Table of Contents

Delaware (State or Other Jurisdiction of Incorporation or Organization)		4922 (Primary Standard Industrial Classification Code Number)		76-0568816 (I.R.S. Employer Identification Number)

El Paso Building 1001 Louisiana Street Houston, Texas 77002 (713) 420-2600 (Address, Including Zip Code, and Telephone Number, Including Area Code, of Registrant’s Principal Executive Offices)		Robert W. Baker, Esq. El Paso Building 1001 Louisiana Street Houston, Texas 77002 (713) 420-2600 (Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent For Service)

Andrews Kurth LLP 600 Travis, Suite 4200 Houston, Texas 77002 Attention: G. Michael O’Leary, Esq. (713) 220-4200

Proposed Maximum

Proposed Maximum

Title of Each Class of

Amount

Offering Price

Aggregate

Amount of

Securities to be Registered

to be Registered

per Share(1)

Offering Price(1)

Registration Fee

4.99% Convertible Perpetual Preferred Stock, par value $0.01 per share

750,000

$

1,000

$

750,000,000

$

88,275

Common Stock, par value $3.00 per share(2)

57,581,550

(3)

N/A

N/A

(2)

(1)	Estimated solely for purposes of calculating the registration fee pursuant to Rule 457 under the Securities Act of 1933, as amended.
(2)	The registrant will receive no consideration for the issuance of these shares of common stock upon conversion of the preferred stock. Therefore, pursuant to Rule 457(i), no filing fee is required with respect to these shares of common stock registered hereby.
(3)	Represents the maximum number of shares of common stock which may be issued upon conversion of the preferred stock registered hereby.

---

Table of Contents

We will amend and complete the information in this prospectus. The selling security holders may not sell these securities or accept your offer to buy them until the documentation filed with the SEC relating to these securities has been declared effective by the SEC. This prospectus is not an offer to sell these securities or our solicitation of your offer to buy these securities in any jurisdiction where that would not be permitted or legal.

---

		Page
Industry and Market Data			i
Non-GAAP Financial Measures			ii
Where You Can Find More Information			iii
Cautionary Statement Regarding Forward-Looking Statements			iii
Summary			1
Risk Factors			7
Use of Proceeds			19
Selected Financial Data			20
Management’s Discussion and Analysis of Financial Condition and Results of Operations			22
Business			98
Market Price of and Dividends on the Common Stock and Related Stockholder Matters			126
Directors and Executive Officers			129
Executive Compensation			132
Security Ownership of Certain Beneficial Owners and Management			142
Certain Relationships and Related Transactions			143
Description of the Preferred Stock			143
Description of El Paso Capital Stock			159
Selling Stockholders			160
Plan of Distribution			162
Certain United States Federal Income Tax Considerations			164
ERISA Considerations			168
Legal Matters			169
Experts			169
Index to Financial Statements			F-1
Statement re: computation of ratio of earnings to fixed charges
Consent of PricewaterhouseCoopers LLP (Houston)
Consent of PricewaterhouseCoopers LLP (Detroit)
Consent of Ryder Scott Company, L.P.

i

---

Table of Contents

/d		= per day
Bbl		= barrels
BBtu		= billion British thermal units
BBtue		= billion British thermal unit equivalents
Bcf		= billion cubic feet
Bcfe		= billion cubic feet of natural gas equivalents
MBbls		= thousand barrels
Mcf		= thousand cubic feet
MDth		= thousand dekatherms
Mcfe		= thousand cubic feet of natural gas equivalents
Mgal		= thousand gallons
MMBbls		= million barrels
MMBtu		= million British thermal units
MMcf		= million cubic feet
MMcfe		= million cubic feet of natural gas equivalents
MMWh		= thousand megawatt hours
MTons		= thousand tons
MW		= megawatt
NGL		= natural gas liquids
TBtu		= trillion British thermal units
Tcfe		= trillion cubic feet of natural gas equivalents

ii

---

Table of Contents

iii

---

Table of Contents

iv

---

Table of Contents

1

---

Table of Contents

2

---

Table of Contents

3

---

Table of Contents

4

---

Table of Contents

5

---

Table of Contents

6

---

Table of Contents

	The preferred stock ranks junior to all of our liabilities.

	We may not be able to pay cash dividends on the preferred stock.

	There is no public market for the preferred stock.

7

---

Table of Contents

	We may not be able to pay the redemption price of the preferred stock in cash upon a fundamental change. We also could be prevented from paying dividends on shares of the preferred stock.

	If you convert your shares of preferred stock into shares of common stock, you may experience immediate dilution.

	The price of our common stock, and therefore of the preferred stock, may fluctuate significantly, which may make it difficult for you to resell the preferred stock, or common stock issuable upon conversion thereof, when you want or at prices you find attractive.

	The additional shares of our common stock payable on our preferred stock in connection with a fundamental change may not adequately compensate you for the lost option time value of your shares of our preferred stock as a result of such fundamental change.

8

---

Table of Contents

	We may issue additional series of preferred stock that rank equally to the preferred stock as to dividend payments and liquidation preference.

	Future issuances of preferred stock may adversely affect the market price for our common stock.

	We may not have sufficient earnings and profits in order for distributions on the preferred stock to be treated as dividends.

	Our corporate documents and Delaware law contain provisions that could discourage, delay or prevent a change in control of our company even if some stockholders might consider such a development favorable, which may adversely affect the price of our common stock.

9

---

Table of Contents

	Our operations are subject to operational hazards and uninsured risks.

	The success of our pipeline business depends, in part, on factors beyond our control.

	•	service area competition;
	•	expiration and/or turn back of significant contracts;
	•	changes in regulation and action of regulatory bodies;
	•	future weather conditions;
	•	price competition;
	•	drilling activity and availability of natural gas supplies;
	•	decreased availability of conventional gas supply sources and the availability and timing of other gas supply sources, such as LNG;
	•	increased availability or popularity of alternative energy sources such as hydroelectric power;
	•	increased cost of capital;
	•	opposition to energy infrastructure development, especially in environmentally sensitive areas;
	•	adverse general economic conditions;
	•	expiration and/or renewal of existing interests in real property, including real property on Native American lands, and
	•	unfavorable movements in natural gas and liquids prices.

	The revenues of our pipeline businesses are generated under contracts that must be renegotiated periodically.

10

---

Table of Contents

	•	competition by other pipelines, including the proposed construction by other companies of additional pipeline capacity or LNG terminals in markets served by our interstate pipelines;
	•	changes in state regulation of local distribution companies, which may cause them to negotiate short-term contracts or turn back their capacity when their contracts expire;
	•	reduced demand and market conditions in the areas we serve;
	•	the availability of alternative energy sources or gas supply points; and
	•	regulatory actions.

	Fluctuations in energy commodity prices could adversely affect our pipeline businesses.

	•	regional, domestic and international supply and demand;
	•	availability and adequacy of transportation facilities;
	•	energy legislation;
	•	federal and state taxes, if any, on the sale or transportation of natural gas and natural gas liquids;
	•	abundance of supplies of alternative energy sources; and
	•	political unrest among oil producing countries.

	Natural gas and oil prices are volatile. A substantial decrease in natural gas and oil prices could adversely affect the financial results of our exploration and production business.

11

---

Table of Contents

	•	the level of consumer demand for, and the supply of, natural gas and oil;
	•	commodity processing, gathering and transportation availability;
	•	the level of imports of, and the price of, foreign natural gas and oil;
	•	the ability of the members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;
	•	domestic governmental regulations and taxes;
	•	the price and availability of alternative fuel sources;
	•	the availability of pipeline capacity;
	•	weather conditions;
	•	market uncertainty;
	•	political conditions or hostilities in natural gas and oil producing regions;
	•	worldwide economic conditions; and
	•	decreased demand for the use of natural gas and oil because of market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives.

	The success of our natural gas and oil exploration and production businesses is dependent, in part, on factors that are beyond our control.

	•	the results of future drilling activity;
	•	our ability to identify and precisely locate prospective geologic structures and to drill and successfully complete wells in those structures in a timely manner;
	•	our ability to expand our leased land positions in desirable areas, which often are subject to intensely competitive conditions;
	•	increased competition in the search for and acquisition of reserves;
	•	future drilling, production and development costs, including drilling rig rates and oil field services costs;
	•	future tax policies, rates, and drilling or production incentives by state, federal, or foreign governments;
	•	increased federal or state regulations, including environmental regulations, or adverse court decisions that limit or restrict the ability to drill natural gas or oil wells, reduce operational flexibility, or increase capital and operating costs;
	•	decreased demand for the use of natural gas and oil because of market concerns about global warming or changes in governmental policies and regulations due to climate change initiatives;

12

---

Table of Contents

	•	declines in production volumes, including those from the Gulf of Mexico; and
	•	continued access to sufficient capital to fund drilling programs to develop and replace a reserve base with rapid depletion characteristics.

	Our natural gas and oil drilling and producing operations involve many risks and may not be profitable.

	Estimating our reserves, production and future net cash flow is difficult.

	The success of our power activities depends, in part, on many factors beyond our control.

	•	alternative sources and supplies of energy becoming available due to new technologies and interest in self generation and cogeneration;
	•	increases in the costs of generation, including increases in fuel costs;

13

---

Table of Contents

	•	uncertain regulatory conditions resulting from the ongoing deregulation of the electric industry in the United States and in foreign jurisdictions;
	•	our ability to negotiate successfully, and enter into advantageous power purchase and supply agreements;
	•	the possibility of a reduction in the projected rate of growth in electricity usage as a result of factors such as regional economic conditions, excessive reserve margins and the implementation of conservation programs;
	•	risks incidental to the operation and maintenance of power generation facilities;
	•	the inability of customers to pay amounts owed under power purchase agreements;
	•	the increasing price volatility due to deregulation and changes in commodity trading practices; and
	•	over-capacity of generation in markets served by the power plants we own or in which we have an interest.

	Our use of derivative financial instruments could result in financial losses.

	Our businesses are subject to the risk of payment defaults by our counterparties.

	Our foreign operations and investments involve special risks.

	•	loss of revenue, property and equipment as a result of hazards such as expropriation, nationalization, wars, insurrection and other political risks;
	•	the effects of currency fluctuations and exchange controls, such as devaluation of foreign currencies and other economic problems; and
	•	changes in laws, regulations and policies of foreign governments, including those associated with changes in the governing parties.

14

---

Table of Contents

	Retained liabilities associated with businesses that we have sold could exceed our estimates.

	Ongoing litigation and investigations related to our financial statements associated with our reserve estimates and hedges could significantly adversely affect our business.

	The outcome of pending governmental investigations could be materially adverse to us.

	The agencies that regulate our pipeline businesses and their customers affect our profitability.

15

---

Table of Contents

	Costs of environmental liabilities, regulations and litigation could exceed our estimates.

	•	the uncertainties in estimating pollution control and clean up costs;
	•	the discovery of new sites or information;
	•	the uncertainty in quantifying liability under environmental laws that impose joint and several liability on all potentially responsible parties;
	•	the nature of environmental laws and regulations; and
	•	potential changes in environmental laws and regulations, including changes in the interpretation and enforcement thereof.

	Costs of litigation matters and other contingencies could exceed our estimates.

16

---

Table of Contents

	Our system of internal controls ensures the accuracy or completeness of our disclosures and a loss of public confidence in the quality of our internal controls or disclosures could have a negative impact on us.

	We have significant debt and below investment grade credit ratings, which have impacted and will continue to impact our financial condition, results of operations and liquidity.

	We may not achieve all of the objectives set forth in our Long-Range Plan in a timely manner or at all.

17

---

Table of Contents

	A breach of the covenants applicable to our debt and other financing obligations could affect our ability to borrow funds and could accelerate our debt and other financing obligations and those of our subsidiaries.

	Our ability to access capital markets is limited to private placements or filing new registration statements as a result of the restatement of our historical financial results.

	We are subject to financing and interest rate exposure risks.

	•	our credit ratings;
	•	interest rates;
	•	the structured and commercial financial markets;
	•	market perceptions of us or the natural gas and energy industry;
	•	changes in tax rates due to new tax laws;
	•	our stock price; and
	•	changes in market prices for energy.

18

---

Table of Contents

19

---

Table of Contents

																							As of or for the
			As of or for the Year Ended December 31,																				Six Months
																							Ended June 30,
			2004				2003				2002
			(Restated)(3)				(Restated)(1)(2)(3)				(Restated)(1)				2001				2000(4)				2005(5)				2004
																			(Unaudited)
																							(Unaudited)
			(In millions, except per common share amounts)
Operating Results Data:
	Operating revenues		$	5,874			$	6,668			$	6,881			$	10,186			$	6,179			$	2,366			$	3,081
	Income (loss) from continuing operations available to common stockholders(6)		$	(833	)		$	(595	)		$	(1,242	)		$	(223	)		$	481			$	(140	)		$	(191	)
	Net income (loss)		$	(947	)		$	(1,883	)		$	(1,875	)		$	(447	)		$	665			$	(132	)		$	(191	)
	Basic income (loss) per common share from continuing operations		$	(1.30	)		$	(0.99	)		$	(2.22	)		$	(0.44	)		$	0.98			$	0.22			$	(0.30	)
	Diluted income (loss) per common share from continuing operations		$	(1.30	)		$	(0.99	)		$	(2.22	)		$	(0.44	)		$	0.95			$	(0.22	)		$	(0.30	)
	Cash dividends declared per common share(7)		$	0.16			$	0.16			$	0.87			$	0.85			$	0.82			$	0.08			$	0.08
	Basic average common shares outstanding			639				597				560				505				494				640				639
	Diluted average common shares outstanding			639				597				560				505				506				640				639
Financial Position Data:
	Total assets(8)		$	31,383			$	36,943			$	41,923			$	44,271			$	43,992			$	29,676			$	31,383
	Long-term financing obligations (9)			18,241				20,275				16,106				12,840				11,206				16,379				18,241
	Securities of subsidiaries(9)			367				447				3,420				4,013				3,707				59				367
	Stockholders’ equity			3,438				4,346				5,749				6,666				6,145				3,800				3,438

(1)		During the completion of the financial statements for the year ended December 31, 2004, we identified an error in the manner in which we had originally adopted the provisions of SFAS No. 141, Business Combinations, and SFAS No. 142, Goodwill and Other Intangible Assets, in 2002. Upon adoption of these standards, we incorrectly adjusted the cost of investments in unconsolidated affiliates and the cumulative effect of change in accounting principle for the excess of our share of the affiliates fair value of the net assets over their original cost, which we believed was negative goodwill. The amount originally recorded as a cumulative effect of accounting change was $154 million and related to our investments in Citrus Corporation, Portland Natural Gas, several Australian investments and an investment in the Korea Independent Energy Corporation. We subsequently determined that the amounts we adjusted were not negative goodwill, but rather amounts that should have been allocated to the long-lived assets underlying our investments. As a result, we were required to restate our 2002 financial statements to reverse the amount we recorded as a cumulative effect of an accounting change on January 1, 2002. This adjustment also impacted a deferred tax adjustment and an unrealized loss we recorded on our Australian investments during 2002, requiring a further restatement of that year. The restatements also affected the investment, deferred tax liability and stockholders’ equity balances we reported as of December 31, 2002 and 2003. See Notes to Consolidated Financial Statements, Note 1, on page F-46, for a further discussion of the restatements.

20

---

Table of Contents

(2)		After filing our 2004 Form 10-K, we determined that in our discontinued Canadian exploration and production operations, we had previously recorded deferred tax benefits of $82 million in 2003 in continuing operations that we have now properly reflected in discontinued operations.
(3)		After filing our amended 2004 Form 10-K, we identified errors related to the accounting and reporting of foreign currency translation adjustments (CTA) on several of our foreign operations. In addition, we determined that upon initially recognizing U.S. deferred income taxes on our investment in certain foreign operations, we did not properly allocate taxes to CTA. These errors resulted in us having to record additional income tax benefits in 2003 in our continuing operations of $10 million and in our discontinued operations of $35 million. In 2004, we determined that we should have recorded a reduction in our loss from discontinued operations of $32 million and an increase in our loss from continuing operations of $31 million, related to CTA balances and related tax adjustments. As a result of these errors, we restated our 2003 and 2004 financial statements, related quarterly information, and interim period financial statements. See Notes to Consolidated Financial Statements and Notes to Condensed Consolidated Financial Statements, Note 1, on pages F-46 and F-8 for a further discussion of the restatements.
(4)		These amounts are derived from unaudited financial statements. Such amounts were restated in 2003 for the accounting impact of adjustments to our historical reserve estimates.
(5)		During the second quarter of 2005, we discontinued our south Louisiana gathering and processing operations, which were part of our Field Services segment. Our operating results for the quarter and six months ended June 30, 2005 reflect these operations as discontinued. Prior period amounts have not been adjusted as these operations were not material to prior period results or historical trends.
(6)		We incurred losses of $1.1 billion in 2004, $1.2 billion in 2003 and $0.9 billion in 2002 related to impairments of assets and equity investments as well as restructuring charges related to industry changes and the related realignment of our businesses in response to those changes. In 2003, we also entered into an agreement in principle to settle claims associated with the western energy crisis of 2000 and 2001. This settlement resulted in charges of $104 million in 2003 and $899 million in 2002, both before income taxes. In addition, we incurred ceiling test charges of $5 million, $5 million and $1,895 million in 2003, 2002 and 2001 on our full cost natural gas and oil properties. During 2001, we merged with The Coastal Corporation and incurred costs and asset impairments related to this merger that totaled approximately $1.5 billion. We recognized net losses of $349 million and $297 million for the six months ended June 30, 2005 and June 30, 2004, related to sales and impairments of long-lived assets and equity investments. For further discussions of events affecting comparability of our results in 2004, 2003 and 2002, see Notes to Consolidated Financial Statements, Notes 2 through 5, on pages F-58 to F-68.
(7)		Cash dividends declared per share of common stock represent the historical dividends declared by El Paso for all periods presented.
(8)		Decreases in 2002, 2003, 2004 and the first quarter of 2005, were a result of asset sales activities during these periods. See Notes to Condensed Consolidated Financial Statements, Note 3, on page F-11, and Notes to Consolidated Financial Statements, Note 3, on page F-62.
(9)		The increases in total long-term financing obligations in 2002 and 2003 was a result of the consolidations of our Chaparral and Gemstone power investments, the restructuring of other financing transactions, and the reclassification of securities of subsidiaries as a result of our adoption of SFAS No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, during 2003.

21

---

Table of Contents

	•	We focused capital investment on our core pipeline and production businesses, where in 2002, 2003 and 2004, we spent 87 percent, 91 percent, and 97 percent of our total capital dollars;
	•	We completed the sale of a number of assets and investments including international production properties, a substantial portion of our general and limited partnership interests in GulfTerra, a significant portion of our worldwide petroleum markets operations, a significant portion of our domestic power generation operations and our merchant LNG business. Total proceeds from these sales were approximately $3.3 billion;
	•	We reduced our net debt (debt, net of cash) by $3.4 billion in 2004, lowering our net debt to $17.1 billion as of December 31, 2004; and
	•	We continued our cost-reduction efforts with a goal of achieving $150 million of savings by the end of 2006.

22

---

Table of Contents

	•	Simplifying our capital structure;
	•	Continuing to focus on expansions in our core pipeline business and completing the turnaround of our production business;
	•	Selling additional assets that we expect will generate proceeds from $1.8 billion to $2.2 billion;
	•	Reducing outstanding debt (net of cash) to $15 billion by the end of 2005; and
	•	Continuing to reduce costs to achieve the cost savings outlined in our plan.

Debt obligations as of December 31, 2003			$	21,732
Principal amounts borrowed(1)				1,513
Repayment of principal(2)				(3,370	)
Sale of entities(3)				(887	)
Other				208
	Total debt as of December 31, 2004		$	19,196

(1)	Includes proceeds from a $1.25 billion term loan under our new $3 billion credit agreement.
(2)	Includes $850 million of repayments under our previous $3 billion revolving credit facility.
(3)	Consists of $815 million of debt related to Utility Contract Funding and $72 million of debt related to Mohawk River Funding IV.

23

---

Table of Contents

Available cash			$	1.8
Available capacity under our $3 billion credit agreement				0.6
	Net available liquidity at December 31, 2004		$	2.4

24

---

Table of Contents

25

---

Table of Contents

										2003
						2004				(Restated)
						(In billions)
Cash inflows
	Continuing operating activities
		Net loss before discontinued operations				$	(0.8	)		$	(0.6	)
		Non-cash income adjustments					2.4				1.8
		Payment on Western Energy Settlement					(0.6	)			—
		Change in assets and liabilities					0.1				1.1
							1.1				2.3
	Continuing investing activities
		Net proceeds from the sale of assets and investments					1.9				2.5
		Net proceeds from restricted cash					0.6				—
		Other					0.1				—
							2.6				2.5
	Continuing financing activities
		Net proceeds from the issuance of long-term debt					1.3				3.6
		Borrowings under long-term credit facility					—				0.5
		Proceeds from the issuance of common stock					0.1				0.1
		Net discontinued operations activity					1.0				0.4
							2.4				4.6
			Total cash inflows			$	6.1			$	9.4
Cash outflows
	Continuing investing activities
		Additions to property, plant, and equipment				$	1.8			$	2.4
		Net cash paid to acquire Chaparral and Gemstone					—				1.1
		Net payments of restricted cash					—				0.5
		Other					—				0.1
							1.8				4.1
	Continuing financing activities
		Payments to retire long-term debt and redeem preferred interests					2.5				4.1
		Payments of revolving credit facilities					0.9				1.2
		Dividends paid to common stockholders					0.1				0.2
		Other					0.1				—
							3.6				5.5
			Total cash outflows				5.4				9.6
				Net change in cash		$	0.7			$	(0.2	)

26

---

Table of Contents

Production exploration, development and acquisition expenditures			$	0.7
Pipeline expansion, maintenance and integrity projects				1.0
Other (primarily power projects)				0.1
	Total capital expenditures and net additions to equity investments		$	1.8

27

---

Table of Contents

	Guarantees

28

---

Table of Contents

				2005				2006				2007				2008				2009				Thereafter				Total
				(In millions)
Long-term financing obligations:(1)
	Principal			$	948			$	1,155			$	835			$	733			$	2,637			$	13,031			$	19,339
	Interest				1,356				1,330				1,257				1,191				1,127				11,762				18,023
Western Energy Settlement(2)					44				44				44				44				44				634				854
Other contractual liabilities(3)					31				47				23				22				5				32				160
Operating leases(4)					79				66				51				43				40				163				442
Other contractual commitments and purchase obligations:(5)
	Tolling, transportation and storage(6)				178				144				131				127				122				779				1,481
	Commodity purchases(7)				30				28				28				17				10				36				149
	Other(8)				151				36				14				15				5				3				224
		Total contractual obligations		$	2,817			$	2,850			$	2,383			$	2,192			$	3,990			$	26,440			$	40,672

(1)	See Notes to Consolidated Financial Statements, Note 15, on page F-81.
(2)	See Notes to Consolidated Financial Statements, Note 17, on page F-89.
(3)	Includes contractual, environmental and other obligations included in other noncurrent liabilities in our balance sheet. Excludes expected contributions to our pension and other postretirement benefit plans of $68 million in 2005 and $209 million for the four year period ended December 31, 2009, because these expected contributions are not contractually required.
(4)	See Notes to Consolidated Financial Statements, Note 17, on page F-89.
(5)	Other contractual commitments and purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations.
(6)	These are commitments for demand charges on our tolling arrangements and for firm access to natural gas transportation and storage capacity.
(7)	Includes purchase commitments for natural gas and power.
(8)	Includes commitments for drilling and seismic activities in our production operations and various other maintenance, engineering, procurement and construction contracts, as well as service and license agreements, used by our other operations.

29

---

Table of Contents

					Maturity				Maturity				Maturity				Maturity				Maturity				Total
					Less Than				1 to 3				4 to 5				6 to 10				Beyond				Fair
Source of Fair Value					1 Year				Years				Years				Years				10 Years				Value
					(In millions)
Derivatives designated as hedges
	Assets				$	92			$	33			$	—			$	—			$	—			$	125
	Liabilities					(416	)			(222	)			(14	)			(9	)			—				(661	)
			Total derivatives designated as hedges			(324	)			(189	)			(14	)			(9	)			—				(536	)
Assets from power contract restructuring derivatives(1)(2)						105				199				151				210				—				665
Other commodity-based derivatives
	Exchange-traded positions(3)
		Assets				19				220				76				—				—				315
		Liabilities				(107	)			(1	)			—				—				—				(108	)
	Non-exchange traded positions(2)
		Assets				431				271				186				166				46				1,100
		Liabilities(1)				(372	)			(448	)			(267	)			(230	)			(51	)			(1,368	)
			Total other commodity-based derivatives			(29	)			42				(5	)			(64	)			(5	)			(61	)
			Total commodity-based derivatives		$	(248	)		$	52			$	132			$	137			$	(5	)		$	68

(1)	Includes $259 million of intercompany derivatives that eliminate in consolidation and have no impact on our consolidated assets and liabilities from price risk management activities.
(2)	In March 2005, we sold our Cedar Brakes I and II subsidiaries and their related restructured power contracts, which had a fair value of $596 million as of December 31, 2004. In connection with this sale, we also assigned or terminated other commodity-based derivatives that had a fair value loss of $240 million as of December 31, 2004.
(3)	Exchange-traded positions are traded on active exchanges such as the New York Mercantile Exchange, the International Petroleum Exchange and the London Clearinghouse.

30

---

Table of Contents

								Derivatives from				Other				Total
				Derivatives				Power Contract				Commodity-				Commodity-
				Designated				Restructuring				Based				Based
				as Hedges				Activities				Derivatives				Derivatives
				(In millions)
Fair value of contracts outstanding at December 31, 2002				$	(21	)		$	968			$	(525	)		$	422
	Fair value of contract settlements during the period				15				(405	)			602				212
	Change in fair value of contracts				(25	)			140				(477	)			(362	)
	Original fair value of contracts consolidated as a result of Chaparral acquisition				—				1,222				—				1,222
	Option premiums received, net				—				—				(88	)			(88	)
		Net change in contracts outstanding during the period			(10	)			957				37				984
Fair value of contracts outstanding at December 31, 2003					(31	)			1,925				(488	)			1,406
	Fair value of contract settlements during the period				49				(1,132	)(1)			284				(799	)
	Change in fair value of contracts				38				(128	)(2)			(513	)(3)			(603	)
	Other commodity-based derivatives designated as hedges				(592	)			—				592				—
	Option premiums paid, net				—				—				64				64
		Net change in contracts outstanding during the period			(505	)			(1,260	)			427				(1,338	)
Fair value of contracts outstanding at December 31, 2004				$	(536	)		$	665			$	(61	)		$	68

(1)	Includes $861 million and $75 million of derivative contracts sold in conjunction with the sales of Utility Contract Funding and Mohawk River Funding IV in 2004. See Notes to Consolidated Financial Statements, Notes 3 and 5, on pages F-62 and F-68, for additional information on these sales.
(2)	In the fourth quarter of 2004, we recorded a $227 million charge associated with the sale of our Cedar Brakes I and II subsidiaries and their related restructured power contracts. See Notes to Consolidated Financial Statements, Notes 3 and 5, on pages F-62 and F-68, for additional information on this sale.
(3)	In the second quarter of 2004, we reclassified a $69 million liability from our Western Energy Settlement obligation to our price risk management activities.

31

---

Table of Contents

		Volume				Hedge Price(1)				Cash Price
		(TBtu)				(per MMBtu)				(per MMBtu)
2005			132			$	6.75			$	3.74	(2)
2006			86			$	6.34			$	4.01	(2)
2007			5			$	3.56			$	3.56
2008 to 2012			21			$	3.67			$	3.67

(1)	Our Production segment will record revenues related to these natural gas volumes at this price in their operating results.
(2)	The difference between our Production segment’s hedge price and the cash price we will receive upon settlement of the derivative transactions was previously recorded as losses in our Marketing and Trading segment.

						Floor				Ceiling				Ceiling
		Floor Price(1)				Volume				Price(2)				Volume
		(per MMBtu)				(TBtu)				(per MMBtu)				(TBtu)
2005		$	6.00				60				—				—
2006		$	6.00				120			$	9.50				60
2007		$	6.00				30				—				—

(1)	The floor price is the minimum cash price to be received under the option contract.
(2)	The ceiling price is the maximum cash price to be received under the option contract.

32

---

Table of Contents

				2004				2003				2002
				(Restated)(1)				(Restated)(1)				(Restated)(1)
				(In millions)
Regulated Business
	Pipelines			$	1,331			$	1,234			$	828
Non-regulated Businesses
	Production				734				1,091				808
	Marketing and Trading				(539	)			(809	)			(1,977	)
	Power				(599	)			(28	)			12
	Field Services				120				133				289
		Segment EBIT			1,047				1,621				(40	)
Corporate and other					(217	)			(852	)			(387	)
		Consolidated EBIT			830				769				(427	)
Interest and debt expense					(1,607	)			(1,791	)			(1,297	)
Distributions on preferred interests of consolidated subsidiaries					(25	)			(52	)			(159	)
Income taxes					(31	)			479				641
	Loss from continuing operations				(833	)			(595	)			(1,242	)
Discontinued operations, net of income taxes					(114	)			(1,279	)			(425	)
Cumulative effect of accounting changes, net of income taxes					—				(9	)			(208	)
	Net loss			$	(947	)		$	(1,883	)		$	(1,875	)

(1)

See Notes to Consolidated Financial Statements, Note 1, on page F-46, for a discussion of the restatements of our 2002, 2003 and 2004 financial statements. The restatement of our 2002 financial statements affected our Pipelines segment results and the amounts reported as a cumulative effect of accounting change in 2002. The restatement of our 2003 financial statements affected the classification of income taxes between continuing and discontinued operations as well as the amount of income taxes recorded in both continuing and discontinued operations related to certain of our foreign investments with CTA balances. The restatement of our 2004 financial statements affected the amount of losses on long-lived assets, earnings from unconsolidated affiliates and other income for certain foreign operations in our Power and Marketing and Trading segments, in our corporate operations, and in our discontinued operations, as well as the related amount of income taxes recorded on these assets and investments.

33

---

Table of Contents

			Operating Segments
											Marketing
			Pipelines								and				Power				Field				Corporate &
			(Restated)				Production				Trading				(Restated)				Services				Other
			(In millions)
2004
Asset and investment impairments, net of gain (loss) on sales(1)			$	20			$	(8	)		$	—			$	(994	)		$	(7	) (2)		$	3
Restructuring charges				(5	)			(14	)			(2	)			(5	)			(1	)			(91	)
	Total		$	15			$	(22	)		$	(2	)		$	(999	)		$	(8	)		$	(88	)
2003
Asset and investment impairments, net of gain (loss) on sales(1)			$	9			$	(5	)		$	3			$	(525	)		$	9			$	(525	)
Ceiling test charges				—				(5	)							—				—				—
Restructuring charges				(2	)			(6	)			(16	)			(5	)			(4	)			(91	)
Western Energy Settlement (3)				(140	)			—				(26	)			—				—				(4	)
	Total		$	(133	)		$	(16	)		$	(39	)		$	(530	)		$	5			$	(620	)
2002 (Restated)
Asset and investment impairments, net of gain (loss) on sales(1)			$	(125	)		$	1			$	—			$	(642	)		$	129			$	(212	)
Ceiling test charges				—				(5	)			—				—				—				—
Restructuring charges				(1	)			—				(10	)			(14	)			(1	)			(51	)
Western Energy Settlement				(412	)			—				(487	)			—				—				—
Net gain on power contract restructurings(4)				—				—				—				578				—				—
	Total		$	(538	)		$	(4	)		$	(497	)		$	(78	)		$	128			$	(263	)

(1)	Includes net impairments of cost-based investments included in other income and expense.
(2)	Includes the gain on our transactions with Enterprise and a goodwill impairment.
(3)	Includes $66 million of accretion expense and other charges included in operation and maintenance expense associated with the Western Energy Settlement.
(4)	Excludes intercompany transactions related to the UCF restructuring transaction which were eliminated in consolidation.

34

---

Table of Contents

35

---

Table of Contents

						Percent of Total
		MDth/d				Contracted Capacity
2005			3,838				13
2006(1)(2)			6,414				21
2007			4,539				15
2008 and beyond			15,540				51

(1)	Reflects the impact of an agreement, that we entered into to extend 750 MMcf/d of SoCal’s current capacity, effective September 1, 2006, for terms of three to five years. The agreement is subject to FERC approval.
(2)	Includes approximately 1,564 MMcf/d currently under contract on EPNG’s system through 2011 and beyond that is subject to early termination in August 2006 provided customers give timely notice of an intent to terminate.

	Operating Results

Pipelines Segment Results				2004				2003				2002
												(Restated)
				(In millions, except volume amounts)
Operating revenues				$	2,651			$	2,647			$	2,610
Operating expenses					(1,522	)			(1,584	)			(1,822	)
	Operating income				1,129				1,063				788
Other income					202				171				40
	EBIT			$	1,331			$	1,234			$	828
Throughput volumes (BBtu/d)(1)
	TGP				4,519				4,760				4,610
	EPNG and MPC				4,235				4,066				4,065
	ANR				4,067				4,232				4,130
	CIG, WIC and CPG				2,795				2,743				2,768
	SNG				2,163				2,101				2,151
	Equity investments (our ownership share)				2,798				2,433				2,408
		Total throughput			20,577				20,335				20,132

(1)	Throughput volumes exclude volumes related to our equity investments in Portland Natural Gas Transmission System, EPIC Energy Australia Trust and Alliance Pipeline, which have been sold. In addition, volumes exclude intrasegment activities. Throughput volumes include volumes related to our Mexico investments which were transferred from our Power segment effective January 1, 2004.

36

---

Table of Contents

			2004 to 2003																2003 to 2002
															EBIT																EBIT
			Revenue				Expense				Other				Impact				Revenue				Expense				Other				Impact
			Favorable/(Unfavorable)																Favorable/(Unfavorable)
			(In millions)																(In millions)
Contract modifications/terminations			$	(93	)		$	37				—			$	(56	)		$	(52	)		$	(7	)			—			$	(59	)
Gas not used in operations and other natural gas sales				67				(16	)			—				51				57				(18	)			—				39
Mainline expansions				33				(6	)			(6	)			21				47				(7	)			3				43
Sale of Panhandle fields and other production properties in 2002				—				—				—				—				(50	)			21				—				(29	)
Operation and maintenance costs(1)				—				(69	)			—				(69	)			—				9				—				9
Other regulatory matters				—				(9	)			(19	)			(28	)			—				—				18				18
Equity earnings from Citrus				—				—				22				22				—				—				—				—
Mexico investments				9				(6	)			17				20				—				—				—				—
Australia investment impairment				—				—				—				—				—				—				141				141
Western Energy Settlement				—				140				—				140				—				272				—				272
Other(2)				(12	)			(9	)			17				(4	)			35				(32	)			(31	)			(28	)
	Total impact on EBIT		$	4			$	62			$	31			$	97			$	37			$	238			$	131			$	406

(1)	Consists of costs of operations, electric and power purchase costs, shared services allocations and environmental costs.
(2)	Consists of individually insignificant items across several of our pipeline systems.

37

---

Table of Contents

	•	Cheyenne Plains Gas Pipeline commenced free-flow operations in December 2004 and as of January 31, 2005 is fully in-service. Approval has already been received for Cheyenne Plains Phase II which will add an additional 179 MMcf/d of capacity that is scheduled to be available by the end of 2005.
	•	CIG’s Raton Basin 2005 Expansion will add 104 MMcf/d of capacity that is scheduled to be available by the end of 2005.
	•	WIC expects to complete its Piceance lateral with capacity of 333 MMcf/d by the end of 2005.
	•	EPNG’s Line 1903 project, consisting of an expansion from Cadiz, California to Ehrenberg, Arizona, that is expected to be in-service by end of 2005 and will increase its capacity by 372 MMcf/d.

38

---

Table of Contents

	•	SNG — filed a rate case in August 2004; settlement discussions with major customers are underway with a settlement conference to be scheduled in early 2005.
	•	EPNG — expected to file for new rates that would be effective January 2006.
	•	CIG — required to file for new rates that would be effective October 2006.
	•	MPC — expected to file for new rates that would be effective February 2007.

39

---

Table of Contents

	Reserves, Production and Costs

	Production Hedge Position

40

---

Table of Contents

		Quarter Ended
		March 31								June 30								September 30								December 31								Total
						Hedged								Hedged								Hedged								Hedged								Hedged
						Price								Price								Price								Price								Price
		Volume				(per				Volume				(per				Volume				(per				Volume				(per				Volume				(per
		(BBtu)				MMBtu)				(BBtu)				MMBtu)				(BBtu)				MMBtu)				(BBtu)				MMBtu)				(BBtu)				MMBtu)
2005			33,019			$	7.26				33,037			$	6.47				33,055			$	6.49				33,055			$	6.77				132,166			$	6.75
2006			21,349			$	7.07				21,367			$	6.01				21,385			$	6.01				21,385			$	6.28				85,486			$	6.34
2007			1,579			$	3.79				1,447			$	3.64				1,155			$	3.35				1,155			$	3.35				5,336			$	3.56
2008 through 2012																																			20,620			$	3.67

	Oil

		Quarter Ended
		March 31								June 30								September 30								December 31								Total
						Hedged								Hedged								Hedged								Hedged								Hedged
		Volume				Price				Volume				Price				Volume				Price				Volume				Price				Volume				Price
		(MBbls)				(per Bbl)				(MBbls)				(per Bbl)				(MBbls)				(per Bbl)				(MBbls)				(per Bbl)				(MBbls)				(per Bbl)
2005			94			$	35.15				96			$	35.15				96			$	35.15				97			$	35.15				383			$	35.15
2006			94			$	35.15				96			$	35.15				96			$	35.15				97			$	35.15				383			$	35.15
2007			47			$	35.15				48			$	35.15				48			$	35.15				49			$	35.15				192			$	35.15

	Operational Factors Affecting the Year Ended December 31, 2004

	•	Higher realized prices. Realized natural gas prices, which include the impact of our hedges, increased eight percent and oil, condensate and NGL prices increased 33 percent compared to 2003.
	•	Average daily production of 814 MMcfe/d (excluding discontinued Canadian and other international operations of 15 MMcfe/d). We achieved the low end of our projected production volume despite the impact of hurricanes in the Gulf of Mexico.
	•	Capital expenditures and acquisitions of $790 million (excluding discontinued Canadian and other international expenditures of $29 million). During the first quarter of 2004, we experienced disappointing drilling results. As a result, we significantly reduced our drilling activities and instituted a new, more rigorous, risk analysis program, with an emphasis on strict capital discipline. After implementing this new program, we increased our domestic drilling activities in the third and fourth quarters of 2004 with improved drilling results. During 2004, we drilled 325 wells with a 96 percent success rate. We also acquired the remaining 50 percent interest in UnoPaso in Brazil in July 2004. This acquisition has performed above expectations in the fourth quarter of 2004.
	•	Sale of Canadian and other international operations. These operations were sold in order to focus our operations in the United States and Brazil.

41

---

Table of Contents

	Operating Results

				2004				2003				2002
				(In millions)
Operating Revenues:
	Natural gas			$	1,428			$	1,831			$	1,574
	Oil, condensate and NGL				305				305				350
	Other				2				5				7
		Total operating revenues			1,735				2,141				1,931
Transportation and net product costs					(54	)			(82	)			(109	)
		Total operating margin			1,681				2,059				1,822
Depreciation, depletion and amortization					(548	)			(576	)			(601	)
Production costs(1)					(210	)			(229	)			(285	)
Ceiling test and other charges(2)					(22	)			(16	)			(4	)
General and administrative expenses					(173	)			(160	)			(122	)
Taxes, other than production and income					(2	)			(5	)			(7	)
		Total operating expenses(3)			(955	)			(986	)			(1,019	)
	Operating income				726				1,073				803
Other income					8				18				5
	EBIT			$	734			$	1,091			$	808

42

---

Table of Contents

									Percent								Percent
					2004				Variance				2003				Variance				2002
Volumes, prices and costs per unit:
	Natural gas
		Volumes (MMcf)				244,857				(28	)%			338,762				(28	)%			470,082
		Average realized prices including hedges ($/Mcf)(4)			$	5.83				8	%		$	5.40				61	%		$	3.35
		Average realized prices excluding hedges ($/Mcf)(4)			$	5.90				7	%		$	5.51				74	%		$	3.17
		Average transportation costs ($/Mcf)			$	0.17				(6	)%		$	0.18				—			$	0.18
	Oil, condensate and NGL
		Volumes (MBbls)				8,818				(25	)%			11,778				(28	)%			16,462
		Average realized prices including hedges ($/Bbl)(4)			$	34.61				33	%		$	25.96				22	%		$	21.28
		Average realized prices excluding hedges ($/Bbl)(4)			$	34.75				30	%		$	26.64				25	%		$	21.38
		Average transportation costs ($/Bbl)			$	1.12				7	%		$	1.05				8	%		$	0.97
	Total equivalent volumes(MMcfe)					297,766				(27	)%			409,432				(28	)%			568,852
	Production costs($/Mcfe)
		Average lease operating costs			$	0.60				43	%		$	0.42				—			$	0.42
		Average production taxes				0.11				(21	)%			0.14				75	%			0.08
			Total production cost(1)		$	0.71				27	%		$	0.56				12	%		$	0.50
	Average general and administrative expenses ($/Mcfe)				$	0.58				49	%		$	0.39				86	%		$	0.21
	Unit of production depletion cost ($/Mcfe)				$	1.69				29	%		$	1.31				28	%		$	1.02

(1)	Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes).
(2)	Includes ceiling test charges, restructuring charges, asset impairments and gains on asset sales.
(3)	Transportation costs are included in operating expenses on our consolidated statements of income.
(4)	Prices are stated before transportation costs.

	Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

43

---

Table of Contents

				Variance
				Operating				Operating								EBIT
				Revenue				Expense				Other(1)				Impact
				Favorable/(Unfavorable)
				(In millions)
Natural Gas Revenue
	Higher prices in 2004			$	96			$	—			$	—			$	96
	Lower production volumes in 2004				(518	)			—				—				(518	)
	Impact from hedge program in 2004 versus 2003				19				—				—				19
Oil, Condensate and NGL Revenue
	Higher realized prices in 2004				72				—				—				72
	Lower production volumes in 2004				(79	)			—				—				(79	)
	Impact from hedge program in 2004 versus 2003				7				—				—				7
Depreciation, Depletion and Amortization Expense
	Higher depletion rate in 2004				—				(115	)			—				(115	)
	Lower production volumes in 2004				—				146				—				146
Production Costs
	Higher lease operating costs in 2004				—				(8	)			—				(8	)
	Lower production taxes in 2004				—				27				—				27
Other
	Higher general and administrative expenses in 2004				—				(13	)			—				(13	)
	Other				(3	)			(6	)			18				9
		Total variance 2004 to 2003		$	(406	)		$	31			$	18			$	(357	)

(1)	Consists primarily of changes in transportation costs and other income.

44

---

Table of Contents

	Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

				Variance
				Operating				Operating								EBIT
				Revenue				Expense				Other(1)				Impact
				Favorable/(Unfavorable)
				(In millions)
Natural Gas Revenue
	Higher realized prices in 2003			$	792			$	—			$	—			$	792
	Lower production volumes in 2003				(416	)			—				—				(416	)
	Impact from hedge program in 2003 versus 2002				(119	)			—				—				(119	)
Oil, Condensate and NGL Revenue
	Higher prices in 2003				62				—				—				62
	Lower production volumes in 2003				(100	)			—				—				(100	)
	Impact from hedge program in 2003 versus 2002				(7	)			—				—				(7	)
Depreciation, Depletion and Amortization Expense
	Higher depletion rate in 2003				—				(116	)			—				(116	)
	Lower production volumes in 2003				—				163				—				163
	Higher accretion expense for asset retirement obligations				—				(23	)			—				(23	)
Production Costs
	Lower lease operating costs in 2003				—				71				—				71
	Higher production taxes in 2003				—				(15	)			—				(15	)
Other
	Ceiling test and other charges				—				(12	)			—				(12	)
	Higher general and administrative costs in 2003				—				(38	)			—				(38	)
	Other				(2	)			3				40				41
		Total variance 2003 to 2002		$	210			$	33			$	40			$	283

(1)	Consists primarily of changes in transportation costs and other income.

45

---

Table of Contents

	2001 and 2002

	•	The deterioration of the energy trading environment followed by our announcement in November 2002 that we would reduce our involvement in the energy marketing and trading business and pursue an orderly liquidation of our trading portfolio.

	2003 and 2004

	•	A challenging trading environment with reduced liquidity, lower credit standing of industry participants and a general decline in the number of trading counterparties.
	•	The ongoing liquidation of our historical trading portfolio.
	•	The announcement in December 2003 that we would change our operations to primarily focus on the physical marketing of natural gas and oil produced in our Production segment.

	Natural Gas Contracts

	Production-related and other natural gas derivatives

46

---

Table of Contents

	Transportation-related contracts

Alliance

Texas Intrastate

Other

Daily capacity (MMBtu/day)

160,000

435,000

910,000

Annual demand charges (in millions)

$66

$21

$62

Expiration

2015

2006

2005 to 2028

Receipt points

AECO Canada

South Texas

Various

Delivery points

Chicago

Houston Ship Channel

Various

	•	The difference in natural gas prices at contractual receipt and delivery locations;
	•	The capital needed to use this capacity (i.e. cash margins or letters of credit associated with the purchase and sale of natural gas to use the capacity); and
	•	The capacity required to meet our other long term obligations.

	Storage contracts

	Power Contracts

47

---

Table of Contents

48

---

Table of Contents

	Operating Results

						2004
						(Restated)				2003				2002
						(In millions)
Overall EBIT:
	Gross margin(1)					$	(508	)		$	(636	)		$	(1,316	)
	Operating expenses						(54	)			(183	)			(677	)
		Operating loss					(562	)			(819	)			(1,993	)
	Other income						23				10				16
		EBIT				$	(539	)		$	(809	)		$	(1,977	)
Gross Margin by Significant Contract Type:
Natural Gas Contracts
		Production-related and other natural gas derivatives
			Changes in fair value on positions designated as hedges on December 1, 2004			$	(439	)		$	(425	)		$	(601	)
			Changes in fair value on production-related options				53				—				—
			Changes in fair value on other natural gas positions				44				2				(486	)
			Early contract terminations				48				(8	)			—
				Total production-related and other natural gas derivatives			(294	)			(431	)			(1,087	)
		Transportation-related contracts
			Demand charges				(149	)			(156	)			(36	)
			Settlements				39				4				16
				Total transportation-related contracts			(110	)			(152	)			(20	)
		Storage contracts
			Demand charges				(2	)			(21	)			(15	)
			Settlements				—				31				56
			Early contract terminations				—				(17	)			—
				Total storage contracts			(2	)			(7	)			41
		Total gross margin — natural gas contracts					(406	)			(590	)			(1,066	)
Power Contracts
		Changes in fair value on Cordova tolling agreement					(36	)			75				(112	)
		Other power derivatives
			Changes in fair value				(85	)			(96	)			(138	)
			Early contract terminations				19				(25	)			—
				Total other power derivatives			(66	)			(121	)			(138	)
				Total gross margin — power contracts			(102	)			(46	)			(250	)
				Total gross margin		$	(508	)		$	(636	)		$	(1,316	)

(1)	Gross margin for our Marketing and Trading segment consists of revenues from commodity trading and origination activities less the costs of commodities sold, including changes in the fair value of our derivative contracts.

