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 (State or Other Jurisdiction of Incorporation or Organization)		76-0568816 (I.R.S. Employer Identification No.)
El Paso Building 1001 Louisiana Street Houston, Texas (Address of Principal Executive Offices)		77002 (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 (Do not check if a smaller reporting company)		Smaller reporting company o

     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 3, 2010: 703,741,156

 

 

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			22
Item 3.		Quantitative and Qualitative Disclosures About Market Risk			39
Item 4.		Controls and Procedures			40
PART II — OTHER INFORMATION
Item 1.		Legal Proceedings			41
Item 1A.		Risk Factors			41
Item 2.		Unregistered Sales of Equity Securities and Use of Proceeds			41
Item 3.		Defaults Upon Senior Securities			41
Item 4.		(Removed and Reserved)			41
Item 5.		Other Information			42
Item 6.		Exhibits			42
		Signatures			43
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		MMBtu		= million British thermal units
Bbl		= barrels		MMcf		= million cubic feet
BBtu		= billion British thermal units		MMcfe		= million cubic feet of natural gas equivalents
LNG		= liquefied natural gas		GW		= gigawatts
MBbls		= thousand barrels		GWh		= thousand megawatt hours
MMBbls		= million barrels		NGL		= natural gas liquids
Mcf		= thousand cubic feet		TBtu		= trillion British thermal units
Mcfe		= thousand cubic feet of natural gas equivalents

     When we refer to 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)

		Quarter Ended
		March 31,
		2010				2009
Operating revenues		$	1,401			$	1,484
Operating expenses
Cost of products and services			53				61
Operation and maintenance			299				300
Ceiling test charges			2				2,068
Depreciation, depletion and amortization			218				256
Taxes, other than income taxes			69				68
			641				2,753
Operating income (loss)			760				(1,269	)
Earnings from unconsolidated affiliates			28				19
Other income, net			60				22
Interest and debt expense			(243	)			(255	)
Income (loss) before income taxes			605				(1,483	)
Income tax (benefit) expense			186				(526	)
Net income (loss)			419				(957	)
Net income attributable to noncontrolling interests			(31	)			(12	)
Net income (loss) attributable to El Paso Corporation			388				(969	)
Preferred stock dividends of El Paso Corporation			9				9
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	379			$	(978	)
Basic earnings (loss) per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	0.54			$	(1.41	)
Diluted earnings (loss) per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	0.51			$	(1.41	)
Dividends declared per El Paso Corporation’s common share		$	0.01			$	0.05

See accompanying notes.

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

		March 31,				December 31,
		2010				2009
ASSETS
Current assets
Cash and cash equivalents (include $111 in 2010 and $149 in 2009 held by variable interest entities)		$	715			$	635
Accounts and notes receivable
Customer, net of allowance of $6 in 2010 and $8 in 2009			312				346
Affiliates			25				92
Other			208				115
Materials and supplies			169				175
Assets from price risk management activities			337				221
Deferred income taxes			204				298
Other			125				126
Total current assets			2,095				2,008
Property, plant and equipment, at cost
Pipelines (include $1,512 in 2010 and $1,179 in 2009 held by variable interest entities)			20,208				19,722
Natural gas and oil properties, at full cost			21,032				20,846
Other			323				314
			41,563				40,882
Less accumulated depreciation, depletion and amortization			23,124				22,987
Total property, plant and equipment, net			18,439				17,895
Other assets
Investments in unconsolidated affiliates			1,725				1,718
Assets from price risk management activities			156				123
Other			776				761
			2,657				2,602
Total assets		$	23,191			$	22,505

See accompanying notes.

EL PASO CORPORATION

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

		March 31,				December 31,
		2010				2009
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade		$	427			$	459
Affiliates			5				7
Other			410				424
Short-term financing obligations, including current maturities			622				477
Liabilities from price risk management activities			221				269
Asset retirement obligations			155				158
Accrued interest			242				208
Other			617				684
Total current liabilities			2,699				2,686
Long-term financing obligations, less current maturities			13,416				13,391
Other
Liabilities from price risk management activities			403				462
Deferred income taxes			444				339
Other			1,460				1,491
			2,307				2,292
Commitments and contingencies (Note 9)
Preferred stock of subsidiary			145				145
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 716,159,760 shares in 2010 and 716,041,302 shares in 2009			2,148				2,148
Additional paid-in capital			4,497				4,501
Accumulated deficit			(2,804	)			(3,192	)
Accumulated other comprehensive loss			(706	)			(718	)
Treasury stock (at cost); 14,820,145 shares in 2010 and 14,761,654 shares in 2009			(284	)			(283	)
Total El Paso Corporation stockholders’ equity			3,601				3,206
Noncontrolling interests			1,023				785
Total equity			4,624				3,991
Total liabilities and equity		$	23,191			$	22,505

See accompanying notes.

