UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

(Mark One)

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

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

Commission File Number 1-14365

El Paso Corporation

(Exact Name of Registrant as Specified in Its Charter)

Delaware		76-0568816
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)
El Paso Building		77002
1001 Louisiana Street		(Zip Code)
Houston, Texas
(Address of Principal Executive Offices)

Telephone Number: (713) 420-2600
Internet Website: www.elpaso.com

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 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 (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 November 3, 2009: 701,270,947

 

 

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			28
Item 3. Quantitative and Qualitative Disclosures About Market Risk			52
Item 4. Controls and Procedures			53
PART II — OTHER INFORMATION
Item 1. Legal Proceedings			54
Item 1A. Risk Factors			55
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			56
Item 3. Defaults Upon Senior Securities			56
Item 4. Submission of Matters to a Vote of Security Holders			56
Item 5. Other Information			56
Item 6. Exhibits			56
Signatures			57
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								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Operating revenues		$	981			$	1,598			$	3,438			$	4,020
Operating expenses
Cost of products and services			45				68				158				195
Operation and maintenance			346				328				910				874
Ceiling test charges			5				1				2,085				8
Depreciation, depletion and amortization			200				292				653				903
Taxes, other than income taxes			56				70				181				230
			652				759				3,987				2,210
Operating income (loss)			329				839				(549	)			1,810
Earnings from unconsolidated affiliates			11				52				42				141
Other income, net			33				(3	)			71				52
Interest and debt expense			(256	)			(221	)			(764	)			(675	)
Income (loss) before income taxes			117				667				(1,200	)			1,328
Income tax expense (benefit)			35				215				(425	)			450
Net income (loss)			82				452				(775	)			878
Net income attributable to noncontrolling interests			(15	)			(7	)			(38	)			(23	)
Net income (loss) attributable to El Paso Corporation			67				445				(813	)			855
Preferred stock dividends			9				9				28				28
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	58			$	436			$	(841	)		$	827
Basic earnings per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	0.08			$	0.63			$	(1.21	)		$	1.19
Diluted earnings per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	0.08			$	0.58			$	(1.21	)		$	1.12
Dividends declared per El Paso Corporation’s common share		$	0.05			$	0.05			$	0.15			$	0.13

See accompanying notes.

EL PASO CORPORATION

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

		September 30,				December 31,
		2009				2008
ASSETS
Current assets
Cash and cash equivalents		$	1,121			$	1,024
Accounts and notes receivable
Customers, net of allowance of $9 in 2009 and 2008			271				466
Affiliates			84				133
Other			121				217
Materials and supplies			172				187
Assets from price risk management activities			316				876
Deferred income taxes			231				—
Other			109				148
Total current assets			2,425				3,051
Property, plant and equipment, at cost
Pipelines			19,237				18,042
Natural gas and oil properties, at full cost			20,537				20,009
Other			357				342
			40,131				38,393
Less accumulated depreciation, depletion and amortization			22,931				20,535
Total property, plant and equipment, net			17,200				17,858
Other assets
Investments in unconsolidated affiliates			1,705				1,703
Assets from price risk management activities			109				201
Other			718				855
			2,532				2,759
Total assets		$	22,157			$	23,668

See accompanying notes.

EL PASO CORPORATION

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

		September 30,				December 31,
		2009				2008
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade		$	300			$	372
Affiliates			7				6
Other			492				618
Short-term financing obligations, including current maturities			339				1,090
Liabilities from price risk management activities			224				250
Accrued interest			241				192
Other			852				715
Total current liabilities			2,455				3,243
Long-term financing obligations, less current maturities			13,633				12,818
Other
Liabilities from price risk management activities			523				767
Deferred income taxes			265				565
Other			1,557				1,679
			2,345				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 715,877,755 shares in 2009 and 712,628,781 shares in 2008			2,148				2,138
Additional paid-in capital			4,505				4,612
Accumulated deficit			(3,466	)			(2,653	)
Accumulated other comprehensive loss			(709	)			(532	)
Treasury stock (at cost); 14,612,967 shares in 2009 and 14,061,474 shares in 2008			(282	)			(280	)
Total El Paso Corporation stockholders’ equity			2,946				4,035
Noncontrolling interests			778				561
Total equity			3,724				4,596
Total liabilities and equity		$	22,157			$	23,668

See accompanying notes.

