e10vq

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
		For the quarterly period ended March 31, 2007
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to .

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 1001 Louisiana Street Houston, Texas		77002 (Zip Code)
(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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ Accelerated filer o Non-accelerated filer 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 registrant’s classes of common stock, as of the latest practicable date.

Common Stock, par value $3 per share. Shares outstanding on May 4, 2007: 700,240,771

EL PASO CORPORATION
TABLE OF CONTENTS


Caption			Page

PART I — FINANCIAL INFORMATION
	Item 1.	Financial Statements		1
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		22
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		40
	Item 4.	Controls and Procedures		41

PART II — OTHER INFORMATION
	Item 1.	Legal Proceedings		42
	Item 1A.	Risk Factors		42
		Cautionary Statements for Purposes of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995		42
	Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		42
	Item 3.	Defaults Upon Senior Securities		42
	Item 4.	Submission of Matters to a Vote of Security Holders		42
	Item 5.	Other Information		43
	Item 6.	Exhibits		43
		Signatures		44
Ratio of Earnings to Combined Fixed Charges
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

Below is a list of terms that are common to our industry and used throughout this document:


/d	= per day	Mcfe	= thousand cubic feet of natural gas equivalents
Bbl	= barrels	MMBtu	= million British thermal units
BBtu	= billion British thermal units	MMcf	= million cubic feet
LNG	= liquefied natural gas	MMcfe	= million cubic feet of natural gas equivalents
MBbls	= thousand barrels	NGL	= natural gas liquids
Mcf	= thousand cubic feet	TBtu	= trillion British thermal units

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 March 31,
	2007			2006

Operating revenues	$	1,022		$	1,337

Operating expenses
Cost of products and services		55			62
Operation and maintenance		301			285
Depreciation, depletion and amortization		271			250
Taxes, other than income taxes		60			57

		687			654

Operating income		335			683
Earnings from unconsolidated affiliates		37			29
Loss on debt extinguishment		(201	)		(6	)
Other income, net		45			50
Interest and debt expense		(283	)		(331	)

Income (loss) before income taxes from continuing operations		(67	)		425
Income taxes		(19	)		124

Income (loss) from continuing operations		(48	)		301
Discontinued operations, net of income taxes		677			55

Net income		629			356
Preferred stock dividends		9			10

Net income available to common stockholders	$	620		$	346

Basic earnings (loss) per common share
Income (loss) from continuing operations	$	(0.08	)	$	0.44
Discontinued operations, net of income taxes		0.97			0.09

Net income per common share	$	0.89		$	0.53

Diluted earnings (loss) per common share
Income (loss) from continuing operations	$	(0.08	)	$	0.42
Discontinued operations, net of income taxes		0.97			0.07

Net income per common share	$	0.89		$	0.49

Dividends declared per common share	$	0.04		$	0.04

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions, except share amounts)
(Unaudited)


	March 31,			December 31,
	2007			2006

LIABILITIES AND STOCKHOLDERS’ EQUITY



Current liabilities
Accounts payable
Trade	$	367		$	478
Affiliates		2			3
Other		552			569
Current maturities of long-term financing obligations		403			1,360
Liabilities from price risk management activities		338			278
Liabilities related to discontinued operations		—			1,817
Accrued interest		233			269
Other		1,074			1,377

Total current liabilities		2,969			6,151

Long-term financing obligations, less current maturities		11,263			13,329

Other
Liabilities from price risk management activities		947			924
Deferred income taxes		1,047			950
Other		1,718			1,690

		3,712			3,564

Commitments and contingencies
Securities of subsidiaries		22			31

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 706,100,142 shares in 2007 and 705,833,206 shares in 2006		2,118			2,118
Additional paid-in capital		4,769			4,804
Accumulated deficit		(2,315	)		(2,940	)
Accumulated other comprehensive loss		(446	)		(343	)
Treasury stock (at cost); 7,771,602 shares in 2007 and 8,715,288 shares in 2006		(179	)		(203	)

Total stockholders’ equity		4,697			4,186

Total liabilities and stockholders’ equity	$	22,663		$	27,261

See accompanying notes.

EL PASO CORPORATION

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)
(Unaudited)


	Quarters Ended March 31,
	2007			2006

Cash flows from operating activities
Net income	$	629		$	356
Less income from discontinued operations, net of income taxes		677			55

Net income (loss) before discontinued operations		(48	)		301
Adjustments to reconcile net income to net cash from operating activities
Depreciation, depletion and amortization		271			250
Deferred income tax expense (benefit)		(18	)		121
Earnings from unconsolidated affiliates, adjusted for cash distributions		37			9
Loss on debt extinguishment		201			6
Other		(2	)		15
Asset and liability changes		(93	)		160

Cash provided by continuing activities		348			862
Cash provided by (used in) discontinued activities		(35	)		89

Net cash provided by operating activities		313			951

Cash flows from investing activities
Capital expenditures		(783	)		(373	)
Net proceeds from the sale of assets and investments		38			59
Other		2			22

Cash used in continuing activities		(743	)		(292	)
Cash provided by (used in) discontinued activities		3,678			(28	)

Net cash provided by (used in) investing activities		2,935			(320	)

Cash flows from financing activities
Net proceeds from issuance of long-term debt		1,424			—
Payments to retire long-term debt and other financing obligations		(4,654	)		(946	)
Dividends paid		(37	)		(36	)
Contributions from discontinued operations		3,360			59
Other		(3	)		—

Cash provided by (used in) continuing activities		90			(923	)
Cash used in discontinued activities		(3,643	)		(61	)

Net cash used in financing activities		(3,553	)		(984	)

Change in cash and cash equivalents		(305	)		(353	)
Cash and cash equivalents
Beginning of period		537			2,132

End of period	$	232		$	1,779

See accompanying notes.

EL PASO CORPORATION

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)


1.	Basis of Presentation and Significant Accounting Policies

Basis of Presentation

We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the United States Securities and Exchange Commission (SEC). Because this is an interim period filing presented using a condensed format, it does not include all of the disclosures required by U.S. generally accepted accounting principles. You should read this Quarterly Report on Form 10-Q along with our 2006 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, 2007, and for the quarters ended March 31, 2007 and 2006, are unaudited. We derived the condensed consolidated balance sheet as of December 31, 2006, from the audited balance sheet filed in our 2006 Annual Report on Form 10-K. 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 results of operations for the entire year. Our results for all periods reflect ANR Pipeline Company (ANR), our Michigan storage assets and our 50 percent interest in Great Lakes Gas Transmission (Great Lakes), as well as our Macae power facility in Brazil as discontinued operations. Additionally, our financial statements for prior periods include reclassifications that were made to conform to the current period presentation. Those reclassifications did not impact our reported net income or stockholders’ equity.

Significant Accounting Policies

The information below provides updating information with respect to our significant accounting policies and accounting pronouncements issued but not yet adopted discussed in our 2006 Annual Report on Form 10-K.

Accounting for Uncertainty in Income Taxes. On January 1, 2007, we adopted Financial Accounting Standards Board (FASB) Interpretation (FIN) No. 48, Accounting for Uncertainty in Income Taxes and its related interpretation. FIN No. 48 clarifies Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for Income Taxes, and requires us to evaluate our tax positions for all jurisdictions and for all years where the statute of limitations has not expired. FIN No. 48 requires companies to meet a “more-likely-than-not” threshold (i.e. greater than a 50 percent likelihood of a tax position being sustained under examination) prior to recording a benefit for their tax positions. Additionally, for tax positions meeting this “more-likely-than-not” threshold, the amount of benefit is limited to the largest benefit that has a greater than 50 percent probability of being realized upon ultimate settlement. For further information on the impact on our financial statements of the adoption of this interpretation, see Note 3.

Accounting for Offsetting Contractual Amounts. In April 2007, the FASB issued FASB Staff Position (FSP) No. FIN 39-1. The FSP amends FASB Interpretation No. 39, Offsetting of Amounts Related to Certain Contracts, and allows companies to offset amounts recorded for the fair value of derivative contracts with the related amounts of cash collateral posted or held if the contracts are executed with the same counterparty under the same master netting arrangement. This pronouncement is effective for fiscal years beginning after November 15, 2007, although early application is permitted. We are currently evaluating the impact of this pronouncement on our assets and liabilities from price risk management contracts and amounts recorded for broker margin and deposits.


2.	Divestitures

Under SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, we classify assets to be disposed of as held for sale or, if appropriate, discontinued operations when they have received appropriate approvals to be disposed of by our management or Board of Directors and when they meet other criteria. Cash flows from our discontinued businesses are reflected as discontinued operating, investing, and financing activities in our statement of cash flows. To the extent these operations do not maintain separate cash balances, we reflect the net cash flows generated from these businesses as a contribution to our continuing operations in cash from continuing

financing activities. As of December 31, 2006, we had total assets of $4.1 billion and total liabilities of $1.8 billion related to our discontinued operations, the composition of which is disclosed in our 2006 Annual Report on Form 10-K. We also had $28 million of assets held for sale as of December 31, 2006. As of March 31, 2007, all of our assets and liabilities related to our discontinued operations and our assets held for sale had been sold. The following is a description of each of our discontinued operations:

ANR and Related Operations. During the first quarter of 2007, we sold ANR, our Michigan storage assets and our 50 percent interest in Great Lakes to TransCanada Corporation and TC Pipeline, LP for net cash proceeds of approximately $3.7 billion and recorded a gain of approximately $651 million, net of taxes of $356 million on the sale. Included in the net assets of these discontinued operations as of the date of the sale were net deferred tax liabilities assumed by TransCanada.

International Power Operations. During 2006, we completed the sale of all of our discontinued international power operations for net proceeds of approximately $368 million including our interest in Macae, a wholly owned power plant facility in Brazil, and certain power assets in Asia and Central America.

Below is summarized income statement information regarding our discontinued operations:


	ANR and			International
	Related			Power
	Operations			Operations			Total
	(In millions)

Quarter Ended March 31, 2007
Revenues	$	101		$	—		$	101
Costs and expenses		(43	)		—			(43	)
Other expense⁽¹⁾		(7	)		—			(7	)
Interest and debt expense		(10	)		—			(10	)
Income taxes		(15	)		—			(15	)

Income from operations		26			—			26
Gain on sale, net of income taxes of $356 million		651			—			651

Net income from discontinued operations	$	677		$	—		$	677

Quarter Ended March 31, 2006
Revenues	$	194		$	50		$	244
Costs and expenses		(77	)		(65	)		(142	)
Other income		15			—			15
Interest and debt expense		(17	)		(7	)		(24	)
Income taxes		(41	)		3			(38	)

Net income (loss) from discontinued operations	$	74		$	(19	)	$	55


⁽¹⁾		Includes a loss of approximately $19 million associated with the extinguishment of certain debt obligations.


3.	Income Taxes

Income taxes included in our income (loss) from continuing operations for the quarters ended March 31 were as follows:


	2007			2006
	(In millions, except rates)

Income taxes	$	(19	)	$	124
Effective tax rate		28	%		29	%

We compute our quarterly 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, which may

include the conclusion of income tax audits, are recorded in the period that the specific item occurs. During both the first quarter of 2007 and 2006, our overall effective tax rate on continuing operations was different than the statutory rate of 35 percent primarily due to state income taxes (net of federal income tax effects) and earnings/losses from unconsolidated affiliates where we anticipate receiving dividends. Additionally, during the first quarter of 2006, our overall effective tax rate on continuing operations was different than the statutory rate of 35 percent due to the conclusion of IRS audits resulting in the reduction of tax contingencies of $16 million.