EL PASO CORPORATION

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

		Quarter Ended
		March 31,
		2010				2009
Cash flows from operating activities
Net income (loss)		$	419			$	(957	)
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization			218				256
Ceiling test charges			2				2,068
Deferred income tax expense (benefit)			194				(528	)
Earnings from unconsolidated affiliates, adjusted for cash distributions			(13	)			(8	)
Other non-cash income items			(6	)			14
Asset and liability changes			(244	)			(36	)
Net cash provided by operating activities			570				809
Cash flows from investing activities
Capital expenditures			(833	)			(759	)
Cash paid for acquisitions, net of cash acquired			(8	)			—
Net proceeds from the sale of assets and investments			1				210
Other			1				13
Net cash used in investing activities			(839	)			(536	)
Cash flows from financing activities
Net proceeds from issuance of long-term debt			775				842
Payments to retire long-term debt and other financing obligations			(617	)			(244	)
Net proceeds from issuance of noncontrolling interests			231				—
Dividends paid			(16	)			(44	)
Distributions to noncontrolling interest holders			(19	)			(10	)
Distributions to holders of preferred stock of subsidiary			(5	)			—
Net cash provided by financing activities			349				544
Change in cash and cash equivalents			80				817
Cash and cash equivalents
Beginning of period			635				1,024
End of period		$	715			$	1,841

See accompanying notes.

EL PASO CORPORATION

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

		Quarter Ended
		March 31,
		2010				2009
El Paso Corporation stockholders’ equity:
Preferred stock:
Balance at beginning and end of period		$	750			$	750
Common stock:
Balance at beginning and end of period			2,148				2,138
Additional paid-in capital:
Balance at beginning of period			4,501				4,612
Dividends			(16	)			(44	)
Other, including stock-based compensation			12				14
Balance at end of period			4,497				4,582
Accumulated deficit:
Balance at beginning of period			(3,192	)			(2,653	)
Net income (loss) attributable to El Paso Corporation			388				(969	)
Balance at end of period			(2,804	)			(3,622	)
Accumulated other comprehensive income (loss):
Balance at beginning of period			(718	)			(532	)
Other comprehensive income (loss)			12				(73	)
Balance at end of period			(706	)			(605	)
Treasury stock, at cost:
Balance at beginning of period			(283	)			(280	)
Stock-based and other compensation			(1	)			—
Balance at end of period			(284	)			(280	)
Total El Paso Corporation stockholders’ equity at end of period			3,601				2,963
Noncontrolling interests:
Balance at beginning of period			785				561
Distributions paid to noncontrolling interests			(19	)			(10	)
Issuances of noncontrolling interests			231				—
Net income attributable to noncontrolling interests (Note 11)			26				12
Balance at end of period			1,023				563
Total equity at end of period		$	4,624			$	3,526

See accompanying notes.

EL PASO CORPORATION

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

		Quarter Ended
		March 31,
		2010				2009
Net income (loss)		$	419			$	(957	)
Pension and postretirement obligations:
Reclassification of actuarial gains during period (net of income taxes of $6 in 2010 and $4 in 2009)			13				7
Cash flow hedging activities:
Unrealized mark-to-market gains (losses) arising during period (net of income taxes of $2 in 2010 and $1 in 2009)			(3	)			2
Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $1 in 2010 and $46 in 2009)			2				(82	)
Other comprehensive income (loss)			12				(73	)
Comprehensive income (loss)			431				(1,030	)
Comprehensive income attributable to noncontrolling interests			(31	)			(12	)
Comprehensive income (loss) attributable to El Paso Corporation		$	400			$	(1,042	)

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). Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. generally accepted accounting principles. You should read this report along with our 2009 Annual Report on Form 10-K, which contains a summary of our significant accounting policies and other disclosures. The financial statements as of March 31, 2010, and for the quarters ended March 31, 2010 and 2009, are unaudited. We derived the condensed consolidated balance sheet as of December 31, 2009, from the audited balance sheet filed in our 2009 Annual Report on Form 10-K. In our opinion, we have made adjustments, all of which are of a normal, recurring nature to fairly present our interim period results. Due to the seasonal nature of our businesses, information for interim periods may not be indicative of our operating results for the entire year.