49

---

Table of Contents

	Natural Gas Contracts

	Production-related and other natural gas derivatives

	•	Derivatives designated as hedges. The amounts in the above table represent changes in the fair values of derivative contracts that were designated as accounting hedges of our Production segment’s natural gas production on December 1, 2004. The losses indicated were a result of increases in natural gas prices in 2002, 2003 and 2004 relative to the fixed prices in these contracts and these losses were historically included in our financial results. Following their designation as accounting hedges, future income impacts of these contracts will be reflected in our Production segment. However, the act of designating these contracts as hedges will have no impact on El Paso’s overall cash flows in any period.
	•	Production-related options. As natural gas prices decreased in the fourth quarter of 2004, the fair value of the options we entered into in 2004 increased. These contracts had a fair value of $120 million as of December 31, 2004, which includes the premium we initially paid for the options. If gas prices remain above the option price of $6.00 per MMBtu, the fair value of these contracts will decrease over their term since they would expire unexercised. We paid a total net premium of $64 million for these options and the additional option contracts we entered into in the first quarter of 2005.
	•	Other natural gas derivatives. Because we were obligated to purchase more natural gas at a fixed price than we sold under these contracts during 2003 and 2004, the fair value of these contracts increased as natural gas prices increased during those years. In 2002, we incurred significant losses on these contracts because of lower price volatility and the deterioration of the energy trading environment described above.
	•	Early contract terminations. This amount includes a $50 million gain recognized on the termination of an LNG contract at the Elba Island facility in 2004.

50

---

Table of Contents

	Transportation-related contracts

	•	In the fourth quarter of 2002, we began accounting for our transportation contracts as accrual-based contracts with the adoption of EITF Issue No. 02-3. As a result, our 2002 results include the demand charges and accrual settlements we recorded during the fourth quarter of 2002. The mark-to-market losses on these contracts during the first nine months of 2002 are included in the change in fair value of our other natural gas derivatives above. Our annual demand charges on these contracts were approximately $149 million in 2004 and $156 million in 2003. The decrease in 2004 was due to the liquidation of a number of these positions prior to their original settlement dates.
	•	Our ability to use our Alliance pipeline capacity contract was relatively consistent during 2003 and 2004, allowing us to recover approximately 73 percent of the demand charges we paid each year. This resulted from the price differentials between the receipt and delivery points staying relatively consistent during these years, which resulted in EBIT losses from this contract of $15 million in 2003 and $17 million during 2004. Our Texas Intrastate transportation contracts incurred EBIT losses of $36 million in 2003 and $26 million in 2004. We were unable to utilize a significant portion of the capacity on these pipelines primarily due to a decrease in the price differentials between South Texas receipt points and Houston Ship Channel delivery locations under the contracts. If the differences in these prices do not improve, we will continue to experience losses on these contracts.

	Storage contracts

	Power Contracts

	Cordova tolling agreement

	Other power derivatives

	•	Historically, many of our contract origination activities related to power contracts. Because of the changes in the energy trading environment and the change in focus of our Marketing and Trading segment, these activities substantially decreased from 2002 to 2004.
	•	The ongoing liquidation of our trading book significantly impacted our power contracts. We also recorded a $25 million gain on the termination of a power contract with our Power segment in 2004, which was eliminated in El Paso’s consolidated results.
	•	In the first quarter of 2005, we assigned our contracts to supply power to our Power segment’s Cedar Brakes I and II entities to Constellation Energy Commodities Group, Inc. We recorded a loss of approximately $30 million during the fourth quarter of 2004 upon signing the assignment and

51

---

Table of Contents

		termination agreement. These contracts decreased in fair value by $64 million, $67 million and $48 million in 2004, 2003 and 2002.
	•	In the first quarter of 2002, we recorded an $80 million gain related to a power supply agreement that we entered into with our Power segment. The gain, which was associated with the UCF restructured power contract, was eliminated from El Paso’s consolidated results. Later in 2002, we terminated this contract and entered into a new power supply agreement with Morgan Stanley related to UCF. The Morgan Stanley contract decreased in fair value by $72 million, $77 million and $58 million in 2004, 2003 and 2002.
	•	Our remaining power contracts, which include those that are used to manage the risk associated with our obligations to supply power, increased in fair value by $81 million in 2004 and $48 million in 2003.

	Operating Expenses

	•	In 2002 and 2003, we recorded $487 million and $26 million of charges in operating expenses related to the Western Energy Settlement. In late 2003, this obligation was transferred to our corporate operations.
	•	In 2003 and 2004, we recorded $28 million and $10 million of bad debt expense associated with a fuel supply agreement we have with the Berkshire power plant.
	•	As a result of the decision in November 2002 to reduce the size of our trading portfolio, we experienced a significant decline in employee headcount, which resulted in lower general and administrative expenses in 2003. This decline in headcount, coupled with the closing of our London office in 2003, contributed to further decreases in general and administrative expenses in 2004.
	•	Overall cost reduction efforts at the corporate level and our reduced level of operations resulted in lower corporate overhead being allocated to us in 2003 and 2004.

	International Power Plant Operations

	•	Macae. Our Macae power plant sells a majority of its power to the wholesale Brazilian power market. Macae also has a contract that requires Petrobras to make minimum revenue payments until August 2007. Petrobras did not pay amounts due under the contract for December 2004 and January 2005 and filed a lawsuit and for arbitration. For a further discussion of this matter, see Notes to Consolidated Financial Statements, Note 17, on page F-89. The future financial performance of the Macae plant will be affected by the outcome of this dispute and by regional changes in power markets.
	•	Porto Velho. Our Porto Velho plant sells power to Eletronorte under two power sales agreements that expire in 2010 and 2023. Eletronorte absorbs substantially all of the plant’s fuel costs and purchases all of the power the plant is able to generate, as long as the plant operates within availability levels

52

---

Table of Contents

		required by these contracts. As a result, the profitability of the plant is dependent primarily on maintaining these availability levels through efficient operations and maintenance practices. These availability levels are expected to decrease in 2005 because of an equipment failure at the plant during 2004 that is expected to be repaired by the first quarter of 2006. In addition, we are negotiating potential contractual amendments with Eletronorte that may alter the volumes and prices of power to be sold under the contracts and may affect our future earnings. For a further discussion of these negotiations, see Notes to Consolidated Financial Statements, Note 17, on page F-89.
	•	Manaus and Rio Negro. In January 2005, we signed new power sales contracts for our Manaus and Rio Negro power plants with Manaus Energia. Under these new contracts, Manaus Energia will pay a price for its power that is similar to that in the previous contracts. In addition, Manaus Energia will assume ownership of the Manaus and Rio Negro plants in 2008. Based on this ownership transfer and the contract terms, we will deconsolidate the plants in the first quarter of 2005 and begin to account for them as equity investments. In addition, the earnings from these assets will decrease as a result of the new contracts.
	•	Other. The power sales contract of the Araucaria power plant is currently in international arbitration due to non-payment by the utility that purchases power from the plant. As a result, Araucaria ceased its operations in 2003. For a further discussion of these arbitration proceedings, see Notes to Consolidated Financial Statements, Note 17, on page F-89.

	Domestic Power Plant Operations

53

---

Table of Contents

	Domestic Power Contract Restructuring Business

	Operating Results

					2004
					(Restated)				2003				2002
					(In millions)
Overall EBIT:
	Gross margin(1)				$	643			$	865			$	1,103
	Operating expenses
		Loss on long-lived assets				(599	)			(185	)			(160	)
		Other operating expenses				(468	)			(693	)			(591	)
			Operating income (loss)			(424	)			(13	)			352
	Earnings from unconsolidated affiliates
		Impairments and net losses on sale				(395	)			(347	)			(426	)
		Equity in earnings				146				256				170
	Other income (expense)					74				76				(84	)
		EBIT			$	(599	)		$	(28	)		$	12
EBIT by Area:
	International power
		Brazilian operations			$	52			$	177			$	78
		Asian operations				(148	)			49				(3	)
		Other				7				70				(243	)
						(89	)			296				(168	)
	Domestic power plant operations
		MCV				(171	)			29				28
		Sold or sale announced				(58	)			(400	)			55
		Other				—				(12	)			(3	)
						(229	)			(383	)			80
	Domestic power contract restructuring activities					(228	)			150				341
	Power turbine impairments					(1	)			(33	)			(162	)
	Other(2)					(52	)			(58	)			(79	)
		EBIT			$	(599	)		$	(28	)		$	12

(1)	Gross margin for our Power segment consists of revenues from our power plants and the initial net gains and losses incurred in connection with the restructuring of power contracts, as well as the subsequent revenues, cost of electricity purchases and changes in fair value of those contracts. The cost of fuel used in the power generation process is included in operating expenses.

54

---

Table of Contents

(2)	Other consists of the indirect expenses and general and administrative costs associated with our domestic and international operations, including legal, finance, and engineering costs. Direct general and administrative expenses of our domestic and international operations are included in EBIT of those operations.

				2004
				(Restated)				2003				2002
				(In millions)
Brazil
	Earnings from consolidated and unconsolidated plant operations			$	235			$	177			$	97
	Manaus and Rio Negro impairment				(183	)			—				—
	Contract termination fee				—				—				(19	)
		Total Brazil			52				177				78
Asia
	Earnings from consolidated and unconsolidated plant operations				61				49				45
	Asian asset impairments				(212	)			—				—
	PPN impairment				—				—				(41	)
	Meizhou Wan impairment				—				—				(7	)
	Other				3				—				—
		Total Asia			(148	)			49				(3	)
Other International Power
	Earnings from consolidated and unconsolidated plant operations				24				42				102
	Argentina gain on sale (impairment)				—				28				(342	)
	Other impairments				(3	)			—				(3	)
	Other				(14	)			—				—
		Total Other			7				70				(243	)
		Total		$	(89	)		$	296			$	(168	)

	Macae and Porto Velho

55

---

Table of Contents

	Manaus and Rio Negro

	South American Pipelines

	•	The conversion of two of our Chinese power plants from heavy fuel oil to natural gas, which lowered the production costs at these facilities;
	•	The issuance of debt at our Meizhou Wan plant in 2004, which reduced liquidity concerns about the plant’s operation. This plant had been partially impaired in 2002 based on those concerns;
	•	The favorable completion of negotiations with Philippine regulators on fuel and power prices at our East Asia plants; and
	•	The closing of our Singapore office in 2002, which lowered operating expenses.

56

---

Table of Contents

	•	Dominican Republic. An economic crisis in the Dominican Republic during 2002 and 2003 significantly reduced the amount of power generated and impacted our ability to collect some of the receivables at our power plants in the country during 2003 and 2004. The Dominican Republic’s economy began to improve in late 2004 following the election of a new president. See Notes to Consolidated Financial Statements, Note 22, on page F-110 for a further discussion of our investments in the Dominican Republic.
	•	El Salvador. In 2002, we restructured a power contract at our El Salvador power facility, which resulted in a $77 million gain in 2002. This restructuring converted the plant to a merchant facility that sells power under short-term contracts and on the open market. As a result, the power and resulting earnings generated by this plant in 2002 were higher than in 2003 and 2004.
	•	Argentina. In 2002, we impaired our investment in Argentina based on new legislation resulting from an economic crisis in Argentina. We sold these plants in 2003 and are attempting to recover a portion of these losses through international arbitration.
	•	Other. Our other international operations are also sensitive to changes in the local demand for power and the cost of fuel to run the power facilities. Our power plant in England benefited from increases in demand and power prices in 2004, but this was largely offset by higher fuel prices at our Central American power plants.

				2004				2003				2002
				(In millions)
MCV
	Earnings from plant operations			$	(10	)		$	29			$	28
	Impairments				(161	)			—				—
Assets sold or expected to be sold in 2005
	Earnings from consolidated and unconsolidated plant operations(1)				47				103				144
	Impairments and write-offs				(105	)			(503	)			(89	)
Other					—				(12	)			(3	)
		Total		$	(229	)		$	(383	)		$	80

(1)	During 2004 and 2003, we recorded $60 million and $105 million of operating income generated by the power plants from Chaparral, an equity investment we consolidated effective January 1, 2003. Prior to January 2003, we recorded our earnings from the Chaparral power plants through the equity earnings and management fees we received which were approximately $124 million in 2002.

57

---

Table of Contents

	•	In 2004, 2003, and 2002, we incurred approximately $105 million, $208 million and $89 million of asset impairments, net of realized gains and losses, in our domestic power business based on the anticipated sale of these assets as well as operational and contractual issues at several of these facilities. During 2004, these amounts included $81 million related to impairing the earnings of assets held for sale, in addition to $24 million of impairments, net of gains and losses, on long-lived assets related to our held for sale merchant and contracted plants. We also incurred a $25 million loss on the termination of a power contract with our Marketing and Trading segment related to one of the assets sold, which is reflected in our 2004 earnings from plant operations.
	•	In 2003, we also:

	•	Recorded an impairment of our Chaparral investment of $207 million based on a decline in the investment’s value that was considered to be other than temporary. See Notes to Consolidated Financial Statements, Notes 2 and 3, on pages F-58 to F-62, and Note 22, on page F-110, for further discussion of these matters.
	•	Wrote-off a receivable of $88 million from Milford Power LLC related to the transfer of our interest in Milford Power LLC to its lenders after continued difficulties with this facility.

				2004				2003				2002
				(In millions)
Restructuring gain				$	—			$	—			$	331
Impairments and gains (losses) on sale
		UCF			(99	)			—				—
		Cedar Brakes I and II			(227	)			—				—
		Other			—				(15	)			—
Change in fair value of contracts
		UCF, Cedar Brakes I and II			97				119				9
		MRF II			4				10				—
		Other			(2	)			15				—
Other					(1	)			21				1
	EBIT			$	(228	)		$	150			$	341

58

---

Table of Contents

		Earnings				Cash
		Recognized				Received
		(In millions)
General partner’s share of distributions		$	65			$	67
Proportionate share of income available to common unit holders			16				26
Series C units			14				24
Gain on issuance by GulfTerra of its common units			5				—
		$	100			$	117

59

---

Table of Contents

				2004				2003				2002
Gathering and processing gross margins(1)				$	165			$	132			$	349
Operating expenses
	Gain (loss) on long-lived assets				(508	)			(173	)			179
	Other operating expenses				(122	)			(152	)			(255	)
		Operating income (loss)			(465	)			(193	)			273
Other income
	Gain (loss) on unconsolidated affiliates				501				181				(50	)
	Other income				84				145				66
	EBIT			$	120			$	133			$	289
Volumes and Prices:
	Gathering
		Volumes (BBtu/d)			203				357				3,023
		Prices ($/MMBtu)		$	0.10			$	0.18			$	0.17
	Processing
		Volumes (BBtu/d)			2,780				3,206				3,920
		Prices ($/MMBtu)		$	0.14			$	0.10			$	0.10

(1)	Gross margins consist of operating revenues less cost of products sold. We believe that this measurement is more meaningful for understanding and analyzing our Field Services segment’s operating results because commodity costs play such a significant role in the determination of profit from our midstream activities.

60

---

Table of Contents

				2004				2003				2002
Gathering and Processing Activities
	Gathering and processing margins			$	165			$	132			$	349
	Operating expenses				(122	)			(152	)			(255	)
	Other				10				(7	)			(53	)
					53				(27	)			41
GulfTerra/ Enterprise Related Items
	Sale of assets to GulfTerra
		San Juan, Texas, and New Mexico assets			—				—				210
		Release of Chaco lease obligation			—				67				—
		Pipeline integrity indemnification			9				(74	)			—
	Sale of assets/interests to Enterprise
		Gain on sale of GP/ LP interests			507				266				—
		Minority interest			(32	)			—				—
		South Texas			(11	)			(167	)			—
		Indian Springs			(13	)			—				—
		Goodwill impairment			(480	)			—				—
	Equity earnings				100				153				69
					80				245				279
Other Asset Sales
	Asset impairments and gains (losses) on sales
		North Louisiana			—				—				(66	)
		Dauphin Island/ Mobile Bay			—				(86	)			—
		Other			(13	)			1				35
					(13	)			(85	)			(31	)
	EBIT			$	120			$	133			$	289

61

---

Table of Contents

	•	2002 — the gain on our sale of our Texas and New Mexico gathering and pipeline assets and our San Juan gathering assets.
	•	2003 — the release from our Chaco lease obligation in return for communication assets and clarification of our obligation to provide for pipeline integrity costs through 2006.

			2004				2003				2002
Impairments, contract terminations and gains (losses) on asset sales:
	Telecommunications business		$	—			$	(396	)		$	(168	)
	LNG business			—				(108	)			—
	Aircraft.			8				(8	)			—
Earnings from operations:
	Financial services business			17				21				(18	)
	Petroleum ship charters			15				1				(13	)
	Telecommunications business			—				(44	)			(65	)
Restructuring charges				(91	)			(91	)			(51	)
Debt gains (losses):
	Foreign currency fluctuations on Euro-denominated debt			(26	)			(112	)			(95	)
	Early extinguishment/exchange of debt			(18	)			(49	)			21
Change in litigation, insurance and other reserves				(116	)			(19	)			14
Other				(6	)			(47	)			(12	)
Total EBIT			$	(217	)		$	(852	)		$	(387	)

62

---

Table of Contents

			2004				2003				2002
Long-term debt, including current maturities			$	1,510			$	1,628			$	1,153
Revolving credit facilities				109				121				16
Commercial paper				—				—				26
Other interest				27				73				130
Capitalized interest				(39	)			(31	)			(28	)
	Total interest and debt expense		$	1,607			$	1,791			$	1,297

	Year Ended December 31, 2004 Compared to Year Ended December 31, 2003

	Year Ended December 31, 2003 Compared to Year Ended December 31, 2002

63

---

Table of Contents

	•	state income taxes, net of federal income tax effect;
	•	earnings/losses from unconsolidated affiliates where we anticipate receiving dividends;
	•	foreign income taxed at different rates;
	•	abandonments and sales of foreign investments;
	•	valuation allowances;
	•	non-deductible dividends on the preferred stock of subsidiaries;
	•	non-conventional fuel tax credits; and
	•	non-deductible goodwill impairments.

64

---

Table of Contents

65

---

Table of Contents

						10 Percent								10 Percent
						Increase								Decrease
		Fair				Fair								Fair
		Value				Value				Change				Value				Change
Derivatives designated as hedges		$	(536	)		$	(672	)		$	(136	)		$	(400	)		$	136
Other commodity-based derivatives			(61	)			(84	)			(23	)			(24	)			37
Total		$	(597	)		$	(756	)		$	(159	)		$	(424	)		$	173

66

---

Table of Contents

67

---

Table of Contents

			Pension Benefits								Other Postretirement Benefits
			Net Benefit				Projected				Net Benefit				Accumulated
			Expense				Benefit				Expense				Postretirement
			(Income)				Obligation				(Income)				Benefit Obligation
One percent increase in:
	Discount rates		$	(13	)		$	(197	)		$	—			$	(37	)
	Expected return on plan assets			(22	)			—				(1	)			—
	Rate of compensation increase			2				4				—				—
	Health care cost trends			—				—				1				19
One percent decrease in:
	Discount rates		$	15			$	236			$	—			$	40
	Expected return on plan assets(1)			22				—				1				—
	Rate of compensation increase			(1	)			(4	)			—				—
	Health care cost trends			—				—				(1	)			(18	)

(1)	If the actual return on plan assets was one percent lower than the expected return on plan assets, our expected cash contributions to our pension and other postretirement benefit plans would not significantly change.

68

---

Table of Contents

	•	Commodity Price Risk

	•	Natural gas prices change, impacting the forecasted sale of natural gas in our Production segment;
	•	Price spreads between natural gas and natural gas liquids change, making the natural gas liquids we produce in our Field Services segment less valuable;
	•	Locational price differences in natural gas change, affecting our ability to optimize pipeline transportation capacity contracts held in our Marketing and Trading segment; and
	•	Electricity and natural gas prices change, affecting the value of our natural gas contracts, power contracts and tolling contracts held in our Marketing and Trading and Power segments.

	•	Interest Rate Risk

	•	Changes in interest rates affect the interest expense we incur on our variable-rate debt and the fair value of our fixed-rate debt; and
	•	Changes in interest rates used in the estimation of the fair value of our derivative positions can result in increases or decreases in the unrealized value of those positions.

	•	Foreign Currency Exchange Rate Risk

	•	Weakening or strengthening of the U.S. dollar relative to the Euro can result in an increase or decrease in the value of our Euro-denominated debt obligations and the related interest costs associated with that debt; and
	•	Changes in foreign currencies exchange rates where we have international investments may impact the value of those investments and the earnings and cash flows from those investments.

	•	Forward contracts, which commit us to purchase or sell energy commodities in the future, involving the physical delivery of an energy commodity, and energy related contracts including transportation, storage, transmission and power tolling arrangements;
	•	Futures contracts, which are exchange-traded standardized commitments to purchase or sell a commodity or financial instrument, or to make a cash settlement at a specific price and future date;
	•	Options, which convey the right to buy or sell a commodity, financial instrument or index at a predetermined price;

69

---

Table of Contents

	•	Swaps, which require payments to or from counterparties based upon the differential between two prices for a predetermined contractual (notional) quantity; and
	•	Structured contracts, which may involve a variety of the above characteristics.

	Marketing and Trading

	Production

70

---

Table of Contents

							10 Percent Increase								10 Percent Decrease
			Fair Value				Fair Value				(Change)				Fair Value				Increase
			(In millions)
Impact of changes in commodity prices on derivative commodity instruments
	December 31, 2004		$	(557	)		$	(697	)		$	(140	)		$	(417	)		$	140
	December 31, 2003		$	(45	)		$	(60	)		$	(15	)		$	(30	)		$	15

	Field Services

	Debt

			December 31, 2004																																December 31, 2003
			Expected Fiscal Year of Maturity of Carrying Amounts
																															Fair				Carrying				Fair
			2005				2006				2007				2008				2009				Thereafter				Total				Value				Amounts				Value
			(Dollars in millions)
Liabilities:
Short-term debt — fixed rate			$	7																							$	7			$	8			$	8			$	8
	Average interest rate			6.2	%
Long-term debt and other obligations, including current portion — fixed rate			$	740			$	1,111			$	797			$	703			$	1,464			$	12,932			$	17,747			$	18,387			$	20,152			$	19,594
	Average interest rate			8.2	%			6.7	%			7.3	%			7.5%				6.1	%			7.6	%
Long-term debt and other obligations, including current portion — variable rate			$	197			$	33			$	27			$	20			$	1,165			$	—			$	1,442			$	1,442			$	1,572			$	1,572
	Average interest rate			9.1	%			4.8	%			4.7	%			5.6%				5.6	%			—

71

---

Table of Contents

	Derivatives from Power Contract Restructuring Activities

	Debt

	Power Contracts

72

---

Table of Contents

	Quarter and Six Months Ended June 30, 2005 and 2004

	•	Our pipeline segment made further progress on its plans by settling a rate case at SNG, recontracting with large customers on the SNG and EPNG systems, and making progress on several pipeline expansion projects in our pipeline systems and at our Elba Island LNG facility;
	•	Our production segment continued to make progress on its turnaround and the stabilization of its production rates through its capital program and four strategic acquisitions of natural gas and oil properties totalling approximately $1.1 billion, including our recently announced Medicine Bow acquisition which we expect to close in the third quarter of 2005 for approximately $814 million;
	•	We continued the exit of our legacy trading business through the assignment or termination of derivative contracts associated with Cedar Brakes I and II;
	•	We completed the sale of a number of assets and investments including, among others, our remaining general and limited partnership interests in Enterprise, interests in Cedar Brakes I and II, the Lakeside Technology Center, and our interest in a Korean power facility. Total proceeds from these sales were approximately $1.2 billion ($918 million through June 30, 2005);
	•	We reduced our net debt to $15.9 billion (debt of $17.48 billion, net of cash of $1.54 billion) as of June 30, 2005, lowering our net debt by $1.1 billion; and
	•	We completed a private placement of $750 million of 4.99% convertible perpetual preferred stock. The proceeds from this offering were used to prepay our remaining deferred payment obligation on the Western Energy Settlement for $442 million and to redeem the $300 million of EPTP, 8.25%, Series A cumulative preferred stock.

Short-term financing obligations, including current maturities			$	955
Long-term financing obligations				18,241
	Total debt as of December 31, 2004			19,196
Principal amounts borrowed				466
Repayments/retirements of principal				(1,563	)
Sales of entities(1)				(546	)
Other reductions				(75	)
	Total debt as of June 30, 2005		$	17,478

(1)	Related to the sale of Cedar Brakes I and II.

73

---

Table of Contents

						2005				2004
						(In billions)
Cash Inflows
	Continuing operating activities
		Net loss before discontinued operations				$	(0.1	)		$	(0.1	)
		Non-cash income adjustments					0.9				0.8
		Change in assets and liabilities					(0.8	)			(0.6	)
							—				0.1
	Continuing investing activities
		Net proceeds from the sale of assets and investments					0.8				0.2
		Proceeds from settlement of foreign currency derivatives					0.1				—
		Reduction of restricted cash					0.1				0.4
		Other					0.1				0.1
							1.1				0.7
	Continuing financing activities
		Net proceeds from the issuance of long-term debt					0.5				0.1
		Proceeds from the issuance of preferred and common stock					0.7				0.1
		Contributions from discontinued operations					0.1				0.9
							1.3				1.1
			Total cash inflows			$	2.4			$	1.9
Cash Outflows
	Continuing investing activities
		Additions to property, plant and equipment				$	0.8			$	0.8
		Net cash paid for acquisitions					0.2				—
							1.0				0.8
	Continuing financing activities
		Payments to retire debt and redeem preferred interests					1.6				1.0
		Redemption of preferred stock					0.3				—
		Other					0.1				0.1
							2.0				1.1
			Total cash outflows			$	3.0			$	1.9
				Net change in cash		$	(0.6	)		$	—

74

---

Table of Contents

Production exploration, development and acquisition expenditures			$	(0.6	)
Pipeline expansion, maintenance and integrity projects				(0.3	)
Decrease in restricted cash				0.1
Settlement of a foreign currency derivative				0.1
Proceeds from sales of assets and investments				0.8
	Total continuing investing activities		$	0.1

75

---

Table of Contents

					Maturity				Maturity				Maturity				Maturity				Maturity				Total
					Less Than				1 to 3				4 to 5				6 to 10				Beyond				Fair
Source of Fair Value					1 year				Years				Years				Years				10 Years				Value
					(In millions)
Derivatives designated as hedges
	Assets				$	16			$	9			$	—			$	—			$	—			$	25
	Liabilities					(423	)			(196	)			(27	)			(19	)			—				(665	)
		Total derivatives designated as hedges				(407	)			(187	)			(27	)			(19	)			—				(640	)
Assets from power contract restructuring derivatives(1)						20				40				—				—				—				60
Other commodity-based derivatives
	Exchange-traded positions(2)
		Assets				115				243				135				13				—				506
		Liabilities				(102	)			(9	)			(1	)			—				—				(112	)
	Non-exchange-traded positions
		Assets				421				379				197				151				27				1,175
		Liabilities(1)				(394	)			(591	)			(312	)			(186	)			(50	)			(1,533	)
			Total other commodity-based derivatives			40				22				19				(22	)			(23	)			36
	Total commodity-based derivatives				$	(347	)		$	(125	)		$	(8	)		$	(41	)		$	(23	)		$	(544	)

(1)	Includes $6 million of intercompany derivatives that eliminate in consolidation and had no impact on our consolidated assets and liabilities from price risk management activities for the six months ended June 30, 2005.
(2)	Exchange-traded positions are those traded on active exchanges such as the New York Mercantile Exchange, the International Petroleum Exchange and the London Clearinghouse.

								Derivatives
								from Power				Other				Total
				Derivatives				Contract				Commodity-				Commodity-
				Designated				Restructuring				Based				Based
				as Hedges(1)				Activities				Derivatives				Derivatives
				(In millions)
Fair value of contracts outstanding at January 1, 2005				$	(536	)		$	665			$	(61	)		$	68
	Fair value of contract settlements during the period				182				(616	)			282				(152	)
	Change in fair value of contracts				(286	)			11				(182	)			(457	)
	Option premiums received, net				—				—				(3	)			(3	)
		Net change in contracts outstanding during the period			(104	)			(605	)			97				(612	)
Fair value of contracts outstanding at June 30, 2005				$	(640	)		$	60			$	36			$	(544	)

(1)	In December 2004, we designated a number of our other commodity-based derivative contracts in our Marketing and Trading segment as hedges of our 2005 and 2006 natural gas production. As a result, we reclassified this $592 million liability to derivatives designated as hedges in December 2004.

76

---

Table of Contents

77

---

Table of Contents

				Quarter Ended								Six Months Ended
				June 30,								June 30,
				2005				2004				2005				2004
				(In millions)
Regulated Business
	Pipelines			$	309			$	308			$	721			$	694
Non-regulated Businesses
	Production				176				204				359				408
	Marketing and Trading				(30	)			(152	)			(215	)			(316	)
	Power				(381	)			102				(431	)			(67	)
	Field Services				(3	)			27				179				63
		Segment EBIT			71				489				613				782
Corporate					(12	)			9				(102	)			36
		Consolidated EBIT from continuing operations			59				498				511				818
Interest and debt expense					(340	)			(410	)			(690	)			(833	)
Distributions on preferred interests of consolidated subsidiaries					(3	)			(6	)			(9	)			(12	)
Income taxes					51				(48	)			57				(58	)
	Income (loss) from continuing operations				(233	)			34				(131	)			(85	)
Discontinued operations, net of income taxes					(5	)			(29	)			(1	)			(106	)
	Net income (loss)			$	(238	)		$	5			$	(132	)		$	(191	)

Pipelines		Our Pipelines segment generated EBIT of $721 million, which was slightly above our expectations for the period.
Production		Our Production segment generated EBIT of $359 million, which was slightly above our expectations for the period. Lower than expected production volumes and higher depreciation and production costs were more than offset by higher than expected commodity prices.
Marketing and Trading		Our Marketing and Trading segment generated an EBIT loss of $215 million, which was a greater loss than our expectations. The performance was driven by significant mark-to-market losses on our production-related derivatives due to natural gas price increases during the period. In addition, our power contracts, primarily our Cordova tolling agreement, experienced significant losses during the period due to changes in natural gas and power prices.
Power		Our Power segment generated an EBIT loss of $431 million, which was a greater loss than expected and was impacted by significant impairments of our Macae project in Brazil and impairments of our Asian and Central American power assets based on additional information received about the value we may receive upon the sale of these assets.
Field Services		Our Field Services segment generated EBIT of $179 million, which was consistent with our expectations and was primarily due to the gain on the sale of our remaining interests in Enterprise.

78

---

Table of Contents

			Quarter Ended								Six Months Ended
			June 30,								June 30,
Pipelines Segment Results			2005				2004				2005				2004
			(In millions except volume amounts)
Operating revenues			$	653			$	617			$	1,421			$	1,338
Operating expenses				(391	)			(357	)			(797	)			(730	)
	Operating income			262				260				624				608
Other income				47				48				97				86
	EBIT		$	309			$	308			$	721			$	694
Throughput volumes (BBtu/d)				20,316				19,935				21,444				21,223

			Quarter Ended June 30,																Six Months Ended June 30,
			Revenue				Expense				Other				EBIT				Revenue				Expense				Other				EBIT
			Favorable/(Unfavorable)																Favorable/(Unfavorable)
			(In millions)																(In millions)
Contract modifications/ terminations/ settlements			$	14			$	—			$	1			$	15			$	46			$	—			$	1			$	47
Gas not used in operations, processing revenues and other natural gas sales				(1	)			10				—				9				19				1				—				20
Favorable resolution in 2004 of measurement dispute at a processing plant				—				—				—				—				(10	)			—				—				(10	)
Pipeline expansions				22				(8	)			2				16				38				(15	)			2				25
Higher allocated costs				—				(25	)			—				(25	)			—				(46	)			—				(46	)
Equity earnings from our investment in Citrus				—				—				(3	)			(3	)			—				—				5				5
Other(1)				1				(11	)			(1	)			(11	)			(10	)			(7	)			3				(14	)
	Total impact on EBIT		$	36			$	(34	)		$	(1	)		$	1			$	83			$	(67	)		$	11			$	27

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

79

---

Table of Contents

80

---

Table of Contents

81

---

Table of Contents

	Overview

	Significant Operational Factors Since December 31, 2004

	•	Higher realized prices. During the first six months of 2005, we continued to benefit from a strong commodity pricing environment. Realized natural gas prices, which include the impact of our hedges, increased eight percent while oil, condensate and NGL prices increased 33 percent compared to 2004.
	•	Average daily production of 775 MMcfe/d (excluding discontinued operations of 3 MMcfe/d). Our average daily production in the second quarter of 2005 increased approximately two percent over the first quarter of 2005 and was relatively stable compared with the third and fourth quarters of 2004. Specifically, during the last twelve months we have experienced increased production in our onshore region, relatively stable production in our offshore Gulf of Mexico region, and declining production in our Texas Gulf Coast region due to normal declines and mechanical well failures. In addition, we acquired the remaining interest in UnoPaso located in Brazil in July 2004 and began consolidating this operation. During the first six months of 2005, our operations in Brazil produced at an average of approximately 54 MMcfe/d, and our first quarter 2005 acquisitions of domestic producing properties discussed below benefited our average daily production by approximately 44 MMcfe/d. In July 2005, hurricanes in the Gulf of Mexico caused us to shut in production for periods of time impacting production volumes by approximately 12 MMcfe/d for the month.

82

---

Table of Contents

	•	Acquisitions and other capital expenditures. During the first six months of 2005, our capital expenditures of $651 million included acquisitions in east and south Texas and the purchase of the interest held by one of our partners under a net profits interest agreement for a total of $271 million. These acquisitions added properties with approximately 140 Bcfe of proved reserves and 52 MMcfe/d of production at the acquisition dates. More importantly, the Texas acquisitions offer additional exploration upside in two of our key operating areas. We have integrated these acquisitions into our operations with minimal additional administrative expenses.

In July 2005, we announced we will acquire Medicine Bow, a privately held energy company with an estimated 356 Bcfe of proved reserves, primarily in the Rocky Mountains and east Texas, for $814 million. Of this proved reserve amount, our net interest in approximately 226 Bcfe will not be consolidated in our reserves, as these reserves are owned by an unconsolidated affiliate of Medicine Bow. The operating results associated with these unconsolidated reserves will be reported through an equity interest. Concurrent with this announcement, our Marketing and Trading segment entered into several derivative positions associated with the properties to be acquired as further discussed on page 89. The acquisition of these properties will complement our existing core operations, diversify our commodity mix and increase our reserve life. The transaction is expected to close during the third quarter of 2005.

	•	Drilling Results. In 2005, we have announced deep shelf discoveries at West Cameron Block 75 and Block 62 in the Gulf of Mexico. At West Cameron Block 75, we tested the discovery and anticipate deliverability of approximately 40 MMcfe/d to begin in the fourth quarter of 2005, after the installation of facilities. We own a 36 percent working interest and an approximate 30 percent net revenue interest in the West Cameron Block 75.

	Outlook for the last six months of 2005

	•	Total capital expenditures of approximately $1.1 billion for the last six months of 2005, including amounts to be paid to acquire Medicine Bow.
	•	Daily production volumes for the year to average in excess of 810 MMcfe/d, including approximately 10 MMcfe/d expected from the Medicine Bow acquisition and 24 MMcfe/d from Medicine Bow’s interest in an unconsolidated affiliate.
	•	Cash operating costs to be approximately $1.45/Mcfe as we continue to focus on cost control, operating efficiencies, and process improvements.
	•	Industry-wide increases in drilling and oilfield service costs that will require constant monitoring of capital spending programs.
	•	A domestic unit of production depletion rate of $2.10/ Mcfe in the third quarter of 2005 as compared to $2.04/ Mcfe in the second quarter of 2005, due to higher finding and development costs and the costs of acquired reserves. We also expect a higher depletion rate in the fourth quarter of 2005 as we complete the announced Medicine Bow acquisition.

83

---

Table of Contents

	Production Hedge Position

84

---

Table of Contents

	Operating Results

				Quarter Ended								Six Months
				June 30,								Ended June 30,
Production Segment Results				2005				2004				2005				2004
				(In millions)
Operating Revenues:
	Natural gas			$	354			$	363			$	707			$	731
	Oil, condensate and NGL				96				66				181				143
	Other				2				1				3				2
		Total operating revenues			452				430				891				876
Transportation and net product costs(1)					(12	)			(13	)			(25	)			(27	)
		Total operating margin			440				417				866				849
Operating Expenses:
	Depreciation, depletion and amortization				(157	)			(131	)			(303	)			(271	)
	Production costs(2)				(59	)			(44	)			(114	)			(86	)
	Restructuring charges				(2	)			(2	)			(2	)			(11	)
	General and administrative expenses				(43	)			(37	)			(84	)			(73	)
	Taxes other than production and income				(4	)			(1	)			(8	)			(3	)
		Total operating expenses(1)			(265	)			(215	)			(511	)			(444	)
	Operating income				175				202				355				405
Other income					1				2				4				3
	EBIT			$	176			$	204			$	359			$	408

					Quarter Ended June 30,												Six Months Ended June 30,
													Percent												Percent
					2005				2004				Variance				2005				2004				Variance
Volumes, prices and costs:
	Natural gas
		Volumes (MMcf)				57,790				61,535				(6	)%			113,948				127,234				(10	)%
		Average realized prices including hedges ($/Mcf) (3)(4)			$	6.13			$	5.90				4	%		$	6.20			$	5.75				8	%
		Average realized prices excluding hedges ($/Mcf)(3)			$	6.35			$	5.95				7	%		$	6.03			$	5.81				4	%
		Average transportation costs ($/Mcf)			$	0.17			$	0.14				21	%		$	0.17			$	0.15				13	%
	Oil, condensate and NGL
		Volumes (MBbls)				2,260				1,937				17	%			4,396				4,647				(5	)%
		Average realized prices including hedges ($/Bbl)(3)			$	42.39			$	34.11				24	%		$	41.16			$	30.86				33	%
		Average realized prices excluding hedges ($/Bbl)(3)			$	43.07			$	34.11				26	%		$	41.68			$	30.86				35	%
		Average transportation costs ($/Bbl)			$	0.59			$	1.54				(62	)%		$	0.67			$	1.35				(50	)%
	Total equivalent volumes (MMcfe)					71,351				73,157				(2	)%			140,327				155,115				(10	)%
	Production costs ($/Mcfe)
		Average lease operating cost			$	0.76			$	0.51				49	%		$	0.69			$	0.50				38	%
		Average production taxes				0.07				0.09				(22	)%			0.13				0.06				117	%
			Total production cost(1)		$	0.83			$	0.60				38	%		$	0.82			$	0.56				46	%
	Average general and administrative cost ($/Mcfe)				$	0.61			$	0.51				20	%		$	0.60			$	0.47				28	%
	Unit of production depletion cost ($/Mcfe)				$	2.05			$	1.64				25	%		$	2.02			$	1.61				25	%

(1)	Transportation and net product costs are included in operating expenses on our consolidated statements of income.
(2)	Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes).
(3)	Prices are stated before transportation costs
(4)	The average realized prices for natural gas, including hedges listed above, reflect the amounts recorded by the Production segment for sales of natural gas volumes. On a consolidated basis, El Paso receives a lower cash price on a portion of the volumes sold as further discussed on page 32.

85

---

Table of Contents

	Quarter and Six Months Ended June 30, 2005 Compared to Quarter and Six Months Ended June 30, 2004

				Variance
				Operating				Operating								EBIT
Quarter Ended June 30,				Revenue				Expense				Other(1)				Impact
				Favorable/(Unfavorable)
				(In millions)
Natural Gas Revenue
	Higher realized prices in 2005			$	23			$	—			$	—			$	23
	Lower volumes in 2005				(22	)			—				—				(22	)
	Impact from hedge program in 2005 versus 2004				(10	)			—				—				(10	)
Oil, Condensate, and NGL Revenue
	Higher realized prices in 2005				20				—				—				20
	Higher volumes in 2005				11				—				—				11
	Impact from hedge program in 2005 versus 2004				(1	)			—				—				(1	)
Depreciation, Depletion, and Amortization Expense
	Higher depletion rate in 2005				—				(29	)			—				(29	)
	Lower production volumes in 2005				—				3				—				3
Production Costs
	Higher lease operating costs in 2005				—				(17	)			—				(17	)
	Lower production taxes in 2005				—				2				—				2
Other
	Higher general and administrative costs in 2005				—				(6	)			—				(6	)
	Other				1				(3	)			—				(2	)
		Total variances		$	22			$	(50	)		$	—			$	(28	)

				Variance
				Operating				Operating								EBIT
Six Months Ended June 30,				Revenue				Expense				Other(1)				Impact
				Favorable/(Unfavorable)
				(In millions)
Natural Gas Revenue
	Higher realized prices in 2005			$	25			$	—			$	—			$	25
	Lower volumes in 2005				(77	)			—				—				(77	)
	Impact from hedge program in 2005 versus 2004				28				—				—				28
Oil, Condensate, and NGL Revenue
	Higher realized prices in 2005				48				—				—				48
	Lower volumes in 2005				(8	)			—				—				(8	)
	Impact from hedge program in 2005 versus 2004				(2	)			—				—				(2	)
Depreciation, Depletion, and Amortization Expense
	Higher depletion rate in 2005				—				(58	)			—				(58	)
	Lower production volumes in 2005				—				24				—				24
Production Costs
	Higher lease operating costs in 2005				—				(19	)			—				(19	)
	Higher production taxes in 2005				—				(9	)			—				(9	)
Other
	Higher general and administrative costs in 2005				—				(11	)			—				(11	)
	Other				1				6				3				10
		Total variances		$	15			$	(67	)		$	3			$	(49	)

(1)	Consists primarily of changes in transportation costs and other income

86

---

Table of Contents

	Significant factors impacting or occurring in the six months ended June 30, 2005:

	•	Increases in natural gas prices continue to have an overall negative impact on the fair value of our natural gas and power derivatives, which generally require us to supply natural gas and power at fixed prices. In addition, natural gas prices increased more than power prices, which negatively impacted the fair value of our Cordova tolling agreement.
	•	Effective April 1, 2005 we began using new forward pricing data provided by Platts Research and Consulting, our independent pricing source, due to their decision to discontinue the publication of the pricing data we had been utilizing in prior periods. In addition, due to the nature of the new forward

87

---

Table of Contents

		pricing data, we extended the use of that data over the entire contractual term of our derivative contracts. Previously, we only used Platts’ pricing data to value our derivative contracts beyond two years. Based on our analysis, we do not believe the overall impact of this change in estimate was material to our results for the period.

													Six Months
					Quarter Ended								Ended
					June 30,								June 30,
					2005				2004				2005				2004
					(In millions)
Overall EBIT:
	Gross margin(1)				$	(21	)		$	(141	)		$	(196	)		$	(300	)
	Operating expenses					(11	)			(13	)			(22	)			(29	)
		Operating loss				(32	)			(154	)			(218	)			(329	)
	Other income					2				2				3				13
		EBIT			$	(30	)		$	(152	)		$	(215	)		$	(316	)
Gross margin by significant contract type:
Natural gas contracts
	Production-related and other natural gas derivatives
		Changes in fair value on positions designated as hedges in December 2004			$	—			$	(104	)		$	—			$	(260	)
		Changes in fair value on production-related contracts				(12	)			—				(118	)			—
		Changes in fair value on other natural gas positions				93				13				119				8
			Total production-related and other natural gas derivatives			81				(91	)			1				(252	)
	Transportation-related contracts
		Demand charges				(40	)			(40	)			(79	)			(79	)
		Settlements				21				26				48				47
			Total transportation-related contracts			(19	)			(14	)			(31	)			(32	)
	Total gross margin — natural gas contracts					62				(105	)			(30	)			(284	)
Power contracts
	Changes in fair value on Cordova tolling agreement					(78	)			(18	)			(111	)			(3	)
	Changes in fair value on other power derivatives					(22	)			(18	)			(72	)			(13	)
	Favorable resolution of bankruptcy claim					17				—				17				—
	Total gross margin — power contracts					(83	)			(36	)			(166	)			(16	)
			Total gross margin		$	(21	)		$	(141	)		$	(196	)		$	(300	)

(1)	Gross margin for our Marketing and Trading segment consists of revenues from commodity trading and origination activities less the costs of commodities sold, including changes in the fair value of our derivative contracts.

88

---

Table of Contents

	Natural Gas Contracts

	Production-related and other natural gas derivatives

	•	Derivatives designated as hedges. The amounts in the above table represent changes in the fair values of derivative contracts that were designated as accounting hedges of our Production segment’s natural gas production on December 1, 2004. Losses for the quarter and six months ended June 30, 2004 were a result of increases in natural gas prices relative to the fixed prices in these contracts. Following the designation of these derivatives as accounting hedges in the fourth quarter of 2004, we began reflecting the income impacts of these contracts in our Production segment.
	•	Other production-related derivatives. We hold several option contracts that provide price protection on a portion of our Production segment’s anticipated natural gas and oil production. These contracts, which are not accounting hedges and are marked to market in our results each period, provide El Paso with the following floor and ceiling prices on our future natural gas and oil production:

		2005				2006				2007
Natural Gas Options Held at June 30, 2005
Volumes with Floor Price (TBtu)			36				120				30
Floor Price (per MMBtu)			$6.00				$7.00(1)				$6.00
Volumes with Ceiling Price (TBtu)			—				60				—
Ceiling Price (per MMBtu)			—				$9.50				—

			2007				2008				2009
Positions Added in July 2005(2)
Natural Gas Options
	Volumes (TBtu)			21				18				17
	Floor Price (per MMBtu)			$7.00				$6.00				$6.00
	Ceiling Price (per MMBtu)			$9.00				$10.00				$8.75
Oil Options
	Volumes (MBbls)			1,009				930				—
	Floor Price (per Bbl)			$55.00				$55.00				—
	Average Ceiling Price (per Bbl)			$60.38				$57.03				—

	(1)	In July 2005, we paid a net premium of $30 million to raise the floor price on these contracts from $6.00 per MMBtu.
	(2)	We entered into these positions related to our announced acquisition of Medicine Bow Energy Corporation.

	•	Other natural gas derivatives. Other natural gas derivatives consist of physical and financial natural gas contracts that impact our earnings as the fair value of these contracts change. These contracts obligate us to either purchase or sell natural gas at fixed prices. Our exposure to natural gas price changes will vary from period to period based on whether we purchase more or less natural gas than we sell under these contracts. Under certain of these contracts, we supply gas to power plants that we partially own. Due to their affiliated nature, we do not currently recognize mark-to-market gains or

89

---

Table of Contents

		losses on these contracts to the extent of our ownership interests in the plants. However, should we sell our interests in these plants, we would be required to record the cumulative unrecognized mark-to-market losses on these contracts, which totaled approximately $106 million as of June 30, 2005, net of related hedges.

	Transportation-related contracts

	•	Demand charges paid on our Alliance pipeline capacity contract were $16 million and $32 million in the quarter and six months ended June 30, 2005, versus $15 million and $30 million in the same periods of 2004. Our ability to use our Alliance pipeline capacity contract was relatively consistent during these periods, allowing us to recover approximately 66 percent of our demand charges in the first six months of 2005 and 65 percent in the first six months of 2004. This resulted from the price differentials between the receipt and delivery points remaining relatively consistent during these periods.
	•	Demand charges paid on our Texas Intrastate and remaining transportation contracts were $24 million and $47 million in the quarter and six months ended June 30, 2005, versus $25 million and $49 million in the same periods of 2004. Our ability to use the capacity under our Texas intrastate contracts improved in 2005 due to increased price differentials between the receipt and delivery points for the contracts. This allowed us to recover approximately 61 percent of the demand charges in the first six months of 2005 compared to only 18 percent during the same period in 2004. However, we only recovered 62 percent of the demand charges on our other transportation contracts in 2005 as compared to 70 percent in 2004, as price differentials between receipt and delivery points for these contracts decreased during the first six months of 2005.