We file income tax returns in the U.S. federal jurisdiction, and various state and foreign jurisdictions. With a few exceptions, we are no longer subject to U.S. federal, state and local, or non-U.S. income tax examinations by tax authorities for years before 1999. Certain issues raised on examination by tax authorities on El Paso’s 2003 and 2004 federal tax years are currently being appealed. For our open tax years, we have unrecognized tax benefits (liabilities for uncertain tax matters) which could increase or decrease our income tax expense and effective income tax rates as these matters are finalized.

Upon the adoption of FIN No. 48, we recorded additional liabilities for unrecognized tax benefits of $2 million, including interest and penalties, which we accounted for as an increase of $4 million to the January 1, 2007 accumulated deficit and an increase of $2 million to additional paid in capital. The additional amounts recorded increased our overall unrecognized tax benefits (including interest and penalties) to $178 million as of January 1, 2007. Of this amount, approximately $109 million (net of federal tax benefits) would favorably affect our income tax expense and our effective income tax rate if recognized in future periods. While the amount of our unrecognized tax benefits could change in the next twelve months, we do not expect this change to have a significant impact on our results of operations or financial position.

We recognize accrued interest and penalties related to unrecognized tax benefits in income tax expense on our income statement. Total accrued interest and penalties recognized in our income statement was not material for the quarters ended March 31, 2007 and 2006. As of January 1, 2007 and March 31, 2007, we had approximately $39 million and $41 million of liabilities for interest and penalties related to our unrecognized tax benefits.


4.	Earnings Per Share

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


	2007						2006
	Basic			Diluted			Basic			Diluted
	(In millions, except per share amounts)

Income (loss) from continuing operations	$	(48	)	$	(48	)	$	301		$	301
Convertible preferred stock dividends		(9	)		(9	)		(10	)		—
Interest on trust preferred securities		—			—			—			2

Income (loss) from continuing operations available to common stockholders		(57	)		(57	)		291			303
Discontinued operations, net of income taxes		677			677			55			55

Net income available to common stockholders	$	620		$	620		$	346		$	358

Weighted average common shares outstanding		694			694			656			656
Effect of dilutive securities:
Options and restricted stock		—			—			—			3
Convertible preferred stock		—			—			—			57
Trust preferred securities		—			—			—			8

Weighted average common shares outstanding and dilutive securities		694			694			656			724

Earnings per common share:
Income (loss) from continuing operations	$	(0.08	)	$	(0.08	)	$	0.44		$	0.42
Discontinued operations, net of income taxes		0.97			0.97			0.09			0.07

Net income	$	0.89		$	0.89		$	0.53		$	0.49

We exclude potentially dilutive securities (such as employee stock options, restricted stock, convertible preferred stock, and trust preferred securities) from the determination of diluted earnings per share (as well as their related income statement impacts) when their impact on income from continuing operations per common share is antidilutive. For the quarter ended March 31, 2007, we incurred losses from continuing operations 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, 2006, certain employee stock options and our zero coupon convertible debentures (redeemed in April 2006) were antidilutive. For a further discussion of our potentially dilutive securities, see our 2006 Annual Report on Form 10-K.


5.	Price Risk Management Activities

The following table summarizes the carrying value of the derivatives used in our price risk management activities as of March 31, 2007 and December 31, 2006. In the table, derivatives designated as accounting hedges consist of instruments used to hedge our natural gas and oil production. Other commodity-based derivative contracts relate to derivative contracts not designated as accounting hedges, such as options and swaps, other natural gas and power purchase and supply contracts, and derivatives from our historical energy trading activities. Interest rate and foreign currency derivatives consist of swaps that are primarily designated as hedges of our interest rate and foreign currency risk on long-term debt.


	March 31,			December 31,
	2007			2006
	(In millions)

Net assets (liabilities):
Derivatives designated as accounting hedges	$	(86	)	$	61
Other commodity-based derivative contracts⁽¹⁾		(932	)		(456	)

Total commodity-based derivatives		(1,018	)		(395	)
Interest rate and foreign currency derivatives		43			43

Net liabilities from price risk management activities	$	(975	)	$	(352	)


⁽¹⁾		During the first quarter of 2007, we settled contracts associated with approximately $381 million of our assets from price risk management activities by applying the related cash margin we held against amounts due under those contracts. This non-cash transaction is not reflected in our statement of cash flows.


6.	Long-Term Financing Obligations and Other Credit Facilities


	March 31,		December 31,
	2007		2006
	(In millions)

Current maturities of long-term financing obligations	$	403	$	1,360
Long-term financing obligations		11,263		13,329

Total	$	11,666	$	14,689

Changes in Long-Term Financing Obligations. During the quarter ended March 31, 2007, 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 Exploration and Production Company (EPEP) revolving credit facility	variable	$	255		$	255
El Paso revolving credit facility	variable		675			675
Southern Natural Gas (SNG) notes	5.900%		500			494

Increases through March 31, 2007		$	1,430		$	1,424

Repayments, repurchases, and other
Notes/Other
El Paso	6.375%-10.75%	$	(2,837	)	$	(3,011	)
El Paso - Euro	7.125%		(157	)		(165	)
SNG	6.700%		(52	)		(52	)
SNG	8.875%		(398	)		(418	)
Other	various		(9	)		(8	)

			(3,453	)		(3,654	)

Revolving Credit Facilities
EPEP	variable		(200	)		(200	)
El Paso	variable		(800	)		(800	)

			(1,000	)		(1,000	)

Decreases through March 31, 2007		$	(4,453	)	$	(4,654	)

In the first quarter of 2007, we recorded a $201 million pre-tax loss on the extinguishment of certain of the debt repurchased above. In April 2007, we issued $355 million of El Paso Natural Gas Company (EPNG) 5.95% notes due in 2017 and repaid approximately $301 million of EPNG 7.625% notes.

Approximately $100 million of our debt obligations are redeemable at the option of the holders in the second quarter of 2007, which is prior to its stated maturity date. As a result, these amounts are classified as current liabilities in our balance sheet as of March 31, 2007. In addition, approximately $7 billion of our debt obligations (increasing to approximately $9 billion by the end of 2008) provide us the ability to call the debt prior to its stated maturity date. If redeemed prior to their stated maturities, we will be required to pay a make-whole or fixed premium in addition to repaying the principal and accrued interest.

Prior to their redemption in 2006, we recorded accretion expense on our zero coupon debentures. During the quarter ended March 31, 2006, we redeemed $612 million of our zero coupon debentures, of which $110 million represented an increase in the principal balance of long-term debt due to the accretion of interest on the debentures we redeemed. We account for these redemptions as financing activities in our statement of cash flows.

Credit Facilities

Credit Agreements. As of March 31, 2007, we had available capacity under our credit agreements of approximately $1.1 billion. Of this amount, approximately $0.3 billion is related to the $500 million revolving credit agreement of our subsidiary, EPEP, and approximately $0.8 billion is available under our $1.75 billion credit agreement and our $500 million unsecured revolving credit facility. As a result of upgrades to our credit ratings, we can now borrow funds under the $1.75 billion credit agreement at rates of LIBOR plus 1.25% or issue letters of credit at a rate of 1.40%. The commitment fee on any unused capacity under the $1.25 billion revolving credit facility of that agreement is 0.25%.

Contingent Letter of Credit Facility. In January 2007, we entered into a $250 million unsecured contingent letter of credit facility that matures in March 2008. Letters of credit are available to us under the facility if the average NYMEX gas price strip for the remaining calendar months through March 2008 is equal to or exceeds $11.75 per MMBtu. The facility fee, if triggered, is 1.66% per annum.

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, 2007, we had outstanding letters of credit of approximately $1.5 billion of which approximately $1.0 billion secures our recorded obligations related to price risk management activities.


7.	Commitments and Contingencies

Legal Proceedings

Shareholder Litigation. Twenty-eight purported shareholder class action lawsuits have been pending since 2002 and are consolidated in federal court in Houston, Texas. The consolidated lawsuit alleges violations of federal securities laws against us and several of our current and former officers and directors. In November 2006, the parties executed a definitive settlement agreement in which the parties agreed to settle these class action lawsuits. Pursuant to the terms of the settlement, El Paso contributed approximately $48 million, its insurers have contributed approximately $225 million and a third party contributed $12 million into an escrow account. The settlement was approved by the court in the first quarter of 2007 and became final in April 2007.

ERISA Class Action Suits. 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 misrepresentations and omissions similar to those pled in the consolidated shareholder litigation that caused members of the class to hold and maintain investments in El Paso stock in violation of the Employee Retirement Income Security Act (ERISA). A briefing schedule has been set for dispositive motions. We have insurance coverage for this lawsuit, subject to certain deductibles and co-pay obligations. We have established accruals for these matters 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. Certain plaintiff’s claims that our cash balance plan violated ERISA were recently dismissed by the trial court. Our costs and legal exposure related to this lawsuit are not currently determinable.

Retiree Medical Benefits Matters. We currently serve as the plan administrator for a medical benefits plan that covers a closed group of retirees of the Case Corporation who retired on or before July 1, 1994. Case was formerly a subsidiary of Tenneco, Inc. that was spun off prior to our acquisition of Tenneco in 1996. Tenneco retained the obligation to provide certain medical and prescription drug benefits to eligible retirees and their spouses. We assumed this obligation as a result of our merger with Tenneco. Pursuant to an agreement with the applicable union for Case employees, our liability for these benefits was subject to a cap, such that costs in excess of the cap are assumed by plan participants. In 2002, we and Case were sued by individual retirees in a federal court in Detroit, Michigan in an action entitled Yolton et al. v. El Paso Tennessee Pipeline Co. and Case Corporation. The suit alleges, among other things, that El Paso and Case violated ERISA and that they should be required to pay all amounts above the cap. Case further filed claims against El Paso asserting that El Paso is obligated to indemnify, defend and hold Case harmless for the amounts it would be required to pay. In separate rulings in 2004, the court ruled that, pending a trial on the merits, Case must pay the amounts incurred above the cap and that El Paso must reimburse Case for those payments. In January 2006, these rulings were upheld on appeal by the U.S. Court of Appeals for the 6th Circuit. We will proceed with a trial on the merits with regard to the issues of whether the cap is enforceable and what degree of benefits have actually vested. Until this is resolved, El Paso will indemnify Case for any payments Case makes above the cap, which are currently about $1.8 million per month. We continue to defend the action and have filed for approval by the trial court various amendments to the medical benefit plans which would allow us to deliver the benefits to plan participants in a more cost effective manner. Although it is uncertain what plan amendments will ultimately be approved, the approval of plan amendments could reduce our overall costs

and, as a result, could reduce our recorded obligation. We have established an accrual for this matter which we believe is adequate.

