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. (Check one):

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 August 5, 2009: 701,196,377

 

 

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			27
Item 3. Quantitative and Qualitative Disclosures About Market Risk			49
Item 4. Controls and Procedures			50
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			51
Item 1A. Risk Factors			52
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			52
Item 3. Defaults Upon Senior Securities			52
Item 4. Submission of Matters to a Vote of Security Holders			53
Item 5. Other Information			54
Item 6. Exhibits			54
Signatures			55
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
Bcf		= billion cubic feet		GWh		= thousand megawatt hours
LNG		= liquefied natural gas		GW		= gigawatts
MBbls		= thousand barrels		NGL		= natural gas liquids
Mcf		= thousand cubic feet		TBtu		= trillion British thermal units
Mcfe		= thousand cubic feet of natural gas equivalents		tonne		= metric ton

     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)

		Quarters Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Operating revenues		$	973			$	1,153			$	2,457			$	2,422
Operating expenses
Cost of products and services			52				71				113				127
Operation and maintenance			264				275				564				546
Ceiling test charges			12				7				2,080				7
Depreciation, depletion and amortization			197				298				453				611
Taxes, other than income taxes			57				81				125				160
			582				732				3,335				1,451
Operating income (loss)			391				421				(878	)			971
Earnings from unconsolidated affiliates			12				52				31				89
Other income, net			16				33				38				55
Interest and debt expense			(253	)			(221	)			(508	)			(454	)
Income (loss) before income taxes			166				285				(1,317	)			661
Income tax expense (benefit)			66				87				(460	)			235
Net income (loss)			100				198				(857	)			426
Net income attributable to noncontrolling interests			(11	)			(7	)			(23	)			(16	)
Net income (loss) attributable to El Paso Corporation			89				191				(880	)			410
Preferred stock dividends			10				—				19				19
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	79			$	191			$	(899	)		$	391
Basic earnings per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	0.11			$	0.27			$	(1.29	)		$	0.56
Diluted earnings per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	0.11			$	0.25			$	(1.29	)		$	0.54
Dividends declared per El Paso Corporation’s common share		$	0.05			$	—			$	0.10			$	0.08

See accompanying notes.

EL PASO CORPORATION

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

		June 30,				December 31,
		2009				2008
ASSETS
Current assets
Cash and cash equivalents		$	970			$	1,024
Accounts and notes receivable
Customers, net of allowance of $11 in 2009 and $9 in 2008			342				466
Affiliates			131				133
Other			127				217
Materials and supplies			190				187
Assets from price risk management activities			459				876
Deferred income taxes			114				—
Other			138				148
Total current assets			2,471				3,051
Property, plant and equipment, at cost
Pipelines			18,749				18,042
Natural gas and oil properties, at full cost			20,341				20,009
Other			363				342
			39,453				38,393
Less accumulated depreciation, depletion and amortization			22,844				20,535
Total property, plant and equipment, net			16,609				17,858
Other assets
Investments in unconsolidated affiliates			1,724				1,703
Assets from price risk management activities			176				201
Other			663				855
			2,563				2,759
Total assets		$	21,643			$	23,668

See accompanying notes.

EL PASO CORPORATION

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

		June 30,				December 31,
		2009				2008
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade		$	304			$	372
Affiliates			7				6
Other			495				674
Short-term financing obligations, including current maturities			169				1,090
Liabilities from price risk management activities			185				250
Accrued interest			204				192
Other			698				659
Total current liabilities			2,062				3,243
Long-term financing obligations, less current maturities			13,477				12,818
Other
Liabilities from price risk management activities			577				767
Deferred income taxes			182				565
Other			1,626				1,679
			2,385				3,011
Commitments and contingencies (Note 9)
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 715,683,940 shares in 2009 and 712,628,781 shares in 2008			2,147				2,138
Additional paid-in capital			4,537				4,612
Accumulated deficit			(3,533	)			(2,653	)
Accumulated other comprehensive loss			(650	)			(532	)
Treasury stock (at cost); 14,493,649 shares in 2009 and 14,061,474 shares in 2008			(281	)			(280	)
Total El Paso Corporation stockholders’ equity			2,970				4,035
Noncontrolling interests			749				561
Total equity			3,719				4,596
Total liabilities and equity		$	21,643			$	23,668

See accompanying notes.

EL PASO CORPORATION

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

		Six Months Ended
		June 30,
		2009				2008
Cash flows from operating activities
Net income (loss)		$	(857	)		$	426
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization			453				611
Ceiling test charges			2,080				7
Deferred income tax expense (benefit)			(470	)			236
Earnings from unconsolidated affiliates, adjusted for cash distributions			4				(8	)
Other non-cash income items			26				13
Asset and liability changes			(63	)			33
Net cash provided by operating activities			1,173				1,318
Cash flows from investing activities
Capital expenditures			(1,363	)			(1,175	)
Cash paid for acquisitions, net of cash acquired			—				(336	)
Net proceeds from the sale of assets and investments			300				659
Other			(3	)			43
Net cash used in investing activities			(1,066	)			(809	)
Cash flows from financing activities
Net proceeds from issuance of long-term debt			983				2,670
Payments to retire long-term debt and other financing obligations			(1,214	)			(3,071	)
Dividends paid			(89	)			(75	)
Net proceeds from issuance of noncontrolling interests			184				—
Distributions to noncontrolling interest holders			(19	)			(12	)
Other			(6	)			(32	)
Net cash used in financing activities			(161	)			(520	)
Change in cash and cash equivalents			(54	)			(11	)
Cash and cash equivalents
Beginning of period			1,024				285
End of period		$	970			$	274

See accompanying notes.