EL PASO CORPORATION

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

		Nine Months Ended
		September 30,
		2009				2008
Cash flows from operating activities
Net income (loss)		$	(775	)		$	878
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization			653				903
Ceiling test charges			2,085				8
Deferred income tax expense (benefit)			(448	)			470
Earnings from unconsolidated affiliates, adjusted for cash distributions			17				(12	)
Other non-cash income items			53				16
Asset and liability changes			196				(212	)
Net cash provided by operating activities			1,781				2,051
Cash flows from investing activities
Capital expenditures			(2,081	)			(1,905	)
Cash paid for acquisitions, net of cash acquired			(39	)			(362	)
Net proceeds from the sale of assets and investments			303				671
Net change in restricted cash			41				35
Other			(26	)			44
Net cash used in investing activities			(1,802	)			(1,517	)
Cash flows from financing activities
Net proceeds from issuance of long-term debt			1,369				4,083
Payments to retire long-term debt and other financing obligations			(1,290	)			(3,556	)
Dividends paid			(133	)			(113	)
Net proceeds from issuance of noncontrolling interests			212				15
Distributions to noncontrolling interest holders			(33	)			(20	)
Repurchase of common shares			—				(77	)
Other			(7	)			9
Net cash provided by financing activities			118				341
Change in cash and cash equivalents			97				875
Cash and cash equivalents
Beginning of period			1,024				285
End of period		$	1,121			$	1,160

See accompanying notes.

EL PASO CORPORATION

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

		Nine Months Ended
		September 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			10				8
Balance at end of period			2,148				2,136
Additional paid-in capital:
Balance at beginning of period			4,612				4,699
Dividends			(133	)			(119	)
Other, including stock-based compensation			26				69
Balance at end of period			4,505				4,649
Accumulated deficit:
Balance at beginning of period			(2,653	)			(1,834	)
Net income (loss) attributable to El Paso Corporation			(813	)			855
Cumulative effect of adopting new pension plan accounting standards, net of income tax of $2			—				4
Balance at end of period			(3,466	)			(975	)
Accumulated other comprehensive loss:
Balance at beginning of period			(532	)			(272	)
Other comprehensive income (loss)			(177	)			102
Cumulative effect of adopting new pension plan accounting standards, net of income tax of $2			—				3
Balance at end of period			(709	)			(167	)
Treasury stock, at cost:
Balance at beginning of period			(280	)			(191	)
Share repurchases			—				(77	)
Stock-based and other compensation			(2	)			(10	)
Balance at end of period			(282	)			(278	)
Total El Paso Corporation stockholders’ equity at end of period			2,946				6,115
Noncontrolling interests:
Balance at beginning of period			561				565
Distributions paid to noncontrolling interests			(33	)			(20	)
Issuance of noncontrolling interests			212				15
Net income attributable to noncontrolling interests			38				23
Other			—				(24	)
Balance at end of period			778				559
Total equity at end of period		$	3,724			$	6,674

See accompanying notes.

EL PASO CORPORATION

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

		Quarters Ended								Nine Months Ended
		September 30,								September 30,
		2009				2008				2009				2008
Net income (loss)		$	82			$	452			$	(775	)		$	878
Pension and postretirement obligations:
Unrealized actuarial losses arising during period (net of income taxes of $1 in 2008)			—				—				—				(2	)
Reclassification of actuarial losses during period (net of income taxes of $3 and $11 in 2009 and $2 and $7 in 2008)			7				3				21				13
Cash flow hedging activities:
Unrealized mark-to-market gains (losses) arising during period (net of income taxes of $5 and $3 in 2009 and $227 and $5 in 2008)			(5	)			405				5				10
Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $34 and $114 in 2009 and $24 and $46 in 2008)			(61	)			42				(203	)			81
Other comprehensive income (loss)			(59	)			450				(177	)			102
Comprehensive income (loss)			23				902				(952	)			980
Comprehensive income attributable to noncontrolling interests			(15	)			(7	)			(38	)			(23	)
Comprehensive income (loss) attributable to El Paso Corporation		$	8			$	895			$	(990	)		$	957

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 (GAAP). 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 September 30, 2009, and for the quarters and nine months ended September 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 January 1, 2009 adoption of new presentation and disclosure requirements for noncontrolling interests. Our financial statements for prior periods also include certain reclassifications that were made to conform to the current period presentation, none of which impacted our reported net income (loss) or stockholders’ equity. 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 November 6, 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 new accounting and reporting standards related to 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 also 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. Substantially all of the derivative liabilities in our Marketing segment are supported by letters of credit. Under these accounting standard updates, 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 these new accounting updates.

