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

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

     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 o 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 May 6, 2009: 701,004,510

 

 

EL PASO CORPORATION
TABLE OF CONTENTS

Caption		Page
PART I — FINANCIAL INFORMATION
Item 1. Financial Statements			3
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
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			51
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			52
Item 5. Other Information			52
Item 6. Exhibits			52
Signatures			53
EX-12
EX-31.A
EX-31.B
EX-32.A
EX-32.B

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

     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.

		Quarter Ended
		March 31,
		2009				2008
Operating revenues		$	1,484			$	1,269
Operating expenses
Cost of products and services			61				56
Operation and maintenance			300				271
Ceiling test charges			2,068				—
Depreciation, depletion and amortization			256				313
Taxes, other than income taxes			68				79
			2,753				719
Operating income (loss)			(1,269	)			550
Earnings from unconsolidated affiliates			19				37
Other income, net			22				22
Interest and debt expense			(255	)			(233	)
Income (loss) before income taxes			(1,483	)			376
Income tax expense (benefit)			(526	)			148
Net income (loss)			(957	)			228
Net income attributable to noncontrolling interests			(12	)			(9	)
Net income (loss) attributable to El Paso Corporation			(969	)			219
Preferred stock dividends			9				19
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	(978	)		$	200
Basic and diluted earnings per common share
Net income (loss) attributable to El Paso Corporation’s common stockholders		$	(1.41	)		$	0.29
Dividends declared per El Paso Corporation’s common share		$	0.05			$	0.08

See accompanying notes.

		March 31,				December 31,
		2009				2008
ASSETS
Current assets
Cash and cash equivalents		$	1,841			$	1,024
Accounts and notes receivable
Customers, net of allowance of $9 in 2009 and 2008			360				466
Affiliates			127				133
Other			193				217
Materials and supplies			192				187
Assets from price risk management activities			678				876
Other			159				148
Total current assets			3,550				3,051
Property, plant and equipment, at cost
Pipelines			18,301				18,042
Natural gas and oil properties, at full cost			20,328				20,009
Other			345				342
			38,974				38,393
Less accumulated depreciation, depletion and amortization			22,899				20,535
Total property, plant and equipment, net			16,075				17,858
Other assets
Investments in unconsolidated affiliates			1,764				1,703
Assets from price risk management activities			195				201
Deferred income taxes			145				2
Other			695				853
			2,799				2,759
Total assets		$	22,424			$	23,668

See accompanying notes.

		March 31,				December 31,
		2009				2008
LIABILITIES AND EQUITY
Current liabilities
Accounts payable
Trade		$	265			$	372
Affiliates			11				6
Other			477				674
Short-term financing obligations, including current maturities			961				1,090
Liabilities from price risk management activities			194				250
Accrued interest			260				192
Other			674				659
Total current liabilities			2,842				3,243
Long-term financing obligations, less current maturities			13,541				12,818
Other
Liabilities from price risk management activities			646				767
Deferred income taxes			182				565
Other			1,687				1,679
			2,515				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 712,760,115 shares in 2009 and 712,628,781 shares in 2008			2,138				2,138
Additional paid-in capital			4,582				4,612
Accumulated deficit			(3,622	)			(2,653	)
Accumulated other comprehensive loss			(605	)			(532	)
Treasury stock (at cost); 14,106,447 shares in 2009 and 14,061,474 shares in 2008			(280	)			(280	)
Total El Paso Corporation stockholders’ equity			2,963				4,035
Noncontrolling interests			563				561
Total equity			3,526				4,596
Total liabilities and equity		$	22,424			$	23,668

See accompanying notes.

		Quarter Ended
		March 31,
		2009				2008
Cash flows from operating activities
Net income (loss)		$	(957	)		$	228
Adjustments to reconcile net income (loss) to net cash from operating activities
Depreciation, depletion and amortization			256				313
Ceiling test charges			2,068				—
Deferred income tax expense (benefit)			(528	)			146
Earnings from unconsolidated affiliates, adjusted for cash distributions			(8	)			23
Other non-cash income items			14				6
Asset and liability changes			(36	)			(82	)
Net cash provided by operating activities			809				634
Cash flows from investing activities
Capital expenditures			(759	)			(531	)
Cash paid for acquisitions, net of cash acquired			—				(295	)
Net proceeds from the sale of assets and investments			210				598
Other			13				37
Net cash used in investing activities			(536	)			(191	)
Cash flows from financing activities
Net proceeds from issuance of long-term debt			842				1,240
Payments to retire long-term debt and other financing obligations			(244	)			(1,430	)
Dividends paid			(44	)			(38	)
Distributions to noncontrolling interest holders			(10	)			(4	)
Other			—				2
Net cash provided by (used in) financing activities			544				(230	)
Change in cash and cash equivalents			817				213
Cash and cash equivalents
Beginning of period			1,024				285
End of period		$	1,841			$	498

See accompanying notes.