Natural Gas Commodities Litigation. Beginning in August 2003, several lawsuits have been filed against El Paso Marketing L.P. (EPM) that allege 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 cases have been consolidated in federal court in New York for all pre-trial purposes and are styled In re: Gas Commodity Litigation. In September 2005, the court certified the class to include all persons who purchased or sold NYMEX natural gas futures between January 1, 2000 and December 31, 2002. A settlement has been finalized with the plaintiffs and funded subject to final court approval. The second set of cases, involving similar allegations on behalf of commercial and residential customers, were transferred to a multi-district litigation proceeding (MDL) in the U.S. District Court for Nevada, In re: Western States Wholesale Natural Gas Antitrust Litigation, dismissed and have been appealed. The third set of cases also involve similar allegations on behalf of certain purchasers of natural gas. These include 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. v. AEP Energy Services Inc., et al. (filed in federal court for the Eastern District of California in June 2005); Farmland Industries, Inc. v. Oneok Inc. (filed in state court in Wyandotte County, Kansas in July 2005); Learjet, Inc. v. Oneok Inc., (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), 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), Arandell, et al. v. Xcel Energy, et al. (filed in the circuit court of Dane County, Wisconsin in December 2006) and Heartland, et al. v. Oneok Inc., et al. (filed in the circuit court of Buchanan County, Missouri in March 2007). The Leggett and Farmland cases have been dismissed, subject to appeal. The Arandell and Missouri Public Service cases have been removed to federal court. The Heartland case has only recently been filed. The remaining cases have all been transferred to the MDL proceeding. Similar motions to dismiss have either been filed or are anticipated to be filed in these cases as well. Our costs and legal exposure related to these 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, which has 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 May 2005, a representative appointed by the court issued a recommendation to dismiss most of the actions. In October 2006, the U.S. District Judge issued an order dismissing all mismeasurement claims against all defendants. An appeal has been filed.

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 claim are not currently determinable.

MTBE. Certain of our subsidiaries used the gasoline additive methyl tertiary-butyl ether (MTBE) in some of their gasoline. Certain subsidiaries have also produced, bought, sold and distributed MTBE. A number of lawsuits have been filed throughout the U.S. regarding MTBE’s potential impact on water supplies. Some of our subsidiaries are among the defendants in 78 such lawsuits. These suits have been consolidated for pre-trial purposes in multi- district litigation in the U.S. District Court for the Southern District of New York. The plaintiffs, certain state attorneys general, various water districts and a limited number of individual water customers, generally seek remediation of their groundwater, prevention of future contamination, damages, punitive damages, attorney’s fees and court costs. Among other allegations, plaintiffs assert that gasoline containing MTBE is a defective product and that defendant refiners are liable in proportion to their market share. The court has ordered that the parties engage in

mediation proceedings to attempt to settle the case. Our costs and legal exposure related to these lawsuits are not currently determinable.

Government Investigations and Inquiries

Reserve Revisions. In March 2004, we received a subpoena from the SEC requesting documents relating to our December 31, 2003 natural gas and oil reserve revisions. We continue to cooperate with the SEC in its investigation related to such reserve revisions.

Iraq Oil Sales. Several government agencies have been investigating The Coastal Corporation’s and El Paso’s purchases of crude oil from Iraq under the United Nations’ Oil for Food Program. These agencies include the U.S. Attorney for the Southern District of New York (SDNY), the SEC and the Office of Foreign Assets Control (OFAC). In February 2007, we entered into agreements with the SDNY, SEC , and OFAC to resolve their pending investigations of our participation in the Oil for Food Program. Pursuant to those agreements we paid approximately $8 million, with approximately $6 million intended to be ultimately transferred to a humanitarian fund for the benefit of the Iraqi people.

Other Government Investigations. We continue to provide information and cooperate with the inquiry or investigation of the U.S. Attorney and the SEC in response to requests for information regarding price reporting of transactional data to the energy trade press and the hedges of our natural gas production.

Other Contingencies

EPNG Rate Case. In June 2005, EPNG filed a rate case with the FERC proposing an increase in revenues of 10.6 percent or $56 million annually over current tariff rates, new services and revisions to certain terms and conditions of existing services. On January 1, 2006, the rates became effective, subject to refund. In March 2006, the FERC issued an order that generally approved our proposed new services, which were implemented on June 1, 2006. In December 2006, EPNG filed settlement of this rate case with the FERC. The settlement provides benefits for both EPNG and its customers for a three-year period ending December 31, 2008. Only one party in the rate case contested the settlement. The administrative law judge has certified the settlement to the FERC finding that the settlement could be approved for all parties or in the alternative that the contesting party could be severed from the settlement. We have reserved sufficient amounts to meet EPNG’s refund obligations under the settlement. Such refunds will be payable within 120 days after approval by the FERC.

Iraq Imports. In December 2005, the Ministry of Oil for the State Oil Marketing Organization of Iraq (SOMO) sent an invoice to one of our subsidiaries with regard to shipments of crude oil that SOMO alleged were purchased and paid for by Coastal in 1990. The invoice requests an additional $144 million for such shipments, along with an allegation of an undefined amount of interest. The invoice appears to be associated with cargoes that Coastal had purchased just before the 1990 invasion of Kuwait by Iraq. We have requested additional information from SOMO to further assist in our evaluation of the invoice and the underlying facts. In addition, we are evaluating our legal defenses, including applicable statute of limitation periods.

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. An interim agreement with the Navajo Nation expired at the end of December 2006. Negotiations on the terms of the long-term agreement are continuing. In addition, we continue to preserve other legal, regulatory and legislative alternatives, which includes continuing to pursue our application with the Department of the Interior for renewal of our rights-of-way on Navajo Nation lands. It is uncertain whether our negotiation, or other alternatives, will be successful, or if successful, what the ultimate cost will be of obtaining the rights-of-way and whether we will be able to recover these costs in our rates.

In addition to the above legal proceedings, governmental proceedings, and other contingent matters, we and our subsidiaries and affiliates are named defendants in numerous lawsuits and governmental proceedings 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 our outstanding legal and other contingent matters, we evaluate the

merits of the case, 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. However, it is possible 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, 2007, we had approximately $531 million accrued, net of related insurance receivables, for outstanding legal and other contingent matters.

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. As of March 31, 2007, we have accrued approximately $295 million, which has not been reduced by $31 million for amounts to be paid directly under government sponsored programs. Our accrual includes approximately $286 million for expected remediation costs and associated onsite, offsite and groundwater technical studies and approximately $9 million for related environmental legal costs. Of the $295 million accrual, $28 million was reserved for facilities we currently operate and $267 million was reserved for non-operating sites (facilities that are shut down or have been sold) and Superfund sites.

Our reserve estimates range from approximately $295 million to approximately $516 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 ($23 million). Second, where the most likely outcome cannot be estimated, a range of costs is established ($272 million to $493 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, 2007
Sites	Expected		High
	(In millions)

Operating	$	28	$	34
Non-operating		233		423
Superfund		34		59

Total	$	295	$	516

Below is a reconciliation of our accrued liability from January 1, 2007 to March 31, 2007 (in millions):


Balance as of January 1, 2007	$	314
Additions/adjustments for remediation activities		8
Payments for remediation activities		(27	)

Balance as of March 31, 2007	$	295

For the remainder of 2007, we estimate that our total remediation expenditures will be approximately $62 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 $26 million in the aggregate for the remainder of 2007 through 2011. These expenditures primarily relate to compliance with clean air regulations.

CERCLA Matters. 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 50 active

sites under the 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. As of March 31, 2007, we have estimated our share of the remediation costs at these sites to be between $34 million and $59 million. 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 Indemnifications

We are involved in various joint ventures and other ownership arrangements that sometimes require additional financial support that results in the issuance of financial and performance guarantees. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnification for income taxes, the resolution of existing disputes, environmental matters, and necessary expenditures to ensure the safety and integrity of the assets sold.

Our potential exposure under the 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. For those arrangements with a specified dollar amount, we have a maximum stated value of approximately $811 million, for which we are indemnified by third parties for $15 million. These amounts exclude guarantees for which we have issued related letters of credit discussed in Note 6. Included in the above maximum stated value is approximately $440 million related to indemnification arrangements associated with the sale of ANR, and related operations and approximately $120 million related to tax matters, related interest and other indemnifications and guarantees arising out of the sale of our Macae power facility. As of March 31, 2007, we have recorded obligations of $85 million related to our guarantees and indemnification arrangements, of which $11 million is related to ANR and related assets and Macae. We are unable to estimate a maximum exposure for our guarantee and indemnification agreements that do not provide for limits on the amount of future payments under the agreement due to the uncertainty of these exposures.

In addition to the exposures described above, a trial court has ruled, which was upheld on appeal, that we are required to indemnify a third party for benefits being paid to a closed group of retirees of one of our former subsidiaries. We have a liability of approximately $364 million associated with our estimated exposure under this matter as of March 31, 2007. For a further discussion of this matter, see Retiree Medical Benefits Matters above.


8.	Retirement Benefits

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


							Other
							Postretirement
	Pension Benefits						Benefits
	2007			2006			2007			2006
	(In millions)

Service cost	$	5		$	4		$	—		$	—
Interest cost		30			29			6			7
Expected return on plan assets		(45	)		(44	)		(4	)		(4	)
Amortization of net actuarial loss		10			14			—			—
Amortization of prior service cost⁽¹⁾		(1	)		—			—			—
Special termination benefits⁽²⁾		6			—			—			—

Net benefit cost	$	5		$	3		$	2		$	3


⁽¹⁾		As permitted, the amortization of any prior service cost is determined using a straight-line amortization of the cost over the average remaining service period of employees expected to receive benefits under the plan.

⁽²⁾		Relates to providing enhanced benefits to former ANR employees, which is included in discontinued operations in our income statement.

In December 2006, we adopted the recognition provisions of SFAS No. 158, Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — an amendment of FASB Statements No. 87, 88, 106 and 132(R) and began reflecting assets and liabilities related to our pension and other postretirement benefit plans based on their funded or unfunded status and reclassifying all actuarial deferrals as a component of accumulated other comprehensive income. In March 2007, the FERC issued guidance requiring regulated pipeline companies to recognize a regulatory asset or liability for the funded status asset or liability that would otherwise be recorded in accumulated other comprehensive income under SFAS No. 158, if it is probable that amounts calculated on the same basis as SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions would be included in rates in future periods. Upon adoption of this FERC guidance, we reclassified approximately $4 million from the beginning balance of accumulated other comprehensive income to other non-current assets and liabilities on our balance sheet.

During the three months ended March 31, 2007 and 2006, we made $8 million and $11 million of cash contributions to our Supplemental Benefits Plan and other postretirement benefit plans. We also made $2 million in cash contributions to our pension plans for the quarter ended March 31, 2007. We expect to contribute an additional $4 million to the Supplemental Benefits Plan and $27 million to our other postretirement benefit plans for the remainder of 2007. Contributions to our pension plans will be approximately $1 million for the remainder of 2007.