EL PASO CORPORATION

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

		Six Months Ended
		June 30,
		2009				2008
El Paso Corporation stockholders’ equity:
Preferred stock:
Balance at beginning and end of period		$	750			$	750
Common stock:
Balance at beginning of period			2,138				2,128
Other, net			9				8
Balance at end of period			2,147				2,136
Additional paid-in capital:
Balance at beginning of period			4,612				4,699
Dividends			(89	)			(75	)
Other, including stock-based compensation			14				55
Balance at end of period			4,537				4,679
Accumulated deficit:
Balance at beginning of period			(2,653	)			(1,834	)
Net income (loss) attributable to El Paso Corporation			(880	)			410
Cumulative effect of adopting SFAS No. 158, net of income tax of $2			—				4
Balance at end of period			(3,533	)			(1,420	)
Accumulated other comprehensive loss:
Balance at beginning of period			(532	)			(272	)
Other comprehensive loss			(118	)			(348	)
Cumulative effect of adopting SFAS No. 158, net of income tax of $2			—				3
Balance at end of period			(650	)			(617	)
Treasury stock, at cost:
Balance at beginning of period			(280	)			(191	)
Stock-based and other compensation			(1	)			(13	)
Balance at end of period			(281	)			(204	)
Total El Paso Corporation stockholders’ equity at end of period			2,970				5,324
Noncontrolling interests:
Balance at beginning of period			561				565
Distributions paid to noncontrolling interests			(19	)			(12	)
Issuance of noncontrolling interests			184				—
Net income attributable to noncontrolling interests			23				16
Other			—				(24	)
Balance at end of period			749				545
Total equity at end of period		$	3,719			$	5,869

See accompanying notes.

EL PASO CORPORATION

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

		Quarters Ended								Six Months Ended
		June 30,								June 30,
		2009				2008				2009				2008
Net income (loss)		$	100			$	198			$	(857	)		$	426
Pension and postretirement obligations:
Unrealized actuarial losses arising during period (net of income taxes of $1 in 2008)			—				—				—				(2	)
Reclassification of actuarial gains and losses during period (net of income taxes of $4 and $8 in 2009 and $3 and $5 in 2008)			7				5				14				10
Cash flow hedging activities:
Unrealized mark-to-market gains (losses) arising during period (net of income taxes of $7 and $8 in 2009 and $152 and $222 in 2008)			8				(272	)			10				(395	)
Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $34 and $80 in 2009 and $21 and $22 in 2008)			(60	)			37				(142	)			39
Other comprehensive loss			(45	)			(230	)			(118	)			(348	)
Comprehensive income (loss)			55				(32	)			(975	)			78
Comprehensive income attributable to noncontrolling interests			(11	)			(7	)			(23	)			(16	)
Comprehensive income (loss) attributable to El Paso Corporation		$	44			$	(39	)		$	(998	)		$	62

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 Quarterly Report on Form 10-Q along with our 2008 Annual Report on Form 10-K, which contains a summary of our significant accounting policies and other disclosures. The financial statements as of June 30, 2009, and for the quarters and six months ended June 30, 2009 and 2008, are unaudited. We derived the condensed consolidated balance sheet as of December 31, 2008, from the audited balance sheet filed in our 2008 Annual Report on Form 10-K. As discussed below, certain amounts related to noncontrolling interests have been retrospectively adjusted within these consolidated financial statements to reflect the adoption of Statement of Financial Accounting Standards (SFAS) No. 160, Noncontrolling Interests in Consolidated Financial Statements. Our financial statements for prior periods also include certain reclassifications that were made to conform to the current period presentation. There were no reclassifications that impacted our reported net income (loss) or stockholders’ equity other than those required by SFAS No. 160. In our opinion, we have made adjustments, all of which are of a normal, recurring nature to fairly present our interim period results. We have evaluated subsequent events through the time of filing on August 7, 2009, the date of issuance of our 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.

Significant Accounting Policies

     The information below provides an update of our significant accounting policies and accounting pronouncements issued but not yet adopted as discussed in our 2008 Annual Report on Form 10-K.

     Fair Value Measurements. On January 1, 2009, we adopted the provisions of SFAS No. 157, Fair Value Measurements, for our non-financial assets and liabilities that are measured at fair value on a non-recurring basis, as further described in Note 6. The adoption did not have a material impact on our financial statements.

     On January 1, 2009, we adopted the provisions of the Emerging Issues Task Force (EITF) Issue No. 08-5, Issuer’s Accounting for Liabilities Measured at Fair Value with a Third-Party Credit Enhancement. EITF Issue No. 08-5 provides guidance to companies about how they should consider their own credit in determining the fair value of their liabilities that have third party credit enhancements related to them. Substantially all of our derivative liabilities in our Marketing segment are supported by letters of credit. This standard requires that non-cash credit enhancements, such as letters of credit, should not be considered in determining the fair value of these liabilities, including derivative liabilities. Accordingly, we recorded a $34 million gain (net of $18 million of taxes), or $0.05 per share, in the first quarter of 2009 as a result of adopting EITF Issue No. 08-5.

     Business Combinations. On January 1, 2009, we adopted SFAS No. 141(R), Business Combinations, which provides revised guidance on the accounting for acquisitions of businesses. This standard changes the current guidance to require that all acquired assets, liabilities, noncontrolling interests and certain contingencies be measured at fair value, and certain other acquisition-related costs be expensed rather than capitalized. SFAS No. 141(R) applies to acquisitions that are effective after December 31, 2008.