		Quarter Ended
		March 31,
		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			—				1
Balance at end of period			2,138				2,129
Additional paid-in capital:
Balance at beginning of period			4,612				4,699
Dividends			(44	)			(75	)
Other, including stock-based compensation			14				15
Balance at end of period			4,582				4,639
Accumulated deficit:
Balance at beginning of period			(2,653	)			(1,834	)
Net income (loss) attributable to El Paso Corporation			(969	)			219
Cumulative effect of adopting SFAS No. 158, net of income tax of $2			—				5
Balance at end of period			(3,622	)			(1,610	)
Accumulated other comprehensive income (loss):
Balance at beginning of period			(532	)			(272	)
Other comprehensive loss			(73	)			(118	)
Cumulative effect of adopting SFAS No. 158, net of income tax of $2			—				3
Balance at end of period			(605	)			(387	)
Treasury stock, at cost:
Balance at beginning of period			(280	)			(191	)
Stock-based and other compensation			—				(1	)
Balance at end of period			(280	)			(192	)
Total El Paso Corporation stockholders’ equity at end of period			2,963				5,329
Noncontrolling interests:
Balance at beginning of period			561				565
Distributions paid to noncontrolling interests			(10	)			(4	)
Net income attributable to noncontrolling interests			12				9
Other			—				(23	)
Balance at end of period			563				547
Total equity at end of period		$	3,526			$	5,876

See accompanying notes.

		Quarter Ended
		March 31,
		2009				2008
Net income (loss)		$	(957	)		$	228
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 in 2009 and $2 in 2008)			7				5
Cash flow hedging activities:
Unrealized mark-to-market gains (losses) arising during period (net of income taxes of $1 in 2009 and $70 in 2008)			2				(123	)
Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $46 in 2009 and $1 in 2008)			(82	)			2
Other comprehensive loss			(73	)			(118	)
Comprehensive income (loss)			(1,030	)			110
Comprehensive income attributable to noncontrolling interests			(12	)			(9	)
Comprehensive income (loss) attributable to El Paso Corporation		$	(1,042	)		$	101

See accompanying notes.

     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 March 31, 2009, and for the quarters ended March 31, 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 all adjustments which are of a normal, recurring nature to fairly present our interim period results. Due to the seasonal nature of our businesses, information for interim periods may not be indicative of our operating results for the entire year.

Significant Accounting Policies

     The 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, 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 the presentation of 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 apply the provisions of this statement. This standard also requires all transactions with noncontrolling interest holders, 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 March 31, 2009, the following accounting standard had 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.

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 for which we have advanced approximately $33 million as of March 31, 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.

Divestitures

     During the first quarter of 2009, we completed the sale of our interests in the Porto Velho power generation facility in Brazil for total consideration of $179 million (see Note 13) and the sale of non-core natural gas producing properties located in our Western and Central regions for approximately $93 million. During 2008, we sold natural gas and oil properties primarily in the Gulf of Mexico and Texas Gulf Coast regions for total proceeds of $637 million, of which approximately $600 million was sold during the first quarter of 2008.

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 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. In calculating our ceiling test charges, we are required to hold these 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 continue to decrease from their current levels.

4. Income Taxes

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

		2009				2008
		(In millions, except rates)
Income tax (benefit) expense		$	(526	)		$	148
Effective tax rate			35	%			39	%

     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 first quarter of 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 first quarter of 2008, our effective tax rate was higher than the statutory rate primarily due to the tax impact of adjusting our postretirement benefit obligations, as discussed in Note 10.

     Deferred Tax Asset. As of March 31, 2009, we have a net federal deferred tax asset of $179 million 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 for the quarters ended March 31:

		2009								2008
		Basic				Diluted				Basic				Diluted
		(In millions, except per share amounts)
Net income (loss) attributable to El Paso Corporation		$	(969	)		$	(969	)		$	219			$	219
Convertible preferred stock dividends			(9	)			(9	)			(19	)(1)			(19	)(1)
Net income (loss) attributable to El Paso
Corporation’s common stockholders		$	(978	)		$	(978	)		$	200			$	200
Weighted average common shares outstanding			695				695				697				697
Effect of dilutive securities:
Options and restricted stock			—				—				—				4
Weighted average common shares outstanding and dilutive securities			695				695				697				701
Basic and diluted earnings per common share:
Net income (loss) attributable to El Paso
Corporation’s common stockholders		$	(1.41	)		$	(1.41	)		$	0.29			$	0.29

     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 income from continuing operations 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 quarter ended March 31, 2009, we incurred losses

attributable to El Paso Corporation and, accordingly, excluded all of our potentially dilutive securities from the determination of diluted earnings per share as their impact on loss per common share was antidilutive. For the quarter ended March 31, 2008, certain of our employee stock options, our convertible preferred stock, and our trust preferred securities were antidilutive. For a further discussion of our potentially dilutive securities, see our 2008 Annual Report on Form 10-K.

     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 quarter ended March 31, 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. 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.