9.	Stockholders’ Equity

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


		Convertible
	Common Stock	Preferred Stock
	($0.04/Share)	(4.99%/Year)

Amount paid through March 31, 2007	$28	$9
Amount paid in April 2007	$27	$9
Declared subsequent to March 31, 2007:
Date of declaration	April 3, 2007	April 3, 2007
Date payable	July 2, 2007	July 2, 2007
Payable to shareholders on record	June 1, 2007	June 15, 2007

Dividends on our common stock are treated as a reduction of additional paid-in-capital since we currently have an accumulated deficit. We expect dividends paid on our common and preferred stock in 2007 will be taxable to our stockholders because we anticipate they 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 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 our fixed charge ratio were to exceed the permitted maximum level, our ability to pay additional dividends would be restricted.


10.	Business Segment Information

As of March 31, 2007, our business consists of Pipelines, Exploration and Production, Marketing and Power segments. We have reclassified certain operations as discontinued operations for all periods presented (see Notes 1 and 2). 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 operations 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, 2007, we conducted our activities primarily through seven wholly owned and four partially owned interstate transmission systems along with two underground natural gas storage entities and an LNG terminalling facility.

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

Marketing. Focuses on marketing and managing the price risks associated with our natural gas and oil production as well as the management of our remaining historical trading portfolio.

Power. Focuses primarily on managing the risks associated with our remaining international power assets, primarily in Brazil, Asia and Central America. We continue to pursue the sale of our remaining international power assets.

Our management uses earnings before interest expense and income taxes (EBIT) to assess the operating results and effectiveness of our business segments which consist of both consolidated businesses as well as substantial investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to more effectively evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income or loss adjusted for (i) items that do not impact our income or loss from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) preferred dividends. Also, we exclude interest and debt expense so that 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 and other performance measures such as operating income or operating cash flow. Below is a reconciliation of our EBIT to our income (loss) from continuing operations for the quarters ended March 31:


	2007			2006
	(In millions)

Segment EBIT	$	426		$	756
Corporate and other		(210	)		—
Interest and debt expense		(283	)		(331	)
Income taxes		19			(124	)

Income (loss) from continuing operations	$	(48	)	$	301

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


	Segment
			Exploration and								Corporate
	Pipelines		Production			Marketing			Power		and Other⁽¹⁾			Total
			(In millions)

2007
Revenue from external customers	$	631	$	220	⁽²⁾	$	159		$	—	$	12		$	1,022
Intersegment revenue		13		285	⁽²⁾		(294	)		—		(4	)		—
Operation and maintenance		161		110			—			4		26			301
Depreciation, depletion, and amortization		94		170			1			—		6			271
Earnings (losses) from unconsolidated affiliates		26		(1	)		—			11		1			37
EBIT		364		179			(135	)		18		(210	)		216
2006
Revenue from external customers	$	629	$	81	⁽²⁾	$	598		$	1	$	28		$	1,337
Intersegment revenue		14		385	⁽²⁾		(393	)		—		(6	)		—
Operation and maintenance		168		88			3			14		12			285
Depreciation, depletion, and amortization		93		146			1			—		10			250
Earnings (losses) from unconsolidated affiliates		16		7			—			7		(1	)		29
EBIT		346		199			208			3		—			756


⁽¹⁾		Includes eliminations of intercompany transactions. Our intersegment revenues, along with our intersegment operating expenses, were incurred in the normal course of business between our operating segments. During the quarters ended March 31, 2007 and 2006, we recorded an intersegment revenue elimination of $5 million and $6 million.

⁽²⁾		Revenues from external customers include gains and losses related to our hedging of price risk associated with our natural gas and oil production. Intersegment revenues represent sales to our Marketing segment, which is responsible for marketing our production.

Total assets by segment are presented below:


	March 31,		December 31,
	2007		2006
	(In millions)

Pipelines	$	13,171	$	13,105
Exploration and Production		6,422		6,262
Marketing and Trading		727		1,143
Power		630		618

Total segment assets		20,950		21,128
Corporate		1,713		2,000
Discontinued operations		—		4,133

Total consolidated assets	$	22,663	$	27,261


11.	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. Our income statement typically reflects (i) our share of net earnings directly attributable to these unconsolidated affiliates, and (ii) impairments and other adjustments recorded by us. During the quarters ended March 31, 2007 and 2006, we received distributions and dividends of $74 million and $36 million, which includes less than $1 million of returns of capital, from our investments. 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
							Unconsolidated
							Affiliates
Net investment and earnings (losses)	Investment						Quarter Ended
	March 31,			December 31,			March 31,
	2007			2006			2007			2006
	(In millions)						(In millions)

Domestic:
Four Star⁽¹⁾	$	703		$	723		$	(1	)	$	7
Citrus		571			597			22			10
Other		38			36			—			—
Foreign:
Bolivia to Brazil Pipeline		108			105			3			1
Manaus/Rio Negro⁽²⁾		93			96			4			6
Porto Velho⁽³⁾		(32	)		(34	)		2			(3	)
Asian and Central American Investments⁽³⁾⁽⁴⁾		27			27			—			1
Other⁽³⁾		163			157			7			7

Total	$	1,671		$	1,707		$	37		$	29


⁽¹⁾		Amortization of our purchase cost in excess of the underlying net assets of Four Star was $14 million during each of the quarters ended March 31, 2007 and 2006. For a further discussion, see our 2006 Annual Report on Form 10-K.

⁽²⁾		We will transfer ownership of these plants to the power purchaser in January 2008.

⁽³⁾		As of March 31, 2007 and December 31, 2006, we had outstanding advances and notes receivable of $381 million and $380 million related to our foreign investments of which $360 million and $350 million related to our investment in Porto Velho. We recognized interest income on these outstanding advances and notes receivable of approximately $12 million and $11 million for the three months ended March 31, 2007 and 2006.

⁽⁴⁾		We have received approval from our Board of Directors to sell our interest in these investments, all of which are expected to be sold in 2007.


Summarized financial information	Quarter Ended March 31,
	2007		2006
	(In millions)

Operating results data:
Operating revenues	$	189	$	305
Operating expenses		111		263
Income (loss) from continuing operations		51		(19	)
Net income (loss)⁽¹⁾		51		(19	)


⁽¹⁾		Includes net income of $5 million for each of the quarters ended March 31, 2007 and 2006, related to our proportionate share of affiliates in which we hold greater than a 50 percent interest.


	Quarter Ended
Revenues and charges with unconsolidated affiliates	March 31,
	2007		2006
	(In millions)

Operating revenue⁽¹⁾	$	1	$	34
Other income		1		2
Interest income		12		11


⁽¹⁾		Decrease primarily due to the sale of investments in our Power segment.

Matters that Could Impact Our Investments

The following information is a discussion of significant matters that could impact certain of our investments.

Porto Velho. As of March 31, 2007, our total investment (including advances to the project) and guarantees related to this project was approximately $329 million. The state-owned facility that purchases power generated by the facility in Brazil has approached us with the opportunity to sell them our interest in this power plant. Although we currently have no indications of an impairment of our investment, as we evaluate this opportunity, we could be required to record a loss based on the value we may receive. In December 2006, the Brazilian tax authorities assessed a $30 million fine against the Porto Velho power project for allegedly not filing the proper tax forms related to the consumption of fuel by the power facility under its power purchase agreement. We believe this claim by the tax authority is without merit.

Asian and Central American power investments. As of March 31, 2007, our total investment (including advances to the projects) and guarantees related to these projects was approximately $93 million. We are in the process of selling these assets. Any changes in the political and economic conditions could negatively impact the amount of net proceeds we expect to receive upon their sale, which may result in additional impairments.

Investment in Bolivia. We own an 8 percent interest in the Bolivia to Brazil pipeline. As of March 31, 2007, our total investment and guarantees related to this pipeline project was approximately $120 million, of which the Bolivian portion was $3 million. In 2006, the Bolivian government announced a decree significantly increasing its interest in and control over Bolivia’s oil and gas assets. We continue to monitor and evaluate, together with our partners, the potential commercial impact that recent political events in Bolivia could have on the Bolivia to Brazil pipeline. As new information becomes available or future material developments arise, we may be required to record an impairment of our investment.

Investment in Argentina. We own an approximate 22 percent interest in the Argentina to Chile pipeline. As of March 31, 2007, our total investment in this pipeline project was approximately $24 million. In July 2006, the Ministry of Economy and Production in Argentina issued a decree that significantly increases the export taxes on natural gas. We continue to evaluate, together with our partners, the potential commercial impact that this decree could have on the Argentina to Chile pipeline. As new information becomes available or future material developments arise, we may be required to record an impairment of our investment.


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 2006 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

Financial Update. During the first three months of 2007, our pipeline operations continued to provide a strong base of earnings and cash flow and make progress on expansion projects. Our exploration and production business continued to execute on its drilling programs resulting in higher production levels in the first quarter of 2007, consistent with the levels originally expected for the quarter and higher when compared to the same period in 2006. During the first quarter of 2007, our financial results were also marked by several significant events including the completion of the sale of ANR and related assets in which we recorded a gain of approximately $651 million (net of taxes of $356 million), and the repurchase of approximately $3.5 billion of debt on which we recorded a pre-tax loss of $201 million due to the extinguishment of certain of these obligations.

We have strengthened our credit metrics in 2007 through various financing activities including the repurchases mentioned above as well as refinancing a portion of EPNG and SNG’s debt that provides us with a lower cost of capital and an investment grade covenant package on that debt. Additionally, our credit ratings were upgraded by both Moody’s and Standard & Poor’s and Fitch Ratings initiated coverage on El Paso in the first quarter of 2007. For further information on these debt repurchases and changes to our credit ratings, see our Liquidity and Capital Resources discussion.

What to Expect Going Forward. In our pipeline operations, we will continue with our expansion projects in our primary growth areas and anticipate that our remaining pipeline operations will continue to provide strong operating results throughout the year based on the current levels of contracted capacity, continued success in re-contracting, expansion plans in our market and supply areas and the status of rate and regulatory actions. As previously announced, we are pursuing the formation of a master limited partnership in 2007 to enhance the value and financial flexibility of our pipeline assets and provide a lower-cost source of capital for new projects.

In our exploration and production business, we will continue to seek to create value through a disciplined and balanced capital investment program, through active management of the cost of production services, portfolio management and a focus on delivering reserves and volumes at reasonable finding and operating costs. Our future financial results in this business will be primarily dependent on continued successful execution of our drilling programs. These results may also be impacted by changes in commodity prices to the extent our anticipated natural gas and oil production is unhedged. We have currently hedged a substantial portion of our remaining anticipated 2007 natural gas production and a portion of our anticipated natural gas production for 2008 and forward and continue to evaluate opportunities to effectively manage our commodity price risk.