     Business Combinations. On January 1, 2009, we adopted accounting standard updates related to business acquisitions. These updates apply to acquisitions that are effective after December 31, 2008 and 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.

     Noncontrolling Interests. Effective January 1, 2009, we adopted accounting standard updates on accounting and reporting for noncontrolling interests in the financial statements which require us to present our noncontrolling interests that have the characteristics of permanent equity (primarily related 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 on our balance sheets. Additionally, we are also required 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 these changes to the presentation and disclosure requirements related to noncontrolling interests. These accounting standard updates also require 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 September 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 updates to the existing accounting standards on financial asset transfers. Among other items, these accounting standard updates eliminate the concept of a qualifying special-purpose entity (QSPE) for purposes of evaluating whether an entity should be consolidated as a variable interest entity and are 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 these accounting standard updates 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 updates to existing accounting standards for variable interest entities which revise how companies determine their primary beneficiaries, among other changes. These updates require companies to use a qualitative approach based on their responsibilities and controlling power over the variable interest entities’ operations rather than a quantitative approach in determining the primary beneficiary as previously required. We are currently assessing the impact that these accounting standard updates, effective January 1, 2010, 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 $49 million as of September 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. During the third quarter of 2009, we acquired a 50 percent interest in the South Alamein concession in the Western Desert of Egypt for approximately $39 million. During the nine months ended September 30, 2008, we acquired additional interests in onshore domestic natural gas and oil properties for approximately $61 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 14). Subsequently, in the second quarter of 2009, we sold the notes, including accrued interest, to a third party financial institution for $57 million and recorded a loss of $22 million. During 2009 we also sold 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

     During the nine months ended September 30, 2009, we recorded a reduction to our property, plant and equipment due to total non-cash ceiling test charges of $2.1 billion that resulted primarily from declines in natural gas prices. In the first quarter of 2009, capitalized costs exceeded the ceiling limit by approximately $2.0 billion for our domestic full cost pool and approximately $28 million for our Brazilian full cost pool. The calculation of the first quarter of 2009 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.

     By September 30, 2009, spot natural gas prices declined to $3.30 per MMBtu while oil prices improved to $70.61 per barrel. As a result of higher oil prices, reserve additions and lower costs, we did not have a ceiling test charge in our domestic or Brazilian full cost pools during the second or third quarters of 2009.

     During the nine months ended September 30, 2009, we recorded non-cash ceiling test charges in our Egyptian full cost pool totaling approximately $26 million, of which $5 million was recorded in the third quarter of 2009. During the quarter and nine months ended September 30, 2008, we recorded non-cash ceiling test charges of $1 million and $8 million 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. We may be required to record additional ceiling test charges in the future if commodity prices decrease from the September 30, 2009 levels.

4. Income Taxes

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

		Quarters Ended September 30,								Nine Months Ended September 30,
		2009				2008				2009				2008
						(In millions, except rates)
Income tax (benefit) expense		$	35			$	215			$	(425	)		$	450
Effective tax rate			30	%			32	%			35	%			34	%

     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 our annual estimate of 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 nine months ended September 30, 2009 and 2008, 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 third quarter of 2009, our effective tax rate was primarily impacted by foreign income which can be taxed at different rates. During the third quarter of 2008, our effective tax rate was lower than the statutory rate primarily due to the foreign tax impact of fluctuations in exchange rates.

     Deferred Tax Asset. As of September 30, 2009, we have a net federal deferred tax asset of $131 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 September 30,

		2009								2008
		Basic				Diluted				Basic				Diluted
		(In millions, except per share amounts)
Net income attributable to El Paso Corporation		$	67			$	67			$	445			$	445
Convertible preferred stock dividends			(9	)			(9	)			(9	)			—
Interest on trust preferred securities			—				—				—				3
Net income attributable to El Paso Corporation’s common stockholders		$	58			$	58			$	436			$	448
Weighted average common shares outstanding			696				696				696				696
Effect of dilutive securities:
Options and restricted stock			—				4				—				4
Trust preferred securities			—				—				—				8
Convertible preferred stock			—				—				—				58
Weighted average common shares outstanding and dilutive securities			696				700				696				766
Basic and diluted earnings per common share:
Net income attributable to El Paso Corporation’s common stockholders		$	0.08			$	0.08			$	0.63			$	0.58