     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 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 March 31, 2009 (in millions):

		Level 1				Level 2				Level 3				Total
Assets
Commodity-based derivatives
Production-related natural gas and oil derivatives		$	—			$	625			$	—			$	625
Other natural gas derivatives			—				82				26				108
Power-related derivatives			—				—				53				53
Interest rate and foreign currency derivatives			—				87				—				87
Marketable securities invested in non-qualified compensation plans			19				—				—				19
Total assets			19				794				79				892

Liabilities
Commodity-based derivatives
Production-related natural gas and oil derivatives			—				(52	)			—				(52	)
Other natural gas derivatives			—				(167	)			(158	)			(325	)
Power-related derivatives			—				—				(445	)			(445	)
Interest rate derivatives			—				(18	)			—				(18	)
Other			—				—				(56	)			(56	)
Total liabilities			—				(237	)			(659	)			(896	)
Total		$	19			$	557			$	(580	)		$	(4	)

     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 ended March 31, 2009 (in millions):

						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		$	103			$	(21	)		$	—			$	(3	)		$	79
Liabilities			(751	)			62				(1	)			31				(659	)
Total		$	(648	)		$	41			$	(1	)		$	28			$	(580	)

7. Price Risk Management Activities

     Our price risk management activities relate primarily to derivatives entered into to hedge or otherwise reduce the commodity exposure on our natural gas and oil production and interest rate and foreign currency exposure on our long-term 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 hedging 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 March 31, 2009 and December 31, 2008, we have production-related derivatives on 194 TBtu and 187 TBtu of natural gas and 1,348 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 March 31, 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 Pennsylvania-New Jersey-Maryland (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 offset our exposure to price changes on substantially all of these volumes.

     Interest Rate and Foreign Currency Derivatives. We have fixed rate U.S. dollar and Euro-denominated debt that exposes us to paying higher than market rates should interest rates decline. We use interest rate swaps to protect the value 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. Certain of our interest rate derivatives were designated as cash flow hedges or fair value hedges based on whether the interest on the underlying debt was converted to a fixed or floating interest rate. As of March 31, 2009 and December 31, 2008, we have (i) interest rate swaps designated as cash flow hedges that converted the interest rate on approximately $178 million of debt from a LIBOR-based variable rate to a fixed rate of 4.56% and (ii) 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% and (iii) 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.

     In addition, we use cross-currency swaps to mitigate a portion of the foreign currency risk related to our Euro-denominated debt, which exposes us to fluctuating foreign currency exchange rates. Our cross-currency swaps are designated as fair value hedges and these swaps converted approximately €330 million of our Euro-denominated debt to $379 million, and converted the interest rate on this debt from a fixed rate to a variable rate of LIBOR plus 4.23% as of March 31, 2009 and December 31, 2008.

     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
		March 31, 2009				December 31, 2008				March 31, 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			76				94				—				—
Total derivatives designated as hedges			87				106				(18	)			(21	)
Derivatives not Designated as Hedges:
Commodity-based derivatives
Production-related			643				738				(70	)			(56	)
Other natural gas			667				853				(884	)			(1,122	)
Power-related			80				111				(472	)			(549	)
Total commodity-based derivatives			1,390				1,702				(1,426	)			(1,727	)
Interest rate derivatives			12				12				(12	)			(12	)
Total derivatives not designated as hedges			1,402				1,714				(1,438	)			(1,739	)
Impact of master netting arrangements (1)			(616	)			(743	)			616				743
Total assets (liabilities) from price risk management activities			873				1,077				(840	)			(1,017	)
Other derivatives(2)			—				—				(56	)			(55	)
Total derivatives		$	873			$	1,077			$	(896	)		$	(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 ended March 31, 2009 (in millions):

		Operating				Interest				Other				Other Comprehensive
		Revenues				Expense				Income				Income (Loss)
Commodity-based derivatives
Production-related derivatives (1)		$	394			$	—			$	—			$	(128	)
Other natural gas and power derivatives not designated as hedges			55				—				—				—
Total commodity-based derivatives			449				—				—				(128	)
Interest rate derivatives (2)
Designated as cash flow hedges(3)			—				1				—				3
Designated as fair value hedges(4)			—				1				—				—
Cross-currency derivatives designated as fair value hedges(4)			—				2				(24	)			—
Total interest rate and foreign currency derivatives			—				4				(24	)			3
Total price risk management activities (5)		$	449			$	4			$	(24	)		$	(125	)

8. Debt, Other Financing Obligations and Other Credit Facilities

		March 31,				December 31,
		2009				2008
		(In millions)
Short-term financing obligations, including current maturities		$	961			$	1,090
Long-term financing obligations			13,541				12,818
Total		$	14,502			$	13,908

     Changes in Long-Term Financing Obligations. During the quarter ended March 31, 2009, we had the following changes in our long-term financing obligations (in millions):

										Cash
						Book Value				Received /
Company		Interest Rate				Increase (Decrease)				(Paid)
Issuances
El Paso Notes due 2016(1)			8.25	%		$	478			$	473
Tennessee Gas Pipeline (TGP) notes due 2016(1)			8.00	%			237				235
Southern LNG notes due 2014 and 2016			9.60	%			135				134
Increases through March 31, 2009						$	850			$	842
Repayments, repurchases, and other
El Paso Corporation
Notes due 2009			6.375	%		$	(112	)		$	(112	)
Revolving credit facilities		variable					(97	)			(97	)
El Paso Pipeline Partners, L.P. (EPB) revolving credit facilities		variable					(10	)			(10	)
El Paso Exploration and Production Company (EPEP) revolving credit facility		variable					(20	)			(20	)
Other		variable					(17	)			(5	)
Decreases through March 31, 2009						$	(256	)		$	(244	)

     Credit Facilities. As of March 31, 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.