Segment Results

Below are our results of operations (as measured by earnings before interest expense and income taxes (EBIT)) by segment. Our business segments consist of our Pipelines, Exploration and Production, Marketing and Power segments. These 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 EBIT to assess the operating results and effectiveness of our business segments, which consist of both consolidated businesses as well as substantial investments in unconsolidated affiliates. We believe EBIT is useful to our investors because it allows them to more effectively evaluate our operating performance using the same performance measure analyzed internally by our management. We define EBIT as net income or loss adjusted for (i) items that do not impact our income or loss from continuing operations, such as extraordinary items, discontinued operations and the impact of accounting changes, (ii) income taxes, (iii) interest and debt expense and (iv) preferred dividends. Also, we exclude interest and debt expense so that 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 and other performance measures such as operating income or operating cash flow. Below is a reconciliation of our EBIT (by segment) to our consolidated net income for the quarters ended March 31:


	2007			2006
	(In millions)

Segment
Pipelines	$	364		$	346
Exploration and Production		179			199
Marketing		(135	)		208
Power		18			3

Segment EBIT		426			756
Corporate and other		(210	)		—

Consolidated EBIT		216			756
Interest and debt expense		(283	)		(331	)
Income taxes		19			(124	)

Income (loss) from continuing operations		(48	)		301
Discontinued operations, net of income taxes		677			55

Net income	$	629		$	356

Pipelines Segment

Operating Results. Below are the operating results for our Pipelines segment as well as a discussion of factors impacting EBIT for the periods ending March 31, 2007 and 2006, or that could potentially impact EBIT in future periods.


	2007			2006
	(In millions, except volume amounts)

Operating revenues	$	644		$	643
Operating expenses		(320	)		(322	)

Operating income		324			321
Other income		40			25

EBIT	$	364		$	346

Throughput volumes (BBtu/d)⁽¹⁾		18,040			16,620


⁽¹⁾		Throughput volumes include volumes associated with our proportionate share of unconsolidated affiliates.


	Quarter Ended March 31,
	Variance
	Revenue			Expense			Other		EBIT
	Impact			Impact			Impact		Impact
	Favorable/(Unfavorable)
	(In millions)

Expansions	$	8		$	(1	)	$	2	$	9
Lower reservation and usage revenues		(6	)		—			—		(6	)
Operational gas and revaluations		—			(10	)		—		(10	)
Hurricanes Katrina and Rita		—			6			—		6
Gain on sale of asset in 2007		—			7			—		7
Equity earnings from Citrus		—			—			12		12
Other⁽¹⁾		(1	)		—			1		—

Total impact on EBIT	$	1		$	2		$	15	$	18


⁽¹⁾		Consists of individually insignificant items on several of our pipeline systems.

Expansions. During the quarter ended March 31, 2007, our reservation revenues and throughput volumes were higher than the same period in 2006 primarily due to the Elba Island LNG and Piceance Basin expansion projects completed during the first quarter of 2006.

We have several expansion projects approved by the FERC in various stages of completion including our Louisiana Deepwater Link, Triple-T Extension, Essex Middlesex Project, Northeast Connexion — New England and Cypress Expansion projects. In May 2007, we placed the Cypress pipeline into service which is estimated to have an annual EBIT contribution of approximately $32 million.

Lower Reservation and Usage Revenues. During the quarter ended March 31, 2007, our overall reservation and usage revenues were lower than the same period in 2006. Usage revenues decreased in 2007 due to reduced activity under certain interruptible services primarily on our TGP system and a higher provision for rate refunds on our EPNG system in 2007. However, our EBIT was favorably impacted in 2007 due to higher volumes on our pipeline systems, mainly the CIG system, due to cold weather and transportation services to new power plants. Additionally, CIG experienced increased revenues due to higher rates that went into effect in October 2006.

Operational Gas and Revaluations. Our net gas imbalances and other gas owed to customers are revalued each period. During the quarter ended March 31, 2007, our EBIT decreased from the same period in 2006 due to these revaluations. During the first quarter of 2007, natural gas prices increased unfavorably impacting our results. Additionally, natural gas prices decreased during the first quarter of 2006 favorably impacting our results during

that period. We anticipate that the overall activity in this area will continue to vary based on factors such as regulatory actions, some of which have already been implemented, the efficiency of our pipeline operations, natural gas prices and other factors.

Hurricanes Katrina and Rita. During the first quarter of 2007, we incurred lower operation and maintenance expenses to repair damage caused by Hurricanes Katrina and Rita as compared to the same period in 2006. For a further discussion of the impact of these hurricanes on our capital expenditures, see Liquidity and Capital Resources.

Gain on sale of asset. In February 2007, Tennessee Gas Pipeline Company completed the sale of a lateral for approximately $35 million and recorded a pretax gain on the sale of approximately $7 million.

Equity earnings from Citrus. Our equity earnings increased by approximately $12 million, $8 million of which was due to a favorable settlement of litigation brought against Spectra LNG Sales (formerly Duke Energy LNG Sales, Inc.) related to the wrongful termination of a gas supply contract.

Regulatory Matters/Rate Cases. Our pipeline systems periodically file for changes in their rates, which are subject to the approval of the FERC. Changes in rates and other tariff provisions resulting from these regulatory proceedings have the potential to positively or negatively impact our profitability.


	•	EPNG — In December 2006, EPNG filed a settlement of its rate case with the FERC providing benefits for both EPNG and its customers for a three year period ending December 31, 2008. Under the terms of the settlement, EPNG is required to file a new rate case effective January 1, 2009. EPNG’s recorded income amounts currently reflect their proposed rates and we have reserved sufficient amounts to meet EPNG’s refund obligations under this settlement. For a further discussion, see Item 1, Financial Statements, Note 7.

	•	Mojave Pipeline (MPC) — In February 2007, as required by its prior rate case settlement, MPC filed with the FERC a general rate case proposing a 33 percent decrease in its base tariff rates resulting from a variety of factors, including a decline in rate base and various changes in rate design since the last rate case. No new services were proposed. We anticipate a decrease in revenues of approximately $13 million annually due to Mojave’s reduced base rates. The new base rates were effective March 1, 2007 and are subject to further adjustment upon the outcome of the hearing.

Exploration and Production Segment

Overview and Strategy

Our Exploration and Production segment conducts our natural gas and oil exploration and production activities. Our profitability and performance in this segment are driven by the ability to locate and develop economic natural gas and oil reserves and extract those reserves with the lowest possible production and administrative costs. Accordingly, we manage this business with the goal of creating value through disciplined capital allocation, cost control and portfolio management. Our domestic natural gas and oil reserve portfolio blends slower decline rate, typically longer lived assets in our Onshore region, with steeper decline rate, shorter lived assets in our Texas Gulf Coast and Gulf of Mexico Shelf and south Louisiana regions. We believe the combination of our assets in these regions provides significant near-term cash flows while providing consistent opportunities for competitive investment returns. In addition, our international activities in Brazil and Egypt provide opportunity for additional future reserve additions and longer term cash flows. For a further discussion of our business and strategy, see our 2006 Annual Report on Form 10-K.

Operating Results for the Quarter Ended March 31, 2007

Average Daily Production. Our average daily production for the three months ended March 31, 2007, was 750 MMcfe/d (excluding 70 MMcfe/d from our equity investment in Four Star). Our average daily production levels in the first quarter of 2007 were consistent with the levels originally expected for the quarter and have increased as compared to the same period in 2006. Below is a further analysis of our production by region for the quarters ended March 31:


	2007		2006
	(MMcfe/d)

United States
Onshore		363		334
Texas Gulf Coast		189		195
Gulf of Mexico Shelf/south Louisiana		182		133
International
Brazil		16		32

Total Consolidated		750		694

Four Star⁽¹⁾		70		71


⁽¹⁾		Amounts represent our proportionate share of the production of Four Star.

In our Onshore region, our 2007 production increased through capital projects where we maintained or increased production in most of our major operating areas, with the majority of growth coming from the Rockies. In the Texas Gulf Coast region, our 2007 production volumes remained stable as the acquisition of properties in the first quarter of 2007 mostly offset natural production declines and the sale of certain non-strategic south Texas properties in 2006. In the Gulf of Mexico Shelf/south Louisiana region, we increased production in 2007 through development projects in the West Cameron area and our Catapult project and recovery of volumes shut-in by hurricane damage, which helped to offset natural production declines. In Brazil, production volumes decreased primarily due to a contractual reduction of our ownership interest in the Pescada-Arabaiana fields in early 2006.

Drilling

Onshore. We realized a 100 percent success rate on 152 gross wells drilled.

Texas Gulf Coast. We experienced a 91 percent success rate on 23 gross wells drilled.

Gulf of Mexico Shelf and south Louisiana. We drilled two unsuccessful wells in the first quarter of 2007, but expect to place four to eight wells in production for the remainder of 2007.

Brazil. In the Pinauna Field in the Camamu Basin, we began drilling two exploratory wells. Additionally, we began drilling an exploration well with Petrobras in the ES-5 Block in the Espirito Santo Basin. These three exploratory wells are expected to reach their targeted zones and be evaluated by the third quarter of 2007.

Egypt. In April 2007, we received formal government approval and signed the concession agreement for the South Mariut Block. We paid $3 million for the concession and agreed to a $22 million firm working commitment over three years. The block is approximately 1.2 million acres and is located onshore in the western part of the Nile Delta.

Cash Operating Costs. We monitor the cash operating costs required to produce our natural gas and oil volumes. These costs are generally reported on a per Mcfe basis and include total operating expenses less depreciation, depletion and amortization expense and cost of products and services on our income statement. During the three months ended March 31, 2007, cash operating costs increased to $1.99/Mcfe as compared to $1.71/Mcfe for the same period in 2006, primarily as a result of higher production costs from higher workover activity levels, industry inflation in services, labor and material costs and lower severance tax credits.

Capital Expenditures. Our total natural gas and oil capital expenditures on an accrual basis were $606 million for the quarter ended March 31, 2007, including $254 million to acquire producing properties and undeveloped acreage in Zapata County, Texas in January 2007. The acquisition in Zapata County complements our existing Texas Gulf Coast operations and provides a re-entry into the Lobo area.

Outlook

For the full year 2007, we anticipate the following on a worldwide basis:


	•	Average daily production volumes of approximately 740 MMcfe/d to 795 MMcfe/d, which excludes approximately 60 MMcfe/d to 65 MMcfe/d from our equity investment in Four Star.

	•	Capital expenditures, excluding acquisitions, between $1.4 billion and $1.5 billion. While 85% of the planned 2007 capital program is allocated to our domestic program, we plan to invest approximately $215 million internationally during 2007, primarily in our Brazil exploration and development program.

	•	Average cash operating costs which include production costs, general and administrative expenses and taxes (other than production and income) of approximately $1.68/Mcfe to $2.00/Mcfe; and

	•	Depreciation, depletion, and amortization rate between $2.50/Mcfe and $2.75/Mcfe.

Price Risk Management Activities

As part of our strategy, we enter into derivative contracts on our natural gas and oil production to stabilize cash flows, to reduce the risk and financial impact of downward commodity price movements on commodity sales and to protect the economic assumptions associated with our capital investment programs. Because this strategy only partially reduces our exposure to downward movements in commodity prices, our reported results of operations, financial position and cash flows can be impacted significantly by movements in commodity prices from period to period. Adjustments to our hedging strategy and the decision to enter into new positions or to alter existing positions are made based on the goals of the overall company.