Significant Accounting Policies

     The following is an update of our significant accounting policies and accounting pronouncements issued but not yet adopted as discussed in our 2009 Annual Report on Form 10-K.

     Transfers of Financial Assets. On January 1, 2010, we adopted accounting standard updates for financial asset transfers. Among other items, these updates require 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 these accounting standard updates 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 these accounting standard updates. 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 13.

     Variable Interest Entities. On January 1, 2010, we adopted accounting standard updates 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 these accounting standard updates did not have a material impact on our financial statements. For a further discussion of our involvement with variable interest entities, see Note 13.

2. Divestitures

     During the first quarter of 2009, we completed the sale of our interests in the Porto Velho power generation facility in Brazil for total consideration of $179 million and the sale of non-core natural gas producing properties located in our Central and Western divisions for approximately $93 million. In April 2010, we completed the sale of our interests in Mexican pipeline and compression assets for approximately $300 million. We currently expect to record a pretax gain of approximately $80 million in the second quarter of 2010.

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 ended March 31, 2010 and 2009, we recorded the following ceiling test charges:

		2010				2009
		(In millions)
Full cost pool:
U.S		$	—			$	2,031
Brazil			—				28
Egypt			2				9
Total		$	2			$	2,068

     During the first quarter of 2009, the calculation of these charges was based on spot commodity prices as of March 31, 2009, 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 now use 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. Income Taxes

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

		2010				2009
		(In millions, except rates)
Income tax (benefit) expense		$	186			$	(526	)
Effective tax rate			31	%			35	%

     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. Significant tax items are recorded in the period that the item occurs and 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 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. During the first quarter of 2009, our effective tax rate was relatively consistent with the statutory rate.

5. Earnings Per Share

     We calculated basic and diluted earnings (loss) per common share as follows for the quarters ended March 31:

		2010								2009
		Basic				Diluted				Basic				Diluted
		(In millions, except per share amounts)
Net income (loss) attributable to El Paso Corporation		$	388			$	388			$	(969	)		$	(969	)
Preferred stock dividends of El Paso Corporation			(9	)			—				(9	)			(9	)
Interest on preferred securities			—				3				—				—
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	379			$	391			$	(978	)		$	(978	)
Weighted average common shares outstanding			696				696				695				695
Effect of dilutive securities:
Options and restricted stock			—				6				—				—
Convertible preferred stock			—				58				—				—
Trust preferred securities			—				8				—				—
Weighted average common shares outstanding and dilutive securities			696				768				695				695
Basic and diluted earnings (loss) per common share:
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	0.54			$	0.51			$	(1.41	)		$	(1.41	)

     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. Potentially dilutive securities consist of employee stock options, restricted stock, convertible preferred stock and trust preferred securities. For the quarter ended March 31, 2010, certain of our employee stock options were antidilutive. For the quarter ended March 31, 2009, we incurred losses attributable to El Paso Corporation and, accordingly, excluded all of our potentially dilutive securities from the determination of diluted earnings per share.

6. Fair Value of Financial Instruments

     On January 1, 2009, we adopted accounting standard updates regarding how companies should consider their own credit in determining the fair value of their liabilities that have third party credit enhancements related to them and recorded a $34 million gain (net of $18 million of taxes), or $0.05 per share, in 2009 as a result of adopting these new accounting updates.

     We use various methods to determine the fair values of our financial instruments and other derivatives that are measured at fair value on a recurring basis. The fair value of an instrument depends on a number of factors, including the availability of observable market data over the contractual term of the underlying instrument. For some of our instruments, the fair value is calculated based on directly observable market data or data available for similar instruments in similar markets. For other instruments, the fair value may be calculated based on these inputs as well as other assumptions related to estimates of future settlements of the instrument. We separate our financial instruments and other derivatives 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 of an instrument can change over time based on the maturity or liquidity of the instrument, which could result in a change in the classification of the instruments between levels.

Each of these levels is described below:

	•		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.

     During the quarter ended March 31, 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 March 31, 2010 and December 31, 2009:

		March 31, 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		$	—			$	358			$	—			$	358			$	—			$	169			$	—			$	169
Other natural gas derivatives			—				82				21				103				—				106				21				127
Power-related derivatives			—				—				21				21				—				—				37				37
Interest rate derivatives			—				11				—				11				—				11				—				11
Marketable securities invested in non-qualified compensation plans			20				—				—				20				20				—				—				20
Total assets			20				451				42				513				20				286				58				364
Liabilities
Commodity-based derivatives
Production-related natural gas and oil derivatives			—				(25	)			—				(25	)			—				(42	)			—				(42	)
Other natural gas derivatives			—				(124	)			(118	)			(242	)			—				(153	)			(133	)			(286	)
Power-related derivatives			—				—				(341	)			(341	)			—				—				(386	)			(386	)
Interest rate derivatives			—				(16	)			—				(16	)			—				(17	)			—				(17	)
Other			—				—				(31	)			(31	)			—				—				(31	)			(31	)
Total liabilities			—				(165	)			(490	)			(655	)			—				(212	)			(550	)			(762	)
Total		$	20			$	286			$	(448	)		$	(142	)		$	20			$	74			$	(492	)		$	(398	)