Nine Months Ended September 30,

		2009								2008
		Basic				Diluted				Basic				Diluted
		(In millions, except per share amounts)
Net income (loss) attributable to El Paso Corporation		$	(813	)		$	(813	)		$	855			$	855
Convertible preferred stock dividends			(28	)			(28	)			(28	)			—
Interest on trust preferred securities			—				—				—				8
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	(841	)		$	(841	)		$	827			$	863
Weighted average common shares outstanding			695				695				697				697
Effect of dilutive securities:
Options and restricted stock			—				—				—				4
Trust preferred securities			—				—				—				8
Convertible preferred stock			—				—				—				58
Weighted average common shares outstanding and dilutive securities			695				695				697				767
Basic and diluted earnings per common share:
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	(1.21	)		$	(1.21	)		$	1.19			$	1.12

     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 nine months ended September 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 quarter ended September 30, 2009, our convertible preferred stock and trust preferred securities were antidilutive. Additionally, for the quarters ended September 30, 2009 and 2008 and nine months ended September 30, 2008, certain of our employee stock options were antidilutive. For a further discussion of our potentially dilutive securities, see our 2008 Annual Report on Form 10-K.

6. Fair Value Measurements

     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 interest rate swaps, 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 September 30, 2009 (in millions):

		Level 1				Level 2				Level 3				Total
Assets
Commodity-based derivatives
Production-related natural gas and oil derivatives		$	—			$	273			$	—			$	273
Other natural gas derivatives			—				79				20				99
Power-related derivatives			—				—				42				42
Interest rate derivatives			—				11				—				11
Marketable securities invested in non-qualified compensation plans			19				—				—				19
Total assets			19				363				62				444
Liabilities
Commodity-based derivatives
Production-related natural gas and oil derivatives			—				(54	)			—				(54	)
Other natural gas derivatives			—				(136	)			(143	)			(279	)
Power-related derivatives			—				—				(396	)			(396	)
Interest rate derivatives			—				(18	)			—				(18	)
Other			—				—				(32	)			(32	)
Total liabilities			—				(208	)			(571	)			(779	)
Total		$	19			$	155			$	(509	)		$	(335	)

     On certain derivative contracts recorded as assets 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. Based on this assessment, we have determined that our exposure is primarily related to our production-related derivatives 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 nine months ended September 30, 2009 (in millions):

						Change in fair				Change in fair
		Balance at				value reflected in				value reflected in								Balance at
		Beginning of				operating				operating				Settlements,				End of
		Period				revenues(1)				expenses(2)				net				Period
Quarter Ended September 30, 2009
Assets		$	73			$	(10	)		$	—			$	(1	)		$	62
Liabilities			(582	)			(9	)			(3	)			23				(571	)
Total		$	(509	)		$	(19	)		$	(3	)		$	22			$	(509	)
Nine Months Ended September 30, 2009
Assets		$	103			$	(35	)		$	—			$	(6	)		$	62
Liabilities			(751	)			79				22				79				(571	)
Total		$	(648	)		$	44			$	22			$	73			$	(509	)

     The following table reflects the carrying value and fair value of all our financial instruments and derivatives that are measured at fair value:

		September 30, 2009								December 31, 2008
		Carrying				Fair				Carrying				Fair
		Amount				Value				Amount				Value
		(In millions)
Long-term financing obligations, including current maturities		$	13,972			$	13,871			$	13,908			$	11,227
Marketable securities invested in non-qualified compensation plans			19				19				19				19
Commodity-based derivatives			(315	)			(315	)			(25	)			(25	)
Interest rate and foreign currency derivatives			(7	)			(7	)			85				85
Other			17				17				72				72

     As of September 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. During the nine months ended September 30, 2009, we did not have any non-financial assets and liabilities that were recorded at fair value subsequent to their initial measurement.

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; (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 required documentation. 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.

     Production-Related Derivatives. We attempt to mitigate commodity price risk and stabilize cash flows associated with our forecasted sales of natural gas and oil production through the use of derivative natural gas and oil swaps, basis swaps and option contracts. These 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 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 September 30, 2009 and December 31, 2008, we have production-related derivatives on 353 TBtu and 187 TBtu of natural gas and 727 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. These contracts 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 September 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. 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.

     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 September 30, 2009 and December 31, 2008, we have interest rate swaps designated as cash flow hedges that converted the interest rate on approximately $172 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 and record changes in the fair value of these derivatives in interest expense. As of September 30, 2009 and December 31, 2008, we have interest rate swaps designated as fair value hedges that convert 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 September 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 contracts.