	Power Contracts

	Cordova tolling agreement

	Our Cordova agreement is sensitive to changes in forecasted natural gas and power prices. During 2005 and 2004, forecasted natural gas prices increased relative to power prices, resulting in a decrease in the fair value of the contract.

	Other power derivatives

	•	During the first quarter of 2005, we assigned our contracts to supply power to our Power segment’s Cedar Brakes I and II entities to Constellation Energy Commodities Group, Inc. These contracts decreased in fair value by $15 million and $38 million in the quarter and six months ended June 30, 2004. In conjunction with the transfer, we also entered into derivative contracts with Constellation that swap the locational differences in power prices at the Camden, Bayonne and Newark Bay power plants and the Pennsylvania-New Jersey-Maryland power pool’s West Hub through 2013. The fair value of these swaps decreased by $6 million and $13 million during the quarter and six months ended June 30, 2005, due to unfavorable changes in the power prices at each location.
	•	We have a contract to supply power to Morgan Stanley at a fixed price through 2016. This contract increased in fair value by less than $1 million and $10 million during the quarters ended June 30, 2005 and 2004, and decreased in fair value by $90 million and $45 million during the six months ended June 30, 2005 and 2004. The overall decrease in the fair value of these derivatives during the six months ended June 30, 2005 and 2004 resulted from increasing power prices related to these obligations during these periods. However prices during the second quarters of 2005 and 2004 decreased.
	•	During the six months ended June 30, 2005 and 2004, we were required to purchase power under remaining power contracts, which include those used to manage the risk associated with our other power supply obligations. Due to changes in power prices, the fair value of these contracts decreased by $16 million and increased by $31 million during the quarter and six months ended June 30, 2005, and decreased by $13 million and increased by $70 million during the same periods of 2004.

90

---

Table of Contents

	•	On March 24, 2005, a bankruptcy court entered an order allowing Mohawk River Funding III’s (MRF III) bankruptcy claims with USGen New England. We received payment on this claim and recognized a gain of $17 million for amounts received in excess of receivables previously recorded.

	Operating Expenses

	Significant developments in our operations that occurred since December 31, 2004 include:

	•	Brazil. Our Macae project in Brazil has a contract that requires Petrobras to make minimum revenue payments until August 2007. Petrobras has not paid amounts due under the contract for December 2004 through the second quarter of 2005 and has initiated arbitration proceedings related to that obligation. For a further discussion of this matter, see Item 1, Financial Statements, Note 10. As a result of continued negotiations and discussions with Petrobras regarding this dispute, we recorded an impairment of this investment in the second quarter of 2005. This impairment was based on information regarding the potential value we would receive from the resolution of this matter. The future financial performance of the Macae plant will be affected by the ultimate outcome of this dispute, the timing of that outcome, and by regional changes in the Brazilian power markets.
	•	Asia. During the second and third quarters of 2005, we announced the sale of substantially all of our Asian power assets. We recorded impairments on certain of these assets based on information received regarding the potential value we may receive when we sell them. In July 2005, we completed the sale of our 50 percent interest in the KIECO power facility in Korea. The sale resulted in a gain of $109 million, which will be recorded in the third quarter of 2005. We expect to receive total proceeds of approximately $180 million from the sale of our remaining Asian assets, which we expect will be substantially completed by the end of 2005. We will continue to assess the fair value of those assets throughout the sales process, which may result in additional impairments or gains in future periods.
	•	Other International Power. During the second quarter of 2005, we engaged an investment banker to facilitate the sale of our Central American power assets. We recorded an impairment in the second quarter of 2005 based on information received about the value we may receive upon the sale of these assets. We will continue to assess the value of these assets throughout the sales process, which may result in additional impairments that may be significant. See Notes to Condensed Consolidated Financial Statements, Note 3 on page F-11 for further information on our divestitures.

91

---

Table of Contents

	Operating Results

													Six Months
					Quarter Ended								Ended
					June 30,								June 30,
					2005				2004				2005				2004
					(In millions)
Overall EBIT:
	Gross margin(1)				$	101			$	194			$	160			$	354
	Operating expenses
		Loss on long-lived assets				(361	)			(16	)			(388	)			(256	)
		Other operating expenses				(97	)			(122	)			(167	)			(246	)
			Operating loss			(357	)			56				(395	)			(148	)
	Earnings from unconsolidated affiliates
		Impairments, net of gains on sale				(87	)			(15	)			(148	)			(38	)
		Equity in earnings				28				39				61				78
	Other income					35				22				51				41
		EBIT			$	(381	)		$	102			$	(431	)		$	(67	)

(1)	Gross margin for our Power segment consists of revenues from our power plants and the revenues, cost of electricity purchases and changes in fair value of restructured power contracts. The cost of fuel used in the power generation process is included in operating expenses.

92

---

Table of Contents

												Six Months
				Quarter Ended								Ended
				June 30,								June 30,
				2005				2004				2005				2004
				(In millions)
EBIT by Area:
Brazil
	Impairments			$	(294	)		$	—			$	(294	)		$	(151	)
	Earnings from consolidated and unconsolidated plant operations				12				50				26				106
Asia and Other International Power
	Impairments, net(1)				(161	)			—				(258	)			(5	)
	Dividend on investment fund				16				—				16				—
	Gain on sale of PPN power plant				—				—				22				—
	Earnings from consolidated and unconsolidated plant operations				11				20				31				36
Domestic Power
	Power Contract Restructurings:
		Favorable resolution of bankruptcy claim			53				—				53				—
		Impairments, net(1)			—				—				—				(96	)
		Change in fair value of contracts			1				39				11				58
	Other Domestic Operations				(10	)			2				(8	)			6
Other(2)					(9	)			(9	)			(30	)			(21	)
		EBIT		$	(381	)		$	102			$	(431	)		$	(67	)

(1)	Includes impairment charges and gains (losses) on sales of assets and investments, net of any related minority interest.
(2)	Other consists of the indirect expenses and general and administrative costs associated with our domestic and international operations, including legal, finance and engineering costs. Direct general and administrative expenses of our domestic and international operations are included in EBIT of those operations. Other also includes gains and losses associated with our power turbine inventory. During the first quarter of 2005, we recorded a $15 million impairment of those turbines based on the receipt of further information about their fair value.

93

---

Table of Contents

	•	MCV. In 2004, we impaired our investment in MCV based on a decline in the value of the investment due to increased fuel costs. During the quarter ended June 30, 2005, we recorded a further impairment of $4 million based on a decrease in the fair value of the investment due to delays in the timing of expected cash flow receipts from this investment. After eliminating affiliated transactions, our proportionate share of MCV’s reported losses during the second quarter of 2005 was $14 million and our proportionate share of their earnings during the six months ended June 30, 2005 was $58 million. A significant portion of these earnings (losses) related to mark-to-market changes recorded by MCV on their unaffiliated fuel supply contracts. We determined that these fair value changes did not increase or decrease the fair value of our equity investment and could not be realized in the future. Accordingly, we decreased our proportionate share of MCV’s losses by $14 million during the second quarter of 2005 and decreased our proportionate share of their earnings by $57 million during the six months ended June 30, 2005. We will continue to assess our ability to recover our investment in MCV and its related operations in the future.
	•	Other Domestic Assets. During the quarter and six months ended June 30, 2004, we recorded earnings from consolidated and unconsolidated affiliates of approximately $41 million and $48 million and impairments of approximately $34 million and $45 million on our domestic power plants to adjust their book value to their estimated sales proceeds.

94

---

Table of Contents

			Favorable				Favorable
			(unfavorable) EBIT				(unfavorable) EBIT
			impact for the				impact for the
			quarter ended				six months ended
			June 30, 2005				June 30, 2005
			compared to 2004				compared to 2004
Gathering and processing margins			$	(37	)		$	(79	)
Operating expenses				25				59
Gain on sale of GP interest and common units to Enterprise				—				183
Other equity earnings				(30	)			(68	)
Minority interest				11				22
Other				1				(1	)
	Total increase (decrease) in EBIT		$	(30	)		$	116

			Favorable				Favorable
			(unfavorable) EBIT				(unfavorable) EBIT
			impact for				impact for
			quarter ended				six months ended
			June 30, 2005				June 30, 2005
			compared to 2004				compared to 2004
			(In millions)
Western Energy Settlement charge in 2005(1)			$	—			$	(59	)
Losses on early extinguishment of debt in 2005				—				(29	)
Lease termination costs due to office consolidation				(27	)			(27	)
Change in litigation, insurance and other reserves				(1	)			(16	)
Other				7				(7	)
	Total decrease in EBIT		$	(21	)		$	(138	)

(1)	In the first quarter of 2005, we incurred this $59 million charge associated with the payment of the Western Energy Settlement obligation earlier than originally expected. This charge has been recorded in operations and maintenance expense.

95

---

Table of Contents

											Six Months
			Quarter Ended								Ended
			June 30,								June 30,
			2005				2004				2005				2004
			(In millions)
Long-term debt, including current maturities			$	331			$	391			$	675			$	795
Other				9				19				15				38
	Total interest and debt expense		$	340			$	410			$	690			$	833

		Quarter Ended								Six Months Ended
		June 30,								June 30,
		2005				2004				2005				2004
		(In millions, except for rates)
Income taxes		$	(51	)		$	48			$	(57	)		$	58
Effective tax rate			18	%			59	%			30	%			(215	)%

96

---

Table of Contents

97

---

Table of Contents

98

---

Table of Contents

Regulated Operations      Pipelines		Our interstate natural gas pipeline system is the largest in the U.S., and owns or has interests in approximately 56,000 miles of pipeline and approximately 420 Bcf of storage capacity. We provide customers with interstate natural gas transmission and storage services from a diverse group of supply regions to major markets around the country, serving many of the largest market areas.
Non-regulated Operations      Production		Our production business holds interests in approximately 3.6 million net developed and undeveloped acres and had approximately 2.2 Tcfe of proved natural gas and oil reserves worldwide at the end of 2004. During 2004, our production averaged approximately 814 MMcfe/d.
Marketing and Trading		Our marketing and trading business markets our natural gas and oil production and manages our historical energy trading portfolio. During 2004, we continued to actively liquidate this historical trading portfolio.
Power		Our power business changed significantly during 2003 and 2004 with the sale of a substantial portion of our domestic power assets. As of December 31, 2004, we continued to own or manage approximately 10,400 MW of gross generating capacity in 16 countries. Our plants serve customers under long-term and market-based contracts or sell to the open market in spot market transactions. We have completed the sale of substantially all of our domestic contracted power assets and are either pursuing or evaluating the sale of many of our international assets.
Field Services		Our midstream or field services business provides processing and gathering services, primarily in south Louisiana. Through December 2004, we also owned a 9.9 percent interest in the general partner of Enterprise Products Partners L.P. (Enterprise), a large publicly traded master limited partnership, as well as a 3.7 percent limited partner interest in Enterprise. In January 2005, we sold all of our ownership interests in Enterprise and its general partner. We currently expect to sell many of our remaining Field Services assets.

99

---

Table of Contents

Business		Objective and Strategy
Pipelines		Protecting and enhancing asset value through successful recontracting, continuous efficiency improvements through cost management, and prudent capital spending in the U.S. and Mexico.
Production		Growing our production business in a way that creates shareholder value through disciplined capital allocation, cost leadership and superior portfolio management.
Marketing and Trading		Marketing and physical trading of our natural gas and oil production.
Power		Managing our remaining power generation assets to maximize value.
Field Services		Optimizing our remaining gathering and processing assets.

100

---

Table of Contents

	Wholly Owned Interstate Transmission Systems

				As of December 31, 2004
																Average Throughput(1)
								Design				Storage
Transmission				Miles of				Capacity				Capacity						2003
System		Supply and Market Region		Pipeline				(MMcf/d)				(Bcf)				2004		(BBtu/d)				2002
Tennessee Gas Pipeline (TGP)		Extends from Louisiana, the Gulf of Mexico and south Texas to the northeast section of the U.S., including the metropolitan areas of New York City and Boston.			14,200				6,876				90			4,469			4,710			4,596
ANR Pipeline (ANR)		Extends from Louisiana, Oklahoma, Texas and the Gulf of Mexico to the midwestern and northeastern regions of the U.S., including the metropolitan areas of Detroit, Chicago and Milwaukee.			10,500				6,620				192			4,067			4,232			4,130
El Paso Natural Gas (EPNG)		Extends from the San Juan, Permian and Anadarko basins to California, its single largest market, as well as markets in Arizona, Nevada, New Mexico, Oklahoma, Texas and northern Mexico.			11,000				5,650	(2)			—			4,074			3,874			3,799

101

---

Table of Contents

				As of December 31, 2004
																Average Throughput(1)
								Design				Storage
Transmission				Miles of				Capacity				Capacity						2003
System		Supply and Market Region		Pipeline				(MMcf/d)				(Bcf)				2004		(BBtu/d)				2002
Southern Natural Gas (SNG)		Extends from Texas, Louisiana, Mississippi, Alabama and the Gulf of Mexico to Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina and Tennessee, including the metropolitan areas of Atlanta and Birmingham.			8,000				3,437				60			2,163			2,101			2,151
Colorado Interstate Gas (CIG)		Extends from most production areas in the Rocky Mountain region and the Anadarko Basin to the front range of the Rocky Mountains and multiple interconnects with pipeline systems transporting gas to the Midwest, the Southwest, California and the Pacific Northwest.			4,000				3,000				29			1,744			1,685			1,687
Wyoming Interstate (WIC)		Extends from western Wyoming and the Powder River Basin to various pipeline interconnections near Cheyenne, Wyoming.			600				1,997				—			1,201			1,213			1,194
Mojave Pipeline (MPC)		Connects with the EPNG and Transwestern transmission systems at Topock, Arizona, and the Kern River Gas Transmission Company transmission system in California, and extends to customers in the vicinity of Bakersfield, California.			400				400				—			161			192			266
Cheyenne Plains Gas Pipeline (CPG)		Extends from the Cheyenne hub in Colorado to various pipeline interconnects near Greensburg, Kansas.			400				396	(3)			—			89			—			—

(1)	Includes throughput transported on behalf of affiliates.
(2)	This capacity reflects winter-sustainable west-flow capacity and 800 MMcf/d of east-end delivery capacity.
(3)	This capacity was placed in service on December 1, 2004. Compression was added and placed in service on January 31, 2005, which increased the design capacity to 576 MMcf/d.

102

---

Table of Contents

Transmission

Anticipated

System

Project

Capacity

Description

Completion Date

(MMcf/d)

ANR

East Leg Wisconsin expansion

142

To replace 4.7 miles of an existing 14-inch natural gas pipeline with a 30-inch line in Washington County, add 3.5 miles of 8-inch looping(1) on the Denmark Lateral in Brown County, and modify ANR’s existing Mountain Compressor Station in Oconto County, Wisconsin.

November 2005

North Leg Wisconsin expansion

110

To add 6,000 horsepower of electric- powered compression at ANR’s Weyauwega Compressor station in Waupaca County, Wisconsin.

November 2005

CPG

Cheyenne Plains expansion

179

To add approximately 10,300 horsepower of compression and an additional treatment facility to the Cheyenne Plains project.

December 2005

(1)	Looping is the installation of a pipeline, parallel to an existing pipeline, with tie-ins at several points along the existing pipeline. Looping increases a transmission system’s capacity.

	Partially Owned Interstate Transmission Systems

				As of December 31, 2004
																Average Throughput(2)
Transmission				Ownership				Miles of				Design
System(1)		Supply and Market Region		Interest				Pipeline(2)				Capacity(2)				2004				2003				2002
				(Percent)								(MMcf/d)				(BBtu/d)
Florida Gas Transmission(3)		Extends from south Texas to south Florida.			50				4,870				2,082				2,014				1,963				2,004
Great Lakes Gas Transmission		Extends from the Manitoba-Minnesota border to the Michigan-Ontario border at St. Clair, Michigan.			50				2,115				2,895				2,200				2,366				2,378
Samalayuca Pipeline and Gloria a Dios Compression Station		Extends from U.S./Mexico border to the State of Chihuahua, Mexico.			50				23				460				433				409				434
San Fernando Pipeline		Pipeline running from Pemex Compression Station 19 to Pemex metering station in San Fernando, Mexico in the State of Tamaulipas.			50				71				1,000				951				130				—

(1)	These systems are accounted for as equity investments.
(2)	Miles, volumes and average throughput represent the systems’ totals and are not adjusted for our ownership interest.
(3)	We have a 50 percent equity interest in Citrus Corporation, which owns this system.

103

---

Table of Contents

	Underground Natural Gas Storage Entities

As of December 31, 2004

Ownership

Storage

Storage Entity

Interest

Capacity(1)

Location

(Percent)

(Bcf)

Bear Creek Storage

100

58

Louisiana

ANR Storage

100

56

Michigan

Blue Lake Gas Storage

75

47

Michigan

Eaton Rapids Gas Storage(2)

50

13

Michigan

Young Gas Storage(2)

48

6

Colorado

(1)	Includes a total of 133 Bcf contracted to affiliates. Storage capacity is under long-term contracts and is not adjusted for our ownership interest.
(2)	These systems were accounted for as equity investments as of December 31, 2004.

	LNG Facility

	Regulatory Environment

	•	rates and charges for natural gas transportation, storage, terminalling and related services;
	•	certification and construction of new facilities;
	•	extension or abandonment of facilities;
	•	maintenance of accounts and records;
	•	relationships between pipeline and energy affiliates;
	•	terms and conditions of service;
	•	depreciation and amortization policies;
	•	acquisition and disposition of facilities; and
	•	initiation and discontinuation of services.

104

---

Table of Contents

	Markets and Competition

105

---

Table of Contents

Transmission
System				Customer Information		Contract Information		Competition
	TGP			Approximately 432 firm and interruptible customers.		Approximately 464 firm contracts Weighted average remaining contract term of approximately five years.		TGP faces strong competition in the Northeast, Appalachian, Midwest and Southeast market areas. It competes with other interstate and intrastate pipelines for deliveries to multiple-connection customers who can take deliveries at alternative points. Natural gas delivered on the TGP system competes with alternative energy sources such as electricity, hydroelectric power, coal and fuel oil. In addition, TGP competes with pipelines and gathering systems for connection to new supply sources in Texas, the Gulf of Mexico and from the Canadian border.
				Major Customers: None of which individually represents more than 10 percent of revenues
								In the offshore areas of the Gulf of Mexico, factors such as the distance of the supply field from the pipeline, relative basis pricing of the pipeline receipt options, costs of intermediate gathering or required processing of the gas all influence determinations of whether gas is ultimately attached to our system.

106

---

Table of Contents

Transmission
System				Customer Information		Contract Information		Competition
	ANR			Approximately 259 firm and interruptible customers		Approximately 570 firm contracts Weighted average remaining contract term of approximately three years.		In the Midwest, ANR competes with other interstate and intrastate pipeline companies and local distribution companies in the transportation and storage of natural gas. In the Northeast, ANR competes with other interstate pipelines serving electric generation and local distribution companies. ANR also competes directly with other interstate pipelines, including Guardian Pipeline, for markets in Wisconsin. We Energies owns an interest in Guardian, which is currently serving a portion of its firm transportation requirements. ANR also competes directly with numerous pipelines and gathering systems for access to new supply sources. ANR’s principal supply sources are the Rockies and mid-continent production accessed in Kansas and Oklahoma, western Canadian production delivered to the Chicago area and Gulf of Mexico sources, including deepwater production and LNG imports.
				Major Customer: We Energies (909 Bbtu/d)		Contract terms expire in 2005-2010.
	EPNG			Approximately 155 firm and interruptible customers		Approximately 213 firm contracts Weighted average remaining contract term of approximately five years (1)(2).		EPNG faces competition in the West and Southwest from other existing pipelines, storage facilities, as well as alternative energy sources that generate electricity such as hydroelectric power, nuclear, coal and fuel oil.
				Major Customer: Southern California Gas Company(2) (475 BBtu/d) (82 BBtu/d) (768 BBtu/d)		Contract terms expire in 2006. Contract terms expire in 2005 and 2007. Contract terms expire in 2009-2011.

(1)	Approximately 1,564 MMcf/d currently under contract is subject to early termination in August 2006 provided customers give timely notice of an intent to terminate. If all of these rights were exercised, the weighted average remaining contract term would decrease to approximately three years.
(2)	Reflects the impact of an agreement we entered into, subject to FERC approval, to extend 750 MMCf/d of SoCal’s current capacity, effective September 1, 2006, for terms of three to five years.

107

---

Table of Contents

Transmission
System				Customer Information		Contract Information		Competition
	SNG			Approximately 230 firm and interruptible customers		Approximately 203 firm contracts Weighted average remaining contract term of approximately five years.		Competition is strong in a number of SNG’s key markets. SNG’s four largest customers are able to obtain a significant portion of their natural gas requirements through transportation from other pipelines. Also, SNG competes with several pipelines for the transportation business of many of its other customers.
				Major Customers: Atlanta Gas Light Company (972 BBtu/d) Southern Company Services (418 BBtu/d) Alabama Gas Corporation (415 BBtu/d) Scana Corporation (346 BBtu/d)		Contract terms expire in 2005-2007. Contract terms expire in 2010-2018. Contract terms expire in 2006-2013. Contract terms expire in 2005-2019.
	CIG			Approximately 112 firm and interruptible customers Major Customers: Public Service Company of Colorado (970 BBtu/d) (261 BBtu/d) (187 BBtu/d)		Approximately 191 firm contracts Weighted average remaining contract term of approximately five years. Contract term expires in 2007. Contract term expires in 2009-2014. Contract term expires in 2006.		CIG serves two major markets. Its “on- system” market consists of utilities and other customers located along the front range of the Rocky Mountains in Colorado and Wyoming. Its “off-system” market consists of the transportation of Rocky Mountain production from multiple supply basins to interconnections with other pipelines bound for the Midwest, the Southwest, California and the Pacific Northwest. Competition for its on-system market consists of local production from the Denver-Julesburg basin, an intrastate pipeline, and long-haul shippers who elect to sell into this market rather than the off-system market. Competition for its off-system market consists of other interstate pipelines that are directly connected to its supply sources.
	WIC			Approximately 49 firm and interruptible customers Major Customers: Williams Power Company (303 BBtu/d) Colorado Interstate Gas Company (247 BBtu/d) Western Gas Resources (235 BBtu/d) Cantera Gas Company (226 BBtu/d)		Approximately 47 firm contracts Weighted average remaining contract term of approximately six years. Contract terms expire in 2008-2013. Contract terms expire in 2005-2016. Contract terms expire in 2007-2013. Contract terms expire in 2012-2013.		WIC competes with eight interstate pipelines and one intrastate pipeline for its mainline supply from several producing basins. WIC’s one Bcf/d Medicine Bow lateral is the primary source of transportation for increasing volumes of Powder River Basin supply and can readily be expanded as supply increases. Currently, there are two other interstate pipelines that transport limited volumes out of this basin.

108

---

Table of Contents

Transmission
System				Customer Information		Contract Information		Competition
	MPC			Approximately 14 firm and interruptible customers Major Customers: Texaco Natural Gas Inc. (185 BBtu/d) Burlington Resources Trading Inc. (76 BBtu/d) Los Angeles Department of Water and Power (50 BBtu/d)		Approximately nine firm contracts Weighted average remaining contract term of approximately two years. Contract term expires in 2007. Contract term expires in 2007. Contract term expires in 2007.		MPC faces competition from existing pipelines, a newly proposed pipeline, LNG projects and alternative energy sources that generate electricity such as hydroelectric power, nuclear, coal and fuel oil.
	CPG			Approximately 15 firm and interruptible customers.		Approximately 14 firm contracts Weighted average remaining contract term of approximately 10 years.		Cheyenne Plains competes directly with other interstate pipelines serving the Mid-continent region. Indirectly, Cheyenne Plains competes with other interstate pipelines that transport Rocky Mountain gas to other markets.
				Major Customers:
				Oneok Energy Services
				Company L.P.		Contract term expires in 2015.
				(195 BBtu/d)
				Anadarko Energy Service
				Company		Contract term expires in 2015.
				(100 BBtu/d)
				Kerr McGee		Contract term expires in 2015.
				(83 BBtu/d)

Area			Operating Regions
United States
	Onshore		Black Warrior Basin in Alabama Arkoma Basin in Oklahoma Raton Basin in New Mexico Central (primarily in north Louisiana) Rocky Mountains (primarily in Utah)
	Texas Gulf Coast		South Texas
	Offshore and south Louisiana		Gulf of Mexico (Texas and Louisiana) South Louisiana
Brazil			Camamu, Santos, Espirito Santos and Potiguar Basins

109

---

Table of Contents

	Natural Gas, Oil and Condensate and Natural Gas Liquids Reserves

			Net Proved Reserves(1)
			Natural				Oil/																2004
			Gas				Condensate				NGL				Total								Production
			(MMcf)				(MBbls)				(MBbls)				(MMcfe)				(Percent)				(MMcfe)
United States
	Onshore			1,100,681				14,675				1,233				1,196,133				55				84,568
	Texas Gulf Coast			431,508				3,118				9,874				509,454				23				103,286
	Offshore and south Louisiana			191,652				9,538				2,094				261,444				12				101,140
	Total United States			1,723,841				27,331				13,201				1,967,031				90				288,994
Brazil				68,743				24,171				—				213,769				10				8,772
Total				1,792,584				51,502				13,201				2,180,800				100				297,766

(1)	Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

110

---

Table of Contents

				Net Proved Reserves(1)
								Oil/
				Natural Gas				Condensate				NGL				Total
				(MMcf)				(MBbls)				(MBbls)				(MMcfe)				(Percent)
United States
Producing					1,085,581				12,507				10,588				1,224,152				62
	Non-Producing				201,696				7,134				1,355				252,626				13
	Undeveloped				436,564				7,690				1,258				490,253				25
		Total proved			1,723,841				27,331				13,201				1,967,031				100
Brazil
Producing					29,239				1,375				—				37,488				18
	Non-Producing				24,988				1,238				—				32,415				15
	Undeveloped				14,516				21,558				—				143,866				67
		Total proved			68,743				24,171				—				213,769				100
Worldwide
Producing					1,114,820				13,882				10,588				1,261,640				58
	Non-Producing				226,684				8,372				1,355				285,041				13
	Undeveloped				451,080				29,248				1,258				634,119				29
		Total proved			1,792,584				51,502				13,201				2,180,800				100

(1)	Net proved reserves exclude royalties and interests owned by others and reflect contractual arrangements and royalty obligations in effect at the time of the estimate.

111

---

Table of Contents

	Acreage and Wells

				Developed								Undeveloped								Total
				Gross(1)				Net(2)				Gross(1)				Net(2)				Gross(1)				Net(2)
United States
	Onshore				1,032,115				419,789				1,653,540				1,308,491				2,685,655				1,728,280
	Texas Gulf Coast				199,035				82,850				257,225				172,340				456,260				255,190
	Offshore and south Louisiana				643,861				448,599				744,957				697,515				1,388,818				1,146,114
		Total			1,875,011				951,238				2,655,722				2,178,346				4,530,733				3,129,584
Brazil					39,476				13,817				1,346,919				452,552				1,386,395				466,369
		Worldwide Total			1,914,487				965,055				4,002,641				2,630,898				5,917,128				3,595,953

(1)	Gross interest reflects the total acreage we participated in, regardless of our ownership interests in the acreage.
(2)	Net interest is the aggregate of the fractional working interest that we have in our gross acreage.

				Productive Natural								Productive								Total								Number of Wells
				Gas Wells								Oil Wells								Productive Wells								Being Drilled
				Gross(1)				Net(2)				Gross(1)				Net(2)				Gross(1)				Net(2)				Gross(1)				Net(2)
United States
	Onshore				2,864				2,088				292				220				3,156				2,308				59				48
	Texas Gulf Coast				808				669				2				1				810				670				5				4
	Offshore and south Louisiana				287				194				75				41				362				235				4				1
		Total United States			3,959				2,951				369				262				4,328				3,213				68				53
Brazil					4				3				11				9				15				12				—				—
		Worldwide Total			3,963				2,954				380				271				4,343				3,225				68				53

(1)	Gross interest reflects the total number of wells we participated in, regardless of our ownership interests in the wells.
(2)	Net interest is the aggregate of the fractional working interest that we have in our gross wells.

112

---

Table of Contents

				Net Exploratory												Net Development
				Wells Drilled(1)												Wells Drilled(1)
				2004				2003				2002				2004				2003				2002
United States
	Productive				13				54				27				298				272				511
	Dry				10				22				14				3				1				5
		Total			23				76				41				301				273				516
Brazil
	Productive				—				2				—				—				—				—
	Dry				1				4				—				—				—				—
		Total			1				6				—				—				—				—
Worldwide
	Productive				13				56				27				298				272				511
	Dry				11				26				14				3				1				5
		Total			24				82				41				301				273				516

(1)	Net interest is the aggregate of the fractional working interest that we have in our gross wells drilled.

113

---

Table of Contents

	Net Production, Sales Prices, Transportation and Production Costs

					2004				2003				2002
Net Production Volumes
	United States
		Natural Gas (MMcf)				238,009				338,762				470,082
		Oil, Condensate and NGL (MBbls)				8,498				11,778				16,462
			Total (MMcfe)			288,994				409,432				568,852
	Brazil
		Natural Gas (MMcf)				6,848				—				—
		Oil, Condensate and NGL (MBbls)				320				—				—
			Total (MMcfe)			8,772				—				—
	Worldwide
		Natural Gas (MMcf)				244,857				338,762				470,082
		Oil, Condensate and NGL (MBbls)				8,818				11,778				16,462
			Total (MMcfe)			297,766				409,432				568,852
Natural Gas Average Realized Sales Price ($/Mcf)(1)
	United States
		Price, excluding hedges			$	6.02			$	5.51			$	3.17
		Price, including hedges			$	5.94			$	5.40			$	3.35
	Brazil
		Price, excluding hedges			$	2.01			$	—			$	—
		Price, including hedges			$	2.01			$	—			$	—
	Worldwide
		Price, excluding hedges			$	5.90			$	5.51			$	3.17
		Price, including hedges			$	5.83			$	5.40			$	3.35

114

---

Table of Contents

					2004				2003				2002
Oil, Condensate, and NGL Average Realized Sales Price ($/Bbl)(1)
	United States
		Price, excluding hedges			$	34.44			$	26.64			$	21.38
		Price, including hedges			$	34.44			$	25.96			$	21.28
	Brazil
		Price, excluding hedges			$	43.01			$	—			$	—
		Price, including hedges			$	39.19			$	—			$	—
	Worldwide
		Price, excluding hedges			$	34.75			$	26.64			$	21.38
		Price, including hedges			$	34.61			$	25.96			$	21.28
Average Transportation Cost
	United States
		Natural gas ($/Mcf)			$	0.17			$	0.18			$	0.18
		Oil, condensate and NGL ($/Bbl)			$	1.16			$	1.05			$	0.97
	Worldwide
		Natural gas ($/Mcf)			$	0.17			$	0.18			$	0.18
		Oil, condensate and NGL ($/Bbl)			$	1.12			$	1.05			$	0.97
Average Production Cost($/Mcfe)(2)
	United States
		Average lease operating cost			$	0.62			$	0.42			$	0.42
		Average production taxes				0.11				0.14				0.08
			Total production cost		$	0.73			$	0.56			$	0.50
	Worldwide
		Average lease operating cost			$	0.60			$	0.42			$	0.42
		Average production taxes				0.11				0.14				0.08
			Total production cost		$	0.71			$	0.56			$	0.50

(1)	Prices are stated before transportation costs.
(2)	Production costs include lease operating costs and production related taxes (including ad valorem and severance taxes).

115

---

Table of Contents

	Acquisition, Development and Exploration Expenditures

				2004				2003				2002
				(In millions)
United States
	Acquisition Costs:
		Proved		$	33			$	10			$	362
		Unproved			32				35				29
	Development Costs				395				668				1,242
	Exploration Costs:
		Delay Rentals			7				6				7
		Seismic Acquisition and Reprocessing			29				56				35
		Drilling			149				405				482
	Asset Retirement Obligations(1)				30				124				—
		Total full cost pool expenditures			675				1,304				2,157
		Non-full cost pool expenditures			11				17				47
		Total capital expenditures		$	686			$	1,321			$	2,204
Brazil
	Acquisition Costs:
		Proved		$	69			$	—			$	—
		Unproved			3				4				9
	Development Costs				1				—				—
	Exploration Costs:
		Seismic Acquisition and Reprocessing			15				11				32
		Drilling			10				84				13
	Asset Retirement Obligations				3				—				—
		Total full cost pool expenditures			101				99				54
		Non-full cost pool expenditures			3				1				2
		Total capital expenditures		$	104			$	100			$	56

116

---

Table of Contents

				2004				2003				2002
				(In millions)
Worldwide
	Acquisition Costs:
		Proved		$	102			$	10			$	362
		Unproved			35				39				38
	Development Costs				396				668				1,242
	Exploration Costs:
		Delay Rentals			7				6				7
		Seismic Acquisition and Reprocessing			44				67				67
		Drilling			159				489				495
	Asset Retirement Obligations				33				124				—
		Total full cost pool expenditures			776				1,403				2,211
		Non-full cost pool expenditures			14				18				49
		Total capital expenditures		$	790			$	1,421			$	2,260

(1)	Includes an increase to our property, plant and equipment of approximately $114 million in 2003 associated with our adoption of Statement of Financial Accounting Standards No. 143.

	Regulatory and Operating Environment

117

---

Table of Contents

	Markets and Competition

	•	Natural gas derivative contracts. Our natural gas contracts include long-term obligations to deliver natural gas at fixed prices as well as derivatives related to our production activities. As of December 31, 2004, we have seven significant physical natural gas contracts with power plants. These contracts have various expiration dates ranging from 2011 to 2028, with expected obligations under individual contracts with third parties ranging from 32,000 MMBtu/d to 142,000 MMBtu/d.

	•	Transportation-related contracts. Our transportation contracts give us the right to transport natural gas using pipeline capacity for a fixed reservation charge plus variable transportation costs. We typically refer to the fixed reservation cost as a demand charge. As of December 31, 2004, we have contracted for 1.5 Bcf/d of capacity with contract expiration dates through 2028. Our ability to utilize our transportation capacity is dependent on several factors including the difference in natural gas prices at receipt and delivery locations along the pipeline system, the amount of capital needed to use this capacity and the capacity required to meet our other long-term obligations.

118

---

Table of Contents

	•	Tolling contracts. Our tolling contracts provide us with the right to require counterparties to convert natural gas into electricity. Under these arrangements, we supply the natural gas used in the underlying power plants and sell the electricity produced by the power plant. In exchange for this right, we pay a monthly fixed fee and a variable fee based on the quantity of electricity produced. As of December 31, 2004, we have two unaffiliated physical tolling contracts, the largest of which is a contract on the Cordova power project in the Midwest. This contract expires in 2019.
	•	Power and other. Our power and other contracts include long-term obligations to provide power to our Power segment for its restructured domestic power contracts. As of December 31, 2004, we have four power supply contracts remaining, the largest being a contract with Morgan Stanley for approximately 1,700 MMWh per year extending through 2016. In the first quarter of 2005, we sold two of these contracts related to subsidiaries in our Power segment, Cedar Brakes I and II. We also have other contracts that require the physical delivery of power or that are used to manage the risk associated with our obligations to supply power. In addition, we have natural gas storage contracts that provide capacity of approximately 4.7 Bcf of storage for operational and balancing purposes.

	Markets and Competition

	•	Affiliates of major oil and natural gas producers;
	•	Large domestic and foreign utility companies;
	•	Affiliates of large local distribution companies;
	•	Affiliates of other interstate and intrastate pipelines; and
	•	Independent energy marketers and power producers with varying scopes of operations and financial resources.

119

---

Table of Contents

El Paso

Expiration

Ownership

Gross

Year of Power

Project

Country

Interest

Capacity

Power Purchaser

Sales Contracts

Fuel Type

(Percent)

(MW)

Brazil

Araucaria(1)

Brazil

60

484

Copel

—

(2)

Natural Gas

Macae

Brazil

100

928

Petrobras(3)

2007

(2)

Natural Gas

Manaus

Brazil

100

238

Manaus Energia(4)

2008

Oil

Porto Velho(1)

Brazil

50

404

Eletronorte

2010,2023

Oil

Rio Negro

Brazil

100

158

Manaus Energia(4)

2008

Oil

Asia

Fauji(1)

Pakistan

42

157

Pakistan Water and Power

2029

Natural Gas

Habibullah(1)

Pakistan

50

136

Pakistan Water and Power

2029

Natural Gas

KIECO(1)

South Korea

50

1,720

KEPCO

2020

Natural Gas

Meizhou Wan(1)

China

26

734

Fujian Power

2025

Coal

Haripur(1)

Bangladesh

50

116

Bangladesh Power

2014

Natural Gas

PPN(1)(5)

India

26

325

Tamil Nadu

2031

Naphtha/Natural Gas

Saba(1)

Pakistan

94

128

Pakistan Water and Power

2029

Oil

Sengkang(1)

Indonesia

48

135

PLN

2022

Natural Gas

Central and other South America

Aguaytia(1)

Peru

24

155

Various

2005,2006

Natural Gas

Fortuna(1)

Panama

25

300

Union Fenosa

2005,2008

Hydroelectric

Itabo(1)

Dominican   Republic

25

416

CDEEE and AES

2016

Oil/Coal

Nejapa

El Salvador

87

144

AES and PPL

2005

Oil

Europe

Enfield(1)

United Kingdom

25

378

Spot Market

—

Natural Gas

EMA(1)

Hungary

50

69

Dunaferr Energy Services

2016

Natural Gas/Oil

(1)	These power facilities are reflected as investments in unconsolidated affiliates in our financial statements.
(2)	These facilities’ power sales contracts are currently in arbitration.
(3)	Although a majority of the power generated by this power facility is sold to the wholesale power markets, Petrobras provides a minimum level of revenue under its contract until 2007. Petrobras did not make their December 2004 and January 2005 payments under this contract and have filed a lawsuit and for arbitration. See Notes to Consolidated Financial Statements, Note 17, on page F-89, for a further discussion of this matter.
(4)	These power facilities have new power purchase agreements that were signed in January 2005 extending the terms of the contract through 2008 at which time we will transfer ownership of the plants to Manaus Energia.
(5)	We sold our investment in this plant in the first quarter of 2005.

El Paso

Ownership

Miles of

Design

Average 2004

Pipeline

Interest

Pipeline

Capacity(1)

Throughput(1)

(Percent)

(MMcf/d)

(BBtu/d)

Bolivia to Brazil

8

1,957

1,059

722

Argentina to Chile

22

336

124

77

(1)	Volumes represent the pipeline’s total design capacity and average throughput and are not adjusted for our ownership interest.

120

---

Table of Contents

						El Paso												Expiration
						Ownership				Gross								Year of Power
Project		State				Interest				Capacity				Power Purchaser				Sales Contracts				Fuel Type
						(Percent)				(MW)
Berkshire(1)			MA				56				261				—	(2)			—	(2)			Natural Gas
Midland Cogeneration(1)			MI				44				1,575				Consumers Power, Dow				2025				Natural Gas
CDECCA(3)			CT				100				62				—	(2)			—	(2)			Natural Gas
Pawtucket(3)			RI				100				69				—	(2)			—	(2)			Natural Gas
San Joaquin(3)			CA				100				48				—	(2)			—	(2)			Natural Gas
Eagle Point(4)			NJ				100				233				—	(2)			—	(2)			Natural Gas
Rensselaer(4)			NY				100				86				—	(2)			—	(2)			Natural Gas

(1)	These power facilities are reflected as investments in unconsolidated affiliates in our financial statements.
(2)	These power facilities (referred to as merchant plants) do not have long-term power purchase agreements with third parties. Our Marketing and Trading segment sells the power that a majority of these facilities generate to the wholesale power market.
(3)	These plants have Board approval for sale and are targeted to be sold in the first half of 2005. We have executed sales agreements on the Pawtucket and San Joaquin facilities.
(4)	These plants were sold in the first quarter of 2005.

	Regulatory Environment & Markets and Competition

121

---

Table of Contents

			Inlet Capacity
							Average Inlet Volume												Average Sales
			December 31,
Processing Plants			2004				2004				2003				2002				2004				2003				2002
			(MMcfe/d)				(BBtue/d)												(Mgal/d)
South Louisiana				2,550				1,600				1,627				1,407				1,631				1,726				1,604
Other areas(1)				186				1,180				1,579				2,513				2,460				2,611				5,134
	Total			2,736				2,780				3,206				3,920				4,091				4,337				6,738

(1)	During 2002, 2003 and 2004, we sold a substantial amount of our midstream assets to GulfTerra and Enterprise. Included in the volume and sales columns is activity through the sale date for the assets which were sold.

	Corporate Activities

122

---

Table of Contents

	Discontinued Operations

123

---

Table of Contents

124

---

Table of Contents

125

---

Table of Contents

			High				Low				Dividends
			(Per share)
2005
	Third Quarter (through August 22, 2005)		$	12.57			$	11.13			$	0.04
	Second Quarter			11.87				9.30				0.04
	First Quarter			13.15				10.01				0.04
2004
	Fourth Quarter		$	11.85			$	8.42			$	0.04
	Third Quarter			9.20				7.37				0.04
	Second Quarter			7.95				6.58				0.04
	First Quarter			9.88				6.57				0.04
2003
	Fourth Quarter		$	8.29			$	5.97			$	0.04
	Third Quarter			8.95				6.51				0.04
	Second Quarter			9.89				5.85				0.04
	First Quarter			10.30				3.33				0.04

126

---

Table of Contents

(a)

(b)

(c)

Number of Securities

Remaining Available for

Future Issuance under

Number of Securities to be

Weighted-Average

Equity Compensation

Issued upon Exercise of

Exercise Price of

Plans (Excluding

Outstanding Options,

Outstanding Options,

Securities Reflected in

Plan Category

Warrants and Rights (1)

Warrants and Rights

Column (a))

Equity compensation plans approved by stockholders

6,624,686

$

28.07

4,537,843

(2)

Equity compensation plans not approved by stockholders

24,954,615

$

47.00

25,804,722

(3)

Total

31,579,301

30,342,565

(1)	Column (a) does not include 2,344,277 shares with a weighted-average exercise price of $38.62 per share which were assumed by El Paso under the Executive Award Plan of Sonat Inc. as a result of the merger with Sonat in October 1999. The Executive Award Plan of Sonat Inc. has been terminated and no future awards can be made under it.
(2)	In column (c), equity compensation plans approved by stockholders include 2,831,050 shares available for future issuance under the Employee Stock Purchase Plan.
(3)	In column (c), equity compensation plans not approved by stockholders include 77,568 shares available for future awards granted under the Restricted Stock Award Plan for Management Employees.

127

---

Table of Contents

128

---

Table of Contents

				Officer/
				Director
Name		Office		Since				Age
Douglas L. Foshee		President and Chief Executive Officer of El Paso, Director			2003				46
D. Mark Leland		Executive Vice President and Chief Financial Officer of El Paso			2005				43
Robert W. Baker		Executive Vice President and General Counsel of El Paso			2002				48
Lisa A. Stewart		Executive Vice President of El Paso and President of El Paso Production and Non-Regulated Operations			2004				48
Ronald L. Kuehn, Jr.		Chairman of the Board			1999				70
Juan Carlos Braniff		Director			1997				48
James L. Dunlap		Director			2003				68
Robert W. Goldman		Director			2003				63
Anthony W. Hall, Jr.		Director			2001				60
Thomas R. Hix		Director			2004				57
William H. Joyce		Director			2004				69
J. Michael Talbert		Director			2003				58
Robert F. Vagt		Director			2005				58
John L. Whitmire		Director			2003				64
Joe B. Wyatt		Director			1999				70

129

---

Table of Contents

130

---

Table of Contents

131

---

Table of Contents

																			Long-Term Compensation
							Annual Compensation												Awards								Payouts
																			Restricted				Securities				Long-Term
															Other Annual				Stock				Underlying				Incentive Plan				All Other
							Salary				Bonus				Compensation				Awards				Options				Payouts				Compensation
Name and Principal Position			Year				($)(1)				($)				($)(2)				($)(3)				(#)				($)(4)				($)(5)
Douglas L. Foshee(6)				2004			$	630,000			$	1,250,000			$	—			$	1,320,000				375,000			$	180,500			$	51,750
	President and Chief			2003			$	297,115			$	600,000			$	—			$	—				1,000,000			$	—			$	1,758,913
	Executive Officer
John W. Somerhalder II(7)				2004			$	642,000			$	684,735			$	—			$	492,800				140,000			$	—			$	46,500
	Executive Vice President			2003			$	617,500			$	750,000			$	—			$	—				—			$	215,850			$	14,250
				2002			$	600,000			$	—			$	—			$	—				—			$	—			$	81,926
Lisa A. Stewart(8)				2004			$	458,337			$	441,604			$	—			$	1,077,600				295,000			$	—			$	316,250
	Executive Vice President
D. Dwight Scott(9)				2004			$	453,929			$	498,644			$	—			$	739,200				210,000			$	261,300			$	42,825
	Executive Vice President			2003			$	517,504			$	750,000			$	—			$	—				—			$	—			$	511,775
	and Chief Financial Officer			2002			$	387,504			$	—			$	—			$	—				—			$	—			$	71,108
Robert W. Baker				2004			$	404,004			$	295,203			$	—			$	492,800				140,000			$	97,350			$	25,658
	Executive Vice President			2003			$	360,837			$	350,000			$	—			$	—				—			$	—			$	10,500
	and General Counsel			2002			$	250,008			$	50,000			$	36,000			$	—				—			$	—			$	21,857

(1)	The amount in this column for 2004 for Messrs. Foshee and Scott reflects a voluntary reduction in annual base salary. For a one-year period beginning on January 1, 2004, Mr. Foshee voluntarily reduced his annual base salary by 30 percent to $630,000. Beginning on June 16, 2004, and for the remainder of 2004, Mr. Scott voluntarily reduced his annual base salary by 30 percent to $379,404. In addition, the amount reflected in this column for 2004, 2003 and 2002 for Messrs. Somerhalder and Baker includes an amount for El Paso mandated reductions to fund certain charitable organizations.
(2)	There were no amounts paid for other annual compensation in 2004. The amount reflected for Mr. Baker in 2002 is a $36,000 perquisite and benefit allowance. During 2003, El Paso eliminated perquisite and benefit allowances for its officers and, except as noted, the total value of the perquisites and other personal benefits received by the other executives named in this prospectus in 2003 and 2002 are not included in this column since they were below the SEC’s reporting threshold.
(3)	In 2004, Ms. Stewart received a grant of 80,000 shares of restricted stock on the start date of her employment and the total value reflected in this column for Ms. Stewart includes the value of those shares on the date of grant. The remainder of the shares of restricted stock granted to the executives named in this prospectus during 2004 are annual grants pursuant to El Paso’s long-term incentive compensation plan. The total number of shares and value of restricted stock granted (including the amount reflected in this column) held on December 31, 2004, is as follows:

		Total Number
		of Restricted				Value of
		Stock				Restricted Stock
Name		(#)				($)
Douglas L. Foshee			267,500			$	2,782,000
John W. Somerhalder II			158,004			$	1,643,242
Lisa A. Stewart			150,000			$	1,560,000
D. Dwight Scott			113,444			$	1,179,818
Robert W. Baker			102,511			$	1,066,114

These shares are subject to a time-vesting schedule of three to five years from the date of grant. In addition, most of these shares were granted as a result of the achievement of certain performance measures. Any dividends awarded on the restricted stock are paid directly to the holder of the El Paso common stock. These total values can be realized only if the executives named in this prospectus remain employees of El Paso for the required vesting period.