     The following table presents the changes in our financial assets and liabilities included in Level 3 for the quarter ended March 31, 2010:

						Change in Fair				Change in Fair
		Balance at				Value Reflected in				Value Reflected in
		Beginning of				Operating				Operating				Settlements,				Balance at End of
		Period				Revenues(1)				Expenses(2)				Net				Period
										(In millions)
Assets		$	58			$	(15	)		$	—			$	(1	)		$	42
Liabilities			(550	)			33				(4	)			31				(490	)
Total		$	(492	)		$	18			$	(4	)		$	30			$	(448	)

     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 eight financial institutions, each of which has a current Standard & Poor’s credit rating of A or better.

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

		March 31, 2010								December 31, 2009
		Carrying				Fair				Carrying				Fair
		Amount				Value				Amount				Value
						(In millions)
Long-term financing obligations, including current maturities		$	14,038			$	14,481			$	13,868			$	14,151
Marketable securities invested in non-qualified compensation plans			20				20				20				20
Commodity-based derivatives			(126	)			(126	)			(381	)			(381	)
Interest rate derivatives			(5	)			(5	)			(6	)			(6	)
Other derivatives			(31	)			(31	)			(31	)			(31	)
Other			17				17				17				17

     As of March 31, 2010 and December 31, 2009, the carrying amounts of cash and cash equivalents, short-term borrowings, and trade receivables and payables represented 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 debt based on quoted market prices for the same or similar issues, including consideration of our credit risk related to those instruments.

7. Price Risk Management Activities

     Our price risk management activities relate primarily to derivatives entered into to hedge or otherwise reduce (i) the commodity price exposure on our natural gas and oil production and (ii) interest rate exposure on our long-term debt. We also hold other derivatives not intended to hedge these exposures. When we enter into derivative contracts, we may designate the derivative as either a cash flow hedge or a fair value hedge. Hedges of cash flow exposure are designed to hedge forecasted sales transactions or limit the variability of cash flows to be received or paid related to a recognized asset or liability. Hedges of fair value exposure are entered into to protect the fair value of a recognized asset, liability or firm commitment.

     Financial Statement Presentation. For a detailed description on how our derivatives are reflected and accounted for on our balance sheet and statements of income, comprehensive income and cash flow, see our 2009 Annual Report on Form 10-K. The following table presents the fair value of our derivatives on a gross basis by contract type. We have not netted these contracts for counterparties where we have a legal right of offset or for cash collateral associated with these derivatives. At March 31, 2010 and December 31, 2009, cash collateral held was not material.

		Fair Value of Derivative Assets								Fair Value of Derivative Liabilities
		March 31, 2010				December 31, 2009				March 31, 2010				December 31, 2009
						(In millions)
Derivatives Designated as Hedges:
Interest rate derivatives
Cash flow hedges		$	1			$	1			$	(16	)		$	(17	)
Fair value hedges			10				10				—				—
Total derivatives designated as hedges			11				11				(16	)			(17	)
Derivatives not Designated as Hedges:
Commodity-based derivatives
Production-related			421				239				(88	)			(112	)
Other natural gas			358				519				(497	)			(678	)
Power-related			30				57				(350	)			(406	)
Total commodity-based derivatives			809				815				(935	)			(1,196	)
Interest rate derivatives			13				10				(13	)			(10	)
Total derivatives not designated as hedges			822				825				(948	)			(1,206	)
Impact of master netting arrangements (1)			(340	)			(492	)			340				492
Total assets (liabilities) from price risk management activities			493				344				(624	)			(731	)
Other derivatives			—				—				(31	)			(31	)
Total derivatives		$	493			$	344			$	(655	)		$	(762	)

Commodity-Based Derivatives

     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 March 31, 2010 and December 31, 2009, we have production-related derivatives on 261 TBtu and 313 TBtu of natural gas and 5,556 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 March 31, 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 in previous years to economically mitigate our exposure to commodity price changes on substantially all of these volumes, although we continue to have exposure to changes in locational price differences between the PJM regions.