     In November 2008, we entered into an unsecured credit facility for which we were required to pay fixed facility fees at an annual rate of 7.91% on the total committed amount of the facility. As of March 31, 2009, we had capacity under this facility of $100 million. In April 2009, we entered into an additional $50 million 5-year letter of credit facility with a fixed facility fee of 5.95% maturing June 2014. We currently have a total letter of credit capacity under this program of $150 million with an average fixed facility fee of 7.26% and maturities ranging from December 2013 to June 2014.

     The availability of borrowings under our $1.5 billion revolving credit agreement and our ability to incur additional debt is subject to various financial and non-financial covenants and restrictions. There have been no significant changes to our restrictive covenants from those disclosed in our 2008 Annual Report on Form 10-K.

     Letters of Credit. We enter into letters of credit in the ordinary course of our operating activities as well as periodically in conjunction with the sales of assets or businesses. As of March 31, 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.

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). We have insurance coverage for this lawsuit, subject to certain deductibles and co-pay obligations. We executed agreements to settle this matter and the court has approved the settlement. We have established accruals for this matter which we believe are adequate.

     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 transferred to the MDL, but remanded back to state court, where a motion to dismiss has been granted. 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 in principle to settle the Western States and Ever-Bloom cases and have established accruals for those cases which we believe are adequate. Settlement documents have been executed, but court approval is still required. 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.

     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 plaintiff seeks 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. We settled 59 of these lawsuits, with our payments being made in October 2008. These payments were covered by insurance and all of the payments have been funded by our insurers. Following such settlements, there are 30 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 nine 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 March 31, 2009, we had approximately $81 million accrued, which has not been reduced by $14 million of related insurance receivables, 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 appointed an administrative law judge who will decide the remaining issues should EPNG be unable to reach a settlement with its customers in upcoming negotiations.

     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 appointed an administrative law judge who will decide the rate case issues should SNG be unable to reach a settlement with its customers.

     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. Approximately 900 looped pipeline miles of the north mainline of our EPNG pipeline system are located on lands held in trust by the United States for the benefit of the Navajo Nation. Our rights-of-way on lands crossing the Navajo Nation are the subject of a pending renewal application filed in 2005 with the Department of the Interior’s Bureau of Indian Affairs. In March 2009, representatives of the Navajo Nation and EPNG executed an agreement setting forth the terms and conditions of the Nation’s consent to EPNG’s rights-of-way. Under this agreement, we will make annual payments of approximately $18 million for our rights-of-way beginning in 2009 and continuing through 2025, subject to annual adjustments. 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 that the submission of the consent agreement 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 March 31, 2009, we had accrued approximately $201 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 $195 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $6 million for related environmental legal costs. Of the $201 million accrual, $17 million was reserved for facilities we currently operate and $184 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 $201 million to approximately $383 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 ($189 million to $371 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:

		March 31, 2009
Sites		Expected				High
		(In millions)
Operating		$	17			$	23
Non-operating			165				318
Superfund			19				42
Total		$	201			$	383

     Below is a reconciliation of our accrued liability from January 1, 2009 to March 31, 2009 (in millions):

Balance as of January 1, 2009		$	204
Additions/adjustments for remediation activities			6
Payments for remediation activities			(9	)
Balance as of March 31, 2009		$	201

     For the remainder of 2009, we estimate that our total remediation expenditures will be approximately $59 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 $9 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 30 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.

     Greenhouse Gas (GHG) Emissions. Legislative and regulatory measures to address GHG emissions are in various phases of discussions or implementation at the international, national, regional and state levels. These measures include the Kyoto Protocol, which has been ratified by some of the international countries in which we have operations such as Mexico, Brazil, and Egypt. In the United States, it is likely that federal legislation requiring GHG controls will be enacted in the next few years. In addition, the United States Environmental Protection Agency (EPA) is considering initiating a rulemaking to regulate GHGs under the Clean Air Act. Furthermore, the EPA recently issued proposed regulations requiring monitoring and reporting of GHG emissions on an annual basis economy wide, including extensive new monitoring and reporting requirements applicable to our industry. The EPA has also recently proposed findings that GHGs in the atmosphere endanger public health and welfare and that emissions from mobile sources cause or contribute to GHGs in the atmosphere. These proposed findings, if finalized as proposed, would not immediately affect our operations, but standards eventually promulgated pursuant to these findings could affect our operations and ability to obtain air permits for new or modified facilities. Legislation and regulation are also in various stages of discussion or implementation in many of the states in which we operate. These measures include recommendations released by the Western Climate Initiative regarding a cap-and-trade program and targeted emission reductions in several states in which we operate in the western United States. In California, recently enacted legislation and proposed rules would impose GHG emission reduction targets on our operations there. Meanwhile, lawsuits have been filed seeking to force the federal government to regulate GHG emissions under the Clean Air Act and to require individual companies to reduce GHG emissions from their operations. These and other lawsuits may result in decisions by state and federal courts and agencies that could impact our operations and ability to obtain certifications and permits to construct future projects. Our costs and legal exposure related to GHG regulations are not currently determinable.

