703			$	84	(1)		$	201			$	1			$	—			$	989
Intersegment revenue			50				166	(1)			(213	)			1				(4	)			—
Operation and maintenance			190				101				2				13				(1	)			305
Depreciation, depletion and amortization			114				134				—				6				—				254
Earnings (losses) from unconsolidated affiliates			25				(2	)			—				7				—				30
Segment EBIT			499				(31	)			(14	)			(59	)			—				395
2010
Revenue from external customers		$	724			$	427	(1)		$	249			$	1			$	—			$	1,401
Intersegment revenue			13				220	(1)			(230	)			—				(3	)			—
Operation and maintenance			184				99				2				16				—				301
Depreciation, depletion and amortization			106				107				—				5				—				218
Earnings from unconsolidated affiliates			22				—				—				6				—				28
Segment EBIT			452				390				17				(11	)			—				848

     Total assets by segment are presented below:

		March 31,				December 31,
		2011				2010
		(In millions)
Pipelines		$	20,189			$	19,651
Exploration and Production			4,735				4,657
Marketing			210				222
Other			896				943
Total segment assets			26,030				25,473
Eliminations			(173	)			(203	)
Total consolidated assets		$	25,857			$	25,270

11. Variable Interest Entities and Accounts Receivable Sales Programs

     Ruby/Cheyenne Plains. As of March 31, 2011 GIP, our partner in the Ruby pipeline project, had contributed approximately $700 million in exchange for convertible preferred equity interests (see Note 9) in Ruby and Cheyenne Plains. We consolidate Ruby and Cheyenne Plains as variable interest entities as we are the primary beneficiary of 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 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 by the end of November 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. If all conditions to closing are satisfied or waived, GIP would own a 50 percent preferred equity interest in Ruby and all ownership in Cheyenne Plains would be transferred back to us. Additionally, GIP has the right to convert its preferred equity in Ruby to common equity in Ruby at any time.

     Accounts Receivable Sales Program. We participate in accounts receivable sales programs where several of our pipeline subsidiaries sell receivables in their entirety to a third-party financial institution (through wholly-owned special purpose entities). The sale of these accounts receivable (which are short-term assets that generally settle within 60 days) qualify for sale accounting. The third party financial institution involved in 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 since our receivables do not comprise a significant portion of its operations.

     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 (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 table below contains information related to our accounts receivable sales program.

		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

		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

     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