     Listed below are the impacts of our commodity-based derivatives to our income statement and statement of comprehensive income for the quarters ended March 31:

		2010								2009
						Other								Other
		Operating				Comprehensive				Operating				Comprehensive
		Revenues				Income				Revenues				(Loss)
						(In millions)
Production-related derivatives(1)		$	253			$	3			$	394			$	(128	)
Other natural gas and power derivatives not designated as hedges			17				—				55				—
Total commodity-based derivatives(2)		$	270			$	3			$	449			$	(128	)

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, 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 $166 million of debt from a LIBOR-based variable rate to a fixed rate of 4.56%.

     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 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. As of March 31, 2010 and December 31, 2009, our hedges converted the interest rate on approximately $218 million of debt from a fixed rate to a variable rate of LIBOR plus 4.18% and we also had interest rate swaps not designated as hedges with a notional amount of $222 million for which changes in the fair value of these swaps were substantially eliminated by offsetting swaps contracts.

     Our interest rate derivatives did not have a significant impact to our interest expense or other comprehensive income (loss) during the first quarter of 2010 or 2009, and we did not record any ineffectiveness on these derivatives during these periods. We do not anticipate that the accumulated other comprehensive loss associated with these derivatives to be reclassified to interest expense during the next twelve months will be significant to our financial statements.

Cross-Currency Derivatives

     During the second quarter of 2009, our Euro-denominated debt matured and we settled all of our related cross-currency swaps. These cross-currency swaps were designated as fair value hedges of this debt, and for the quarter ended March 31, 2009, these swaps increased our interest expense by approximately $2 million and decreased our other income by approximately $24 million as a result of changing interest and foreign currency rates during the first quarter of 2009.

8. Debt, Other Financing Obligations and Other Credit Facilities

		March 31,				December 31,
		2010				2009
		(In millions)
Short-term financing obligations, including current maturities		$	622			$	477
Long-term financing obligations			13,416				13,391
Total		$	14,038			$	13,868

     Changes in Financing Obligations. During the quarter ended March 31, 2010, we had the following changes in our financing obligations:

										Cash
						Book Value				Received
Company		Interest Rate				Increase (Decrease)				(Paid)
						(In millions)
Issuances
Elba Express Company L.L.C. credit facility		variable				$	19			$	19
Ruby Holding Company loan commitment		7.000%					144				143
El Paso Pipeline Partners L.P. notes due 2020		6.500%					425				420
El Paso revolving credit facility		variable					193				193
Increases through March 31, 2010						$	781			$	775
Repayments, repurchases, and other
El Paso Exploration and Production Company revolving credit facility		variable				$	(419	)		$	(419	)
El Paso revolving credit facility		variable					(193	)			(193	)
Other		various					1				(5	)
Decreases through March 31, 2010						$	(611	)		$	(617	)

     Credit Facilities. We have various credit facilities in place which allow us to borrow funds or issue letters of credit as noted in the table above or further discussed below. As of March 31, 2010, we had total available capacity under these facilities (not including capacity available under the El Paso Pipeline Partners, L.P. (EPB) $750 million revolving credit facility and all project financings) of approximately $1.9 billion.

     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. These restrictions include potential limitations in the credit agreements of certain of our subsidiaries on their ability to declare and pay dividends and loan funds to us. Additionally, the revolving credit facility of our exploration and production subsidiary is collateralized by certain of our natural gas and oil properties and has a borrowing base subject to revaluation on a semi-annual basis. There have been no significant changes to our restrictive covenants from those disclosed in our 2009 Annual Report on Form 10-K, and as of March 31, 2010, we were in compliance with all of our debt covenants.

     Letters of Credit. We enter into letters of credit in the ordinary course of our operating activities as well as periodically in conjunction with the sales of assets or businesses. As of March 31, 2010, we increased the total letter of credit capacity under certain existing letter of credit facilities to $350 million with a weighted average fixed facility fee of 6.50% and maturities ranging from December 2013 to September 2014. As of March 31, 2010, we had total outstanding letters of credit issued under all of our facilities of approximately $1.1 billion. Included in this amount is approximately $0.6 billion of letters of credit securing our recorded obligations related to price risk management activities.

     Ruby Pipeline Financing. In May 2010, we closed on a 7-year amortizing $1.5 billion financing facility for our Ruby pipeline project that matures in June 2017. We have various conditions precedent to funding. Our initial interest rate on amounts borrowed will be 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 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. We entered into hedges that hedge at least 75 percent of the floating LIBOR interest rate exposure on this facility beginning in June 2011 and extending through the maturity of the facility. We have 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.