In March 2007, we entered into additional floor and ceiling option contracts on approximately 44 TBtu of our anticipated 2008 natural gas production. The following table reflects the contracted volumes and the minimum, maximum and average prices we will receive under our derivative contracts when combined with the sale of the underlying hedged production as of March 31, 2007:


	Fixed Price												Basis
	Swaps⁽¹⁾				Floors⁽¹⁾				Ceilings⁽¹⁾				Swaps⁽¹⁾⁽²⁾
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes

Natural Gas
2007		59	$	7.71		41	$	8.00		41	$	16.89		83
2008		5	$	3.42		44	$	8.00		44	$	10.53		—
2009		5	$	3.56		—		—		—		—		—
2010-2012		11	$	3.81		—		—		—		—		—
Oil
2007		144	$	35.15		—		—		—		—		—


⁽¹⁾		Volumes presented are TBtu for natural gas and MBbl for oil. Prices presented are per MMBtu of natural gas and per Bbl of oil.

⁽²⁾		Our basis swaps effectively “lock-in” locational price differences on a portion of our natural gas production in Texas and Oklahoma.

Our natural gas fixed price swaps, floors and ceiling contracts in the table above are designated as accounting hedges. Gains and losses associated with these natural gas contracts are deferred in accumulated other comprehensive income and will be recognized in earnings upon the sale of the related production at market prices, resulting in a realized price that is approximately equal to the hedged price. Our oil fixed price swaps and approximately 39 TBtu of our natural gas basis swaps are not designated as accounting hedges. Accordingly, changes in the fair value of these swaps are not deferred, but are recognized in earnings each period.

The table above does not include (i) net realized gains on derivative contracts we previously accounted for as hedges on which we will record an additional $45 million as natural gas and oil revenues for the remainder of 2007, which are also currently deferred in accumulated other comprehensive income or (ii) contracts entered into by our Marketing segment as further described in that segment. For the consolidated impact of the entirety of El Paso’s production-related price risk management activities on our liquidity, see the discussion of factors that could impact our liquidity in Liquidity and Capital Resources.


					Percent
	2007		2006		Variance

Consolidated volumes, prices and costs per unit:
Natural gas
Volumes (MMcf)		56,713		52,029		9	%
Prices ($/Mcf)
Average realized prices including hedges	$	7.19	$	7.03		2	%
Average realized prices excluding hedges	$	6.46	$	7.77		(17	)%
Average transportation costs ($/Mcf)	$	0.31	$	0.24		29	%
Oil, condensate and NGL
Volumes (MBbls)		1,788		1,745		2	%
Prices ($/Bbl)
Average realized prices including hedges	$	49.32	$	51.25		(4	)%
Average realized prices excluding hedges	$	50.07	$	52.60		(5	)%
Average transportation costs ($/Bbl)	$	0.76	$	1.25		(39	)%
Total equivalent volumes
MMcfe		67,442		62,500		8	%
MMcfe/d		750		694		8	%
Production costs and other cash operating costs ($/Mcfe)
Average lease operating costs	$	0.95	$	0.73		30	%
Average production taxes		0.32		0.29		10	%

Total production costs⁽¹⁾		1.27		1.02		25	%
Average general and administrative expenses		0.69		0.67		3	%
Average taxes, other than production and income		0.03		0.02		50	%

Total cash operating costs	$	1.99	$	1.71		16	%

Unit of production depletion cost ($/Mcfe)	$	2.40	$	2.20		9	%

Unconsolidated affiliate volumes (Four Star)
Natural gas (MMcf)		4,941		4,507
Oil, condensate and NGL (MBbls)		233		309
Total equivalent volumes
MMcfe		6,338		6,360
MMcfe/d		70		71


⁽¹⁾		Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes).

Quarter Ended March 31, 2007 Compared to Quarter Ended March 31, 2006

The table below outlines the variances in our operating results for the quarter ended March 31, 2007 as compared to the same period in 2006:


	Variances
	Operating			Operating
	Revenues			Expenses			Other			EBIT
	Favorable/(Unfavorable)
	(In millions)

Natural Gas Revenues
Lower realized prices in 2007	$	(74	)	$	—		$	—		$	(74	)
Impact of hedges		80			—			—			80
Higher production volumes in 2007		36			—			—			36
Oil, Condensate and NGL Revenues
Lower realized prices in 2007		(5	)		—			—			(5	)
Impact of hedges		1			—			—			1
Higher production volumes in 2007		2			—			—			2
Other Revenues
Change in fair value of derivatives not designated as accounting hedges		2			—			—			2
Other		(3	)		—			—			(3	)
Depreciation, Depletion and Amortization Expense
Higher depletion rate in 2007		—			(13	)		—			(13	)
Higher production volumes in 2007		—			(11	)		—			(11	)
Production Costs
Higher lease operating costs in 2007		—			(18	)		—			(18	)
Higher production taxes in 2007		—			(4	)		—			(4	)
General and Administrative Expenses		—			(4	)		—			(4	)
Other		—			(3	)		(6	)		(9	)

Total Variances	$	39		$	(53	)	$	(6	)	$	(20	)

Operating revenues. In 2007, our revenues increased as compared to 2006 primarily due to the success in our drilling program which resulted in higher production volumes as previously discussed. Offsetting the positive impact of higher production volumes were reduced prices as compared to 2006. However, the effect of our hedging program somewhat mitigated the impact of price declines as gains on hedging settlements were $40 million during the first quarter of 2007 as compared to losses of $41 million in the first quarter of 2006.

Depreciation, depletion and amortization expense. During the first quarter of 2007, our depletion rate increased as compared to the same period in 2006 as a result of higher finding and development costs due to service cost inflation, mechanical problems in executing our drilling program during 2006 and downward revisions in previous estimates of reserves due to lower commodity prices.

Production costs. In the first quarter of 2007, our lease operating costs increased as compared to the same period in 2006 due to higher workover activity levels, industry inflation in services, labor and material costs and lower severance tax credits.

General and administrative expenses. Our general and administrative expenses increased during 2007 as compared to the same period in 2006, primarily due to higher labor costs.

Other. During the first quarter of 2007, Four Star’s equity earnings decreased by $8 million as compared to the same period in 2006 due to lower natural gas prices, higher production costs and higher depreciation, depletion, and amortization expense.

Marketing Segment

Overview. Our Marketing segment markets our Exploration and Production segment’s natural gas and oil production and manages the company’s overall price risks, primarily through the use of natural gas and oil derivative contracts. This segment also continues to manage and liquidate our remaining historical natural gas supply, transportation, power and other natural gas contracts entered into prior to the deterioration of the energy trading environment in 2002. To the extent it is economical to do so, we may liquidate certain of these remaining historical contracts before their expiration, which could affect our operating results in future periods . For a further discussion of our contracts in this segment including our expected earnings volatility by contract type, see our 2006 Annual Report on Form 10-K.

Operating Results. During the quarter ended March 31, 2007, we generated an EBIT loss of $135 million primarily driven by mark-to-market changes in the fair value of our options and swaps intended to manage the price risk of the company’s natural gas and oil production. We also incurred losses resulting from our remaining positions in our historical natural gas and power books and from terminating a gas supply contract as part of the continued efforts to reduce our exposure to these contracts. Below is further information about our overall operating results during each of the quarters ended March 31:


	2007			2006
	(In millions)

Gross Margin by Significant Contract Type:
Production-Related Natural Gas and Oil Derivative Contracts
Changes in fair value of derivatives	$	(87	)	$	162

Gross margin		(87	)		162

Contracts Related to Historical Trading Operations:
Natural gas transportation-related natural gas contracts:
Demand charges		(27	)		(35	)
Settlements		20			20
Changes in fair value of other natural gas derivative contracts		(24	)		47
Changes in fair value of power contracts		(17	)		11

Gross margin⁽¹⁾		(48	)		43

Total gross margin		(135	)		205
Operating expenses		(1	)		(5	)

Operating income (loss)		(136	)		200
Other income, net		1			8

EBIT	$	(135	)	$	208


⁽¹⁾		Gross margin consists of revenues from commodity marketing activities less costs of commodities sold, including changes in the fair value of derivative contracts.

Production-related Natural Gas and Oil Derivative Contracts

Options and swaps. Our production-related natural gas and oil derivative contracts are designed to provide protection to El Paso against changes in natural gas and oil prices. These are in addition to those contracts entered into by our Exploration and Production segment which are further discussed in that segment. For the consolidated impact of all of El Paso’s production-related price risk management activities, refer to our Liquidity and Capital Resources discussion. Our production-related derivatives consist of various option contracts which are

marked-to-market in our results each period based on changes in commodity prices. Listed below are the volumes and average prices associated with our production-related derivative contracts as of March 31, 2007:


	Floors⁽¹⁾				Ceilings⁽¹⁾
			Average				Average
	Volumes		Price		Volumes		Price

Natural Gas
2007		67	$	7.50		—	$	—
2008		18	$	6.00		18	$	10.00
2009		17	$	6.00		17	$	8.75
Oil
2007		744	$	55.00		744	$	59.86
2008		930	$	55.00		930	$	57.03


⁽¹⁾		Volumes presented are TBtu for natural gas and MBbl for oil. Prices presented are per MMBtu of natural gas and per Bbl of oil.

We experience volatility in our financial results based on changes in the fair value of our option contracts which generally move in the opposite direction from changes in commodity prices. During the quarter ended March 31, 2007, increases in commodity prices reduced the fair value of our option contracts resulting in a loss on these contracts, while in the quarter ended March 31, 2006, decreases in commodity prices increased the fair value of our option contracts resulting in a gain on these contracts. However, during the quarter ended March 31, 2007, we received cash of approximately $17 million on contracts that settled during the period, while in the quarter ended March 31, 2006, we paid approximately $13 million for contracts that settled during the period.

Contracts Related to Historical Trading Operations

Natural gas transportation-related contracts. As of March 31, 2007, our transportation contracts provide us with approximately 0.8 Bcf/d of pipeline capacity that require us to pay approximately $83 million in demand charges for the remainder of 2007. Effective November 1, 2007, our Alliance capacity will transfer to a third party and our demand charges will be reduced to an average of $46 million annually from 2008 to 2011. The recovery of demand charges and profitability of our transportation contracts is dependent upon our ability to use or remarket the contracted pipeline capacity, which is impacted by a number of factors as described in our 2006 Annual Report on Form 10-K. These transportation contracts are accounted for on an accrual basis and impact our gross margin as delivery or service under the contracts occurs. The following table is a summary of our demand charges (in millions) and our percentage of recovery of these charges for the quarters ended March 31:


	2007			2006

Alliance:
Demand charges	$	16		$	16
Recovery		48	%		19	%
Other:
Demand charges	$	11		$	19
Recovery		100	%		87	%

Other natural gas derivative contracts. In addition to our transportation-related natural gas contracts, we have other contracts with third parties that require us to purchase or deliver natural gas primarily at market prices. During 2006, we divested or entered into transactions to divest of a substantial portion of these natural gas contracts, which substantially reduced our future cash and earnings exposure to price movements on these contracts. During the quarter ended March 31, 2007, we assigned a weather call derivative which had required us to supply gas in the northeast region if temperatures fell to specific levels resulting in a charge of $13 million. During the quarter ended March 31, 2006, we recognized a $49 million gain associated with the assignment of certain natural gas derivative contracts to supply natural gas in the southeastern U.S.