     Noncontrolling Interests. Effective January 1, 2009, we adopted the provisions of SFAS No. 160, which provides guidance on accounting and reporting for noncontrolling interests in the financial statements. This standard requires us to present our noncontrolling interests, which primarily relate to El Paso Pipeline Partners, L.P., our consolidated subsidiary, as a separate component of equity rather than as a “mezzanine” item between liabilities and equity in our balance sheets, and also requires us to present our noncontrolling interests as a separate caption in our income statements. Our financial statements for all periods presented have been adjusted to retrospectively apply the provisions of this statement. This standard also requires that all transactions with noncontrolling interest holders after adoption, including the issuance and repurchase of noncontrolling interests, be accounted for as equity transactions unless a change in control of the subsidiary occurs.

New Accounting Pronouncements Issued But Not Yet Adopted

     As of June 30, 2009, the following accounting standards have not yet been adopted by us:

     Oil and Gas Reserves Reporting. In December 2008, the SEC issued a final rule adopting revisions to its oil and gas reporting requirements. The revisions will impact the determination and disclosures of oil and gas reserves information. Among other items, the new rules will revise the definition of proved reserves and will require full cost companies to use a twelve month average commodity price in determining future net revenues, rather than a period-end price as is currently required. These changes, along with other proposed changes, will impact the manner in which we perform our full cost ceiling test calculation and determine any related ceiling test charge. The provisions of this final rule are effective on December 31, 2009, and cannot be applied earlier than that date. We are currently assessing the impact that this final rule may have on our determination and disclosures of oil and gas reserves information.

     Transfers of Financial Assets. In June 2009, the Financial Accounting Standards Board (FASB) issued SFAS No. 166, Accounting for Transfers of Financial Assets, which amends SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities — a replacement of FASB Statement No. 125. Among other items, this standard eliminates the concept of a qualifying special-purpose entity (QSPE) for purposes of evaluating whether an entity should be consolidated as a variable interest entity. SFAS No. 166 is effective for existing QSPEs as of January 1, 2010 and for transactions entered into on or after January 1, 2010. We are currently assessing the impact that this standard may have on our financial statements, including any impacts it may have on accounting for our accounts receivable sales program and the related senior beneficial interests (see Note 13).

     Variable Interest Entities. In June 2009, the FASB issued SFAS No. 167, Amendments to FASB Interpretation No. 46(R), which revises how companies determine who the primary beneficiaries of their variable interest entities are. This standard requires companies to use a qualitative approach based on their responsibilities and controlling power over the variable interest entities’ operations rather than a quantitative approach as previously required. SFAS No. 167 will be effective beginning January 1, 2010, and will require us to reevaluate the primary beneficiaries of our variable interest entities. We are currently assessing the impact that this standard may have on our financial statements.

2. Acquisitions and Divestitures

Acquisitions

     Gulf LNG. In February 2008, we paid $295 million to complete the acquisition of a 50 percent interest in the Gulf LNG Clean Energy Project, an LNG terminal which is currently under construction in Pascagoula, Mississippi. The terminal is expected to be placed in service in late 2011 at an estimated total cost of $1.1 billion. In addition, we have a commitment to loan Gulf LNG up to $150 million of which we have advanced approximately $42 million as of June 30, 2009. Our partner in this project has a commitment to loan up to $64 million. We account for our investment in Gulf LNG using the equity method.

     Exploration and Production properties. In June 2008, we acquired interests in onshore domestic natural gas and oil properties for approximately $43 million.

Divestitures

     During the first quarter of 2009, we completed the sale of our interest in the Porto Velho power generation facility in Brazil to our partner in the project for total consideration of $179 million, including $78 million in notes receivable (see Note 13). Subsequently, in the second quarter of 2009, we sold the notes, including accrued interest, to a third party financial institution for $57 million and recorded a loss of approximately $22 million. In addition, during 2009 we completed the sale of our investment in the Argentina-to-Chile pipeline to our partners in the project for approximately $32 million and completed the sale of non-core natural gas producing properties located in our Central and Western regions for approximately $95 million. During 2008, we sold natural gas and oil properties primarily in the Gulf Coast region for total proceeds of $637 million as well as two power investments located in Central America and Asia.

3. Ceiling Test Charges

     In the first quarter of 2009, we recorded a reduction to our property, plant and equipment due to non-cash ceiling test charges of $2.1 billion that resulted primarily from declines in natural gas prices. Capitalized costs exceeded the ceiling limit by approximately $2.0 billion for our domestic full cost pool, approximately $28 million for our Brazilian full cost pool and approximately $9 million for our Egyptian full cost pool. The calculation of these ceiling test charges was based on the March 31, 2009 spot natural gas price of $3.63 per MMBtu and oil price of $49.66 per barrel.

     As of June 30, 2009, spot natural gas prices improved to $3.89 per MMBtu and oil prices to $69.89 per barrel. As a result of these higher commodity prices and lower costs, we did not have a ceiling test charge in our domestic or Brazilian full cost pools during the second quarter of 2009. However, we recorded a $12 million charge during the second quarter of 2009 in our Egyptian full cost pool. Additionally, during the second quarter of 2008, we recorded a $7 million charge in our Egyptian full cost pool.

     In performing our ceiling test charge calculations, we are 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. Subsequent to June 30, 2009, commodity prices have declined, and as such, we may be required to record additional ceiling test charges in the future.