9. 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. The trial court has dismissed the claims that our plan violated ERISA. Our costs and legal exposure related to this lawsuit are not currently determinable.

     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 filed 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 were obligated to pay the amounts above the cap, but intend to pursue appellate options following the determination by the trial court of any damages incurred by the plaintiffs during the period when premium payments above the cap were paid by the retirees. 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 agreed to, settled, and paid, several of the cases are in various stages of appellate proceedings as further described in our 2009 Annual report on Form 10-K. In this regard, in April 2010, the Tennessee Supreme Court dismissed the lawsuit entitled Leggett, et al. v. Duke Energy Corporation, et al. Our costs and legal exposure related to the remaining lawsuits and claims which have not yet been settled and paid are not currently determinable.

     Gas Measurement Class Action. In 1999, a purported class action lawsuit entitled Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., was filed in the District Court of Stevens County, Kansas against a number of our subsidiaries. The complaint alleges that the defendants inaccurately measured the volume and heating content of gas that resulted in the underpayment of royalties to royalty owners on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. The court has denied motions for class certification, and the deadline for an appeal of this order has now passed. Our costs and legal exposure related to this lawsuit and claim 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, including remedial activities, damages, attorneys’ fees and costs. These cases were initially consolidated for pre-trial purposes in multi-district litigation in the U.S. District Court for the Southern District of New York. Several cases were later remanded to state court. One case has been dismissed. We settled 60 cases in 2008 and 2009 which were covered by insurance. We have reached an agreement in principle to settle another 26 cases, which will be substantially funded by insurance. Following dismissal of these settled cases, we will have seven lawsuits that remain. It is likely that our insurers will assert denial of coverage on the four most-recently filed cases. 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. There are also other regulatory rules and orders in various stages of adoption, review and/or implementation. 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, 2010, we had approximately $48 million accrued, which has not been reduced by $2 million of related insurance receivables, for our outstanding legal and governmental proceedings.

Rates and Regulatory Matters

     SNG Rate Case. In January 2010, the Federal Energy Regulatory Commission (FERC) approved Southern Natural Gas Company’s (SNG’s) settlement in which SNG (i) increased its base tariff rates, (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. In June 2008, El Paso Natural Gas Company (EPNG) filed a rate case with the FERC proposing an increase in EPNG’s base tariff rates. In August 2008, the FERC issued an order accepting the proposed rates effective January 1, 2009, subject to refund. In March 2010, EPNG filed an uncontested partial offer of settlement which was approved in April 2010. The settlement provides for an increase in EPNG’s base tariff rates over rates existing prior to January 1, 2009. Under the terms of the settlement, EPNG agreed to file its next general rate case to be effective as early as April 1, 2011, but not later than April 1, 2012. As part of the settlement, EPNG made an initial refund to its customers in April 2010, with the remaining refunds to be paid during the remainder of 2010. The refunds to be paid are fully reserved. The settlement resolves all but four issues in the proceeding. A hearing on the remaining issues is scheduled for May 2010 and the outcome is not currently determinable.

Environmental Matters

     We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect of the disposal or release of specified substances at current and former operating sites. At March 31, 2010, we had accrued approximately $182 million for environmental matters, which has not been reduced by $23 million for amounts to be paid directly under government sponsored programs or through contractual arrangements with third parties. Our accrual includes approximately $178 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $4 million for related environmental legal costs. Of the $182 million accrual, $13 million was reserved for facilities we currently operate and $169 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 $182 million to approximately $393 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, 2010
Sites		Expected				High
		(In millions)
Operating		$	13			$	19
Non-operating			153				333
Superfund			16				41
Total		$	182			$	393

     Below is a reconciliation of our accrued liability from January 1, 2010 to March 31, 2010 (in millions):

Balance as of January 1, 2010		$	189
Additions/adjustments for remediation activities			2
Payments for remediation activities			(9	)
Balance as of March 31, 2010		$	182

     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 the remainder of 2010, we estimate that our total remediation expenditures will be approximately $39 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 $5 million in the aggregate for the remainder of 2010 through 2014.

     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 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 arrangements 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 legacy assets. These amounts exclude guarantees for which we have issued related letters of credit discussed in Note 8. 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. 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, 2010, we have recorded obligations of $52 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 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 on our balance sheet and are expected to be paid over a three year period with interest. As of March 31, 2010, TGP has refunded approximately $30 million to their customers.