(4)	For 2004 and 2003, the amounts reflected in this column are the value of shares of performance-based restricted stock on the date they vested. These shares of performance-based restricted stock were originally reported, if required, in a long-term incentive table in

132

---

Table of Contents

	El Paso’s proxy statement for the year in which the shares of restricted stock were granted, along with the necessary performance measures for their vesting. No long-term incentive payouts were made in 2002. On the start date of his employment, Mr. Foshee was granted 200,000 shares of performance-based restricted stock. Based on El Paso’s performance relative to its peer companies during the first year of Mr. Foshee’s employment, 100,000 of the 200,000 shares vested and the remaining 100,000 shares were forfeited. The 100,000 shares that vested based on performance also time vest pro-rata over a five-year period. The first 20,000 shares of restricted stock vested based on time on October 11, 2004, and the value of the shares on the date they vested is reflected in this column for Mr. Foshee for 2004. On February 1, 2001, Mr. Scott was granted 50,000 shares of performance-based restricted stock. These shares time vested over a four-year period. Based on performance, 30,000 of the 50,000 shares vested on October 18, 2004, and the value of the 30,000 shares on the date they vested is reflected in this column for Mr. Scott for 2004. The remaining 20,000 shares were forfeited.
(5)	The compensation reflected in this column for 2004 includes El Paso’s contributions to the El Paso Retirement Savings Plan and supplemental company match for the Retirement Savings Plan under the Supplemental Benefits Plan and any other special payments, as follows:

		Retirement				Supplemental				Other Special
		Savings Plan				Benefits Plan				Payments
Name		($)				($)				($)(a)
Douglas L. Foshee		$	6,150			$	45,600			$	0
John W. Somerhalder II		$	6,150			$	40,350			$	0
Lisa A. Stewart		$	4,900			$	11,350			$	300,000	(b)
D. Dwight Scott		$	6,150			$	36,675			$	0
Robert W. Baker		$	6,150			$	19,508			$	0

	(a)	El Paso does not have a deferred compensation plan for executives and, therefore, does not pay any interest on deferred amounts.
	(b)	The amount in this column reflects the value of Ms. Stewart’s sign-on bonus which was paid to her when she joined El Paso on February 2, 2004.

(6)	Mr. Foshee began his employment with El Paso on September 1, 2003.
(7)	Mr. Somerhalder ceased to be an employee of El Paso on April 30, 2005.
(8)	Ms. Stewart began her employment with El Paso on February 2, 2004.
(9)	Mr. Scott ceased to be an employee of El Paso on August 10, 2005. D. Mark Leland was appointed to replace Mr. Scott effective August 10, 2005.

133

---

Table of Contents

														2005
														Annual Long-Term
														Incentive Award
										Annual Cash
		2004				2005				Incentive Bonus				Stock				Restricted
		Base Salary				Base Salary				for 2004				Options				Stock
Name		($)				($)				Performance ($)				(#)				(#)
Douglas L. Foshee		$	900,000			$	950,004			$	1,250,000				403,950				194,301
John W. Somerhalder II		$	642,000			$	642,000			$	684,735				—				—
Lisa A. Stewart		$	500,004			$	520,008			$	441,604				121,185				58,290
D. Dwight Scott		$	542,004			$	542,004			$	498,644				121,185				58,290
Robert W. Baker		$	410,004			$	426,408			$	295,203				121,185				58,290

134

---

Table of Contents

			Individual Grants(1)																Potential Realizable Value at
																			Assumed Annual Rates of Stock
																			Price Appreciation for Option Term
							Percent
							of Total												If Stock Price at				If Stock Price at
			Number of				Options												$11.98866 and				$19.08994 and
			Securities				Granted												$11.54886 in				$18.38963 in
			Underlying				to all				Exercise								2014				2014
			Options				Employees				Price				Expiration
Name			Granted (#)				in 2004				($/Share)				Date				5% ($)				10% ($)
Potential Increase in Value of All Common Stock Outstanding on December 31, 2004
	March 8, 2004 Grant			N/A				N/A				N/A				N/A			$	2,985,175,767			$	7,565,021,497
	April 1, 2004 Grant			N/A				N/A				N/A				N/A			$	2,875,665,243			$	7,287,500,328
Douglas L. Foshee				375,000				7.76	%		$	7.09000				4/1/2014			$	1,672,076			$	4,237,363
John W. Somerhalder II				140,000				2.90	%		$	7.09000				4/1/2014			$	624,241			$	1,581,949
Lisa A. Stewart				155,000				3.21	%		$	7.36000				3/8/2014			$	717,443			$	1,818,141
				140,000				2.90	%		$	7.09000				4/1/2014			$	624,241			$	1,581,949
D. Dwight Scott				210,000				4.35	%		$	7.09000				4/1/2014			$	936,361			$	2,372,923
Robert W. Baker				140,000				2.90	%		$	7.09000				4/1/2014			$	624,241			$	1,581,949

(1)

There were no stock appreciation rights granted in 2004. Any unvested stock options become fully exercisable in the event of a “change in control” of El Paso. See page 128 of this prospectus for a description of El Paso’s 2001 Omnibus Incentive Compensation Plan and the definition of the term “change in control.” Under the terms of El Paso’s 2001 Omnibus Incentive Compensation Plan, the Compensation Committee may, in its sole discretion and at any time, change the vesting of the stock options. Certain non-qualified stock options may be transferred to immediate family members, directly or indirectly or by means of a trust, corporate entity or partnership. Further, stock options are subject to forfeiture and/or time limitations on exercise in the event of termination of employment.

										Number of Securities								Value of Unexercised
		Shares								Underlying Unexercised Options								In-the-Money Options at
		Acquired				Value				at Fiscal Year-End (#)								Fiscal Year-End ($)(2)
		on Exercise				Realized
Name		(#)(1)				($)(1)				Exercisable				Unexercisable				Exercisable				Unexercisable
Douglas L. Foshee			0			$	—				200,000				1,175,000			$	607,000			$	3,661,750
John W. Somerhalder II			0			$	—				439,250				140,000			$	—			$	460,600
Lisa A. Stewart			0			$	—				0				295,000			$	—			$	928,700
D. Dwight Scott			0			$	—				143,494				210,000			$	8,280			$	690,900
Robert W. Baker			11,333			$	80,238				183,709				140,000			$	—			$	460,600

(1)	The amounts in these columns represent the number of shares and the value realized upon conversion of stock options into shares of stock that occurred during 2004 based upon the achievement of certain performance targets established when they were originally granted in 1999.
(2)	The figures presented in these columns have been calculated based upon the difference between $10.38, the fair market value of the common stock on December 31, 2004, for each in-the-money stock option, and its exercise price. No cash is realized until the shares received upon exercise of an option are sold. No executives named in this prospectus had stock appreciation rights that were outstanding on December 31, 2004.

135

---

Table of Contents

Age Plus Service		Pay Credit Percentage
Less than 35			4	%
35 to 49			5	%
50 to 64			6	%
65 and over			7	%

										Estimated
						Pay Credit Percentage				Annual
Named Executive		Credited Service(1)				During 2004				Benefits ($)(2)
Douglas L. Foshee			N/A				5	%		$	330,053
John W. Somerhalder II			24				7	%		$	402,152
Lisa A. Stewart			N/A				5	%		$	140,639
D. Dwight Scott			N/A				5	%		$	261,592
Robert W. Baker			N/A				7	%		$	142,601

(1)	For Mr. Somerhalder, credited service shown is as of December 31, 2001.
(2)	The Prior Plan minimum benefit for Mr. Somerhalder is greater than his projected cash balance benefit at age 65. As of his termination date, Mr. Somerhalder’s vested pension benefit amount under the Prior Plan is estimated to be $212,414, payable commencing at age 49 as an immediate lump sum. Mr. Somerhalder will receive his Supplemental Benefits Plan benefit in a lump sum of approximately $1.77 million, minus amounts withheld for taxes.

136

---

Table of Contents

137

---

Table of Contents

138

---

Table of Contents

139

---

Table of Contents

		Retirement				Non-Qualified
Name		Savings Plan				Pension Benefit(1)
Douglas L. Foshee		$	48,513			$	76,451
John W. Somerhalder II		$	54,488			$	1,774,503
Lisa A. Stewart		$	11,350			$	12,826
D. Dwight Scott		$	48,450			$	107,578
Robert W. Baker		$	27,195			$	114,818

	(1)	This amount is included in the calculation of the estimated annual benefits described under “— Pension Plans” on page 136 of this prospectus.

140

---

Table of Contents

141

---

Table of Contents

						Beneficial Ownership				Stock								Percent
Title of Class				Name of Beneficial Owner		(Excluding Options)(1)				Options(2)				Total				of Class
	Common Stock			Pacific Financial Research Inc.(3)			78,130,889				0				78,130,889				12.10	%
				9601 Wilshire Boulevard, Suite 800 Beverly Hills, CA 90210
	Common Stock			Brandes Investment Partners, L.L.C.(3)			71,441,912				0				71,441,912				11.06	%
				11988 El Camino Real Suite 500 San Diego, CA 92130
	Common Stock			State Street Bank and Trust Company(3)			32,321,279				0				32,321,279				5.01	%
				P.O. Box 1389 Boston, MA 02104-1389
	Common Stock			J.C. Braniff			77,334	(4)			21,000				98,334				*
	Common Stock			J.L. Dunlap			39,343	(5)			8,000				47,343				*
	Common Stock			R.W. Goldman			44,363				8,000				52,363				*
	Common Stock			A.W. Hall, Jr.			52,998				12,000				64,998				*
	Common Stock			T.R. Hix			21,136				0				21,136				*
	Common Stock			W.H. Joyce			22,136				0				22,136				*
	Common Stock			R.L. Kuehn, Jr.			329,397	(6)			502,300				831,697				*
	Common Stock			J.M. Talbert			31,413				8,000				39,413				*
	Common Stock			R.F. Vagt			5,247				0				5,247				*
	Common Stock			J.L. Whitmire			52,019				8,000				60,019				*
	Common Stock			J.B. Wyatt			66,512				14,000				80,512				*
	Common Stock			D.L. Foshee			581,431				493,750				1,075,181				*
	Common Stock			D.M. Leland			125,855	(7)			162,656				288,511				*
	Common Stock			J.W. Somerhalder II			357,154	(8)			95,000				452,154				*
	Common Stock			L.A. Stewart			196,210	(9)			73,750				269,960				*
	Common Stock			D.D. Scott			190,191	(10)			195,994				386,185				*
	Common Stock			R.W. Baker			184,443				218,709				403,152				*
	Common Stock			Directors, nominee and executive officers as a group (17 persons total), including those individuals listed above			2,377,182				1,821,159				4,198,341				0.64	%

*	Less than one percent

(1)	The individuals named in the table have sole voting and investment power with respect to shares of El Paso common stock beneficially owned, except that Mr. Talbert shares with one or more other individuals voting and investment power with respect to 5,000 shares of common stock. This column also includes shares of common stock held in the El Paso Benefits Protection Trust (as of August 19, 2005) as a result of deferral elections made in accordance with El Paso’s benefit plans. These individuals share voting power with the trustee under that plan and receive dividend equivalents on such shares, but do not have the power to dispose of, or direct the disposition of, such shares until such shares are distributed. In addition, some shares of common stock reflected in this column for certain individuals are subject to restrictions.
(2)	The directors and executive officers have the right to acquire the shares of common stock reflected in this column within 60 days of August 19, 2005, through the exercise of stock options.

142

---

Table of Contents

	(3)	According to a Schedule 13G filed on February 11, 2005, as of December 31, 2004, Pacific Financial Research Inc. had sole voting power over 73,376,789 shares of common stock, no voting power over 4,754,100 shares of common stock and sole dispositive power of 78,130,889 shares of common stock. According to a Schedule 13G filed on February 14, 2005, as of December 31, 2004, Brandes Investment Partners, L.L.C. had shared voting power of 55,594,630 shares of common stock and shared dispositive power over 71,441,912 shares of common stock. According to a Schedule 13G/ A filed on February 18, 2005, as of December 31, 2004, State Street Bank and Trust Company had sole voting power over 17,728,241 shares of common stock, shared voting power over 14,593,038 shares of common stock and shared dispositive power of 32,321,279 shares of common stock.
	(4)	Mr. Braniff’s beneficial ownership excludes 3,500 shares owned by his wife. Mr. Braniff disclaims any beneficial ownership in those shares.
	(5)	Mr. Dunlap’s beneficial ownership excludes 900 shares held by his wife as trustee. Mr. Dunlap disclaims any beneficial ownership in those shares.
	(6)	Mr. Kuehn’s beneficial ownership excludes 28,720 shares owned by his wife or children. Mr. Kuehn disclaims any beneficial ownership in those shares.
	(7)	Effective as of August 10, 2005, Mr. Leland, the former executive vice president and chief financial officer of El Paso Production Company, replaced Mr. Scott as our executive vice president and chief financial officer.
	(8)	Mr. Somerhalder’s stock ownership is as of April 30, 2005, when he left the company.
	(9)	Ms. Stewart’s beneficial ownership includes 216 shares held by her husband.

(10)	Mr. Scott’s stock ownership is as of August 10, 2005, when he resigned as our executive vice president and chief financial officer.

143

---

Table of Contents

	•	junior to all our existing and future debt obligations;
	•	junior to “senior stock,” which is all classes or series of our capital stock, other than (1) our common stock and any other class or series of our capital stock the terms of which provide that such class or series will rank junior to the preferred stock and (2) any other class or series of our capital stock the terms of which provide that such class or series will rank on a parity with the preferred stock;
	•	on a parity with “parity stock,” which is any class or series of our capital stock that has terms which provide that such class or series will rank on a parity with the preferred stock;
	•	senior to “junior stock,” which is our common stock and each class or series of our capital stock that has terms which provide that such class or series will rank junior to the preferred stock; and
	•	effectively junior to all of our subsidiaries’ (1) existing and future liabilities and (2) capital stock held by others.

144

---

Table of Contents

145

---

Table of Contents

	Fundamental Change Requires Us to Redeem Shares of Preferred Stock at the Option of the Holder

	•	are listed on, or immediately after the transaction or event will be listed on, a United States national securities exchange, or

146

---

Table of Contents

	•	are approved, or immediately after the transaction or event will be approved, for quotation on a United States national securities exchange or quotation thereof in an inter-dealer quotation system of any registered United States national securities association.

	•	the event causing a fundamental change;
	•	the date of such fundamental change;
	•	the last date on which the redemption right triggered by such fundamental change may be exercised;
	•	the fundamental change redemption price;
	•	the fundamental change redemption date;
	•	the name and address of the paying agent and the conversion agent;
	•	the conversion rate and any adjustments to the conversion rate;
	•	that the preferred stock with respect to which a fundamental change redemption notice is given by the holder may be converted only if the fundamental change redemption notice has been withdrawn in accordance with the terms of the preferred stock; and
	•	the procedures that holders must follow to exercise these rights.

	•	if certificated shares of preferred stock have been issued, the preferred stock certificate numbers, or if not, such information as may be required under applicable DTC procedures;
	•	the number of preferred shares to be redeemed; and
	•	that we are to redeem such preferred stock pursuant to the applicable provisions of the preferred stock and our amended and restated certificate of incorporation.

	•	the number of the withdrawn shares of preferred stock;
	•	if certificated shares of preferred stock have been issued, the preferred stock certificate numbers, or if not, such information as may be required under applicable DTC procedures; and
	•	the number, if any, of shares of preferred stock that remain subject to your fundamental change redemption notice.

147

---

Table of Contents

	•	the shares of preferred stock will cease to be outstanding;
	•	dividends will cease to accrue; and
	•	all other rights of the holder will terminate.

	•	to accumulate shares of common stock;
	•	to obtain control of our company by means of a merger, tender offer, solicitation or otherwise; or
	•	by management to adopt a series of anti-takeover provisions.

	Make Whole Payment Upon the Occurrence of a Fundamental Change

148

---

Table of Contents

		Stock Price on the Effective Date
Fundamental Change Date in Years		$10.42				$11.00				$12.00				$13.00				$14.00				$15.00				$16.00				$17.00				$18.00				$19.00				$20.00				$25.00				$30.00				$35.00				$40.00
April 15, 2005			17.59				15.72				13.16				11.10				9.41				8.01				6.96				6.00				5.17				4.48				3.90				1.88				0.81				0.24				0.00
April 5, 2006			16.92				14.98				12.39				10.34				8.68				7.47				6.40				5.46				4.66				4.07				3.51				1.68				0.72				0.21				0.00
April 5, 2007			16.12				14.47				11.74				9.63				8.02				6.70				5.61				4.70				3.94				3.46				2.94				1.37				0.58				0.16				0.00
April 5, 2008			15.75				13.84				11.03				8.83				7.12				5.75				4.65				3.77				3.23				2.71				2.25				1.03				0.43				0.11				0.00
April 5, 2009			15.51				13.31				10.35				7.96				6.04				4.51				3.33				2.44				2.10				1.61				1.23				0.52				0.21				0.04				0.00
April 5, 2010			15.60				13.33				10.28				7.75				5.46				3.56				1.50				0.65				0.54				0.00				0.00				0.00				0.00				0.00				0.00
April 5, 2011			15.46				13.07				10.08				7.47				5.27				3.12				1.39				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00
April 5, 2012			15.37				13.19				10.00				7.42				5.24				3.11				1.39				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00
April 5, 2013			15.22				13.32				9.85				7.31				5.15				3.06				1.37				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00
April 5, 2014			15.36				13.39				10.10				7.22				5.07				3.02				1.35				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00
April 5, 2015			0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00				0.00

	•	If the stock price is between two stock price amounts in the table or the effective date is between two effective dates in the table, the number of additional shares will be determined by a straight-line interpolation between the number of additional shares set forth for the higher and lower stock price amounts and the two dates, as applicable, based on a 365-day year.
	•	If the stock price is equal to or in excess of $40.00 per share (subject to adjustment), no additional shares will be issued upon conversion.
	•	If the stock price is less than $10.42 per share (subject to adjustment), no additional shares will be issued upon conversion.

149

---

Table of Contents

	•	The numerator of which will be (i) in the case of a consolidation, merger or binding share exchange, pursuant to which our common stock is converted into or exchanged for the right to receive cash, securities or other property, the value of all cash and any other consideration (as determined by our board of directors) paid or payable per share of common stock or (ii) in the case of any other public acquirer fundamental change, the average of the last closing price of our common stock for the five consecutive trading days prior to but excluding the effective date of such public acquirer fundamental change, and
	•	The denominator of which will be the average of the last closing sale prices of the public acquirer common stock for the five consecutive trading days commencing on the trading day next succeeding the effective date of such public acquirer fundamental change.

	•	the issuance of our common stock as a dividend or distribution on our common stock;
	•	certain subdivisions and combinations of our common stock;
	•	the issuance to all holders of our common stock of certain rights or warrants to purchase our common stock (or securities convertible into our common stock) at less than (or having a conversion price per share less than) the current market price of our common stock, provided that no such adjustment shall be made for the rights of holders of our common stock to participate in any dividend reinvestment plan in existence on the date hereof and made available to all holders of our common stock or the employee stock purchase plan effective in July 2005, or the purchase of shares pursuant to any such plan;
	•	the dividend or other distribution to all holders of our common stock of shares of our capital stock (other than common stock) or evidences of indebtedness or assets (including securities, but excluding

150

---

Table of Contents

		(1) those rights and warrants referred to above or (2) dividends or distributions paid exclusively in cash);

In the event that we make a dividend or distribution to all or substantially all holders of our common stock consisting of capital stock of, or similar equity interest in, a subsidiary or other business unit of ours, unless we distribute such capital stock or equity interests to holders of the preferred stock in such distribution on the same basis as they would have received had they converted their shares of preferred stock into shares of our common stock immediately prior to such distributions, the conversion rate will be adjusted based on the market value of the securities so distributed relative to the market value of our common stock, in each case based on the average closing sale prices of those securities for the 10 trading days commencing on and including the fifth trading day after the date on which “ex-dividend trading” commences for such dividend or distribution on the New York Stock Exchange or such other national or regional exchange or market on which the securities are then listed or quoted;

	•	distributions consisting exclusively of cash to all holders of shares of our common stock (excluding (1) any dividend or distribution in connection with our liquidation, dissolution or winding up and (2) any quarterly cash dividend on our shares of common stock to the extent that the aggregate cash dividend per share of our common stock in any quarter does not exceed $0.04 (such amount being the “dividend threshold amount”); if there is a dividend or distribution to which this bullet point applies, the conversion rate will be adjusted by multiplying the applicable conversion rate by a fraction,

	—	the numerator of which will be the current market price of our common stock minus the dividend threshold amount; and
	—	the denominator of which will be the current market price of our common stock minus the amount per share of such dividend or distribution; if an adjustment is required to be made as a result of a distribution that is not a quarterly dividend, the dividend threshold amount will be deemed to be zero; and

	•	we or one of our subsidiaries makes a payment in respect of a tender offer or exchange offer for our common stock (other than payments made under our “odd-lot” stock sales program in existence on the date hereof) to the extent that the cash and value of any other consideration included in the payment per share of common stock exceeds the closing sale price per share of common stock on the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to such tender or exchange offer.

151

---

Table of Contents

	•	any reclassification of our common stock;
	•	a consolidation, merger or combination involving us; or
	•	a sale or conveyance to another person or entity of all or substantially all of our property and assets;

152

---

Table of Contents

	•	the Mandatory Conversion Date;
	•	the number of shares of common stock to be issued upon conversion of each share of preferred stock;
	•	the number of shares of preferred stock to be converted; and
	•	that dividends on the preferred stock to be converted will cease to accrue on the Mandatory Conversion Date.

153

---

Table of Contents

	•	shares of preferred stock held by DTC or its nominees, deposit or cause to be deposited, irrevocably with DTC, cash sufficient to pay the redemption price and will give DTC irrevocable instructions and authority to pay the redemption price to holders of such shares of preferred stock; and
	•	shares of preferred stock held in certificated form, deposit or cause to be deposited, irrevocably with the paying agent, cash sufficient to pay the redemption price and will give the paying agent irrevocable instructions and authority to pay the redemption price to holders of such shares of preferred stock upon surrender of their certificates evidencing their shares of preferred stock.

154

---

Table of Contents

155

---

Table of Contents

156

---

Table of Contents

	•	exceed 30 days in any three-month period; or
	•	exceed an aggregate of 90 days for all periods in any 12-month period.

	•	on the preferred stock at an annual rate equal 0.50% of the aggregate liquidation preference of preferred stock; and
	•	on the common stock, if any, that have been issued on conversion of the preferred stock, at an annual rate equal to 0.50% of an amount equal to the conversion price.

157

---

Table of Contents

	•	be named as a selling security holder in this prospectus or an amendment or supplement thereto;
	•	deliver a prospectus to purchasers; and
	•	be bound by certain provisions of the registration rights agreement that are applicable to such holder, including certain indemnification provisions, and will be subject to certain civil liability provisions under the Securities Act.

	•	pay all of our expenses of the shelf registration statement of which this prospectus is a part;
	•	provide copies of the prospectus to each holder that has notified us of its acquisition of preferred stock or common stock issued upon conversion of the preferred stock;
	•	notify each such holder when the shelf registration statement of which this prospectus is a part has become effective as described below; and
	•	take certain other actions as are required to permit, subject to the foregoing, unrestricted resales of the preferred stock and the common stock issued upon conversion of the preferred stock.

158

---

Table of Contents

159

---

Table of Contents

	•	our charter prohibits the taking of any action by written stockholder consent in lieu of a meeting;
	•	our by-laws provide that special meetings of stockholders may be called only by a majority of the Board, the Chairman of the Board, the Chief Executive Officer, the President or the Vice Chairman of the Board; and
	•	our by-laws establish an advance notice procedure for stockholders to make nominations of candidates for election as directors or to bring other business before an annual meeting of stockholders.

160

---

Table of Contents

										Securities Offered by
		Ownership Before Closing								this Prospectus								Ownership After Offering
Name		Preferred				Common				Preferred				Common				Preferred				Common				% of Common(1)
ADAR Investment Fund Ltd.			36,000				2,763,914				36,000				2,763,914				0				0				0
AG Domestic Convertibles, LP			5,600				478,242				5,600				429,942				0				48,300				*
AG Offshore Convertibles, Ltd.			10,400				888,164				10,400				798,464				0				89,700				*
Alpine Associates			2,502				192,092				2,502				192,092				0				0				0
Alpine Partners, L.P.			345				26,488				345				26,488				0				0				0
Citigroup Global Markets Inc.			2,000				153,551				2,000				153,551				0				0				0
Clinton Multistrategy Master Fund, Ltd.			1,950				149,712				1,950				149,712				0				0				0
DBAG London			50,625				3,886,795				50,625				3,886,755				0				0				0
Franklin Income Fund			215,000				16,506,711				215,000				16,506,711				0				0				0
FTVIP Franklin Income Securities Fund			20,000				1,535,508				20,000				1,535,508				0				0				0
FIST Convertible Securities Fund			12,000				921,304				12,000				921,304				0				0				0
FTIF Franklin Income Fund			13,000				998,080				13,000				998,080				0				0				0
FrontPoint Convertible Arbitrage Fund, LP			1,000				76,775				1,000				76,775				0				0				0
Institutional Benchmark Management Fund c/o Quattro Fund			250				19,194				250				19,194				0				0				0
Kamunting Street Master Fund, Ltd.			15,500				190,019				15,500				1,190,019				0				0				0
LDG Limited			96				7,370				96				7,370				0				0				0
Mohican VCA Master Fund, Ltd.			1,180				90,595				1,180				90,595				0				0				0
MSS Convertible Arbitrage 1			34				5,028				34				2,610				0				2,418
Newport Alternative Income Fund			520				39,923				520				39,923				0				0				0
Partners Group c/o Quattro Fund			750				57,582				750				57,582				0				0				0
Pebble Limited Partnership			280				21,497				280				21,497				0				0				0
Quattro Fund Ltd			3,750				287,908				3,750				287,908				0				0				0
Quattro Multistrategy Masterfund LP			250				19,194				250				19,194				0				0				0
RCG Latitude Master Fund, Ltd.			1,500				115,163				1,500				115,163				0				0				0
RGC Multi-Strategy Master Fund, Ltd			1,000				76,775				1,000				76,775				0				0				0
Ritchie Convertible Arbitrage Trading			820				62,956				820				62,956				0				0				0
Sage Capital Management, LLC			3,500				268,714				3,500				268,714				0				0				0
Sphinx Fund			398				70,458				398				30,557				0				39,901				*
Sphinx Convertible Arbitrage (Clinton) Segregated Portfolio			550				42,226				550				42,226				0				0				0
Tribeca Global Convertible Investments Ltd.			3,500				317,314				3500				268,714				0				48,600				*
TQA Master Plus Fund, Ltd.			3,760				725,537				3,760				288,676				0				436,861				*
Silvercreek Limited Partnership			1,600				122,841				1,600				122,841				0				0				0
Silvercreek II Limited			1,600				122,841				1,600				122,841				0				0				0
TQA Master Fund, Ltd.			2,335				506,232				2,335				179,271				0				326,961				*
Xavex-Convertible Arbitrage 7 c/o TQA			150				38,635				150				11,516				0				27,119				*
ZLP Master Fund, Ltd.			25,000				1,919,385				25,000				1,919,385				0				0				0
Zurich Institutional Benchmark Master c/o TQA			557				99,205				557				42,764				0				56,441				*

*	Less than 1%.

(1)	Based on 659,367,168 shares of common stock outstanding as of August 19, 2005.

161

---

Table of Contents

	•	all or a portion of the shares of preferred stock or common stock beneficially owned by selling stockholders or their respective pledgees, donees, transferees or successors-in-interest, may be sold on any national securities exchange or quotation service on which the shares of preferred stock or common stock may be listed or quoted at the time of sale, in the over-the counter market, in privately negotiated transactions, through the writing of options, whether such options are listed on an options exchange or otherwise, short sales or in combination of such transactions;
	•	each sale may be made at market prices prevailing at the time of such sale, at negotiated prices, at fixed prices, or at varying prices determined at the time of sale; and
	•	some or all of the shares of preferred stock or common stock may be sold through one or more broker-dealers or agents and may involve crosses, block transactions in which the broker-dealer will attempt to sell shares as agent but may position and resell a portion of the block as principal to facilitate the transaction, or hedging transactions. The selling stockholders may enter into hedging transactions with broker-dealers or agents, which may in turn engage in short sales of preferred stock and common stock in the course of hedging in positions they assume. The selling stockholders may also sell shares of preferred stock and common stock short and deliver shares of preferred stock and common stock to close out short positions, or loan pledge shares of preferred stock and common stock to broker-dealers or agents that in turn may sell such shares.

162

---

Table of Contents

163

---

Table of Contents

	•	an individual citizen or resident of the United States;
	•	a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States, any state thereof or the District of Columbia;
	•	an estate the income of which is subject to United States federal income tax regardless of source thereof; or
	•	a trust with respect to which a court within the United States is able to exercise primary supervision over its administration and one or more United States persons have the authority to control all of its substantial decisions, or that has in effect a valid election under applicable Treasury regulations to be treated as a United States person.

	Distributions

164

---

Table of Contents

	Dividends to Corporate Shareholders

	•	the holder’s holding period for the stock;
	•	debt-financed portfolio stock;
	•	dividends treated as “extraordinary dividends” for purposes of Section 1059 of the Internal Revenue Code; and
	•	holders that pay corporate alternative minimum tax.

	Sale or Other Taxable Disposition

165

---

Table of Contents

	•	the U.S. holder’s interest in our stock is completely terminated as a result of the redemption;
	•	the U.S. holder’s percentage ownership in our voting stock immediately after the redemption is less than 80% of the holder’s percentage ownership immediately before the redemption; or
	•	the redemption is “not essentially equivalent to a dividend.”

	Conversion of Preferred Stock

	Adjustments of Conversion Rate

166

---

Table of Contents

	Information Reporting and Backup Withholding

	•	the U.S. holder is a corporation or comes within certain other exempt categories and, when required, demonstrates this fact; or
	•	within a reasonable period of time, the U.S. holder provides a taxpayer identification number, certified under penalties of perjury, as well as certain other information, or otherwise establishes an exemption from the backup withholding rules.

	Distributions

	Sale or Other Taxable Disposition

	•	the gain is effectively connected with the conduct by the non-U.S. holder of a trade or business within the United States (and, if required by an applicable income tax treaty, is attributable to a United States permanent establishment of the non-U.S. holder);
	•	the non-U.S. holder is an individual who is present in the United States for 183 days or more in the taxable year of disposition and certain other requirements are met; or
	•	we are or have been a “United States real property holding corporation” for United States federal income tax purposes at any time during the shorter of the five-year period preceding such sale or other disposition or the period that such non-U.S. holder held the preferred stock (or is treated as having held the common stock received upon conversion thereof, as applicable.)

167

---

Table of Contents

	•	will not be subject to United States federal income tax on the disposition of the common stock if it holds and has held (at all times during the shorter of the five-year period immediately preceding the date of disposition or the holder’s holding period) not more than 5% of the total outstanding shares of our common stock; and
	•	will not be subject to United States federal income tax on the disposition of the preferred stock if it holds and has held (at all times during the shorter of the five-year period immediately preceding the date of disposition or the holder’s holding period) preferred stock with a fair market value that is not more than 5% of the total outstanding shares of the preferred stock.

	Conversion of Preferred Stock

	Information Reporting and Backup Withholding

168

---

Table of Contents

169

---

Table of Contents

					Page
El Paso Corporation
Unaudited Consolidated Financial Statements:
	Condensed Consolidated Statements of Income for the quarters and six months ended June 30, 2005 and 2004					F-3
	Condensed Consolidated Balance Sheets as of June 30, 2005 and December 31, 2004					F-4
	Condensed Consolidated Statements of Cash Flows for six months ended June 30, 2005 and 2004					F-6
	Condensed Consolidated Statements of Comprehensive Income for quarters and six months ended June 30, 2005 and 2004					F-7
	Notes to the Condensed Consolidated Financial Statements					F-8
			1. Basis of Presentation and Significant Accounting Policies			F-8
			2. Acquisitions			F-10
			3. Divestitures			F-11
			4. Restructuring Costs			F-14
			5. Loss on Long Lived Assets			F-14
			6. Income Taxes			F-15
			7. Earnings Per Share			F-16
			8. Price Risk Management Activities			F-16
			9. Debt, Other Financing Obligations and Other Credit Facilities			F-17
		10. Commitments and Contingencies				F-19
		11. Retirement Benefits				F-28
		12. Capital Stock				F-28
		13. Business Segment Information				F-29
		14. Investments in Unconsolidated Affiliates and Related Party Transactions				F-32
	Controls and Procedures					F-37
Audited Consolidated Financial Statements
	Consolidated Statements of Income for the years ended December 31, 2004, 2003 and 2002					F-39
	Consolidated Balance Sheets as of December 31, 2004 and 2003					F-40
	Consolidated Statements of Cash Flows for the years ended December 31, 2004, 2003 and 2002					F-42
	Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2004, 2003 and 2002					F-44
	Consolidated Statements of Comprehensive Income for the years ended December 31, 2004, 2003 and 2002					F-45
	Notes to Consolidated Financial Statements					F-46
			1. Basis of Presentation and Significant Accounting Policies			F-46
			2. Acquisitions and Consolidations			F-58
			3. Divestitures			F-62
			4. Restructuring Costs			F-66
			5. Loss on Long-Lived Assets			F-68
			6. Other Income and Other Expenses			F-69
			7. Income Taxes			F-70
			8. Earnings Per Share			F-73
			9. Fair Value of Financial Instruments			F-73

F-1

---

Table of Contents

				Page
		10. Price Risk Management Activities			F-73
		11. Inventory			F-79
		12. Regulatory Assets and Liabilities			F-79
		13. Other Assets and Liabilities			F-80
		14. Property, Plant and Equipment			F-81
		15. Debt, Other Financing Obligations and Other Credit Facilities			F-81
		16. Preferred Interests of Consolidated Subsidiaries			F-88
		17. Commitments and Contingencies			F-89
		18. Retirement Benefits			F-99
		19. Capital Stock			F-103
		20. Stock-Based Compensation			F-103
		21. Business Segment Information			F-105
		22. Investments in, Earnings from and Transactions with Unconsolidated Affiliates			F-110
	Report of Management on Internal Controls Over Financial Reporting				F-118
	Report of Independent Registered Public Accounting Firm				F-121
	Supplemental Financial Information
		Supplemental Selected Quarterly Financial Information (Unaudited)			F-125
		Supplemental Natural Gas and Oil Operations (Unaudited)			F-126
		Schedule II — Valuation and Qualifying Accounts			F-135
	Midland Cogeneration Venture Limited Partnership
		Report of Management on Internal Controls Over Financial Reporting			FA-1
		Report of Independent Registered Public Accounting Firm			FA-2
		Consolidated Balance Sheets			FA-4
		Consolidated Statements of Operations			FA-5
		Consolidated Statements of Partners’ Equity			FA-6
		Consolidated Statements of Cash Flows			FA-7
		Notes to Consolidated Financial Statements			FA-8
El Paso Corporation
Unaudited Pro Forma Condensed Consolidated Financial Statements
	Introduction				FB-1
	Unaudited Pro Forma Condensed Consolidated Balance Sheet as of June 30, 2005				FB-2
	Unaudited Pro Forma Condensed Consolidated Statement of Income for the six months ended June 30, 2005				FB-3
	Unaudited Pro Forma Condensed Consolidated Statement of Income for the year ended December 31, 2004				FB-4
	Notes to the Unaudited Pro Forma Condensed Consolidated Financial Statements				FB-5

F-2

---

Table of Contents

			Quarter Ended								Six Months Ended
			June 30,								June 30,
			2005				2004				2005				2004
Operating revenues			$	1,224			$	1,524			$	2,366			$	3,081
Operating expenses
	Cost of products and services			60				435				159				825
	Operation and maintenance			438				373				880				774
	Depreciation, depletion and amortization			294				263				574				538
	Loss on long-lived assets			360				17				381				255
	Taxes, other than income taxes			65				66				136				130
				1,217				1,154				2,130				2,522
Operating income (loss)				7				370				236				559
Earnings (loss) from unconsolidated affiliates				(19	)			98				171				185
Other income, net				71				30				104				74
Interest and debt expense				(340	)			(410	)			(690	)			(833	)
Distributions on preferred interests of consolidated subsidiaries				(3	)			(6	)			(9	)			(12	)
Income (loss) before income taxes				(284	)			82				(188	)			(27	)
Income taxes				(51	)			48				(57	)			58
Income (loss) from continuing operations				(233	)			34				(131	)			(85	)
Discontinued operations, net of income taxes				(5	)			(29	)			(1	)			(106	)
Net income (loss)				(238	)			5				(132	)			(191	)
Preferred stock dividends				(8	)			—				(8	)			—
Net income (loss) available to common stockholders			$	(246	)		$	5			$	(140	)		$	(191	)
Basic and diluted income (loss) per common share
	Income (loss) from continuing operations		$	(0.37	)		$	0.05			$	(0.22	)		$	(0.13	)
	Discontinued operations, net of income taxes			(0.01	)			(0.04	)			—				(0.17	)
	Net income (loss) per common share		$	(0.38	)		$	0.01			$	(0.22	)		$	(0.30	)
Basic and diluted average common shares outstanding				641				639				640				639
Dividends declared per common share			$	0.04			$	0.04			$	0.08			$	0.08

F-3

---

Table of Contents

					June 30,				December 31,
					2005				2004
ASSETS
Current assets
	Cash and cash equivalents				$	1,540			$	2,117
	Accounts and notes receivable
		Customers, net of allowance of $77 in 2005 and $199 in 2004				975				1,388
		Affiliates				90				133
		Other				151				188
	Assets from price risk management activities					576				601
	Margin and other deposits held by others					328				79
	Deferred income taxes					607				418
	Other					539				708
			Total current assets			4,806				5,632
Property, plant and equipment, at cost
	Pipelines					19,609				19,418
	Natural gas and oil properties, at full cost					15,693				14,968
	Power facilities					957				1,550
	Gathering and processing systems					64				171
	Other					629				882
						36,952				36,989
	Less accumulated depreciation, depletion and amortization					18,265				18,177
			Total property, plant and equipment, net			18,687				18,812
Other assets
	Investments in unconsolidated affiliates					2,275				2,614
	Assets from price risk management activities					1,203				1,584
	Goodwill and other intangible assets, net					422				428
	Other					2,283				2,313
						6,183				6,939
			Total assets		$	29,676			$	31,383

F-4

---

Table of Contents

					June 30,				December 31,
					2005				2004
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Accounts payable
		Trade			$	792			$	1,052
		Affiliates				8				21
		Other				399				483
	Short-term financing obligations, including current maturities					1,099				955
	Liabilities from price risk management activities					920				852
	Margin and other deposits					342				131
	Western Energy Settlement					—				44
	Accrued interest					281				333
	Other					818				701
			Total current liabilities			4,659				4,572
Long-term financing obligations, less current maturities						16,379				18,241
Other
	Liabilities from price risk management activities					1,390				1,026
	Deferred income taxes					1,528				1,312
	Western Energy Settlement					—				351
	Other					1,861				2,076
						4,779				4,765
Commitments and contingencies
Securities of subsidiaries						59				367
Stockholders’ equity
	4.99% Convertible perpetual preferred stock, par value $0.01 per share; authorized 50,000,000 shares; issued 750,000 shares in 2005; stated at liquidation value					750				—
	Common stock, par value $3 per share; authorized 1,500,000,000 shares; issued 653,065,090 shares in 2005 and 651,064,508 shares in 2004					1,959				1,953
	Additional paid-in capital					4,431				4,538
	Accumulated deficit					(2,941	)			(2,809	)
	Accumulated other comprehensive income (loss)					(183	)			1
	Treasury stock (at cost); 7,361,325 shares in 2005 and 7,767,088 shares in 2004					(189	)			(225	)
	Unamortized compensation					(27	)			(20	)
			Total stockholders’ equity			3,800				3,438
			Total liabilities and stockholders’ equity		$	29,676			$	31,383

F-5

---

Table of Contents

					Six Months Ended
					June 30,
					2005				2004
Cash flows from operating activities
	Net loss				$	(132	)		$	(191	)
		Less loss from discontinued operations, net of income taxes				(1	)			(106	)
	Net loss from continuing operations					(131	)			(85	)
	Adjustments to reconcile net loss to net cash from operating activities
		Depreciation, depletion and amortization				574				538
		Loss on long-lived assets				381				255
		Earnings from unconsolidated affiliates, adjusted for cash distributions				(24	)			(27	)
		Deferred income taxes				4				37
		Other non-cash items				35				53
		Other asset and liability changes				(812	)			(636	)
		Cash provided by continuing operations				27				135
		Cash provided by (used in) discontinued operations				(17	)			161
			Net cash provided by operating activities			10				296
Cash flows from investing activities
	Additions to property, plant and equipment					(806	)			(782	)
	Purchases of interests in equity investments					(15	)			(21	)
	Net proceeds from the sale of assets and investments					834				165
	Proceeds from settlement of a foreign currency derivative					131				—
	Cash paid for acquisitions, net of cash acquired					(178	)			2
	Net change in restricted cash					62				447
	Net change in notes receivable from unconsolidated affiliates					5				98
	Other					47				—
		Cash provided by (used in) continuing operations				80				(91	)
		Cash provided by discontinued operations				70				1,113
			Net cash provided by investing activities			150				1,022
Cash flows from financing activities
	Payments to retire long-term debt and other financing obligations					(1,563	)			(1,024	)
	Net proceeds from the issuance of long-term debt and other financing obligations					458				50
	Net proceeds from the issuance of preferred stock					723				—
	Redemption of preferred stock of subsidiary					(300	)			—
	Dividends paid					(51	)			(49	)
	Contributions from discontinued operations					53				909
	Issuances of common stock, net					—				73
	Other					(4	)			(21	)
		Cash used in continuing operations				(684	)			(62	)
		Cash used in discontinued operations				(53	)			(1,274	)
			Net cash used in financing activities			(737	)			(1,336	)
Change in cash and cash equivalents						(577	)			(18	)
Cash and cash equivalents
	Beginning of period					2,117				1,429
	End of period				$	1,540			$	1,411

F-6

---

Table of Contents

				Quarter Ended								Six Months
				June 30,								Ended June 30,
				2005				2004				2005				2004
Net income (loss)				$	(238	)		$	5			$	(132	)		$	(191	)
Foreign currency translation adjustments (net of income taxes of $6 and $7 in 2005 and $14 and $51 in 2004)					(4	)			(24	)			7				(20	)
Unrealized net gains (losses) from cash flow hedging activity
	Unrealized mark-to-market gains (losses) arising during period (net of income taxes of $13 and $89 in 2005 and $2 and $12 in 2004)				17				(4	)			(172	)			(23	)
	Reclassification adjustments for changes in initial value to the settlement date (net of income taxes of $1 and $12 in 2005 and $7 and $15 in 2004)				2				24				(19	)			39
		Other comprehensive income (loss)			15				(4	)			(184	)			(4	)
Comprehensive income (loss)				$	(223	)		$	1			$	(316	)		$	(195	)

F-7

---

Table of Contents

F-8

---

Table of Contents

		2005				2004
		(In millions)
Operating revenues		$	(111	)		$	(3	)
Current liabilities from price risk management activities			21				20
Non-current liabilities from price risk management activities			127				29

	Stock-Based Compensation

			Quarter Ended								Six Months
			June 30,								Ended June 30,
			2005				2004				2005				2004
			(In millions)
Net income (loss) available to common stockholders as reported			$	(246	)		$	5			$	(140	)		$	(191	)
Add: Stock-based compensation expense in net income (loss), net of taxes				3				7				5				11
Deduct: Stock-based compensation expense determined under fair value-based method for all awards, net of taxes				5				11				10				21
Net income (loss) available to common stockholders, pro forma			$	(248	)		$	1			$	(145	)		$	(201	)
Income (loss) per share:
	Basic and diluted, as reported		$	(0.38	)		$	0.01			$	(0.22	)		$	(0.30	)
	Basic and diluted, pro forma		$	(0.39	)		$	—			$	(0.23	)		$	(0.31	)

	New Accounting Pronouncements Issued But Not Yet Adopted

F-9

---

Table of Contents

F-10

---

Table of Contents

	Sales of Assets and Investments

			2005				2004
			(In millions)
Regulated
	Pipelines		$	35			$	50
Non-regulated
	Power			176				99
	Field Services			501				—
Other
	Corporate			121				16
Total continuing				833	(1)			165
Discontinued				85				1,261
Total			$	918			$	1,426

(1)	Proceeds exclude returns of capital from unconsolidated affiliates and cash transferred with the assets sold and include costs incurred for disposal. These increased our sales proceeds by $1 million for the six months ended June 30, 2005.

		2005		2004
Pipelines		• Facilities located in the southeastern U.S.		• Australia pipeline • Aircraft
Power		• Cedar Brakes I and II • Interest in a power plant in India • Interest in a power plant in England • 4 domestic power facilities • Power turbine		• Mohawk River Funding IV • Utility Contract Funding (UCF) • Bastrop Company equity investment
Field Services		• 9.9% interest in general partner of Enterprise Products Partners, L.P.		• None
		• 13.5 million common units in Enterprise
		• Interest in Indian Springs natural gas gathering system and processing facility
Corporate		• Lakeside Technology Center		• Aircraft
Discontinued		• Interest in Paraxylene facility • MTBE processing facility • International natural gas and oil production properties		• Natural gas and oil production properties in Canada • Aruba and Eagle Point refineries and other petroleum assets

F-11

---

Table of Contents

	Discontinued Operations

F-12

---

Table of Contents

										South
						International				Louisiana
						Natural Gas				Gathering
						and Oil				and
		Petroleum				Production				Processing
		Markets				Operations				Operations				Total
		(In millions)
Operating Results Data
Quarter Ended June 30, 2005
Revenues		$	30			$	—			$	90			$	120
Costs and expenses			(33	)			(1	)			(79	)			(113	)
Loss on long-lived assets			—				(4	)			—				(4	)
Other expense			(4	)			—				—				(4	)
Income (loss) before income taxes			(7	)			(5	)			11				(1	)
Income taxes			1				(2	)			5				4
Income (loss) from discontinued operations, net of income taxes		$	(8	)		$	(3	)			6			$	(5	)
Quarter Ended June 30, 2004
Revenues		$	54			$	1			$	—			$	55
Costs and expenses			(77	)			(3	)			—				(80	)
Gain on long-lived assets			4				—				—				4
Other income			2				—				—				2
Loss before income taxes			(17	)			(2	)			—				(19	)
Income taxes			(3	)			13				—				10
Loss from discontinued operations, net of income taxes		$	(14	)		$	(15	)		$	—			$	(29	)
Six Months Ended June 30, 2005
Revenues		$	74			$	2			$	177			$	253
Costs and expenses			(86	)			(2	)			(157	)			(245	)
Gain (loss) on long-lived assets			3				(5	)			—				(2	)
Other income			11				—				—				11
Income (loss) before income taxes			2				(5	)			20				17
Income taxes			13				(3	)			8				18
Income (loss) from discontinued operations, net of income taxes		$	(11	)		$	(2	)			12			$	(1	)

F-13

---

Table of Contents

										South
						International				Louisiana
						Natural Gas				Gathering
						and Oil				and
		Petroleum				Production				Processing
		Markets				Operations				Operations				Total
		(In millions)
Six Months Ended June 30, 2004
Revenues		$	693			$	28			$	—			$	721
Costs and expenses			(730	)			(47	)			—				(777	)
Loss on long-lived assets			(38	)			(16	)			—				(54	)
Interest and debt expense			(3	)			1				—				(2	)
Other expense			(8	)			—				—				(8	)
Loss before income taxes			(86	)			(34	)			—				(120	)
Income taxes			(9	)			(5	)			—				(14	)
Loss from discontinued operations, net of income taxes		$	(77	)		$	(29	)		$	—			$	(106	)

										Six Months
		Quarter Ended								Ended
		June 30,								June 30,
		2005				2004				2005				2004
		(In millions)
Net realized gain		$	(6	)		$	(6	)		$	(13	)		$	(14	)
Asset impairments			366				23				394				269
Loss on long-lived assets			360				17				381				255
(Gain) loss on investments in unconsolidated affiliates (1)			87				18				(32	)			42
Loss on long-lived assets and investments		$	447			$	35			$	349			$	297

(1)	See Note 14 on page F-32 for a further description of these gains and losses.