4. Income Taxes

     Income taxes included in our net income (loss) for the periods ended June 30 were as follows:

		Quarters Ended June 30,								Six Months Ended June 30,
		2009				2008				2009				2008
		(In millions, except rates)
Income tax (benefit) expense		$	66			$	87			$	(460	)		$	235
Effective tax rate			40	%			31	%			35	%			36	%

     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. Our effective tax rate may be affected by items such as 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 second quarter of 2009, our effective tax rate was primarily impacted by the sale and writedown of certain foreign investments for which there was no U.S. tax impact. For the six months ended June 30, 2009, our effective tax rate was relatively consistent with the statutory rate and the customary relationship between our pretax accounting income and income tax expense. During the second quarter of 2008, our effective tax rate was primarily impacted by the tax impact of the settlement of legacy litigation matters. For the six months ended June 30, 2008, this impact was largely offset by the tax impact of adjusting our postretirement benefit obligations, as discussed in Note 10.

     Deferred Tax Asset. As of June 30, 2009, we have a net federal deferred tax asset of $138 million primarily as a result of recognizing a deferred tax benefit attributable to the domestic ceiling test charge during the first quarter of 2009. We believe it is more likely than not that we will realize the benefit of this net deferred tax asset (net of existing valuation allowances) based on recognition of sufficient taxable income during periods in which those temporary differences or net operating losses are deductible.

5. Earnings Per Share

     We calculated basic and diluted earnings per common share as follows:

Quarters Ended June 30,

		2009								2008
		Basic				Diluted				Basic				Diluted
		(In millions, except per share amounts)
Net income attributable to El Paso Corporation		$	89			$	89			$	191			$	191
Convertible preferred stock dividends			(10	)			(10	)			—	(1)			—
Net income attributable to El Paso Corporation’s common stockholders		$	79			$	79			$	191			$	191
Weighted average common shares outstanding			696				696				698				698
Effect of dilutive securities:
Options and restricted stock			—				3				—				5
Convertible preferred stock			—				—				—				58
Weighted average common shares outstanding and dilutive securities			696				699				698				761
Basic and diluted earnings per common share:
Net income attributable to El Paso Corporation’s common stockholders		$	0.11			$	0.11			$	0.27			$	0.25

Six Months Ended June 30,

		2009								2008
		Basic				Diluted				Basic				Diluted
		(In millions, except per share amounts)
Net income (loss) attributable to El Paso Corporation		$	(880	)		$	(880	)		$	410			$	410
Convertible preferred stock dividends			(19	)			(19	)			(19	)(1)			—
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	(899	)		$	(899	)		$	391			$	410
Weighted average common shares outstanding			695				695				698				698
Effect of dilutive securities:
Options and restricted stock			—				—				—				4
Convertible preferred stock			—				—				—				58
Weighted average common shares outstanding and dilutive securities			695				695				698				760
Basic and diluted earnings per common share:
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	(1.29	)		$	(1.29	)		$	0.56			$	0.54

     We exclude potentially dilutive securities (as well as their related income statement impacts) from the determination of diluted earnings per share when their impact on net income attributable to El Paso Corporation per common share is antidilutive. These potentially dilutive securities consist of our employee stock options, restricted stock, convertible preferred stock and trust preferred securities. For the six months ended June 30, 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 as their impact on loss per common share was antidilutive. For the quarters ended June 30, 2009 and 2008, and six months ended June 30, 2008, certain of our employee stock options, restricted stock and trust preferred securities were antidilutive. Additionally, for the quarter ended June 30, 2009, our convertible preferred stock was antidilutive. For a further discussion of our potentially dilutive securities, see our 2008 Annual Report on Form 10-K.

6. Fair Value Measurements

     We apply the provisions of SFAS No. 157, Fair Value Measurements, to our assets and liabilities that are measured at fair value. We adopted the provisions of SFAS No. 157 on January 1, 2009 for our non-financial assets and liabilities that are measured at fair value on a non-recurring basis, which primarily relates to any impairment of long-lived assets or investments. During the six months ended June 30, 2009, we did not have any non-financial assets and liabilities that were recorded at fair value subsequent to their initial measurement.

     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, which depend 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 these instruments. 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 the fair value of our instruments. 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 and our corresponding instruments classified by level are further described below:

	•		Level 1 instruments’ fair values are based on quoted prices for the instruments in actively traded markets. Included in this level are our marketable securities invested in non-qualified compensation plans whose fair value is determined using the quoted prices of these instruments.
	•		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). Included in this level are our foreign currency and interest rate swaps. Also included in this level are our production-related natural gas and oil derivatives and certain of our other natural gas derivatives (such as natural gas supply arrangements) whose fair values are based on commodity pricing data obtained from third party pricing sources and our creditworthiness or that of our counterparties (adjusted for collateral related to our asset positions).
	•		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. For these instruments, we obtain pricing data from third party pricing sources, adjust this data based on the liquidity of the underlying forward markets over the contractual terms and use the adjusted pricing data to develop an estimate of forward price curves that market participants would use. The curves are then used to estimate the value of settlements in future periods based on contractual settlement quantities and dates. Our valuation of these instruments considers specific contractual terms, statistical and simulation analysis, present value concepts and other internal assumptions related to (i) contract maturities that extend beyond the periods in which quoted market prices are available; (ii) the uniqueness of the contract terms; (iii) the limited availability of forward pricing information in markets where there is a lack of viable participants, such as in the Pennsylvania-New Jersey-Maryland (PJM) forward power market and the forward market for ammonia; and (iv) our creditworthiness or that of our counterparties (adjusted for collateral related to our asset positions). Since a significant portion of the fair value of our power-related derivatives and certain of our remaining natural gas derivatives with longer terms or in less liquid markets than similar Level 2 derivatives rely on the techniques discussed above, we classify these instruments as Level 3 instruments.