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 $811 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 March 31, 2009, we have recorded obligations of $78 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 liabilities on our balance sheet and are expected to be paid over a three year period with interest commencing the later of July 1, 2009 or within 20 days of the FERC’s approval.

10. Retirement Benefits

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

										Other
		Pension								Postretirement
		Benefits								Benefits
		2009				2008				2009				2008
		(In millions)
Service cost		$	4			$	4			$	—			$	—
Interest cost			30				30				9				7
Expected return on plan assets			(43	)			(47	)			(3	)			(4	)
Amortization of net actuarial loss (gain)			11				6				—				(1	)
Amortization of prior service credit(1)			—				(1	)			—				—
Net benefit cost (income)		$	2			$	(8	)		$	6			$	2

     Other Matter. In various court rulings prior to March 2008, we were required to indemnify Case for certain benefits paid to a closed group of Case retirees as further discussed in Note 9. In conjunction with those rulings, we recorded a liability for estimated amounts due under the indemnification using actuarial methods similar to those used in estimating our postretirement benefit plan obligations. This liability, however, was not included in our postretirement benefit obligations or disclosures prior to March 2008.

     In March 2008, we received a summary judgment from the trial court on this matter, and thus became the primary party that is obligated to pay these benefit payments. As a result of the judgment, we adjusted our obligation using current actuarial assumptions and recorded a $65 million reduction to operation and maintenance expense. We also reclassified this obligation from an indemnification liability to a postretirement benefit obligation.

11. Equity

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

		Common Stock				Convertible Preferred Stock
		($0.05/Share)				(4.99%/Year)
Amount paid through March 31, 2009		$	35			$	9
Amount paid in April 2009		$	34			$	9
Declared in May 2009:
Date of declaration		May 6, 2009				May 6, 2009
Payable to shareholders on record		June 5, 2009				June 15, 2009
Date payable		July 1, 2009				July 1, 2009

     Dividends on our common stock and preferred stock are treated as a reduction of additional paid-in-capital since we currently have an accumulated deficit. For the remainder of 2009, we expect dividends paid on our common and preferred stock will be taxable to our stockholders because we anticipate that these dividends will be paid out of current or accumulated earnings and profits for tax purposes.

     The terms of our 750,000 outstanding shares of 4.99% convertible preferred stock provide for the conversion ratio on our preferred stock to increase when we pay quarterly dividends to our common shareholders in excess of $0.04 per share, as we did in January 2009. The terms of these preferred shares also prohibit the payment of dividends on our common stock unless we have paid or set aside for payment all accumulated and unpaid dividends on such preferred stock for all preceding dividend periods. In addition, although our credit facilities do not contain any direct restriction on the payment of dividends, dividends are included as a fixed charge in the calculation of our fixed charge coverage ratio under our credit facilities. If we are unable to comply with our fixed charge coverage ratio, our ability to pay additional dividends would be restricted.

     Noncontrolling Interests. In November 2007, we issued common units in our subsidiary (EPB), a master limited partnership, and recorded noncontrolling interests in our balance sheet of $537 million. During the quarters ended March 31, 2009 and 2008, EPB made cash distributions of $10 million and $4 million to its non-affiliated common unitholders.

12. Business Segment Information

     As of March 31, 2009, our business consists of two core segments, Pipelines and Exploration and Production. We also have Marketing and Power segments. Our segments are strategic business units that provide a variety of energy products and services. They are managed separately as each segment requires different technology and marketing strategies. Our corporate activities include our general and administrative functions, as well as other miscellaneous businesses and various other contracts and assets, all of which are immaterial. A further discussion of each segment follows.

     Pipelines. Provides natural gas transmission, storage, and related services, primarily in the United States. As of March 31, 2009, we conducted our activities primarily through seven wholly or majority owned interstate pipeline systems and equity interests in four transmission systems. We also own or have interests in two underground natural gas storage facilities, and two LNG terminalling facilities, one of which is under construction.

     Exploration and Production. Engaged in the exploration for and the acquisition, development and production of natural gas, oil and NGL, in the United States, Brazil and Egypt.

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

     Power. Manages the risks associated with our remaining international power and pipeline assets and investments located primarily in South America and Asia. We continue to pursue the sale of these assets.