F-14

---

Table of Contents

										Six Months
		Quarter Ended								Ended
		June 30,								June 30,
		2005				2004				2005				2004
		(In millions, except rates)
Income taxes		$	(51	)		$	48			$	(57	)		$	58
Effective tax rate			18	%			59	%			30	%			(215	)%

	•	Impairments of certain foreign investments for which there was only a partial corresponding income tax benefit, as well as foreign income taxed at different rates;
	•	Benefits recorded on book versus tax differences related to certain of our Asian and Indian power assets as further described below;
	•	A reduction of our liabilities for tax contingencies as a result of an IRS settlement on the 1995 to 1997 Coastal Corporation income tax returns of $33 million, expiration of a tax indemnity claim, and approval of a 1986 refund claim; and

F-15

---

Table of Contents

	•	Other items including (i) state income taxes (including valuation allowances) and state tax adjustments to reflect income tax returns as filed, net of federal income tax effects; (ii) earnings/losses from unconsolidated affiliates where we anticipate receiving dividends; and (iii) non-deductible dividends on the preferred stock of subsidiaries.

				June 30,				December 31,
				2005				2004
				(In millions)
Net assets (liabilities)
	Derivatives designated as hedges			$	(640	)		$	(536	)
	Derivatives from power contract restructuring activities (1)				60				665
	Other commodity-based derivative contracts(1)				36				(61	)
		Total commodity-based derivatives			(544	)			68
	Interest rate and foreign currency hedging derivatives (2)				13				239
		Net assets (liabilities) from price risk management activities(3)		$	(531	)		$	307

(1)	Derivatives from power contract restructuring activities as of December 31, 2004 includes $596 million of derivative contracts sold in connection with the sale of Cedar Brakes I and II in March 2005. In connection with this sale, we also assigned or terminated other commodity-based derivatives that had a fair value liability of $240 million as of December 31, 2004.
(2)	In March 2005, we repurchased approximately €528 million of debt, of which €375 million was hedged with interest rate and foreign currency derivatives. As a result of the repurchase, we removed the hedging designation on these derivatives and cancelled

F-16

---

Table of Contents

	substantially all of the contracts. We recorded a gain of approximately $2 million during the first quarter of 2005 upon the reversal of the related accumulated other comprehensive income associated with these derivatives.
(3)	Included in both current and non-current assets and liabilities on the balance sheet.

		June 30,				December 31,
		2005				2004
		(In millions)
Short-term financing obligations, including current maturities		$	1,099	(1)		$	955
Long-term financing obligations			16,379				18,241
Total		$	17,478			$	19,196

(1)	Includes $599 million of zero coupon debentures that the holders may require us to redeem in February 2006, prior to their stated maturities.

F-17

---

Table of Contents

	Long-Term Financing Obligations

																Cash Received/
Company				Type				Interest Rate				Book Value				Paid
												(In millions)
	Issuances
Colorado Interstate Gas Company (CIG)					Senior Notes due 2015				5.95%			$	200			$	197
Cheyenne Plains Gas Pipeline Company(1)					Non-recourse term loan due  2015				Variable				266				261
					Increases through June 30, 2005							$	466			$	458
Repayments, repurchases, retirements and other
	El Paso				Zero coupon debenture(2)				—			$	236			$	237
	El Paso				Notes				6.88%				167				167
	Cedar Brakes I(3)				Non-recourse notes				8.5%				241				15
	Cedar Brakes II(3)				Non-recourse notes				9.88%				334				14
	El Paso(4)				Euro notes				5.75%				695				722
	CIG				Debentures				10.00%				180				180
	Other				Long-term debt				Various				331				228
					Decreases through June 30, 2005							$	2,184			$	1,563
	Other				Long-term debt								5				5
					Decreases through filing date							$	2,189			$	1,568

(1)	In addition to the borrowing, we have an associated letter of credit facility for $12 million, under which we issued $6 million of letters of credit in May 2005. We also concurrently entered into swaps to convert the variable interest rate on approximately $213 million of this debt to a current fixed rate of 5.94 percent.
(2)	This security has a yield-to-maturity of approximately four percent.
(3)	Prior to the sale of Cedar Brakes I and II, we made $29 million of scheduled principal repayments. Upon the sale of these entities in March 2005, the remaining balance of the debt was eliminated.
(4)	We recorded a $26 million loss on the early extinguishment of this debt.

F-18

---

Table of Contents

10.	Commitments and Contingencies

	Legal Proceedings

	Shareholder/ Derivative/ ERISA Litigation

	Shareholder Litigation. Twenty-eight purported shareholder class action lawsuits have been pending since 2002 and are consolidated in federal court in Houston, Texas. This consolidated lawsuit, which alleges violations of federal securities laws against us and several of our current and former officers and directors, includes allegations regarding the accuracy or completeness of press releases and other public statements made during the class period from 2001 through early 2004 related to wash trades, mark-to-market accounting, off-balance sheet debt, the overstatement of oil and gas reserves and manipulation of the California energy market. Discovery in the consolidated lawsuit is currently stayed.
	Derivative Litigation. Since 2002, six shareholder derivative actions have also been filed. Three of the actions allege the same claims as in the consolidated shareholder class action suit described above, with one of the actions including a claim for compensation disgorgement against certain individuals. Discovery in two of those three lawsuits are stayed in federal court in Houston, Texas. The third, originally pending in Delaware, was voluntarily dismissed by the plaintiffs in July 2005. The Delaware plaintiffs’ claims will be pursued with two other actions consolidated in state court in Houston, Texas. The state court lawsuits generally allege that the manipulation of California gas prices exposed us to claims of antitrust conspiracy, FERC penalties and erosion of share value and are set for trial in January 2006. The sixth derivative action, Laties v. El Paso, et al. was filed in Delaware in April 2005 against our former Chief Executive Officer, William Wise and current and former members of our Board of Directors. This derivative action seeks restitution of the 2001 incentive compensation paid to William Wise due to the Company’s restatement of its financial statements for that year.

F-19

---

Table of Contents

	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 generally that our direct and indirect communications with participants in the El Paso Corporation Retirement Savings Plan included misrepresentations and omissions that caused members of the class to hold and maintain investments in El Paso stock in violation of the Employee Retirement Income Security Act (ERISA). That lawsuit was subsequently amended to include allegations relating to our reporting of natural gas and oil reserves. Discovery in this lawsuit is currently stayed.
	We and our representatives have insurance coverages that are applicable to each of these shareholder, derivative and ERISA lawsuits. There are certain deductibles and co-pay obligations under some of those insurance coverages for which we have established certain accruals we believe are adequate.

F-20

---

Table of Contents

F-21

---

Table of Contents

F-22

---

Table of Contents

	Government Investigations

F-23

---

Table of Contents

F-24

---

Table of Contents

F-25

---

Table of Contents

		June 30, 2005
Sites		Expected				High
		(In millions)
Operating		$	100			$	111
Non-operating			244				374
Superfund			27				46
Total		$	371			$	531

Balance as of January 1, 2005		$	380
Additions/adjustments for remediation activities			15
Payments for remediation activities			(26	)
Other changes, net			2
Balance as of June 30, 2005		$	371

F-26

---

Table of Contents

F-27

---

Table of Contents

			Quarters Ended June 30,																Six Months Ended June 30,
											Other																Other
			Pension								Postretirement								Pension								Postretirement
			Benefits								Benefits								Benefits								Benefits
			2005				2004				2005				2004				2005				2004				2005				2004
			(In millions)																(In millions)
Service cost			$	6			$	8			$	—			$	—			$	12			$	16			$	—			$	—
Interest cost				29				30				8				8				58				61				15				16
Expected return on plan assets				(42	)			(47	)			(3	)			(3	)			(84	)			(95	)			(6	)			(6	)
Amortization of net actuarial loss				16				12				—				1				32				24				—				2
Amortization of transition obligation				—				—				2				2				—				—				4				4
Amortization of prior service cost (1)				(1	)			(1	)			—				—				(2	)			(2	)			—				—
	Net benefit cost		$	8			$	2			$	7			$	8			$	16			$	4			$	13			$	16

(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.

F-28

---

Table of Contents

											Six Months
			Quarter Ended								Ended
			June 30,								June 30,
			2005				2004				2005				2004
			(In millions)
Total EBIT			$	59			$	498			$	511			$	818
Interest and debt expense				(340	)			(410	)			(690	)			(833	)
Distributions on preferred interests of consolidated subsidiaries				(3	)			(6	)			(9	)			(12	)
Income taxes				51				(48	)			57				(58	)
	Income (loss) from continuing operations		$	(233	)		$	34			$	(131	)		$	(85	)

F-29

---

Table of Contents

		Regulated				Non-regulated
										Marketing
										and								Field
Quarter Ended June 30,		Pipelines				Production				Trading				Power				Services				Corporate(1)				Total
		(In millions)
2005
Revenues from external customers		$	634			$	171	(2)		$	240			$	112			$	23			$	24			$	1,204
Intersegment revenues			19				281	(2)			(261	)			(3	)			5				(21	)			20	(3)
Operation and maintenance			214				99				9				78				4				34				438
Depreciation, depletion and amortization			108				157				1				10				1				17				294
(Gain) loss on long-lived assets			(3	)			—				—				361				6				(4	)			360
Operating income (loss)		$	262			$	175			$	(32	)		$	(357	)		$	(5	)		$	(36	)		$	7
Earnings (losses) from unconsolidated affiliates			38				—				—				(59	)			2				—				(19	)
Other income, net			9				1				2				35				—				24				71
EBIT		$	309			$	176			$	(30	)		$	(381	)		$	(3	)		$	(12	)		$	59
2004
Revenues from external customers		$	595			$	144	(2)		$	187			$	202			$	375			$	29			$	1,532
Intersegment revenues			22				286	(2)			(328	)			34				53				(75	)			(8	) (3)
Operation and maintenance			172				77				10				97				25				(8	)			373
Depreciation, depletion and amortization			101				131				3				12				4				12				263
(Gain) loss on long-lived assets			—				—				—				16				6				(5	)			17
Operating income (loss)		$	260			$	202			$	(154	)		$	56			$	7			$	(1	)		$	370
Earnings from unconsolidated affiliates			41				2				—				24				31				—				98
Other income (expense), net			7				—				2				22				(11	)			10				30
EBIT		$	308			$	204			$	(152	)		$	102			$	27			$	9			$	498

(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. For the quarters ended June 30, 2005 and 2004, we recorded an intersegment revenue elimination of $39 million and $75 million and an operations and maintenance expense elimination of less than $1 million and $1 million, which is included in the “Corporate” column, to remove intersegment transactions.
(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 and Trading segment, which is responsible for marketing our production.
(3)	Relates to intercompany activities between our continuing operations and our discontinued operations.

F-30

---

Table of Contents

		Regulated				Non-regulated
										Marketing
										and								Field
Six Months Ended June 30,		Pipelines				Production				Trading				Power				Services				Corporate(1)				Total
		(In millions)
2005
Revenues from external customers		$	1,382			$	302	(2)		$	333			$	191			$	65			$	51			$	2,324
Intersegment revenues			39				589	(2)			(529	)			(5	)			11				(63	)			42	(3)
Operation and maintenance			417				183				19				129				3				129				880
Depreciation, depletion and amortization			219				303				2				22				2				26				574
(Gain) loss on long-lived assets			(10	)			—				—				388				7				(4	)			381
Operating income (loss)		$	624			$	355			$	(218	)		$	(395	)		$	(3	)		$	(127	)		$	236
Earnings (losses) from unconsolidated affiliates			76				—				—				(87	)			182				—				171
Other income, net			21				4				3				51				—				25				104
EBIT		$	721			$	359			$	(215	)		$	(431	)		$	179			$	(102	)		$	511
2004
Revenues from external customers		$	1,293			$	277	(2)		$	368			$	351			$	720			$	72			$	3,081
Intersegment revenues			45				599	(2)			(668	)			92				95				(163	)			—
Operation and maintenance			352				162				23				194				51				(8	)			774
Depreciation, depletion and amortization			201				271				6				28				7				25				538
(Gain) loss on long-lived assets			(1	)			—				—				256				8				(8	)			255
Operating income (loss)		$	608			$	405			$	(329	)		$	(148	)		$	17			$	6			$	559
Earnings from unconsolidated affiliates			74				3				—				40				68				—				185
Other income (expense), net			12				—				13				41				(22	)			30				74
EBIT		$	694			$	408			$	(316	)		$	(67	)		$	63			$	36			$	818

(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. For the six months ended June 30, 2005 and 2004, we recorded an intersegment revenue elimination of $103 million and $163 million and an operations and maintenance expense elimination of less than $1 million and $1 million, which is included in the “Corporate” column, to remove intersegment transactions.
(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 and Trading segment, which is responsible for marketing our production.
(3)	Relates to intercompany activities between our continuing operations and our discontinued operations.

				June 30,				December 31,
				2005				2004
				(In millions)
Regulated
	Pipelines			$	16,056			$	15,988
Non-regulated
	Production				4,518				4,080
	Marketing and Trading				2,718				2,404
	Power				2,348				3,599
	Field Services				121				686
		Total segment assets			25,761				26,757
Corporate					3,722				4,520
Discontinued operations					193				106
		Total consolidated assets		$	29,676			$	31,383

F-31

---

Table of Contents

14.	Investments in Unconsolidated Affiliates and Related Party Transactions

								Earnings								Earnings
								(Losses) from								(Losses) from
								Unconsolidated								Unconsolidated
								Affiliates								Affiliates
				Net
				Ownership
				Interest				Quarter Ended								Six Months Ended
								June 30,								June 30,
				June 30,
				2005				2005				2004				2005				2004
				(Percent)				(In millions)
Domestic:
	Enterprise Products Partners, L.P.(1)				—			$	—			$	—			$	183			$	—
	GulfTerra Energy Partners, L.P.(1)				—				—				29				—				63
	Citrus				50				18				21				33				28
	Midland Cogeneration Venture (MCV)(2)				44				(4	)			(2	)			(3	)			3
	Great Lakes Gas Transmission				50				14				16				31				36
	Other Domestic Investments				various				4				8				6				9
		Total domestic							32				72				250				139
Foreign:
	Asia Investments(3)				various				—				20				(68	)			41
	Central American Investments(4)				various				(55	)			—				(49	)			3
	PPN(5)				—				—				—				22				—
	Other Foreign Investments				various				4				6				16				2
		Total foreign							(51	)			26				(79	)			46
Total earnings from unconsolidated affiliates								$	(19	)		$	98			$	171			$	185

(1)	In January 2005, we sold all of these remaining interests to Enterprise and recognized a $183 million gain.
(2)	Our proportionate share of MCV’s losses, after intercompany eliminations, was $14 million during the second quarter of 2005. We did not record our remaining proportionate share of MCV’s losses as these losses resulted primarily from changes in the fair value of their derivative contracts, which we believe did not affect the value of our investment and would not be realized. We did not recognize substantially all of our proportionate share of MCV’s earnings, after intercompany eliminations, of approximately $58 million during the six months ended June 30, 2005 for the same reasons.
(3)	Consists of our investments in 12 power plants, including Korea Independent Energy Corporation, Meizhou Wan Generating, Habibullah Power and Saba Power Company. Our proportionate share of earnings reported by our Asia investments was $19 million and $44 million, for the quarter and six months ended June 30, 2005. We decreased our proportionate share of equity earnings for our Asia investments by $8 million and $19 million, for the quarter and six months ended June 30, 2005, to reflect the amount of earnings we believe will be realized.
(4)	Consists of our investments in 6 power plants. Our proportionate share of earnings reported by our Central American investments was $2 million and $8 million for the quarter and six months ended June 30, 2005. We recorded an impairment of $57 million during the quarter ended June 30, 2005 related to these investments.
(5)	We sold our interest in March 2005 and recorded a $22 million gain.

F-32

---

Table of Contents

			Quarter				Six Months
			Ended				Ended
Investment			June 30,				June 30,
			Pre-tax Gain (Loss)
			(In millions)
2005
Impairments
	Asia power investments(1)		$	(11	)		$	(93	)
	Central American power investments(1)			(57	)			(57	)
	Other foreign investments(1)			(16	)			(17	)
	Midland Cogeneration Venture(2)			(4	)			(4	)
Gain on sale of PPN				—				22
Gain on sale of Enterprise				—				183
Other				1				(2	)
			$	(87	)		$	32
2004
Impairments
	Milford power facility(1)		$	—			$	(2	)
	Power plants held for sale(1)			(19	)			(35	)
Other				1				(5	)
			$	(18	)		$	(42	)

(1)	We impaired our interests in these investments based on information received regarding the potential value we may receive when we sell the investments.
(2)	We impaired our investment in this power facility due to delays in the timing of expected cash flow receipts from this investment.

F-33

---

Table of Contents

			Quarter Ended June 30,												Six Months Ended June 30,
			MCV				Other Investments				Total				MCV				Other Investments				Total
							(In millions)												(In millions)
2005
Operating results data
	Revenues		$	62			$	342			$	404			$	127			$	625			$	752
	Operating expenses			69				208				277				34				384				418
	Income (loss) from continuing operations			(17	)			67				50				75				134				209
	Net income (loss)(1)			(17	) (2)			67				50				75				134				209
2004
Operating results data
	Revenues		$	69			$	558			$	627			$	139			$	1,072			$	1,211
	Operating expenses			60				359				419				113				691				804
	Income (loss) from continuing operations			(2	)			107				105				3				214				217
	Net income (loss)(1)			(2	)			112				110				3				216				219

(1)	Includes net income of $10 million and $7 million for the quarters ended June 30, 2005 and 2004, and $14 million and $21 million for the six months ended June 30, 2005 and 2004, related to our proportionate share of affiliates in which we hold a greater than 50 percent interest.
(2)	Includes $3 million of losses during the second quarter of 2005 and $17 million of earnings during the six months ended June 30, 2005 attributable to transactions with El Paso which were eliminated.

		Quarter Ended								Six Months
		June 30,								Ended June 30,
		2005				2004				2005				2004
		(In millions)
Operating revenue		$	43			$	68			$	92			$	118
Cost of sales			2				38				6				60
Reimbursement for operating expenses			—				34				1				65
Other income			5				4				9				9

	GulfTerra Energy Partners, L.P.

F-34

---

Table of Contents

F-35

---

Table of Contents

F-36

---

Table of Contents

	•	Implemented automated and manual controls for our primary financial system to monitor unauthorized password changes;
	•	Developed a segregation of duties matrix for our primary financial system that documents existing role assignments;
	•	Formalized and issued a company-wide account reconciliation policy;
	•	Implemented an account reconciliation monitoring tool that also allows for aggregation of unreconciled amounts;
	•	Provided additional training regarding the company-wide account reconciliation policy and appropriate use of the account reconciliation monitoring tool;
	•	Developed a process to improve communication between commercial and accounting personnel to allow for complete and timely communication of information to record non-routine transactions related to divestiture activity; and
	•	Implemented an accounting policy that requires a higher level of review of non-routine transactions.

	•	Performed an in-depth analysis of the company’s primary financial accounting system to examine existing functional access to identify any potentially incompatible duties.
	•	Enhanced the segregation of duties matrix for our primary financial accounting system based on the in-depth analysis of user access.
	•	Modified the primary financial accounting system to eliminate or modify potentially conflicting functionality.

F-37

---

Table of Contents

	•	Rewrote the computer programs for Marketing and Trading’s mark-to-market accounting system to significantly reduce the number of different combinations of user access and to modify remaining capabilities to eliminate potentially conflicting duties.
	•	Implemented a process to evaluate all new user access requests against segregation of duties matrices to ensure no new conflicts are created for our applications described above.
	•	Separated security administration rights from system update capabilities for our applications described above.
	•	Implemented monitoring procedures to monitor activities of security administration roles for our applications described above.
	•	Improved communications to establish the expectation that non-routine transactions must be communicated to ensure timely identification and thorough review of transactions.
	•	Established periodic business unit meetings to ensure relevant information related to non-routine transactions is captured and validated.
	•	Enhanced the Disclosure Committee Charter and meeting content to better address areas impacted by non-routine transactions, including discussion of impairments, significant estimates and legal and regulatory changes.
	•	Established a more rigorous top-down review of the financial statements at the management, corporate and Disclosure Committee levels.

F-38

---

Table of Contents

			Year Ended December 31,
			2004				2003				2002
			(Restated)				(Restated)				(Restated)
Operating revenues
	Pipelines		$	2,651			$	2,647			$	2,610
	Production			1,735				2,141				1,931
	Marketing and Trading			(508	)			(635	)			(1,324	)
	Power			795				1,176				1,672
	Field Services			1,362				1,529				2,029
	Corporate and eliminations			(161	)			(190	)			(37	)
				5,874				6,668				6,881
Operating expenses
	Cost of products and services			1,363				1,818				2,468
	Operation and maintenance			1,872				2,010				2,091
	Depreciation, depletion and amortization			1,088				1,176				1,159
	Loss on long-lived assets			1,108				860				181
	Western Energy Settlement			—				104				899
	Taxes, other than income taxes			253				295				254
				5,684				6,263				7,052
Operating income (loss)				190				405				(171	)
Earnings (losses) from unconsolidated affiliates				546				363				(214	)
Other income				193				203				197
Other expenses				(99	)			(202	)			(239	)
Interest and debt expense				(1,607	)			(1,791	)			(1,297	)
Distributions on preferred interests of consolidated subsidiaries				(25	)			(52	)			(159	)
Loss before income taxes				(802	)			(1,074	)			(1,883	)
Income taxes				31				(479	)			(641	)
Loss from continuing operations				(833	)			(595	)			(1,242	)
Discontinued operations, net of income taxes				(114	)			(1,279	)			(425	)
Cumulative effect of accounting changes, net of income taxes				—				(9	)			(208	)
Net loss			$	(947	)		$	(1,883	)		$	(1,875	)
Basic and diluted loss per common share
	Loss from continuing operations		$	(1.30	)		$	(0.99	)		$	(2.22	)
	Discontinued operations, net of income taxes			(0.18	)			(2.14	)			(0.76	)
	Cumulative effect of accounting changes, net of income taxes			—				(0.02	)			(0.37	)
	Net loss		$	(1.48	)		$	(3.15	)		$	(3.35	)
Basic and diluted average common shares outstanding				639				597				560

F-39

---

Table of Contents

					December 31,
					2004				2003
					(Restated)				(Restated)
ASSETS
Current assets
	Cash and cash equivalents				$	2,117			$	1,429
	Accounts and notes receivable
		Customer, net of allowance of $199 in 2004 and $273 in 2003				1,388				2,039
		Affiliates				133				189
		Other				188				245
	Inventory					168				181
	Assets from price risk management activities					601				706
	Margin and other deposits held by others					79				203
	Assets held for sale and from discontinued operations					181				2,538
	Restricted cash					180				590
	Deferred income taxes					418				593
	Other					179				210
			Total current assets			5,632				8,923
Property, plant and equipment, at cost
	Pipelines					19,418				18,563
	Natural gas and oil properties, at full cost					14,968				14,689
	Power facilities					1,550				1,660
	Gathering and processing systems					171				334
	Other					882				998
						36,989				36,244
	Less accumulated depreciation, depletion and amortization					18,177				18,049
			Total property, plant and equipment, net			18,812				18,195
Other assets
	Investments in unconsolidated affiliates					2,614				3,409
	Assets from price risk management activities					1,584				2,338
	Goodwill and other intangible assets, net					428				1,082
	Other					2,313				2,996
						6,939				9,825
			Total assets		$	31,383			$	36,943

F-40

---

Table of Contents

					December 31,
					2004				2003
					(Restated)				(Restated)
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Accounts payable
		Trade			$	1,052			$	1,552
		Affiliates				21				26
		Other				483				438
	Short-term financing obligations, including current maturities					955				1,457
	Liabilities from price risk management activities					852				734
	Western Energy Settlement					44				633
	Liabilities related to assets held for sale and discontinued operations					12				933
	Accrued interest					333				391
	Other					820				910
			Total current liabilities			4,572				7,074
Long-term financing obligations, less current maturities						18,241				20,275
Other
	Liabilities from price risk management activities					1,026				781
	Deferred income taxes					1,312				1,558
	Western Energy Settlement					351				415
	Other					2,076				2,047
						4,765				4,801
Commitments and contingencies
Securities of subsidiaries
	Securities of consolidated subsidiaries					367				447
Stockholders’ equity
	Common stock, par value $3 per share; authorized 1,500,000,000 shares; issued 651,064,508 shares in 2004 and 639,299,156 shares in 2003					1,953				1,917
	Additional paid-in capital					4,538				4,576
	Accumulated deficit					(2,809	)			(1,862	)
	Accumulated other comprehensive income (loss)					1				(40	)
	Treasury stock (at cost); 7,767,088 shares in 2004 and 7,097,326 shares in 2003					(225	)			(222	)
	Unamortized compensation					(20	)			(23	)
			Total stockholders’ equity			3,438				4,346
			Total liabilities and stockholders’ equity		$	31,383			$	36,943

F-41

---

Table of Contents

						Year Ended December 31,
						2004				2003				2002
						(Restated)(1)				(Restated)(1)				(Restated)(1)
Cash flows from operating activities
	Net loss					$	(947	)		$	(1,883	)		$	(1,875	)
	Less loss from discontinued operations, net of income taxes						(114	)			(1,279	)			(425	)
	Net loss before discontinued operations						(833	)			(604	)			(1,450	)
	Adjustments to reconcile net loss to net cash from operating activities
		Depreciation, depletion and amortization					1,088				1,176				1,159
		Western Energy Settlement					—				94				899
		Deferred income tax benefit					(32	)			(614	)			(685	)
		Cumulative effect of accounting changes					—				9				208
		Loss on long-lived assets					1,108				785				181
		Losses (earnings) from unconsolidated affiliates, adjusted for cash distributions					(211	)			(17	)			521
		Other non-cash income items					447				399				255
		Asset and liability changes
			Accounts and notes receivable				471				2,552				(629	)
			Inventory				9				76				248
			Change in non-hedging price risk management activities, net				191				85				1,074
			Accounts payable				(295	)			(2,127	)			(114	)
			Broker and other margins on deposit with others				121				623				(257	)
			Broker and other margins on deposit with us				(24	)			32				(647	)
			Western Energy Settlement liability				(626	)			—				—
			Other asset and liability changes
				Assets			(20	)			(267	)			54
				Liabilities			(301	)			102				(139	)
			Cash provided by continuing activities				1,093				2,304				678
			Cash provided by (used in) discontinued activities				223				25				(242	)
				Net cash provided by operating activities			1,316				2,329				436
Cash flows from investing activities
	Additions to property, plant and equipment						(1,782	)			(2,328	)			(3,243	)
	Purchases of interests in equity investments						(34	)			(33	)			(299	)
	Cash paid for acquisitions, net of cash acquired						(47	)			(1,078	)			45
	Net proceeds from the sale of assets and investments						1,927				2,458				2,779
	Net change in restricted cash						578				(534	)			(260	)
	Net change in notes receivable from affiliates						120				(43	)			4
	Other						(1	)			—				22
			Cash provided by (used in) continuing activities				761				(1,558	)			(952	)
			Cash provided by (used in) discontinued activities				1,142				369				(303	)
				Net cash provided by (used in) investing activities			1,903				(1,189	)			(1,255	)

(1)	Only individual line items in cash flows from operating activities have been restated. Total cash flows from continuing operating activities, investing activities, and financing activities, as well as discontinued operations were unaffected by our restatements.

F-42

---

Table of Contents

					Year Ended December 31,
					2004				2003				2002
					(Restated)(1)				(Restated)(1)				(Restated)(1)
Cash flows from financing activities
	Net proceeds from issuance of long-term debt					1,300				3,633				4,294
	Payments to retire long-term debt and other financing obligations					(2,306	)			(2,824	)			(1,777	)
	Net borrowings/(repayments) under revolving and other short-term credit facilities					(850	)			(650	)			154
	Net proceeds from issuance of notes payable					—				84				—
	Repayment of notes payable					(214	)			(8	)			(94	)
	Payments to minority interest and preferred interest holders					(35	)			(1,277	)			(861	)
	Issuances of common stock					73				120				1,053
	Dividends paid					(101	)			(203	)			(470	)
	Other					(33	)			(177	)			(476	)
	Contributions from (distributions to) discontinued operations					1,000				394				(1,106	)
		Cash provided by (used in) continuing activities				(1,166	)			(908	)			717
		Cash provided by (used in) discontinued activities				(1,365	)			(394	)			555
			Net cash provided by (used in) financing activities			(2,531	)			(1,302	)			1,272
Change in cash and cash equivalents						688				(162	)			453
	Less change in cash and cash equivalents related to discontinued operations					—				—				10
	Change in cash and cash equivalents from continuing operations					688				(162	)			443
Cash and cash equivalents
	Beginning of period					1,429				1,591				1,148
	End of period				$	2,117			$	1,429			$	1,591
Supplemental Cash Flow Information:
	Interest paid, net of amounts capitalized				$	1,536			$	1,657			$	1,291
	Income tax payments (refunds)					68				23				(106	)

(1)	Only individual line items in cash flows from operating activities have been restated. Total cash flows from continuing operating activities, investing activities, and financing activities, as well as discontinued operations were unaffected by our restatements.

F-43

---

Table of Contents

				For the Years Ended December 31,
				2004								2003								2002
				(Restated)								(Restated)								(Restated)
				Shares				Amount				Shares				Amount				Shares				Amount
Common stock, $3.00 par:
	Balance at beginning of year				639			$	1,917				605			$	1,816				538			$	1,615
	Equity offering				—				—				—				—				52				155
	Exchange of equity security units				—				—				15				45				—				—
	Western Energy Settlement equity offerings				9				26				18				53				—				—
	Other, net				3				10				1				3				15				46
		Balance at end of year			651				1,953				639				1,917				605				1,816
Additional paid-in capital:
	Balance at beginning of year								4,576								4,444								3,130
	Compensation related issuances								15								8								57
	Tax effects of equity plans								5								(26	)							15
	Equity offering								—								—								846
	Exchange of equity security units								—								189								—
	Conversion of FELINE PRIDESSM								—								—								423
	Western Energy Settlement equity offerings								46								67								—
	Dividends ($0.16 per share)								(104	)							(96	)							—
	Other								—								(10	)							(27	)
		Balance at end of year							4,538								4,576								4,444
Accumulated deficit (Restated):
	Balance at beginning of year								(1,862	)							21								2,387
	Net loss								(947	)							(1,883	)							(1,875	)
	Dividends ($0.87 per share)								—								—								(491	)
		Balance at end of year							(2,809	)							(1,862	)							21
Accumulated other comprehensive income (loss)
	Balance at beginning of year								(40	)							(235	)							(18	)
	Other comprehensive income (loss)								41								195								(217	)
		Balance at end of year							1								(40	)							(235	)
Treasury stock, at cost:
	Balance at beginning of year				(7	)			(222	)			(6	)			(201	)			(8	)			(261	)
	Compensation related issuances				—				9				—				—				3				79
	Other				(1	)			(12	)			(1	)			(21	)			(1	)			(19	)
		Balance at end of year			(8	)			(225	)			(7	)			(222	)			(6	)			(201	)
Unamortized compensation:
	Balance at beginning of year								(23	)							(95	)							(187	)
	Issuance of restricted stock								(28	)							(1	)							(36	)
	Amortization of restricted stock								23								60								73
	Forfeitures of restricted stock								9								15								15
	Other								(1	)							(2	)							40
		Balance at end of year							(20	)							(23	)							(95	)
Total stockholders’ equity					643			$	3,438				632			$	4,346				599			$	5,750

F-44

---

Table of Contents

					Year Ended December 31,
					2004				2003				2002
					(Restated)				(Restated)				(Restated)
Net loss					$	(947	)		$	(1,883	)		$	(1,875	)
	Foreign currency translation adjustments (net of income tax of $38 in 2004 and $51 in 2003)					11				108				(20	)
	Minimum pension liability accrual (net of income tax of $11 in 2004, $7 in 2003 and $20 in 2002)					(22	)			11				(35	)
	Net gains (losses) from cash flow hedging activities:
		Unrealized mark-to-market gains (losses) arising during period (net of income tax of $8 in 2004, $50 in 2003 and $53 in 2002)				22				101				(90	)
		Reclassification adjustments for changes in initial value to settlement date (net of income tax of $8 in 2004, $11 in 2003 and $40 in 2002)				30				(25	)			(73	)
	Other					—				—				1
			Other comprehensive income (loss)			41				195				(217	)
Comprehensive loss					$	(906	)		$	(1,688	)		$	(2,092	)

F-45

---

Table of Contents

				For the Year Ended
				December 31, 2002
				As				As
				Reported				Restated
				(In millions except per
				common share
				amounts)
Income Statement:
	Earnings (losses) from unconsolidated affiliates			$	(226	)		$	(214	)
	Income taxes (benefit)				(621	)			(641	)
	Cumulative effect of accounting changes, net of income taxes				(54	)			(208	)
	Net loss				(1,753	)			(1,875	)
	Basic and diluted net loss per share:
		Cumulative effect of accounting changes, net of income taxes			(0.10	)			(0.37	)
		Net loss			(3.13	)			(3.35	)

F-46

---

Table of Contents

			As of
			December 31,
			2002								2003
			As				As				As				As
			Reported				Restated				Reported				Restated
Balance Sheet:
	Investments in unconsolidated affiliates		$	4,891			$	4,749			$	3,551			$	3,409
	Non-current deferred income tax liabilities			2,094				2,074				1,571				1,551
	Stockholders’ equity			5,872				5,750				4,474				4,352

F-47

---

Table of Contents

					For the Year Ended December 31,
					2004								2003
					As				As				As				As				As Further
					Reported				Restated				Reported				Restated(1)				Restated(2)
					(In millions, except per share amounts)
Income Statement:
	Loss on long-lived assets				$	1,092			$	1,108			$	860			$	860			$	860
	Operating income					206				190				405				405				405
	Earnings from unconsolidated affiliates					559				546				363				363				363
	Other income					189				193				203				203				203
	Loss before income taxes					(777	)			(802	)			(1,074	)			(1,074	)			(1,074	)
	Income taxes					25				31				(551	)			(469	)			(479	)
	Loss from continuing operations					(802	)			(833	)			(523	)			(605	)			(595	)
	Discontinued operations, net of income taxes					(146	)			(114	)			(1,396	)			(1,314	)			(1,279	)
	Net loss					(948	)			(947	)			(1,928	)			(1,928	)			(1,883	)
	Basic and diluted loss per share:
		Loss from continuing operations			$	(1.25	)		$	(1.30	)		$	(0.87	)		$	(1.01	)		$	(0.99	)
		Discontinued operations, net of income taxes				(0.23	)			(0.18	)			(2.34	)			(2.20	)			(2.14	)
		Cumulative effect of accounting changes, net of income taxes				—				—				(0.02	)			(0.02	)			(0.02	)
			Net loss		$	(1.48	)		$	(1.48	)		$	(3.23	)		$	(3.23	)		$	(3.15	)
Statement of Comprehensive Income
	Foreign currency translation adjustments				$	7			$	11			$	159			$	159			$	108
	Other comprehensive income					37				41				246				246				195

(1)	Amounts restated reflect the effects of reclassifying deferred income tax benefits from continuing operations to discontinued operations as originally reported in our Form 10-K/ A (Amendment No. 1) filed on April 8, 2005. This restatement is further described on page F-47 under the heading Income Taxes.
(2)	Amounts further restated reflect the effects of adjusting CTA and related income taxes on certain of our foreign investments with CTA balances as further described on page F-47 under the heading Cumulative Foreign Currency Translation Adjustments (CTA).

			As of December 31,
			2004								2003
			As Reported				As Restated				As Reported				As Restated
			(In millions)
Balance Sheet:
	Deferred income tax assets, current		$	418			$	418			$	592			$	593
	Deferred income tax liabilities, non-current			1,311				1,312				1,551				1,558
	Accumulated deficit			(2,855	)			(2,809	)			(1,907	)			(1,862	)
	Accumulated other comprehensive income (loss)			48				1				11				(40	)
	Total stockholders’ equity			3,439				3,438				4,352				4,346

F-48

---

Table of Contents

F-49

---

Table of Contents

Type			Method				Depreciable Lives
							(In years)
Regulated interstate systems
	SFAS No. 71			Composite (1)				1-63
	Non-SFAS No. 71			Composite (1)				1-64
Non-regulated systems
	Transmission and storage facilities			Straight-line				35
	Power facilities			Straight-line				3-30
	Gathering and processing systems			Straight-line				3-33
	Buildings and improvements			Straight-line				5-40
	Office and miscellaneous equipment			Straight-line				1-10

(1)

For our regulated interstate systems, we use the composite (group) method to depreciate property, plant and equipment. Under this method, assets with similar useful lives and other characteristics are grouped and depreciated as one asset. We apply the depreciation rate approved in our rate settlements to the total cost of the group until its net book value equals its salvage value. We re-evaluate depreciation rates each time we redevelop our transportation rates when we file with the FERC for an increase or decrease in rates.

F-50

---

Table of Contents

F-51

---

Table of Contents

							Field								Corporate &
			Pipelines				Services				Power				Other				Total
			(In millions)
Balances as of January 1, 2003			$	413			$	483			$	3			$	205			$	1,104
	Additions to goodwill			—				—				22				—				22
	Impairments of goodwill			—				—				(22	)			(163	)			(185	)
	Dispositions of goodwill			—				—				—				(42	)			(42	)
	Other changes			—				(3	)			—				—				(3	)
Balances as of December 31, 2003				413				480				3				—				896
	Impairments of goodwill			—				(480	)			—				—				(480	)
	Other changes			—				—				(3	)			—				(3	)
Balances as of December 31, 2004			$	413			$	—			$	—			$	—			$	413

F-52

---

Table of Contents

F-53

---

Table of Contents

	•	derivatives entered into to hedge the commodity, interest rate and foreign currency exposures primarily on our natural gas and oil production and our long-term debt;
	•	derivatives related to our power contract restructuring business; and
	•	derivatives related to our trading activities that we historically entered into with the objective of generating profits from exposure to shifts or changes in market prices.

F-54

---

Table of Contents

	Income Taxes

	Foreign Currency Transactions and Translation

F-55

---

Table of Contents

	Treasury Stock

	Stock-Based Compensation

			Year Ended December 31,
			2004				2003				2002
			(Restated)				(Restated)				(Restated)
			(In millions, except per common
			share amounts)
Net loss, as reported			$	(947	)		$	(1,883	)		$	(1,875	)
Add: Stock-based employee compensation expense included in reported net loss, net of taxes				14				38				47
Deduct: Total stock-based employee compensation determined under fair value-based method for all awards, net of taxes				(35	)			(88	)			(169	)
Pro forma net loss			$	(968	)		$	(1,933	)		$	(1,997	)
Loss per share:
	Basic and diluted, as reported		$	(1.48	)		$	(3.15	)		$	(3.35	)
	Basic and diluted, pro forma		$	(1.51	)		$	(3.24	)		$	(3.57	)

	Accounting for Asset Retirement Obligations

F-56

---

Table of Contents

		2004				2003
		(In millions, except
		for rates)
Current asset retirement liability		$	28			$	26
Non-current asset retirement liability(1)		$	244			$	192
Discount rates			6-8	%			8- 10	%
Inflation rates			2.5	%			2.5	%

(1)	We estimate that approximately 61 percent of our non-current asset retirement liability as of December 31, 2004 will be settled in the next five years.

			2004				2003
Net asset retirement liability at January 1			$	218			$	209
Liabilities settled				(34	)			(39	)
Accretion expense				24				22
Liabilities incurred				34				13
Changes in estimate				30				13
	Net asset retirement liability at December 31		$	272			$	218

	Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity

F-57

---

Table of Contents

	New Accounting Pronouncements Issued But Not Yet Adopted

F-58

---

Table of Contents

		(Unaudited)
Revenues		$	223
Operating income			(119	)
Net income			19
Basic and diluted earnings per share		$	0.03

Total assets
	Current assets			$	312
	Assets from price risk management activities, current				190
	Investments in unconsolidated affiliates				1,366
	Property, plant and equipment, net				519
	Assets from price risk management activities, non-current				1,089
	Goodwill				22
	Other assets				467
		Total assets			3,965
Total liabilities
	Current liabilities				908
	Liabilities from price risk management activities, current				19
	Long-term debt, less current maturities(1)				1,433
	Liabilities from price risk management activities, non-current				34
	Other liabilities				351
		Total liabilities			2,745
Net assets				$	1,220

(1)	This debt is recourse only to the project, contract or plant to which it relates.

F-59

---

Table of Contents

Fair value of assets acquired
	Note and interest receivable			$	122
	Investments in unconsolidated affiliates				892
	Other assets				3
		Total assets			1,017
Fair value of liabilities assumed
	Note and interest payable				967
		Total liabilities			967
Net assets acquired				$	50

		Increase/(Decrease)
		(In millions)
Restricted cash		$	34
Accounts and notes receivable from affiliates			(54	)
Investments in unconsolidated affiliates			(5	)
Property, plant, and equipment, net			37
Other current and non-current assets			(15	)
Long-term financing obligations			15
Other current and non-current liabilities			(4	)
Minority interest of consolidated subsidiaries			(14	)

F-60

---

Table of Contents

		2004				2003
		(In millions)
Operating revenues		$	(36	)		$	75
Current liabilities from price risk management activities			(20	)			(28	)
Non-current liabilities from price risk management activities			(29	)			(6	)

F-61

---

Table of Contents

3.	Divestitures

	Sales of Assets and Investments

			2004				2003				2002
			(In millions)
Regulated
	Pipelines		$	59			$	145			$	303
Non-regulated
	Production			24				673				1,248
	Power			884				768				90
	Field Services			1,029				753				1,513
Other
	Corporate			16				149				—
Total continuing(1)				2,012				2,488				3,154
Discontinued				1,295				808				177
Total			$	3,307			$	3,296			$	3,331

(1)

Proceeds exclude returns of invested capital and cash transferred with the assets sold and include costs incurred in preparing assets for disposal. These items decreased our sales proceeds by $85 million, $30 million, and $25 million for the years ended December 31, 2004, 2003 and 2002. Proceeds also exclude any non-cash consideration received in these sales, such as the receipt of $350 million of Series C units in GulfTerra from the sale of assets in our Field Services segment in 2002.

F-62

---

Table of Contents

		2004		2003		2002
Pipelines		• Australian pipelines • Interest in gathering systems		• 2.1% interest in Alliance pipeline • Equity interest in Portland Natural Gas Transmission System • Horsham pipeline in Australia		• Natural gas and oil properties located in TX, KS, and OK • 12.3% equity interest in Alliance pipeline • Typhoon natural gas pipeline
Production		• Brazilian exploration and production acreage		• Natural gas and oil properties in NM, TX, LA, OK and the Gulf of Mexico		• Natural gas and oil properties located in TX, CO and Utah
Power		• Utility Contract Funding • 31 domestic power plants and several turbines		• Interest in CE Generation L.L.C. • Mt. Carmel power plant • CAPSA/CAPEX investments • East Coast Power		• 40% equity interest in Samalayuca Power II power project in Mexico
Field Services		• Remaining general partnership interest, common units and Series C units in GulfTerra • South TX processing plants • Dauphin Island and Mobile Bay investments		• Gathering systems located in WY • Midstream assets in the north LA and Mid-Continent regions • Common and Series B preference units in GulfTerra • 50% of GulfTerra General Partnership		• TX & NM midstream assets • Dragon Trail gas processing plant • San Juan basin gathering, treating and processing assets • Gathering facilities in Utah
Corporate		• Aircraft		• Aircraft • Enerplus Global Energy Management Company and its financial operations • EnCap funds management business and its investments		• None
Discontinued		• Natural gas and oil production properties in Canada and other international production assets • Aruba and Eagle Point refineries and other petroleum assets		• Corpus Christi refinery • Florida petroleum terminals • Louisiana lease crude • Coal reserves • Canadian natural gas and oil properties • Asphalt facilities		• Coal reserves and properties and petroleum assets • Natural gas and oil properties located in Western Canada

	•	Remaining 9.9% membership interest in the general partner of Enterprise and approximately 13.5 million units in Enterprise for $425 million;
	•	Interests in Cedar Brakes I and II for $94 million;
	•	Interest in a paraxylene plant for $74 million;
	•	Interest in a natural gas gathering system and processing facility for $75 million;
	•	Pipeline facilities for $31 million;
	•	Interest in an Indian power plant for $20 million;
	•	MTBE processing facility for $5 million;
	•	Eagle Point power facility for $3 million; and
	•	Interest in the Rensselaer power facility and its obligations.

F-63

---

Table of Contents

Assets Held for Sale
Current assets			$	46
Investments in unconsolidated affiliates				480
Property, plant and equipment, net				477
Other assets				136
	Total assets		$	1,139
Current liabilities			$	54
Long-term debt, less current maturities				169
Other liabilities				13
	Total liabilities		$	236

	Discontinued Operations

F-64

---

Table of Contents

						International
						Natural Gas
						and Oil
		Petroleum				Production				Coal
		Markets				Operations				Mining				Total
		(In millions)
Operating Results Data
Year Ended December 31, 2004 (Restated)(1)
Revenues		$	787			$	31			$	—			$	818
Costs and expenses			(839	)			(53	)			—				(892	)
Loss on long-lived assets			(36	)			(22	)			—				(58	)
Other income			15				—				—				15
Interest and debt expense			(3	)			1				—				(2	)
Loss before income taxes			(76	)			(43	)			—				(119	)
Income taxes			2				(7	)			—				(5	)
Loss from discontinued operations, net of income taxes		$	(78	)		$	(36	)		$	—			$	(114	)

Year Ended December 31, 2003 (Restated)(1)
Revenues		$	5,652			$	88			$	27			$	5,767
Costs and expenses			(5,793	)			(129	)			(13	)			(5,935	)
Loss on long-lived assets			(1,404	)			(89	)			(9	)			(1,502	)
Other income			(10	)			—				1				(9	)
Interest and debt expense			(11	)			4				—				(7	)
Gain (loss) before income taxes			(1,566	)			(126	)			6				(1,686	)
Income taxes			(262	)			(150	)			5				(407	)
Gain (loss) from discontinued operations, net of income taxes		$	(1,304	)		$	24			$	1			$	(1,279	)
Year Ended December 31, 2002
Revenues		$	4,788			$	71			$	309			$	5,168
Costs and expenses			(4,916	)			(172	)			(327	)			(5,415	)
Loss on long-lived assets			(97	)			(4	)			(184	)			(285	)
Other income			20				—				5				25
Interest and debt expense			(12	)			4				—				(8	)
Loss before income taxes			(217	)			(101	)			(197	)			(515	)
Income taxes			16				(33	)			(73	)			(90	)
Loss from discontinued operations, net of income taxes		$	(233	)		$	(68	)		$	(124	)		$	(425	)

(1)	For 2004, amounts related to Petroleum Markets and Canadian Natural Gas and Oil Production Operations were restated. For 2003, amounts related to Canadian Natural Gas and Oil Production Operations were restated. See Note 1, on page F-46, to the consolidated financial statements for a further discussion of the restatements.