     Listed below are the fair values of our financial instruments that are recorded at fair value classified in each level at June 30, 2009 (in millions):

		Level 1				Level 2				Level 3				Total
Assets
Commodity-based derivatives
Production-related natural gas and oil derivatives		$	—			$	499			$	—			$	499
Other natural gas derivatives			—				55				27				82
Power-related derivatives			—				—				46				46
Interest rate derivatives			—				8				—				8
Marketable securities invested in non-qualified compensation plans			19				—				—				19
Total assets			19				562				73				654
Liabilities
Commodity-based derivatives
Production-related natural gas and oil derivatives			—				(66	)			—				(66	)
Other natural gas derivatives			—				(127	)			(148	)			(275	)
Power-related derivatives			—				—				(405	)			(405	)
Interest rate derivatives			—				(16	)			—				(16	)
Other			—				—				(29	)			(29	)
Total liabilities			—				(209	)			(582	)			(791	)
Total		$	19			$	353			$	(509	)		$	(137	)

     On certain derivative contracts recorded as assets we are exposed to the risk that our counterparties may not be able to 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 the current instability in the credit markets. Based on this assessment, we have determined that our exposure is primarily related to our production-related derivatives and foreign currency swaps and is limited to five 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 and six months ended June 30, 2009 (in millions):

Quarter Ended June 30, 2009

						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
Assets		$	79			$	(4	)		$	—			$	(2	)		$	73
Liabilities			(659	)			26				26				25				(582	)
Total		$	(580	)		$	22			$	26			$	23			$	(509	)
Six Months Ended June 30,2009
Assets		$	103			$	(25	)		$	—			$	(5	)		$	73
Liabilities			(751	)			88				25				56				(582	)
Total		$	(648	)		$	63			$	25			$	51			$	(509	)

		June 30, 2009								December 31, 2008
		Carrying				Fair				Carrying				Fair
		Amount				Value				Amount				Value
						(In millions)
Long-term financing obligations, including current maturities		$	13,646			$	12,417			$	13,908			$	11,227
Marketable securities invested in non-qualified compensation plans			19				19				19				19
Commodity-based derivatives			(119	)			(119	)			(25	)			(25	)
Interest rate and foreign currency derivatives			(8	)			(8	)			85				85
Other			17				17				72				72

     As of June 30, 2009 and December 31, 2008, 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 their interest rates and our assessment of our 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 exposure on our natural gas and oil production; (ii) interest rate exposure on our long-term debt; and (iii) our historical foreign currency exposure on our Euro-denominated debt. We also hold other derivatives not intended to hedge these exposures, including those related to our legacy trading activities. When we enter into derivative contracts, we may designate the derivative as either a cash flow hedge or a fair value hedge, at which time we prepare the documentation required under SFAS No. 133. 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. A detailed discussion and analysis of our various price risk management activities follows below and in the related tables.

     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. Our production-related derivatives do not mitigate all of the commodity price risks of our sales of natural gas and oil production and, as a result, we are subject to commodity price risks on our remaining forecasted natural gas and oil production. Prior to removing the accounting hedge designation on all of our production-related derivatives during the fourth quarter of 2008, certain of these derivatives were designated as cash flow hedges. As of June 30, 2009 and December 31, 2008, we have production-related derivatives on 393 TBtu and 187 TBtu of natural gas and 902 MBbl and 3,431 MBbl of oil.

     Other Commodity-Based Derivatives. In our Marketing segment, we have long-term natural gas and power derivative contracts that are primarily related to our legacy trading activities, which include forwards, swaps and options that we either intend to manage until their expiration or seek opportunities to liquidate to the extent it is economical and prudent. None of these derivatives are designated as accounting hedges. As of June 30, 2009 and December 31, 2008, our other commodity based 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 PJM eastern region with the PJM west hub on approximately 3,700 GWh from 2009 to 2012, 2,400 GWh for 2013 and 1,700 GWh from 2014 to April 2016. Additionally, these contracts 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 both the natural gas and power contracts discussed above, 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.

     Interest Rate Derivatives. We have long-term debt with variable interest rates that exposes us to changes in market-based interest rates. We use interest rate swaps to convert the variable rates on certain of these debt instruments to a fixed interest rate. As of June 30, 2009 and December 31, 2008, we have interest rate swaps designated as cash flow hedges that converted the interest rate on approximately $175 million of debt from a LIBOR-based variable rate to a fixed rate of 4.56%.

     In addition, we 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 and have recorded changes in the fair value of these derivatives in interest expense. As of June 30, 2009 and December 31, 2008, we have interest rate swaps designated as fair value hedges that converted the interest rate on approximately $218 million of debt from a fixed rate to a variable rate of LIBOR plus 4.18%. In addition, as of June 30, 2009 and December 31, 2008, we 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 are substantially eliminated by offsetting swaps.

     Cross-Currency Derivatives. In May 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.

     Balance Sheet Presentation. Our derivatives are reflected on our balance sheet at their fair value as assets and liabilities from price risk management activities. 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. The following table presents the fair value of our derivatives on a gross basis by contract. The derivative asset and liability amounts presented below are summarized by contract type and have not been netted for counterparties where we have a legal right of offset or for cash collateral associated with these derivatives, which is not significant to our financial statements.