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

		2009				2008
		(In millions)
Segment EBIT		$	(1,233	)		$	561
Corporate and other			(7	)			39
Interest and debt expense			(255	)			(233	)
Income taxes			526				(148	)
Net income (loss) attributable to El Paso Corporation			(969	)			219
Net income attributable to noncontrolling interests			12				9
Net income (loss)		$	(957	)		$	228

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

		Segments
						Exploration
						and												Corporate
		Pipelines				Production				Marketing				Power				and Other(1)				Total
		(In millions)
2009
Revenue from external customers		$	721			$	574	(2)		$	188			$	—			$	1			$	1,484
Intersegment revenue			12				126	(2)			(135	)			—				(3	)			—
Operation and maintenance			183				109				1				2				5				300
Ceiling test charges			—				2,068				—				—				—				2,068
Depreciation, depletion and amortization			104				150				—				—				2				256
Earnings (losses) from unconsolidated affiliates			21				(9	)			—				6				1				19
EBIT			396				(1,685	)			52				4				(7	)			(1,240	)
2008
Revenue from external customers		$	707			$	83	(2)		$	469			$	—			$	10			$	1,269
Intersegment revenue			13				520	(2)			(526	)			—				(7	)			—
Operation and maintenance			195				108				2				5				(39	)			271
Depreciation, depletion and amortization			99				212				—				—				2				313
Earnings from unconsolidated affiliates			21				10				—				5				1				37
EBIT			381				242				(60	)			(2	)			39				600

     Total assets by segment are presented below:

		March 31,				December 31,
		2009				2008
		(In millions)
Pipelines		$	15,504			$	15,121
Exploration and Production			4,070				6,142
Marketing			303				465
Power			313				417
Total segment assets			20,190				22,145
Corporate and Other			2,234				1,523
Total consolidated assets		$	22,424			$	23,668

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

     We hold investments in unconsolidated affiliates which are accounted for using the equity method of accounting. The earnings from unconsolidated affiliates reflected in our income statement include (i) our share of net earnings directly attributable to these unconsolidated affiliates, and (ii) any impairments and other adjustments recorded by us. The information below related to our unconsolidated affiliates includes (i) our net investment and earnings (losses) we recorded from these investments, (ii) summarized financial information of our proportionate share of these investments, and (iii) revenues and charges with our unconsolidated affiliates.

										Earnings (Losses) from
		Investment								Unconsolidated Affiliates
		March 31,				December 31,				Quarter Ended March 31,
		2009				2008				2009				2008
		(In millions)								(In millions)
Net Investment and Earnings (Losses)
Four Star (1)		$	512			$	525			$	(10	)		$	10
Citrus			578				564				14				13
Gulf LNG(2)			278				279				—				—
Gasoductos de Chihuahua			180				174				6				7
Porto Velho(3)			—				(64	)			—				—
Bolivia-to-Brazil Pipeline			113				119				4				3
Argentina to Chile Pipeline			29				27				2				1
Other			74				79				3				3
Total		$	1,764			$	1,703			$	19			$	37

		Quarter Ended
		March 31,
		2009				2008
		(In millions)
Summarized Financial Information
Operating results data:
Operating revenues		$	123			$	186
Operating expenses			68				93
Income from continuing operations and net income			35				56

     We received distributions and dividends from our unconsolidated affiliates of $12 million and $60 million for the quarters ended March 31, 2009 and 2008. Included in these amounts for the quarter ended March 31, 2009 and 2008 are returns of capital of approximately $1 million and less than $1 million. Our revenues and charges with unconsolidated affiliates were not material during the quarters ended March 31, 2009 and 2008.

     Accounts Receivable Sales Program. Several of our pipeline subsidiaries have agreements to sell certain accounts receivable to qualifying special purpose entities (QSPEs) under SFAS No. 140, Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities. The QSPEs purpose is solely to invest in our pipeline receivables which are short-term assets that generally settle within 60 days. As of March 31, 2009 and December 31, 2008, we sold approximately $159 million and $174 million of receivables, received cash of approximately $79 million and $82 million, and received subordinated beneficial interests of approximately $80 million and $89 million. The QSPEs also issued senior beneficial interests on the receivables sold to a third party financial institution, which totaled $79 million and $85 million as of March 31, 2009 and December 31, 2008. We recognized a loss of less than $1 million related to our transactions with these QSPEs during the quarters ended March 31, 2009 and 2008. We reflect the subordinated beneficial interest in receivables sold at their fair value on the date they are issued. These amounts (adjusted for subsequent collections) are recorded as accounts receivable from affiliates in our balance sheet. Our ability to recover our carrying value of our subordinated beneficial interests is based on the collectibility of the underlying receivables sold to the QSPEs. We reflect accounts receivable sold under this program and changes in the subordinated beneficial interests as operating cash flows in our statement of cash flows. Under the agreements, we earn a fee for servicing the accounts receivable and performing all administrative duties for the QSPEs which is reflected as a reduction of operation and maintenance expense in our income statement. The fair value of these servicing and administrative agreements as well as the fees earned were not material to our financial statements for the periods ended March 31, 2009 and 2008.

Other Investment-Related Matters

     Porto Velho. In February 2009, we completed the sale of our interests in Porto Velho to our partner in the project for $101 million of cash and $78 million of notes receivable from the buyer that have an 8.25% annual interest rate and mature in 2013.