F-65

---

Table of Contents

									International
									Natural Gas
									and Oil
					Petroleum				Production
					Markets				Operations				Total
					(In millions)
Financial Position Data
	December 31, 2004
	Assets of discontinued operations
		Accounts and notes receivable			$	39			$	2			$	41
		Inventory				8				—				8
		Other current assets				3				1				4
		Property, plant and equipment, net				14				6				20
		Other non-current assets				33				—				33
			Total assets		$	97			$	9			$	106
	Liabilities of discontinued operations
		Accounts payable			$	5			$	1			$	6
		Other current liabilities				3				—				3
		Other non-current liabilities				3				—				3
			Total liabilities		$	11			$	1			$	12
	December 31, 2003
	Assets of discontinued operations
		Accounts and notes receivable			$	259			$	22			$	281
		Inventory				385				3				388
		Other current assets				131				8				139
		Property, plant and equipment, net				521				399				920
		Other non-current assets				70				6				76
			Total assets		$	1,366			$	438			$	1,804
	Liabilities of discontinued operations
		Accounts payable			$	172			$	39			$	211
		Other current liabilities				86				—				86
		Long-term debt				374				—				374
		Other non-current liabilities				26				3				29
			Total liabilities		$	658			$	42			$	700

4.	Restructuring Costs

F-66

---

Table of Contents

										Marketing
										and								Field				Corporate
		Pipelines				Production				Trading				Power				Services				and Other				Total
		(In millions)
2004
Employee severance, retention and transition costs		$	5			$	14			$	2			$	5			$	1			$	11			$	38
Office relocation and consolidation			—				—				—				—				—				80				80
		$	5			$	14			$	2			$	5			$	1			$	91			$	118
2003
Employee severance, retention and transition costs		$	2			$	6			$	12			$	5			$	4			$	47			$	76
Contract termination and other costs			—				—				4				—				—				44				48
		$	2			$	6			$	16			$	5			$	4			$	91			$	124
2002
Employee severance, retention and transition costs		$	1			$	—			$	10			$	14			$	1			$	11			$	37
Transaction costs			—				—				—				—				—				40				40
		$	1			$	—			$	10			$	14			$	1			$	51			$	77

F-67

---

Table of Contents

				2004								2002
				(Restated)				2003				(Restated)
				(In millions)
Net realized (gain) loss				$	(16	)		$	69			$	(259	)
Asset impairments
	Power
		Domestic assets and restructured power contract entities			397				147				—
		International assets			213				—				—
		Turbines			1				33				162
	Field Services
		South Texas processing assets			—				167				—
		North Louisiana gathering facility			—				—				66
		Indian Springs processing assets			13				—				—
		Goodwill impairment			480				—				—
		Other			11				4				—
	Production
		Other			8				10				—
	Corporate
		Telecommunications assets			—				396				168
		Other			1				34				44
		Total asset impairments			1,124				791				440
	Loss on long-lived assets				1,108				860				181
	(Gain) loss on investments in unconsolidated affiliates (1)				(124	)			176				612
	Loss on assets and investments			$	984			$	1,036			$	793

(1)	See Note 22, on page F-110, for a further description of these gains and losses.

	Net Realized (Gain) Loss

F-68

---

Table of Contents

	Asset Impairments

				2004
				(Restated)				2003				2002
				(In millions)
Other Income
	Interest income			$	93			$	83			$	84
	Allowance for funds used during construction				23				19				7
	Development, management and administrative services fees on power projects from affiliates				21				18				21
	Re-application of SFAS No. 71 (CIG and WIC)				—				18				—
	Net foreign currency gain				13				12				—
	Favorable resolution of non-operating contingent obligations				—				9				38
	Gain on early extinguishment of debt				—				—				21
	Other				43				44				26
		Total		$	193			$	203			$	197

F-69

---

Table of Contents

				2004
				(Restated)				2003				2002
				(In millions)
Other Expenses
	Net foreign currency losses(1)			$	26			$	112			$	91
	Loss on early extinguishment of debt				12				37				—
	Loss on exchange of equity security units				—				12				—
	Impairment of cost basis investment(2)				—				5				56
	Minority interest in consolidated subsidiaries				41				1				58
	Other				20				35				34
		Total		$	99			$	202			$	239

(1)	Amounts in 2004, 2003 and 2002 were primarily related to losses on our Euro-denominated debt.
(2)	We impaired our investment in our Costañera power plant in 2002.

		2004				2003				2002
		(In millions)
U.S.		$	(721	)		$	(1,330	)		$	(2,282	)
Foreign			(81	)			256				399
		$	(802	)		$	(1,074	)		$	(1,883	)

				2004				2003				2002
				(In millions)
Current
	Federal			$	(15	)		$	36			$	(15	)
	State				39				58				27
	Foreign				39				41				32
					63				135				44
Deferred
	Federal				(57	)			(566	)			(679	)
	State				(5	)			(55	)			(11	)
	Foreign				30				7				5
					(32	)			(614	)			(685	)
		Total income taxes		$	31			$	(479	)		$	(641	)

F-70

---

Table of Contents

			2004				2003				2002
			(In millions, except rates)
Income taxes at the statutory federal rate of 35%			$	(281	)		$	(376	)		$	(659	)
Increase (decrease)
	Abandonments and sales of foreign investments			14				(53	)			—
	Valuation allowances			18				(57	)			44
	Foreign income taxed at different rates			152				(21	)			6
	Earnings from unconsolidated affiliates where we anticipate receiving dividends			(18	)			(13	)			(18	)
	Non-deductible dividends on preferred stock of subsidiaries			9				10				10
	State income taxes, net of federal income tax effect			5				5				2
	Non-conventional fuel tax credits			—				—				(11	)
	Non-deductible goodwill impairments			139				29				—
	Other			(7	)			(3	)			(15	)
Income taxes			$	31			$	(479	)		$	(641	)
Effective tax rate				(4	)%			45	%			34	%

					2004				2003
					(In millions)
Deferred tax liabilities
	Property, plant and equipment				$	2,590			$	2,112
	Investments in unconsolidated affiliates					410				757
	Employee benefits and deferred compensation					93				126
	Price risk management activities					71				—
	Regulatory and other assets					163				193
			Total deferred tax liability			3,327				3,188
Deferred tax assets
	Net operating loss and tax credit carryovers
		U.S. federal				1,194				814
		State				174				146
		Foreign				35				18
	Western Energy Settlement					144				400
	Environmental liability					174				206
	Price risk management activities					—				136
	Debt					79				105
	Inventory					85				91
	Deferred federal tax on deferred state income tax liability					59				75
	Allowance for doubtful accounts					99				75
	Lease liabilities					53				—
	Other					388				235
	Valuation allowance					(51	)			(9	)
			Total deferred tax asset			2,433				2,292
Net deferred tax liability					$	894			$	896

F-71

---

Table of Contents

		Carryover Period
		2005				2006-2010				2011-2015				2016-2024				Total
		(In millions)
U.S. federal net operating loss		$	—			$	7			$	—			$	3,113			$	3,120
State net operating loss			8				849				412				987				2,256

F-72

---

Table of Contents

		2004								2003
		Carrying								Carrying
		Amount				Fair Value				Amount				Fair Value
		(In millions)
Long-term financing obligations, including current maturities		$	19,189			$	19,829			$	21,724			$	21,166
Commodity-based price risk management derivatives			68				68				1,406				1,406
Interest rate and foreign currency hedging derivatives			239				239				123				123
Investments			6				6				12				12

F-73

---

Table of Contents

				2004				2003
				(In millions)
Net assets (liabilities)
	Derivatives designated as hedges(1)			$	(536	)		$	(31	)
	Derivatives from power contract restructuring activities (2)				665				1,925
	Other commodity-based derivative contracts(1)				(61	)			(488	)
		Total commodity-based derivatives			68				1,406
	Interest rate and foreign currency hedging derivatives				239				123
		Net assets from price risk management activities(3)		$	307			$	1,529

(1)	In December 2004, we designated other commodity-based derivative contracts with a fair value loss of $592 million as hedges of our 2005 and 2006 natural gas production. As a result, we reclassified this amount to derivatives designated as hedges beginning in the fourth quarter of 2004.
(2)	Includes derivative contracts with a fair value of $596 million as of December 31, 2004 that we sold in connection with the sale of Cedar Brakes I and II in the first quarter of 2005, and $942 million as of December 31, 2003 that we sold in connection with the sales of UCF and Mohawk River Funding IV in 2004.
(3)	Included in both current and non-current assets and liabilities from price risk management activities on the balance sheet.

F-74

---

Table of Contents

			Accumulated
			Other
			Comprehensive								Estimated
			Income (Loss)								Income (Loss)				Final
											Reclassification				Termination
			2004				2003				in 2005(1)				Date
Commodity cash flow hedges
	Held by consolidated entities		$	(23	)		$	(72	)		$	24				2012
	Held by unconsolidated affiliates			(8	)			13				4				2006
	Total commodity cash flow hedges			(31	)			(59	)			28
Foreign currency cash flow hedges
	Fixed rate(2)			81				58				81				2005
	Undesignated(3)			(8	)			(9	)			(4	)			2009
	Total foreign currency cash flow hedges			73				49				77
	Total(4)		$	42			$	(10	)		$	105

(1)	Reclassifications occur upon the physical delivery of the hedged commodity and the corresponding expiration of the hedge or if the forecasted transaction is no longer probable.
(2)	Substantially all of these amounts were reclassified into income with the repurchase of approximately €528 million of debt in March 2005.
(3)	In December 2002, we removed the hedging designation on these derivatives related to our Euro-denominated debt.
(4)	Accumulated other comprehensive income (loss) also includes $5 million and $(6) million of net cumulative currency translation adjustments and $(46) million and $(24) million of additional minimum pension liability as of December 31, 2004 and 2003. All amounts are net of taxes.

F-75

---

Table of Contents

	Power Contract Restructuring Activities

F-76

---

Table of Contents

			Assets from				Liabilities from				Property, Plant												Increase
			Price Risk				Price Risk				and Equipment												(Decrease)
			Management				Management				and Intangible				Operating				Operating				in Minority
			Activities				Activities				Assets				Revenues				Expenses				Interest(1)
Initial gain on restructured contracts			$	978			$	—			$	—			$	1,118			$	—			$	172
Write-down of power plants and intangibles and other fees				—				—				(352	)			—				476				(109	)
Change in value of restructured contracts during 2002				8				—				—				(96	)			—				(20	)
Change in value of third-party wholesale power supply contracts				—				18				—				(18	)			—				(3	)
Purchase of power under power supply contracts				—				—				—				—				47				(11	)
Sale of power under restructured contracts				—				—				—				111				—				28
	Total		$	986			$	18			$	(352	)		$	1,115			$	523			$	57

(1)	In our restructuring activities, third-party owners also held ownership interests in the plants and were allocated a portion of the income or loss.

	Other Commodity-Based Derivatives

	Credit Risk

F-77

---

Table of Contents

			Net Financial Instrument Asset Exposure
							Below				Not
Counterparty			Investment Grade(1)				Investment Grade(1)				Rated(1)				Total
			(In millions)
December 31, 2004
Energy marketers			$	440			$	44			$	35			$	519
Natural gas and electric utilities				424				—				91				515
Other				245				—				7				252
	Net financial instrument assets (2)			1,109				44				133				1,286
	Collateral held by us			(349	)			(39	)			(81	)			(469	)
	Net exposure from financial instrument assets		$	760			$	5			$	52			$	817
December 31, 2003
Energy marketers			$	425			$	43			$	53			$	521
Natural gas and electric utilities				1,755				—				78				1,833
Other				106				1				75				182
	Net financial instrument assets (2)			2,286				44				206				2,536
	Collateral held by us			(132	)			(10	)			(83	)			(225	)
	Net exposure from financial instrument assets		$	2,154			$	34			$	123			$	2,311

(1)	“Investment Grade” and “Below Investment Grade” are determined using publicly available credit ratings. “Investment Grade” includes counterparties with a minimum Standard & Poor’s rating of BBB- or Moody’s rating of Baa3. “Below Investment Grade” includes counterparties with a public credit rating that do not meet the criteria of “Investment Grade”. “Not Rated” includes counterparties that are not rated by any public rating service.
(2)	Net asset exposure from financial instrument assets primarily relates to our assets and liabilities from price risk management activities. These exposures have been prepared by netting assets against liabilities on counterparties where we have a contractual right to offset. The positions netted include both current and non-current amounts and do not include amounts already billed or delivered under the derivative contracts, which would be netted against these exposures.

F-78

---

Table of Contents

			2004				2003
			(In millions)
Materials and supplies and other			$	130			$	145
NGL and natural gas in storage				38				36
	Total current inventory		$	168			$	181

			2004				2003
			(In millions)
Dark fiber			$	—			$	5
Turbines				76				98
	Total non-current inventory		$	76			$	103

Description				2004				2003
				(In millions)
Current regulatory assets(1)				$	3			$	2
Non-current regulatory assets
	Grossed-up deferred taxes on capitalized funds used during construction(1)				85				77
	Postretirement benefits(1)				30				32
	Unamortized net loss on reacquired debt(1)				23				26
	Under-collected state income tax(1)				7				4
	Other(1)				10				4
		Total non-current regulatory assets			155				143
		Total regulatory assets		$	158			$	145
Current regulatory liabilities
	Cashout imbalance settlement(1)			$	9			$	9
	Other				—				2
					9				11

F-79

---

Table of Contents

Description				2004				2003
				(In millions)
Non-current regulatory liabilities
	Environmental liability(1)				97				87
	Cost of removal of offshore assets				50				51
	Property and plant depreciation				35				28
	Postretirement benefits(1)				13				11
	Plant regulatory liability(1)				11				11
	Excess deferred income taxes				11				10
	Other				11				5
		Total non-current regulatory liabilities			228				203
		Total regulatory liabilities		$	237			$	214

(1)	Some of these amounts are not included in our rate base on which we earn a current return.

				2004				2003
				(In millions)
Other current assets
	Prepaid expenses			$	132			$	146
	Other				47				64
		Total		$	179			$	210
Other non-current assets
	Pension assets (Note 18, page F-99)			$	933			$	962
	Notes receivable from affiliates				287				349
	Restricted cash (Note 1, page F-46)				180				349
	Unamortized debt expenses				192				246
	Regulatory assets (Note 12, page F-79)				155				143
	Long-term receivables				343				108
	Notes receivable				46				113
	Turbine inventory (Note 11, page F-79)				76				98
	Other investments				48				60
	Assets of discontinued operations				—				405
	Other				53				163
		Total		$	2,313			$	2,996

F-80

---

Table of Contents

				2004				2003
				(In millions)
Other current liabilities
	Accrued taxes, other than income			$	136			$	156
	Broker margin and other amounts on deposit with us				131				155
	Income taxes				80				132
	Environmental, legal and rate reserves (Note 17, page F-89)				84				96
	Deposits				39				67
	Obligations under swap agreement (Note 15, page F-81)				—				49
	Other postretirement benefits (Note 18, page F-99)				38				45
	Asset retirement obligations (Note 1, page F-46)				28				26
	Dividends payable				25				23
	Accrued liabilities				74				49
	Other				185				112
		Total		$	820			$	910
Other non-current liabilities
	Environmental and legal reserves (Note 17, page F-89)			$	763			$	450
	Other postretirement and employment benefits (Note 18, page F-99)				248				272
	Obligations under swap agreement (Note 15, page F-81)				—				208
	Regulatory liabilities (Note 12, page F-79)				228				203
	Asset retirement obligations (Note 1, page F-46)				244				192
	Other deferred credits				126				157
	Accrued lease obligations				157				106
	Insurance reserves				125				136
	Deferred gain on sale of assets to GulfTerra (Note 17, page F-89)				15				101
	Deferred compensation				56				60
	Pipeline integrity liability (Note 22, page F-110)				50				69
	Liabilities of discontinued operations				—				3
	Other				64				90
		Total		$	2,076			$	2,047

			2004				2003
			(In millions)
Short-term financing obligations, including current maturities			$	955			$	1,457
Long-term financing obligations				18,241				20,275
	Total		$	19,196			$	21,732

F-81

---

Table of Contents

Debt obligations as of December 31, 2003			$	21,732
Principal amounts borrowed(1)				1,513
Repayment of principal(2)				(3,370	)
Sale of entities(3)				(887	)
Other				208
	Total debt as of December 31, 2004		$	19,196

(1)	Includes proceeds from a $1.25 billion term loan under our new $3 billion credit agreement.
(2)	Includes $850 million of repayments under our previous revolving credit facility.
(3)	Consists of $815 million of debt related to Utility Contract Funding, L.L.C. and $72 million of debt related to Mohawk River Funding IV.

		2004				2003
		(In millions)
Current maturities of long-term debt and other financing obligations			$948			$	1,449
Short-term financing obligation			7				8
			$955			$	1,457

				2004				2003
				(In millions)
Long-term debt
	ANR Pipeline Company
		Debentures and senior notes, 7.0% through 9.625%, due 2010 through 2025		$	800			$	800
		Notes, 13.75% due 2010			12				13
	Colorado Interstate Gas Company
		Debentures, 6.85% through 10.0%, due 2005 and 2037			280				280
	El Paso CGP Company
		Senior notes, 6.2% through 7.75%, due 2004 through 2010			930				1,305
		Senior debentures, 6.375% through 10.75%, due 2004 through 2037			1,357				1,395
	El Paso Corporation
		Senior notes, 5.75% through 7.125%, due 2006 through 2009			1,956				1,817
		Equity security units, 6.14% due 2007			272				272
		Notes, 6.625% through 7.875%, due 2005 through 2018			1,952				2,002
		Medium-term notes, 6.95% through 9.25%, due 2004 through 2032			2,784				2,812
		Zero coupon convertible debentures due 2021			822				895
		$3 billion revolver, LIBOR plus 3.5% due June 2005			—				850
		$1.25 billion term loan, LIBOR plus 2.75% due 2009			1,245				—
	El Paso Natural Gas Company
		Notes, 7.625% and 8.375%, due 2010 and 2032			655				655
		Debentures, 7.5% and 8.625%, due 2022 and 2026			460				460
	El Paso Production Holding Company
		Senior notes, 7.75%, due 2013			1,200				1,200

F-82

---

Table of Contents

					2004				2003
					(In millions)
	Power
		Non-recourse senior notes, 7.75% through 9.875%, due 2008 through 2014				666				770
		Non-recourse notes, variable rates, due 2007 and 2008				320				361
		Recourse notes, 7.27% and 8.5%, due 2005 and 2016				40				85
		Gemstone notes, 7.71% due 2004				—				950
		Non-recourse financing—UCF, 7.944%, due 2016				—				829
	Southern Natural Gas Company
		Notes and senior notes, 6.125% through 8.875%, due 2007 through 2032				1,200				1,200
	Tennessee Gas Pipeline Company
		Debentures, 6.0% through 7.625%, due 2011 through 2037				1,386				1,386
		Notes, 8.375%, due 2032				240				240
	Other					137				404
						18,714				20,981
Other financing obligations
	Capital Trust I					325				325
	Coastal Finance I					300				300
	Lakeside Technology Center lease financing loan due 2006					—				275
						625				900
			Subtotal			19,339				21,881
Less:
	Unamortized discount and premium on long-term debt					150				157
	Current maturities					948				1,449
			Total long-term financing obligations, less current maturities		$	18,241			$	20,275

F-83

---

Table of Contents

Company			Type		Interest Rate		Principal				Due Date
							(In millions)
Issuances and other increases
	Macae		Non-recourse note		LIBOR + 4.25%		$	50				2007
	Blue Lake Gas Storage(1)		Non-recourse term loan		LIBOR + 1.2%			14				2006
	El Paso(2)		Notes		6.50%			213				2005
	El Paso(3)		Term loan		LIBOR + 2.75%			1,250				2009
Increases through December 31, 2004							$	1,527
	Colorado Interstate Gas Company		Senior Notes		5.95%			200				2015
Increases through March 25, 2005							$	1,727
Repayments, repurchases and other retirements
	El Paso CGP		Note		LIBOR + 3.5%		$	200
	El Paso		Revolver		LIBOR + 3.5%			850
	El Paso CGP		Note		6.2%			190
	Mohawk River Funding IV (4)		Non-recourse note		7.75%			72
	Utility Contract Funding (4)		Non-recourse
			senior notes		7.944%			815
	Gemstone		Notes		7.71%			950
	Lakeside		Note		LIBOR + 3.5%			275
	El Paso CGP		Senior Debentures		10.25%			38
	El Paso(2)		Notes		6.50%			213
	El Paso(5)		Zero coupon debenture		—			109
	El Paso		Notes		Various			49
	El Paso CGP		Notes		Various			185
	El Paso		Medium-term notes		Various			28
	Other		Long-term debt		Various			283
Decreases through December 31, 2004								4,257
	El Paso(5)		Zero coupon debenture		—			185
	Cedar Brakes I(4)		Non-recourse notes		8.5%			286
	Cedar Brakes II(4)		Non-recourse notes		9.88%			380
	El Paso(6)		Euros		5.75%			715
	Other		Long-term debt		Various			96
Decreases through March 25, 2005							$	5,919

(1)	This debt was consolidated as a result of adopting FIN No. 46 (see Note 2, on page F-58).
(2)	In the fourth quarter of 2004, we entered into an agreement with Enron that liquidated two derivative swap agreements of approximately $221 million in exchange for approximately $213 million of 6.5% one year notes. Subsequent to the closing of our new credit agreement, these notes were paid in full.
(3)	Proceeds from the $1.25 billion term loan under the new credit agreement entered into in November 2004.
(4)	The remaining balance of these debt obligations was eliminated when we sold our interests in Mohawk River Funding IV, UCF and Cedar Brakes I and II.
(5)	In December 2004 and January 2005, we repurchased these 4% yield-to-maturity zero-coupon debentures. The amount shown as principal is the carrying value on the date the debt was retired as compared to its maturity value in 2021 of $206 million in December 2004, and $351 million in January 2005.
(6)	In March 2005, we repaid debt with a principal balance of €528 million, which had a carrying value of $724 million in long-term debt on our balance sheet as of December 31, 2004. In conjunction with this repayment, we also terminated derivative contracts with a fair value of $152 million as of December 31, 2004 that hedged this debt. The total net payment was $579 million. See Note 10, on page F-73, for additional information on the repurchase of the derivative contracts.

F-84

---

Table of Contents

2005			$	948
2006(1)				1,155
2007				835
2008				733
2009				2,637
Thereafter				13,031
	Total long-term financing obligations, including current maturities		$	19,339

(1)	Excludes $0.8 billion of zero coupon debentures as discussed below.

	Restrictive Covenants

F-85

---

Table of Contents

	(a)	El Paso’s ratio of Debt to Consolidated EBITDA, each as defined in the new credit agreement, shall not exceed 6.50 to 1.0 at any time prior to September 30, 2005, 6.25 to 1.0 at any time on or after September 30, 2005 and prior to June 30, 2006, and 6.00 to 1.0 at any time on or after June 30, 2006 until maturity;
	(b)	El Paso’s ratio of Consolidated EBITDA, as defined in the new credit agreement, to interest expense plus dividends paid shall not be less than 1.60 to 1.0 prior to March 31, 2006, 1.75 to 1.0 on or after March 31, 2006 and prior to March 31, 2007, and 1.80 to 1.0 on or after March 31, 2007 until maturity;
	(c)	EPNG, TGP, ANR, and CIG cannot incur incremental Debt if the incurrence of this incremental Debt would cause their Debt to Consolidated EBITDA ratio, each as defined in the new credit agreement, for that particular company to exceed 5 to 1;
	(d)	the proceeds from the issuance of Debt by our pipeline company borrowers can only be used for maintenance and expansion capital expenditures or investments in other FERC-regulated assets, to fund working capital requirements, or to refinance existing debt; and
	(e)	the occurrence of an event of default and after the expiration of any applicable grace period, with respect to Debt in an aggregate principal amount of $200 million or more.

F-86

---

Table of Contents

F-87

---

Table of Contents

			Year Ended December 31,
			2004				2003				2002
			(In millions)
			(unaudited)
Operating results data:
	Operating revenues		$	812			$	1,459			$	1,132
	Operating expenses			1,131				1,865				2,268
	Loss from continuing operations			(399	)			(377	)			(1,288	)
	Net loss			(399	)			(377	)			(1,510	)

F-88

---

Table of Contents

			December 31,
			2004				2003
			(In millions)
			(unaudited)
Financial position data:
	Current assets		$	2,783			$	4,217
	Non-current assets			9,001				9,892
	Short-term debt			402				1,111
	Other current liabilities			4,693				5,409
	Long-term debt			2,183				2,545
	Other non-current liabilities			2,580				2,642
	Securities of subsidiaries			3				28
	Equity in net assets			1,923				2,374

17.	Commitments and Contingencies

F-89

---

Table of Contents

	Shareholder Litigation. Since 2002, twenty-nine purported shareholder class action lawsuits alleging violations of federal securities laws have been filed against us and several of our current and former officers and directors. One of these lawsuits has been dismissed and the remaining 28 lawsuits have been consolidated in federal court in Houston, Texas. The consolidated lawsuit generally challenges the accuracy or completeness of press releases and other public statements made during the class period from 2001 through early 2004, related to wash trades, mark-to-market accounting, off-balance sheet debt, overstatement of oil and gas reserves and manipulation of the California energy market. The consolidated lawsuit is currently stayed.
	Derivative Litigation. Since 2002, five shareholder derivative actions have also been filed. Three of the actions allege the same claims as in the consolidated shareholder class action suit described above, with one of the actions including a claim for compensation disgorgement against certain individuals. These actions are currently stayed. Two actions are now consolidated in state court in Houston, Texas and generally allege that manipulation of California gas prices exposed us to claims of antitrust conspiracy, FERC penalties and erosion of share value.
	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 generally that our direct and indirect communications with participants in the El Paso Corporation Retirement Savings Plan included misrepresentations and omissions that caused members of the class to hold and maintain investments in El Paso stock in violation of the Employee Retirement Income Security Act (ERISA). That lawsuit was subsequently amended to include allegations relating to our reporting of natural gas and oil reserves. This lawsuit has been stayed.
	We and our representatives have insurance coverages that are applicable to each of these shareholder, derivative and ERISA lawsuits. There are certain deductibles and co-pay obligations under some of those insurance coverages for which we have established certain accruals we believe are adequate.

F-90

---

Table of Contents

F-91

---

Table of Contents

F-92

---

Table of Contents

F-93

---

Table of Contents

F-94

---

Table of Contents

	Enron Trading Claims. We have largely sold or settled all of our original claims of our trading entities with Enron. In particular, on June 24, 2004, the Bankruptcy Court approved a settlement agreement with Enron that resolved most of our trading or merchant issues between the parties for which final payments were made in the third quarter of 2004. The only remaining trading claims involve our European trading businesses, claims against Enron Capital and Trade Resources Limited, which are subject to separate proceedings in the United Kingdom, in addition to a corresponding claim against Enron Corp. based on a corporate guarantee. After considering the valuation and setoff arguments and the reserves we have established, we believe our overall remaining trading exposure to Enron is $3 million.
	Enron Pipeline Claims. In addition, various Enron subsidiaries had transportation contracts on several of our pipeline systems. Most of these transportation contracts were rejected, and our pipeline subsidiaries filed proofs of claim totaling approximately $137 million. EPNG filed the largest proof of claim in the amount of approximately $128 million, which included $18 million for amounts due for services provided through the date the contracts were rejected and $110 million for damage claims arising from the rejection of its transportation contracts. EPNG expects that Enron will vigorously contest these claims. Our remaining pipeline claimants, ANR TGP and WIC, are in various stages of attempting to resolve their claims with Enron. Given the uncertainty of the bankruptcy process, the results are uncertain. We have fully reserved for the amounts due through the date the contracts were rejected, and we have not recognized any amounts under these contracts since that time.

F-95

---

Table of Contents

			December 31, 2004
Sites			Expected				High
			(In millions)
Operating			$	100			$	111
Non-operating				249				384
Superfund				31				52
	Total		$	380			$	547

F-96

---

Table of Contents

Balance as of January 1, 2004		$	412
Additions/adjustments for remediation activities			17
Payments for remediation activities			(51	)
Other changes, net			2
Balance as of December 31, 2004		$	380

F-97

---

Table of Contents

Year Ending December 31,			Operating Leases
			(In millions)
2005			$	79
2006				66
2007				51
2008				43
2009				40
Thereafter				163
	Total		$	442

F-98

---

Table of Contents

F-99

---

Table of Contents

		Primary								Other
		Pension Plan								Pension Plans
		2004				2003				2004				2003
		(In millions)
Projected benefit obligation		$	1,948			$	1,928			$	170			$	163
Accumulated benefit obligation			1,934				1,902				169				163
Fair value of plan assets			2,196				2,104				93				93
Accrued benefit liability			—				—				74				69
Prepaid benefit cost			960				960				—				21
Accumulated other comprehensive loss			—				—				70				37

		2004				2003
		(In millions)
Projected benefit obligation		$	170			$	134
Accumulated benefit obligation			169				134
Fair value of plan assets			93				63

											Other
											Postretirement
			Pension Benefits								Benefits
			2004				2003				2004				2003
			(In millions)
Change in benefit obligation:
	Projected benefit obligation at beginning of period		$	2,091			$	2,088			$	575			$	558
	Service cost			31				36				1				1
	Interest cost			121				134				34				35
	Participant contributions			—				—				27				24
	Settlements, curtailments and special termination benefits			(3	)			—				—				(6	)
	Actuarial loss (gain)			76				22				(20	)			50
	Benefits paid			(198	)			(189	)			(76	)			(87	)
	Projected benefit obligation at end of period		$	2,118			$	2,091			$	541			$	575
Change in plan assets:
	Fair value of plan assets at beginning of period		$	2,197			$	2,072			$	196			$	164
	Actual return on plan assets			277				285				12				25
	Employer contributions			12				29				61				70
	Participant contributions			—				—				27				24
	Benefits paid			(198	)			(189	)			(76	)			(87	)
	Administrative expenses			1				—				—				—
	Fair value of plan assets at end of period		$	2,289			$	2,197			$	220			$	196

F-100

---

Table of Contents

											Other
											Postretirement
			Pension Benefits								Benefits
			2004				2003				2004				2003
			(In millions)
Reconciliation of funded status:
	Fair value of plan assets at September 30		$	2,289			$	2,197			$	220			$	196
	Less: Projected benefit obligation at end of period			2,118				2,091				541				575
	Funded status at September 30			171				106				(321	)			(379	)
	Fourth quarter contributions and income			2				2				13				17
	Unrecognized net actuarial loss(1)			800				868				32				57
	Unrecognized net transition obligation			—				1				8				15
	Unrecognized prior service cost			(17	)			(28	)			(6	)			(7	)
	Prepaid (accrued) benefit cost at December 31		$	956			$	949			$	(274	)		$	(297	)

(1)

The decrease in unrecognized net actuarial loss in our pension benefits was primarily due to historical changes and assumptions on discount rates, expected return on plan assets and rate of compensation increase. We recognize the difference between the actual return and our expected return over a three year period as permitted by SFAS No. 87. The decrease in unrecognized net actuarial loss in our other postretirement benefits was primarily due to the adoption of FSP No. 106-2.

Year Ending							Other Postretirement
December 31,			Pension Benefits				Benefits(1)
			(In millions)
2005			$	160			$	57
2006				160				52
2007				161				50
2008				161				48
2009				160				46
2010-2014				788				208
	Total		$	1,590			$	461

(1)	Includes a reduction of $3 million in each year excluding 2005 for an expected subsidy related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003.

															Other Postretirement
			Pension Benefits												Benefits
			2004				2003				2002				2004				2003				2002
			(In millions)
Service cost			$	31			$	36			$	33			$	1			$	1			$	2
Interest cost				121				134				135				34				35				38
Expected return on plan assets				(187	)			(227	)			(260	)			(11	)			(9	)			(9	)
Amortization of net actuarial (gain) loss				47				7				—				4				1				(1	)
Amortization of transition obligation				—				(1	)			(6	)			8				8				8
Amortization of prior service cost(1)				(3	)			(3	)			(3	)			(1	)			(1	)			(1	)
Settlements, curtailment, and special termination benefits				(4	)			11				—				—				(6	)			—
	Net benefit cost (income)		$	5			$	(43	)		$	(101	)		$	35			$	29			$	37

F-101

---

Table of Contents

(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.

															Other
			Pension Benefits												Postretirement Benefits
			2004				2003				2002				2004				2003				2002
			(Percent)												(Percent)
Assumptions related to benefit obligations at September 30:
	Discount rate			5.75				6.00								5.75				6.00
	Rate of compensation increase			4.00				4.00
Assumptions related to benefit costs for the year ended December 31:
	Discount rate			6.00				6.75				7.25				6.00				6.75				7.25
	Expected return on plan assets(1)			8.50				8.80				8.80				7.50				7.50				7.50
	Rate of compensation increase			4.00				4.00				4.00

(1)

The expected return on plan assets is a pre-tax rate (before a tax rate ranging from 26 percent to 27 percent on other postretirement benefits) that is primarily based on an expected risk-free investment return, adjusted for historical risk premiums and specific risk adjustments associated with our debt and equity securities. These expected returns were then weighted based on our target asset allocations of our investment portfolio. For 2005, the assumed expected return on assets for pension benefits will be reduced to 8 percent.

			2004				2003
			(In millions)
One percentage point increase:
	Aggregate of service cost and interest cost		$	1			$	1
	Accumulated postretirement benefit obligation			19				21
One percentage point decrease:
	Aggregate of service cost and interest cost		$	(1	)		$	(1	)
	Accumulated postretirement benefit obligation			(18	)			(19	)

			Pension Plans												Other Postretirement Plans
Asset Category			Target				Actual 2004				Actual 2003				Target				Actual 2004				Actual 2003
			(Percent)												(Percent)
Equity securities(1)				60				62				70				65				60				29
Debt securities				40				37				29				35				33				60
Other				—				1				1				—				7				11
	Total			100				100				100				100				100				100

(1)	Actuals for our pension plans include $42 million (1.8 percent of total assets) and $33 million (1.5 percent of total assets) of our common stock at September 30, 2004 and September 30, 2003.

F-102

---

Table of Contents

F-103

---

Table of Contents

			Stock Options
			2004								2003								2002
							Weighted								Weighted								Weighted
			# Shares of				Average				# Shares of				Average				# Shares of				Average
			Underlying				Exercise				Underlying				Exercise				Underlying				Exercise
			Options				Price				Options				Price				Options				Price
Outstanding at beginning of year				36,245,014			$	47.90				43,208,374			$	49.16				44,822,146			$	50.02
	Granted			4,842,453			$	7.16				1,180,041			$	7.29				3,435,138			$	35.41
	Exercised			(3,193	)		$	7.64				—				—				(310,611	)		$	22.44
	Converted(1)			(11,333	)		$	42.99				(871,250	)		$	42.00				—				—
	Forfeited or canceled			(7,149,363	)		$	44.75				(7,272,151	)		$	49.53				(4,738,299	)		$	51.83
Outstanding at end of year				33,923,578			$	42.73				36,245,014			$	47.90				43,208,374			$	49.18
Exercisable at end of year				28,455,056			$	49.45				28,703,151			$	46.04				25,493,152			$	43.00
Weighted average fair value of options granted during the year							$	2.69							$	3.21							$	14.23

(1)	Includes the conversion of stock options into common stock and cash at no cost to employees based upon achievement of certain performance targets and lapse of time. These options had an original stated exercise price of approximately $43 per share and $42 per share in 2004 and 2003.

		Options Outstanding												Options Exercisable
						Weighted Average				Weighted								Weighted
Range of		Number				Remaining Years of				Average				Number				Average
Exercise Prices		Outstanding				Contractual Life				Exercise Price				Exercisable				Exercise Price
$ 0.00 - $21.39			7,537,238				7.1			$	9.25				2,154,339			$	14.35
$21.40 - $42.89			8,761,610				2.9			$	37.53				8,707,300			$	37.52
$42.90 - $64.29			12,302,057				3.6			$	54.88				12,272,411			$	54.91
$64.30 - $70.63			5,322,673				4.7			$	70.59				5,321,006			$	70.59
			33,923,578				4.4			$	42.73				28,455,056			$	49.45

Assumption:		2004				2003				2002
Expected Term in Years			5.35				6.19				6.95
Expected Volatility			45%				52%				43%
Expected Dividends			2.1%				2.2%				1.8%
Risk-Free Interest Rate			3.7%				3.4%				3.2%

F-104

---

Table of Contents

21.	Business Segment Information

F-105

---

Table of Contents

F-106

---

Table of Contents

			2004				2003				2002
			(Restated)				(Restated)				(Restated)
			(In millions)
Total EBIT			$	830			$	769			$	(427	)
Interest and debt expense				(1,607	)			(1,791	)			(1,297	)
Distributions on preferred interests of consolidated subsidiaries				(25	)			(52	)			(159	)
Income taxes				(31	)			479				641
	Loss from continuing operations		$	(833	)		$	(595	)		$	(1,242	)

			As of or for the Year Ended December 31, 2004
			Regulated				Non-regulated
											Marketing
											and Trading				Power				Field				Corporate(1)				Total
			Pipelines				Production				(Restated)				(Restated)				Services				(Restated)				(Restated)
			(In millions)
Revenue from external customers
	Domestic		$	2,554			$	535	(2)		$	697			$	241			$	1,203			$	132			$	5,362
	Foreign			9				26	(2)			2				460				—				15				512
Intersegment revenue				88				1,174	(2)			(1,207	)			94				159				(308	)			—
Operation and maintenance				777				365				53				374				102				201				1,872
Depreciation, depletion, and amortization				410				548				13				54				12				51				1,088
(Gain) loss on long-lived assets				(1	)			8				—				599				508				(6	)			1,108
Operating income (loss)			$	1,129			$	726			$	(562	)		$	(424	)		$	(465	)		$	(214	)		$	190
Earnings from unconsolidated affiliates				173				4				—				(249	)			618				—				546
Other income				33				4				23				83				2				48				193
Other expense				(4	)			—				—				(9	)			(35	)			(51	)			(99	)
EBIT			$	1,331			$	734			$	(539	)		$	(599	)		$	120			$	(217	)		$	830
Discontinued operations, net of income taxes			$	—			$	(36	)		$	—			$	—			$	—			$	(78	)		$	(114	)
Assets of continuing operations (3)
	Domestic			15,930				3,714				2,372				982				686				4,424				28,108
	Foreign(4)			58				366				32				2,617				—				96				3,169
Capital expenditures and investments in and advances to unconsolidated affiliates, net (5)				1,047				728				—				29				(5	)			10				1,809
Total investments in unconsolidated affiliates				1,032				6				—				1,262				308				6				2,614

(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. We recorded an intersegment revenue elimination of $308 million and an operation and maintenance expense elimination of $25 million, which is included in the “Corporate” column, to remove intersegment transactions.
(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 and Trading segment, which is responsible for marketing our production.
(3)	Excludes assets of discontinued operations of $106 million (see Note 3, on page F-62).
(4)	Of total foreign assets, approximately $1.3 billion relates to property, plant and equipment and approximately $1.5 billion relates to investments in and advances to unconsolidated affiliates.
(5)	Amounts are net of third party reimbursements of our capital expenditures and returns of invested capital.

F-107

---

Table of Contents

			As of or for the Year Ended December 31, 2003
			Regulated				Non-regulated
							Production				Marketing								Field								Total
			Pipelines				(Restated)				and Trading				Power				Services				Corporate(1)				(Restated)
			(In millions)
Revenue from external customers
	Domestic		$	2,527			$	201	(2)		$	1,430			$	515			$	1,153			$	113			$	5,939
	Foreign			2				—				—				516				2				13				533
Intersegment revenue				118				1,940	(2)			(2,065	)			145				374				(316	)			196	(3)
Operation and maintenance				720				342				183				562				110				93				2,010
Depreciation, depletion, and amortization				386				576				25				91				31				67				1,176
Western Energy Settlement				127				—				(25	)			—				—				2				104
(Gain) loss on long-lived assets				(10	)			5				(3	)			185				173				510				860
Operating income (loss)			$	1,063			$	1,073			$	(819	)		$	(13	)		$	(193	)		$	(706	)		$	405
Earnings (losses) from unconsolidated affiliates				119				13				—				(91	)			329				(7	)			363
Other income				57				5				12				90				—				39				203
Other expense				(5	)			—				(2	)			(14	)			(3	)			(178	)			(202	)
EBIT			$	1,234			$	1,091			$	(809	)		$	(28	)		$	133			$	(852	)		$	769
Discontinued operations, net of income taxes			$	—			$	24			$	—			$	—			$	—			$	(1,303	)		$	(1,279	)
Cumulative effect of accounting changes, net of income taxes				(4	)			(3	)			—				—				(2	)			—				(9	)
Assets of continuing operations(4)
	Domestic			15,659				3,459				2,661				3,897				1,990				3,890				31,556
	Foreign			27				308				5				3,102				—				141				3,583
Capital expenditures and investments in and advances to unconsolidated affiliates, net(5)				837				1,300				(1	)			1,083				(15	)			89				3,293
Total investments in unconsolidated affiliates				1,018				79				—				1,652				655				5				3,409

(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. We recorded an intersegment revenue elimination of $316 million and an operation and maintenance expense elimination of $59 million, which is included in the “Corporate” column, to remove intersegment transactions.
(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 and Trading segment, which is responsible for marketing our production.
(3)	Relates to intercompany activities between our continuing operations and our discontinued operations.
(4)	Excludes assets of discontinued operations of $1.8 billion (see Note 3, on page F-62).
(5)	Amounts are net of third party reimbursements of our capital expenditures and returns of invested capital. Our Power Segment Includes $1 billion to acquire remaining interest in Chaparral and Gemstone (see Note 2, on page F-58).

F-108

---

Table of Contents

			As of or for the Year Ended December 31, 2002
			Regulated				Non-regulated
			Pipelines								Marketing								Field								Total
			(Restated)				Production				and Trading				Power				Services				Corporate(1)				(Restated)
			(In millions)
Revenue from external customers
	Domestic		$	2,389			$	308	(2)		$	926			$	1,268			$	1,145			$	97			$	6,133
	Foreign			3				—				(41	)			361				3				79				405
Intersegment revenue				218				1,623	(2)			(2,209	)			43				881				(213	)			343
Operation and maintenance				752				368				173				520				179				99				2,091
Depreciation, depletion, and amortization				374				601				11				45				56				72				1,159
Western Energy Settlement				412				—				487				—				—				—				899
(Gain) loss on long-lived assets				(13	)			(1	)			—				160				(179	)			214				181
Operating income (loss)			$	788			$	803			$	(1,993	)		$	352			$	273			$	(394	)		$	(171	)
Earnings (losses) from unconsolidated affiliates				10				7				—				(256	)			18				7				(214	)
Other income				34				1				19				40				3				100				197
Other expense				(4	)			(3	)			(3	)			(124	)			(5	)			(100	)			(239	)
EBIT			$	828			$	808			$	(1,977	)		$	12			$	289			$	(387	)		$	(427	)
Discontinued operations, net of income taxes			$	—			$	(68	)		$	—			$	—			$	—			$	(357	)		$	(425	)
Cumulative effect of accounting changes, net of income taxes				—				—				(222	)			14				—				—				(208	)
Assets of continuing operations (4)
	Domestic			14,727				3,495				5,568				2,759				2,714				4,265				33, 528
	Foreign			59				208				844				2,485				14				277				3,887
Capital expenditures and investments in and advances to unconsolidated affiliates, net (5)				1,075				2,114				47				91				187				48				3,562
Total investments in unconsolidated affiliates				992				87				—				2,725				922				23				4,749

(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. We recorded an intersegment revenue elimination of $213 million and an operation and maintenance expense elimination of $41 million, which is included in the “Corporate” column, to remove intersegment transactions.
(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 and Trading segment, which is responsible for marketing our production.
(3)	Relates to intercompany activities between our continuing operations and our discontinued operations.
(4)	Excludes assets of discontinued operations of $4.5 billion (see Note 3, on page F-62).
(5)	Amounts are net of third party reimbursements of our capital expenditures and returns of invested capital.