Power Contracts. Our first quarter 2007 losses and first quarter 2006 gains on our power contracts relate to four contracts that require us to swap locational differences in power prices between several power plants in the

Pennsylvania-New Jersey-Maryland (PJM) eastern region with the PJM west hub, and provide installed capacity in the PJM power pool. During 2005 and 2006, we entered into contracts that eliminated the commodity risk associated with these contracts. A dispute has arisen with a downstream purchaser with regard to the region within PJM that capacity must be made available under one of our remaining power contracts. Although we believe that we are entitled to make such capacity available at any delivery point within the PJM power pool, if we are restricted to delivering such capacity in particular regions, the fair value of that power contract and our operating results could be negatively impacted.

Power Segment

Our Power segment consists of assets in Brazil, Asia and Central America. We continue to pursue the sales of these remaining power investments. As of March 31, 2007, our remaining investment, guarantees and letters of credit related to power projects in this segment totaled approximately $662 million which consisted of approximately $624 million in equity investments and notes receivable and approximately $38 million in financial guarantees and letters of credit, as follows (in millions):


Area	Amount

Brazil
Porto Velho	$	329
Manaus & Rio Negro		95
Pipeline projects		145
Asia & Central America		93

Total investment, guarantees and letters of credit	$	662

Brazil. We continue to evaluate the potential opportunity to sell our interest in our Porto Velho project to the power purchaser who has expressed an interest in acquiring our interest in the plant. Additionally, we are continuing to monitor other matters that could impact our other Brazilian investments as further described in Item 8, Financial Statements and Supplementary Data, Note 18 of our 2006 Annual Report on Form 10-K.

Asia and Central America. We continue to pursue the sale of our four remaining investments in Asia and Central America. Until the sale of these investments is completed, any changes in regional political and economic conditions could negatively impact the anticipated proceeds, which could result in additional impairments of our investments.

Operating Results. During the quarters ended March 31, 2007 and 2006, our Power segment generated EBIT of $18 million and $3 million, primarily from our Porto Velho project in Brazil which generated EBIT of $13 million and $7 million. In 2006, our operating results were also impacted by operations and impairments of certain domestic and other international operations substantially all of which have been sold. During both periods, we did not recognize earnings from certain of our Asian and Central American assets based on our inability to realize earnings through the expected selling price of these assets.

Corporate and Other Expenses, Net

Our corporate activities include our general and administrative functions as well as a number of miscellaneous businesses, which do not qualify as operating segments and are not material to our current period results. The following is a summary of significant items impacting the EBIT in our corporate operations for the quarters ended March 31:


	2007			2006
	(In millions)

Loss on extinguishment of debt	$	(201	)	$	(6	)
Foreign currency fluctuations on Euro-denominated debt		(2	)		(4	)
Change in litigation, insurance and other reserves		(28	)		(22	)
Other, primarily interest income		21			32

Total EBIT	$	(210	)	$	—

Extinguishment of debt. During the first quarter of 2007, in conjunction with the repurchase of approximately $3.5 billion of our debt obligations, we recorded a $201 million charge in our income statement for the loss on extinguishment of these obligations. For further information on our debt, see Item 1, Financial Statements, Note 6.

Litigation, Insurance, and Other Reserves. We have a number of pending litigation matters and reserves related to our historical business operations. Adverse rulings or unfavorable outcomes or settlements against us related to these matters have impacted and may further impact our future results.

Interest and Debt Expense

Interest and debt expense for the quarter ended March 31, 2007 decreased to $283 million compared to $331 million for the same period in 2006 due primarily to the retirement (net of issuances) of approximately $2.6 billion of debt during 2006. In the first quarter of 2007, we further reduced our debt obligations, net of issuances by an additional $3 billion which should significantly decrease our interest expense in future periods.

Income Taxes


	Quarter Ended March 31,
	2007			2006
	(In millions)

Income taxes from continuing operations	$	(19	)	$	124
Effective tax rate		28	%		29	%

For a discussion of our effective tax rates and other matters impacting our income taxes, see Item 1, Financial Statements, Note 3.

Discontinued Operations

Income from our discontinued operations for the quarters ended March 31, 2007 and 2006, was $677 million and $55 million. In February 2007, we sold ANR, and related operations and recognized a gain in the first quarter of approximately $651 million, net of taxes of $356 million.

Commitments and Contingencies

For a further discussion of our commitments and contingencies, see Item I, Financial Statements, Note 7 which is incorporated herein by reference.

Liquidity and Capital Resources

Sources and Uses of Cash. Our primary sources of cash are cash flow from operations and amounts available to us under revolving credit facilities. In 2007, our sources also include proceeds from asset sales. On occasion and as conditions warrant, we also generate funds through capital market activities. Our primary uses of cash are funding the capital expenditure programs of our pipeline and exploration and production operations, meeting operating needs, and repaying debt when due or repurchasing certain debt obligations when conditions warrant.

Overview of Cash Flow Activities. For the quarters ended March 31, 2007 and 2006, our cash flows of continuing operations are summarized as follows:


	Quarter Ended March 31,
	2007			2006
	(In billions)

Cash Flow from Operations
Continuing operating activities
Net income before discontinued operations	$	—		$	0.3
Loss on debt extinguishment		0.2			—
Other income adjustments		0.3			0.4
Change in other assets and liabilities		(0.1	)		0.2

Total cash flow from operations	$	0.4		$	0.9

Other Cash Inflows
Continuing investing activities
Net proceeds from the sale of assets and investments	$	—		$	0.1

		—			0.1

Continuing financing activities
Net proceeds from the issuance of long-term debt		1.4			—
Contribution from discontinued operations		3.4			—

Total other cash inflows	$	4.8		$	0.1

Cash Outflows
Continuing investing activities
Capital expenditures	$	0.8		$	0.4

		0.8			0.4

Continuing financing activities
Payments to retire long-term debt and other financing obligations		4.7			0.9
Dividends and other		—			0.1

		4.7			1.0

Total cash outflows	$	5.5		$	1.4

Net change in cash	$	(0.3	)	$	(0.4	)

During the first quarter of 2007, we generated positive operating cash flow of approximately $0.4 billion, primarily as a result of cash provided by our pipeline and exploration and production operations less interest paid during the quarter on our debt obligations which includes interest prepaid due to early extinguishment of debt. We utilized this operating cash flow generated and cash from our discontinued operations to fund both maintenance and growth projects in our pipeline and exploration and production operations and reduce our debt obligations (see Item 1, Financial Statements, Note 6). Cash generated from our discontinued operations reflected above consists of the following for the quarter ended March 31, 2007:


	(In billions)

Operating cash flow from discontinued operations	$	—
Proceeds from sale of ANR and related assets		3.7
Payments to retire ANR debt obligations		(0.3	)

Contribution from discontinued operations	$	3.4

Our capital expenditures, including acquisitions for the quarter and the amount we expect to spend for the remainder of 2007 to grow and maintain our businesses are as follows (in billions).


	Quarter Ended
	March 31, 2007		2007 Remaining		Total

Maintenance
Pipelines	$	0.1	$	0.3	$	0.4
Exploration and Production		0.4		0.8		1.2
Growth
Pipelines		0.1		0.5		0.6
Exploration and Production		0.2		0.3		0.5

	$	0.8	$	1.9	$	2.7

The substantial repayment of debt obligations during the first quarter of 2007 was a milestone in improving our credit profile and credit ratings. In March 2007, Moody’s Investor Services upgraded our pipeline subsidiaries’ senior unsecured debt rating to an investment grade rating of Baa3 and upgraded El Paso’s senior unsecured debt rating to Ba3 while maintaining a positive outlook. Additionally, in March 2007, (i) Standard and Poor’s upgraded our pipeline subsidiaries’ senior unsecured debt rating to BB and upgraded El Paso’s senior unsecured debt rating to BB- maintaining a positive outlook and (ii) Fitch Ratings initiated coverage on El Paso assigning a rating of BB+ on our senior unsecured debt and an investment grade rating of BBB- to our pipeline subsidiaries’ senior unsecured debt. Additionally, the refinancing in March and April of 2007 of approximately $750 million of the debt of SNG and EPNG, our subsidiaries, will further improve our credit profile by providing us with a lower cost of borrowing and less restrictive covenants on this debt.

Liquidity/Cash Flow Outlook. For the remainder of 2007, we expect to continue to generate positive operating cash flows. We anticipate using these amounts together with amounts borrowed under credit facilities, proceeds from remaining asset sales, and proceeds from capital market activities, if necessary, for working capital requirements, expected capital expenditures and to repay debt as it matures. We have approximately $0.3 billion of debt that matures through March 31, 2008, and approximately $0.1 billion of debt that the holders can require us to redeem prior to its scheduled maturity in the second quarter of 2007.

Factors That Could Impact Our Future Liquidity. Based on the simplification of our capital structure and our businesses, we have reduced the amount of liquidity needed in the normal course of business. However, our liquidity needs could increase or decrease based on certain factors described below. For a complete discussion of risk factors that could impact our liquidity, see our 2006 Annual Report on Form 10-K.

Price Risk Management Activities and Cash Margining Requirements. Our Exploration and Production and Marketing segments have derivative contracts to provide price protection on a portion of our anticipated natural gas and oil production. As of March 31, 2007, these contracts include new floor and ceiling contracts entered into in the first quarter of 2007 on approximately 44 TBtu of our anticipated 2008 natural gas production. The following table shows the contracted volumes and the minimum, maximum and average cash prices that we will receive under our derivative contracts when combined with the sale of the underlying production as of March 31, 2007. These cash prices may differ from the income impacts of our derivative contracts, depending on whether the contracts are designated as hedges for accounting purposes or not. The individual segment discussions provide additional information on the income impacts of our derivative contracts.


	Fixed Price												Basis
	Swaps⁽¹⁾				Floors⁽¹⁾				Ceilings⁽¹⁾				Swaps⁽¹⁾⁽²⁾
	Volumes		Price		Volumes		Price		Volumes		Price		Volumes

Natural Gas
2007		59	$	7.71		108	$	7.69		41	$	16.89		83
2008		5	$	3.42		62	$	7.42		62	$	10.38		—
2009		5	$	3.56		17	$	6.00		17	$	8.75		—
2010-2012		11	$	3.81		—		—		—		—		—
Oil
2007		144	$	35.15		744	$	55.00		744	$	59.86		—
2008		—		—		930	$	55.00		930	$	57.03		—


⁽¹⁾		Volumes presented are TBtu for natural gas and MBbl for oil. Prices presented are per MMBtu of natural gas and per Bbl of oil.

⁽²⁾		Our basis swaps effectively “lock-in” locational price differences on a portion of our natural gas production in Texas and Oklahoma.

We currently post letters of credit for a substantial portion of the required margin on natural gas fixed price swap contracts that are at prices below current market prices. Historically we were required to post cash margin deposits for these amounts. During the first quarter of 2007, approximately $20 million of posted cash margin deposits were returned to us resulting from settlement of the related contracts. For the remainder of 2007, based on current prices, we expect approximately $0.2 billion of the total of $1.1 billion in collateral outstanding at March 31, 2007 to be returned to us in the form of both cash margin deposits and letters of credit.