     Manaus/Rio Negro. In 2008, we transferred our ownership in the Manaus and Rio Negro facilities to the plants’ power purchaser as required by their power purchase agreements. As of March 31, 2009, we have approximately $50 million of Brazilian reais-denominated accounts receivable owed to us under the projects’ terminated power purchase agreements, which are guaranteed by the purchaser’s parent. The purchaser has withheld payment of these receivables in light of their Brazilian reais-denominated claims of approximately $48 million related to plant maintenance the purchaser claims should have been performed at the plants prior to the transfer, inventory levels and other items. We have been in discussions with the purchaser and have initiated regulatory proceedings to allow us to settle these outstanding claims and recover our accounts receivable. We may also initiate legal action against the purchaser’s parent to collect our receivables, under its guarantee to the projects. We have reviewed our obligations under the power purchase agreement in relation to the claims and have accrued an obligation for the uncontested claims. We believe the remaining contested claims are without merit. The ultimate resolution of each of these matters is unknown at this time, and adverse developments related to either our ability to collect amounts due to us or related to the dispute could require us to record additional losses in the future.

     During 2009, the Brazilian taxing authorities began legal proceedings against the Manaus and Rio Negro projects for $47 million of ICMS taxes allegedly due on capacity payments received from the plants’ power purchaser from 1999 to 2001. By agreement, the power purchaser must indemnify the Manaus and Rio Negro projects for these ICMS taxes, along with related interest and penalties, and is therefore defending the projects against this lawsuit. In order to stay the taxing authorities’ collection efforts related to this matter and secure this potential liability, the power purchaser offered to pledge certain of its assets; however, this pledge was rejected by the Brazilian courts. We have called on the power purchaser’s parent to provide security satisfactory to the courts under its parental guarantee to us. We anticipate that if we reach an agreement on the matters described above (other than those related to ICMS taxes), the power purchaser will reaffirm its responsibility for any amounts related to this ICMS tax matter.

     Investment in Bolivia and Argentina. We own an 8 percent interest in the Bolivia-to-Brazil pipeline and a 22 percent interest in the Argentina-to-Chile pipeline. As of March 31, 2009, our total investment and guarantees related to these pipeline projects was approximately $164 million. Discussions with a group of our partners regarding the sale of our interest in the Argentina-to-Chile pipeline to them have continued to progress and we expect to complete the sale in mid-2009. We continue to monitor and evaluate the potential impact that regional and political events in Bolivia and Argentina could have on our investments in these pipeline projects, as further discussed in our 2008 Annual Report on Form 10-K. As new information becomes available or future material developments arise, we may be required to record an impairment of our investments.

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

     The information contained in Item 2 updates, and you should read it in conjunction with, information disclosed in our 2008 Annual Report on Form 10-K, and the financial statements and notes presented in Item 1 of this Quarterly Report on Form 10-Q.

Overview and Outlook

     During the quarter ended March 31, 2009, our pipeline operations continued to provide a strong base of earnings and operating cash flow. In our pipeline business, approximately three-fourths of the revenues are collected in the form of demand or reservation charges which are not dependent upon commodity prices or throughput levels. We remain focused on implementing the nearly $8 billion backlog of committed pipeline growth projects, with several of those projects expected to commence service in 2009.

     In our exploration and production business, we continued to generate significant positive operating cash flow during the quarter despite a low commodity price environment, principally as a result of derivatives we have in place related to our 2009 production. As of March 31, 2009, we had 120 TBtu of natural gas hedges with an average floor price of $9.02 per MMBtu and an average ceiling price of $14.35 per MMBtu and 1,348 MBbls of crude oil swaps at $45 per barrel on our remaining anticipated 2009 production. However, lower natural gas prices at the end of the first quarter of 2009 resulted in approximately $2.1 billion of non-cash ceiling test charges, primarily in our domestic full cost pool, which significantly impacted our overall first quarter 2009 results. The ceiling test charges did not consider the value of our financial derivative contracts which was $573 million as of March 31, 2009. If commodity prices decrease further and we do not experience anticipated further reductions in oilfield service costs, we may be required to record additional non-cash ceiling test charges in the future.

     In both of our core businesses, we have implemented various cost saving measures to reduce our capital, operating, and general and administrative costs. These measures include reducing drilling activity in our exploration and production business until we experience further expected reductions in oilfield service costs, realizing cost reductions in our capital and maintenance programs by renegotiating contracts with contractors, suppliers and service providers, and deferring and eliminating various discretionary costs.

     The volatility in the financial markets, the energy industry and the global economy is expected to continue for the remainder of 2009 and possibly beyond. This could impact our longer-term access to capital for future growth projects as well as the cost of such capital, and may require us to further adjust our current financing and business plans. Additionally, commodity prices for natural gas and oil have been and are expected to remain volatile, and although we have attempted to mitigate the effects of these reductions in commodity prices by entering into derivative contracts on our natural gas and oil production, we still have a portion of our production subject to the current lower commodity price environment as further described below. Finally, while the impacts are difficult to quantify, a continued downward trend in the global economy could have adverse impacts on natural gas consumption and demand over time. All of these factors may impact our outlook for the remainder of 2009 and beyond.