		Fair Value of Asset Derivatives								Fair Value of Liability Derivatives
		June 30, 2009				December 31, 2008				June 30, 2009				December 31, 2008
						(In millions)
Derivatives Designated as Hedges:
Cash flow hedges
Interest rate derivatives		$	—			$	—			$	(16	)		$	(21	)
Fair value hedges
Interest rate derivatives			8				12				—				—
Cross-currency derivatives			—				94				—				—
Total derivatives designated as hedges			8				106				(16	)			(21	)
Derivatives not Designated as Hedges:
Commodity-based derivatives
Production-related			626				738				(193	)			(56	)
Other natural gas			659				853				(852	)			(1,122	)
Power-related			70				111				(429	)			(549	)
Total commodity-based derivatives			1,355				1,702				(1,474	)			(1,727	)
Interest rate derivatives			9				12				(9	)			(12	)
Total derivatives not designated as hedges			1,364				1,714				(1,483	)			(1,739	)
Impact of master netting arrangements(1)			(737	)			(743	)			737				743
Total assets (liabilities) from price risk management activities			635				1,077				(762	)			(1,017	)
Other derivatives( 2)			—				—				(29	)			(55	)
Total derivatives		$	635			$	1,077			$	(791	)		$	(1,072	)

     Statements of Income, Comprehensive Income and Cash Flow Presentation. Derivatives that we have designated as accounting hedges impact our revenues or expenses based on the nature and timing of the transactions that they hedge. Changes in derivative fair values that are designated as cash flow hedges are deferred in accumulated other comprehensive income or loss to the extent that they are effective and then recognized in earnings when the hedged transactions occur. Ineffectiveness related to our cash flow hedges is recognized in earnings as it occurs. Changes in the fair value of derivatives that are designated as fair value hedges are recognized in earnings as offsets to the changes in fair values of the related hedged assets, liabilities or firm commitments.

     Derivatives that we have not designated as accounting hedges are marked-to-market each period and changes in their fair value are generally reflected as operating revenues, except as indicated in the table below. In our cash flow statement, cash inflows and outflows associated with the settlement of our derivative instruments are recognized in operating cash flows (other than those derivatives intended to hedge the principal amounts of our foreign currency denominated debt, which are recorded in financing activities). Listed below are the impacts to our income statement and statement of comprehensive income for the quarter and six months ended June 30, 2009:

Quarter Ended June 30, 2009

		Operating				Interest				Other				Other Comprehensive
		Revenues				Expense				Income				Income (Loss)
		(in millions)
Commodity-based derivatives
Production-related derivatives(1)		$	55			$	—			$	—			$	(99	)
Other natural gas and power derivatives not designated as hedges			18				—				—				—
Total commodity-based derivatives			73				—				—				(99	)
Interest rate and foreign currency derivatives(2)
Designated as cash flow hedges(3)			—				1				(5	)			5
Designated as fair value hedges(4)			—				1				—				—
Cross-currency derivatives designated as fair value hedges(4)			—				1				3				—
Total interest rate and foreign currency derivatives			—				3				(2	)			5
Total price risk management activities(5)		$	73			$	3			$	(2	)		$	(94	)
Six Months Ended June 30, 2009
Commodity-based derivatives
Production-related derivatives(1)		$	449			$	—			$	—			$	(227	)
Other natural gas and power derivatives not designated as hedges			73				—				—				—
Total commodity-based derivatives			522				—				—				(227	)
Interest rate and foreign currency derivatives(2)
Designated as cash flow hedges(3)			—				2				(5	)			8
Designated as fair value hedges(4)			—				2				—				—
Cross-currency derivatives designated as fair value hedges(4)			—				3				(21	)			—
Total interest rate and foreign currency derivatives.			—				7				(26	)			8
Total price risk management activities (5)		$	522			$	7			$	(26	)		$	(219	)

8. Debt, Other Financing Obligations and Other Credit Facilities

		June 30,				December 31,
		2009				2008
		(In millions)
Short-term financing obligations, including current maturities		$	169			$	1,090
Long-term financing obligations			13,477				12,818
Total		$	13,646			$	13,908

     Changes in Long-Term Financing Obligations. During the six months ended June 30, 2009, we had the following changes in our long-term financing obligations (in millions):

						Book Value				Cash
Company		Interest Rate				Increase (Decrease)				Received (Paid)
Issuances
El Paso Notes due 2016(1)			8.25%			$	478			$	473
Tennessee Gas Pipeline (TGP) notes due 2016(1)			8.00%				237				234
Southern LNG notes due 2014 and 2016			9.60%				135				134
Elba Express Company LLC credit facility		variable					99				92
El Paso Pipeline Partners, L.P. (EPB) revolving credit facilities		variable					50				50
Increases through June 30, 2009						$	999			$	983
Repayments, repurchases, and other
El Paso Corporation
Notes due 2009		6.375% to 7.125%				$	(1,054	)		$	(1,054	)(2)
Revolving credit facilities		variable					(97	)			(97	)
EPB revolving credit facilities		variable					(115	)			(115	)
El Paso Exploration and Production Company (EPEP) revolving credit facility		variable					(20	)			(20	)
Other		variable					25				(11	)
Decreases through June 30, 2009						$	(1,261	)		$	(1,297	)

     Credit Facilities. As of June 30, 2009, we had total available capacity under various credit agreements (not including capacity available under the EPB $750 million revolving credit facility) of approximately $1.5 billion. In determining our available capacity, we have assessed our lender’s ability to fund under our various credit facilities, as further discussed in our 2008 Annual Report on Form 10-K.

     During the first six months of 2009, we increased the size of or entered into new letter of credit facilities totaling $225 million. As of June 30, 2009, we had total letter of credit capacity under these facilities of $250 million with a weighted average fixed facility fee of 6.90% and maturities ranging from December 2013 to September 2014. Additionally, in June 2009, $150 million of another letter of credit facility entered into in 2007 matured.

     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. As of June 30, 2009 and December 31, 2008, the restricted net assets of our consolidated subsidiaries were less than $1 million and approximately $1 billion. 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. Our existing borrowing base was approved by the banks in May 2009 and will be redetermined in November 2009. There have been no significant changes to our restrictive covenants from those disclosed in our 2008 Annual Report on Form 10-K and as of June 30, 2009, 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 June 30, 2009, we had outstanding letters of credit issued under all of our facilities of approximately $1.6 billion. Included in this amount is approximately $0.8 billion of letters of credit securing our recorded obligations related to price risk management activities.