F-109

---

Table of Contents

																				Earnings from
				Net Ownership								Investment								Unconsolidated Affiliates
				Interest
																2003				2004								2002
				2004				2003				2004				(Restated)				(Restated)				2003				(Restated)
				(Percent)								(In millions)								(In millions)
Domestic:
	Citrus				50				50			$	589			$	593			$	65			$	43			$	43
	Enterprise Products Partners(1)				—	(1)			—				257				—				6				—				—
	GulfTerra Energy Partners(1)				—				—	(1)			—				599				601				419				69
	Midland Cogeneration Venture(2)				44				44				191				348				(171	)			29				28
	Great Lakes Gas Transmission(3)				50				50				316				325				65				57				63
	Javelina				40				40				45				40				15				(2	)			—
	Milford(4)				—				—				—				—				(1	)			(88	)			(22	)
	Bastrop Company(5)				—				50				—				73				(1	)			(48	)			(5	)
	Mobile Bay Processing(5)				—				42				—				11				—				(48	)			(2	)
	Blue Lake Gas Storage(6)				—				75				—				30				—				9				8
	Chaparral Investors (Electron)(7)				—				—				—				—				—				(207	)			(62	)
	Linden Venture L.P. (East Coast Power)				—				—				—				—				—				65				—
	Dauphin Island(5)				—				15				—				—				—				(40	)			(1	)
	Alliance Pipeline Limited Partnership(4)				—				—				—				—				—				—				25
	CE Generation(4)				—				—				—				—				—				—				(52	)
	Aux Sable NGL				—				—				—				—				—				—				(50	)
	Other Domestic Investments				various				various				136				137				26				26				29
		Total domestic											1,534				2,156				605				215				71
Foreign:
	Korea Independent Energy Corporation				50				50				176				145				22				29				24
	Araucaria Power(8)				60				60				186				181				—				—				—
	EGE Itabo				25				25				88				87				1				1				(2	)
	Bolivia to Brazil Pipeline				8				8				86				66				24				17				2
	EGE Fortuna				25				25				65				59				6				3				5
	Meizhou Wan Generating				26				25				52				63				(14	)			8				(20	)
	Enfield Power(9)				25				25				51				55				1				3				(3	)
	Aguaytia Energy				24				24				39				51				(5	)			4				3
	San Fernando Pipeline				50				50				46				41				13				5				—
	Habibullah Power(10)				50				50				20				48				(46	)			(3	)			10
	Gasoducto del Pacifico Pipeline				22				22				33				37				4				3				(2	)
	Samalayuca(11)				50				50				35				24				5				3				21
	Saba Power Company				94				94				7				59				(51	)			4				7
	Australian Pipelines(5)				—				33				—				38				4				(3	)			(142	)
	UnoPaso(6)				—				50				—				73				4				14				6
	Diamond Power (Gemstone)(7)				—				—				—				—				—				17				109
	CAPSA(4)				—				—				—				—				—				24				(262	)
	PPN(12)				26				26				—				—				—				—				(50	)
	Agua del Cajon(4)				—				—				—				—				—				—				(24	)
	Other Foreign Investments(10)				various				various				196				226				(27	)			19				33
		Total foreign											1,080				1,253				(59	)			148				(285	)
Total investments in unconsolidated affiliates												$	2,614			$	3,409
Total earnings (losses) from unconsolidated affiliates																				$	546			$	363			$	(214	)

F-110

---

Table of Contents

(1)	As of December 31, 2003, we owned an effective 50 percent interest in the one percent general partner of GulfTerra, approximately 17.8 percent of the partnership’s common units and all of the outstanding Series C units. During 2004 we sold our remaining interest in GulfTerra to Enterprise for cash and equity interests in Enterprise and recognized a $507 million gain. As of December 31, 2004, our ownership consisted of a 9.9 percent interest in the two percent general partner of Enterprise and approximately 3.7 percent of Enterprise’s common units. In January 2005, we sold all of these remaining interests to Enterprise. For a further discussion of our interests in GulfTerra and Enterprise, see page F-114.
(2)	Our ownership interest consists of a 38.1 percent general partner interest and 5.4 percent limited partner interest.
(3)	Includes a 47 percent general partner interest in Great Lakes Gas Transmission Limited Partnership and a 3 percent limited partner interest through our ownership in Great Lakes Gas Transmission Company.
(4)	In 2003 we completed the sale or transfer of our interest in this investment.
(5)	In 2004 we completed the sale of our interest in this investment.
(6)	Consolidated in 2004.
(7)	This investment was consolidated in 2003.
(8)	Our investment in Araucaria Power was included in Diamond Power (Gemstone) prior to 2003.
(9)	We have signed an agreement to sell our interest in the project and expect to close the transaction in the first half of 2005.

(10)	As of December 31, 2004 and 2003, we also had outstanding advances of $64 million and $90 million related to our investment in Habibullah Power. We also had other outstanding advances of $318 million and $327 million related to our other foreign investments as of December 31, 2004 and 2003, of which $307 million and $290 million are related to our investment in Porto Velho.
(11)	Consists of investments in a power facility and pipeline. In 2002, we sold our investment in the power facility.
(12)	Impaired in 2002 due to our inability to recover our investment. Earnings generated in 2003 and 2004 did not improve the recoverability of this investment. We sold our interest in March 2005.

F-111

---

Table of Contents

			Pre-tax
Investment			Gain (Loss)				Cause of Impairments or Gain (Loss)
			(In millions)
2004 (Restated)
Gain on sale of interests in GulfTerra(1)			$	507			Sale of investment
Asian power investments(2)				(182	)		Anticipated sales of investments
Midland Cogeneration Venture				(161	)		Decline in investment’s fair value based on increased fuel costs
Power investments held for sale				(49	)		Anticipated sales of investments
Net gain on domestic power investment sales (3)				7			Sales of power investments
Other				2
	Total		$	124
2003
Gain on sale of interests in GulfTerra(4)			$	266			Sale of various investment interests in GulfTerra
Chaparral Investors (Electron)				(207	)		Decline in the investment’s fair value based on developments in our power business and the power industry
Milford power facility(5)				(88	)		Transfer of ownership to lenders
Dauphin Island Gathering/Mobile Bay Processing				(86	)		Decline in the investments’ fair value based on the devaluation of the underlying assets
Bastrop Company				(43	)		Decision to sell investment
Linden Venture, L.P.(East Coast Power)				(22	)		Sale of investment in East Coast Power
Other investments				4
	Total		$	(176	)
2002 (Restated)
CAPSA/CAPEX			$	(262	)		Weak economic conditions in Argentina
EPIC Australia				(141	)		Regulatory difficulties and the decision to discontinue further capital investment
CE Generation				(74	)		Sale of investment
Aux Sable NGL				(47	)		Sale of investment
Agua del Cajon				(24	)		Weak economic conditions in Argentina
PPN				(41	)		Loss of economic fuel supply and payment default
Meizhou Wan Generating				(7	)		Weak economic conditions in China
Other investments				(16	)
	Total		$	(612	)

(1)	In September 2004, in connection with the closing of the merger between GulfTerra and Enterprise, we sold to affiliates of Enterprise substantially all of our interests in GulfTerra. See further discussion of GulfTerra beginning on page F-114.
(2)	Includes impairments of our investments in Korea Independent Energy Corporation, Meizhou Wan Generating, Habibullah Power, Saba Power Company and several other foreign power investments.
(3)	Includes a loss on the sale of Bastrop Company and gains on the sale of several other domestic investments.

F-112

---

Table of Contents

(4)	In 2003, we sold 50 percent of the equity of our consolidated subsidiary that holds our 1 percent general partner interest. This was recorded as minority interest in our balance sheet.
(5)	In December 2003, we transferred our ownership interest in Milford to its lenders in order to terminate all of our obligations associated with Milford.

			Year Ended December 31,
			2004				2003				2002
			(Unaudited)
			(In millions)
Operating results data:
	Operating revenues		$	2,211			$	3,360			$	2,486
	Operating expenses			1,485				2,309				1,632
	Income from continuing operations			388				519				422
	Net income			388				520				445

			December 31,
			2004				2003
			(Unaudited)
			(In millions)
Financial position data:
	Current assets		$	1,270			$	1,024
	Non-current assets			5,243				8,001
	Short-term debt			250				1,169
	Other current liabilities			488				645
	Long-term debt			2,044				1,892
	Other non-current liabilities			779				1,703
	Minority interest			73				71
	Equity in net assets			2,879				3,545

			Nine months ended				Year Ended				Year ended
			September 30, 2004				December 31, 2003				December 31, 2002
			(Unaudited)
Operating results data:
	Net sales or gross revenues		$	677			$	871			$	457
	Operating expenses			432				557				297
	Income from continuing operations			155				161				93
	Net income			155				163				98

			As of				As of
			September 30, 2004				December 31, 2003
			(Unaudited)
Financial position data:
	Current assets		$	230			$	209
	Noncurrent assets			3,167				3,113
	Current liabilities			200				209
	Noncurrent liabilities			1,921				1,860
	Equity in net assets			1,276				1,253

F-113

---

Table of Contents

		2004				2003				2002
		(In millions)
Operating revenue		$	218			$	216			$	65
Other revenue — management fees			4				13				192
Cost of sales			102				106				178
Reimbursement for operating expenses			97				140				186
Other income			8				10				18
Interest income			8				11				30
Interest expense			—				2				42

	Chaparral and Gemstone

	GulfTerra

F-114

---

Table of Contents

							Realized
Transaction			Proceeds				Gain/(Loss)
			(In millions)
2002
	Sold San Juan Basin gathering, treating, and processing assets and Texas & New Mexico midstream assets to GulfTerra(1)		$	1,501			$	210
2003
	Sold 9.9% of our 1% general partner interest in GulfTerra to Goldman Sachs			88				—
	Repurchased the 9.9% interest from Goldman Sachs(2)			(116	)			(28	)
	Redeemed series B preference units			156				(11	)
	Released from obligation in 2021 to purchase Chaco facility(3)			(10	)			67
	Sold 50% general partnership interest in GulfTerra to Enterprise(4)			425				297
	Other GulfTerra common unit sales			23				8
2004
	Sold our interest in the general partner of GulfTerra, 2.9 million common units and 10.9 million series C units in GulfTerra to Enterprise(5)(6)			951				507

(1)	We received $955 million of cash, Series C units in GulfTerra with a value of $356 million, and an interest in a production field with a value of $190 million. We recorded an additional $74 million liability and related loss in 2003 for future pipeline integrity costs related to the transmission assets, for which we agreed to reimburse GulfTerra through 2006.
(2)	We paid $92 million in cash and transferred GulfTerra common units with a book value of $19 million to Goldman Sachs in December 2003. We also paid $5 million of miscellaneous expenses related to the repurchase.
(3)	We satisfied our obligation to GulfTerra through the transfer of communications assets with a book value of $10 million.
(4)	The cash flows were reflected in our 2003 cash flow statement as an investing activity and $84 million of the proceeds were reflected as minority interest on our balance sheet. We also agreed to pay $45 million to Enterprise through 2006.
(5)	We received $870 million in cash and a 9.9 percent interest in the general partner of the combined organization, Enterprise Products GP, with a fair value of $82 million. We also exchanged our remaining GulfTerra common units for 13.5 million Enterprise common units.
(6)	As a result of the Enterprise transaction, we also recorded a $480 million impairment of the goodwill in loss on long-lived assets on our income statement associated with our Field Services segment. In addition, we sold South Texas assets to Enterprise for total proceeds of $156 million and a loss of $11 million included in our loss on long-lived assets.

			2004								2003
			Book Value				Ownership				Book Value				Ownership
			(In millions)				(Percent)				(In millions)				(Percent)
One Percent General Partner(1)			$	82				9.9			$	194				100.0
Common Units				175				3.7				251				17.8
Series C Units				—				—				335				100.0
	Total		$	257							$	780

(1)

We had $181 million of indefinite-lived intangible assets related to our general partner interest as of December 31, 2003. We also have $96 million recorded as minority interest related to the effective general partnership interest acquired by Enterprise in December 2003. This reduced our effective ownership interest in the general partner to 50 percent. Both of these were disposed of in the Enterprise sales described above.

F-115

---

Table of Contents

			2004				2003				2002
			(In millions)
Revenues received from GulfTerra
	Field Services		$	2			$	5			$	1
	Marketing and Trading			26				28				19
	Production			—				—				3
			$	28			$	33			$	23
Expenses paid to GulfTerra
	Field Services		$	84			$	75			$	97
	Marketing and Trading			20				30				93
	Production			9				9				9
			$	113			$	114			$	199
Reimbursements received from GulfTerra
	Field Services		$	71			$	91			$	60

F-116

---

Table of Contents

F-117

---

Table of Contents

F-118

---

Table of Contents

F-119

---

Table of Contents

	•	Improving in the area of estimating oil and gas reserves, including changes in the composition of our Board of Directors and management by adding persons with greater experience in the oil and gas industry, creating a centralized reserve reporting function and internal committee that provides oversight of the reporting function, continuing the use of third party reserve engineering firms to perform an independent assessment of our proved reserves, and enhancing documentation with regard to the procedures and controls for recording proved reserves;
	•	Implementing changes to our systems and procedures to segregate responsibilities for manual journal entry preparation and procurement activities; and
	•	Implementing formal training to educate appropriate personnel on management’s responsibilities mandated by the Sarbanes Oxley Act, Section 404, the components of the internal control framework on which we rely and its relationship to our core values.

F-120

---

Table of Contents

F-121

---

Table of Contents

	1.	Access to Financial Application Programs and Data. At December 31, 2004, the Company did not maintain effective controls over access to financial application programs and data at each of its operating segments. Internal control deficiencies were identified with respect to inadequate design of and compliance with security access procedures related to identifying and monitoring conflicting roles (i.e., segregation of duties) and lack of independent monitoring of access to various systems by information technology staff, as well as certain users with accounting and reporting responsibilities who also have security administrator access to financial and reporting systems to perform their responsibilities. These control deficiencies did not result in an adjustment to the 2004 interim or annual consolidated financial statements. However, these control deficiencies could result in a misstatement of a number of the Company’s financial statement accounts, including accounts receivable, property, plant and equipment, accounts payable, revenue, price risk management assets and liabilities, and potentially others, that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, these control deficiencies constitute a material weakness.

F-122

---

Table of Contents

	2.	Account Reconciliations. At December 31, 2004, the Company did not maintain effective controls over the preparation and review of account reconciliations related to accounts such as prepaid insurance, accounts receivable, other assets and taxes other than income taxes. Specifically, instances were identified in the Power and Marketing and Trading businesses where (1) account balances were not properly reconciled and (2) there was not consistent communication of reconciling differences within the organization to allow for adequate accumulation and resolution of reconciling items. Instances were also noted where accounts were not being reconciled and reviewed by individuals with adequate accounting experience and training. These control deficiencies resulted in adjustments impacting the fourth quarter of 2004 financial statements. Furthermore, these control deficiencies could result in a misstatement of the aforementioned accounts that would result in a material misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly, these control deficiencies constitute a material weakness.
	3.	Identification, Capture and Communication of Financial Data Used in Accounting for Non-Routine Transactions or Activities. At December 31, 2004, the Company did not maintain effective controls related to identification, capture and communication of financial data used for accounting for non-routine transactions or activities. Control deficiencies were identified related to the identification, capture and validation of pertinent information necessary to ensure the timely and accurate recording of non-routine transactions or activities, primarily related to accounting for investments in unconsolidated affiliates, determining impairment of long-lived assets, and accounting for divestitures. These control deficiencies resulted in (a) the restatement of the 2002 consolidated financial statements, (b) the restatement of the 2003 consolidated financial statements and related 2003 fourth quarter financial information as described in the fifth paragraph of Note 1 as previously reported in the Company’s April 8, 2005 Form 10-K/A, (c) the restatement of the 2003 and 2004 consolidated financial statements and related 2003 fourth quarter and 2004 first, second and fourth quarter information as described in the sixth paragraph of Note 1 as reported in this Registration Statement on Form S-1 and (d) adjustments to the financial statements for the fourth quarter of 2004. Furthermore, these control deficiencies could result in a material misstatement in the aforementioned accounts that would result in a misstatement to the annual or interim consolidated financial statements that would not be prevented or detected. Accordingly these control deficiencies constitute a material weakness.

F-123

---

Table of Contents

F-124

---

Table of Contents

				Quarters Ended
				March 31				June 30				September 30				December 31				Total
				(Restated)(2)				(Restated)(2)								(Restated)(2)
				(In millions, except per common share amounts)
2004
	Operating revenues			$	1,557			$	1,524			$	1,429			$	1,364			$	5,874
	Loss on long-lived assets				238				17				582				271				1,108
	Operating income (loss)				189				370				(355	)			(14	)			190
	Income (loss) from continuing operations			$	(119	)		$	34			$	(202	)		$	(546	)		$	(833	)
	Discontinued operations, net of income taxes(1)				(77	)			(29	)			(12	)			4				(114	)
	Net income (loss)			$	(196	)		$	5			$	(214	)		$	(542	)		$	(947	)
	Basic and diluted earnings per common share
		Income (loss) from continuing operations		$	(0.19	)		$	0.05			$	(0.31	)		$	(0.86	)		$	(1.30	)
		Discontinued operations, net of income taxes			(0.12	)			(0.04	)			(0.02	)			0.01				(0.18	)
		Net income (loss)		$	(0.31	)		$	0.01			$	(0.33	)		$	(0.85	)		$	(1.48	)

				Quarters Ended
				March 31				June 30				September 30				December 31				Total
																(Restated)(2)
				(In millions, except per common share amounts)
2003
	Operating revenues			$	1,828			$	1,569			$	1,714			$	1,557			$	6,668
	Loss on long-lived assets				14				395				54				397				860
	Western Energy Settlement				—				123				(20	)			1				104
	Operating income (loss)				264				(272	)			481				(68	)			405
	Income (loss) from continuing operations			$	(207	)		$	(297	)		$	65			$	(156	)		$	(595	)
	Discontinued operations, net of income taxes(1)				(215	)			(939	)			(41	)			(84	)			(1,279	)
	Cumulative effect of accounting changes, net of income taxes				(9	)			—				—				—				(9	)
	Net income (loss)			$	(431	)		$	(1,236	)		$	24			$	(240	)		$	(1,883	)
	Basic and diluted earnings per common share
		Income (loss) from continuing operations		$	(0.34	)		$	(0.50	)		$	0.11			$	(0.26	)		$	(0.99	)
		Discontinued operations, net of income taxes			(0.36	)			(1.57	)			(0.07	)			(0.14	)			(2.14	)
		Cumulative effect of accounting changes, net of income taxes			(0.02	)			—				—				—				(0.02	)
		Net income (loss)		$	(0.72	)		$	(2.07	)		$	0.04			$	(0.40	)		$	(3.15	)

(1)	Our petroleum markets operations, our Canadian and certain other international natural gas and oil production operations, and our coal mining operations are classified as discontinued operations (See Note 3, on page F-62, for further discussion).
(2)	The table below reflects the amounts we originally reported in our Form 10-K filed on March 28, 2005. Items indicated with a (*) were not restated. See Note 1, on page F-46, to the consolidated financial statements for a further discussion of these restatements and the impact on each annual period.

			Quarters Ended
			March 31,				June 30,				December 31,				December 31,
			2004				2004				2004				2003
			(In millions, except per common share amounts)
Loss on long-lived assets			$	222				*				*				*
Operating income (loss)				205				*				*				*
Income (loss) from continuing operations				(97	)		$	45			$	(548	)		$	(84	)
Discontinued operations, net of income taxes				(109	)			*				*				(201	)
Net income (loss)				(206	)			16				(544	)			(285	)
Basic and diluted earnings per common share
	Income (loss ) from continuing operations		$	(0.15	)		$	0.07				*			$	(0.14	)
	Discontinued operations, net of income taxes			(0.17	)			*				*				(0.33	)
	Net income (loss)		$	(0.32	)		$	0.03				*			$	(0.47	)

F-125

---

Table of Contents

				United
				States				Brazil				Worldwide
2004
	Natural gas and oil properties:
		Costs subject to amortization(1)		$	14,211			$	337			$	14,548
		Costs not subject to amortization			308				112				420
					14,519				449				14,968
	Less accumulated depreciation, depletion and amortization				11,130				138				11,268
	Net capitalized costs			$	3,389			$	311			$	3,700
	FAS143 abandonment liability			$	252			$	4			$	256
2003
	Natural gas and oil properties:
		Costs subject to amortization(1)		$	14,052			$	146			$	14,198
		Costs not subject to amortization			371				117				488
					14,423				263				14,686
	Less accumulated depreciation, depletion and amortization				11,216				58				11,274
	Net capitalized costs			$	3,207			$	205			$	3,412
	FAS 143 abandonment liability			$	210			$	—			$	210

(1)	As of January 1, 2003, we adopted SFAS No. 143, which is further discussed in Note 1, on page F-46. Included in our costs subject to amortization at December 31, 2004 and 2003 are SFAS No. 143 asset values of $154 million and $124 million for the United States and $3 million and $0.2 million for Brazil.

					United
					States				Brazil				Worldwide
2004
	Property acquisition costs
		Proved properties			$	33			$	69			$	102
		Unproved properties				32				3				35
	Exploration costs(1)					185				25				210
	Development costs(1)					395				1				396
		Costs expended in 2004				645				98				743
	Asset retirement obligation costs					30				3				33
			Total costs incurred		$	675			$	101			$	776

F-126

---

Table of Contents

					United
					States				Brazil				Worldwide
2003
	Property acquisition costs
		Proved properties			$	10			$	—			$	10
		Unproved properties				35				4				39
	Exploration costs(1)					467				95				562
	Development costs(1)					668				—				668
		Costs expended in 2003				1,180				99				1,279
	Asset retirement obligation costs(2)					124				—				124
			Total costs Incurred		$	1,304			$	99			$	1,403
2002
	Property acquisition costs
		Proved properties			$	362			$	—			$	362
		Unproved properties				29				9				38
	Exploration costs					524				45				569
	Development costs					1,242				—				1,242
			Total costs incurred		$	2,157			$	54			$	2,211

(1)	Excludes approximately $110 million and $130 million that was paid in 2004 and 2003 under net profits agreements described beginning on page F-131.
(2)	In January 2003, we adopted SFAS No. 143, which is further discussed in Note 1, on page F-46. The cumulative effect of adopting SFAS No. 143 was $3 million.

			Cumulative				Costs Excluded												Cumulative
			Balance				for Years Ended												Balance
							December 31
			December 31,																December 31,
			2004				2004				2003				2002				2001
Worldwide(1)(2)
	Acquisition		$	209			$	76			$	51			$	61			$	21
	Exploration			178				62				92				18				6
	Development			33				1				3				27				2
			$	420			$	139			$	146			$	106			$	29

(1)	Includes operations in the United States and Brazil.
(2)	Includes capitalized interest of $20 million, $6 million, and less than $1 million for the years ended December 31, 2004, 2003, and 2002.

F-127

---

Table of Contents

				Natural Gas (in Bcf)
				United
				States				Brazil				Worldwide
Net proved developed and undeveloped reserves(1)
	January 1, 2002				2,799				—				2,799
		Revisions of previous estimates			(155	)			—				(155	)
		Extensions, discoveries and other			829				—				829
		Purchases of reserves in place			142				—				142
		Sales of reserves in place			(657	)			—				(657	)
		Production			(470	)			—				(470	)
	December 31, 2002				2,488				—				2,488
		Revisions of previous estimates			(24	)			—				(24	)
		Extensions, discoveries and other			405				—				405
		Purchases of reserves in place			2				—				2
		Sales of reserves in place(2)			(471	)			—				(471	)
		Production			(339	)			—				(339	)
	December 31, 2003				2,061				—				2,061
		Revisions of previous estimates			(172	)			—				(172	)
		Extensions, discoveries and other			79				38				117
		Purchases of reserves in place			15				38				53
		Sales of reserves in place(2)			(21	)			—				(21	)
		Production			(238	)			(7	)			(245	)
	December 31, 2004				1,724				69				1,793
Proved developed reserves
		December 31, 2002			1,799				—				1,799
		December 31, 2003			1,428				—				1,428
		December 31, 2004			1,287				54				1,341

(1)	Net proved reserves exclude royalties and interests owned by others and reflects contractual arrangements and royalty obligations in effect at the time of the estimate.
(2)	Sales of reserves in place include 20,729 MMcf and 28,779 MMcf of natural gas conveyed to third parties under net profits agreements in 2004 and 2003 as described beginning on page F-131.

F-128

---

Table of Contents

				Oil and Condensate (in MBbls)
				United
				States				Brazil				Worldwide
Net proved developed and undeveloped reserves(1)
	January 1, 2002				45,153				—				45,153
		Revisions of previous estimates			1,552				—				1,552
		Extensions, discoveries and other			7,921				—				7,921
		Purchases of reserves in place			62				—				62
		Sales of reserves in place			(3,754	)			—				(3,754	)
		Production			(12,580	)			—				(12,580	)
	December 31, 2002				38,354				—				38,354
		Revisions of previous estimates			895				—				895
		Extensions, discoveries and other			5,000				20,543				25,543
		Purchases of reserves in place			5				—				5
		Sales of reserves in place(2)			(4,328	)			—				(4,328	)
		Production			(7,555	)			—				(7,555	)
	December 31, 2003				32,371				20,543				52,914
		Revisions of previous estimates			(999	)			252				(747	)
		Extensions, discoveries and other			2,214				1,848				4,062
		Purchases of reserves in place			—				1,848				1,848
		Sales of reserves in place(2)			(1,276	)			—				(1,276	)
		Production			(4,979	)			(320	)			(5,299	)
	December 31, 2004				27,331				24,171				51,502
Proved developed reserves
		December 31, 2002			28,554				—				28,554
		December 31, 2003			22,821				—				22,821
		December 31, 2004			19,641				2,613				22,254

(1)	Net proved reserves exclude royalties and interests owned by others and reflects contractual agreements and royalty obligations in effect at the time of the estimate.
(2)	Sales of reserves in place include 1,276 MBbl and 1,098 MBbl of liquids conveyed to third parties under net profits agreements in 2004 and 2003 as described beginning on page F-131.

F-129

---

Table of Contents

				NGL (in MBbls)
				United
				States				Brazil				Worldwide
Net proved developed and undeveloped reserves(1)
	January 1, 2002				28,874				—				28,874
		Revisions of previous estimates			(2,289	)			—				(2,289	)
		Extensions, discoveries and other			6,820				—				6,820
		Purchases of reserves in place			—				—				—
		Sales of reserves in place			(7,916	)			—				(7,916	)
		Production			(3,882	)			—				(3,882	)
	December 31, 2002				21,607				—				21,607
		Revisions of previous estimates			(2,717	)			—				(2,717	)
		Extensions, discoveries and other			1,795				—				1,795
		Purchases of reserves in place			27				—				27
		Sales of reserves in place(2)			(504	)			—				(504	)
		Production			(4,223	)			—				(4,223	)
	December 31, 2003				15,985				—				15,985
		Revisions of previous estimates			724				—				724
		Extensions, discoveries and other			58				—				58
		Purchases of reserves in place			—				—				—
		Sales of reserves in place(2)			(47	)			—				(47	)
		Production			(3,519	)			—				(3,519	)
	December 31, 2004				13,201				—				13,201
Proved developed reserves
		December 31, 2001			17,526				—				17,526
		December 31, 2002			14,088				—				14,088
		December 31, 2003			11,943				—				11,943

(1)	Net proved reserves exclude royalties and interests owned by others and reflects contractual agreements and royalty obligations in effect at the time of the estimate.
(2)	Sales of reserves in place include 47 MBbl and 194 MBbl of NGL conveyed to third parties under net profits agreements in 2004 and 2003 as described below.

F-130

---

Table of Contents

F-131

---

Table of Contents

					United
					States				Brazil				Worldwide
2004
	Net Revenues
		Sales to external customers			$	518			$	27			$	545
		Affiliated sales				1,137				(1	)			1,136
			Total			1,655				26				1,681
	Production costs(1)					(210	)			—				(210	)
	Depreciation, depletion and amortization(2)					(530	)			(18	)			(548	)
						915				8				923
	Income tax (expense) benefit					(333	)			(3	)			(336	)
	Results of operations from producing activities				$	582			$	5			$	587
2003
	Net Revenues
		Sales to external customers			$	191			$	—			$	191
		Affiliated sales				1,868				—				1,868
			Total			2,059				—				2,059
	Production costs(1)					(229	)			—				(229	)
	Depreciation, depletion and amortization(2)					(576	)			—				(576	)
	Ceiling test charges					—				(5	)			(5	)
						1,254				(5	)			1,249
	Income tax (expense) benefit					(449	)			2				(447	)
	Results of operations from producing activities				$	805			$	(3	)		$	802
2002
	Net Revenues
		Sales to external customers			$	134			$	—			$	134
		Affiliated sales				1,677				—				1,677
			Total			1,811				—				1,811
	Production costs(1)					(284	)			—				(284	)
	Depreciation, depletion and amortization					(599	)			—				(599	)
	Gain on long-lived assets					2				—				2
						930				—				930
	Income tax (expense) benefit					(327	)			—				(327	)
	Results of operations from producing activities				$	603			$	—			$	603

(1)	Production cost includes lease operating costs and production related taxes, including ad valorem and severance taxes.
(2)	In January 2003, we adopted SFAS No. 143, which is further discussed in Note 1, on page F-46. Our depreciation, depletion and amortization includes accretion expense for SFAS 143 abandonment liabilities of $23 million primarily for the United States for both 2004 and 2003.

F-132

---

Table of Contents

		United
		States				Brazil				Worldwide
2004
Future cash inflows(1)		$	11,895			$	1,077			$	12,972
Future production costs			(3,585	)			(135	)			(3,720	)
Future development costs			(1,234	)			(274	)			(1,508	)
Future income tax expenses			(1,184	)			(141	)			(1,325	)
Future net cash flows			5,892				527				6,419
10% annual discount for estimated timing of cash flows			(2,004	)			(219	)			(2,223	)
Standardized measure of discounted future net cash flows		$	3,888			$	308			$	4,196
Standardized measure of discounted future net cash flows, including effects of hedging activities		$	3,907			$	305			$	4,212
2003
Future cash inflows(1)		$	13,302			$	588			$	13,890
Future production costs			(3,025	)			(65	)			(3,090	)
Future development costs			(1,325	)			(236	)			(1,561	)
Future income tax expenses			(1,695	)			(75	)			(1,770	)
Future net cash flows			7,257				212				7,469
10% annual discount for estimated timing of cash flows			(2,449	)			(128	)			(2,577	)
Standardized measure of discounted future net cash flows		$	4,808			$	84			$	4,892
Standardized measure of discounted future net cash flows, including effects of hedging activities		$	4,759			$	84			$	4,843
2002
Future cash inflows(1)		$	12,847			$	—			$	12,847
Future production costs			(2,924	)			—				(2,924	)
Future development costs			(1,361	)			—				(1,361	)
Future income tax expenses			(1,960	)			—				(1,960	)
Future net cash flows			6,602				—				6,602
10% annual discount for estimated timing of cash flows			(2,293	)			—				(2,293	)
Standardized measure of discounted future net cash flows		$	4,309			$	—			$	4,309
Standardized measure of discounted future net cash flows, including effects of hedging activities		$	4,266			$	—			$	4,266

(1)	United States excludes $1 million, $104 million and $85 million of future net cash outflows attributable to hedging activities in the years 2004, 2003 and 2002. Brazil excludes $5 million of future net cash outflows attributable to hedging activities in 2004.

F-133

---

Table of Contents

		Years Ended December 31,(1),(2)
		2004				2003				2002
		(In Millions)
Sales and transfers of natural gas and oil produced net of production costs		$	(1,470	)		$	(1,829	)		$	(1,526	)
Net changes in prices and production costs			29				1,586				3,301
Extensions, discoveries and improved recovery, less related costs			268				1,105				1,561
Changes in estimated future development costs			4				(16	)			17
Previously estimated development costs incurred during the period			156				220				275
Revision of previous quantity estimates			(453	)			(94	)			(348	)
Accretion of discount			568				526				275
Net change in income taxes			257				159				(934	)
Purchases of reserves in place			114				5				284
Sale of reserves in place			(75	)			(1,229	)			(1,418	)
Change in production rates, timing and other			(94	)			150				93
Net change		$	(696	)		$	583			$	1,580

F-134

---

Table of Contents

							Charged
			Balance at				to Costs								Charged				Balance
			Beginning				and								to Other				at End
Description			of Period				Expenses				Deductions				Accounts				of Period
2004
	Allowance for doubtful accounts		$	273			$	(48	)		$	(22	)(1)		$	(4	)		$	199
	Valuation allowance on deferred tax assets			9				46	(3)			(4	)			—				51
	Legal reserves			1,169				145				(655	)(5)			(67	)			592
	Environmental reserves			412				17				(51	)(5)			2				380
	Regulatory reserves			13				—				(12	)(5)			—				1
2003
	Allowance for doubtful accounts		$	176			$	18			$	(31	)(1)		$	110	(2)		$	273
	Valuation allowance on deferred tax assets			72				4				(68	)(3)			1				9
	Legal reserves			1,031				180	(4)			(43	)(5)			1				1,169
	Environmental reserves			389				8				(52	)(5)			67	(6)			412
	Regulatory reserves			24				32				(43	)(5)			—				13
2002
	Allowance for doubtful accounts		$	117			$	30			$	(14	)(1)		$	43	(2)		$	176
	Valuation allowance on deferred tax assets			28				46	(3)			(2	)			—				72
	Legal reserves			149				954	(4)			(74	)(5)			2				1,031
	Environmental reserves			468				(3	)			(63	)			(13	)			389
	Regulatory reserves			34				48				(59	)(5)			1				24

(1)	Relates primarily to accounts written off.
(2)	Relates primarily to receivables from trading counterparties, reclassified due to bankruptcy or declining credit that have been accounted for within our price risk management activities.
(3)	Relates primarily to valuation allowances for deferred tax assets related to the Western Energy Settlement, foreign ceiling test charges, foreign asset impairments and net operating loss carryovers.
(4)	Relates to our Western Energy Settlement of $104 million in 2003 and $899 million in 2002. In June 2004, we released approximately $602 million to the settling parties (including approximately $568 million from escrow) and correspondingly reduced our liability by this amount.
(5)	Relates primarily to payments for various litigation reserves, including the Western Energy Settlement, environmental remediation reserves or revenue crediting and rate settlement reserves.
(6)	Relates primarily to liabilities previously classified in our petroleum discontinued operations, but reclassified as continuing operations due to our retention of these obligations.

F-135

---

Table of Contents

FA-1

---

Table of Contents

FA-2

---

Table of Contents

FA-3

---

Table of Contents

				2004				2003
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents			$	125,781			$	173,651
	Accounts and notes receivable — related parties				54,368				43,805
	Accounts receivable				42,984				38,333
	Gas inventory				17,509				20,298
	Unamortized property taxes				18,060				17,672
	Derivative assets				94,977				86,825
	Broker margin accounts, and prepaid gas costs and expenses				13,147				8,101
		Total current assets			366,826				388,685
PROPERTY, PLANT AND EQUIPMENT:
	Property, plant and equipment				2,466,944				2,463,931
	Pipeline				21,432				21,432
		Total property, plant and equipment			2,488,376				2,485,363
	Accumulated depreciation				(1,062,821	)			(991,556	)
		Net property, plant and equipment			1,425,555				1,493,807
OTHER ASSETS:
	Restricted investment securities held-to-maturity				139,410				139,755
	Derivative assets non-current				24,337				18,100
	Deferred financing costs, net of accumulated amortization of $18,498 and $17,285, respectively				6,467				7,680
	Prepaid gas costs, spare parts deposit, materials and supplies				17,782				21,623
		Total other assets			187,996				187,158
TOTAL ASSETS				$	1,980,377			$	2,069,650
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
	Accounts payable and accrued liabilities			$	82,693			$	57,368
	Gas supplier funds on deposit				19,613				4,517
	Interest payable				47,738				53,009
	Current portion of long-term debt				76,548				134,576
		Total current liabilities			226,592				249,470
NON-CURRENT LIABILITIES:
	Long-term debt				942,097				1,018,645
	Other				1,712				2,459
		Total non-current liabilities			943,809				1,021,104
COMMITMENTS AND CONTINGENCIES (Notes 7 and 8)
TOTAL LIABILITIES					1,170,401				1,270,574
PARTNERS’ EQUITY					809,976				799,076
TOTAL LIABILITIES AND PARTNERS’ EQUITY				$	1,980,377			$	2,069,650

FA-4

---

Table of Contents

				2004				2003				2002
OPERATING REVENUES:
	Capacity			$	405,415			$	404,681			$	404,713
	Electric				225,154				162,093				177,569
	Steam				19,090				17,638				14,537
		Total operating revenues			649,659				584,412				596,819
OPERATING EXPENSES:
	Fuel costs				413,061				254,988				255,142
	Depreciation				88,712				89,437				88,963
	Operations				18,769				16,943				16,642
	Maintenance				13,508				15,107				12,666
	Property and single business taxes				28,834				30,040				27,087
	Administrative, selling and general				11,236				9,959				8,195
		Total operating expenses			574,120				416,474				408,695
OPERATING INCOME					75,539				167,938				188,124
OTHER INCOME (EXPENSE):
	Interest and other income				5,460				5,100				5,555
	Interest expense				(104,618	)			(113,247	)			(119,783	)
		Total other income (expense), net			(99,158	)			(108,147	)			(114,228	)
NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE					(23,619	)			59,791				73,896
Cumulative effect of change in method of accounting for derivative option contracts (to April 1, 2002) (Note 2)					—				—				58,131
NET INCOME (LOSS)				$	(23,619	)		$	59,791			$	132,027

FA-5

---

Table of Contents

				General				Limited
				Partners				Partners				Total
BALANCE, DECEMBER 31, 2001				$	468,972			$	82,740			$	551,712
Comprehensive Income
	Net Income				114,947				17,080				132,027
	Other Comprehensive Income
		Unrealized gain on hedging activities since beginning of period			33,311				4,950				38,261
		Reclassification adjustments recognized in net income above			10,717				1,593				12,310
		Total other comprehensive income			44,028				6,543				50,571
	Total Comprehensive Income				158,975				23,623				182,598
BALANCE, DECEMBER 31, 2002				$	627,947			$	106,363			$	734,310
Comprehensive Income
	Net Income				52,056				7,735				59,791
	Other Comprehensive Income
		Unrealized gain on hedging activities since beginning of period			34,484				5,125				39,609
		Reclassification adjustments recognized in net income above			(30,153	)			(4,481	)			(34,634	)
		Total other comprehensive income			4,331				644				4,975
	Total Comprehensive Income				56,387				8,379				64,766
BALANCE, DECEMBER 31, 2003				$	684,334			$	114,742			$	799,076
Comprehensive Income
	Net Loss				(20,563	)			(3,056	)			(23,619	)
	Other Comprehensive Income
		Unrealized gain on hedging activities since beginning of period			62,292				9,256				71,548
		Reclassification adjustments recognized in net income above			(32,239	)			(4,790	)			(37,029	)
		Total other comprehensive income			30,053				4,466				34,519
	Total Comprehensive Income				9,490				1,410				10,900
BALANCE, DECEMBER 31, 2004				$	693,824			$	116,152			$	809,976

FA-6

---

Table of Contents

				2004				2003				2002
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net income (loss)			$	(23,619	)		$	59,791			$	132,027
	Adjustments to reconcile net income to net cash provided by operating activities
	Depreciation and amortization				89,925				90,792				90,430
	Cumulative effect of change in accounting principle				—				—				(58,131	)
	(Increase) decrease in accounts receivable				(15,214	)			(1,211	)			48,343
	(Increase) decrease in gas inventory				2,789				(732	)			133
	(Increase) decrease in unamortized property taxes				(388	)			683				(1,730	)
	(Increase) decrease in broker margin accounts and prepaid expenses				(5,046	)			(4,778	)			31,049
	(Increase) decrease in derivative assets				20,130				4,906				(20,444	)
	(Increase) decrease in prepaid gas costs, materials and supplies				3,841				(8,704	)			1,376
	Increase (decrease) in accounts payable and accrued liabilities				25,775				(712	)			8,774
	Increase in gas supplier funds on deposit				15,096				4,517				—
	Decrease in interest payable				(5,271	)			(3,377	)			(3,948	)
	Increase (decrease) in other non-current liabilities				(1,197	)			311				(24	)
		Net cash provided by operating activities			106,821				141,486				227,855
CASH FLOWS FROM INVESTING ACTIVITIES:
	Plant modifications and purchases of plant equipment				(20,460	)			(33,278	)			(29,529	)
	Maturity of restricted investment securities held-to-maturity				674,553				601,225				377,192
	Purchase of restricted investment securities held-to-maturity				(674,208	)			(602,279	)			(374,426	)
		Net cash used in investing activities			(20,115	)			(34,332	)			(26,763	)
CASH FLOWS FROM FINANCING ACTIVITIES:
	Repayment of financing obligation				(134,576	)			(93,928	)			(182,084	)
		Net cash used in financing activities			(134,576	)			(93,928	)			(182,084	)
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS					(47,870	)			13,226				19,008
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD					173,651				160,425				141,417
CASH AND EQUIVALENTS AT END OF PERIOD				$	125,781			$	173,651			$	160,425

FA-7

---

Table of Contents

(1)	The Partnership and Associated Risks

FA-8

---

Table of Contents

(2)	Significant Accounting Policies

FA-9

---

Table of Contents

	Principles of Consolidation

	Revenue Recognition

	Fuel Costs

	Accounts Receivable

FA-10

---

Table of Contents

	Inventory

	Materials and Supplies

	Depreciation

	Federal Income Tax

	Statement of Cash Flows

	Fair Value of Financial Instruments

	Accounting for Derivative Instruments and Hedging Activities

FA-11

---

Table of Contents

	Electric Sales Agreements

	Natural Gas Supply Contracts

FA-12

---

Table of Contents

	Natural Gas Supply Futures and Options

FA-13

---

Table of Contents

	New Accounting Standard

(3)	Restricted Investment Securities Held-to-Maturity

		2004				2003
Funds restricted for rental payments pursuant to the Overall Lease Transaction		$	138,150			$	137,296
Funds restricted for management non-qualified plans			1,260				2,459
Total		$	139,410			$	139,755

(4)	Accounts Payable and Accrued Liabilities

			2004				2003
Accounts payable
	Related parties		$	12,772			$	7,386
	Trade creditors			53,476				34,786
Property and single business taxes				11,833				12,548
Other				4,612				2,648
Total			$	82,693			$	57,368

(5)	Gas Supplier Funds on Deposit

FA-14

---

Table of Contents

(6)	Long-Term Debt

		2004				2003
Financing obligation, maturing through 2015, payable in semi-annual installments of principal and interest, collateralized by property, plant and equipment		$	1,018,645			$	1,153,221
Less current portion			(76,548	)			(134,576	)
Total long-term debt		$	942,097			$	1,018,645

	Financing Obligation

FA-15

---

Table of Contents

		Principal				Interest				Total
2005		$	76,548			$	97,835			$	174,383
2006			63,459				92,515				155,974
2007			62,916				87,988				150,904
2008			67,753				83,163				150,916
2009			70,335				76,755				147,090
		$	341,011			$	438,256			$	779,267

FA-16

---

Table of Contents

(7)	Commitments and Other Agreements

FA-17

---

Table of Contents

FA-18

---

Table of Contents

(8)	Contingencies

	Property Taxes

	NOx Allowances

	Environmental Issues

FA-19

---

Table of Contents

(9)	Voluntary Severance Program

(10)	Retirement Benefits

	Postretirement Health Care Plans

FA-20

---

Table of Contents

		2004				2003
Change in benefit obligation:
Benefit obligation at beginning of year		$	3,276.0			$	2,741.9
Service cost			232.1				212.5
Interest cost			174.8				178.2
Actuarial gain (loss)			1,298.0				147.4
Benefits paid during year			(8.3	)			(4.0	)
Benefit obligation at end of year			4,972.6				3,276.0
Change in Plan assets:
Fair value of Plan assets at beginning of year			2,826.8				2,045.8
Actual return on Plan assets			292.7				527.5
Employer contribution			206.5				257.5
Benefits paid during year			(8.3	)			(4.0	)
Fair value of Plan assets at end of year			3,317.7				2,826.8
Unfunded (funded) status			1,654.9				449.2
Unrecognized prior service cost			(155.9	)			(170.3	)
Unrecognized net gain (loss)			(1,499.0	)			(278.9	)
Accrued benefit cost		$	—			$	—

		2004				2003				2002
Components of net periodic benefit cost:
Service cost		$	232.1			$	212.5			$	197.3
Interest cost			174.8				178.2				188.7
Expected return on Plan assets			(216.1	)			(163.7	)			(167.0	)
Amortization of unrecognized net (gain) or loss			15.7				30.5				14.3
Net periodic benefit cost		$	206.5			$	257.5			$	233.3

		1-Percentage-				1-Percentage
		Point				Point
		Increase				Decrease
Effect on total of service and interest cost components		$	51.6			$	44.7
Effect on postretirement benefit obligation		$	514.8			$	447.1

FA-21

---

Table of Contents

			2004				2003				2002
Discount rate				5.75%				6.00%				6.75%
Long-term rate of return on Plan assets				8.00%				8.00%				8.00%
Inflation benefit amount
	1998 through 2004			0.00%				0.00%				0.00%
	2005 and later years			5.00%				4.00%				4.00%

			2004				2003
Asset Category:
Cash and cash equivalents				1	%			11	%
Fixed income				19	%			17	%
Equity securities				80	%			72	%
	Total			100	%			100	%

FA-22

---

Table of Contents

(11)	Partners’ Equity and Related Party Transactions

Beneficial Owner, Equity Partner,				Equity
Type of Partner and Nature of Related Party				Interest				Interest				Related Party Transactions and Agreements		2004				2003				2002
CMS Energy Company
CMS Midland, Inc.				$	396,888				49.0	%		Power purchase agreements		$	601,535			$	513,774			$	557,149
	General Partner; wholly-owned											Purchases under gas transportation
	subsidiary of Consumers Energy											agreements			9,349				14,294				23,552
	Company											Purchases under spot gas agreements			—				663				3,631
												Purchases under gas supply agreements			—				2,330				11,306
												Gas storage agreement			2,563				2,563				2,563
												Land lease/easement agreements			600				600				600
												Accounts receivable			50,364				40,373				44,289
												Accounts payable			1,031				1,025				3,502
												Sales under spot gas agreements			—				3,260				1,084
El Paso Corporation				$	141,397				18.1	%
Source Midland Limited Partnership												Purchase under gas transportation
	(“SMLP”)											agreements			12,334				13,023				12,463
	General Partner; owned by											Purchases under spot gas agreement			—				610				15,655
	subsidiaries of El Paso Corporation											Purchases under gas supply agreement			70,000				54,308				47,136
												Gas agency agreement			264				238				365
												Deferred reservation charges under gas
												purchase agreement			3,152				4,728				—
												Accounts receivable			—				—				523
												Accounts payable			10,997				5,751				7,706
												Sales under spot gas agreements			—				3,474				14,007
El Paso Midland, Inc. (“El Paso Midland”)					84,838				10.9			See related party activity listed under
	General Partner; wholly-owned subsidiary of El Paso Corporation											SMLP.
MEI Limited Partnership (“MEI”)												See related party activity listed under
	A General and Limited Partner; 50% interest owned by El Paso Midland, Inc. and 50% interest owned by SMLP											SMLP.
		General Partnership Interest			70,701				9.1
		Limited Partnership Interest			7,068				.9
Micogen Limited Partnership (“MLP”)					35,348				4.5			See related party activity listed under
	Limited Partner, owned subsidiaries of El Paso Corporation											SMLP.
		Total El Paso Corporation		$	339,352				43.5	%
The Dow Chemical Company
The Dow Chemical Company				$	73,735				7.5	%		Steam and electric power agreement			39,055				36,207				29,385
	Limited Partner											Steam purchase agreement — Dow Corning
												Corp (affiliate)			4,289				4,017				3,746
												Purchases under demineralized water
												supply agreement			8,142				6,396				6,605
												Accounts receivable			4,003				3,431				3,635
												Accounts payable			744				610				1,016
												Standby and backup fees			766				731				734
												Sales of gas under tolling agreement			—				—				6,442
Alanna Corporation
Alanna Corporation				$	1	(1)			.00001	%		Note receivable			1				1				1
	Limited Partner; wholly-owned subsidiary of Alanna Holdings Corporation

(1)	Alanna’s capital stock is pledged to secure MCV’s obligation under the lease and other overall lease transaction documents.