     As of March 31, 2009, we had approximately $3.3 billion of available liquidity (see Liquidity and Capital Resources) and have designed our 2009 plans to address the impacts of current volatility in the global financial markets. Based on our activities to date, we do not anticipate a need to further access the capital markets to meet our 2009 debt maturities or fund our 2009 capital program, regardless of whether we are successful in obtaining equity partners on any of our capital projects. When prudent, however, we will continue to be opportunistic in building liquidity to meet our long-term capital needs. There are no assurances, however, that we will be able to access the financial markets to fund our long-term capital needs. Our 2009 plans are also designed to retain our long-term growth potential, including our committed pipeline project backlog and our core domestic and international drilling programs, as well as our natural gas and oil resource positions. In light of the current volatility of the financial markets, the energy industry and the global economy, it is possible additional adjustments to our plan and outlook will be required which could impact our financial and operating performance.

     Currently, these plans include:

	•		Capital Expenditures. Planned 2009 capital expenditures between approximately $2.7 billion to $3.0 billion, with $1.7 billion of capital being spent in our pipeline business and $0.9 billion to $1.2 billion in our exploration and production business. Our $1.7 billion of planned pipeline capital reflects equity partnering on one or more of our expansion projects. In our exploration and production business, although it will also impact our near-term growth profile in this business, the objective of reductions in our capital program is to retain substantially all of our existing natural gas and oil resource positions for future exploration and production when commodity prices and oilfield service costs return to more favorable levels.
	•		Asset Sales. We have sold or are evaluating the sale of several non-core assets generating cash proceeds of approximately $0.4 billion in 2009, of which approximately $0.2 billion have already been completed.
	•		Other Liquidity Sources. We will continue to be opportunistic in generating additional liquidity, which may include additional asset sales or partnering opportunities on expansion projects. To the extent these opportunities are delayed or cannot be completed, there is a further decline in commodity prices or we experience other major disruptions in the financial markets, we could also pursue other alternatives, including additional reductions in our discretionary capital program, further reductions in operating and general and administrative expenses, additional secured financing arrangements, seeking additional partners for one or more of our other growth projects or selling additional non-core assets.

               Our plans were determined based on a number of factors, the most significant of which are described below and in further detail in our 2008 Annual Report on Form 10-K:

	•		Debt Capital Structure. Our debt capital structure is 82 percent fixed interest rates and 18 percent floating interest rates. Accordingly, we believe we have lessened exposure to market changes in interest rates on our existing debt which impact our interest costs.
	•		Revenue and Price Sensitivities. As previously discussed, we have mitigated our sensitivity to commodity prices with approximately three-fourths of our pipeline revenues collected in the form of demand or reservation charges and derivative contracts in our exploration and production business. As noted above, we have significant derivative contracts in place for our 2009 natural gas and oil production. We have also entered into derivative contracts on a substantial portion of our anticipated 2010 natural gas production and a portion of our 2011 natural gas production to mitigate exposure to low commodity prices; however, we continue to have some commodity price exposure in 2010 and beyond. Finally, in the event of lower oil or natural gas prices, we currently have unencumbered exploration and production properties and reserves that we could pledge as collateral to maintain our current available borrowing base under the revolving credit facilities at our exploration and production subsidiary.
	•		Counterparty Risk. We continue to monitor the financial situation of our major lenders, derivative counterparties, customers, joint interest partners, vendors and suppliers, and enforce our contractual rights with regard to obtaining collateral or providing credit.
	•		Lending Institutions. As of March 31, 2009, we have determined the potential exposure to a loss of available capacity under our credit agreements, due to our assessment of our lenders’ ability to fund, to be approximately $30 million from El Paso’s $1.5 billion revolving credit facility, approximately $2 million from EPEP’s $1.0 billion revolving credit facility, and approximately $15 million under EPB’s $750 million credit facility.

Segment Results

     We have two core operating business segments, Pipelines and Exploration and Production. We also have a Marketing segment that markets our natural gas and oil production and manages our legacy trading activities and a Power segment that has interests in power and pipeline assets in South America and Asia. Our segments are managed separately, provide a variety of energy products and services, and require different technology and marketing strategies. Our corporate activities include our general and administrative functions, as well as other miscellaneous businesses, contracts and assets all of which are immaterial.

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

     Below is a reconciliation of our EBIT (by segment) to our consolidated net income (loss) for the quarters ended March 31:

		2009				2008
		(In millions)
Segment
Pipelines		$	396			$	381
Exploration and Production			(1,685	)			242
Marketing			52				(60	)
Power			4				(2	)
Segment EBIT			(1,233	)			561
Corporate and other			(7	)			39
Consolidated EBIT			(1,240	)			600
Interest and debt expense			(255	)			(233	)
Income taxes			526				(148	)
Net income (loss) attributable to El Paso Corporation			(969	)			219
Net income attributable to noncontrolling interests			12				9
Net income (loss)		$	(957	)		$	228