     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.

     Balance Sheet Presentation. Our derivatives are reflected at fair value on our balance sheet 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 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, which is not significant to our financial statements.

		Fair Value of Asset Derivatives								Fair Value of Liability Derivatives
		September 30, 2009				December 31, 2008				September 30, 2009				December 31, 2008
		(In millions)
Derivatives Designated as Hedges:
Cash flow hedges
Interest rate derivatives		$	—			$	—			$	(18	)		$	(21	)
Fair value hedges
Interest rate derivatives			11				12				—				—
Cross-currency derivatives			—				94				—				—
Total derivatives designated as hedges			11				106				(18	)			(21	)
Derivatives not Designated as Hedges:
Commodity-based derivatives
Production-related			408				738				(189	)			(56	)
Other natural gas			618				853				(798	)			(1,122	)
Power-related			65				111				(419	)			(549	)
Total commodity-based derivatives			1,091				1,702				(1,406	)			(1,727	)
Interest rate derivatives			12				12				(12	)			(12	)
Total derivatives not designated as hedges			1,103				1,714				(1,418	)			(1,739	)
Impact of master netting arrangements(1)			(689	)			(743	)			689				743
Total assets (liabilities) from price risk management activities			425				1,077				(747	)			(1,017	)
Other derivatives( 2)			—				—				(32	)			(55	)
Total derivatives		$	425			$	1,077			$	(779	)		$	(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 designated as cash flow hedges are deferred in accumulated other comprehensive income or loss to the extent 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 not designated as accounting hedges are marked-to-market each period and changes in their fair value are generally reflected in income 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 nine months ended September 30, 2009:

		Operating				Interest				Other				Other Comprehensive
		Revenues				Expense				Income				Income (Loss)
		(In millions)
Quarter Ended September 30, 2009
Commodity-based derivatives
Production-related derivatives(1)		$	87			$	—			$	—			$	(95	)
Other natural gas and power derivatives not designated as hedges			(20	)			—				—				—
Total commodity-based derivatives			67				—				—				(95	)
Interest rate derivatives(2)
Designated as cash flow hedges(3)			—				1				—				—
Designated as fair value hedges(4)			—				1				—				—
Total interest rate derivatives			—				2				—				—
Total price risk management activities(5)		$	67			$	2			$	—			$	(95	)
Nine Months Ended September 30, 2009
Commodity-based derivatives
Production-related derivatives(1)		$	536			$	—			$	—			$	(322	)
Other natural gas and power derivatives not designated as hedges			53				—				—				—
Total commodity-based derivatives			589				—				—				(322	)
Interest rate and foreign currency derivatives(2)
Designated as cash flow hedges(3)			—				3				(5	)			8
Designated as fair value hedges(4)			—				6				(21	)			—
Total interest rate and foreign currency derivatives			—				9				(26	)			8
Total price risk management activities (5)		$	589			$	9			$	(26	)		$	(314	)

8. Debt, Other Financing Obligations and Other Credit Facilities

		September 30,				December 31,
		2009				2008
		(In millions)
Short-term financing obligations, including current maturities		$	339			$	1,090
Long-term financing obligations			13,633				12,818
Total		$	13,972			$	13,908

     Changes in Long-Term Financing Obligations. During the nine months ended September 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					129				121
Ruby Holding Company loan commitment		7.00%					157				154
Ruby Pipeline, LLC term loan		variable					116				115
El Paso Pipeline Partners, L.P. (EPB) revolving credit facilities		variable					138				138
Increases through September 30, 2009						$	1,390			$	1,369
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					(188	)			(188	)
El Paso Exploration and Production Company revolving credit facility		variable					(20	)			(20	)
Other		variable					33				(14	)
Decreases through September 30, 2009						$	(1,326	)		$	(1,373	)