10. Retirement Benefits

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

										Other
		Pension								Postretirement
		Benefits								Benefits
		2010				2009				2010				2009
						(In millions)
Service cost		$	5			$	4			$	—			$	—
Interest cost			28				30				8				9
Expected return on plan assets			(39	)			(43	)			(3	)			(3	)
Amortization of net actuarial loss (gain)			19				11				(1	)			—
Net benefit cost		$	13			$	2			$	4			$	6

11. Equity and Preferred Stock of Subsidiary

     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, 2010		$	7			$	9
Amount paid in April 2010		$	7			$	9
Declared in April 2010:
Date of declaration		April 1, 2010				April 1, 2010
Payable to shareholders on record		June 4, 2010				June 15, 2010
Date payable		July 1, 2010				July 1, 2010

     Dividends on our common stock and preferred stock are treated as a reduction of additional paid-in-capital since we currently have an accumulated deficit. For the remainder of 2010, we expect dividends paid on our common 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 2009 Annual Report on Form 10-K.

     Noncontrolling Interests. In March 2010, we contributed a 51 percent interest in both Southern LNG, L.L.C. (SLNG), which owns the Elba Island LNG receiving terminal, and El Paso Elba Express Company, L.L.C. (Elba Express), which owns the Elba Express Pipeline, to EPB in exchange for $810 million which included cash and 5.3 million EPB common units. EPB raised the funds for the acquisition through the issuance of 9.9 million common units and the proceeds from a March 2010 debt offering. As of March 31, 2010, our ownership interest in EPB is 64 percent, including our 2 percent general partner interest. EPB makes quarterly distributions of available cash to its unitholders in accordance with its partnership agreement. During the quarters ended March 31, 2010 and 2009, EPB made cash distributions of $19 million and $10 million to its non-affiliated common unitholders. During the quarters ended March 31, 2010 and 2009, we have recorded $26 million and $12 million in net income attributable to noncontrolling interest holders on our income statement which represents the non-affiliated common unitholders share of EPB’s income.

     Preferred Stock of Subsidiary. During 2009, Global Infrastructure Partners (GIP), our partner on our Ruby pipeline project, contributed $145 million to our subsidiary, Ruby Pipeline Holding Company, L.L.C. (Ruby) and received a convertible preferred equity interest in Ruby that was simultaneously exchanged for a convertible preferred equity interest in Cheyenne Plains Gas Pipeline Company, L.L.C. (Cheyenne Plains). The preferred stock in Cheyenne Plains has been classified between liabilities and equity on our balance sheet since the events that require redemption of the preferred interest are not entirely within our control. The preferred dividend associated with GIP’s preferred interest of $5 million was paid during the first quarter of 2010 and is reflected in net income attributable to noncontrolling interests on our income statement. For a further discussion of the Ruby transaction, see Note 13.

12. Business Segment Information

     As of March 31, 2010, our business consists of two core segments, Pipelines and Exploration and Production, as well as our Marketing segment. 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. As of March 31, 2010, we conducted our activities primarily through seven wholly or majority owned interstate pipeline systems and equity interests in four 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 natural gas, oil and NGL, in the United States, Brazil and Egypt.

     Marketing. Our Marketing segment markets and manages the price risks associated with our natural gas and oil production as well as manages our remaining legacy trading portfolio.

     Corporate and Other. Our corporate and other activities include our general and administrative functions as well as a number of miscellaneous businesses.

     Our management uses earnings before interest expense and income taxes (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. We believe EBIT is useful to our investors because it allows them to evaluate more effectively the operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income (loss) adjusted for items such as (i) interest and debt expense, (ii) income taxes, and (iii) net income attributable to noncontrolling interests so that our investors may evaluate our operating results without regard to our financing methods or capital structure. EBIT may not be comparable to measures used by other companies. Additionally, 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. Below is a reconciliation of our EBIT to our net income (loss) for the periods ended March 31:

		2010				2009
		(In millions)
Segment EBIT		$	828			$	(1,237	)
Corporate and Other			(11	)			(3	)
Consolidated EBIT			817				(1,240	)
Interest and debt expense			(243	)			(255	)
Income tax benefit (expense)			(186	)			526
Net income (loss) attributable to El Paso Corporation			388				(969	)
Net income attributable to noncontrolling interests			31				12
Net income (loss)		$	419			$	(957	)

     The following table reflects our segment results for the quarters ended March 31 (in millions):