FA-23

---

Table of Contents

FB-1

---

Table of Contents

								Pro Forma
								Adjustments
								Other
				El Paso				Asia Power
				Historical				Assets				Pro Forma
ASSETS
Current assets
	Cash and cash equivalents			$	1,540			$	180	(a)		$	1,710
									(10	)(a)
	Accounts and notes receivable, net				1,216				(8	)(a)			1,208
	Other				2,050				(6	)(a)			2,044
		Total current assets			4,806				156				4,962
Property, plant and equipment, net					18,687				(6	)(a)			18,681
Other assets
	Investments in unconsolidated affiliates				2,275				(100	)(a)			2,175
	Other				3,908				(45	)(a)			3,863
		Total assets		$	29,676			$	5			$	29,681
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
	Accounts payable			$	1,199			$	(8	)(a)		$	1,191
	Short-term financing obligations, including current maturities				1,099								1,099
	Other				2,361				(6	)(a)			2,355
		Total current liabilities			4,659				(14	)			4,645
Long-term debt					16,379								16,379
Other liabilities
	Deferred income taxes				1,528				(5	)(a)			1,523
	Other				3,251								3,251
Commitments and contingencies													—
Securities of subsidiaries					59				(3	)(a)			56
Stockholders’ equity
	Preferred stock				750								750
	Common stock				1,959								1,959
	Additional paid-in-capital				4,431								4,431
	Accumulated deficit				(2,941	)			18	(a)			(2,918	)
									5	(a)
	Other				(399	)			4	(a)			(395	)
		Total stockholders’ equity			3,800				27				3,827
		Total liabilities and stockholders’ equity		$	29,676			$	5			$	29,681

FB-2

---

Table of Contents

							Pro Forma Adjustments
											Other
			El Paso				GulfTerra/				Asia Power
			Historical				Enterprise				Assets				Pro Forma
Operating revenues			$	2,366			$				$	(28	)(b)		$	2,338
Operating expenses
	Cost of products and services			159												159
	Operation and maintenance			880								(27	)(b)			853
	Depreciation, depletion and amortization			574								(3	)(b)			571
	Loss on long-lived assets			381								(37	)(b)			344
	Taxes, other than income taxes			136												136
				2,130								(67	)			2,063
Operating income				236								39				275
Earnings from unconsolidated affiliates				171				(183	)(e)			55	(b)			43
Other income, net				104								(1	)(b)			103
Interest and debt expense				(690	)											(690	)
Distributions on preferred interests of consolidated subsidiaries				(9	)											(9	)
Income (loss) before income taxes				(188	)			(183	)			93				(278	)
Income taxes				(57	)			(64	)(f)			69	(c)			(52	)
Income (loss) from continuing operations			$	(131	)		$	(119	)		$	24			$	(226	)
Basic and diluted income per common share from continuing operations			$	(0.22	) (d)										$	(0.37	) (d)
Basic and diluted average common shares outstanding				640												640

FB-3

---

Table of Contents

							Pro Forma Adjustments
											Other
			El Paso				GulfTerra/				Asia Power
			Historical				Enterprise				Assets				Pro Forma
Operating revenues			$	5,874			$	(722	) (e)		$	(52	) (b)		$	5,100
Operating expenses
	Cost of products and services			1,363				(528	)(e)							835
	Operation and maintenance			1,872				(12	)(e)			(48	)(b)			1,812
	Depreciation, depletion and amortization			1,088				(8	)(e)			(7	)(b)			1,073
	Loss on long-lived assets			1,108				(491	)(e)			(30	)(b)			587
	Taxes, other than income taxes			253				(2	)(e)							251
				5,684				(1,041	)			(85	)			4,558
Operating income				190				319				33				542
Earnings from unconsolidated affiliates				546				(613	)(e)			118	(b)			51
Other income, net				94								(2	)(b)			92
Interest and debt expense				(1,607	)							1	(b)			(1,606	)
Distributions on preferred interests of consolidated subsidiaries				(25	)											(25	)
Income (loss) before income taxes				(802	)			(294	)			150				(946	)
Income taxes				31				(242	)(f)			(8	)(c)			(219	)
Income (loss) from continuing operations			$	(833	)		$	(52	)		$	158			$	(727	)
Basic and diluted loss per common share from continuing operations			$	(1.30	)										$	(1.14	)
Basic and diluted average common shares outstanding				639												639

FB-4

---

Table of Contents

	Other Asian Power Assets

	GulfTerra/Enterprise

	These amounts represent the historical results related to our interests in Enterprise and GulfTerra which were accounted for as equity investments and the nine processing plants sold to affiliates of EPCO, Inc. for the period presented. The pro forma adjusting entries reflect the following transactions:

	•	The sale of all of our interest in the general partner of Enterprise and GulfTerra;
	•	The elimination of all effects of our common units of GulfTerra and Enterprise and Series C units of GulfTerra; and
	•	The elimination of all non-affiliated effects of the nine processing plants sold.

	Other Asian Power Assets

	(1) Receipt of anticipated proceeds of $180 million from the sale of these interests based on bids received.
	(2) Elimination of the individual assets and liabilities of the consolidated power plants and our interests in the unconsolidated power plants.
	(3) Recognition of a gain on the sale of our interests in the Asian power assets of $18 million.
	(4) Recognition of the income tax liability of $5 million on the gain on the sale.

FB-5

---

Table of Contents

	GulfTerra/Enterprise

	(1) Adjustment for the historical results of operations for our nine processing plants, including impairment charges recorded during 2004 on these assets;
	(2) Reduction of earnings from unconsolidated affiliates in 2004 for (i) all of our general partner interests in Enterprise and GulfTerra, (ii) all of our Series C units in GulfTerra and (iii) all of the common units sold in both GulfTerra and Enterprise; and
	(3) Elimination of gains and losses on long-lived assets during 2004 on sales of our Enterprise and GulfTerra interests, and during 2005 on the sale of our remaining interest in Enterprise.

FB-6

---

Table of Contents

---

Table of Contents

ITEM 13.	OTHER EXPENSES OF ISSUANCE AND DISTRIBUTION

SEC registration fee			$	88,000
Printing and engraving expenses				100,000
Legal fees and expenses				150,000
Accounting fees and expenses				75,000
Miscellaneous				50,000
	Total		$	463,000

ITEM 14.	INDEMNIFICATION OF DIRECTORS AND OFFICERS

II-1

---

Table of Contents

ITEM 15.	RECENT SALES OF UNREGISTERED SECURITIES

ITEM 16.	EXHIBITS

Exhibit No.				Exhibit
	2	.A		Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (including the form of Assumption Agreement to be entered into in connection with the merger, attached as an exhibit thereto) (Exhibit 2.1 to our Form 8-K filed December 15, 2003)

II-2

---

Table of Contents

Exhibit No.				Exhibit
	2	.B		Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (including the form of Second Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, to be entered into in connection with the merger, attached as an exhibit thereto) (Exhibit 2.2 to our Form 8-K filed December 15, 2003); Amendment No. 1 to Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company, dated as of April 19, 2004 (including the forms of Second Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, Exchange and Registration Rights Agreement and Performance Guaranty, to be entered into by the parties named therein in connection with the merger of Enterprise and GulfTerra, attached as Exhibits 1, 2 and 3, respectively, thereto) (Exhibit 2.1 to our Form 8-K filed April 21, 2004); Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003 (Exhibit 2.3 to our Form 8-K filed December 15, 2003); Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (Exhibit 2.4 to our Form 8-K filed December 15, 2003)
	2	.B.1		Purchase and Sale Agreement, dated as of January 14, 2005, by and among Enterprise GP Holdings, L.P., Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso Corporation and GulfTerra GP Holding Company (Exhibit 2.B.1 to our 2004 Form 10-K)
	3	.A		Amended and Restated Certificate of Incorporation effective as of May 26, 2005 (Exhibit 3.A to our Current Report on Form 8-K filed May 27, 2005)
	3	.B		By-Laws effective as of July 31, 2003 (Exhibit 3.B to our 2003 Second Quarter Form 10-Q)
	4	.A		Indenture dated as of May 10, 1999, by and between El Paso and HSBC Bank USA, National Association (as successor-in-interest to JPMorgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4.A to our 2004 Form 10-K)
	4	.B		Certificate of Designations of 4.99% Convertible Perpetual Preferred Stock (included in Exhibit 3.A to our Current Report on Form 8-K filed May 27, 2005)
	4	.C		Registration Rights Agreement, dated April 15, 2005, by and among El Paso Corporation and the Initial Purchasers party thereto (Exhibit 4.A to our Current Report on Form 8-K filed April 15, 2005)
	*5	.A		Opinion of Andrews Kurth LLP as to the legality of the common stock (to be filed by amendment)
	10	.A		Amended and Restated Credit Agreement dated as of November 23, 2004, among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent (Exhibit 10.A to our Form 8-K filed November 29, 2004); Amended and Restated Subsidiary Guarantee Agreement dated as of November 23, 2004, made by each of the Subsidiary Guarantors, as defined therein, in favor of JPMorgan Chase Bank, N.A., as collateral agent (Exhibit 10.C to our Form 8-K filed November 29, 2004); Amended and Restated Parent Guarantee Agreement dated as of November 23, 2004, made by El Paso Corporation, in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.D to our Form 8-K filed November 29, 2004)
	10	.B		Amended and Restated Security Agreement dated as of November 23, 2004, among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank (Exhibit 10.B to our Form 8-K filed November 29, 2004)

II-3

---

Table of Contents

Exhibit No.				Exhibit
	10	.C		$3,000,000,00 Revolving Credit Agreement dated as of April 16, 2003 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company and ANR Pipeline Company, as Borrowers, the Lenders Party thereto, and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Document Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as Joint Bookrunners and Co-Lead Arrangers (Exhibit 99.1 to our Form 8-K filed April 18, 2003); First Amendment to the $3,000,000,000 Revolving Credit Agreement and Waiver dated as of March 17, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lender and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents (Exhibit 10.A.1 to our 2003 Form 10-K); Second Waiver to the $3,000,000,000 Revolving Credit Agreement dated as of June 15, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents (Exhibit 10.A.2 to our 2003 Form 10-K); Second Amendment to the $3,000,000,000 Revolving Credit Agreement and Third Waiver dated as of August 6, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents (Exhibit 99.B to our Form 8-K filed August 10, 2004)
	10	.D		$1,000,000,000 Amended and Restated 3-Year Revolving Credit Agreement dated as of April 16, 2003 among El Paso Corporation, El Paso Natural Gas Company and Tennessee Gas Pipeline Company, as Borrowers, The Lenders Party Thereto, and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Document Agents, Bank of America, N.A., as Syndication Agent, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as Joint Bookrunners and Co-Lead Arrangers. (Exhibit 99.2 to our Form 8-K filed April 18, 2003)
	10	.E		Security and Intercreditor Agreement dated as of April 16, 2003 Among El Paso Corporation, the Persons Referred to therein as Pipeline Company Borrowers, the Persons Referred to therein as Grantors, Each of the Representative Agents, JPMorgan Chase Bank, as Credit Agreement Administrative Agent and JPMorgan Chase Bank, as Collateral Agent, Intercreditor Agent, and Depository Bank. (Exhibit 99.3 to our Form 8-K filed April 18, 2003)
	+10	.F		1995 Compensation Plan for Non-Employee Directors Amended and Restated effective as of December 4, 2003 (Exhibit 10.F to our 2003 Form 10-K)
	+10	.G		Stock Option Plan for Non-Employee Directors Amended and Restated effective as of January 20, 1999 (Exhibit 10.G to our 2004 Form 10-K); Amendment No. 1 effective as of July 16, 1999 to the Stock Option Plan for Non-Employee Directors (Exhibit 10.G.1 to our 2004 Form 10-K); Amendment No. 2 effective as of February 7, 2001 to the Stock Option Plan for Non-Employee Directors (Exhibit 10.F.1 to our 2001 First Quarter Form 10-Q)
	+10	.H		2001 Stock Option Plan for Non-Employee Directors effective as of January 29, 2001 (Exhibit 10.1 to our Form S-8, Registration No. 333-64240, filed June 29, 2001); Amendment No. 1 effective as of February 7, 2001 to the 2001 Stock Option Plan for Non-Employee Directors (Exhibit 10.G.1 to our 2001 Form 10-K); Amendment No. 2 effective as of December 4, 2003 to the 2001 Stock Option Plan for Non-Employee Directors (Exhibit 10.H.1 to our 2003 Form 10-K)
	+10	.I		1995 Omnibus Compensation Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.I to our 2004 Form 10-K); Amendment No. 1 effective as of December 3, 1998 to the 1995 Omnibus Compensation Plan (Exhibit 10.I.1 to our 2004 Form 10-K); Amendment No. 2 effective as of January 20, 1999 to the 1995 Omnibus Compensation Plan (Exhibit 10.I.2 to our 2004 Form 10-K)

II-4

---

Table of Contents

Exhibit No.				Exhibit
	+10	.J		1999 Omnibus Incentive Compensation Plan dated January 20, 1999 (Exhibit 10.1 to our Form S-8, Registration No. 333-78979, filed May 20, 1999); Amendment No. 1 effective as of February 7, 2001 to the 1999 Omnibus Incentive Compensation Plan (Exhibit 10.V.1 to our 2001 First Quarter Form  10-Q); Amendment No. 2 effective as of May 1, 2003 to the 1999 Omnibus Incentive Compensation Plan (Exhibit 10.I.1 to our 2003 Second Quarter Form 10-Q)
	+10	.K		2001 Omnibus Incentive Compensation Plan effective as of January 29, 2001 (Exhibit 10.1 to our Form S-8, Registration No. 333-64236, filed June 29, 2001); Amendment No. 1 effective as of February 7, 2001 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to our 2001 Form 10-K); Amendment No. 2 effective as of April 1, 2001 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to our 2002 Form 10-K); Amendment No. 3 effective as of July 17, 2002 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to our 2002 Second Quarter Form 10-Q); Amendment No. 4 effective as of May 1, 2003 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to our 2003 Second Quarter Form 10-Q); Amendment No. 5 effective as of March 8, 2004 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.K.1 to our 2003 Form 10-K)
	+10	.L		Supplemental Benefits Plan Amended and Restated effective December 7, 2001 (Exhibit 10.K to our 2001 Form 10-K); Amendment No. 1 effective as of November 7, 2002 to the Supplemental Benefits Plan (Exhibit 10.K.1 to our 2002 Form 10-K); Amendment No. 3 effective December 17, 2004 to the Supplemental Benefits Plan (Exhibit 10.UU to our 2004 Third Quarter Form 10-Q); Amendment No. 2 effective as of June 1, 2004 to the Supplemental Benefits Plan (Exhibit 10.L.1 to our 2004 Form 10-K)
	+10	.M		Senior Executive Survivor Benefit Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.M to our 2004 Form 10-K); Amendment No. 1 effective as of February 7, 2001 to the Senior Executive Survivor Benefit Plan (Exhibit 10.I.1 to our 2001 First Quarter Form 10-Q); Amendment No. 2 effective as of October 1, 2002 to the Senior Executive Survivor Benefit Plan (Exhibit 10.L.1 to our 2002 Form 10-K)
	+10	.N		Key Executive Severance Protection Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.N to our 2004 Form 10-K); Amendment No. 1 effective as of February 7, 2001 to the Key Executive Severance Protection Plan (Exhibit 10.K.1 to our 2001 First Quarter Form 10-Q); Amendment No. 2 effective as of November 7, 2002 to the Key Executive Severance Protection Plan (Exhibit 10.N.1 to our 2002 Form 10-K); Amendment No. 3 effective as of December 6, 2002 to the Key Executive Severance Protection Plan (Exhibit 10.N.1 to our 2002 Form 10-K); Amendment No. 4 effective as of September 2, 2003 to the Key Executive Severance Protection Plan (Exhibit 10.N.1 to our 2003 Third Quarter Form 10-Q)
	+10	.O		2004 Key Executive Severance Protection Plan effective as of March 9, 2004 (Exhibit 10.P to our 2003 Form 10-K)
	+10	.P		Director Charitable Award Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.P to our 2004 Form 10-K); Amendment No. 1 effective as of February 7, 2001 to the Director Charitable Award Plan (Exhibit 10.L.1 to our 2001 First Quarter Form 10-Q); Amendment No. 2 effective as of December 4, 2003 to the Director Charitable Award Plan (Exhibit 10.Q.1 to our 2003 Form 10-K)
	+10	.Q		Strategic Stock Plan Amended and Restated effective as of December 3, 1999 (Exhibit 10.1 to our Form S-8, Registration No. 333-94717, filed January 14, 2000); Amendment No. 1 effective as of February 7, 2001 to the Strategic Stock Plan (Exhibit 10.M.1 to our 2001 First Quarter Form 10-Q); Amendment No. 2 effective as of November 7, 2002 to the Strategic Stock Plan; Amendment No. 3 effective as of December 6, 2002 to the Strategic Stock Plan and Amendment No. 4 effective as of January 29, 2003 to the Strategic Stock Plan (Exhibit 10.P.1 to our 2002 Form 10-K)
	+10	.R		Domestic Relocation Policy effective November 1, 1996 (Exhibit 10.R to our 2004 Form 10-K)
	+10	.S		Executive Award Plan of Sonat Inc. Amended and Restated effective as of July 23, 1998, as amended May 27, 1999 (Exhibit 10.S to our 2004 Form 10-K); Termination of the Executive Award Plan of Sonat Inc. (Exhibit 10.K.1 to our 2000 Second Quarter Form 10-Q)

II-5

---

Table of Contents

Exhibit No.				Exhibit
	+10	.T		Omnibus Plan for Management Employees Amended and Restated effective as of December 3, 1999 (Exhibit 10.A to our Form S-8, Registration No. 333-52100, filed December 18, 2000); Amendment No. 1 effective as of December 1, 2000 to the Omnibus Plan for Management Employees (Exhibit 10.A to our Form S-8, Registration No. 333-52100, filed December 18, 2000); Amendment No. 2 effective as of February 7, 2001 to the Omnibus Plan for Management Employees (Exhibit 10.U.1 to our 2001 First Quarter Form 10-Q); Amendment No. 3 effective as of December 7, 2001 to the Omnibus Plan for Management Employees (Exhibit 10.1 to our Form S-8, Registration No. 333-82506, filed February 11, 2002); Amendment No. 4 effective as of December 6, 2002 to the Omnibus Plan for Management Employees (Exhibit 10.T.1 to our 2002 Form 10-K)
	+10	.U		El Paso Production Companies Long-Term Incentive Plan effective as of January 1, 2003 (Exhibit 10.AA to our 2003 First Quarter Form 10-Q); Amendment No. 1 effective as of June 6, 2003 to the El Paso Production Companies Long-Term Incentive Plan (Exhibit 10.AA.1 to our 2003 Second Quarter Form 10-Q); Amendment No. 2 effective as of December 31, 2003 to the El Paso Production Companies Long-Term Incentive Plan (Exhibit 10.V.1 to our 2003 Form 10-K)
	+10	.V		Severance Pay Plan Amended and Restated effective as of October 1, 2002; Supplement No. 1 to the Severance Pay Plan effective as of January 1, 2003; and Amendment No. 1 to Supplement No. 1 effective as of March 21, 2003 (Exhibit 10.Z to our 2003 First Quarter Form 10-Q); Amendment No. 2 to Supplement No. 1 effective as of June 1, 2003 (Exhibit 10.Z.1 to our 2003 Second Quarter Form 10-Q); Amendment No. 3 to Supplement No. 1 effective as of September 2, 2003 (Exhibit 10.Z.1 to our 2003 Third Quarter Form 10-Q); Amendment No. 4 to Supplement No. 1 effective as of October 1, 2003 (Exhibit 10.W.1 to our 2003 Form 10-K); Amendment No. 5 to Supplement No. 1 effective as of February 2, 2004 (Exhibit 10.W.2 to our 2003 Form 10-K)
	+10	.W		Employment Agreement Amended and Restated effective as of February 1, 2001 between El Paso and William A. Wise (Exhibit 10.O to our 2000 Form 10-K)
	+10	.X		Letter Agreement dated July 16, 2004 between El Paso Corporation and D. Dwight Scott. (Exhibit 10.VV to our 2003 Third Quarter Form 10-Q)
	+10	.Y		Letter Agreement dated July 15, 2003 between El Paso and Douglas L. Foshee (Exhibit 10.U to our 2003 Third Quarter Form 10-Q)
	+10	.Y.1		Letter Agreement dated December 18, 2003 between El Paso and Douglas L. Foshee (Exhibit 10.BB.1 to our 2003 Form 10-K)
	+10	.Z		Letter Agreement dated January 6, 2004 between El Paso and Lisa A. Stewart (Exhibit 10.CC to our 2003 Form 10-K)
	+10	.AA		Form of Indemnification Agreement of each member of the Board of Directors effective November 7, 2002 or the effective date such director was elected to the Board of Directors, whichever is later (Exhibit 10.FF to our 2002 Form 10-K)
	+10	.BB		Form of Indemnification Agreement executed by El Paso for the benefit of each officer listed in Schedule A thereto, effective December 17, 2004 (Exhibit 10.WW to our 2003 Third Quarter Form 10-Q)
	+10	.CC		Indemnification Agreement executed by El Paso for the benefit of Douglas L. Foshee, effective December 17, 2004 (Exhibit 10.XX to our 2003 Third Quarter Form 10-Q)

II-6

---

Table of Contents

Exhibit No.				Exhibit
	10	.DD		Master Settlement Agreement dated as of June 24, 2003, by and between, on the one hand, El Paso Corporation, El Paso Natural Gas Company, and El Paso Merchant Energy, L.P.; and, on the other hand, the Attorney General of the State of California, the Governor of the State of California, the California Public Utilities Commission, the California Department of Water Resources, the California Energy Oversight Board, the Attorney General of the State of Washington, the Attorney General of the State of Oregon, the Attorney General of the State of Nevada, Pacific Gas & Electric Company, Southern California Edison Company, the City of Los Angeles, the City of Long Beach, and classes consisting of all individuals and entities in California that purchased natural gas and/or electricity for use and not for resale or generation of electricity for the purpose of resale, between September 1, 1996 and March 20, 2003, inclusive, represented by class representatives Continental Forge Company, Andrew Berg, Andrea Berg, Gerald J. Marcil, United Church Retirement Homes of Long Beach, Inc., doing business as Plymouth West, Long Beach Brethren Manor, Robert Lamond, Douglas Welch, Valerie Welch, William Patrick Bower, Thomas L. French, Frank Stella, Kathleen Stella, John Clement Molony, SierraPine, Ltd., John Frazee and Jennifer Frazee, John W.H.K. Phillip, and Cruz Bustamante (Exhibit 10.HH to our 2003 Second Quarter Form 10-Q)
	10	.EE		Agreement With Respect to Collateral dated as of June 11, 2004, by and among El Paso Production Oil & Gas USA, L.P., a Delaware limited partnership, Bank of America, N.A., acting solely in its capacity as Collateral Agent under the Collateral Agency Agreement, and The Office of the Attorney General of the State of California, acting solely in its capacity as the Designated Representative under the Designated Representative Agreement (Exhibit 10.HH to our 2003 Form 10-K)
	10	.FF		Joint Settlement Agreement submitted and entered into by El Paso Natural Gas Company, El Paso Merchant Energy Company, El Paso Merchant Energy-Gas, L.P., the Public Utilities Commission of the State of California, Pacific Gas & Electric Company, Southern California Edison Company and the City of Los Angeles (Exhibit 10.II to our 2003 Second Quarter Form 10-Q)
	10	.GG		Swap Settlement Agreement dated effective as of August 16, 2004, among the Company, El Paso Merchant Energy, L.P., East Coast Power Holding Company L.L.C. and ECTMI Trutta Holdings LP (Exhibit 10.A to our Form 8-K filed October 15, 2004, and terminated as described in our Form 8-K filed December 3, 2004)
	10	.HH		Purchase Agreement dated April 11, 2005, by and among El Paso Corporation and the Initial Purchasers party thereto (Exhibit 10.A to our Form 8-K filed April 15, 2005)
	+10	.II		Agreement and General Release dated May 4, 2005, by and between El Paso Corporation and John W. Somerhalder II (Exhibit 10.A to our Form 8-K filed May 4, 2005)
	10	.JJ		El Paso Corporation 2005 Compensation Plan for Non-Employee Directors (Exhibit 10.A to our Form 8-K filed on May 31, 2005).
	10	.KK		El Paso Corporation 2005 Omnibus Incentive Compensation Plan (Exhibit 10.B to our Form 8-K filed on May 31, 2005).
	10	.LL		El Paso Corporation Employee Stock Purchase Plan, Amended and Restated Effective as of July 1, 2005. (Exhibit 10.E to our 2005 Second Quarter Form 10-Q)
	10	.MM		Form of Indemnification Agreement executed by El Paso for the benefit of each officer listed in Schedule A thereto, effective August 4, 2005. (Exhibit 10.G to our 2005 Second Quarter Form 10-Q)
	*12			Statement re: computation of ratio of earnings to fixed charges
	21			Subsidiaries of El Paso (Exhibit 21 to our 2004 Form 10-K)
	*23	.A		Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP (Houston, Texas)
	*23	.B		Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP (Detroit, Michigan)
	*23	.C		Consent of Ryder Scott Company, L.P.
	*23	.D		Consent of Andrews Kurth LLP (included in Exhibit 5.A)
	*24	.A		Powers of Attorney (included on signature page)

II-7

---

Table of Contents

ITEM 17.	UNDERTAKINGS

	(1) To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:

	(a) To include any prospectus required by Section 10(a)(3) of the Securities Act;
	(b) To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement; and
	(c) To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in this registration statement;

	provided, however, that paragraphs A(l)(a) and A(l)(b) above do not apply if the information required to be included in a post-effective amendment by those paragraphs is contained in periodic reports filed with or furnished to the SEC by the registrant pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 that are incorporated by reference in the Registration Statement.

	(2) That, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
	(3) To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.

II-8

---

Table of Contents

	EL PASO CORPORATION

	By:	/s/ Douglas L. Foshee

	Douglas L. Foshee
	President and Chief Executive Officer

Signature				Title		Date
/s/ Ronald L. Kuehn, Jr.   Ronald L. Kuehn, Jr.				Chairman of the Board, Director		August 23, 2005
/s/ Douglas L. Foshee   Douglas L. Foshee				President, Chief Executive Officer and Director (Principal Executive Officer)		August 23, 2005
/s/ D. Mark Leland   D. Mark Leland				Executive Vice President and Chief Financial Officer (Principal Financial Officer)		August 23, 2005
/s/ Jeffrey I. Beason   Jeffrey I. Beason				Senior Vice President and Controller (Principal Accounting Officer)		August 23, 2005
/s/ Juan Carlos Braniff   Juan Carlos Braniff				Director		August 23, 2005
/s/ James L. Dunlap   James L. Dunlap				Director		August 23, 2005
/s/ Robert W. Goldman   Robert W. Goldman				Director		August 23, 2005
/s/ Anthony W. Hall, Jr.   Anthony W. Hall, Jr.				Director		August 23, 2005

II-9

---

Table of Contents

Signature				Title		Date
/s/ Thomas R. Hix   Thomas R. Hix				Director		August 23, 2005
/s/ William H. Joyce   William H. Joyce				Director		August 23, 2005
/s/ J. Michael Talbert   J. Michael Talbert				Director		August 23, 2005
/s/ Robert F. Vagt   Robert F. Vagt				Director		August 23, 2005
/s/ John L. Whitmire   John L. Whitmire				Director		August 23, 2005
/s/ Joe B. Wyatt   Joe B. Wyatt				Director		August 23, 2005

II-10

---

Table of Contents

Exhibit No.				Exhibit
	2	.A		Merger Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products Management LLC, GulfTerra Energy Partners, L.P. and GulfTerra Energy Company, L.L.C. (including the form of Assumption Agreement to be entered into in connection with the merger, attached as an exhibit thereto) (Exhibit 2.1 to our Form 8-K filed December 15, 2003)
	2	.B		Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company (including the form of Second Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, to be entered into in connection with the merger, attached as an exhibit thereto) (Exhibit 2.2 to our Form 8-K filed December 15, 2003); Amendment No. 1 to Parent Company Agreement, dated as of December 15, 2003, by and among Enterprise Products Partners L.P., Enterprise Products GP, LLC, Enterprise Products GTM, LLC, El Paso Corporation, Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso EPN Investments, L.L.C. and GulfTerra GP Holding Company, dated as of April 19, 2004 (including the forms of Second Amended and Restated Limited Liability Company Agreement of Enterprise Products GP, LLC, Exchange and Registration Rights Agreement and Performance Guaranty, to be entered into by the parties named therein in connection with the merger of Enterprise and GulfTerra, attached as Exhibits 1, 2 and 3, respectively, thereto) (Exhibit 2.1 to our Form 8-K filed April 21, 2004); Second Amended and Restated Limited Liability Company Agreement of GulfTerra Energy Company, L.L.C., adopted by GulfTerra GP Holding Company, a Delaware corporation, and Enterprise Products GTM, LLC, a Delaware limited liability company, as of December 15, 2003 (Exhibit 2.3 to our Form 8-K filed December 15, 2003); Purchase and Sale Agreement (Gas Plants), dated as of December 15, 2003, by and between El Paso Corporation, El Paso Field Services Management, Inc., El Paso Transmission, L.L.C., El Paso Field Services Holding Company and Enterprise Products Operating L.P. (Exhibit 2.4 to our Form 8-K filed December 15, 2003)
	2	.B.1		Purchase and Sale Agreement, dated as of January 14, 2005, by and among Enterprise GP Holdings, L.P., Sabine River Investors I, L.L.C., Sabine River Investors II, L.L.C., El Paso Corporation and GulfTerra GP Holding Company (Exhibit 2.B.1 to our 2004 Form 10-K)
	3	.A		Amended and Restated Certificate of Incorporation effective as of May 26, 2005 (Exhibit 3.A to our Current Report on Form 8-K filed May 27, 2005)
	3	.B		By-Laws effective as of July 31, 2003 (Exhibit 3.B to our 2003 Second Quarter Form 10-Q)
	4	.A		Indenture dated as of May 10, 1999, by and between El Paso and HSBC Bank USA, National Association (as successor-in-interest to JPMorgan Chase Bank (formerly The Chase Manhattan Bank)), as Trustee (Exhibit 4.A to our 2004 Form 10-K)
	4	.B		Certificate of Designations of 4.99% Convertible Perpetual Preferred Stock (included in Exhibit 3.A to our Current Report on Form 8-K filed May 27, 2005)
	4	.C		Registration Rights Agreement, dated April 15, 2005, by and among El Paso Corporation and the Initial Purchasers party thereto (Exhibit 4.A to our Current Report on Form 8-K filed April 15, 2005)
	*5	.A		Opinion of Andrews Kurth LLP as to the legality of the common stock (to be filed by amendment)

---

Table of Contents

Exhibit No.				Exhibit
	10	.A		Amended and Restated Credit Agreement dated as of November 23, 2004, among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the several banks and other financial institutions from time to time parties thereto and JPMorgan Chase Bank, N.A., as administrative agent and as collateral agent (Exhibit 10.A to our Form 8-K filed November 29, 2004); Amended and Restated Subsidiary Guarantee Agreement dated as of November 23, 2004, made by each of the Subsidiary Guarantors, as defined therein, in favor of JPMorgan Chase Bank, N.A., as collateral agent (Exhibit 10.C to our Form 8-K filed November 29, 2004); Amended and Restated Parent Guarantee Agreement dated as of November 23, 2004, made by El Paso Corporation, in favor of JPMorgan Chase Bank, N.A., as Collateral Agent (Exhibit 10.D to our Form 8-K filed November 29, 2004)
	10	.B		Amended and Restated Security Agreement dated as of November 23, 2004, among El Paso Corporation, ANR Pipeline Company, Colorado Interstate Gas Company, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, the Subsidiary Grantors and certain other credit parties thereto and JPMorgan Chase Bank, N.A., not in its individual capacity, but solely as collateral agent for the Secured Parties and as the depository bank (Exhibit 10.B to our Form 8-K filed November 29, 2004)
	10	.C		$3,000,000,00 Revolving Credit Agreement dated as of April 16, 2003 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company and ANR Pipeline Company, as Borrowers, the Lenders Party thereto, and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Document Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as Joint Bookrunners and Co-Lead Arrangers (Exhibit 99.1 to our Form 8-K filed April 18, 2003); First Amendment to the $3,000,000,000 Revolving Credit Agreement and Waiver dated as of March 17, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lender and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents (Exhibit 10.A.1 to our 2003 Form 10-K); Second Waiver to the $3,000,000,000 Revolving Credit Agreement dated as of June 15, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents (Exhibit 10.A.2 to our 2003 Form 10-K); Second Amendment to the $3,000,000,000 Revolving Credit Agreement and Third Waiver dated as of August 6, 2004 among El Paso Corporation, El Paso Natural Gas Company, Tennessee Gas Pipeline Company, ANR Pipeline Company and Colorado Interstate Gas Company, as Borrowers, the Lenders party thereto and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Documentation Agents, Bank of America, N.A. and Credit Suisse First Boston, as Co-Syndication Agents (Exhibit 99.B to our Form 8-K filed August 10, 2004)
	10	.D		$1,000,000,000 Amended and Restated 3-Year Revolving Credit Agreement dated as of April 16, 2003 among El Paso Corporation, El Paso Natural Gas Company and Tennessee Gas Pipeline Company, as Borrowers, The Lenders Party Thereto, and JPMorgan Chase Bank, as Administrative Agent, ABN AMRO Bank N.V. and Citicorp North America, Inc., as Co-Document Agents, Bank of America, N.A., as Syndication Agent, J.P. Morgan Securities Inc. and Citigroup Global Markets Inc., as Joint Bookrunners and Co-Lead Arrangers. (Exhibit 99.2 to our Form 8-K filed April 18, 2003)
	10	.E		Security and Intercreditor Agreement dated as of April 16, 2003 Among El Paso Corporation, the Persons Referred to therein as Pipeline Company Borrowers, the Persons Referred to therein as Grantors, Each of the Representative Agents, JPMorgan Chase Bank, as Credit Agreement Administrative Agent and JPMorgan Chase Bank, as Collateral Agent, Intercreditor Agent, and Depository Bank. (Exhibit 99.3 to our Form 8-K filed April 18, 2003)
	+10	.F		1995 Compensation Plan for Non-Employee Directors Amended and Restated effective as of December 4, 2003 (Exhibit 10.F to our 2003 Form 10-K)

---

Table of Contents

Exhibit No.				Exhibit
	+10	.G		Stock Option Plan for Non-Employee Directors Amended and Restated effective as of January 20, 1999 (Exhibit 10.G to our 2004 Form 10-K); Amendment No. 1 effective as of July 16, 1999 to the Stock Option Plan for Non-Employee Directors (Exhibit 10.G.1 to our 2004 Form 10-K); Amendment No. 2 effective as of February 7, 2001 to the Stock Option Plan for Non-Employee Directors (Exhibit 10.F.1 to our 2001 First Quarter Form 10-Q)
	+10	.H		2001 Stock Option Plan for Non-Employee Directors effective as of January 29, 2001 (Exhibit 10.1 to our Form S-8, Registration No. 333-64240, filed June 29, 2001); Amendment No. 1 effective as of February 7, 2001 to the 2001 Stock Option Plan for Non-Employee Directors (Exhibit 10.G.1 to our 2001 Form 10-K); Amendment No. 2 effective as of December 4, 2003 to the 2001 Stock Option Plan for Non-Employee Directors (Exhibit 10.H.1 to our 2003 Form 10-K)
	+10	.I		1995 Omnibus Compensation Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.I to our 2004 Form 10-K); Amendment No. 1 effective as of December 3, 1998 to the 1995 Omnibus Compensation Plan (Exhibit 10.I.1 to our 2004 Form 10-K); Amendment No. 2 effective as of January 20, 1999 to the 1995 Omnibus Compensation Plan (Exhibit 10.I.2 to our 2004 Form 10-K)
	+10	.J		1999 Omnibus Incentive Compensation Plan dated January 20, 1999 (Exhibit 10.1 to our Form S-8, Registration No. 333-78979, filed May 20, 1999); Amendment No. 1 effective as of February 7, 2001 to the 1999 Omnibus Incentive Compensation Plan (Exhibit 10.V.1 to our 2001 First Quarter Form  10-Q); Amendment No. 2 effective as of May 1, 2003 to the 1999 Omnibus Incentive Compensation Plan (Exhibit 10.I.1 to our 2003 Second Quarter Form 10-Q)
	+10	.K		2001 Omnibus Incentive Compensation Plan effective as of January 29, 2001 (Exhibit 10.1 to our Form S-8, Registration No. 333-64236, filed June 29, 2001); Amendment No. 1 effective as of February 7, 2001 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to our 2001 Form 10-K); Amendment No. 2 effective as of April 1, 2001 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to our 2002 Form 10-K); Amendment No. 3 effective as of July 17, 2002 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to our 2002 Second Quarter Form 10-Q); Amendment No. 4 effective as of May 1, 2003 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.J.1 to our 2003 Second Quarter Form 10-Q); Amendment No. 5 effective as of March 8, 2004 to the 2001 Omnibus Incentive Compensation Plan (Exhibit 10.K.1 to our 2003 Form 10-K)
	+10	.L		Supplemental Benefits Plan Amended and Restated effective December 7, 2001 (Exhibit 10.K to our 2001 Form 10-K); Amendment No. 1 effective as of November 7, 2002 to the Supplemental Benefits Plan (Exhibit 10.K.1 to our 2002 Form 10-K); Amendment No. 3 effective December 17, 2004 to the Supplemental Benefits Plan (Exhibit 10.UU to our 2004 Third Quarter Form 10-Q); Amendment No. 2 effective as of June 1, 2004 to the Supplemental Benefits Plan (Exhibit 10.L.1 to our 2004 Form 10-K)
	+10	.M		Senior Executive Survivor Benefit Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.M to our 2004 Form 10-K); Amendment No. 1 effective as of February 7, 2001 to the Senior Executive Survivor Benefit Plan (Exhibit 10.I.1 to our 2001 First Quarter Form 10-Q); Amendment No. 2 effective as of October 1, 2002 to the Senior Executive Survivor Benefit Plan (Exhibit 10.L.1 to our 2002 Form 10-K)
	+10	.N		Key Executive Severance Protection Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.N to our 2004 Form 10-K); Amendment No. 1 effective as of February 7, 2001 to the Key Executive Severance Protection Plan (Exhibit 10.K.1 to our 2001 First Quarter Form 10-Q); Amendment No. 2 effective as of November 7, 2002 to the Key Executive Severance Protection Plan (Exhibit 10.N.1 to our 2002 Form 10-K); Amendment No. 3 effective as of December 6, 2002 to the Key Executive Severance Protection Plan (Exhibit 10.N.1 to our 2002 Form 10-K); Amendment No. 4 effective as of September 2, 2003 to the Key Executive Severance Protection Plan (Exhibit 10.N.1 to our 2003 Third Quarter Form 10-Q)
	+10	.O		2004 Key Executive Severance Protection Plan effective as of March 9, 2004 (Exhibit 10.P to our 2003 Form 10-K)
	+10	.P		Director Charitable Award Plan Amended and Restated effective as of August 1, 1998 (Exhibit 10.P to our 2004 Form 10-K); Amendment No. 1 effective as of February 7, 2001 to the Director Charitable Award Plan (Exhibit 10.L.1 to our 2001 First Quarter Form 10-Q); Amendment No. 2 effective as of December 4, 2003 to the Director Charitable Award Plan (Exhibit 10.Q.1 to our 2003 Form 10-K)

---

Table of Contents

Exhibit No.				Exhibit
	+10	.Q		Strategic Stock Plan Amended and Restated effective as of December 3, 1999 (Exhibit 10.1 to our Form S-8, Registration No. 333-94717, filed January 14, 2000); Amendment No. 1 effective as of February 7, 2001 to the Strategic Stock Plan (Exhibit 10.M.1 to our 2001 First Quarter Form 10-Q); Amendment No. 2 effective as of November 7, 2002 to the Strategic Stock Plan; Amendment No. 3 effective as of December 6, 2002 to the Strategic Stock Plan and Amendment No. 4 effective as of January 29, 2003 to the Strategic Stock Plan (Exhibit 10.P.1 to our 2002 Form 10-K)
	+10	.R		Domestic Relocation Policy effective November 1, 1996 (Exhibit 10.R to our 2004 Form 10-K)
	+10	.S		Executive Award Plan of Sonat Inc. Amended and Restated effective as of July 23, 1998, as amended May 27, 1999 (Exhibit 10.S to our 2004 Form 10-K); Termination of the Executive Award Plan of Sonat Inc. (Exhibit 10.K.1 to our 2000 Second Quarter Form 10-Q)
	+10	.T		Omnibus Plan for Management Employees Amended and Restated effective as of December 3, 1999 (Exhibit 10.A to our Form S-8, Registration No. 333-52100, filed December 18, 2000); Amendment No. 1 effective as of December 1, 2000 to the Omnibus Plan for Management Employees (Exhibit 10.A to our Form S-8, Registration No. 333-52100, filed December 18, 2000); Amendment No. 2 effective as of February 7, 2001 to the Omnibus Plan for Management Employees (Exhibit 10.U.1 to our 2001 First Quarter Form 10-Q); Amendment No. 3 effective as of December 7, 2001 to the Omnibus Plan for Management Employees (Exhibit 10.1 to our Form S-8, Registration No. 333-82506, filed February 11, 2002); Amendment No. 4 effective as of December 6, 2002 to the Omnibus Plan for Management Employees (Exhibit 10.T.1 to our 2002 Form 10-K)
	+10	.U		El Paso Production Companies Long-Term Incentive Plan effective as of January 1, 2003 (Exhibit 10.AA to our 2003 First Quarter Form 10-Q); Amendment No. 1 effective as of June 6, 2003 to the El Paso Production Companies Long-Term Incentive Plan (Exhibit 10.AA.1 to our 2003 Second Quarter Form 10-Q); Amendment No. 2 effective as of December 31, 2003 to the El Paso Production Companies Long-Term Incentive Plan (Exhibit 10.V.1 to our 2003 Form 10-K)
	+10	.V		Severance Pay Plan Amended and Restated effective as of October 1, 2002; Supplement No. 1 to the Severance Pay Plan effective as of January 1, 2003; and Amendment No. 1 to Supplement No. 1 effective as of March 21, 2003 (Exhibit 10.Z to our 2003 First Quarter Form 10-Q); Amendment No. 2 to Supplement No. 1 effective as of June 1, 2003 (Exhibit 10.Z.1 to our 2003 Second Quarter Form 10-Q); Amendment No. 3 to Supplement No. 1 effective as of September 2, 2003 (Exhibit 10.Z.1 to our 2003 Third Quarter Form 10-Q); Amendment No. 4 to Supplement No. 1 effective as of October 1, 2003 (Exhibit 10.W.1 to our 2003 Form 10-K); Amendment No. 5 to Supplement No. 1 effective as of February 2, 2004 (Exhibit 10.W.2 to our 2003 Form 10-K)
	+10	.W		Employment Agreement Amended and Restated effective as of February 1, 2001 between El Paso and William A. Wise (Exhibit 10.O to our 2000 Form 10-K)
	+10	.X		Letter Agreement dated July 16, 2004 between El Paso Corporation and D. Dwight Scott. (Exhibit 10.VV to our 2004 Third Quarter Form 10-Q)
	+10	.Y		Letter Agreement dated July 15, 2003 between El Paso and Douglas L. Foshee (Exhibit 10.U to our 2003 Third Quarter Form 10-Q)
	+10	.Y.1		Letter Agreement dated December 18, 2003 between El Paso and Douglas L. Foshee (Exhibit 10.BB.1 to our 2003 Form 10-K)
	+10	.Z		Letter Agreement dated January 6, 2004 between El Paso and Lisa A. Stewart (Exhibit 10.CC to our 2003 Form 10-K)
	+10	.AA		Form of Indemnification Agreement of each member of the Board of Directors effective November 7, 2002 or the effective date such director was elected to the Board of Directors, whichever is later (Exhibit 10.FF to our 2002 Form 10-K)
	+10	.BB		Form of Indemnification Agreement executed by El Paso for the benefit of each officer listed in Schedule A thereto, effective December 17, 2004 (Exhibit 10.WW to our 2003 Third Quarter Form 10-Q)
	+10	.CC		Indemnification Agreement executed by El Paso for the benefit of Douglas L. Foshee, effective December 17, 2004 (Exhibit 10.XX to our 2003 Third Quarter Form 10-Q)

---

Table of Contents

Exhibit No.				Exhibit
	10	.DD		Master Settlement Agreement dated as of June 24, 2003, by and between, on the one hand, El Paso Corporation, El Paso Natural Gas Company, and El Paso Merchant Energy, L.P.; and, on the other hand, the Attorney General of the State of California, the Governor of the State of California, the California Public Utilities Commission, the California Department of Water Resources, the California Energy Oversight Board, the Attorney General of the State of Washington, the Attorney General of the State of Oregon, the Attorney General of the State of Nevada, Pacific Gas & Electric Company, Southern California Edison Company, the City of Los Angeles, the City of Long Beach, and classes consisting of all individuals and entities in California that purchased natural gas and/or electricity for use and not for resale or generation of electricity for the purpose of resale, between September 1, 1996 and March 20, 2003, inclusive, represented by class representatives Continental Forge Company, Andrew Berg, Andrea Berg, Gerald J. Marcil, United Church Retirement Homes of Long Beach, Inc., doing business as Plymouth West, Long Beach Brethren Manor, Robert Lamond, Douglas Welch, Valerie Welch, William Patrick Bower, Thomas L. French, Frank Stella, Kathleen Stella, John Clement Molony, SierraPine, Ltd., John Frazee and Jennifer Frazee, John W.H.K. Phillip, and Cruz Bustamante (Exhibit 10.HH to our 2003 Second Quarter Form 10-Q)
	10	.EE		Agreement With Respect to Collateral dated as of June 11, 2004, by and among El Paso Production Oil & Gas USA, L.P., a Delaware limited partnership, Bank of America, N.A., acting solely in its capacity as Collateral Agent under the Collateral Agency Agreement, and The Office of the Attorney General of the State of California, acting solely in its capacity as the Designated Representative under the Designated Representative Agreement (Exhibit 10.HH to our 2003 Form 10-K)
	10	.FF		Joint Settlement Agreement submitted and entered into by El Paso Natural Gas Company, El Paso Merchant Energy Company, El Paso Merchant Energy-Gas, L.P., the Public Utilities Commission of the State of California, Pacific Gas & Electric Company, Southern California Edison Company and the City of Los Angeles (Exhibit 10.II to our 2003 Second Quarter Form 10-Q)
	10	.GG		Swap Settlement Agreement dated effective as of August 16, 2004, among the Company, El Paso Merchant Energy, L.P., East Coast Power Holding Company L.L.C. and ECTMI Trutta Holdings LP (Exhibit 10.A to our Form 8-K filed October 15, 2004, and terminated as described in our Form 8-K filed December 3, 2004)
	10	.HH		Purchase Agreement dated April 11, 2005, by and among El Paso Corporation and the Initial Purchasers party thereto (Exhibit 10.A to our Form 8-K filed April 15, 2005)
	+10	.II		Agreement and General Release dated May 4, 2005, by and between El Paso Corporation and John W. Somerhalder II (Exhibit 10.A to our Form 8-K filed May 4, 2005)
	10	.JJ		El Paso Corporation 2005 Compensation Plan for Non-Employee Directors (Exhibit 10.A to our Form 8-K filed on May 31, 2005).
	10	.KK		El Paso Corporation 2005 Omnibus Incentive Compensation Plan (Exhibit 10.B to our Form 8-K filed on May 31, 2005).
	10	.LL		El Paso Corporation Employee Stock Purchase Plan, Amended and Restated Effective as of July 1, 2005. (Exhibit 10.E to our 2005 Second Quarter Form 10-Q)
	10	.MM		Form of Indemnification Agreement executed by El Paso for the benefit of each officer listed in Schedule A thereto, effective August 4, 2005. (Exhibit 10.G to our 2005 Second Quarter Form 10-Q)
	*12			Statement re: computation of ratio of earnings to fixed charges
	21			Subsidiaries of El Paso (Exhibit 21 to our 2004 Form 10-K)
	*23	.A		Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP (Houston, Texas)
	*23	.B		Consent of Independent Registered Public Accounting Firm, PricewaterhouseCoopers LLP (Detroit, Michigan)
	*23	.C		Consent of Ryder Scott Company, L.P.
	*23	.D		Consent of Andrews Kurth LLP (included in Exhibit 5.A)
	*24	.A		Powers of Attorney (included on signature page)