Depending on changes in commodity prices, we could be required to post additional margin or recover margin earlier than anticipated. Based on our derivative positions at March 31, 2007, a $0.10/MMBtu increase in the price of natural gas would result in an increase in our margin requirements of approximately $11 million which consists of $3 million for transactions that settle in the remainder of 2007, $5 million for transactions that settle in 2008 and $3 million for transactions that settle in 2009 and thereafter. We have a $250 million unsecured contingent letter of credit facility available to us if the average NYMEX gas price strip for the remaining calendar months through March 2008 reaches $11.75 per MMBtu, which is further described in Item I, Financial Statements, Note 6.

Hurricanes. We continue to repair damages to our pipeline and other facilities caused by Hurricanes Katrina and Rita in 2005. In 2007 and 2008, we expect remaining repair costs of approximately $125 million (a substantial portion of which is capital related) and insurance reimbursements of approximately $195 million for cumulative recoverable costs from our insurers. While our capital expenditures and liquidity may vary from period to period, we do not believe our remaining hurricane related expenditures will materially impact our overall liquidity or financial results.

Commodity-Based Derivative Contracts

We use derivative financial instruments in our Exploration and Production and Marketing segments to manage the price risk of commodities. In the tables below, derivatives designated as accounting hedges primarily consist of collars and swaps used to hedge natural gas production. Other commodity-based derivative contracts relate to derivative contracts not designated as accounting hedges, such as options, swaps and other natural gas and power purchase and supply contracts. The following table details the fair value of our commodity-based derivative contracts by year of maturity and valuation methodology as of March 31, 2007:


	Maturity			Maturity			Maturity			Maturity			Maturity			Total
	Less Than			1 to 3			4 to 5			6 to 10			Beyond			Fair
	1 Year			Years			Years			Years			10 Years			Value
	(In millions)

Derivatives designated as accounting hedges
Assets	$	19		$	14		$	—		$	—		$	—		$	33
Liabilities		(47	)		(40	)		(29	)		(3	)		—			(119	)

Total derivatives designated as accounting hedges		(28	)		(26	)		(29	)		(3	)		—			(86	)

Other commodity-based derivatives
Exchange-traded positions⁽¹⁾
Liabilities		(6	)		(20	)		—			—			—			(26	)
Non-exchange traded positions
Assets		77			65			47			37			9			235
Liabilities		(286	)		(387	)		(253	)		(209	)		(6	)		(1,141	)

Total other commodity-based derivatives		(215	)		(342	)		(206	)		(172	)		3			(932	)

Total commodity-based derivatives	$	(243	)	$	(368	)	$	(235	)	$	(175	)	$	3		$	(1,018	)


⁽¹⁾		These positions are traded on active exchanges such as the New York Mercantile Exchange, the International Petroleum Exchange and the London Clearinghouse.

The following is a reconciliation of our commodity-based derivatives for the quarter ended March 31, 2007:


	Derivatives			Other			Total
	Designated as			Commodity-			Commodity-
	Accounting			Based			Based
	Hedges			Derivatives			Derivatives
	(In millions)

Fair value of contracts outstanding at January 1, 2007	$	61		$	(456	)	$	(395	)

Fair value of contract settlements during the period⁽¹⁾		(29	)		(375	)		(404	)
Change in fair value of contracts		(129	)		(126	)		(255	)
Assignment of contracts		—			25			25
Option premiums paid⁽²⁾		11			—			11

Net change in contracts outstanding during the period		(147	)		(476	)		(623	)

Fair value of contracts outstanding at March 31, 2007	$	(86	)	$	(932	)	$	(1,018	)


⁽¹⁾		During the first quarter of 2007, we settled contracts associated with approximately $381 million of our assets from price risk management activities by applying the related cash margin we held against amounts due under those contracts.

⁽²⁾		Amounts are net of premiums received.


Item 3.	Quantitative And Qualitative Disclosures About Market Risk

This information updates, and you should read it in conjunction with, information disclosed in our Annual Report on Form 10-K, in addition to the information presented in Items 1 and 2 of this Quarterly Report on Form 10-Q.

There are no material changes in our quantitative and qualitative disclosures about market risks from those reported in our Annual Report on Form 10-K, except as presented below:

Commodity Price Risk

Production-Related Derivatives. We attempt to mitigate commodity price risk and stabilize cash flows associated with El Paso’s forecasted sales of natural gas and oil production through the use of derivative natural gas and oil swaps, basis swaps and option contracts. These derivative contracts are entered into by both our Exploration & Production and Marketing segments. The table below presents the hypothetical sensitivity to changes in fair values arising from immediate selected potential changes in the quoted market prices of the derivative commodity instruments used to mitigate these market risks. We have designated certain of these derivatives as accounting hedges. Contracts that are designated as accounting hedges will impact our earnings when the related hedged production sales occur, and, as a result, any gain or loss on these hedging derivatives would be substantially offset by a corresponding gain or loss on the sale of the underlying hedged commodity, which is not included in the table. Contracts that are not designated as accounting hedges will impact our earnings as the fair value of these derivatives changes. Our production-related derivatives do not mitigate all of the commodity price risk related to our forecasted 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.


				10 Percent Increase						10 Percent Decrease
	Fair Value			Fair Value			(Decrease)			Fair Value		Increase

Impact of changes in commodity prices on derivative commodity instruments
March 31, 2007	$	(118	)	$	(250	)	$	(132	)	$	3	$	121
December 31, 2006	$	124		$	(9	)	$	(133	)	$	264	$	140

Other Commodity-Based Derivatives. We have various other financial instruments that are not utilized to mitigate the commodity price risk associated with our natural gas and oil production in our Marketing segment. Many of these contracts, which include forwards, swaps, options and futures, are long-term historical contracts that we either intend to assign to third parties or to manage until their expiration. We measure risks from these contracts on a daily basis using a Value-at-Risk simulation. This simulation allows us to determine the maximum expected one-day unfavorable impact on the fair values of those contracts due to adverse market movements over a defined period of time within a specified confidence level and allows us to monitor our risk in comparison to established thresholds. We use what is known as the historical simulation technique for measuring Value-at-Risk. This technique simulates potential outcomes in the value of our portfolio based on market-based price changes. Our exposure to changes in fundamental prices over the long-term can vary from the exposure using the one-day assumption in our Value-at-Risk simulations. We supplement our Value-at-Risk simulations with additional fundamental and market-based price analyses, including scenario analysis and stress testing to determine our portfolio’s sensitivity to underlying risks. These analyses and our Value-at-Risk simulations do not include commodity exposures related to our production-related derivatives (described above), our Marketing segment’s natural gas transportation related contracts that are accounted for under the accrual basis of accounting, or our Exploration and Production segment’s sales of natural gas and oil production.

Our maximum expected one-day unfavorable impact on the fair values of our other commodity-based derivatives as measured by Value-at-Risk based on a confidence level of 95 percent and a one-day holding period was $4 million and $6 million as of March 31, 2007 and December 31, 2006. We may experience changes in our Value-at-Risk in the future if commodity prices are volatile.


Item 4.	Controls and Procedures

Evaluation of Disclosure Controls and Procedures

As of March 31, 2007, we carried out an evaluation under the supervision and with the participation of our management, including our CEO and our CFO, as to the effectiveness, design and operation of our disclosure controls and procedures, as defined by the Securities Exchange Act of 1934, as amended. This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the U.S. Securities and Exchange Commission (SEC) reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including our CEO and CFO, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Because of the inherent limitations in all control systems, no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within our company have been detected. Based on the results of this evaluation, our CEO and CFO concluded that our disclosure controls and procedures are effective at March 31, 2007.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting that have materially affected or are reasonably likely to materially affect our internal control over financial reporting during the first quarter of 2007.

PART II — OTHER INFORMATION


Item 1.	Legal Proceedings

See Part I, Item 1, Financial Statements, Note 7, which is incorporated herein by reference. Additional information about our legal proceedings can be found, in Part I, Item 3 of our 2006 Annual Report on Form 10-K filed with the SEC.


Item 1A.	Risk Factors

CAUTIONARY STATEMENTS FOR PURPOSES OF THE “SAFE HARBOR” PROVISIONS
OF THE PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

We have made statements in this document that constitute forward-looking statements, as that term is defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements include information concerning possible or assumed future results of operations. The words “believe,” “expect,” “estimate,” “anticipate” and similar expressions will generally identify forward-looking statements. These statements may relate to information or assumptions about:


	•	earnings per share;

	•	capital and other expenditures;

	•	dividends;

	•	financing plans;

	•	capital structure;

	•	liquidity and cash flow;

	•	pending legal proceedings, claims and governmental proceedings, including environmental matters;

	•	future economic and operating performance;

	•	operating income;

	•	management’s plans; and

	•	goals and objectives for future operations.

Forward-looking statements are subject to risks and uncertainties. While we believe the assumptions or bases underlying the forward-looking statements are reasonable and are made in good faith, we caution that assumed facts or bases almost always vary from actual results, and these variances can be material, depending upon the circumstances. We cannot assure you that the statements of expectation or belief contained in the forward-looking statements will result or be achieved or accomplished. Important factors that could cause actual results to differ materially from estimates or projections contained in forward-looking statements are described in our 2006 Annual Report on Form 10-K. There have been no material changes in our risk factors since that report.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

None.


Item 3.	Defaults Upon Senior Securities

None.


Item 4.	Submission of Matters to a Vote of Security Holders

None.


	March 31,		December 31,
	2007		2006

ASSETS
Current assets
Cash and cash equivalents	$	232	$	537
Accounts and notes receivable
Customer, net of allowance of $21 in 2007 and $28 in 2006		475		516
Affiliates		197		192
Other		482		495
Assets from price risk management activities		96		436
Assets held for sale and from discontinued operations		—		4,161
Deferred income taxes		345		478
Other		414		352

Total current assets		2,241		7,167

Property, plant and equipment, at cost
Pipelines		15,789		15,672
Natural gas and oil properties, at full cost		17,098		16,572
Other		562		566

		33,449		32,810
Less accumulated depreciation, depletion and amortization		16,243		16,132

Total property, plant and equipment, net		17,206		16,678

Other assets
Investments in unconsolidated affiliates		1,671		1,707
Assets from price risk management activities		214		414
Other		1,331		1,295

		3,216		3,416

Total assets	$	22,663	$	27,261


	Quarters Ended March 31,
	2007			2006

Net income	$	629		$	356

Foreign currency translation adjustments (net of income tax of less than $1 in 2006)		—			3
Net reclassification adjustments associated with pension and other postretirement obligations (net of income tax of $3 in 2007)		6			—
Net gains (losses) from cash flow hedging activities:
Unrealized mark-to-market gains (losses) arising during period (net of income tax of $47 in 2007 and $76 in 2006)		(83	)		131
Reclassification adjustments for changes in initial value to settlement date (net of income tax of $15 in 2007 and $11 in 2006)		(25	)		20
Net unrealized gains arising during period associated with investments available for sale (net of income tax of $2 in 2007 and $8 in 2006)		3			15

Other comprehensive income (loss)		(99	)		169

Comprehensive income	$	530		$	525


Exhibit
Number			Description

	*12		Ratio of Earnings to Combined Fixed Charges and Preferred Stock Dividends
	*31	.A	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	*31	.B	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
	*32	.A	Certification of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	*32	.B	Certification of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.