     Other. In the second quarter of 2009, our wholly owned subsidiary, Elba Express Company, secured a $165 million non-recourse financing facility, which is available only to the related pipeline project. As of June 30, 2009, $99 million has been borrowed under this facility.

9. Commitments and Contingencies

Legal Proceedings

     ERISA Class Action Suit. In December 2002, a purported class action lawsuit entitled William H. Lewis, III v. El Paso Corporation, et al. was filed in the U.S. District Court for the Southern District of Texas alleging that our communication with participants in our Retirement Savings Plan included various misrepresentations and omissions that caused members of the class to hold and maintain investments in El Paso stock in violation of the Employee Retirement Income Security Act (ERISA). A settlement has been finalized, received court approval and been paid.

     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 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 plaintiffs’ claims. The plaintiffs have filed a motion seeking to overturn the dismissal of the case. 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. The lawsuit was 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, in the first quarter of 2008, the trial court granted a summary judgment and 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 and we adjusted our existing indemnification accrual using current actuarial assumptions and reclassified our liability as a postretirement benefit obligation. See Note 10 for a discussion of the impact of this matter. We 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. The first set of cases, involving similar allegations on behalf of commercial and residential customers, was transferred to a multi-district litigation proceeding (MDL) in the U.S. District Court for Nevada and styled In re: Western States Wholesale Natural Gas Antitrust Litigation. These cases were dismissed. The U.S. Court of Appeals for the Ninth Circuit, however, reversed the dismissal and ordered that these cases be remanded to the trial court. The second set of cases also involve similar allegations on behalf of certain purchasers of natural gas. These include Farmland Industries v. Oneok Inc., et al. (filed in state court in Wyandotte County, Kansas in July 2005) and Missouri Public Service Commission v. El Paso Corporation, et al. (filed in the circuit court of Jackson County, Missouri at Kansas City in October 2006), and the purported class action lawsuits styled: Leggett, et al. v. Duke Energy Corporation, et al. (filed in Chancery Court of Tennessee in January 2005); Ever-Bloom Inc., et al. v. AEP Energy Services Inc., et al. (filed in federal court for the Eastern District of California in September 2005); Learjet, Inc., et al. v. Oneok Inc., et al. (filed in state court in Wyandotte County, Kansas in September 2005); Breckenridge, et al. v. Oneok Inc., et al. (filed in state court in Denver County, Colorado in May 2006); Arandell, et al. v. Xcel Energy, et al. (filed in the circuit court of Dane County, Wisconsin in December 2006); Heartland, et al. v. Oneok Inc., et al. (filed in the circuit court of Buchanan County, Missouri in March 2007); and Newpage Wisconsin System, Inc., et al. (filed in the circuit court of Wood County, Wisconsin in March 2009). The Leggett case was dismissed by the Tennessee state court, but in October 2008, the Tennessee Court of Appeals reversed the dismissal, remanding the matter to the trial court. The decision has been appealed to the Tennessee Supreme Court. The Missouri Public Service case was dismissed by the state court. The dismissal has been appealed. Newpage was recently filed. The remaining cases have all been transferred to the MDL proceeding. The Breckenridge Case has been dismissed as to El Paso and other defendants, and a motion for reconsideration of this decision was denied. This ruling can still be appealed. Discovery is proceeding in the MDL cases. We reached an agreement to settle the Western States and Ever-Bloom cases, subject to court approval, and have established accruals for those cases, which we believe are adequate. Our costs and legal exposure related to the remaining lawsuits and claims are not currently determinable.

     Gas Measurement Cases. A number of our subsidiaries were named defendants in actions that generally allege mismeasurement of natural gas volumes and/or heating content resulting in the underpayment of royalties. The first set of cases was filed in 1997 by an individual under the False Claims Act and have been consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court for the District of Wyoming). These complaints allege an industry-wide conspiracy to underreport the heating value as well as the volumes of the natural gas produced from federal and Native American lands. In October 2006, the U.S. District Judge issued an order dismissing all claims against all defendants. In March 2009, the Tenth Circuit Court of Appeals affirmed the dismissals and in May 2009, the plaintiff’s motion for reconsideration was denied.

     Similar allegations were filed in a set of actions initiated in 1999 in Will Price, et al. v. Gas Pipelines and Their Predecessors, et al., in the District Court of Stevens County, Kansas. The plaintiffs currently seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. Motions for class certification have been briefed and argued in the proceedings and the parties are awaiting the court’s ruling. The plaintiffs seek an unspecified amount of monetary damages in the form of additional royalty payments (along with interest, expenses and punitive damages) and injunctive relief with regard to future gas measurement practices. Our costs and legal exposure related to these 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. They have sought 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. In 2008, we settled 59 of these lawsuits. The settlement payments were covered by insurance and we were reimbursed for the payments by our insurers. Additionally, in July 2009, we made payment on an additional settled case which is expected to be covered by insurance. Following dismissal of the settled cases we have 31 lawsuits that remain. Although there have been settlement discussions with other plaintiffs, such discussions have been unsuccessful to date. While the damages claimed in the remaining actions are substantial, there remains significant legal uncertainty regarding the validity of the causes of action asserted and the availability of the relief sought. We have or will tender these remaining cases to our insurers. It is likely that our insurers will assert denial of coverage on the 11 most-recently filed cases. Our costs and legal exposure related to these 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 June 30, 2009, we had approximately $59 million accrued for our outstanding legal and governmental proceedings.