     Credit Facilities. As of September 30, 2009, we had total available capacity under various credit agreements (not including capacity available under the EPB $750 million revolving credit facility and all project financings) of approximately $1.4 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 nine months of 2009, we increased the size of or entered into new letter of credit facilities totaling $275 million. As of September 30, 2009, we had total letter of credit capacity under these facilities of $300 million with a weighted average fixed facility fee of 6.77% and maturities ranging from December 2013 to September 2014. Additionally, during 2009, $300 million of letter of credit facilities 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 December 31, 2008, the restricted net assets of our consolidated subsidiaries were 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 September 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 September 30, 2009, we had outstanding letters of credit issued under all of our facilities of approximately $1.5 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. During 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 September 30, 2009, $129 million has been borrowed under this facility. During the third quarter of 2009, Ruby, a consolidated variable interest entity, entered into a loan commitment for $405 million, which is available only to fund the Ruby pipeline project. As of September 30, 2009, $157 million has been borrowed by Ruby under this loan commitment. In addition, during 2008 our wholly owned subsidiary, Ruby Pipeline L.L.C., entered into a letter of credit facility which is available only to secure the purchase of pipe for the Ruby pipeline project and in 2009 this facility was amended to provide up to $145 million in loans. As of September 30, 2009, $116 million has been borrowed under this facility. For a further discussion of Ruby, see Note 13.

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. 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, 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 in the first quarter of 2008, 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. 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 which was approved by the court and paid. 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 October 2009, the plaintiff’s appeal to the United States Supreme Court 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 seek certification of a class of royalty owners in wells on non-federal and non-Native American lands in Kansas, Wyoming and Colorado. 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. In September 2009, the court denied the motions for class certification. The plaintiffs have filed a motion for reconsideration. 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. Additionally, in July 2009, we settled an additional case which our insurance covered. Following dismissal of the settled cases we have 32 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 12 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 September 30, 2009, we had approximately $55 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 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 early January 2010. 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 pending the outcome of a hearing. On October 5, 2009, SNG filed with the FERC a settlement of the rate case. The settlement resolved all issues set for hearing and was supported by the FERC Staff and not opposed by the participants associated with the rate case. On October 20, 2009, the Administrative Law Judge assigned to the case certified that the settlement was uncontested. Under the terms of the settlement 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 no earlier than September 1, 2012 and no later than September 1, 2013, and (iv) the vast majority of SNG's firm transportation contracts expiring prior to September 1, 2013 will be extended until August 31, 2013. SNG expects the FERC to approve the settlement in early 2010.

     Notice of Proposed Rulemaking. On October 3, 2007, the Minerals Management Service (MMS) issued a notice of proposed rulemaking that is applicable to pipelines located in the Outer Continental Shelf (OCS). If adopted, the proposed rules would substantially revise MMS OCS pipeline and rights-of-way regulations. The proposed rules would have the effect of (i) increasing the financial obligations of entities which have pipelines and pipeline rights-of-way in the OCS, (ii) increasing the regulatory requirements imposed on the operation and maintenance of existing pipelines and rights-of-way in the OCS, and (iii) 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 (the Department) 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 payments under rights-of-way 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 September 30, 2009, we had accrued approximately $195 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 $190 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $5 million for related environmental legal costs. Of the $195 million accrual, $15 million was reserved for facilities we currently operate and $180 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 $195 million to approximately $385 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 ($10 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($185 million to $375 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:

		September 30, 2009
Sites		Expected				High
		(In millions)
Operating		$	15			$	21
Non-operating			164				325
Superfund			16				39
Total		$	195			$	385

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

Balance as of January 1, 2009		$	204
Additions/adjustments for remediation activities			21
Payments for remediation activities			(30	)
Balance as of September 30, 2009		$	195

     For the remainder of 2009, we estimate that our total remediation expenditures will be approximately $18 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 $804 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 September 30, 2009, we have recorded obligations of $54 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 and Other Matters. During the second quarter of 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.

     Purchase Obligations. During 2009, we entered into additional contracts to purchase and install approximately $0.4 billion of pipe primarily associated with the Ruby pipeline project and TGP’s 300 Line expansion which are anticipated to be placed in service between 2010 and 2011.

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 September 30 are as follows:

		Quarters Ended September 30,																Nine Months Ended September 30,
										Other																Other
		Pension								Postretirement								Pension								Postretirement
		Benefits								Benefits								Benefits								Benefits
		2009				2008				2009				2008				2009				2008				2009				2008
		(In millions)
Service cost		$	6			$	4			$	—			$	—			$	14			$	11			$	—			$	—
Interest cost			31				30				10				10				91				90				29				27
Expected return on plan assets			(43	)			(47	)			(3	)			(4	)			(129	)			(140	)			(9	)			(12	)
Amortization of net actuarial loss (gain)			12				6				—				(1	)			34				18				—				(3	)
Amortization of prior service credit			(1	)			(1	)			(1	)			—				(1	)			(2	)			(1	)			(1	)
Net benefit cost (income)		$	5			$	(8	)		$	6			$	5			$	9			$	(23	)		$	19			$	11