		Segments
						Exploration								Corporate
		Pipelines				and Production				Marketing				and Other(1)				Total
										(In millions)
2010
Revenue from external customers		$	724			$	427	(2)		$	249			$	1			$	1,401
Intersegment revenue			13				220	(2)			(230	)			(3	)			—
Operation and maintenance			184				97				2				16				299
Ceiling test charges			—				2				—				—				2
Depreciation, depletion and amortization			106				107				—				5				218
Earnings from unconsolidated affiliates			22				—				—				6				28
EBIT			421				390				17				(11	)			817
2009
Revenue from external customers		$	721			$	574	(2)		$	188			$	1			$	1,484
Intersegment revenue			12				126	(2)			(135	)			(3	)			—
Operation and maintenance			183				109				1				7				300
Ceiling test charges			—				2,068				—				—				2,068
Depreciation, depletion and amortization			104				150				—				2				256
Earnings (losses) from unconsolidated affiliates			21				(9	)			—				7				19
EBIT			396				(1,685	)			52				(3	)			(1,240	)

     Total assets by segment are presented below:

		March 31,				December 31,
		2010				2009
		(In millions)
Pipelines		$	17,748			$	17,324
Exploration and Production			4,232				4,025
Marketing			298				345
Total segment assets			22,278				21,694
Corporate and Other			913				811
Total consolidated assets		$	23,191			$	22,505

13. Variable Interest Entities and Accounts Receivable Sales Programs

     Ruby. We consolidate our investment in Ruby Pipeline Holding Company, L.L.C. (Ruby) as its primary beneficiary. In July 2009, we entered into an agreement with GIP whereby they agreed to invest up to $700 million and acquire a 50 percent equity interest in Ruby subject to certain conditions. As part of this agreement, GIP: (i) has entered into a loan commitment to provide $405 million of project funding to Ruby, $360 million of which has been borrowed as of March 31, 2010, (ii) has contributed $145 million in exchange 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 (iii) will provide an additional $150 million of preferred equity contributions to Ruby after obtaining all FERC approvals as well as securing approximately $1.4 billion of third party financing. In April 2010, we received certification from the FERC authorizing the project. In May 2010, we closed $1.5 billion of third party project financing; however, the drawing on this financing is contingent on certain conditions. Cheyenne Plains is also a variable interest entity we consolidate as its primary beneficiary. GIP will hold their 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 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 closing 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 August 2011 and/or completing financing, GIP has the option to convert its Cheyenne Plains preferred interest to a common interest and/or be repaid in cash for its remaining investment. 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 a further discussion of our Ruby transaction, refer to our 2009 Annual Report on Form 10-K.

     We also hold interests in other variable interest entities that we account for as investments in unconsolidated affiliates. These entities do not have significant operations and accordingly do not have a material impact to our financial statements.

     Accounts Receivable Sales Programs. During 2009, several of our pipeline subsidiaries had agreements to sell senior interests in certain of their 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 ended March 31, 2009, we received $252 million of cash related to the sale of the senior interests, collected $272 million from the subordinated interests we retained in the receivables, and recognized a loss of less than $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 in 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 in our statement of cash flows.

     In 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 March 31, 2010, the third-party financial institution held $217 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 first quarter of 2010, we received $455 million of cash up front from the sale of the receivables and received an additional $237 million of cash upon the collection of the underlying receivables. As of March 31, 2010, we had not collected approximately $96 million related to our accounts receivable sales, which is reflected as other accounts receivable in 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 less than $1 million on our accounts receivable sales during the first quarter of 2010. Because the cash received up front and the cash received as the underlying receivables are collected both are related to the sale or ultimate collection of the underlying receivables, and 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 in 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 quarters ended March 31, 2010 and 2009.

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

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

     We hold investments in unconsolidated affiliates which are accounted for using the equity method of accounting. The earnings from unconsolidated affiliates reflected in our income statement include (i) our share of net earnings directly attributable to these unconsolidated affiliates, and (ii) impairments and other adjustments recorded by us. The 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.

										Earnings (Losses) from
		Investment								Unconsolidated Affiliates
		March 31,				December 31,				Quarter Ended March 31,
		2010				2009				2010				2009
		(In millions)								(In millions)
Net Investment and Earnings (Losses)
Four Star (1)		$	437			$	450			$	—			$	(10	)
Citrus			644				630				15				14
Gulf LNG(2)			279				285				—				—
Gasoductos de Chihuahua(3)			190				184				6				6
Bolivia-to-Brazil Pipeline			109				105				5				4
Other			66				64				2				5
Total		$	1,725			$	1,718			$	28			$	19

		Quarter Ended
		March 31,
		2010				2009
		(In millions)
Summarized Financial Information
Operating results data:
Operating revenues		$	132			$	123
Operating expenses			73				68
Income from continuing operations and net income			38				35