Rates and Regulatory Matters

     EPNG Rate Case. In June 2008, El Paso Natural Gas Company (EPNG) filed a rate case with the Federal Energy Regulatory Commission (FERC) as required under the settlement of its previous rate case. The filing proposed 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 and the outcome of a hearing and a technical conference. The FERC issued an order in December 2008 that generally accepted most of EPNG’s proposals in the technical conference proceeding. The FERC has appointed an administrative law judge to preside over a hearing if EPNG is unable to reach a negotiated settlement with its customers on the remaining issues. The hearing is currently scheduled to begin in late October 2009. The outcome of the hearing is not currently determinable.

     SNG Rate Case. In March 2009, Southern Natural Gas Company (SNG) filed a rate case with the FERC as permitted under the settlement of its previous rate case. The filing proposed an increase in SNG’s base tariff rates. In April 2009, the FERC issued an order accepting the proposed rates effective September 1, 2009, subject to refund and the outcome of a hearing and a technical conference on certain tariff proposals. The FERC has appointed an administrative law judge to preside over a hearing if SNG is unable to reach a negotiated settlement with its customers on the remaining issues. The hearing is currently scheduled to begin in February 2010. The outcome of the hearing is not currently determinable.

     Notice of Proposed Rulemaking. On October 3, 2007, the Minerals Management Service (MMS) issued a Notice of Proposed Rulemaking for Oil and Gas and Sulphur Operations in the Outer Continental Shelf (OCS) — Pipelines and Pipeline Rights-of-Way. If adopted, the proposed rules would substantially revise MMS OCS pipeline and rights-of-way regulations. The proposed rules would have the effect of: (1) increasing the financial obligations of entities, like us, which have pipelines and pipeline rights-of-way in the OCS; (2) increasing the regulatory requirements imposed on the operation and maintenance of existing pipelines and rights-of-way in the OCS; and (3) increasing the requirements and preconditions for obtaining new rights-of-way in the OCS.

Other Matter

     Navajo Nation. In March 2009, representatives of the Navajo Nation and EPNG executed a final agreement setting forth the full terms and conditions of the Navajo Nation’s consent to EPNG’s rights-of-way through the Navajo Nation. EPNG submitted the Navajo Nation’s consent agreement in support of EPNG’s pending application to the United States Department of the Interior for an extension of the Department’s current right-of-way grant. We expect the submission will result in the Department’s final processing of our application. EPNG has filed with the FERC for recovery of these amounts in its recent rate case.

Environmental Matters

     We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remedy the effect on the environment of the disposal or release of specified substances at current and former operating sites. At June 30, 2009, we had accrued approximately $190 million for environmental matters, which has not been reduced by $24 million for amounts to be paid directly under government sponsored programs or through settlement arrangements. Our accrual includes approximately $185 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $5 million for related environmental legal costs. Of the $190 million accrual, $16 million was reserved for facilities we currently operate and $174 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 $190 million to approximately $371 million. Our accrual represents a combination of two estimation methodologies. First, where the most likely outcome can be reasonably estimated, that cost has been accrued ($12 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($178 million to $359 million) and if no one amount in that range is more likely than any other, the lower end of the expected range has been accrued. Our environmental remediation projects are in various stages of completion. Our recorded liabilities reflect our current estimates of amounts we will expend to remediate these sites. However, depending on the stage of completion or assessment, the ultimate extent of contamination or remediation required may not be known. As additional assessments occur or remediation efforts continue, we may incur additional liabilities. By type of site, our reserves are based on the following estimates of reasonably possible outcomes:

		June 30, 2009
Sites		Expected				High
		(In millions)
Operating		$	16			$	23
Non-operating			157				308
Superfund			17				40
Total		$	190			$	371

     Below is a reconciliation of our accrued liability from January 1, 2009 to June 30, 2009 (in millions):

Balance as of January 1, 2009		$	204
Additions/adjustments for remediation activities			7
Payments for remediation activities			(21	)
Balance as of June 30, 2009		$	190

     For the remainder of 2009, 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 $8 million in the aggregate for the years 2009 through 2013. These expenditures primarily relate to compliance with clean air regulations.

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

     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. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes and environmental matters.

     Our potential exposure under guarantee and indemnification agreements can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim and the particular transaction. While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are circumstances where the amount and duration are unlimited. For those arrangements with a specified dollar amount, we have a maximum stated value of approximately $794 million, which primarily relates 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 June 30, 2009, we have recorded obligations of $51 million related to our 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. On April 13, 2009, TGP filed an amendment to a 1995 FERC settlement that, if approved by the FERC, would provide for interim refunds to its customers of approximately $157 million of 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 commencing within 20 days after the FERC’s order becomes final.

10. Retirement Benefits

     Net Benefit Cost (Income). The components of net benefit cost (income) for our pension and postretirement benefit plans for the periods ended June 30 are as follows:

		Quarters Ended June 30,																Six Months Ended June 30,
										Other																Other
		Pension								Postretirement								Pension								Postretirement
		Benefits								Benefits								Benefits								Benefits
		2009				2008				2009				2008				2009				2008				2009				2008
														(In millions)
Service cost		$	4			$	3			$	—			$	—			$	8			$	7			$	—			$	—
Interest cost			30				30				10				10				60				60				19				17
Expected return on plan assets			(43	)			(46	)			(3	)			(4	)			(86	)			(93	)			(6	)			(8	)
Amortization of net actuarial loss (gain)			11				6				—				(1	)			22				12				—				(2	)
Amortization of prior service credit			—				—				—				(1	)			—				(1	)			—				(1	)
Net benefit cost (income)		$	2			$	(7	)		$	7			$	4			$	4			$	(15	)		$	13			$	6